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Home My WebLink About219-0781. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Re-Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: ______________________ Development Exploratory 3. Address:Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: 7,130; Total Depth measured 9,802 feet 7,430; 7,949 feet true vertical 8,043 feet See schematic feet Effective Depth measured 7,120 feet See schematic feet true vertical 5,461 feet See schematic feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)2-7/8" 6.5 / L-80 / FJ3 7,885 (MD) 6,198 (TVD) Packers and SSSV (type, measured and true vertical depth)See schematic 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date:Contact Name: Contact Email: Authorized Title:Contact Phone: Chad Helgeson, Operations Engineer 324-700 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: WINJ WAG 257 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 N/A chelgeson@hilcorp.com 907-777-8405 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 0 Size 120' 0 0111 0 640 66 Production Liner 6,824' 4,435' measured TVD 7-5/8" 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-078 50-133-20684-00-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL60569 / ADL60568 / ADL324602 / Fee Private Kenai C.L.U. / Beluga Gas Cannery Loop Unit 14 Plugs Junk measured LengthCasing Structural 5,183' 8,041' 6,824' 9,800' 120'Conductor Surface Intermediate 16" 10-3/4" 120' 3,333' 4,790psi 7,500psi 3,580psi 6,890psi 8,430psi 3,333'2,616' Burst Collapse 2,090psi p k ft t Fra O s O 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 3:31 pm, Jan 27, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.01.27 13:11:54 - 09'00' Noel Nocas (4361) DSR-1/31/25A.Dewhurst 13FEB25 RBDMS JSB 013025 BJM 3/12/25 Page 1/1 Well Name: CLU 014 Report Printed: 1/15/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Jobs Actual Start Date:12/26/2024 End Date: Report Number 1 Report Start Date 12/26/2024 Report End Date 12/27/2024 Last 24hr Summary PTW/PJSM, PT 250/2500, Ran GPT tag @ 7102', Fluid level @ 7075'. Reperforate W/ well flowing UB-4A from 7053'-7092'. Reperforate W/ well S/I UB-4L from 7036'-7043' & UB-4U from 7022'-7030' Report Number 2 Report Start Date 12/27/2024 Report End Date 12/28/2024 Last 24hr Summary SL MIRU, PT lube 1500 psi, RIH and set SSSV. Field: Cannery Loop Sundry #: 324-700 State: Alaska Rig/Service:Permit to Drill (PTD) #:219-078Permit to Drill (PTD) #:219-078 Wellbore API/UWI:50-133-20684-00-00 _____________________________________________________________________________________ Updated by DMA 01-21-25 SCHEMATIC Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 OPEN HOLE / CEMENT DETAIL 10-3/4”13-1/2” Hole: 272bbls (640sx) 12# class A lead cement followed by 57bbls of 15.8# Class A tail cement. Bumped plug. Full returns throughout job. 92bbls cement back to Surface 7-5/8"9-7/8” Hole: 159 bbls 12# class A lead cement followed by 59bbls of 15.3# Class A tail cement, bumped plug. 44bbls lost throughout job. 8/9/19 CBL (AKEL) TOC @ 2800’ MD. 4-1/2” 6-3/4” Hole: 125bbls 12# class A lead cement followed by 23bbls 15.3# tail cement. After 124bbls displacement, lost all returns. Estimated 30bbls total lost during job. Spacer and trace cement circulated off liner top back to surface. 8/29/19 CBL TOC @ 8,910’. Ratty cement spots up to 6370. RA tags:6809, 7304, 7829, 8318, 8811, 9347’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 109 / X-56 / Weld 15”Surf 120’ 10-3/4”Surface 45.5 / L-80 / TXP BTC 9.950”Surf 3,333’ 7-5/8"Intermediate 29.7 / L-80 / W563 6.875”Surf 6,824’ 4-1/2"Production 12.6 / L-80 / TXP BTC 3.958”5,365’9,800’ TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8”Tubing 6.5 / L-80 / EUE 2.441”Surf 5,391’ 2-7/8”Tubing 6.5 / L-80 / FJ3 2.30”5,402’7,885’ 3/8”Cap Tubing 0.049 Duplex 2205 Surface ~7000’ JEWELRY DETAIL No Depth (MD) Depth (TVD)Item 1 546’546’SSSV-Halliburton NE SRSV Valve removed for Capillary string 2 2,821’2,272’7-5/8” Swell Packer 3 5,391’3,993’4.5” x 5.75” Bullet Tie-Back Seal Assembly 4 5,365’3,975’7-5/8” X 4-1/2” Liner Hanger 5 7,130’5,471’CIBP with 10’ of cement 7,120’ (5,461’ TVD) 03/25/22 6 7,430’5,759’Quadco Single trip cement retainer 03/19/22 7 7,886’6,199’Wireline Re-entry Guide 07/28/20 8 7,924’6,236’4.4” NEO Vented TTBP - 7,949’ w/ 25’ cement PERFORATION DETAIL Old Zone Name New Zone Name Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Date Status UB4 Upper 7,022’7,030’5,368’5,376’8’12/26/2024 Open UB4 Upper 7,022’7,030’5,368’5,376’8’12/11/2023 Open UB4 Lower 7,036’7,043’5,382’5,388’7’12/26/2024 Open UB4 Lower 7,036’7,043’5,382’5,388’7’12/11/2023 Open UB 4A 7,053’7,092’5,398’5,435’39’12/26/2024 Open UB 4A 7,053’7,092’5,398’5,435’39’3/25&27/2022 Open UB 5A 7,138 7,158 5,479’5,498’20’3/21/2022 Plugged UB 6 7,200 7,210 5,538’5,548’10’3/21/2022 Plugged UB 7 Lower 7,303 7,311 5,637’5,644’8’3/21/2022 Plugged MB_1X 7,538'7,558'5,825'5,845'20'10/29/2021 Plugged MB_1 7,582'7,592'5,867'5,877'10'10/18/2021 Plugged MB 2 MB_4 7,727'7,747'6,045'6,065'20'12/26/2020 Plugged 7,737’7,739’6,055’6,057’2’12/26/2020 Plugged MB- 8/8A MB_6 8,028’8,042’6,336’6,350’14’9/18/2019 Plugged MB_7 8,058’8,078’6,365’6,384’20’9/18/2019 Plugged MB 3 MB_7 8,059'8,078'6,366'6,384'19'12/26/2020 Plugged MB 4 MB-7A 8,148'8,150'6,451'6,453'2'12/24/2020 Plugged MB 7A LB-1X 8,272’8,279’6,571’6,577’7’12/23/2020 Plugged 8,279'8,286'6,577'6,584'7'12/24/2020 Plugged 8,278’8,280’6,576’6,578’2 12/19/2020 Plugged LB-4 LB_16 8,565’8,577’6,852’6,863’12’9/13/2019 Plugged LB-6 LB_2 8,642’8,654’6,926’6,937’12’11/25/2019 Plugged FISH DETAIL 8,663’CIBP Debris 08/18/20 Middle Fish RBP Pushed to Bottom 9,659’CIBP Milled and Pushed to Bottom 09/11/19 Note: tbg. tail is 2.30”. Superseded 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Re-Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Install Cap String 2.Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6.API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 9,802'See Schematic Casing Collapse Structural Conductor Surface 2,090psi Intermediate 4,790psi Production 7,500psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0060568|ADL0060569|ADL0324602|FEE-PRIVATE 219-078 50-133-20684-00-00 Hilcorp Alaska, LLC Proposed Pools: 6.5# / L-80 / FJ3 TVD Burst 7,885' 8,430psi 2,616' Size 120' 7-5/8"6,824' 3,333' MD See Attached Schematic 6,890psi 3,580psi 120' 5,183' 120' 3,333' December 19, 2024 2-7/8" 9,800' Perforation Depth MD (ft): 6,824' 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Cannery Loop Unit (CLU) 14CO 231A Same 8,041'4-1/2" ~500psi 4,435' 7130, 7430, 7924 Length See Schematic See Schematic 8,043'7,120'5,461' Kenai C.L.U.Beluga Gas 16" 10-3/4" See Attached Schematic m n P s 66 t g N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Chad Helgeson for Noel Nocas Digitally signed by Chad Helgeson (1517) DN: cn=Chad Helgeson (1517) Date: 2024.12.13 12:46:11 - 09'00' Chad Helgeson (1517) By Grace Christianson at 1:06 pm, Dec 13, 2024 324-700 10-404 DSR-12/16/24SFD 12/13/2024 Variance to 20AAC25.265(j)(1) approved to leave SSSV defeated without cap string installed for up to 21 days, after which the well must be shut in until either cap string or SSSV is installed. BJM 12/17/24 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.12.18 09:24:22 -09'00'12/18/24 RBDMS JSB 121824 Well: CLU-14 12/13/24 Well Name: CLU-14 API Number: 50-133-20684-00-00 Current Status: Gas Producer Permit to Drill Number: 219-078 First Call Engineer: Chad Helgeson (907) 777-8504 (O) (907) 229-4824 (C) Second Call Engineer: Scott Warner (907) 830-8863 Max. Expected BHP: ~1,000 psi @ 5,385’ TVD Depleted based on recent max buildup Max. Potential Surface Pressure: ~500 psi Max shut-in build up 12/7/24 was 275 psi Applicable Frac Gradient: NA – Reperf existing sands (no new perfs) Shallowest Allowable Perf TVD: 100ft from CINGSA Pool = 5248’ TVD Top of Applicable Gas Pool:6,787’ MD / 5,148’ TVD Well Summary CLU 14 is a gas producer that was drilled and completed in August 2019 targeting gas sands in the Beluga and Sterling formations. In January 2021, the SSSV was pulled and a capillary line installed to help unload water. In October 2021, the capillary line removed and MB6 sands were plugged back and the MB1 was perforated through tubing, where the zone made a little gas, but immediately watered up at rates over 1,000 bwpd. In 2022 these zones were plugged back and additional Upper Beluga sands were perforated. In 2023 the remaining upper beluga 4 sands were added. The well loaded up a week ago and soap sticks have been unsuccessful unloading the well. Objective The objective of this job is to reperforate existing perfs and install a capillary string (defeating the SSSV in this well.) Hilcorp is requesting approval to leave SSSV out of well (defeated) until perfs are complete and cap string is installed – expect the valve to be out longer than regulatory allowed 14 days per 20AAC 25.265(j)(1) - work will be executed as soon as the Sundry is approved and crew schedules allow. Wellbore Notes: x Current T/IA/OA – 67/0/0 Flowing at 200 mcfd x CO 231A Rule 2 & 3. This well already exists solely in the Beluga Gas Pool, and will not perforate any sands within 100ft of CINGSA Pool x WRSSSV was pulled (12-7-24) for well diagnostic work, SL tagged at 7102’ Due to be reinstalled by 12/21/24- unless variance is granted above E-Line Perf 1. Review all approved COAs 2. MIRU E-line and pressure control equipment. PT lubricator to 250psi low / 2,500 psi High 3. SI well for buildup 4. PU and RIH with perf gun 5. Perforate Upper Beluga sands per RE/Geo from bottom up Sand Perforation Top (MD) Perforation Bottom (MD) Perforation Top (TVD) Perforation Bottom (TVD) Total Footage (MD) UB 4 Upper ±7,022’ ±7,030’ ±5,368’ ±5,376’ ±8’ reperforate existing per Variance to 20AAC25.265(j)(1) approved to leave SSSV defeated without cap string installed for up to 21 days, after which the well must be shut in until either cap string or SSSV is installed. -bjm Well: CLU-14 12/13/24 UB 4 Lower ±7,036’ ±7,043’ ±5,382’ ±5,388’ ±7’ UB 4A ±7,053’ ±7,092’ ±5,398’ ±5,435’ ±39’ a. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. b. Record initial and 5/10/15 minute tubing pressures after firing 6. RD E-Line Unit and turn well over to production 7. Operations to flow well and test zones Cap string Procedure: 8. RU Cap String Truck. 9. Stab 3/8” capillary line into wellhead pack-off assembly. Make up BHA components. Install pack-off and pressure test against swab valve to 1500 psi. 10. RIH with 3/8” capillary string to ±7000’ MD. a) Set cap string as deep as practical 11. Install slips and connect tubing to chemical injection pump. 12. Set spool of remaining line near well 13. RD cap string unit, and turn well over to production. E-line Procedure (Contingency) If any zone produces sand and/or water or needs isolated: 14. MIRU Eline 15. Pressure test equipment to 1,500 psi High/250 psi Low 16. Eline run PT to find fluid level (Pressure up with N2 if needed) 17. Push fluid below perfs (verify fluid depth with PT tool) 18. PU 2-7/8” CIBP or Patch and set above perfs or patch across perfs that made water Attachments: 1. Current schematic 2. Proposed Schematic _____________________________________________________________________________________ Updated by DMA 07-10-24 SCHEMATIC Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 OPEN HOLE / CEMENT DETAIL 10-3/4”13-1/2” Hole: 272bbls (640sx) 12# class A lead cement followed by 57bbls of 15.8# Class A tail cement. Bumped plug. Full returns throughout job. 92bbls cement back to Surface 7-5/8"9-7/8” Hole: 159 bbls 12# class A lead cement followed by 59bbls of 15.3# Class A tail cement, bumped plug. 44bbls lost throughout job. 8/9/19 CBL (AKEL) TOC @ 2800’ MD. 4-1/2” 6-3/4” Hole: 125bbls 12# class A lead cement followed by 23bbls 15.3# tail cement. After 124bbls displacement, lost all returns. Estimated 30bbls total lost during job. Spacer and trace cement circulated off liner top back to surface. 8/29/19 CBL TOC @ 8,910’. Ratty cement spots up to 6370. RA tags:6809, 7304, 7829, 8318, 8811, 9347’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 109 / X-56 / Weld 15”Surf 120’ 10-3/4”Surface 45.5 / L-80 / TXP BTC 9.950”Surf 3,333’ 7-5/8"Intermediate 29.7 / L-80 / W563 6.875”Surf 6,824’ 4-1/2"Production 12.6 / L-80 / TXP BTC 3.958”5,365’9,800’ TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8”Tubing 6.5 / L-80 / EUE 2.441”Surf 5,391’ 2-7/8”Tubing 6.5 / L-80 / FJ3 2.30”5,402’7,885’ JEWELRY DETAIL No Depth (MD) Depth (TVD)Item 1 546’546’SSSV-Halliburton NE SRSV 2 2,821’2,272’7-5/8” Swell Packer 3 5,391’3,993’4.5” x 5.75” Bullet Tie-Back Seal Assembly 4 5,365’3,975’7-5/8” X 4-1/2” Liner Hanger 5 7,130’5,471’CIBP with 10’ of cement 7,120’ (5,461’ TVD) 03/25/22 6 7,430’5,759’Quadco Single trip cement retainer 03/19/22 7 7,886’6,199’Wireline Re-entry Guide 07/28/20 8 7,924’6,236’4.4” NEO Vented TTBP - 7,949’ w/ 25’ cement PERFORATION DETAIL Old Zone Name New Zone Name Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Date Status UB4 Upper 7,022’7,030’5,368’5,376’8’12/11/2023 Open UB4 Lower 7,036’7,043’5,382’5,388’7’12/11/2023 Open UB 4A 7,053’7,092’5,398’5,435’39’3/25&27/2022 Open UB 5A 7,138 7,158 5,479’5,498’20’3/21/2022 Plugged UB 6 7,200 7,210 5,538’5,548’10’3/21/2022 Plugged UB 7 Lower 7,303 7,311 5,637’5,644’8’3/21/2022 Plugged MB_1X 7,538'7,558'5,825'5,845'20'10/29/2021 Plugged MB_1 7,582'7,592'5,867'5,877'10'10/18/2021 Plugged MB 2 MB_4 7,727'7,747'6,045'6,065'20'12/26/2020 Plugged 7,737’7,739’6,055’6,057’2’12/26/2020 Plugged MB- 8/8A MB_6 8,028’8,042’6,336’6,350’14’9/18/2019 Plugged MB_7 8,058’8,078’6,365’6,384’20’9/18/2019 Plugged MB 3 MB_7 8,059'8,078'6,366'6,384'19'12/26/2020 Plugged MB 4 MB-7A 8,148'8,150'6,451'6,453'2'12/24/2020 Plugged MB 7A LB-1X 8,272’8,279’6,571’6,577’7’12/23/2020 Plugged 8,279'8,286'6,577'6,584'7'12/24/2020 Plugged 8,278’8,280’6,576’6,578’2 12/19/2020 Plugged LB-4 LB_16 8,565’8,577’6,852’6,863’12’9/13/2019 Plugged LB-6 LB_2 8,642’8,654’6,926’6,937’12’11/25/2019 Plugged FISH DETAIL 8,663’CIBP Debris 08/18/20 Middle Fish RBP Pushed to Bottom 9,659’CIBP Milled and Pushed to Bottom 09/11/19 Note: tbg. tail is 2.30”. _____________________________________________________________________________________ Updated by CAH 12-13-24 PROPOSED Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 OPEN HOLE / CEMENT DETAIL 10-3/4”13-1/2” Hole: 272bbls (640sx) 12# class A lead cement followed by 57bbls of 15.8# Class A tail cement. Bumped plug. Full returns throughout job. 92bbls cement back to Surface 7-5/8"9-7/8” Hole: 159 bbls 12# class A lead cement followed by 59bbls of 15.3# Class A tail cement, bumped plug. 44bbls lost throughout job. 8/9/19 CBL (AKEL) TOC @ 2800’ MD. 4-1/2” 6-3/4” Hole: 125bbls 12# class A lead cement followed by 23bbls 15.3# tail cement. After 124bbls displacement, lost all returns. Estimated 30bbls total lost during job. Spacer and trace cement circulated off liner top back to surface. 8/29/19 CBL TOC @ 8,910’. Ratty cement spots up to 6370. RA tags:6809, 7304, 7829, 8318, 8811, 9347’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 109 / X-56 / Weld 15”Surf 120’ 10-3/4”Surface 45.5 / L-80 / TXP BTC 9.950”Surf 3,333’ 7-5/8"Intermediate 29.7 / L-80 / W563 6.875”Surf 6,824’ 4-1/2"Production 12.6 / L-80 / TXP BTC 3.958”5,365’9,800’ TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8”Tubing 6.5 / L-80 / EUE 2.441”Surf 5,391’ 2-7/8”Tubing 6.5 / L-80 / FJ3 2.30”5,402’7,885’ 3/8”Cap Tubing 0.049 Duplex 2205 Surface ~7000’ JEWELRY DETAIL No Depth (MD) Depth (TVD)Item 1 546’546’SSSV-Halliburton NE SRSV Valve removed for Capillary string 2 2,821’2,272’7-5/8” Swell Packer 3 5,391’3,993’4.5” x 5.75” Bullet Tie-Back Seal Assembly 4 5,365’3,975’7-5/8” X 4-1/2” Liner Hanger 5 7,130’5,471’CIBP with 10’ of cement 7,120’ (5,461’ TVD) 03/25/22 6 7,430’5,759’Quadco Single trip cement retainer 03/19/22 7 7,886’6,199’Wireline Re-entry Guide 07/28/20 8 7,924’6,236’4.4” NEO Vented TTBP - 7,949’ w/ 25’ cement PERFORATION DETAIL Old Zone Name New Zone Name Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Date Status UB4 Upper ±7,022’±7,030’±5,368’±5,376’±8’TBD UB4 Lower ±7,036’±7,043’±5,382’±5,388’±7’TBD UB 4A ±7,053’±7,092’±5,398’±5,435’±39’TBD UB4 Upper 7,022’7,030’5,368’5,376’8’12/11/2023 Open UB4 Lower 7,036’7,043’5,382’5,388’7’12/11/2023 Open UB 4A 7,053’7,092’5,398’5,435’39’3/25&27/2022 Open UB 5A 7,138 7,158 5,479’5,498’20’3/21/2022 Plugged UB 6 7,200 7,210 5,538’5,548’10’3/21/2022 Plugged UB 7 Lower 7,303 7,311 5,637’5,644’8’3/21/2022 Plugged MB_1X 7,538'7,558'5,825'5,845'20'10/29/2021 Plugged MB_1 7,582'7,592'5,867'5,877'10'10/18/2021 Plugged MB 2 MB_4 7,727'7,747'6,045'6,065'20'12/26/2020 Plugged 7,737’7,739’6,055’6,057’2’12/26/2020 Plugged MB- 8/8A MB_6 8,028’8,042’6,336’6,350’14’9/18/2019 Plugged MB_7 8,058’8,078’6,365’6,384’20’9/18/2019 Plugged MB 3 MB_7 8,059'8,078'6,366'6,384'19'12/26/2020 Plugged MB 4 MB-7A 8,148'8,150'6,451'6,453'2'12/24/2020 Plugged MB 7A LB-1X 8,272’8,279’6,571’6,577’7’12/23/2020 Plugged 8,279'8,286'6,577'6,584'7'12/24/2020 Plugged 8,278’8,280’6,576’6,578’2 12/19/2020 Plugged LB-4 LB_16 8,565’8,577’6,852’6,863’12’9/13/2019 Plugged LB-6 LB_2 8,642’8,654’6,926’6,937’12’11/25/2019 Plugged FISH DETAIL 8,663’CIBP Debris 08/18/20 Middle Fish RBP Pushed to Bottom 9,659’CIBP Milled and Pushed to Bottom 09/11/19 Note: tbg. tail is 2.30”. Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 3/20/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240320 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 19RD 50133205790100 219188 2/2/2024 AK E-LINE Perf CLU 14 50133206840000 219078 12/11/2023 AK E-LINE Perf IRU 41-01 50283200880000 192109 11/15/2023 AK E-LINE PERF KBU 22-06Y 50133206500000 215044 12/29/2023 AK E-LINE PERF MPU C-14 50029213440000 185088 3/4/2024 AK E-LINE Whipstock MPU L-62 50029236850000 220059 3/3/2024 AK E-LINE TubingPunch NCIU A-17 50883201880000 223031 12/13/2024 AK E-LINE GPT /Plug /Perf Paxton 6 50133207070000 222054 2/27/2024 AK E-LINE Plug/Perf PBU BORE V-109 50029231200000 202202 2/13/2024 AK E-LINE TubingPunch Please include current contact information if different from above. T38657 T38658 T38659 T38660 T38661 T38662 T38663 T38664 T38665 CLU 14 50133206840000 219078 12/11/2023 AK E-LINE Perf Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.03.21 13:14:02 -08'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: ______________________ Development Exploratory 3. Address:Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: 7,130; Total Depth measured 9,802 feet 7,430; 7,949 feet true vertical 8,043 feet See schematic feet Effective Depth measured 7,120 feet See schematic feet true vertical 5,461 feet See schematic feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)2-7/8" 6.5 / L-80 / FJ3 7,885 (MD) 6,198 (TVD) Packers and SSSV (type, measured and true vertical depth)See schematic 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date:Contact Name: Contact Email: Authorized Title:Contact Phone: 4,790psi 7,500psi 3,580psi 6,890psi 8,430psi 3,333'2,616' Burst Collapse 2,090psi Casing Structural 5,183' 8,041' 6,824' 9,800' 120'Conductor Surface Intermediate 16" 10-3/4" 120' 3,333' measured TVD 7-5/8" 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-078 50-133-20684-00-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL60569 / ADL60568 / ADL324602 / Fee Private Kenai C.L.U. / Beluga Gas Cannery Loop Unit 14 Plugs Junk measured Length Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 0 Size 120' 0 0907 0 690 69 Production Liner 6,824' 4,435' Chad Helgeson, Operations Engineer 323-638 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: WINJ WAG 698 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 N/A chelgeson@hilcorp.com 907-777-8405 measured true vertical Packer Representative Daily Average Production or Injection Data p k ft t Fra O s O 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 3:09 pm, Jan 17, 2024 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.01.17 14:06:22 - 09'00' Noel Nocas (4361) DSR-1/26/24A.Dewhurst 13FEB25 RBDMS JSB 012324 Page 1/1 Well Name: CLU 014 Report Printed: 1/16/2024www.peloton.com Well Operations Summary Jobs Actual Start Date:12/5/2023 End Date: Report Number 1 Report Start Date 12/5/2023 Report End Date 12/6/2023 Operation RU Slickline, PT Lubricator to 2000 psi. good test RIH w/ bow spring cent. 3' stem 2.34'' cent index tool w/ 2.3'' cent. w/ 2.31'' baited G- fishing neck to 505'slm w/ index tool until fishing neck feels tight shear off pooh-bait sub left in hole RIH w/ 2 1/2'' GS w/ 8' stem to 505'slm latch w/ tool comes free pooh w/ sssv RIH w/ 2.25'' g-ring to 7072'slm 7110'kb sit w/ tool would not fall pooh Rig down slickline secure well for night Report Number 2 Report Start Date 12/11/2023 Report End Date 12/12/2023 Operation AKEL Arrive onsite, complete PTW and conduct PJSM. Spot Equipment, MU Lubricator and PT survey tools. Stab on lubricator PT 250/2500H - Passed RIH with PT tools to 7045' tagged and pulled 400# over to get off bottom. No fluid seen in well. Send log to town for correlation. POOH and PU perf guns. PU 2" x 7' long HC gun loaded 6 spf 60 deg phase and RIH, tag 7043' with gun, Correlate and put gun on depth. Perforate 7036-7043 with 236 psi on well. 15 min pressure 237 psi. POOH and LD Guns. All shots fired, gun was dry, no sand. Ops flowed well for 30 min, no change in rate. PU 2" x 6' HC gun loaded 6 spf 60 deg phase. SI well at 1600hrs for buildup. RIH with guns and send correlation log to geo for tie-in. Make 1' adjustment to log. Perforate UB 3 from 7022-7030' with 236 psi on well. 15 min buildup 242 psi. LD guns, dry, all shots fired. Operations flow well. RD EL. Report Number 3 Report Start Date 12/17/2023 Report End Date 12/18/2023 Operation Complete Permit, JSA, TGSM. Continue work from previous day work. PU Lubricator, RIH with 2-7/8" X-Line and SSSV. purge control line with MeOH, set SSSV at 546'. POOH Test SSSV, several times to get from out of the control line. valve functioning in 25-35 seconds. RD, Secure well. API: 50-133-20684-00-00 Field: Cannery Loop Sundry #: 323-638 State: Alaska Rig/Service:Permit to Drill (PTD) #:219-078 _____________________________________________________________________________________ Updated by DMA 01-05-24 SCHEMATIC Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 OPEN HOLE / CEMENT DETAIL 10-3/4”13-1/2” Hole: 272bbls (640sx) 12# class A lead cement followed by 57bbls of 15.8# Class A tail cement. Bumped plug. Full returns throughout job. 92bbls cement back to Surface 7-5/8"9-7/8” Hole: 159 bbls 12# class A lead cement followed by 59bbls of 15.3# Class A tail cement, bumped plug. 44bbls lost throughout job. 8/9/19 CBL (AKEL) TOC @ 2800’ MD. 4-1/2” 6-3/4” Hole: 125bbls 12# class A lead cement followed by 23bbls 15.3# tail cement. After 124bbls displacement, lost all returns. Estimated 30bbls total lost during job. Spacer and trace cement circulated off liner top back to surface. 8/29/19 CBL TOC @ 8,910’. Ratty cement spots up to 6370. RA tags:6809, 7304, 7829, 8318, 8811, 9347’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 109 / X-56 / Weld 15”Surf 120’ 10-3/4”Surface 45.5 / L-80 / TXP BTC 9.950”Surf 3,333’ 7-5/8"Intermediate 29.7 / L-80 / W563 6.875”Surf 6,824’ 4-1/2"Production 12.6 / L-80 / TXP BTC 3.958”5,365’9,800’ TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8”Tubing 6.5 / L-80 / EUE 2.441”Surf 5,391’ 2-7/8”Tubing 6.5 / L-80 / FJ3 2.30”5,402’7,885’ JEWELRY DETAIL No Depth (MD) Depth (TVD)Item 1 546’546’SSSV-Halliburton NE SRSV 2 2,821’2,272’7-5/8” Swell Packer 3 5,391’3,993’4.5” x 5.75” Bullet Tie-Back Seal Assembly 4 5,365’3,975’7-5/8” X 4-1/2” Liner Hanger 5 7,130’5,471’CIBP with 10’ of cement 7,120’ (5,461’ TVD) 03/25/22 6 7,430’5,759’Quadco Single trip cement retainer 03/19/22 7 7,886’6,199’Wireline Re-entry Guide 07/28/20 8 7,924’6,236’4.4” NEO Vented TTBP - 7,949’ w/ 25’ cement PERFORATION DETAIL Old Zone Name New Zone Name Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Date Status UB4 Upper 7,022’7,030’5,368’5,376’8’12/11/2023 Open UB4 Lower 7,036’7,043’5,382’5,388’7’12/11/2023 Open UB 4A 7,053’7,092’5,398’5,435’39’3/25&27/2022 Open UB 5A 7,138 7,158 5,479’5,498’20’3/21/2022 Plugged UB 6 7,200 7,210 5,538’5,548’10’3/21/2022 Plugged UB 7 Lower 7,303 7,311 5,637’5,644’8’3/21/2022 Plugged MB_1X 7,538'7,558'5,825'5,845'20'10/29/2021 Plugged MB_1 7,582'7,592'5,867'5,877'10'10/18/2021 Plugged MB 2 MB_4 7,727'7,747'6,045'6,065'20'12/26/2020 Plugged 7,737’7,739’6,055’6,057’2’12/26/2020 Plugged MB- 8/8A MB_6 8,028’8,042’6,336’6,350’14’9/18/2019 Plugged MB_7 8,058’8,078’6,365’6,384’20’9/18/2019 Plugged MB 3 MB_7 8,059'8,078'6,366'6,384'19'12/26/2020 Plugged MB 4 MB-7A 8,148'8,150'6,451'6,453'2'12/24/2020 Plugged MB 7A LB-1X 8,272’8,279’6,571’6,577’7’12/23/2020 Plugged 8,279'8,286'6,577'6,584'7'12/24/2020 Plugged 8,278’8,280’6,576’6,578’2 12/19/2020 Plugged LB-4 LB_16 8,565’8,577’6,852’6,863’12’9/13/2019 Plugged LB-6 LB_2 8,642’8,654’6,926’6,937’12’11/25/2019 Plugged FISH DETAIL 8,663’CIBP Debris 08/18/20 Middle Fish RBP Pushed to Bottom 9,659’CIBP Milled and Pushed to Bottom 09/11/19 Note: tbg. tail is 2.30”. 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): 9,802'See Schematic Casing Collapse Structural Conductor Surface 2,090psi Intermediate 4,790psi Production 7,500psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng See Schematic See Schematic 8,043'7,120'5,461' Kenai C.L.U.Beluga Gas 16" 10-3/4" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Cannery Loop Unit (CLU) 14CO 231A Same 8,041'4-1/2" ~1831psi 4,435' 7130, 7430, 7924 Length December 1, 2023 2-7/8" 9,800' Perforation Depth MD (ft): 6,824' See Attached Schematic 6,890psi 3,580psi 120' 5,183' 120' 3,333' Size 120' 7-5/8"6,824' 3,333' MD Hilcorp Alaska, LLC Proposed Pools: 6.5# / L-80 / FJ3 TVD Burst 7,885' 8,430psi 2,616' 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 ADL0060568|ADL0060569|ADL0324602|FEE-PRIVATE 219-078 50-133-20684-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior writte n approval. Authorized Name and Digital Signature with Date: m n P s 66 t _ N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 10:46 am, Nov 22, 2023 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.11.21 16:15:24 - 09'00' Noel Nocas (4361) 323-638 DSR-11/22/23BJM 11/27/23 10-404 SFD 11/24/2023 Perforate JLC 11/29/2023 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.11.29 15:12:05 -09'00'11/29/23 RBDMS JSB 113023 Well: CLU-14 11/16/23 Well Name: CLU-14 API Number: 50-133-20684-00-00 Current Status: Gas Producer Permit to Drill Number: 219-078 First Call Engineer: Chad Helgeson (907) 777-8504 (O) (907) 229-4824 (C) Second Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C) Max. Expected BHP: ~2,369 psi @ 5,385’ TVD Based on a 0.44psi/ft gradient. Max. Potential Surface Pressure: ~1831 psi @ 5,385’ TVD Gas gradient to surface @ 0.1 psi/ft Well Summary CLU 14 is a gas producer that was drilled and completed in August 2019 targeting gas sands in the Beluga and Sterling formations. In August of 2020 a 2-7/8” velocity string was installed in the well. A CIBP that provided well control during the running of the 2-7/8” velocity string was drilled up through the 2-7/8” string and pushed to bottom. In October the tubing conveyed SCSSSV failed to close. This valve was pinned open and a WLR SCSSSV was installed in its profile. In January 2021, the SSSV was pulled and a capillary line installed to help unload water. In October 2021, the MB6 sands were plugged back and the MB1 was perforated through tubing, where the zone made a little gas, but immediately watered up at rates over 1,000 bwpd. In 2022 these zones were plugged back and additional Upper Beluga sands were perforated. Objective The objective of this job is to add additional perfs for winter gas supply needs. The proposed zones were part of an approved sundry (Sundry # 322-098) in 2022, but were not perforated on that job. Wellbore Notes: x Current T/IA/OA – 15/0/0 x CO 231A Rule 2 & 3. This well already exists solely in the Beluga Gas Pool, and will not perforate any sands within 100ft of CINGSA Pool x WRSV is currently installed in well x CINGSA Pool bottom – 6,787’ (5,148’ TVD) x WRSV will be pulled prior to job and reinstalled and tested after job is complete E-Line Perf 1. Review all approved COAs 2. MIRU E-line and pressure control equipment. PT lubricator to 250psi low / 2,500 psi High 3. SI well for buildup 4. PU and RIH with perf gun a) May shoot small 2ft gun (4spf) for equalization of zone prior to perforating main zone. 5. Perforate Upper Beluga sands per RE/Geo from bottom up testing each zone individually. Sand Perforation Top (MD) Perforation Bottom (MD) Perforation Top (TVD) Perforation Bottom (TVD) Total Footage (MD) UB Upper ±7,022’ ±7,030’ ±5,368’ ±5,376’ ±8’ UB Lower ±7,036’ ±7,043’ ±5,382’ ±5,388’ ±7’ a. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. Well: CLU-14 11/16/23 b. Record initial and 5/10/15 minute tubing pressures after firing 6. RD E-Line Unit and turn well over to production 7. Operations to flow well and test zones 8. Test SSSV as reequired within 5 days after reinstalling valve E-line Procedure (Contingency) If any zone produces sand and/or water or needs isolated: 1. MIRU Eline 2. Pressure test equipment to 2,500 psi High/250 psi Low 3. Eline run PT to find fluid level (Pressure up with N2 if needed) 4. Push fluid below perfs (verify fluid depth with PT tool) 5. PU 2-7/8” CIBP or Patch and set above perfs or patch across perfs that made water Coil tubing procedure (Contingency) If plug does not get below proposed perfs and SL cannot bail enough fill: a. MIRU Coiled Tubing Unit, PT BOPE to 2,500 psi High/250 psi Low b. Provide AOGCC 24hrs notice of BOP test c. PU CT jet nozzle and cleanout well to top of open perfs d. POOH with coil e. RDMO coil tubing f. Complete Eline, plugs/patch or perfs as necessary Attachments: 1. Current schematic 2. Proposed Schematic _____________________________________________________________________________________ Updated by CAH 04-21-22 SCHEMATIC Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 OPEN HOLE / CEMENT DETAIL 10-3/4”13-1/2” Hole: 272bbls (640sx) 12# class A lead cement followed by 57bbls of 15.8# Class A tail cement. Bumped plug. Full returns throughout job. 92bbls cement back to Surface 7-5/8"9-7/8” Hole: 159 bbls 12# class A lead cement followed by 59bbls of 15.3# Class A tail cement, bumped plug. 44bbls lost throughout job. 8/9/19 CBL (AKEL) TOC @ 2800’ MD. 4-1/2” 6-3/4” Hole: 125bbls 12# class A lead cement followed by 23bbls 15.3# tail cement. After 124bbls displacement, lost all returns. Estimated 30bbls total lost during job. Spacer and trace cement circulated off liner top back to surface. 8/29/19 CBL TOC @ 8,910’ratty cement spots up to 6370. RA tags:6809, 7304, 7829, 8318, 8811, 9347’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 109 / X-56 / Weld 15”Surf 120’ 10-3/4”Surface 45.5 / L-80 / TXP BTC 9.950”Surf 3,333’ 7-5/8"Intermediate 29.7 / L-80 / W563 6.875”Surf 6,824’ 4-1/2"Production 12.6 / L-80 / TXP BTC 3.958”5,365’9,800’ TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8”Tubing 6.5/L-80/EUE 2.441”Surf 5,391’ 2-7/8”Tubing 6.5 / L-80 / FJ3 2.30”5,402’7,885’ JEWELRY DETAIL No Depth (MD) Depth (TVD)Item 1 531’531’SSSV-Halliburton NE SRSV 2 2,821’2,272’7-5/8” Swell Packer 3 5,391’3,993’4.5” x 5.75” Bullet Tie-Back Seal Assembly 4 5,365’3,975’7-5/8” X 4-1/2” Liner Hanger 5 7,130’5,471’CIBP with 10’ of cement 7,120’ (5,461’ TVD) 03/25/22 6 7,430’5,759’Quadco Single trip cement retainer 03/19/22 7 7,886’6,199’Wireline Re-entry Guide 07/28/20 8 7,924’6,236’4.4” NEO Vented TTBP - 7,949’ w/ 25’ cement PERFORATION DETAIL Old Zone Name New Zone Name Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Date Status UB 4A 7,053’7,092’5,398’5,435’39’3/25&27/2022 Open UB 5A 7,138 7,158 5,479’5,498’20’3/21/2022 Plugged UB 6 7,200 7,210 5,538’5,548’10’3/21/2022 Plugged UB 7 Lower 7,303 7,311 5,637’5,644’8’3/21/2022 Plugged MB_1X 7,538'7,558'5,825'5,845'20'10/29/2021 Plugged MB_1 7,582'7,592'5,867'5,877'10'10/18/2021 Plugged MB 2 MB_4 7,727'7,747'6,045'6,065'20'12/26/2020 Plugged 7,737’7,739’6,055’6,057’2’12/26/2020 Plugged MB- 8/8A MB_6 8,028’8,042’6,336’6,350’14’9/18/2019 Plugged MB_7 8,058’8,078’6,365’6,384’20’9/18/2019 Plugged MB 3 MB_7 8,059'8,078'6,366'6,384'19'12/26/2020 Plugged MB 4 MB-7A 8,148'8,150'6,451'6,453'2'12/24/2020 Plugged MB 7A LB-1X 8,272’8,279’6,571’6,577’7’12/23/2020 Plugged 8,279'8,286'6,577'6,584'7'12/24/2020 Plugged 8,278’8,280’6,576’6,578’2 12/19/2020 Plugged LB-4 LB_16 8,565’8,577’6,852’6,863’12’9/13/2019 Plugged LB-6 LB_2 8,642’8,654’6,926’6,937’12’11/25/2019 Plugged FISH DETAIL 8,663’CIBP Debris 08/18/20 Middle Fish RBP Pushed to Bottom 9,659’CIBP Milled and Pushed to Bottom 09/11/19 Note: tbg. tail is 2.30”. _____________________________________________________________________________________ Updated by CAH 11-16-23 PROPOSED Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 OPEN HOLE / CEMENT DETAIL 10-3/4”13-1/2” Hole: 272bbls (640sx) 12# class A lead cement followed by 57bbls of 15.8# Class A tail cement. Bumped plug. Full returns throughout job. 92bbls cement back to Surface 7-5/8"9-7/8” Hole: 159 bbls 12# class A lead cement followed by 59bbls of 15.3# Class A tail cement, bumped plug. 44bbls lost throughout job. 8/9/19 CBL (AKEL) TOC @ 2800’ MD. 4-1/2” 6-3/4” Hole: 125bbls 12# class A lead cement followed by 23bbls 15.3# tail cement. After 124bbls displacement, lost all returns. Estimated 30bbls total lost during job. Spacer and trace cement circulated off liner top back to surface. 8/29/19 CBL TOC @ 8,910’. Ratty cement spots up to 6370. RA tags:6809, 7304, 7829, 8318, 8811, 9347’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 109 / X-56 / Weld 15”Surf 120’ 10-3/4”Surface 45.5 / L-80 / TXP BTC 9.950”Surf 3,333’ 7-5/8"Intermediate 29.7 / L-80 / W563 6.875”Surf 6,824’ 4-1/2"Production 12.6 / L-80 / TXP BTC 3.958”5,365’9,800’ TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8”Tubing 6.5/L-80/EUE 2.441”Surf 5,391’ 2-7/8”Tubing 6.5 / L-80 / FJ3 2.30”5,402’7,885’ JEWELRY DETAIL No Depth (MD) Depth (TVD)Item 1 531’531’SSSV-Halliburton NE SRSV 2 2,821’2,272’7-5/8” Swell Packer 3 5,391’3,993’4.5” x 5.75” Bullet Tie-Back Seal Assembly 4 5,365’3,975’7-5/8” X 4-1/2” Liner Hanger 5 7,130’5,471’CIBP with 10’ of cement 7,120’ (5,461’ TVD) 03/25/22 6 7,430’5,759’Quadco Single trip cement retainer 03/19/22 7 7,886’6,199’Wireline Re-entry Guide 07/28/20 8 7,924’6,236’4.4” NEO Vented TTBP - 7,949’ w/ 25’ cement PERFORATION DETAIL Old Zone Name New Zone Name Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Date Status UB Upper ±7,022’±7,030’±5,368’±5,376’±8’TBD Proposed UB Lower ±7,036’±7,043’±5,382’±5,388’±7’TBD Proposed UB 4A 7,053’7,092’5,398’5,435’39’3/25&27/2022 Open UB 5A 7,138 7,158 5,479’5,498’20’3/21/2022 Plugged UB 6 7,200 7,210 5,538’5,548’10’3/21/2022 Plugged UB 7 Lower 7,303 7,311 5,637’5,644’8’3/21/2022 Plugged MB_1X 7,538'7,558'5,825'5,845'20'10/29/2021 Plugged MB_1 7,582'7,592'5,867'5,877'10'10/18/2021 Plugged MB 2 MB_4 7,727'7,747'6,045'6,065'20'12/26/2020 Plugged 7,737’7,739’6,055’6,057’2’12/26/2020 Plugged MB- 8/8A MB_6 8,028’8,042’6,336’6,350’14’9/18/2019 Plugged MB_7 8,058’8,078’6,365’6,384’20’9/18/2019 Plugged MB 3 MB_7 8,059'8,078'6,366'6,384'19'12/26/2020 Plugged MB 4 MB-7A 8,148'8,150'6,451'6,453'2'12/24/2020 Plugged MB 7A LB-1X 8,272’8,279’6,571’6,577’7’12/23/2020 Plugged 8,279'8,286'6,577'6,584'7'12/24/2020 Plugged 8,278’8,280’6,576’6,578’2 12/19/2020 Plugged LB-4 LB_16 8,565’8,577’6,852’6,863’12’9/13/2019 Plugged LB-6 LB_2 8,642’8,654’6,926’6,937’12’11/25/2019 Plugged FISH DETAIL 8,663’CIBP Debris 08/18/20 Middle Fish RBP Pushed to Bottom 9,659’CIBP Milled and Pushed to Bottom 09/11/19 Note: tbg. tail is 2.30”. _____________________________________________________________________________________ Updated by CAH 04-21-22 SCHEMATIC Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 OPEN HOLE / CEMENT DETAIL 10-3/4”13-1/2” Hole: 272bbls (640sx) 12# class A lead cement followed by 57bbls of 15.8# Class A tail cement. Bumped plug. Full returns throughout job. 92bbls cement back to Surface 7-5/8"9-7/8” Hole: 159 bbls 12# class A lead cement followed by 59bbls of 15.3# Class A tail cement, bumped plug. 44bbls lost throughout job. 8/9/19 CBL (AKEL) TOC @ 2800’ MD. 4-1/2” 6-3/4” Hole: 125bbls 12# class A lead cement followed by 23bbls 15.3# tail cement. After 124bbls displacement, lost all returns. Estimated 30bbls total lost during job. Spacer and trace cement circulated off liner top back to surface. 8/29/19 CBL TOC @ 8,910’. RA tags:6809, 7304, 7829, 8318, 8811, 9347’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 109 / X-56 / Weld 15”Surf 120’ 10-3/4”Surface 45.5 / L-80 / TXP BTC 9.950”Surf 3,333’ 7-5/8"Intermediate 29.7 / L-80 / W563 6.875”Surf 6,824’ 4-1/2"Production 12.6 / L-80 / TXP BTC 3.958”5,365’9,800’ TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8”Tubing 6.5 / L-80 / EUE 2.441”Surf 5,391’ 2-7/8”Tubing 6.5 / L-80 / FJ3 2.30”5,402’7,885’ JEWELRY DETAIL No Depth (MD) Depth (TVD)Item 1 531’531’SSSV-Halliburton NE SRSV 2 2,821’2,272’7-5/8” Swell Packer 3 5,391’3,993’4.5” x 5.75” Bullet Tie-Back Seal Assembly 4 5,365’3,975’7-5/8” X 4-1/2” Liner Hanger 5 7,130’5,471’CIBP with 10’ of cement 7,120’ (5,461’ TVD) 03/25/22 6 7,430’5,759’Quadco Single trip cement retainer 03/19/22 7 7,886’6,199’Wireline Re-entry Guide 07/28/20 8 7,924’6,236’4.4” NEO Vented TTBP - 7,949’ w/ 25’ cement PERFORATION DETAIL Old Zone Name New Zone Name Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Date Status UB 4A 7,053’7,092’5,398’5,435’39’3/25&27/2022 Open UB 5A 7,138 7,158 5,479’5,498’20’3/21/2022 Plugged UB 6 7,200 7,210 5,538’5,548’10’3/21/2022 Plugged UB 7 Lower 7,303 7,311 5,637’5,644’8’3/21/2022 Plugged MB_1X 7,538'7,558'5,825'5,845'20'10/29/2021 Plugged MB_1 7,582'7,592'5,867'5,877'10'10/18/2021 Plugged MB 2 MB_4 7,727'7,747'6,045'6,065'20'12/26/2020 Plugged 7,737’7,739’6,055’6,057’2’12/26/2020 Plugged MB- 8/8A MB_6 8,028’8,042’6,336’6,350’14’9/18/2019 Plugged MB_7 8,058’8,078’6,365’6,384’20’9/18/2019 Plugged MB 3 MB_7 8,059'8,078'6,366'6,384'19'12/26/2020 Plugged MB 4 MB-7A 8,148'8,150'6,451'6,453'2'12/24/2020 Plugged MB 7A LB-1X 8,272’8,279’6,571’6,577’7’12/23/2020 Plugged 8,279'8,286'6,577'6,584'7'12/24/2020 Plugged 8,278’8,280’6,576’6,578’2 12/19/2020 Plugged LB-4 LB_16 8,565’8,577’6,852’6,863’12’9/13/2019 Plugged LB-6 LB_2 8,642’8,654’6,926’6,937’12’11/25/2019 Plugged FISH DETAIL 8,663’CIBP Debris 08/18/20 Middle Fish RBP Pushed to Bottom 9,659’CIBP Milled and Pushed to Bottom 09/11/19 Note: tbg. tail is 2.30”. Superseded _____________________________________________________________________________________ Updated by CAH 11-16-23 PROPOSED Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 OPEN HOLE / CEMENT DETAIL 10-3/4”13-1/2” Hole: 272bbls (640sx) 12# class A lead cement followed by 57bbls of 15.8# Class A tail cement. Bumped plug. Full returns throughout job. 92bbls cement back to Surface 7-5/8"9-7/8” Hole: 159 bbls 12# class A lead cement followed by 59bbls of 15.3# Class A tail cement, bumped plug. 44bbls lost throughout job. 8/9/19 CBL (AKEL) TOC @ 2800’ MD. 4-1/2” 6-3/4” Hole: 125bbls 12# class A lead cement followed by 23bbls 15.3# tail cement. After 124bbls displacement, lost all returns. Estimated 30bbls total lost during job. Spacer and trace cement circulated off liner top back to surface. 8/29/19 CBL TOC @ 8,910’. RA tags:6809, 7304, 7829, 8318, 8811, 9347’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 109 / X-56 / Weld 15”Surf 120’ 10-3/4”Surface 45.5 / L-80 / TXP BTC 9.950”Surf 3,333’ 7-5/8"Intermediate 29.7 / L-80 / W563 6.875”Surf 6,824’ 4-1/2"Production 12.6 / L-80 / TXP BTC 3.958”5,365’9,800’ TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8”Tubing 6.5 / L-80 / EUE 2.441”Surf 5,391’ 2-7/8”Tubing 6.5 / L-80 / FJ3 2.30”5,402’7,885’ JEWELRY DETAIL No Depth (MD) Depth (TVD)Item 1 531’531’SSSV-Halliburton NE SRSV 2 2,821’2,272’7-5/8” Swell Packer 3 5,391’3,993’4.5” x 5.75” Bullet Tie-Back Seal Assembly 4 5,365’3,975’7-5/8” X 4-1/2” Liner Hanger 5 7,130’5,471’CIBP with 10’ of cement 7,120’ (5,461’ TVD) 03/25/22 6 7,430’5,759’Quadco Single trip cement retainer 03/19/22 7 7,886’6,199’Wireline Re-entry Guide 07/28/20 8 7,924’6,236’4.4” NEO Vented TTBP - 7,949’ w/ 25’ cement PERFORATION DETAIL Old Zone Name New Zone Name Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Date Status UB Upper ±7,022’±7,030’±5,368’±5,376’±8’TBD Proposed UB Lower ±7,036’±7,043’±5,382’±5,388’±7’TBD Proposed UB 4A 7,053’7,092’5,398’5,435’39’3/25&27/2022 Open UB 5A 7,138 7,158 5,479’5,498’20’3/21/2022 Plugged UB 6 7,200 7,210 5,538’5,548’10’3/21/2022 Plugged UB 7 Lower 7,303 7,311 5,637’5,644’8’3/21/2022 Plugged MB_1X 7,538'7,558'5,825'5,845'20'10/29/2021 Plugged MB_1 7,582'7,592'5,867'5,877'10'10/18/2021 Plugged MB 2 MB_4 7,727'7,747'6,045'6,065'20'12/26/2020 Plugged 7,737’7,739’6,055’6,057’2’12/26/2020 Plugged MB- 8/8A MB_6 8,028’8,042’6,336’6,350’14’9/18/2019 Plugged MB_7 8,058’8,078’6,365’6,384’20’9/18/2019 Plugged MB 3 MB_7 8,059'8,078'6,366'6,384'19'12/26/2020 Plugged MB 4 MB-7A 8,148'8,150'6,451'6,453'2'12/24/2020 Plugged MB 7A LB-1X 8,272’8,279’6,571’6,577’7’12/23/2020 Plugged 8,279'8,286'6,577'6,584'7'12/24/2020 Plugged 8,278’8,280’6,576’6,578’2 12/19/2020 Plugged LB-4 LB_16 8,565’8,577’6,852’6,863’12’9/13/2019 Plugged LB-6 LB_2 8,642’8,654’6,926’6,937’12’11/25/2019 Plugged FISH DETAIL 8,663’CIBP Debris 08/18/20 Middle Fish RBP Pushed to Bottom 9,659’CIBP Milled and Pushed to Bottom 09/11/19 Note: tbg. tail is 2.30”. Superseded CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Chad Helgeson To:McLellan, Bryan J (OGC) Cc:Donna Ambruz Subject:RE: [EXTERNAL] RE: CLU-14 (PTD 219-078) perf sundry Date:Wednesday, November 29, 2023 7:56:46 AM Attachments:CLU 14 PROPOSED Schematic 11-29-23.pdf CLU 14 Schematic 11-27-23.pdf Bryan, Attached are updated current and proposed schematics. I also spent some time with our tech team reviewing the CBL, and revised the comment about the TOC in the notes. Our thoughts on the CBL are is it doesn’t look great. Based on collars we know that there isn’t much free pipe, indicating probably some cement and therefore added a comment about ratty cement up to 6370. Let me know if you need anything else. Chad From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, November 27, 2023 2:43 PM To: Chad Helgeson <chelgeson@hilcorp.com> Subject: [EXTERNAL] RE: CLU-14 (PTD 219-078) perf sundry I see where you already mentioned the base of the CINGSA gas storage pool and it is behind the 7- 5/8” intermediate casing which is cemented in place, so no need to answer that question. The wellbore diagram incorrectly indicates cement to the top of the 4-1/2” liner top, but the CBL found TOC at 8910’ MD. Can you send corrected wellbore diagrams to include in the sundry? Thanks Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: McLellan, Bryan J (OGC) Sent: Monday, November 27, 2023 2:31 PM To: chelgeson@hilcorp.com Subject: CLU-14 (PTD 219-078) perf sundry Chad, What’s the depth of the C1 storage sand in this well? Checking to see if there are any issues with perforating close to it. Looks like the 4-1/2” TOC is 8910’ MD and the proposed perfs are above that, so want to make sure the storage pool is cemented behind 7-5/8” casing. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. 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ůŽƐĞĐŚŽŬĞĂŶĚŚĞƐŝƚĂƚĞƐƋƵĞĞǌĞƚŚĞƌĞŵĂŝŶŝŶŐϰ͘ϱďďůƐŽĨĐĞŵĞŶƚĨƌŽŵϳϱϯϴ͘/ŶŝƚŝĂůt,WďĞĨŽƌĞĐĞŵĞŶƚŝƐϱϬƉƐŝ͕ĨŝŶĂů ƉƌĞƐƐƵƌĞŽĨϭϴϬƉƐŝ͘WƵůůƵƉŚŽůĞƚŽϳϰϴϴΖĂŶĚĐŝƌĐƵůĂƚĞϮǆĐŽŝůǆƚƵďŝŶŐǀŽůƵŵĞǁŚŝůĞŚŽůĚŝŶŐϭϴϬƉƐŝŽŶĐŚŽŬĞ͘ ůŽƐĞĐŚŽŬĞĂŶĚWKK,ƉƵŵƉŝŶŐƉŝƉĞĚŝƐƉůĂĐĞŵĞŶƚŚŽůĚŝŶŐϭϴϬƉƐŝ͘ŽŝůĂƚƐƵƌĨĂĐĞ͘ůŽƐĞŝŶƐǁĂď͘ >ĂǇĚŽǁŶůƵďƌŝĐĂƚŽƌĂŶĚ,͘/ŶƐƚĂůůŶŝŐŚƚĐĂƉŽŶKWΖƐ͘ ^&E͘ ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ϯͬϭϲͬϮϮ ϰͬϴͬϮϮ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞĞŬůǇKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ >hͲϭϰϱϬͲϭϯϯͲϮϬϲϴϰͲϬϬͲϬϬ ϮϭϵͲϬϳϴ ϬϯͬϭϴͬϮϬϮϮͲ&ƌŝĚĂǇ ϬϯͬϭϵͬϮϬϮϮͲ^ĂƚƵƌĚĂǇ ^>ŽŶůŽĐĂƚŝŽŶĂŶĚǁĂƌŵƵƉĞƋƵŝƉŵĞŶƚ͘ ŝƌĐƵůĂƚĞǁĂƚĞƌŽƵƚƚŽƚĂŶŬ͘KƉĞŶǁĞůů͘dƵďŝŶŐƉƌĞƐƐƵƌĞсϱϬƉƐŝ͘ WƵŵƉǁĂƚĞƌĚŽǁŶǁĞůůĂƚϬ͘ϱďƉŵ͘WƌĞƐƐƵƌĞƌĞĂĐŚĞƐϮϬϬϬƉƐŝĂĨƚĞƌƉƵŵƉŝŶŐϲ͘ϱďďůƐ͘^ŚƵƚĚŽǁŶƉƵŵƉŝŶŐ͘ ^ƚĂƌƚŝŶŐƉƌĞƐƐƵƌĞсϮϬϭϱƉƐŝ͘ ϭŵŝŶсϭϳϳϬƉƐŝ ϮŵŝŶсϭϲϰϬƉƐŝ ϯŵŝŶсϭϱϱϬƉƐŝ ϰŵŝŶсϭϱϬϬƉƐŝ ϱŵŝŶсϭϰϱϬƉƐŝ͘ZĞǀŝĞǁĞĚĚĂƚĂǁŝƚŚŶŐŝŶĞĞƌ͕ĚĞƚĞƌŵŝŶĞĚďĞƐƚƉĂƚŚĨŽƌǁĂƌĚǁĂƐĂĚĚŝŶŐŵŽƌĞĐĞŵĞŶƚŝŶŶĞǆƚƐƚĞƉĂŶĚ ĐŽŶƚŝŶƵŝŶŐĂŚĞĂĚ͘ z:ͲůŝŶĞŽŶůŽĐĂƚŝŽŶ͘ŽŶĚƵĐƚ:^ĂŶĚĂƉƉƌŽǀĞWdt͘ DhůƵďƌŝĐĂƚŽƌĂŶĚϮƐĞƚƐŽĨϭͲϭϭͬϭϲΗƚƵďŝŶŐƉƵŶĐŚĞƐǁŝƚŚƐǁŝƚĐŚŝŶďĞƚǁĞĞŶ͘ 'Zͬ>ƚŽϭƐƚŐƵŶсϭϳ͘ϬΖ 'Zͬ>ƚŽϮŶĚŐƵŶсϭϬ͘ϱΖ 'ŽƚŽƚŚĞǁĞůůĂŶĚWdƚŽϮϱϬƉƐŝůŽǁͬϮϱϬϬƉƐŝŚŝŐŚ͘KƉĞŶǁĞůůĂŶĚZ/,͘ŽƌƌĞůĂƚĞƚŽƉƌĞǀŝŽƵƐƉĞƌĨůŽŐ͘dĂŐĂƚϳϱϱϯΖ ;ĐŽƌƌĞĐƚĞĚͿ WƵŶĐŚƚƵďŝŶŐĨƌŽŵϳϰϳϬͲϳϰϳϯΖ WƵŶĐŚƚƵďŝŶŐĨƌŽŵϲϴϮϴͲϲϴϯϭΖ WKK,͘ĐŽŶĨŝƌŵĂůůƉƵŶĐŚĞƐƐŚŽƚ͘ >ĂǇĚŽǁŶƚŽŽůƐƚƌŝŶŐ͘ͲůŝŶĞĚĞƉĂƌƚ͘^>ĐŽŝůĞĚƚƵďŝŶŐŽŶůŽĐĂƚŝŽŶ͘tĂƌŵƵƉĞƋƵŝƉŵĞŶƚ͘ WŝĐŬƵƉŝŶũĞĐƚŽƌĂŶĚůƵďƌŝĐĂƚŽƌ͘ DhYƵĂĚĐŽĐŽŝůĐŽŶŶĞĐƚŽƌĂŶĚƉƵůůƚĞƐƚ͘ &ůƵŝĚƉĂĐŬĐŽŝůĂŶĚWdƚŽϯϱϬϬƉƐŝ͘DhYƵĂĚĐŽŽŶĞͲƚƌŝƉĐĞŵĞŶƚƌĞƚĂŝŶĞƌ͘ 'ŽƚŽƚŚĞǁĞůůĂŶĚWdƚŽϮϱϬƉƐŝůŽǁͬϰϬϬϬƉƐŝŚŝŐŚ͘KƉĞŶǁĞůů͘tĞůůŚĂƐϭϮϬϬƉƐŝ͘ ůĞĞĚŽĨĨƉƌĞƐƐƵƌĞƚŽƚĂŶŬ͕ŐĂƐƌĞƚƵƌŶƐ͘'ĂƐĨƌŽŵƵŶĚĞƌŶĞĂƚŚůŝŶĞƌŚĂŶŐĞƌĨŽůůŽǁŝŶŐƚƵďŝŶŐƉƵŶĐŚĞƐ͘ Z/,͘ tƚĐŚĞĐŬĂƚϱϬϬϬΖсϭϲŬ tƚĐŚĞĐŬĂƚϳϬϬϬΖсϮϰŬ͘Z/,ǁŝƚŚĐŽŝůƚŽϳϰϲϬΖ͘Wh,ŝŶƚĞŶƐŝŽŶƚŽƐĞƚƚŝŶŐĚĞƉƚŚŽĨϳϰϯϬΖ;ĞͿ͕ϳϰϮϵΖ;ŵͿ͘ WƵŵƉĚŽǁŶďĂĐŬƐŝĚĞƚŽƚĞƐƚĐĂƐŝŶŐǁŝƚŚƚƵďŝŶŐƉƵŶĐŚĞƐ͘ WƵŵƉϭϮ͘ϯďďůƐƚŽƌĞĂĐŚϮϬϬϬƉƐŝ͘ƉƌĞƐƐƵƌĞсϭϰϳϬƉƐŝŝŶϱŵŝŶƵƚĞƐ͘ƐĂŵĞĂƐƉƌŝŽƌƚŽƉƵŶĐŚĞƐ͘ ůĞĞĚƉƌĞƐƐƵƌĞĚŽǁŶƚŽϬƉƐŝ͘ƌŽƉϭͬϮΗďĂůůƚŽƐĞƚƌĞƚĂŝŶĞƌ͘ ĂůůŽŶƐĞĂƚĂƚϮϲ͘ϰďďůƐ͘ĐƚŝǀĂƚĞƐĞƚƚŝŶŐƚŽŽůĂƚΛϯϭϬϬƉƐŝ͘ ^ĞƚĚŽǁŶϲŬƚŽĐŽŶĨŝƌŵƌĞƚĂŝŶĞƌƐĞƚ͘ ƐƚĂďůŝƐŚĐŝƌĐƵůĂƚŝŽŶƚŚƌŽƵŐŚƌĞƚĂŝŶĞƌĂŶĚƚŚƌŽƵŐŚƚƵďŝŶŐƉƵŶĐŚĞƐ͘Ϭ͘ϲďƉŵΛϳϬϬƉƐŝ͘^ƚĂƌƚŵŝǆŝŶŐĐĞŵĞŶƚ͘ĞŵĞŶƚŝƐ ΖtĞƚΖĂƚϭϴ͗ϬϬ͘ ĂƚĐŚŵŝǆϳďďůƐ͕͘^ĐĂůĞǁƚсϭϱ͘ϬƉƉŐ͘ ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ϯͬϭϲͬϮϮ ϰͬϴͬϮϮ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞĞŬůǇKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ >hͲϭϰϱϬͲϭϯϯͲϮϬϲϴϰͲϬϬͲϬϬ ϮϭϵͲϬϳϴ ϬϯͬϮϬͬϮϬϮϮͲ^ƵŶĚĂǇ zĞůůŽǁ:ĂĐŬĞƚͲůŝŶĞĂƌƌŝǀĞŽŶůŽĐĂƚŝŽŶ͘ŽŶĚƵĐƚ:^ĂŶĚĂƉƉƌŽǀĞWdt͘ DhϭͲϭϭͬϭϲΗ>ǁŝƚŚĐĞŶƚƌĂůŝǌĞƌƐ͘hŶĂďůĞƚŽŐĞƚďĞůŽǁϭϰϵϬΖ͘ WKK,ĂŶĚĐŚĂŶŐĞƚŽŽůƐƚƌŝŶŐƚŽϭͲϭϭͬϭϲΗǁƚďĂƌƐ;ǆϮͿĂŶĚ>͘Z/,ĂŶĚƚĂŐĂƚϳϯϵϴΖ͘ƚƚĞŵƉƚƚŽZ/,ǁŝƚŚ>ǁͬ ĐĞŶƚƌĂůŝǌĞƌƐĂŶĚǁƚďĂƌ͘^ĞƚĚŽǁŶĂƚϭϳϴϬΖ͘ WKK,ĂŶĚƌĞŵŽǀĞĐĞŶƚƌĂůŝǌĞƌƐĨƌŽŵ>͘Z/,ǁŝƚŚŶŽŽďƐƚƌƵĐƚŝŽŶ͘ &ŝŶĚdKсϲϴϱϬΖ͕ƚĂŐĂƚϳϯϵϴΖ͘WKK,͘Z͘WŝĐŬƵƉŝŶũĞĐƚŽƌĂŶĚůƵďƌŝĐĂƚŽƌ͘DhdĂŶĚƉƵůůƚĞƐƚ͘DhD,ĂŶĚWd͘Dh ŵŽƚŽƌĂŶĚϮ͘ϮϰΗϯďůĂĚĞũƵŶŬŵŝůů͘ 'ŽƚŽƚŚĞǁĞůůĂŶĚWdϮϱϬƉƐŝůŽǁͬϰϬϬϬƉƐŝŚŝŐŚ͘Z/,ĚƌǇƚŽϮϬϬϬΖ͕ĚŝĚŶŽƚƐĞĞĂŶǇŽďƐƚƌƵĐƚŝŽŶ͘WhƚŽϭϬϬϬΖĂŶĚĐŽŵĞ ŽŶůŝŶĞǁŝƚŚƉƵŵƉĂƚϬ͘ϳďƉŵĂŶĚϭϮϱϬƉƐŝ͘&ƌĞĞƐƉŝŶŽŶŵŽƚŽƌ͘ ŽŶƚŝŶƵĞƚŽZ/,ƉƵŵƉŝŶŐ͘^ƚŽƉĂƚϳϯϲϬΖĂŶĚĚƌŽƉϬ͘ϰϬϲΗďĂůůƚŽƐŚĞĂƌĐŝƌĐƐƵď͘ĂůůŽŶƐĞĂƚĂŶĚĐŝƌĐƐƵďƐŚĞĂƌĞĚ͘WƵŵƉEϮ ĚŽǁŶĐŽŝů͕ƚĂŬŝŶŐƌĞƚƵƌŶƐƚŽƐƵƌĨĂĐĞ͘ tŝƚŚEϮĂƚƐƵƌĨĂĐĞ͕Z/,ĂŶĚƚĂŐĂƚϳϰϭϮΖĐƚŵĚ͘ŝƌĐƵůĂƚĞŽƵƚƌĞŵĂŝŶŝŶŐǁĂƚĞƌĨƌŽŵǁĞůůďŽƌĞǁŝƚŚEϮ͘ ůŽƐĞŝŶĐŚŽŬĞĂŶĚƉƌĞƐƐƵƌĞƵƉƚƵďŝŶŐǁŚŝůĞWKK,͘ ŽŝůĂƚƐƵƌĨĂĐĞ͘>ĞĂǀĞϭϳϬϬƉƐŝŽŶƚƵďŝŶŐ͘>ĂǇĚŽǁŶŵŝůůŝŶŐ,ĂŶĚƌĞĐŽǀĞƌďĂůů͘>ĂǇĚŽǁŶůƵďƌŝĐĂƚŽƌĂŶĚƐĞƚĚŽǁŶ ŝŶũĞĐƚŽƌ͘ dƌĞĞǀĂůǀĞƐůĞĂŬŝŶŐ͘ůŽƐĞƐǁĂď͕ƵƉƉĞƌΘůŽǁĞƌŵĂƐƚĞƌƐ͘EKWΖƐ͘/ŶƐƚĂůůƚƌĞĞĐĂƉ͘ ZŝŐĚŽǁŶŚĂƌĚůŝŶĞ͘WƌĞƉĞƋƵŝƉŵĞŶƚĨŽƌůŽĂĚŝŶŐŽŶƚƌĂŝůĞƌƐ͘ ^&E͘ WƵŵƉϳďďůƐŽĨĐĞŵĞŶƚĚŽǁŶĐŽŝů͘KŶĐĞĐĞŵĞŶƚŝƐĂƚŶŽǌǌůĞ͕ĐůŽƐĞŝŶĐŚŽŬĞĂŶĚƐƋƵĞĞǌĞϭďďůŝŶƚŽůŽǁĞƌƉĞƌĨŽƌĂƚŝŽŶƐ͘ ^ǁĂƉƚŽϲй<ůǁĂƚĞƌ͘^ƚĂƌƚŝŶŐt,WсϲϬϬƉƐŝ͕ĨŝŶĂůt,WсϵϬϬƉƐŝĂĨƚĞƌϭďďů͘KƉĞŶĐŚŽŬĞĂŶĚŚŽůĚϭϬϬƉƐŝ͘ŝƌĐƵůĂƚĞϰ͘ϲ ďďůƐƚŚƌŽƵŐŚůŽǁĞƌƉƵŶĐŚĞƐĂƚϳϰϳϬΖƚŽƵƉƉĞƌƉƵŶĐŚĞƐĂƚϲϴϮϴΖ͘ KĨĨůŝŶĞǁŝƚŚƉƵŵƉĂŶĚĐůŽƐĞĐŚŽŬĞ͘WƵůůŽƵƚŽĨƌĞƚĂŝŶĞƌĂƚϯϮŬ͘KŶůŝŶĞǁŝƚŚƉƵŵƉĂƚϭ͘ϭďƉŵŚŽůĚŝŶŐϭϬϬƉƐŝt,W͘ Wh,ƚŽϲϴϬϬΖ͕ƚŚĞŶZ/,ďĂĐŬƚŽϳϰϬϬΖƉƵŵƉŝŶŐϲй<ǁĂƚĞƌ͘ WKK,ĐŚĂƐŝŶŐĂŶǇĐĞŵĞŶƚƌĞƚƵƌŶƐƚŽƐƵƌĨĂĐĞŚŽůĚŝŶŐϭϬϬƉƐŝŽŶĐŚŽŬĞ͘ ŽŝůĂƚƐƵƌĨĂĐĞ͘ƵƚŽĨĨYƵĂĚĐŽ,ĂŶĚƐƚĂďďĂĐŬŽŶǁĞůůƚŽďůŽǁĚŽǁŶƌĞĞůǁŝƚŚEϮ͘ ůŽǁĚŽǁŶƌĞĞůǁŝƚŚEϮ͘ >ĂǇĚŽǁŶůƵďƌŝĐĂƚŽƌ͘^ĞĐƵƌĞǁĞůůǁŝƚŚŶŝŐŚƚĐĂƉŽŶKWƐ͘ ^&E͘ ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ϯͬϭϲͬϮϮ ϰͬϴͬϮϮ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞĞŬůǇKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ >hͲϭϰϱϬͲϭϯϯͲϮϬϲϴϰͲϬϬͲϬϬ ϮϭϵͲϬϳϴ ϬϯͬϮϭͬϮϬϮϮͲDŽŶĚĂǇ zĞůůŽǁ:ĂĐŬĞƚͲůŝŶĞĂƌƌŝǀĞ͘ŽŶĚƵĐƚ:^ĂŶĚĂƉƉƌŽǀĞWdt͘ DhůƵďƌŝĐĂƚŽƌ͘Dh'WdĂŶĚϮΗǆϴΖƉĞƌĨŐƵŶ͘ ŚĂŶŐĞŽƵƚĨŝƚƚŝŶŐŽŶͲůŝŶĞŐƌĞĂƐĞŝŶũĞĐƚŝŽŶŚŽƐĞ͘ WdůƵďƌŝĐĂƚŽƌƚŽϮϱϬƉƐŝůŽǁͬϮϱϬϬƉƐŝŚŝŐŚ͘Z/,ǁŝƚŚŐƵŶηϭ;ϮΗǆϴΖǁͬ'WdͿ͘ ^ĞŶĚĐŽƌƌĞůĂƚŝŽŶĚĂƚĂƚŽZͬ'K͘^ŚŝĨƚƵƉϭΖ WĞƌĨŽƌĂƚĞhϳůŽǁĞƌǌŽŶĞϳϯϬϯͲϳϯϭϭΖ /ŶŝƚŝĂůƉƌĞƐƐсϭϭϭϰƉƐŝ ϱŵŝŶсϭϭϮϭƉƐŝ ϭϬŵŝŶсϭϭϮϮƉƐŝ ϭϱŵŝŶсϭϭϮϯƉƐŝ ůůƐŚŽƚƐĨŝƌĞĚ͘'ƵŶŝƐĚƌǇǁŝƚŚƐŵĂůůĂŵŽƵŶƚŽĨĨůƵŝĚŝŶďƵůůŶŽƐĞ͘Z/,ǁŝƚŚŐƵŶηϮ;ϮΗǆϭϬΖƉĞƌĨŐƵŶͿ͘ ^ĞŶĚĐŽƌƌĞůĂƚŝŽŶĚĂƚĂƚŽZͬ'K͘^ŚŝĨƚƵƉϭΖ WĞƌĨŽƌĂƚĞhϲǌŽŶĞϳϮϬϬͲϳϮϭϬΖ /ŶŝƚŝĂůƉƌĞƐƐсϭϭϳϮƉƐŝ ϱŵŝŶсϭϭϳϴƉƐŝ ϭϬŵŝŶсϭϭϴϬƉƐŝ ϭϱŵŝŶсϭϭϴϮƉƐŝ ůůƐŚŽƚƐĨŝƌĞĚ͘'ƵŶŝƐǁĞƚ͘Z/,ǁŝƚŚŐƵŶηϯ;ϮΗǆϭϬΖ,^ƉĞƌĨŐƵŶͿ͘ ^ĞŶĚĐŽƌƌĞůĂƚŝŽŶĚĂƚĂƚŽZͬ'K͘KŶĚĞƉƚŚ͘ WĞƌĨŽƌĂƚĞhϱǌŽŶĞϳϭϯϴͲϳϭϱϴΖ /ŶŝƚŝĂůƉƌĞƐƐсϭϮϯϯƉƐŝ ϱŵŝŶсϭϮϯϴƉƐŝ ϭϬŵŝŶсϭϮϰϮƉƐŝ ϭϱŵŝŶсϭϮϰϰƉƐŝ ůůƐŚŽƚƐĨŝƌĞĚ͘'ƵŶŝƐǁĞƚ͘>ŽŐƵƉŚŽůĞǁŝƚŚ'WdĂĨƚĞƌƉĞƌĨŽƌĂƚŝŶŐhϱ͘&ůƵŝĚůĞǀĞůсϲϭϮϬΖ͘ WKK,͘ůůƐŚŽƚƐĨŝƌĞĚ͘'ƵŶŝƐǁĞƚ͘ZDK͘ ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ϯͬϭϲͬϮϮ ϰͬϴͬϮϮ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞĞŬůǇKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ >hͲϭϰϱϬͲϭϯϯͲϮϬϲϴϰͲϬϬͲϬϬ ϮϭϵͲϬϳϴ ϬϯͬϮϱͬϮϬϮϮͲ&ƌŝĚĂǇ zĞůůŽǁũĂĐŬĞƚĂŶĚ&ŽǆĂƌƌŝǀĞĂƚ<'&ŽĨĨŝĐĞ͘^ŝŐŶƉĞƌŵŝƚ͕ŵŽǀĞŽƵƚƚŽůŽĐĂƚŝŽŶ͘ ZŝŐƵƉŽŶĂǁĞůů͘WdůƵďƌŝĐĂƚŽƌϮϱϬƉƐŝͬϯϬϬϬƉƐŝ͕ŐŽŽĚƚĞƐƚ͘ Z/,ǁŝƚŚϮͲϳͬϴΗ/WĂŶĚ'Wd͘ϭϳ͘ϱΖ>ƚŽƉůƵŐ͘ WdŶŝƚƌŽŐĞŶŚĂƌĚůŝŶĞͲϮϱϬƉƐŝͬϯϬϬϬƉƐŝ͕ŐŽŽĚƚĞƐƚ͘ &ŝŶĚĨůƵŝĚůĞǀĞůĂƚϳϬϬΖ͘ WƵŵƉEϮĂƚϭϬϬϬƐĐĨŵ͕t,WĐĂŵĞƵƉƚŽϮϱϬϬƉƐŝ͘>ŽǁĞƌƌĂƚĞƚŽϱϬϬƐĐĨŵ͘ >ŽǁĞƌƌĂƚĞƚŽϯϱϬƐĐĨŵ͘Z/,ƚŽĨŝŶĚĨůƵŝĚůĞǀĞůΛϲϯϬϬΖ͘&ůƵŝĚůĞǀĞůΛϳϮϮϬΖ͘WƵůůĐŽƌƌĞůĂƚŝŽŶůŽŐϳϯϬϬΖƚŽϲϵϵϬΖ͘ ^ĞŶĚůŽŐƚŽƚŽǁŶ͕ƐŚŝĨƚĚĞƉƚŚϰΖƵƉ͘;ŵĂĚĞϳϮϰϴΖϳ͕ϮϰϰΖͿ ^Ğƚ/WĂƚϳ͕ϭϯϬΖ͘'ŽŽĚŝŶĚŝĐĂƚŝŽŶŽĨƐĞƚĂŶĚƚĂŐŐĞĚƉůƵŐĂƚĐŽƌƌĞĐƚĚĞƉƚŚ͘ WKK,͘>ĂǇĚŽǁŶƐĞƚƚŝŶŐƚŽŽů͘ EϮƵŶŝƚƌŝŐŐŝŶŐĚŽǁŶ͘ůĞĞĚĚŽǁŶt,WƚŽϭϬϬƉƐŝ͘ WƵŵƉĞĚϲϵϮŐĂůůŽŶƐŽĨEϮ͘ŽŶƚŝŶƵĞďůĞĞĚŝŶŐt,W͕ĐƵƌƌĞŶƚůǇĂƚϭϮϬϬƉƐŝ͘ DhϭϱΖŽĨϮΗĚƵŵƉďĂŝůĞƌ͘>ŽĂĚϮ͘ϰŐĂůůŽŶƐŽĨĐĞŵĞŶƚ͘ Z/,͘ ƵŵƉďĂŝůϮ͘ϰŐĂůůŽŶƐĂƚϳϭϯϬΖǁŝƚŚdKĂƚϳϭϮϬΖ͘ WKK,͘t,WĂƚϱϮϱƉƐŝ͘ŚĞĐŬĨŝƌĞ͘DhϮΗϮϬΖŐƵŶϲƐƉĨ͘Z/,͘ WƵůůĐŽƌƌĞůĂƚŝŽŶůŽŐĨƌŽŵϳ͕ϬϵϬΖƚŽϲ͕ϳϱϬΖ͘ ^ĞŶĚƚŽƚŽǁŶ͕ŽŶĚĞƉƚŚ͘ ^ŚŽŽƚƚŚĞhϰĨƌŽŵϳ͕ϬϳϮΖƚŽϳ͕ϬϵϮΖ͘'ŽŽĚŝŶĚŝĐĂƚŝŽŶŽĨĨŝƌĞ͘ WƵůůŝŶŐŚĞĂǀǇĂŶĚĚƌĂŐŐŝŶŐǁŚŝůĞWKK,͘ hŶĂďůĞƚŽŵŽǀĞǁŝƌĞĂƚϲ͕ϲϱϬΖ͘ WƵůůĞĚĂďŽǀĞǁĞĂŬƉŽŝŶƚĂŶĚĚŝĚŶŽƚƉƵůůĨƌĞĞ͘ ĂůůĞĚWŽůůĂƌĚĨŽƌĂ<ŝŶůĞǇƵƚƚĞƌ͘WƌĞƐƐƵƌĞĂĨƚĞƌƐŚŽŽƚŝŶŐhϰͲ ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ϯͬϭϲͬϮϮ ϰͬϴͬϮϮ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞĞŬůǇKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ >hͲϭϰϱϬͲϭϯϯͲϮϬϲϴϰͲϬϬͲϬϬ ϮϭϵͲϬϳϴ WŽůůĂƌĚĂƚ<'&͕ǁĂƌŵƵƉĞƋƵŝƉŵĞŶƚ͘ d'^D͕:^͕ĂŶĚƐŝŐŶƉĞƌŵŝƚ͘ ƌƌŝǀĞĂƚĂŶŶĞƌǇ>ŽŽƉĂŶĚZh͘ WdůƵďƌŝĐĂƚŽƌƚŽϮϱϬƉƐŝͬϮϬϬϬƉƐŝ͘ dĂŐĨŝƐŚĂƚϲ͕ϲϴϯΖ<͘ ZĞĐŽǀĞƌĞĚΕϭϮΖŽĨ>ĐĂďůĞ͘ >ĂƚĐŚĞĚĨŝƐŚĂƚϳϭϮϮΖĂŶĚƌĞĐŽǀĞƌĞĚĞŶƚŝƌĞϯϮ͘ϴΖ>ƚŽŽůƐƚƌŝŶŐ͘ zĞůůŽǁũĂĐŬĞƚŽŶůŽĐĂƚŝŽŶƚŽďƌĞĂŬĚŽǁŶƚŽŽůƐ͘ ZĞĐŽǀĞƌĞĚŐƵŶͲĂůůƐŚŽƚƐĨŝƌĞĚ͘ ^ĞĞ^>t^ZĨŽƌĨƵůůƌƵŶĚĞƚĂŝůƐ͘ WŽůůĂƌĚZDK͘ zĞůůŽǁũĂĐŬĞƚĞƋƵŝƉŵĞŶƚƐƚŝůůŽŶůŽĐĂƚŝŽŶ͘ /ŶŝƚŝĂůͲϳϭ͘ϯƉƐŝ ϱŵŝŶͲϮϱϮƉƐŝ ϭϬŵŝŶͲϯϴϬƉƐŝ ϭϱŵŝŶͲϰϱϱƉƐŝ ΎΎ&ŝƐŚůĞĨƚŝŶŚŽůĞ͗ϭΖǆϭͲϯͬϴΗ,ǁŝƚŚĂϭΗ:ĨŝƐŚŶĞǆƚ͕ϲ͘ϯϬΖǆϭͲϭϭͬϭϲΗ'Zͬ>͕ϭ͘ϱΖǆϭͲϭϭͬϭϲΗƐŚŽĐŬͲƐƵď͕ϮϰΖǆϮΗƐƉĞŶƚ ŐƵŶ͘K>ͲϯϮ͘ϴϬΖ͘ΕϭϯΖŽĨϵͬϯϮΗǁŝƌĞůĞĨƚŝŶŚŽůĞΎΎ͘WŽůůĂƌĚŽŶůŽĐĂƚŝŽŶ͘W:^D͘ ůŽƐĞǁŝƌĞůŝŶĞǀĂůǀĞƐ͘ ůĞĞĚƵƉƉĞƌůƵďƌŝĐĂƚŽƌ͘ ^ƚƌŝƉƵƉůƵďƌŝĐĂƚŽƌĂŶĚDhƚŝŵĞĚĐƵƚƚĞƌ͘dŝŵĞƌƐĞƚĨŽƌϲϬŵŝŶ͘ ^ƚƌŝƉďĂĐŬĚŽǁŶĂŶĚƐƚĂďŽŶ͘KƉĞŶǁŝƌĞůŝŶĞǀĂůǀĞƐ͘<ŝŶůĞǇƵƚƚĞƌĐƵƚΛϮϬϯϬ͘,ĂǀĞϭϬϱϬůďƐŽĨŚĂŶŐŝŶŐǁĂŝƚ͘ WKK,͘ ZĞĐŽǀĞƌĞĚĂůůďƵƚΕϭϯΖŽĨǁŝƌĞ͘ <ŝŶůĞǇƵƚƚĞƌǁĂƐĐƌŝŵƉĞĚŽŶǁŝƌĞĂŶĚǁĂƐƌĞĐŽǀĞƌĞĚ͘ dƌĞĞĐĂƉŝŶƐƚĂůůĞĚ͘ ZDK͘ ϬϯͬϮϲͬϮϬϮϮͲ^ĂƚƵƌĚĂǇ ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ϯͬϭϲͬϮϮ ϰͬϴͬϮϮ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞĞŬůǇKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ >hͲϭϰϱϬͲϭϯϯͲϮϬϲϴϰͲϬϬͲϬϬ ϮϭϵͲϬϳϴ ϬϯͬϮϳͬϮϬϮϮͲ^ƵŶĚĂǇ zĞůůŽǁũĂĐŬĞƚĂƌƌŝǀĞŽŶůŽĐĂƚŝŽŶ͘d'^DĂŶĚƐŝŐŶƉĞƌŵŝƚ͘ ŚĞĐŬĨŝƌĞ͘DhϭϵΖϮΗŐƵŶϲƐƉĨ͘ϭϭ͘ϱΖ>ƚŽƚŽƉƐŚŽƚ͘ ^ƚĂďŽŶǁĞůůĂŶĚZ/,͘ dĂŐŐĞĚĐĞŵĞŶƚĂƚϳ͕ϬϭϴΖ WƵůůĐŽƌƌĞůĂƚŝŽŶůŽŐĨƌŽŵϳ͕ϭϬϬΖƚŽϲ͕ϳϱϬΖ͘^ĞŶĚƚŽƚŽǁŶ͕ŽŶĚĞƉƚŚ͘ ^ŚŽŽƚƚŚĞhϰĨƌŽŵϳ͕ϬϱϯΖƚŽϳ͕ϬϳϮΖ͘WKK,͘WƌĞƐƐƵƌĞĚĂƚĂ͗ /ŶŝƚŝĂůͲϰϳϳƉƐŝ ϱŵŝŶͲϰϳϴƉƐŝ ϭϬŵŝŶͲϰϳϴƉƐŝ ϭϱŵŝŶͲϰϳϴƉƐŝ >ĂǇĚŽǁŶŐƵŶƐͲĂůůƐŚŽƚƐĨŝƌĞĚ͘'ƵŶǁĂƐǁĞƚ͘ ^ĞĐƵƌĞǁĞůů͘ ZDK͘ ϬϰͬϬϳͬϮϬϮϮͲdŚƵƌƐĚĂǇ ^>D/Zh͕WdϭϱϬͬϭϱϬϬ͕Z/,ĂŶĚďƌƵƐŚŶŝƉƉůĞ͕Wh^^^s͕Z/,ĂŶĚƐĞƚ^^^s͘dĞƐƚĐůŽƐƵƌĞĂŶĚŽƉĞŶŝŶŐ͕'ŽŽĚdĞƐƚ͕ZDK͘ EŽƚŝĨǇĨŽƌK'ŽĨƉĞƌĨŽƌŵĂŶĐĞƚĞƐƚĨŽƌϰͬϵͬϮϮ͘ ϬϰͬϬϴͬϮϬϮϮͲ&ƌŝĚĂǇ D/Zh^>dĞƐƚĞĚ>ƵďƌŝĐĂƚŽƌƚŽϭϱϬϬ͕WƵůůĞĚ^^^s͕ĨůƵƐŚĞĚĐŽŶƚƌŽůůŝŶĞ͕ƌĞƐĞƚǀĂůǀĞ͘WĞƌĨŽƌŵĂŶĐĞƚĞƐƚĞĚ^^^sƉĞƌK' ƌĞŐƵůĂƚŝŽŶƐ͕ǁŝƚŶĞƐƐǁĂŝǀĞĚ͘ BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB hƉĚĂƚĞĚďǇ,ϬϰͲϮϭͲϮϮ ^,Dd/ ĂŶŶĞƌǇ>ŽŽƉ tĞůů͗>hηϭϰ Wd͗ϮϭϵͲϬϳϴ W/͗ϱϬͲϭϯϯͲϮϬϲϴϰͲϬϬͲϬϬ KWE,K>ͬDEdd/> ϭϬͲϯͬϰ͟ϭϯͲϭͬϮ͟,ŽůĞ͗ϮϳϮďďůƐ;ϲϰϬƐǆͿϭϮηĐůĂƐƐůĞĂĚĐĞŵĞŶƚĨŽůůŽǁĞĚďǇϱϳďďůƐŽĨϭϱ͘ϴηůĂƐƐƚĂŝů ĐĞŵĞŶƚ͘ƵŵƉĞĚƉůƵŐ͘&ƵůůƌĞƚƵƌŶƐƚŚƌŽƵŐŚŽƵƚũŽď͘ϵϮďďůƐĐĞŵĞŶƚďĂĐŬƚŽ^ƵƌĨĂĐĞ ϳͲϱͬϴΗϵͲϳͬϴ͟,ŽůĞ͗ϭϱϵďďůƐϭϮηĐůĂƐƐůĞĂĚĐĞŵĞŶƚĨŽůůŽǁĞĚďǇϱϵďďůƐŽĨϭϱ͘ϯηůĂƐƐƚĂŝůĐĞŵĞŶƚ͕ ďƵŵƉĞĚƉůƵŐ͘ϰϰďďůƐůŽƐƚƚŚƌŽƵŐŚŽƵƚũŽď͘ϴͬϵͬϭϵ>;<>ͿdKΛϮϴϬϬ͛D͘ ϰͲϭͬϮ͟ ϲͲϯͬϰ͟,ŽůĞ͗ϭϮϱďďůƐϭϮηĐůĂƐƐůĞĂĚĐĞŵĞŶƚĨŽůůŽǁĞĚďǇϮϯďďůƐϭϱ͘ϯηƚĂŝůĐĞŵĞŶƚ͘ĨƚĞƌ ϭϮϰďďůƐĚŝƐƉůĂĐĞŵĞŶƚ͕ůŽƐƚĂůůƌĞƚƵƌŶƐ͘ƐƚŝŵĂƚĞĚϯϬďďůƐƚŽƚĂůůŽƐƚĚƵƌŝŶŐũŽď͘^ƉĂĐĞƌĂŶĚƚƌĂĐĞ ĐĞŵĞŶƚĐŝƌĐƵůĂƚĞĚŽĨĨůŝŶĞƌƚŽƉďĂĐŬƚŽƐƵƌĨĂĐĞ͘ϴͬϮϵͬϭϵ>dKΛϴ͕ϵϭϬ͛͘ 5$WDJV¶ ^/E'd/> ^ŝǌĞdǇƉĞtƚͬ'ƌĂĚĞͬŽŶŶ/dŽƉƚŵ ϭϲΗŽŶĚƵĐƚŽƌϭϬϵͬyͲϱϲͬtĞůĚϭϱ͟^ƵƌĨϭϮϬ͛ ϭϬͲϯͬϰ͟^ƵƌĨĂĐĞϰϱ͘ϱͬ>ͲϴϬͬdyWdϵ͘ϵϱϬ͟^ƵƌĨϯ͕ϯϯϯ͛ ϳͲϱͬϴΗ/ŶƚĞƌŵĞĚŝĂƚĞϮϵ͘ϳͬ>ͲϴϬͬtϱϲϯϲ͘ϴϳϱ͟^ƵƌĨϲ͕ϴϮϰ͛ ϰͲϭͬϮΗWƌŽĚƵĐƚŝŽŶϭϮ͘ϲͬ>ͲϴϬͬdyWdϯ͘ϵϱϴ͟ϱ͕ϯϲϱ͛ϵ͕ϴϬϬ͛ dh/E'd/> ^ŝǌĞdǇƉĞtƚͬ'ƌĂĚĞͬŽŶŶ/dŽƉƚŵ 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Dͺϳϴ͕Ϭϱϴ͛ϴ͕Ϭϳϴ͛ϲ͕ϯϲϱ͛ϲ͕ϯϴϰ͛ϮϬ͛ϵͬϭϴͬϮϬϭϵWůƵŐŐĞĚ DϯDͺϳϴ͕ϬϱϵΖϴ͕ϬϳϴΖϲ͕ϯϲϲΖϲ͕ϯϴϰΖϭϵΖϭϮͬϮϲͬϮϬϮϬWůƵŐŐĞĚ DϰDͲϳϴ͕ϭϰϴΖϴ͕ϭϱϬΖϲ͕ϰϱϭΖϲ͕ϰϱϯΖϮΖϭϮͬϮϰͬϮϬϮϬWůƵŐŐĞĚ D ϳ>Ͳϭy ϴ͕ϮϳϮ͛ϴ͕Ϯϳϵ͛ϲ͕ϱϳϭ͛ϲ͕ϱϳϳ͛ϳ͛ϭϮͬϮϯͬϮϬϮϬWůƵŐŐĞĚ ϴ͕ϮϳϵΖϴ͕ϮϴϲΖϲ͕ϱϳϳΖϲ͕ϱϴϰΖϳΖϭϮͬϮϰͬϮϬϮϬWůƵŐŐĞĚ ϴ͕Ϯϳϴ͛ϴ͕ϮϴϬ͛ϲ͕ϱϳϲ͛ϲ͕ϱϳϴ͛ϮϭϮͬϭϵͬϮϬϮϬWůƵŐŐĞĚ >Ͳϰ>ͺϭϲϴ͕ϱϲϱ͛ϴ͕ϱϳϳ͛ϲ͕ϴϱϮ͛ϲ͕ϴϲϯ͛ϭϮ͛ϵͬϭϯͬϮϬϭϵWůƵŐŐĞĚ >Ͳϲ>ͺϮϴ͕ϲϰϮ͛ϴ͕ϲϱϰ͛ϲ͕ϵϮϲ͛ϲ͕ϵϯϳ͛ϭϮ͛ϭϭͬϮϱͬϮϬϭϵWůƵŐŐĞĚ &/^,d/> ϴ͕ϲϲϯ͛/WĞďƌŝƐϬϴͬϭϴͬϮϬ DŝĚĚůĞ&ŝƐŚZWWƵƐŚĞĚƚŽŽƚƚŽŵ ϵ͕ϲϱϵ͛/WDŝůůĞĚĂŶĚWƵƐŚĞĚƚŽŽƚƚŽŵϬϵͬϭϭͬϭϵ EŽƚĞ͗ƚďŐ͘ƚĂŝů ŝƐϮ͘ϯϬ͘͟ Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 4/12/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL CLU 14 (PTD 219-078) Plug/Perf/GPT 3/25/2022 Please include current contact information if different from above. 219-078 T36472 Meredith Guhl Digitally signed by Meredith Guhl Date: 2022.04.13 13:38:18 -08'00' 5HJJ-DPHV%2*& )URP%UDG*DWKPDQ&%UDG*DWKPDQ#KLOFRUSFRP! 6HQW6DWXUGD\0DUFK30 7R5HJJ-DPHV%2*&'2$$2*&&3UXGKRH%D\%URRNV3KRHEH/2*& &F'RQQD$PEUX] 6XEMHFW%23(7HVW5HSRUW&/8 $WWDFKPHQWV%23(7HVW5HSRUW&/8[OV[>(;7(51$/@$2*&&,QVSHFWLRQ)RUP&RQILUPDWLRQ(PDLO >(;7(51$/@5($2*&&7HVW:LWQHVV1RWLILFDWLRQ5HTXHVW%23(6/%&RLOHG7XELQJ8QLW&/8 7KHLQIRUPDWLRQFRQWDLQHGLQWKLVHPDLOPHVVDJHLVFRQILGHQWLDODQGPD\EHOHJDOO\SULYLOHJHGDQGLVLQWHQGHGRQO\IRUWKHXVHRIWKHLQGLYLGXDORUHQWLW\QDPHG DERYH,I\RXDUHQRWDQLQWHQGHGUHFLSLHQWRULI\RXKDYHUHFHLYHGWKLVPHVVDJHLQHUURU\RXDUHKHUHE\QRWLILHGWKDWDQ\GLVVHPLQDWLRQGLVWULEXWLRQRUFRS\RIWKLV HPDLOLVVWULFWO\SURKLELWHG,I\RXKDYHUHFHLYHGWKLVHPDLOLQHUURUSOHDVHLPPHGLDWHO\QRWLI\XVE\UHWXUQHPDLORUWHOHSKRQHLIWKHVHQGHU VSKRQHQXPEHULVOLVWHG DERYHWKHQSURPSWO\DQGSHUPDQHQWO\GHOHWHWKLVPHVVDJH :KLOHDOOUHDVRQDEOHFDUHKDVEHHQWDNHQWRDYRLGWKHWUDQVPLVVLRQRIYLUXVHVLWLVWKHUHVSRQVLELOLW\RIWKHUHFLSLHQWWRHQVXUHWKDWWKHRQZDUGWUDQVPLVVLRQ RSHQLQJRUXVHRIWKLVPHVVDJHDQGDQ\DWWDFKPHQWVZLOOQRWDGYHUVHO\DIIHFWLWVV\VWHPVRUGDWD1RUHVSRQVLELOLW\LVDFFHSWHGE\WKHFRPSDQ\LQWKLVUHJDUGDQG WKHUHFLSLHQWVKRXOGFDUU\RXWVXFKYLUXVDQGRWKHUFKHFNVDVLWFRQVLGHUVDSSURSULDWH &$87,217KLVHPDLORULJLQDWHGIURPRXWVLGHWKH6WDWHRI$ODVNDPDLOV\VWHP'RQRWFOLFNOLQNVRURSHQ DWWDFKPHQWVXQOHVV\RXUHFRJQL]HWKHVHQGHUDQGNQRZWKHFRQWHQWLVVDIH &DQQHU\/RRS 37' -5HJJ STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSu b m i t t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:1 DATE: 3/16/22 Rig Rep.: Rig Phone: 907-659-2434 Operator: Op. Phone:907-777-8300 Rep.: E-Mail Well Name: PTD #22190780 Sundry #322-098 Operation: Drilling: Workover: X Explor.: Test: Initial: X Weekly: Bi-Weekly: Other: Rams:250/4000 Annular: Valves:250/4000 MASP:1981 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 0NA Housekeeping P Rig NA Lower Kelly 0NA PTD On Location P Hazard Sec.NA Ball Type 0NA Standing Order Posted NA Misc.NA Inside BOP 0NA FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 1 1.75" top load P Trip Tank NA NA Annular Preventer 0 NA NA Pit Level Indicators NA NA #1 Rams 1 1.75 B/S P Flow Indicator NA NA #2 Rams 1 1.75 B/S P Meth Gas Detector NA NA #3 Rams 1 1.75 Slips P H2S Gas Detector NA NA #4 Rams 1 1.75 Pipes P MS Misc 0NA #5 Rams 0 NA NA #6 Rams 0 NA NA Quantity Test Result Choke Ln. Valves 1 2x2 FMC P Inside Reel valves 1P HCR Valves 0 NA NA Kill Line Valves 2 2x2 FMC P Check Valve 1 2" 1502 P ACCUMULATOR SYSTEM: BOP Misc 3 EQ PORTS P Time/Pressure Test Result System Pressure (psi)3000 P CHOKE MANIFOLD:Pressure After Closure (psi)1550 P Quantity Test Result 200 psi Attained (sec)20 P No. Valves 5P Full Pressure Attained (sec)76 P Manual Chokes 2P Blind Switch Covers: All stations Yes Hydraulic Chokes 0NA Nitgn. Bottles # & psi (Avg.): NA NA CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:0 Test Time:4.0 Hours Repair or replacement of equipment will be made within NA days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 3/14/22 10:08 Waived By Test Start Date/Time:3/16/2022 13:30 (date) (time)Witness Test Finish Date/Time:3/16/2022 17:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Schlumberger A push/pull test was conducted on the slip rams. Bryson Lowe Hilcorp Brad Gathman CLU 14 Test Pressure (psi): brad.gathman@hilcorp.com Form 10-424 (Revised 02/2022) BOPE Test Report CLU 14 3-16-22 9 9 9 9991$ 9 9 -5HJJ 3/16/22 1$ Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 4/06/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL CLU 14 (PTD 219-078) EV Camera 04/04/2022 Please include current contact information if different from above. 219-078 T36450 Meredith Guhl Digitally signed by Meredith Guhl Date: 2022.04.07 09:29:53 -08'00' Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 3/24/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL CLU 14 (PTD 219-078) CBL/PERF/GPT 3/19/2022 Please include current contact information if different from above. 219-078 T36431 Meredith Guhl Digitally signed by Meredith Guhl Date: 2022.03.29 09:59:06 -08'00' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 RECEIVED By Samantha Carlisle at 2:25 pm, Mar 01, 2022 1. Type of Request: Abandon ❑ Plug Perforations 0 Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate 0 Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: CTU N2 Lift ❑✓ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development Q Stratigraphic ❑ Service ❑ 219-078 3. Address: 6. API Number: 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 50-133-20684-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 231A Will planned perforations require a spacing exception? Yes El No ❑� Cannery Loop Unit (CLU) 14 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL60569, ADL60568, ADL 324602, Fee Private I Cannery Loop / Beluga Gas Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 9,802' 8,043' 7,924' 6,236' -1981 7,924' See Schematic Casing Length Size MD TVD Burst Collapse Structural Conductor 120' 16" 120' 120' Surface 3,333' 10-3/4" 3,333' 2,616' 3,580psi 2,090psi Intermediate 6,824' 7-5/8" 6,824' 5,183' 6,890psi 4,790psi Production 4,435' 4-1/2" 9,800' 8,041' 8,430psi 7,500psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 2-7/8" 6.5# / L-80 / FJ3 7,885' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): See Schematic See Schematic 12. Attachments: Proposal Summary Lj 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: March 12, 2022 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: AOGCC Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Digitally signed by Dan Marlowe Dan Marlowe (1267) Contact Name: Chad Helgeson, Operations Engineer DN: cn=Dan Marlowe (1267), Users Authorized Name and (1267) Dat Date: 2022.03.01 13:56:55-09'00' Digital Signature with Date: Contact Email: chel eson hllcor .com Contact Phone: 907-777-8405 Authorized Title: Dan Marlowe, Operations Manager, 907-283-1329 AOGCC USE ONLY Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: 322-098 Plug Integrity ❑ BOP Test ® Mechanical Integrity Test ❑ Location Clearance ❑ Other: CT BOP test to 4000 psi. Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No ® Subsequent Form Required: 10-404 Jeremy Price APPROVED BY Jeremy Price Datem2012.03.,0 3/10/22 Approved by: 14:49:47-09'00' COMMISSIONER THE AOGCC Date: Comm.dts 3/10/2022 1 COMM JLC 3/10/2022 1 Sr Pet EngBJM 3/10/22 1 JSr Pet GeoDLB 03/09/2022 1 ISr Res Eng DSR-3/1/22 Form 10-403 Revised 10/2021 Approved application is valid for 12 months from the date of approval. RBDMS SJC 031122 Well Prognosis Well: CLU 14 Date:2/28/2022 11ilcurp Alaska, LLC Well Name: CLU 14 API Number: 50-133-20684-00-00 Current Status: SI Gas Well Leg: N/A Estimated Start Date: 3/12/22 Rig: CTU Reg. Approval Req'd? 10-403 Sundry Number: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 219-078 First Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4823 (C) Second Call Engineer: Jake Flora (907) 777-8442 (0) (720) 988-5375 (C) Current BHP —2,563 psi @ 5,825' TVD Based on a 0.44psi/ft gradient Maximum Expected BHP: —2,563 psi @ 5,825' TVD Based on a 0.44psi/ft gradient. Max. Potential Surface Pressure: --1981 psi @ 5,825' TVD Gas gradient to surface @ 0.1 psi/ft Brief Well Summary CLU 14 is a gas producer that was drilled and completed in August 2019 targeting gas sands in the Beluga and Sterling formations. In August of 2020 a 2-7/8" velocity string was installed in the well. A CIBP that provided well control during the running of the 2-7/8" velocity string was drilled up through the 2-7/8" string and pushed to bottom. In October the tubing conveyed SCSSSV failed to close. This valve was pinned open and a WLR SCSSSV was installed in its profile. In January 2021, the SSSV was pulled and a capillary line installed to help unload water. In October 2021, the M136 sands were plugged back and the M131 was perforated through tubing, where the zone made a little gas, but immediately watered up at rates over 1,000 bwpd. Objective The objective of this job is to plugback the existing perfs with coil tubing and perforate additional upper beluga sands. Wellbore Notes: • Current T/IA/OA — 15/0/0 • ICO 123 A Rule 2 & 3. This well already exists solely in the Beluga Gas Pool, and will not perforate any Isands within 100ft of CINGSA Pool • WRSV is not currently installed in well • (CINGSA Pool bottom — 6,787' (5,148' TVD) • SL Tag depth — 7,888' (1/18/2022) Coiled Tubing 1. MIRU coiled tubing. If necessary, pressure test BOPE to 250 psi Low / 4,000 psi High a. Notify State for option to witness 2. RIH w cement nozzle and establish circulation while RIH 3. Stop coil at 7850' and determine injection rates (assuming injection rate >0.75 bpm) a. Pump 6 bbls of cement in coil string (adjust final cement volume depending on injection rates < 0.75 bpm or greater than 1.5 bpm per engineers recommendation) b. Lay 2bbls of cement from 7,888' to 7,538' c. Perform hesitation squeeze of final 4 bbls i. Annulus volume 362' = 2.72 bbls @ 0.0075 bbl/ft Well Prognosis Well: CLU 14 Date:2/28/2022 11ilcurp Alaska, LLC ii. Tubing volume 362' = 2.1 bbls @ 0.0058 bbl/ft 4. PU 50ft to —7,488 and pump full well volume to clean well and circ out any cement 5. POOH with CT 6. WOC and pressure test tubing to 2,000 psi. 7. MIRU E-line on top of coil BOP. Pressure test lubricator to 250 psi low / 2,500 psi high 8. RIH with tubing punch and tag top of cement at >7,488', PU and punch holes at—7,470' 9. Make 2nd run with tubing punch and fire at—6,828' (50ft below CINGSA Pool bottom) 10. RDMO E-line 11. Pressure test tubing (lower casing) to 2,000 psi for 10 min 12. PU CT, RIH w/ single trip cement retainer and set at—7,450' 13. Pump 4.75 bbls of cement (Est TOC—6,817') a. Annulus volume 633' = 4.75 bbls @ 0.0075 bbl/ft 14. POOH circulating and make several passes across 6,850-6800' 15. WOC overnight 16. RIH and jet well dry with N2, (confirm w/ OE on how much pressure to leave on well.) 17. RDMO CTU Contingency Slickline (If CT is not used for jetting well dry, will swab fluid off well prior to perforating) 1. MIRU Slickline 2. Swab well dry 3. RDMO Slickline Eline 1. MIRU E-line, PT lubricator to 2,000 psi Hi 250 Low. 2. Perforate the following sand intervals from bottom to top (2" HC guns): Zone Name Pool Name Top(MD) Btm(MD) Top(TVD) Beluga Gas UB 3A ±7,004 ±7,008 ±5,351' Beluga Gas UB 4 ±7,024 ±7,040 ±5,370' Beluga Gas UB 4A ±7,053 ±7,092 ±5,398' Beluga Gas UB 5A ±7,138 ±7,158 ±5,479' Beluga Gas UB 6 ±7,200 ±7,210 ±5,538' Beluga Gas UB 7 Lower ±7,303 ±7,311 ±5,637' TVD Dist Btm(TVD) Ft from CINGSA (ft) ±5,355' 4 203 ±5,385' 16 222 ±5,435' 39 250 ±5,498' 20 331 ±5,548' 10 390 ±5,644' 8 489 a. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to Geologist (Daniel Yancy) and Reservoir Engineer (Chris Kanyer) for confirmation. b. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record a tubing Surface pressure before each run and after each gun firing of 5, 10, 15 min reading intervals. c. These Beluga sands are governed by CO 231A. 3. POOH. RDMO a -line. 4. Turn well over to production and flow well. Well Prognosis Well: CLU 14 Date:2/28/2022 lIileurp Alaska, LLC 5. If well reaches stable rates within 5 days, complete slickline work below. 6. If well is not at rates optimal for well, perforate additional sands E-line Procedure (Contingency): If any zone produces sand and/or water. 1. MIRU E-line, PT lubricator to 2,000 psi Hi 250 Low. 2. RIH and set 2-7/8" CIBP (or tubing patch). Set at depth specified by Engineer. 3. RU Slickline. Swab fluid down to depth approved by Engineer. a. If necessary RIH with bailer assembly. Dump bail cement on CIBP. POOH. Slickline 1. MIRU Slickline. 2. Install WRSSSV in profile at 531' and notify state to witness test per 20AAC 25.265 Attachments 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. CT BOPE Schematic 4. Standard Nitrogen Procedure Hilcoru Alaska, LLE; RKB: MSL = 38.4' 16, 10-31C 1 7-S/8. Fill @ 7,998' ABO( CTM 1/18122 6B_4 TOC @ 7,924' 5 on Neo Plug 6 Fill @ 8,540' CTM 10/12121 d-1j2" B-6 lB7 AB7-7A LBix LB-10 LB-2 2 TD =9,802' (MD) / 8,043' (rVD) PBTD=7,924' (MD) / 6,236' (TVD) SCHEMATIC Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 109 / X-56 / Weld 15" Surf 120' 10-3/4" Surface 45.5 / L-80 / TXP BTC 9.950" Surf 3,333' 7-5/8" Intermediate 29.7 / L-80 / W563 6.875" Surf 6,824' 4-1/2" Production 12.6 / L-80 / TXP BTC 3.958" 5,365' 9,800' TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8" Tubing 6.5 / L-80 / EUE 2.441" Surf 5,391Note: tbg. tail 2-7/8" Tubing 6.5 / L-80 / F13 2.30" 5,402' 7,885' is 2.30". JEWELRY DETAIL No Depth (MD) Depth (TVD) Item 1 531' 531' SSSV-Halliburton NE SRSV 07/28/20 (PINNED OUT, INOPERABLE) 2 2,821' 2,272' 7-5/8" Swell Packer 3 5,391' 3,993' 4.5" x 5.75" Bullet Tie -Back Seal Assembly 4 5,365' 3,975' 7-5/8" X 4-1/2" Liner Hanger 5 1 7,886' 1 6,199' 1 Wireline Re-entry Guide 07/28/20 6 1 7,924' 1 6,236' 1 4.4" NEO Vented TTBP - 7,949' w/ 25' cement PERFORATION DETAIL Old Zone Name New Zone Name Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status MB_1X 7,538' 7,558' 5,825' 5,845' 20' 10/29/2021 Open MB_1 7,582' 7,592' 5,867' 5,877' 10, 10/18/2021 Open 7,727' 7,747' 6,045' 6,065' 20' 12/26/2020 Open MB 2 MB_4 7 737' 7,739' 6,055' 6,057' 2' 12/26/2020 Open MB_6 8,028' 8,042' 6,336' 6,350' 14' 9/18/2019 Plugged MB-8/8A MB_7 8,058' 8,078' 6,365' 6,384' 20' 9/18/2019 Plugged MB 3 MB_7 8,059' 8,078' 6,366' 6,384' 19, 12/26/2020 Plugged MB 4 MB-7A 8,148' 8,150' 6,451' 6,453' 2' 12/24/2020 Plugged 8,272' 8,279' 6,571' 6,577' 7' 12/23/2020 Plugged MB 7A LB-1X 8,279' 8,286' 6,577' 6,584' 7' 12/24/2020 Plugged 8,278' 8,280' 6,576' 6,578' 2 12/19/2020 Plugged 1-13-4 LB_16 8,565' 8,577' 6,852' 6,863' 12' 9/13/2019 Plugged 1-13-6 LB 2 8,642' 8,654' 6,926' 6,937' 12' 11/25/2019 Plugged FISH DETAIL 8,663' CI BP Debris08/18/20 Middle Fish RBP Pushed to Bottom 9,659' CIBP Milled and Pushed to Bottom 09/11/19 RA taps: 6809, 7304, 7829, 8318, 8811, 9347' OPEN HOLE / CEMENT DETAIL 10-3/4" 13-1/2" Hole: 272bbls (640sx) 12# class A lead cement followed by 57bbls of 15.8# Class A tail cement. Bumped plug. Full returns throughout job. 92bbls cement back to Surface 7 5/8 9-7/8" Hole: 159 bbls 12# class A lead cement followed by 59bbls of 15.3# Class A tail cement, bumped plug. 44bbls lost throughout job. 8/9/19 CBL (AKEL) TOC @ 2800' MD. 6-3/4" Hole: 125bbls 12# class A lead cement followed by 23bbls 15.3# tail cement. After 4-1/2" 124bbls displacement, lost all returns. Estimated 30bbls total lost during job. Spacer and trace cement circulated off liner top back to surface. 8/29/19 CBL TOC @ 8,910'. Updated by CAH 2/17/22 Hilcoru Alaska, LLfi RKB: MSL = 38.4' In 1&314^ CINGSAS I @ 6,787' 7-5/9- Tubing punEhes 7,476 &-< 6, 62V Fill La 7,862' CTM 1J17122 ` TOC L@ 7,924' 5 4n Neo Plug ----* 6 Fill @ 8,54U' CTM 10J12J21 11)2• I I 3 4 ,-r UBMb UB7L ABtx -klnl 6B_4 iB--6 lB7 AB7-7A LBix LB-16 LB-2 2 TD =9,802' (MD) / 8,D43' (TVD) PBTD=7,924' (MD) / 6,236' (TVD) PROPOSED SCHEMATIC Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 109 / X-56 / Weld 15" Surf 120' 10-3/4" Surface 45.5 / L-80 / TXP BTC 9.950" Surf 3,333' 7-5/8" Intermediate 29.7 / L-80 / W563 6.875" Surf 6,824' 4-1/2" Production 12.6 / L-80 / TXP BTC 3.958" 5,365' 9,800' TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8" Tubing 6.5 / L-80 / EUE 2.441" Surf 5,391' Note: tbg. tail 2-7/8" Tubing 6.5 / L-80 / FJ3 2.30" 5,402' 7,885' is 2.30". JEWELRY DETAIL No Depth (MD) Depth (TVD) Item 1 531' 531' SSSV-Halliburton NE SRSV 07/28/20 (PINNED OUT, INOPERABLE) 2 2,821' 2,272' 7-5/8" Swell Packer 3 5,391' 3,993' 4.5" x 5.75" Bullet Tie -Back Seal Assembly 4 5,365' 3,975' 7-5/8" X 4-1/2" Liner Hanger 5 1 7,886' 1 6,199' 1 Wireline Re-entry Guide 07/28/20 6 1 7,924' 1 6,236' 1 4.4" NEO Vented TTBP - 7,949' w/ 25' cement PERFORATION DETAIL Old Zone Name New Zone Name Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status UB 3A ±7,004 ±7,008 ±5,351' ±5,355' 4 Proposed TBD UB 4 ±7,024 ±7,040 ±5,370' ±5,385' 16 Proposed TBD UB 4A ±7,053 ±7,092 ±5,398' ±5,435' 39 Proposed TBD UB 5A ±7,138 ±7,158 ±5,479' ±5,498' 20 Proposed TBD UB 6 ±7,200 ±7,210 ±5,538' ±5,548' 10 Proposed TBD UB 7 Lower ±7,303 ±7,311 ±5,637' ±5,644' 8 Proposed TBD MB_1X 7,538' 7,558' 5,825' 5,845' 20' 10/29/2021 Plugged MB_1 7,582' 7,592' 5,867' 5,877' 10, 10/18/2021 Plugged MB 2 MB 4 - 7,727 7,747' 6,045' 6,065' 20' 12/26/2020 Plugged 7,737' 7,739' 6,055' 6,057' 2' 12/26/2020 Plugged MB- 8/8A M13_6 MB_7 8,028' 8,042' 6,336' 6,350' 14' 9/18/2019 Plugged 8,058' 8,078' 6,365' 6,384' 20' 9/18/2019 Plugged MB 3 MB_7 8,059' 8,078' 6,366' 6,384' 19, 12/26/2020 Plugged MB 4 M13-7A 8,148' 8,150' 6,451' 6,453' 2' 12/24/2020 Plugged MB 7A LB-1X 8,272' 8,279' 6,571' 6,577' 7' 12/23/2020 Plugged 8,279' 8,286' 6,577' 6,584' 7' 12/24/2020 Plugged 8,278' 8,280' 6,576' 6,578' 2 12/19/2020 Plugged LB-4 LB-16 8,565' 8,577' 6,852' 6,863' 12' 9/13/2019 Plugged LB-6 LB 2 8,642' 8,654' 6,926' 6,937' 12' 11/25/2019 Plugged FISH DETAIL 8,663' CIBP Debris 08/18/20 Middle Fish RBP Pushed to Bottom 9,659' CIBP Milled and Pushed to Bottom 09/11/19 RA tags: 6809, 7304, 7829, 8318, 8811, 9347' OPEN HOLE / CEMENT DETAIL 10-3/4" 13-1/2" Hole: 272bbls (640sx) 12# class A lead cement followed by 57bbls of 15.8# Class A tail cement. Bumped plug. Full returns throughout job. 92bbls cement back to Surface 7 5/8 9-7/8" Hole: 159 bbls 12# class A lead cement followed by 59bbls of 15.3# Class A tail cement, bumped plug. 44bbls lost throughout job. 8/9/19 CBL (AKEL) TOC @ 2800' MD. 6-3/4" Hole: 125bbls 12# class A lead cement followed by 23bbls 15.3# tail cement. After 4-1/2" 124bbls displacement, lost all returns. Estimated 30bbls total lost during job. Spacer and trace cement circulated off liner top back to surface. 8/29/19 CBL TOC @ 8,910'. Updated by CAH 2/28/22 Kill Pnr WH PSI 2" 1502 x 2-1/1( Flanged Val (Manual) 2-1/16 1 OK x 10K Ranged (Manual Coil Tubing BOP Coiled Tubing HR580 Injector Head & Gooseneck Weight = 12,850 Ibs 4-1/16" 10K Conventional Stripper 5K C062 Lubricator 5K C062 x 4-1/16" 10K Flange 4-1116" 10K Comb! BOP Top Set: Blind/Shear Second Set: Pipe/Slip 4-1/16" 1OK Flow Cross Manual 2x2 Valve 1: 2" 1502 x 2-1/16" 10K Range Manual 2x2 Valve 2: 2-1/16" 10K x 2-1/16" 10K Range Manual 2x2 Valve 3: 2-1/16" 10K x 2-1/16" 10K Range Manual 2x2 Valve 4: 2" 1502 x 2-1/16" 10K Range 4-1/16" 1 OK x Wellhead Adapter Flange Wellhead 11 STANDARD WELL PROCEDURE HilcorpAlaska, LLC NITROGEN OPERATIONS 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 02 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. 12/08/2015 FINALv1 Page 1 of 1 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: CT / N2 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 9,802 feet 7,949 feet true vertical 8,043 feet See schematic feet Effective Depth measured 7,924 feet See schematic feet true vertical 6,236 feet See schematic feet Perforation depth Measured depth 7,538 - 7,739 feet True Vertical depth 5,825 - 6,057 feet Tubing (size, grade, measured and true vertical depth)2-7/8" 6.5 / L-80 / FJ3 7,885 (MD) 6,198 (TVD) Packers and SSSV (type, measured and true vertical depth)See schematic 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 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: Contact Name: Contact Email: Authorized Title:Contact Phone: 4,790psi 7,500psi 3,580psi 6,890psi 8,430psi Burst Collapse 2,090psi 120' 2,616' 5,183' 8,041' 6,824' 9,800'4-1/2" measuredPlugs Junk measured N/A Length 120' 3,333' Size Conductor Surface Intermediate 16" 10-3/4" 7-5/8" Production Liner 6,824' 4,435' Casing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-078 50-133-20684-00-00 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL60569 / ADL60568 / ADL324602 / Fee Private Cannery Loop / Beluga Gas Pool Hilcorp Alaska LLC 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Cannery Loop Unit 14 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 000 0 1,017 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 120' 3,333' N/a 8 Structural TVD 321-458 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: Authorized Name and Digital Signature with Date: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 0 1,719 Chad Helgeson chelgeson@hilcorp.com (907) 777-8405 L G Form 10-404 Revised 10/2021 Submit Within 30 days of Operations By Samantha Carlisle at 3:25 pm, Nov 23, 2021 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.11.23 14:52:40 -09'00' Dan Marlowe (1267) BJM 12/1/21 RBDMS HEW 11/24/2021 SFD 11/29/2021 DSR-11/24/21 _____________________________________________________________________________________ Updated by JLL 11/21/21 SCHEMATIC Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 TD =9,802’ (MD) /8,043’ (TVD) 16” RKB: MSL = 38.4’ 6 10-3/4” 7-5/8” 3 TOC @ 7,924’ on Neo Plug MB_4 PBTD =7,924’ (MD) /6,236’(TVD) 4-1/2” 2 LB-16 MB-6 LB-2 4 5 1 MB7 MB7 - 7A LB1X MB1X – MB1 5 Fill @ 8,540’ CTM 10/12/21 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 109 / X-56 / Weld 15” Surf 120’ 10-3/4” Surface 45.5 / L-80 / TXP BTC 9.950” Surf 3,333’ 7-5/8" Intermediate 29.7 / L-80 / W563 6.875” Surf 6,824’ 4-1/2" Production 12.6 / L-80 / TXP BTC 3.958” 5,365’ 9,800’ TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8” Tubing 6.5 / L-80 / EUE 2.441” Surf 5,391’ 2-7/8” Tubing 6.5 / L-80 / FJ3 2.30”5,402’ 7,885’ JEWELRY DETAIL No Depth (MD) Depth (TVD)Item 1 531’ 531’ SSSV-Halliburton NE SRSV 07/28/20 (PINNED OUT, INOPERABLE) 2 2,821’ 2,272’ 7-5/8” Swell Packer 3 5,391’ 3,993’ 4.5” x 5.75” Bullet Tie-Back Seal Assembly 4 5,365’ 3,975’ 7-5/8” X 4-1/2” Liner Hanger 5 7,886’ 6,199’ Wireline Re-entry Guide 07/28/20 6 7,924’ 6,236’ 4.4” NEO Vented TTBP - 7,949’ w/ 25’ cement PERFORATION DETAIL Old Zone Name New Zone Name Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status MB_1X 7,538' 7,558' 5,825' 5,845' 20' 10/29/2021 Open MB_1 7,582' 7,592' 5,867' 5,877' 10' 10/18/2021 Open MB 2 MB_4 7,727' 7,747' 6,045' 6,065' 20' 12/26/2020 Open 7,737’ 7,739’ 6,055’ 6,057’ 2’ 12/26/2020 Open MB-8/8A MB_6 8,028’ 8,042’ 6,336’ 6,350’ 14’ 9/18/2019 Plugged MB_7 8,058’ 8,078’ 6,365’ 6,384’ 20’ 9/18/2019 Plugged MB 3 MB_7 8,059' 8,078' 6,366' 6,384' 19' 12/26/2020 Plugged MB 4 MB-7A 8,148' 8,150' 6,451' 6,453' 2' 12/24/2020 Plugged MB 7A LB-1X 8,272’ 8,279’ 6,571’ 6,577’ 7’ 12/23/2020 Plugged 8,279' 8,286' 6,577' 6,584' 7' 12/24/2020 Plugged 8,278’ 8,280’ 6,576’ 6,578’ 2 12/19/2020 Plugged LB-4 LB_16 8,565’ 8,577’ 6,852’ 6,863’ 12’ 9/13/2019 Plugged LB-6 LB_2 8,642’ 8,654’ 6,926’ 6,937’ 12’ 11/25/2019 Plugged FISH DETAIL 8,663’ CIBP Debris 08/18/20 Middle Fish RBP Pushed to Bottom 9,659’ CIBP Milled and Pushed to Bottom 09/11/19 Note: tbg. tail is 2.30”. MB_1X 7,538' 7,558' 5,825' 5,845' 20' 10/29/2021 Open MB_1 7,582' 7,592' 5,867' 5,877' 10' 10/18/2021 Open Rig Start Date End Date CT / E-Line 10/4/21 10/29/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name CLU-14 50-133-20684-00-00 219-078 10/05/2021 - Tuesday Conduct JSA and approve PTW. NU BOP's on well. MU 1.75" slim BHA with JSN. Load coil with water. PT stack to 250/4,000 psi. Open well. Tubing pressure = 1,590 psi. RIH 8' and well pressured up to 2,200 psi. Bleed down pressure to 400 psi. RIH and tag at 61'. Bring pump online and pump down coil at 1.5 bpm, cannot get deeper. POOH. Nozzle has gouges alongside, indicating something metal alongside nozzle. Call out YellowJacket for venturi. MU 2.16" CTC, (pull test to 20K), 1.69" MHA w/ checks and disco, (PT) 1.69" venturi. Open well. Tubing pressure = 1,150 psi. RIH and dry tag at 145'. Pick up. RIH and dry tag at 201'. pickup is ratty and having some overpull of ~ 1k. Bring pump on-line at 0.7 bpm and tag at 250'. Getting returns of gray water. POOH. Recover pieces of coal in veturi basket. Metal scrapes alongside venturi barrel. Laydown BHA, lubricator and install night cap on well. LDFN. 10/04/2021 - Monday Conduct JSA and approve PTW. Move wellhouses with crane to spot equipment. Spot coil unit, pump truck, supply tank, return tank, choke skid. Test BOPE. AOGCC waived witness per Jim Regg. Function test rams. Test full body, pipe rams, top and bottom blind/shear rams. Test to 250 psi low / 4000 psi high. Load 300 bbls of produced water to supply tank. Crane moved to Kenai to support another job. LDFN. Test to 250 psi low / 4000 psi high. Rig Start Date End Date CT / E-Line 10/4/21 10/29/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name CLU-14 50-133-20684-00-00 219-078 Conduct JSA and approve PTW. Mix 10 bbls of gel. MU cleanout BHA with downjet nozzle and jars. 2.16" CTC, 1.69" MHA (circ sub and disco), bi-di jars, 2.13" downjet nozzle. Tag at 253' with 2.13" down jet nozzle. Online with pump at 1.4 bpm @ 3,520 psi CTP. Stack down 7K lbs and cleanout to 267' ctmd. Cannot get any deeper. POOH. Have metal scarring alongside nozzle. MU 1.69" washover shoe with venturi and 1.69" motor BHA with tattle tail pins. Tag at 310' ctmd. Fish moved downhole from nozzle run. Online with pump at 0.7 bpm @ 2,400 psi free spin. Set down 7K and work down to 350'. No stalls. POOH. Metal scarring alongside entire length of venturi barrel. Metal scarring approximately 6' above bottom of washover shoe. No tattle tails remaining. Laydown BHA. Call out for LIB and larger washover shoe. MU 2.34" LIB and RIH and tag at 350' ctmd. Impression of 1/2" nut (flattened). MU 2-1/16" wash pipe with scallop guide below 1.69" venturi and motor and MHA. Wash pipe has 'shark teeth' cut to grab something inside barrel. Tag at 349'. Online with pump at 0.5 bpm at 1,860 psi. RIH to 352', no stalls. POOH. Recover lost foot valve. Laydown YellowJacket tools and cut off CTC. Laydown lubricator and install night cap. LDFN. 10/06/2021 - Wednesday Recover lost foot valve. Rig Start Date End Date CT / E-Line 10/4/21 10/29/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name CLU-14 50-133-20684-00-00 219-078 Crew arrives at facility and obtains permit. MIRU e-line and pressure test lubricator to 250 psi low / 2,500 psi high. MU TTBP assembly and RIH at 150 fpm. Correlate with open hole log and set plug at 7,920'. POOH with setting assembly and lay down same. MU dump bailer assembly and top fill with ceramic shot. RIH and dump beads at 7,910'. POOH with dump bailer and fill with cement. RIH and dump cement at 7,910'. POOH, secure equipment and well. SDFN. 10/12/2021 - Tuesday Crew arrives at facility and obtains permit. Warm up e-line equipment and begin mixing up cement. Fill bailer with 4 gallons (6.25' in 4.5" casing) and RIH with cement dump bailer run #2 of 4 total. Tag cement plug at 7,949'. Dump cement and POOH. Fill bailer with 4 gallons (6.25' in 4.5" casing) and RIH with cement dump bailer run #3 of 4 total. Dump cement and POOH. Fill bailer with 4 gallons (6.25' in 4.5" casing) and RIH with cement dump bailer run #4 of 4 total. Dump cement and POOH. 25' of cement total. Lay down lubricator and stand equipment aside for slickline. SDFN. 10/11/2021 - Monday 10/07/2021 - Thursday Conduct JSA and approve PTW. MU lubricator and 1.75" slim BHA with Down Jet Nozzle. BHA: 1.75" CTC, 1.75" DFCV, 1.75" stinger, 1.75" stinger, 1.75" DJN. PT. Open well. Tubing pressure = 1,720 psi. RIH and dry tag at 353' ctmd. Online with pump at 1.1 bpm and 3,160 psi CTP. Hold 1,200 psi on choke. Clean out sand bridges, getting 1:1 returns with gas. Wt check at 2,000' = 2,200#. Continue to clean out pumping water down coil. Work choke pressure down from 1,200 psi to 700 psi, still getting 1. 1 returns. Lose all returns at ~ 3,600' ctmd. Close choke and offline with pump. RIH with coil from 3,600'. Choke closed, no pumping. Tubing pressure = 400 psi. RIH to 8,540' ctmd. Did not tag, but pickup weights are heavy and sticky. POOH. POOH and pump down coil with water to keep the hole full. Coil at surface. Final tubing pressure = 60 psi. Close swab. Blowdown coil reel with Nitrogen. RDMO. RIH and dry tag at 353' ctmd. RIH to 8,540' ctmd. Did not tag, but pickup weights are heavy and sticky. Tag cement plug at 7,949'. Dump cement and POOH. Fill bailer with 4 gallons (6.25' in 4.5" casing) and RIH with cement dump bailer run #3 of 4 total. Dump cement and POOH. Fill bailer with 4 gallons (6.25' in 4.5" casing) and RIH with cement dump bailer run #4 of 4 total. Dump cement and POOH. 25' of cement total. L Clean out sand bridges, Lose all returns at ~ 3,600' ctmd. RIH and dump beads at 7,910'. POOH with dump bailer and fill with cement. RIH and dump cement at 7,910'. POOH, set plug at 7,920'. Rig Start Date End Date CT / E-Line 10/4/21 10/29/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name CLU-14 50-133-20684-00-00 219-078 10/29/2021- Friday PTW and JSA. Spot equipment and start rig up. Bottom shelve had pins missing. Trouble shoot and fix. Line wiper hose had wrong connections and got some from shop. Rig up lubricator, PT to 250 psi low and 2,500 psi high. Shut well in. RIH w/ GPT tool and logged to 7,850'. Saw cooling effect from 7,600' to 7,850'. Did not see any clear fluid level. TP - 860 psi POOH. Sent log to town and was told to subtract 7' and send back. Sent log back after revision and told to use it as the Perf tie in log. RIH w/2" x 20' HC, 6 spf, 60 deg phase and tie into Perf log. Run correlation log, CCL quit working but gama good and send to town. Get ok to perf from 7,538' to 7,558' w/1,126 psi. Spot and fire gun at 1727 hrs. After 5 min - 1,153.6 psi, 10 min - 1,162.7 psi and 15 min - 1,168.1 psi. POOH. All shots fired and gun was wet but bull plug didn't have a lot of fluid in it. Rig down lubricator and E-Line equip. Turn well over to field. TP - 1,229.2 psi. 10/18/2021 - Monday E-line crew arrives at facility and obtains permit. MIRU e-line equipment and pressure test lubricator to 250 psi low and 2500 psi high. RIH with 2" HC perforating gun loaded at 6 SPF. Correlate to open hole logs and perforate Beluga MB_1 from 7582-7592'. Pick up over 2000# unable to POOH toolstring is stuck. Deviated hole start working weight down to tools finally comes free at 2700#. POOH get stuck multiple times have to work at or above to maximum weakpoint tension to get free. Break lubricator and lay down tools. All shots fired. Gun literally looks like it has been sandblasted. RDMO e-line. Get ok to perf from 7,538' to 7,558' w/1,126 psi. Spot and fire gun a perforate Beluga MB_1 from 7582-7592'. P 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: 11/19/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL CLU 14 (PTD 219-078) Completion Record Perf 10/29/2021 Please include current contact information if different from above. 37' (6HW Received By: 11/22/2021 By Abby Bell at 12:20 pm, Nov 22, 2021 1 Guhl, Meredith D (CED) From:McLellan, Bryan J (CED) Sent:Friday, October 8, 2021 2:20 PM To:Todd Sidoti - (C) Subject:RE: CLU 14 (PTD 219-078) Change of Scope Hi Todd. Yes, you can proceed with this modified plan. The depth of the plug is the same and 25’ of cement meets the regs. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Todd Sidoti ‐ (C) <Todd.Sidoti@hilcorp.com> Sent: Friday, October 8, 2021 12:58 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Subject: CLU 14 (PTD 219‐078) Change of Scope Hi Bryan, We performed a successful fill clean out using coiled tubing but were unable to perform the contingent sand back cement cap procedure. We would like to set a TTP and cap it with cement instead. We propose setting a plug at 7970 and dumping 25’ of cement on top. Please let me know if you have any questions. Thanks, Todd Todd Sidoti | Kenai Field Engineer | Hilcorp Alaska | 907‐632‐4113 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: CT / N2 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? 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): 9,802'8663'; 9659' Casing Collapse Structural Conductor Surface 2,090psi Intermediate 4,790psi Production 7,500psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG 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 todd.sidoti@hilcorp.com 8,043'8,663'6,946'1,981 N/A Swell Pkr, Baker ZXP Pkr; SSSVs Halli FXE WLR & NE SRSV 2,821' MD/2,234' TVD, 5,365' MD/3,921 TVD; 507' MD/TVD & 531' MD/TVD Perforation Depth TVD (ft): Tubing Size: 2-7/8" COMMISSION USE ONLY Authorized Name: Tubing Grade: 6.5# / L-80 / EUE Tubing MD (ft): 5,391' See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL60569, ADL60568, ADL 324602, Fee Private 219-078 50-133-20684-00-00 Cannery Loop Unit (CLU) 14 Cannery Loop / Beluga Gas Pool Length Size CO 231A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY 6.5# / L-80 / FJ3 TVD Burst 7,885' 8,430psi MD 6,890psi 3,580psi 120' 2,616' 5,183' 120' 3,333' 8,041'4-1/2" 16" 10-3/4" 120' 7-5/8"6,824' 3,333' 9,800' Perforation Depth MD (ft): 6,824' See Attached Schematic 4,435' 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 21, 2021 2-7/8" wwnn amamm eee d ed ss No ss No Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 4:21 pm, Sep 08, 2021 321-458 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.09.08 15:23:33 -08'00' Taylor Wellman (2143) 10-404 CT BOP test to 4000 psi. DSR-9/8/21SFD 9/9/2021 X BJM 9/15/21 dts 9/16/2021 JLC 9/16/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.09.16 11:51:22 -08'00' RBDMS HEW 9/16/2021 Well Prognosis Well: CLU 14 Date: 9/7/2021 Well Name: CLU 14 API Number: 50-133-206684-00-00 Current Status: SI Gas Well Leg: N/A Estimated Start Date: 9/21/2021 Rig: CTU Reg. Approval Req’d? 10-403 Sundry Number: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 219-078 First Call Engineer: Todd Sidoti (907) 777-8443 (O) (907) 632-4113 (C) Second Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C) Maximum Expected BHP: ~2,563 psi @ 5,825’ TVD Based on a 0.44psi/ft gradient. Max. Potential Surface Pressure: ~1981 psi Gas gradient to surface @ 0.1 psi/ft Brief Well Summary CLU 14 is a gas producer that was drilled and completed in August 2019 targeting gas sands in the Beluga and Sterling formations. In August of 2020 a 2-7/8” velocity string was installed in the well. A CIBP That provided well control during the running of the 2-7/8” velocity string was drilled up through the 2-7/8” string and pushed to bottom. In October the tubing conveyed SCSSSV failed to close. This valve was pinned open and a WLR SCSSSV was installed in its profile. In January 2021, the SSSV was pulled and a capillary line installed to help unload water. The CLU #14 recently began producing a large quantity of solids (Sand and mud) which caused the well to be shut in. Objective The objective of this job is to plugback the MB6 and below sands with sand and perforate the MB1. Coiled Tubing 1. MIRU coiled tubing. If necessary, pressure test BOPE to 250 psi Low / 4,000 psi High. a. Notify State for option to witness. 2. MIRU nitrogen pump. 3. RIH with jet swirl nozzle. 4. Dry tag fill located at ~100’. 5. Clean out in increments with produced water and N2 down to 7920’ CTMD. a. Note well was flowing solids up hole at 1400 psi FTP. We should get decent returns with water. 6. Circulate a full bottoms up at 7920’ monitor returns and ensure no more solids are present. 7. Dry tag top of fill. 8. POOH 200’ and wait while reciprocating pipe for two hours. 9. RIH and dry tag top of fill. If tag has moved up hole contact OE. ** Contingent steps if fill is not a solid bottom below tubing tail ** 10. MU and RIH with sand laying BHA including big hole nozzle. 11. Fluid pack well with produced water while RIH. 12. Dry tag PBTD and lay in 6 ppa 20/40 river sand HEC slurry while POOH. Pump a 5 bbl clean HEC spacer before and after the sand slurry. OE will calculate how many pounds of river sand needed on location. Bulk and sack sand will be required. 13. POOH 200’ and wait while reciprocating pipe for two hours. SFD 9/9/2021 Existing and proposed perforations conform to the spacing requirements of Conservation Order 231A. plugback the MB6 and below sands with sand and perforate the MB1. Well Prognosis Well: CLU 14 Date: 9/7/2021 14. RIH and dry tag top of sand. Calculate new sand volume required to place top of sand at 7970’. Use sacked sand for this final stage of placement. 15. POOH 200’ and wait while reciprocating pipe for two hours. 16. RIH and dry tag top of sand. ** End of contingent steps ** 17. MIRU E-line on top of coil BOP. Pressure test lubricator to 250 psi low / 2,500 psi high. 18. RIH with JB/GR and tag cement fill at ~7970’. Contact OE and communicate fill depth. 19. RIH and dump bail 25’ of cement on top of fill. 20. RDMO E-line. 21. RDMO CTU. Slickline 1. MIRU Slickline. Pressure test lubricator to 250 psi low / 2,500 psi high. 2. Swab well dry to tubing tail @ 7886’. 3. RDMO Slickline. Eline 1. Perforate the following sand intervals from bottom to top: Zone Name Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt MB_1X ±7,538' ±7,558' ±5,825' ±5,845' 20' MB_1 ±7,582' ±7,592' ±5,867' ±5,877' 10' a. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to Geologist (Jeff Nelson) and Reservoir Engineer (Meredyth Richards) for confirmation. b. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record a tubing Surface pressure before each run and after each gun firing of 5, 10, 15 min reading intervals. c. The Sterling Sands are governed by Conservation Order 716. 2. POOH. RDMO e-line. 3. Turn well over to production. Slickline 1. MIRU Slickline. Pressure test lubricator to 250 psi low / 2,500 psi high. 2. Install WRSSSV in profile at 531’. Attachments 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. CT BOPE Schematic 4. Standard Nitrogen Procedure Test Safety Valve system within 5 days of return to production. bjm Statewide regulations and Storage Injection Order 9A. SFD 9/9/2021 _____________________________________________________________________________________ Updated by DMA 06-04-21 SCHEMATIC Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 109 / X-56 / Weld 15” Surf 120’ 10-3/4” Surface 45.5 / L-80 / TXP BTC 9.950” Surf 3,333’ 7-5/8" Intermediate 29.7 / L-80 / W563 6.875” Surf 6,824’ 4-1/2" Production 12.6 / L-80 / TXP BTC 3.958” 5,365’ 9,800’ TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8” Tubing 6.5 / L-80 / EUE 2.441” Surf 5,391’ 2-7/8” Tubing 6.5 / L-80 / FJ3 2.30” 5,402’ 7,885’ JEWELRY DETAIL No Depth Item 1 531’ SSSV-Halliburton NE SRSV 07/28/20 (PINNED OUT, INOPERABLE) 2 2,821’ 7-5/8” Swell Packer 3 5,391’ 4.5” x 5.75” Bullet Tie-Back Seal Assembly 4 5,365’ 7-5/8” X 4-1/2” Liner Hanger 5 7,886’ Wireline Re-entry Guide 07/28/20 PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status MB 2 7,727' 7,747' 6,045' 6,065' 20' 12/26/2020 Open MB 2 7,737’ 7,739’ 6,055’ 6,057’ 2’ 12/26/2020 Open MB-8/8A 8,028’ 8,042’ 6,336’ 6,350’ 14’ 9/18/2019 Open MB-8/8A 8,058’ 8,078’ 6,365’ 6,384’ 20’ 9/18/2019 Open MB 3 8,059' 8,078' 6,366' 6,384' 19' 12/26/2020 Open MB 4 8,148' 8,150' 6,451' 6,453' 2' 12/24/2020 Open MB 7A 8,272’ 8,279’ 6,571’ 6,577’ 7’ 12/23/2020 Open MB 7A 8,279' 8,286' 6,577' 6,584' 7' 12/24/2020 Open MB 7A 8,278’ 8,280’ 6,576’ 6,578’ 2 12/19/2020 Open LB-4 8,565’ 8,577’ 6,852’ 6,863’ 12’ 9/13/2019 Open LB-6 8,642’ 8,654’ 6,926’ 6,937’ 12’ 11/25/2019 Open FISH DETAIL 8,663’ CIBP Debris 08/18/20 Middle Fish RBP Pushed to Bottom 9,659’ CIBP Milled and Pushed to Bottom 09/11/19 Note: tbg. tail is 2.30” due to pinched connections. _____________________________________________________________________________________ Updated by TCS 09-7-21 PROPOSED SCHEMATIC Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 109 / X-56 / Weld 15” Surf 120’ 10-3/4” Surface 45.5 / L-80 / TXP BTC 9.950” Surf 3,333’ 7-5/8" Intermediate 29.7 / L-80 / W563 6.875” Surf 6,824’ 4-1/2" Production 12.6 / L-80 / TXP BTC 3.958” 5,365’ 9,800’ TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8” Tubing 6.5 / L-80 / EUE 2.441” Surf 5,391’ 2-7/8” Tubing 6.5 / L-80 / FJ3 2.30” 5,402’ 7,885’ JEWELRY DETAIL No Depth Item 1 531’ SSSV-Halliburton NE SRSV 07/28/20 (PINNED OUT, INOPERABLE) 2 2,821’ 7-5/8” Swell Packer 3 5,391’ 4.5” x 5.75” Bullet Tie-Back Seal Assembly 4 5,365’ 7-5/8” X 4-1/2” Liner Hanger 5 7,886’ Wireline Re-entry Guide 07/28/20 PERFORATION DETAIL Old Zone Name New Zone Name Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status MB_1X ±7,538' ±7,558' ±5,825' ±5,845' 20' Proposed TBD MB_1 ±7,582' ±7,592' ±5,867' ±5,877' 10' Proposed TBD MB 2 MB_4 7,727' 7,747' 6,045' 6,065' 20' 12/26/2020 Open 7,737’ 7,739’ 6,055’ 6,057’ 2’ 12/26/2020 Open MB-8/8A MB_6 8,028’ 8,042’ 6,336’ 6,350’ 14’ 9/18/2019 Open MB_7 8,058’ 8,078’ 6,365’ 6,384’ 20’ 9/18/2019 Open MB 3 MB_7 8,059' 8,078' 6,366' 6,384' 19' 12/26/2020 Open MB 4 MB-7A 8,148' 8,150' 6,451' 6,453' 2' 12/24/2020 Open MB 7A LB-1X 8,272’ 8,279’ 6,571’ 6,577’ 7’ 12/23/2020 Open 8,279' 8,286' 6,577' 6,584' 7' 12/24/2020 Open 8,278’ 8,280’ 6,576’ 6,578’ 2 12/19/2020 Open LB-4 LB_16 8,565’ 8,577’ 6,852’ 6,863’ 12’ 9/13/2019 Open LB-6 LB_2 8,642’ 8,654’ 6,926’ 6,937’ 12’ 11/25/2019 Open FISH DETAIL 8,663’ CIBP Debris 08/18/20 Middle Fish RBP Pushed to Bottom 9,659’ CIBP Milled and Pushed to Bottom 09/11/19 Note: tbg. tail is 2.30” due to pinched connections. Coiled Tubing Services Pressure Category 1 BOP Configuration (0-3,500 psi) Client: Hilcorp Date: April 3rd, 2017 Drawn: Chad Barrett Revision: 0 Well Category: CAT I 4-1/16" 10K Combi BOP Top Set: Blind/Shear Second Set: Pipe/Slip Wellhead 4-1/16" 10K Conventional Stripper 4-1/16" 10K x Wellhead Adapter Flange 5K CO62 x 4-1/16" 10K Flange 5K CO62 Lubricator 4-1/16" 10K Flow Cross Manual 2x2 Valve 1: 2" 1502 x 2-1/16" 10K Flange Manual 2x2 Valve 2: 2-1/16" 10K x 2-1/16" 10K Flange Manual 2x2 Valve 3: 2-1/16" 10K x 2-1/16" 10K Flange Manual 2x2 Valve 4: 2" 1502 x 2-1/16" 10K Flange 21 3 4 WH PSI 2" 1502 x 2-1/16 10K Flanged Valve (Manual) 2-1/16 10K x 2-1/16 10K Flanged Valve (Manual) Kill Port Coiled Tubing HR580 Injector Head & Gooseneck Weight = 12,850 lbs Cannery Loop Field CLU 14 09/07/2021 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 and return one copy of this transmittal or FAX to 907 564-4424 Received By: Date: Hilcorp North Slope, LLC Date: 06/22/2021 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 Logging Company CLU 05RD 501332047401 215160 6/15/2021 SET PLUG Yellowjacket CLU-06RD 501332049201 220074 1/26/2021 PERF Yellowjacket CLU-06RD 501332049201 220074 1/28/2021 GPT Yellowjacket CLU 14 501332068400 219078 7/23/2020 SET PLUG/PERF Yellowjacket CLU-15 501332068700 220003 5/27/2020 PERF Yellowjacket Please include current contact information if different from above. 06/28/2021 eceived By: 37' (6HW By Abby Bell at 11:55 am, Jun 28, 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: Cap String 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 9,802 feet N/A feet true vertical 8,043 feet 8,663; 9,659 (fish) feet Effective Depth measured 8,663 feet 2,821 feet true vertical 6,946 feet 2,272 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic 2-7/8" 6.5# / L-80 / EUE 5,391' MD 3,993' TVD Tubing (size, grade, measured and true vertical depth)2-7/8" 6.5# / L80 / FJ3 7,885' MD 6,199' TVD 507' MD/TVD Packers and SSSV (type, measured and true vertical depth)SSSV-Halliburton NE SRSV 527' MD/TVD 2,821' MD/2,234' TVD 5,365' MD/3,975' TVD 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:Ted Kramer Authorized Title:Operations Manager Contact Email: Contact Phone:777-8420 WINJ WAG 1,135 Water-Bbl MD 120' 3,333' 0 2,616' true vertical Packer 4-1/2"9,800' 5,183' 8,041' 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Cannery Loop / Beluga Gas PoolN/A measured TVD Tubing PressureOil-Bbl Cannery Loop Unit (CLU) 14 N/A ADL60569, ADL60568, ADL 324602, Fee Private 6,824' Plugs Junk measured measured STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-078 50-133-02684-00-00 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. N/A 122 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 111 1,935 0 Representative Daily Average Production or Injection Data 860 Swell Pkr; Baker ZXP SSSV-Halli FXE WLR; 4,435' Conductor Surface Intermediate Production 6,824' Casing Structural 16" 10-3/4" 7-5/8" Length 120' 3,333' Collapse 2,090psi 4,790psi 7,500psi Burst 8,430psi 120' 6,890psi 3,580psi tkramer@hilcorp.com Senior Engineer:Senior Res. Engineer: Authorized Signature with date: Authorized Name: 146 Casing Pressure Liner t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 1:21 pm, Jun 18, 2021 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.06.18 11:36:25 -08'00' Taylor Wellman (2143) RBDMS HEW 6/22/2021 DSR-6/21/21 SFD 6/21/2021BJM 10/11/21 Rig Start Date End Date 5/17/21 5/17/21 05/17/2021 - Monday PTW, JSA. Move in, rig up Hilcorp Capillary string truck with 3/8" string, test foot valve 3,500 psi. RIH with Capillary string to 1,000'. Hang off and test pack off. Land string at 1,000'. Rig down spool and place inside inner foot print of well house area. Rig down hot oil truck. Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name CLU-14 50-133-20684-00-00 219-078 _____________________________________________________________________________________ Updated by DMA 06-04-21 SCHEMATIC Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 109 / X-56 / Weld 15” Surf 120’ 10-3/4” Surface 45.5 / L-80 / TXP BTC 9.950” Surf 3,333’ 7-5/8" Intermediate 29.7 / L-80 / W563 6.875” Surf 6,824’ 4-1/2" Production 12.6 / L-80 / TXP BTC 3.958” 5,365’ 9,800’ TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8” Tubing 6.5 / L-80 / EUE 2.441” Surf 5,391’ 2-7/8” Tubing 6.5 / L-80 / FJ3 2.30” 5,402’ 7,885’ JEWELRY DETAIL No Depth Item 1 531’ SSSV-Halliburton NE SRSV 07/28/20 (PINNED OUT, INOPERABLE) 2 2,821’ 7-5/8” Swell Packer 3 5,391’ 4.5” x 5.75” Bullet Tie-Back Seal Assembly 4 5,365’ 7-5/8” X 4-1/2” Liner Hanger 5 7,886’ Wireline Re-entry Guide 07/28/20 PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status MB 2 7,727' 7,747' 6,045' 6,065' 20' 12/26/2020 Open MB 2 7,737’ 7,739’ 6,055’ 6,057’ 2’ 12/26/2020 Open MB-8/8A 8,028’ 8,042’ 6,336’ 6,350’ 14’ 9/18/2019 Open MB-8/8A 8,058’ 8,078’ 6,365’ 6,384’ 20’ 9/18/2019 Open MB 3 8,059' 8,078' 6,366' 6,384' 19' 12/26/2020 Open MB 4 8,148' 8,150' 6,451' 6,453' 2' 12/24/2020 Open MB 7A 8,272’ 8,279’ 6,571’ 6,577’ 7’ 12/23/2020 Open MB 7A 8,279' 8,286' 6,577' 6,584' 7' 12/24/2020 Open MB 7A 8,278’ 8,280’ 6,576’ 6,578’ 2 12/19/2020 Open LB-4 8,565’ 8,577’ 6,852’ 6,863’ 12’ 9/13/2019 Open LB-6 8,642’ 8,654’ 6,926’ 6,937’ 12’ 11/25/2019 Open FISH DETAIL 8,663’ CIBP Debris 08/18/20 Middle Fish RBP Pushed to Bottom 9,659’ CIBP Milled and Pushed to Bottom 09/11/19 Capillary String Installed 05/17/21 3/8” 2205 Stainless Steel (11,500’ spool) Top Bottom MD 0’ 1,000 TVD 0’ 1,000’ Note: tbg. tail is 2.30” due to pinched connections. 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): 9,802'8663'; 9659' Casing Collapse Structural Conductor Surface 2,090psi Intermediate 4,790psi Production 7,500psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG 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: April 16, 2021 2-7/8" 9,800' Perforation Depth MD (ft): 6,824' See Attached Schematic 4,435'8,041'4-1/2" 16" 10-3/4" 120' 7-5/8"6,824' 3,333'3,580psi 120' 2,616' 5,183' 120' 3,333' 6.5# / L-80 / FJ3 TVD Burst 7,885' 8,430psi MD 6,890psi Length Size CO 231A 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 ADL60569, ADL60568, ADL 324602, Fee Private 219-078 50-133-20684-00-00 Cannery Loop Unit (CLU) 14 Cannery Loop / Sterling Undefined Gas Pool, Beluga Gas Pool COMMISSION USE ONLY Authorized Name: Tubing Grade: 6.5# / L-80 / EUE Tubing MD (ft): 5,391' See Attached Schematic tkramer@hilcorp.com 8,043'8,663'6,946'2,006 N/A Swell Pkr, Baker ZXP Pkr; SSSVs Halli FXE WLR & NE SRSV 2,821' MD/2,234' TVD, 5,365' MD/3,921 TVD; 507' MD/TVD & 531' MD/TVD Perforation Depth TVD (ft):Tubing Size: 2-7/8" m n P 66 t Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 10:33 am, Apr 08, 2021 321-175 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.04.08 07:19:30 -08'00' Taylor Wellman (2143) DSR-4/8/21BJM 4/13/21 SFD 4/8/2021 Capillary line installation is not approved as part of this Sundry. SFD 4/8/2021 10-404 Comm 4/13/21 dts 4/13/2021 JLC 4/13/2021 RBDMS HEW 4/13/2021 Well Prognosis Well: CLU 14 Date: 4-1-2021 Well Name: CLU 14 API Number: 50-133-20684-00-00 Current Status: Producing Gas Well Leg: N/A Estimated Start Date: April 16th 2021 Rig: E-line Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 219-078 First Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) Second Call Engineer: Todd Sidoti (907) 777-8443 (O) (907) 632-4113 (C) AFE Number: Maximum Expected BHP: ~ 2,606 psi @ 6,000’ TVD (Based on offset well) Max. Potential Surface Pressure: ~ 2,006 psi (Based on expected max. BHP and gas gradient to surface (0.10psi/ft) Brief Well Summary CLU 14 is a gas producer that was drilled and completed in August 2019 targeting gas sands in the Beluga and Sterling formations. In August of 2020 a 2-7/8” velocity string was installed in the well. A CIBP was drilled up through the 2-7/8” string and pushed to bottom. In October the tubing conveyed SCSSSV failed to close. This valve was pinned open and a WLR SCSSSV was installed in its profile. In January 2021, the SSSV was pulled and a capillary line installed to help unload water. The purpose of this work/sundry is to add the LB 1A, MB3, MB1, and the MB1X sands to increase production. CINGSA Storage Pool Check - A check of the CINGSA Storage Pool in ths well showed that the bottom of the pool to be 5,113’ (TVD). The top shot in this Sundry is at 5,863’ (TVD) which is more than the 100’ buffer outlined in CO 231A (Total distance to CINGSA interval is 750’). Notes Regarding Wellbore Condition x CBL ran 8-9-2019 shows good cement behind the 7-5/8” casing down to 6,748’, which isolates the CINGSA Gas Storage Pool behind pipe. Cement could be deeper (Set depth of 7-5/8”is 6,824’, but 6,748’ is the deepest the CBL was ran. x CBL ran 8-25-2019 shows poor cement behind the 4-1/2” liner. x Casing PT’d to 3,500 psi on 8/20/2019 x This well requires a SSSV due to its close proximity to a public road. Safety Concerns x Ensure all crews are aware of stop work authority Capillary Truck to Remove Cap line. Slickline Procedure (Total distance to CINGSA interval is 750’) CINGSA Storage Pool Check - add the LB 1A, MB3, MB1, and the MB1X sands t Well Prognosis Well: CLU 14 Date: 4-1-2021 x Make a tag for fluid level and for fill prior to rigging up E-line. E-line Procedure 1) MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 3,000 psi High. 2) With the well flowing, RIH with GPT tool to 8,350’ to confirm well is clear of obstructions. (NOTE: CIBP debris @ 8,663’ previously reported). POOH W/GPT. 3) PU Perf Guns. RIH With Perf Gun and perforate the following intervals : Sand MD Top MD Bottom Total Footage (MD) TVD Top TVD Bottom MB1X ±7,537' ±7,557' 20' ±5,863' ±5,883' MB1 ±7,583' ±7,591' 8' ±5,907' ±5,915' MB3 ±7,671' ±7,679' 8' ±5,992' ±6,000' LB 1A ±8,320' ±8,327' 7' ±6,617' ±6,624' a. Well will be shot flowing. b. Proposed perfs also shown on the proposed schematic in red font. c. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. d. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. e. Use Gamma/CCL to correlate. f. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. g. These sands are governed by Conservation Order 231A. 4) POOH. 5) RD E-Line. 6) Turn well over to production. 7) (Test SSV with-in 5 days of stable production on well, SSSV testing within 14 days of stable production if applicable– notify AOGCC 24hrs before testing) 8) Capillary line may be re-installed depending upon rate. If rate is high enough to not need Capillary string, then SCSSV will be re-installed. E-line Procedure (Contingency): 1. If zone produces sand and/or water or needs to be isolated: 2. MIRU E-line, PT lubricator to 250 psi Low / 3,000 psi High. 3. RIH and set Umbrella plug above offending zone. Dump cement on plug. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic Capillary line installation is not approved. Submit separate sundry for Capillary line installation - BJM. _____________________________________________________________________________________ Updated by DMA 04-01-21 SCHEMATIC Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 109 / X-56 / Weld 15” Surf 120’ 10-3/4” Surface 45.5 / L-80 / TXP BTC 9.950” Surf 3,333’ 7-5/8" Intermediate 29.7 / L-80 / W563 6.875” Surf 6,824’ 4-1/2" Production 12.6 / L-80 / TXP BTC 3.958” 5,365’ 9,800’ TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8” Tubing 6.5 / L-80 / EUE 2.441” Surf 5,391’ 2-7/8” Tubing 6.5 / L-80 / FJ3 2.441” 5,402’ 7,885’ JEWELRY DETAIL No Depth Item 1 531’ SSSV-Halliburton NE SRSV 07/28/20 (PINNED OUT, INOPERABLE) 2 2,821’ 7-5/8” Swell Packer 3 5,391’ 4.5” x 5.75” Bullet Tie-Back Seal Assembly 4 5,365’ 7-5/8” X 4-1/2” Liner Hanger 5 7,886’ Wireline Re-entry Guide 07/28/20 PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status MB 2 7,727' 7,747' 6,045' 6,065' 20' 12/26/2020 Open MB 2 7,737’ 7,739’ 6,055’ 6,057’ 2’ 12/26/2020 Open MB-8/8A 8,028’ 8,042’ 6,336’ 6,350’ 14’ 9/18/2019 Open MB-8/8A 8,058’ 8,078’ 6,365’ 6,384’ 20’ 9/18/2019 Open MB 3 8,059' 8,078' 6,366' 6,384' 19' 12/26/2020 Open MB 4 8,148' 8,150' 6,451' 6,453' 2' 12/24/2020 Open MB 7A 8,272’ 8,279’ 6,571’ 6,577’ 7’ 12/23/2020 Open MB 7A 8,279' 8,286' 6,577' 6,584' 7' 12/24/2020 Open MB 7A 8,278’ 8,280’ 6,576’ 6,578’ 2 12/19/2020 Open LB-4 8,565’ 8,577’ 6,852’ 6,863’ 12’ 9/13/2019 Open LB-6 8,642’ 8,654’ 6,926’ 6,937’ 12’ 11/25/2019 Open FISH DETAIL 8,663’ CIBP Debris 08/18/20 Middle Fish RBP Pushed to Bottom 9,659’ CIBP Milled and Pushed to Bottom 09/11/19 Capillary String Installed 02/01/21 3/8” 2205 Stainless Steel (11,500’ spool) Top Bottom MD 0’ 7,700’ TVD 0’ 6,019’ _____________________________________________________________________________________ Updated by DMA 04-01-21 PROPOSED SCHEMATIC Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 109 / X-56 / Weld 15” Surf 120’ 10-3/4” Surface 45.5 / L-80 / TXP BTC 9.950” Surf 3,333’ 7-5/8" Intermediate 29.7 / L-80 / W563 6.875” Surf 6,824’ 4-1/2" Production 12.6 / L-80 / TXP BTC 3.958” 5,365’ 9,800’ TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8” Tubing 6.5 / L-80 / EUE 2.441” Surf 5,391’ 2-7/8” Tubing 6.5 / L-80 / FJ3 2.441” 5,402’ 7,885’ JEWELRY DETAIL No Depth Item 1 531’ SSSV-Halliburton NE SRSV 07/28/20 (PINNED OUT, INOPERABLE) 2 2,821’ 7-5/8” Swell Packer 3 5,391’ 4.5” x 5.75” Bullet Tie-Back Seal Assembly 4 5,365’ 7-5/8” X 4-1/2” Liner Hanger 5 7,886’ Wireline Re-entry Guide 07/28/20 PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status MB1X ±7,537' ±7,557' ±5,863' ±5,883' 20' Proposed TBD MB1 ±7,583' ±7,591' ±5,907' ±5,915' 8' Proposed TBD MB3 ±7,671' ±7,679' ±5,992' ±6,000' 8' Proposed TBD MB 2 7,727' 7,747' 6,045' 6,065' 20' 12/26/2020 Open MB 2 7,737’ 7,739’ 6,055’ 6,057’ 2’ 12/26/2020 Open MB-8/8A 8,028’ 8,042’ 6,336’ 6,350’ 14’ 9/18/2019 Open MB-8/8A 8,058’ 8,078’ 6,365’ 6,384’ 20’ 9/18/2019 Open MB 3 8,059' 8,078' 6,366' 6,384' 19' 12/26/2020 Open MB 4 8,148' 8,150' 6,451' 6,453' 2' 12/24/2020 Open MB 7A 8,272’ 8,279’ 6,571’ 6,577’ 7’ 12/23/2020 Open MB 7A 8,279' 8,286' 6,577' 6,584' 7' 12/24/2020 Open MB 7A 8,278’ 8,280’ 6,576’ 6,578’ 2 12/19/2020 Open LB 1A ±8,320' ±8,327' ±6,617' ±6,624' 7' Proposed TBD LB-4 8,565’ 8,577’ 6,852’ 6,863’ 12’ 9/13/2019 Open LB-6 8,642’ 8,654’ 6,926’ 6,937’ 12’ 11/25/2019 Open FISH DETAIL 8,663’ CIBP Debris 08/18/20 Middle Fish RBP Pushed to Bottom 9,659’ CIBP Milled and Pushed to Bottom 09/11/19 Capillary String Installed 02/01/21 3/8” 2205 Stainless Steel (11,500’ spool) Top Bottom MD 0’ 7,700’ TVD 0’ 6,019’ Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 01/18/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL CLU 14 (PTD 219-078) PERFORATING RECORD 12/26/2020 Please include current contact information if different from above. PTD: 2190780 E-Set: 34577 Received by the AOGCC 01/19/2021 Abby Bell 01/19/2021 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: Pull SCSSV, Run Cap String 2.Operator Name:4.Current Well Class:5. Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? 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): 9,802'8,663' Casing Collapse Structural Conductor Surface 2,090psi Intermediate 4,790psi Production 7,500psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG 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 jake.flora@hilcorp.com 8,043'9,659'7,903'2,221 N/A Swell Pkr; SSSV-Halliburton NE SRSV Swell Pkr 2,821' MD (2,234' TVD); Lnr Top Pkr 5,365' MD ( 3,921 TVD) 531' MD/TVD Perforation Depth TVD (ft): Tubing Size: 2-7/8" COMMISSION USE ONLY Authorized Name: Tubing Grade: 6.5# / L-80 / EUE Tubing MD (ft): 5,391' See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL60569, ADL60568, ADL 324602, Fee Private 219-078 50-133-20684-00-00 Cannery Loop Unit (CLU) 14 Cannery Loop / Sterling Undefined Gas Pool, Beluga Gas Pool Length Size CO 231A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY 6.5# / L-80 / FJ3 TVD Burst 7,885' 8,430psi MD 6,890psi 3,580psi 120' 2,616' 5,183' 120' 3,333' 8,041'4-1/2" 16" 10-3/4" 120' 7-5/8"6,824' 3,333' 9,800' Perforation Depth MD (ft): 6,824' See Attached Schematic 4,435' 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: January 30, 2021 2-7/8" Perforate Repair Wepair Well Exploratory Stratigraphic Development Service BOP TestMechanical Integrity Test Location Clearance No No Wellbore schematic Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 1:40 pm, Jan 15, 2021 321-031 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2021.01.15 13:05:29 -09'00' Taylor Wellman SFD 1/19/2021 10-404 *SSSV waived under 20 AAC 25.265(d)(4) Pull SCSSV, Run Cap String DSR-1/19/21gls 1/21/21Comm. 1/22/21 dts 1/22/2021 JLC 1/22/2021 RBDMS HEW 1/27/2020 Well Prognosis Well: CLU 14 Date: 1-14-2021 Well Name: CLU 14 API Number: 50-133-20684-00-00 Current Status: Producing Gas Well Leg: N/A Estimated Start Date: January 30, 2021 Rig: Cap String Truck Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 219-078 First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C) Second Call Engineer: Todd Sidoti (907) 777-8443 (O) (907) 632-4113 (C) AFE Number: Maximum Expected BHP: ~ 2,879 psi @ 6,584’ TVD (Based on normal gradient) Max. Potential Surface Pressure: ~ 2,221 psi @ 6,584’ TVD (Based on expected max. BHP and gas gradient to surface (0.10psi/ft) Brief Well Summary CLU 14 is a gas producer that was drilled and completed in August 2019 targeting gas sands in the Beluga and Sterling formations. In August of 2020 a 2-7/8” velocity string was installed in the well. A CIBP was drilled up through the 2-7/8” string and pushed to bottom. In October the tubing conveyed SCSSSV failed to close. This valve was pinned open and a WLR SCSSSV was installed in its profile. In December of 2020, the MB7A, MB4, MB3, and MB2 Sands were added. The IP of this addition was 2.9MM MCFD. The rate has started dropping right away and currently the well is making 1.6 MM . The purpose of this work/sundry is to add a capillary string in order to inject soap into the well to help unload water. Notes Regarding Wellbore Condition x CBL ran 8-9-2019 shows good cement behind the 7-5/8” casing down to 6,748’, which isolates the CINGSA Gas Storage Pool behind pipe. Cement could be deeper (Set depth of 7-5/8”is 6,824’, but 6,748’ is the deepest the CBL was ran. x CBL ran 8-25-2019 shows poor cement behind the 4-1/2” liner. x Casing PT’d to 3,500 psi on 8/20/2019 x This well requires a SSSV due to its close proximity to a public road. o Note: The installation of the Capillary string will replace the SSSV in this well. Safety Concerns x Ensure all crews are aware of stop work authority Slickline Procedure x Remove WLR SCSSSV Capillary Truck Procedure Well Prognosis Well: CLU 14 Date: 1-14-2021 1. RU Cap String Truck. 2. Stab 3/8” capillary line into wellhead pack-off assembly. Make up BHA components. Install pack-off and pressure test against swab valve 250 psi low/3,000 psi high. 3. RIH with 3/8” capillary string to ±7,700’ MD. 4. Install slips and connect tubing to chemical injection pump. 5. RDMO Capillary Truck. 6. Turn well over to production. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic _____________________________________________________________________________________ Updated by DMA 01-06-21 SCHEMATIC Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 TD =9,802’ (MD) / 8,043’ (TVD) 16” RKB: MSL = 38.4’ 10-3/43”44 7-5/8” 3 MB2 PBTD =9,659’ (MD) / 7,903’ (TVD) 4-1/2” 1A 2 LB-4 MB-8/8A LB-6 4 5 1 MB3 MB4 MB7A CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 109 / X-56 / Weld 15”Surf 120’ 10-3/4”Surface 45.5 /L-80 /TXP BTC 9.950”Surf 3,333’ 7-5/8"Intermediate 29.7 /L-80 /W563 6.875”Surf 6,824’ 4-1/2"Production 12.6 / L-80 / TXP BTC 3.958”5,365’9,800’ TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8”Tubing 6.5 /L-80 /EUE 2.441”Surf 5,391’ 2-7/8”Tubing 6.5 / L-80 / FJ3 2.441” 5,402’7,885’ JEWELRY DETAIL No Depth Item 1 530’WIRELINE RETRIEVABLE SSSV 1A 531’SSSV-Halliburton NE SRSV07/28/20 2 2,821’7-5/8” Swell Packer 3 5,391’4.5” x 5.75” Bullet Tie-Back Seal Assembly 4 5,365’7-5/8” X 4-1/2” Liner Hanger 5 7,886’Wireline Re-entry Guide 07/28/20 PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status MB 2 7,727'7,747'6,045'6,065'20'12/26/2020 Open MB 2 7,737’ 7,739’ 6,055’ 6,057’2’12/26/2020 Open MB-8/8A 8,028’8,042’6,336’ 6,350’14’9/18/2019 Open MB-8/8A 8,058’8,078’6,365’6,384’20’9/18/2019 Open MB 3 8,059'8,078'6,366'6,384'19'12/26/2020 Open MB 4 8,148'8,150'6,451'6,453'2'12/24/2020 Open MB 7A 8,272’8,279’6,571’6,577’ 7’12/23/2020 Open MB 7A 8,279'8,286'6,577'6,584'7'12/24/2020 Open MB 7A 8,278’8,280’ 6,576’ 6,578’2 12/19/2020 Open LB-4 8,565’8,577’6,852’6,863’12’9/13/2019 Open LB-6 8,642’ 8,654’ 6,926’ 6,937’12’11/25/2019 Open FISH DETAIL 8,663’ CIBP Debris 08/18/20 Middle Fish RBP Pushed to Bottom 9,659’ CIBP Milled and Pushed to Bottom 09/11/19 _____________________________________________________________________________________ Updated by JMF 01-14-21 PROPOSED SCHEMATIC Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 TD =9,802’ (MD) / 8,043’ (TVD) RKB: MSL = 38.4’ 10-3/4”44 7-5/8” 3 MB2 PBTD =9,659’ (MD) / 7,903’ (TVD) 4-1/2” 2 LB-4 MB-8/8A LB-6 4 5 1 MB3 MB4 MB7A 3/8” Cap String ~ 7700’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 109 / X-56 / Weld 15”Surf 120’ 10-3/4”Surface 45.5 /L-80 /TXP BTC 9.950”Surf 3,333’ 7-5/8"Intermediate 29.7 /L-80 /W563 6.875”Surf 6,824’ 4-1/2"Production 12.6 / L-80 / TXP BTC 3.958”5,365’9,800’ TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8”Tubing 6.5 /L-80 /EUE 2.441”Surf 5,391’ 2-7/8”Tubing 6.5 / L-80 / FJ3 2.441” 5,402’7,885’ JEWELRY DETAIL No Depth Item 1 531’SSSV-Halliburton NE SRSV 07/28/20 (PINNED OUT, INOPERABLE) 2 2,821’7-5/8” Swell Packer 3 5,391’4.5” x 5.75” Bullet Tie-Back Seal Assembly 4 5,365’7-5/8” X 4-1/2” Liner Hanger 5 7,886’Wireline Re-entry Guide07/28/20 PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status MB 2 7,727'7,747'6,045'6,065'20'12/26/2020 Open MB 2 7,737’ 7,739’ 6,055’ 6,057’2’12/26/2020 Open MB-8/8A 8,028’8,042’6,336’ 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ƚŽǁŽƌŬƚŚƌŽƵŐŚ͕ŶŽƚƐƵĐĐĞƐƐ͘WŝĐŬƵƉǁĞŝŐŚƚƐĂƌĞĐůĞĂŶ͕ŵŝŶŝŵĂůŽǀĞƌƉƵůů͘WKK,ĂŶĚĐůŽƐĞƐǁĂď͘>ĂǇĚŽǁŶŐƵŶ͘ZDK͘ ϭϮͬϮϯͬϮϬϮϬͲtĞĚŶĞƐĚĂǇ ^ŝŐŶŝŶ͕ŵŽďĞƚŽůŽĐĂƚŝŽŶĂŶĚĚŽĂWdtͬ:^͘tĂŝƚƚƌƚƌŝͲƉůĞǆĨƌŽŵŽƚŚĞƌƉĞƌĨũŽď͘dƌŝƉůĞǆŐŽƚŚĞƌĞ͘WdůƵďƌŝĐĂƚŽƌƚŽϮϱϬƉƐŝ ůŽǁĂŶĚϯ͕ϬϬϬƉƐŝŚŝŐŚ͘tĞůůĨůŽǁϰϴϬ͘ϰ<Ăƚϳϱ͘ϳƉƐŝ͘ZĂŶŝŶŚŽůĞǁŝƚŚϮΗǆϮϬΖĐĂƌƌŝĞƌůŽĂĚĞĚǁŝƚŚϭϰĐŚĂƌŐĞƐͿ͕>ͬƐŚŽŽƚŝŶŐ 'ZĂŶĚƚŝĞĚŝŶƚŽ>͘^ĞƚĚŽǁŶĂƚϴ͕ϬϵϱΖ͘WƵůůĞĚϱϬϬůďƐŽǀĞƌůŝŶĞǁƚƚŽŐĞƚĨƌĞĞ͘dƌĞĞĂŐĂŝŶĂŶĚƐĂŵĞƚŚŝŶŐ͘WKK,͘ĂůůĞĚ ƚŽǁŶĂŶĚĚŝƐĐƵƐƐĞĚ͘ĞĐŝƐŝŽŶǁĂƐŵĂĚĞƚŽŐŽƚŽƌƵŶƚŚĞϭϬΖĐĂƌƌŝĞƌůŽĂĚĞĚǁŝƚŚϳΖŽĨĐŚĂƌŐĞƐ͘Z/,ǁͬϮΗǆϭϭΖ͕ϲƐƉĨ͕ϲϬĚĞŐ ƉŚĂƐĞ͕>ͬ'Z͕ϱΖǁƚďĂƌĂŶĚƐĂƚĚŽǁŶĂƚϴ͕Ϭϵϱ͘dƌŝĞĚĐŽƵƉůĞƚŝŵĞƐĂŶĚƐƚŝůůƉƵůůĞĚϯϬϬůďůŝŶĞƚĞŶƐŝŽŶǁŚĞŶǁĞƉŝĐŬĞĚƵƉ ǁƚ͘ĂůůĞĚƚŽǁŶĂŶĚĚŝƐĐƵƐƐĞĚ͘ĞĐŝƐŝŽŶǁĂƐŵĂĚĞƚŽƐĞŶĚĞŶŐŝŶĞĞƌďĂĐŬƚŽĂŚŽƉĂŶĚůŽŽŬĨŽƌƚŚĞĞͲůŝŶĞ<ŶƵĐŬůĞ:ŽŝŶƚƐ ;<:Ϳ͘WKK,͘,^ĞŶŐŝŶĞĞƌĨŽƵŶĚϱ<:ΖƐĂŶĚĐĂŵĞďĂĐŬƚŽƉĂĚ͘DhͬĂŶĚƌƵŶŝŶŚŽůĞǁŝƚŚϮΗǆϭϭΖĐĂƌƌŝĞƌ;ϳĐŚĂƌŐĞƐůŽĂĚĞĚͿ͕ <:͕>ͬ^ŚŽŽƚŝŶŐ'Z͕E:͕ϭͬϭͲϭϭͬϭϲΗǆϳϱΖǁƚďĂƌĂŶĚƌŽƉĞƐŽĐŬĞƚ͘ǁĞŶƚŽŶĚŽǁŶŚŽůĞĂŶĚŚĂĚƚŽǁŽƌŬƚŽŽůƐƉĂƐƚϴ͕ϬϵϱΖ͘ dŝĞŝŶƚŽ>ůŽŐ͕ƌƵŶĐŽƌƌĞůĂƚŝŽŶůŽŐĂŶĚƐĞŶĚƚŽƚŽǁŶ͘dŽůĚƚŽƐŚŝĨƚŽƵƌůŽŐĚŽǁŶϮΖ͘^ŚŝĨƚĞĚůŽŐĂŶĚƐƉŽƚƚĞĚŐƵŶĨƌŽŵ ϴ͕ϮϳϮΖƚŽϴ͕ϮϳϵΖ͘&ŝƌĞĚŐƵŶǁŝƚŚϱϰϵ͘ϳ<Ăƚϭϯϯ͘ϰƉƐŝ͘ĨƚĞƌϱŵŝŶͲϱϱϮ͘Ϭ<ͬϭϯϳ͘ƉƐŝ͕ϭϬŵŝŶͲϱϱϰ͘ϭ<ͬϭϯϯ͘ϯƉƐŝĂŶĚϱϰϴ͘ϴ<Ăƚ ϭϯϱ͘ϰƉƐŝ͘WKK,͘ůůƐŚŽƚƐĨŝƌĞĚͬŐƵŶǁĂƐǁĞƚ͘^&E͘dƵƌŶǁĞůůŽǀĞƌƚŽĨŝĞůĚ͘ ϭϮͬϮϰͬϮϬϮϬͲdŚƵƌƐĚĂǇ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞůůKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ >hͲϭϰϱϬͲϭϯϯͲϮϬϲϴϰͲϬϬͲϬϬ ϮϭϵͲϬϳϴ ĚƐƉŽƚƚĞĚŐƵŶĨƌŽŵ ϴ͕ϮϳϮΖƚŽϴ͕ϮϳϵΖ͘&ŝƌĞĚŐƵŶǁ ĨŝƌĞĚŐƵŶĨƌŽŵϴ͕ϮϳϵΖƚŽϴ͕ϮϴϲΖ ŽƐŚŽƚϮΖĨƌŽŵϴ͕ϭϰϴΖƚŽϴ͕ϭϱϬΖ͘^ WĞƌĨŽƌĂƚĞϴ͕ϮϳϴΖͲϴ͕ϮϴϬΖ͘t ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ϭϮͬϭϵͬϮϬ ϮͬϭͬϮϭ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞůůKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ >hͲϭϰϱϬͲϭϯϯͲϮϬϲϴϰͲϬϬͲϬϬ ϮϭϵͲϬϳϴ ϬϮͬϬϭͬϮϬϮϭͲDŽŶĚĂǇ ƌƌŝǀĞŽŶůŽĐĂƚŝŽŶ͘^ƚĂƌƚĂƉƐƚƌŝŶŐƚƌƵĐŬ͘Wdtͬ:^ǁŝƚŚƉƌŽĚƵĐƚŝŽŶƉĂĚŽƉĞƌĂƚŽƌ͘ZĞĚƌĞƐƐϰ͘ϱΗKƚŝƐƚŚƌĞĂĚĞĚǁĞůůŚĞĂĚ ĐŽŶŶĞĐƚŝŽŶ͘ZĞƉůĂĐĞŚĂŶŐĞƌƐĞĂůƐĂŶĚƉĂĐŬŽĨĨĞůĞŵĞŶƚ͘ZĞďƵŝůĚĚŽǁŶŚŽůĞĨŽŽƚǀĂůǀĞ͘^ĞƚƉƌĞƐƐƵƌĞƌĞůŝĞĨƚŽϯ͕ϭϱϬƉƐŝ͘&ŽŽƚ ǀĂůǀĞƐƵĐĐĞƐƐĨƵůůǇĨƵŶĐƚŝŽŶĞĚ͘^ƚĂďĂƉƐƚƌŝŶŐŝŶƚŽŝŶũĞĐƚŽƌŚĞĂĚĂŶĚƉĂĐŬŽĨĨĂƐƐĞŵďůǇ͘ZĞŵŽǀĞƐŽĂƉůĂƵŶĐŚĞƌͬŶŝŐŚƚĐĂƉ ĨƌŽŵǁĞůů͘DĂŬĞƵƉĚŽǁŶŚŽůĞĨŽŽƚǀĂůǀĞ͘^ĞƚĂŶĚƚĞƐƚƉŽƉŽĨĨƉƌĞƐƐƵƌĞƚŽϯ͕ϭϱϬƉƐŝ͘^ƚĂďŽŶǁĞůů͘Z/,ǁŝƚŚϯͬϴΗ^^ ĂƉŝůůĂƌǇƚƵďŝŶŐƚŽϳ͕ϳϬϬΖ͘ůĞĂŶƉŝĐŬƵƉǁĞŝŐŚƚĂƚϳ͕ϳϬϬΖŝƐϭ͕ϵϱϬůďƐŽŶǁĞŝŐŚƚŐĂƵŐĞ͘/ŶƐƚĂůůŚĂŶŐĞƌďůŽĐŬƐĂŶĚůĂŶĚĐĂƉ ƐƚƌŝŶŐ͘ZŝŐĚŽǁŶĐĂƉƐƚƌŝŶŐƚƌƵĐŬĂŶĚƚƵƌŶǁĞůůŽǀĞƌƚŽƉƌŽĚƵĐƚŝŽŶƚŽƐƚĂƌƚƉƵŵƉŝŶŐƐŽĂƉ͘ ϭϮͬϮϲͬϮϬϮϬͲ^ĂƚƵƌĚĂǇ ^ŝŐŶŝŶ͕ŵŽďĞƚŽůŽĐĂƚŝŽŶ͘Wdt͕:^͕ƐƉŽƚĞƋƵŝƉŵĞŶƚĂŶĚƌŝŐƵƉůƵďƌŝĐĂƚŽƌ͘WdƚŽϮϱϬƉƐŝůŽǁĂŶĚϯ͕ϱϬϬƉƐŝŚŝŐŚ͘tĞůů ĨůŽǁŝŶŐϱϭϯ͘Ϯ<Ăƚϳϭ͘ϴƉƐŝ͘tĞĂƌĞƚƌǇŝŶŐϳΖŐƵŶƐŝŶƐƚĞĂĚŽĨϭϭΖŐƵŶƐ͘tĞĨŽƵŶĚϯͲϳΖŐƵŶƐǇĞƐƚĞƌĚĂǇ͘tŝůůŚŽůĚϱΖŽĨ ĐŚĂƌŐĞƐ͘tŝůůƉĞƌĨǁŝƚŚǁĞůůĨůŽǁŝŶŐ͘Z/,ǁͬϮΗǆϳΖΖ,;ϱΖůŽĂĚĞĚͿ͕ϲƐƉĨ͕ϲϬĚĞŐƉŚĂƐĞ͕<:͕>ͬƐŚŽŽƚŝŶŐ'Z͕<:͕ϭͲϭϭͬϭϲΗǁƚ ďĂƌĂŶĚƌŽƉĞƐŽĐŬĞƚ͘^ĞƚĚŽǁŶĂƚƐĂŵĞƉůĂĐĞĂƚϴϭϬϬΖ͘dƌŝĞĚŚŝƚƚŝŶŐŝƚŶŽƌŵĂů͕ŚĂƌĚĂŶĚƐůŽǁ͘ůůŚĂĚĂƉƉƌŽǆ͘ϲϬϬůďŵŽƌĞ ƉŝĐŬƵƉǁĞŝŐŚƚ͘tĞůůĨůŽǁŝŶŐϱϭϬ͘ϲD&ĂƚϲϮ͘ϭƉƐŝ͘ĂůůĞĚƚŽǁŶĂŶĚĚŝƐĐƵƐƐĞĚ͘ĞĐŝĚĞĚƚŽďǇͲƉĂƐƐƚŚĞDϰǌŽŶĞ͘ WKK,͘tŚŝůĞƉƵůůŝŶŐŽƵƚŽĨŚŽůĞ/ǁĞŶƚŽǀĞƌƚŽŽĨĨŝĐĞĂŶĚƚŚĞƌĂƚĞǁĂƐƐŚŽǁŝŶŐϭ͘ϭŵŝůůŝŽŶĂƚϵϬ͘ϮƉƐŝ͘/ůĞƚƚŚĞĨŝĞůĚŬŶŽǁ ďƵƚĂƐǁĞŐŽƚŽƵƚŽĨŚŽůĞŝƚǁĂƐďĂĐŬƚŽϱϭϯ<Ăƚϲϲ͘ϰƉƐŝ͘Z/,ǁͬϮΗǆϭϵΖ,͕ϲƐƉĨ͕ϲϬĚĞŐƉŚĂƐĞƐŚŽŽƚŝŶŐ'ĂŵĂͬ>͕ϮͲϮΗ ǁƚƐĂŶĚZ^͘dŝĞŝŶƚŽK,>ĂŶĚƚĂŐĂƚϴϭϬϬ͘ZƵŶĐŽƌƌĞůĂƚŝŽŶůŽŐĂŶĚƐĞŶĚƚŽƚŽǁŶ͘'ĞƚŽŬƚŽƉĞƌĨĨƌŽŵϴ͕ϬϱϵΖƚŽϴ͕ϬϳϴΖ;D ϯͿ͘^ƉŽƚƚĞĚĂŶĚĨŝƌĞĚŐƵŶǁŝƚŚϱϮϭ͘Ϯ<ͬϲϴ͘ϮƉƐŝ͘ĨƚĞƌϱŵŝŶͲϱϰϭ͘ϰ<ͬϲϵ͘ϭƉƐŝ͕ϭϬŵŝŶͲϱϮϮ͘Ϯ<ͬϲϲ͘ϵƉƐŝĂŶĚϭϱŵŝŶͲ ϰϭϰ͘ϵ<ͬϲϰ͘ϴƉƐŝ͘WKK,͘ůůƐŚŽƚƐĨŝƌĞĚͬ'ƵŶǁĞƚ͘Z/,ǁͬϮΗǆϮΖ,͕ϲƐƉĨ͕ϲϬĚĞŐƉŚĂƐĞƐŚŽŽƚŝŶŐ'ĂŵĂͬ>͕ϮͲϮΗǁƚƐĂŶĚ Z^͘ZƵŶĐŽƌƌĞůĂƚŝŽŶůŽŐĂŶĚƐĞŶĚƚŽƚŽǁŶ͘'ŽƚŽŬƚŽƉĞƌĨĨƌŽŵϳ͕ϳϯϳΖƚŽϳ͕ϳϯϵͲǁŝƚŚϱϰϰ<ͬϲϵ͘ϵƉƐŝ͘^ƉŽƚƚĞĚĂŶĚĨŝƌĞĚŐƵŶ͘ ĨƚĞƌϱŵŝŶͲϱϮϳ<ͬϲϵƉƐŝ͕ϭϬŵŝŶͲϱϬϯ͘ϵ<ͬϲϴ͘ϵƉƐŝĂŶĚϭϱŵŝŶͲϱϬϲ͘ϭ<ͬϲϴ͘ϯƉƐŝ͘WKK,͘ĂůůƐŚŽƚƐĨŝƌĞĚͬŐƵŶǁĂƐǁĞƚ͘Z/, ǁͬϮΗǆϮϬΖ,͕ϲƐƉĨ͕ϲϬĚĞŐƉŚĂƐĞƐŚŽŽƚŝŶŐ'ĂŵĂͬ>͕ϭͲϮΗǁƚƐĂŶĚZ^͘ZƵŶĐŽƌƌĞůĂƚŝŽŶůŽŐĂŶĚƐĞŶĚƚŽƚŽǁŶ͘'ŽƚŽŬƚŽ ƉĞƌĨƚŚĞDϮǌŽŶĞĨƌŽŵϳ͕ϳϮϳΖƚŽϳ͕ϳϰϳΖǁŝƚŚϲϬϴ͘ϯ<ͬϳϭ͘ϳƉƐŝ͘^ƉŽƚĂŶĚĨŝƌĞŐƵŶ͘dŽŽŬĂƉƉƌŽǆ͘ϭ͕ϬϬϬŽǀĞƌƉƵůůƚŽŐĞƚĨƌĞĞ͘ ĨƚĞƌϱŵŝŶͲϵϲϰ͘ϰ<ͬϭϭϳ͘ϱƉƐŝ͕ϭϬŵŝŶͲϭ͘ϮϱϵŵŝůͬϭϱϴƉƐŝĂŶĚϭϱŵŝŶͲϭ͘ϲϯϵŵŝůͬϮϰϲ͘ϳƉƐŝ͘WKK,͘ůůƐŚŽƚƐĨŝƌĞĚͬŐƵŶǁĂƐ ǁĞƚ͘ĂůůĞĚƚŽǁŶĂŶĚǁĂƐƚŽůĚƚŽƌŝŐĚŽǁŶ͘ZŝŐĚŽǁŶ,ĂůůŝďƵƌƚŽŶĂŶĚƚƵƌŶǁĞůůŽǀĞƌƚŽĨŝĞůĚ͘&ůŽǁŝŶŐϮ͘ϰϭϰŵŝůůŝŽŶĂƚ ϯϮϱ͘ϲƉƐŝ͘ͲϭϳϰϱŚƌƐ͘ ƉĞƌĨĨƌŽŵϳ͕ϳϯϳΖƚŽϳ͕ϳϯϵͲ Z/,ǁŝƚŚϯͬϴΗ^^ ĂƉŝůůĂƌǇƚƵďŝŶŐƚŽϳ͕ϳϬϬΖ͘ ^ƉŽƚĂŶĚĨŝƌĞŐƵŶ͘d ĞĐŝĚĞĚƚŽďǇͲƉĂƐƐƚŚĞDϰǌŽŶĞ͘ ĨƌŽŵϳ͕ϳϮϳΖƚŽϳ͕ϳϰϳΖ 'ĞƚŽŬƚŽƉĞƌĨĨƌŽŵϴ͕ϬϱϵΖƚŽϴ͕ϬϳϴΖ;D ϯͿ͘^ƉŽƚƚĞĚĂŶĚĨŝƌĞĚŐƵŶǁ ^ƉŽƚƚĞĚĂŶĚĨŝƌĞĚŐƵŶ͘ 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Dϰϴ͕ϭϰϴΖϴ͕ϭϱϬΖϲ͕ϰϱϭΖϲ͕ϰϱϯΖϮΖϭϮͬϮϰͬϮϬϮϬKƉĞŶ Dϳϴ͕ϮϳϮ͛ϴ͕Ϯϳϵ͛ϲ͕ϱϳϭ͛ϲ͕ϱϳϳ͛ϳ͛ϭϮͬϮϯͬϮϬϮϬKƉĞŶ Dϳϴ͕ϮϳϵΖϴ͕ϮϴϲΖϲ͕ϱϳϳΖϲ͕ϱϴϰΖϳΖϭϮͬϮϰͬϮϬϮϬKƉĞŶ Dϳϴ͕Ϯϳϴ͛ϴ͕ϮϴϬ͛ϲ͕ϱϳϲ͛ϲ͕ϱϳϴ͛ϮϭϮͬϭϵͬϮϬϮϬKƉĞŶ >Ͳϰϴ͕ϱϲϱ͛ϴ͕ϱϳϳ͛ϲ͕ϴϱϮ͛ϲ͕ϴϲϯ͛ϭϮ͛ϵͬϭϯͬϮϬϭϵKƉĞŶ >Ͳϲϴ͕ϲϰϮ͛ϴ͕ϲϱϰ͛ϲ͕ϵϮϲ͛ϲ͕ϵϯϳ͛ϭϮ͛ϭϭͬϮϱͬϮϬϭϵKƉĞŶ &/^,d/> ϴ͕ϲϲϯ͛/WĞďƌŝƐϬϴͬϭϴͬϮϬ DŝĚĚůĞ&ŝƐŚZWWƵƐŚĞĚƚŽŽƚƚŽŵ ϵ͕ϲϱϵ͛/WDŝůůĞĚĂŶĚWƵƐŚĞĚƚŽŽƚƚŽŵϬϵͬϭϭͬϭϵ ĂƉŝůůĂƌǇ^ƚƌŝŶŐ /ŶƐƚĂůůĞĚϬϮͬϬϭͬϮϭ ϯͬϴ͟ ϮϮϬϱ^ƚĂŝŶůĞƐƐ^ƚĞĞů;ϭϭ͕ϱϬϬ͛ƐƉŽŽůͿ dŽƉ ŽƚƚŽŵ D Ϭ͛ ϳ͕ϳϬϬ͛ ds Ϭ͛ ϲ͕Ϭϭϵ͛ DϮD ϳ͕ϳϮϳΖϳ͕ϳϰϳΖ ϲ͕ϬϰϱΖ ϲ͕ϬϲϱΖϮϬΖ ϭϮͬϮϲͬϮϬϮϬ KƉĞŶ DϮD ϳ͕ϳϯϳ͛ϳ͕ϳϯϵ͛ϲ͕Ϭϱϱ͛ϲ͕Ϭϱϳ͛Ϯ͛ϭϮͬϮϲͬϮϬϮϬKƉĞŶ Ζ Ζ Ζ Ζ Ζ ͬͬ DϯD ϴ͕ϬϱϵΖϴ͕ϬϳϴΖ ϲ͕ϯϲϲΖ ϲ͕ϯϴϰΖϭϵΖ ϭϮͬϮϲͬϮϬϮϬ KƉĞŶ DϰD ϴ͕ϭϰϴΖϴ͕ϭϱϬΖ ϲ͕ϰϱϭΖ ϲ͕ϰϱϯΖ ϮΖ ϭϮͬϮϰͬϮϬϮϬ KƉĞŶ DϳD ϴ͕ϮϳϮ͛ϴ͕Ϯϳϵ͛ϲ͕ϱϳϭ͛ϲ͕ϱϳϳ͛ϳ͛ϭϮͬϮϯͬϮϬϮϬ KƉĞŶ DϳD ϴ͕ϮϳϵΖϴ͕ϮϴϲΖ ϲ͕ϱϳϳΖ ϲ͕ϱϴϰΖ ϳΖ ϭϮͬϮϰͬϮϬϮϬ KƉĞŶ DϳD ϴ͕Ϯϳϴ͛ϴ͕ϮϴϬ͛ϲ͕ϱϳϲ͛ϲ͕ϱϳϴ͛Ϯ ϭϮͬϭϵͬϮϬϮϬ KƉĞŶƉ 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): 9,802'8,663' Casing Collapse Structural Conductor Surface 2,090psi Intermediate 4,790psi Production 7,500psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG 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: December 16, 2020 2-7/8" 9,800' Perforation Depth MD (ft): 6,824' See Attached Schematic 4,435'8,041'4-1/2" 16" 10-3/4" 120' 7-5/8"6,824' 3,333'3,580psi 120' 2,616' 5,183' 120' 3,333' 6.5# / L-80 / FJ3 TVD Burst 7,885' 8,430psi MD 6,890psi Length Size CO 231A 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 ADL60569, ADL60568, ADL 324602, Fee Private 219-078 50-133-20684-00-00 Cannery Loop Unit (CLU) 14 Cannery Loop / Sterling Undefined Gas Pool, Beluga Gas Pool COMMISSION USE ONLY Authorized Name: Tubing Grade: 6.5# / L-80 / EUE Tubing MD (ft): 5,391' See Attached Schematic tkramer@hilcorp.com 8,043'9,659'7,903'2,342 N/A Swell Pkr; SSSV-Halliburton NE SRSV Swell Pkr 2,821' MD (2,234' TVD); Lnr Top Pkr 5,365' MD ( 3,921 TVD) 531' MD/TVD Perforation Depth TVD (ft):Tubing Size: 2-7/8" m n P 66 t Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 5:29 pm, Dec 02, 2020 320-510 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.12.02 14:50:13 -09'00' Taylor Wellman DSR-12/2/2020SFD 12/3/2020 Perforate gls 12/8/20 10-404 Comm. 12/8/2020 dts12/8/2020 JLC 12/8/2020 RBDMS HEW 12/9/2020 Well Prognosis Well: CLU 14 Date: 11-30-2020 Well Name: CLU 14 API Number: 50-133-20684-00-00 Current Status: Producing Gas Well Leg: N/A Estimated Start Date: December 16th 2020 Rig: E-line Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 219-078 First Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) Second Call Engineer: Todd Sidoti (907) 777-8443 (O) (907) 632-4113 (C) AFE Number: Maximum Expected BHP: ~ 3,038 psi @ 6,946’ TVD (Based on normal gradient) Max. Potential Surface Pressure: ~ 2,342 psi @ 6,865’ TVD (Based on expected max. BHP and gas gradient to surface (0.10psi/ft) Brief Well Summary CLU 14 is a gas producer that was drilled and completed in August 2019 targeting gas sands in the Beluga and Sterling formations. In August of 2020 a 2-7/8” velocity string was installed in the well. A CIBP was drilled up through the 2-7/8” string and pushed to bottom. In October the tubing conveyed SCSSSV failed to close. This valve was pinned open and a WLR SCSSSV was installed in its profile. The purpose of this work/sundry is to add perforations to this well in order to increase production. CINGSA Storage Pool Check - A check of the CINGSA Storage Pool in ths well showed that the bottom of the pool to be 5,113’ (TVD). The top shot in this Sundry is at 5,245’ (TVD) which is more than the 100’ buffer outlined in CO 231A by 32 feet (Total distance 132’). Notes Regarding Wellbore Condition x CBL ran 8-9-2019 shows good cement behind the 7-5/8” casing down to 6,748’, which isolates the CINGSA Gas Storage Pool behind pipe. Cement could be deeper (Set depth of 7-5/8”is 6,824’, but 6,748’ is the deepest the CBL was ran. x CBL ran 8-25-2019 shows poor cement behind the 4-1/2” liner. x Casing PT’d to 3,500 psi on 8/20/2019 x This well requires a SSSV due to its close proximity to a public road. Safety Concerns x Ensure all crews are aware of stop work authority Slickline Procedure x Remove WLR SCSSSV E-line Procedure CINGSA Storage Pool Check - add perforations Agree that proposed shallowest perforation will be more than 100' below base of CINGSA's Sterling C Gas Storage Pool. SFD 12/3/2020 Deepest reading shown on 8-9-2019 CBL is 6,730' MD. SFD 12/3/2020 Well Prognosis Well: CLU 14 Date: 11-30-2020 1) MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 3,000 psi High. 2) With the well flowing, RIH with GPT tool to 8,663’ and lightly tag junk to obtain baseline.. (NOTE: CIBP debris @ 8,663’). POOH W/GPT. 3) PU Perf Guns. RIH With Perf Gun and perforate the following intervals : Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt UB 2 ±6,890' ±6,900' ±5,245' ±5,254' 10' UB 3 ±6,933' ±6,948' ±5,284' ±5,299' 15' UB 4 ±7,024' ±7,033' ±5,370' ±5,379' 9' UB 4A ±7,057' ±7,091' ±5,401' ±5,434' 34' UB 4B ±7,138' ±7,166' ±5,479' ±5,505' 28' UB 5A ±7,201' ±7,210' ±5,539' ±5,545' 9' UB 6 ±7,303' ±7,312' ±5,637' ±5,647' 9' UB 7 ±7,339' ±7,349' ±5,671' ±5,681' 10' UB 7A ±7,538' ±7,562' ±5,863' ±5,886' 24' MB 1X ±7,581' ±7,593' ±5,904' ±5,916' 12' MB 1 ±7,671' ±7,678' ±5,991' ±5,998’ 7' MB 2 ±7,727' ±7,747' ±6,045' ±6,065' 20' MB 3 ±8,059' ±8,078' ±6,366' ±6,384' 19' MB 4 ±8,145' ±8,160' ±6,449' ±6,463' 15' MB 7A ±8,272' ±8,286' ±6,571' ±6,583' 14' LB 1X ±8,641' ±8,653' ±6,925' ±6,936' 12' LB 1A ±8,658' ±8,663' ±6,941' ±6,946' 5' a. Well will be shot flowing. UB 2 ±6,890' ±6,900' ±5,245'±5,254'10' UB 3 ±6,933' ±6,948' ±5,284'±5,299'15' UB 4 ±7,024' ±7,033' ±5,370'±5,379'9' UB 4A ±7,057' ±7,091' ±5,401'±5,434'34' UB 4B ±7,138' ±7,166' ±5,479'±5,505'28' UB 5A ±7,201' ±7,210' ±5,539'±5,545'9' UB 6 ±7,303' ±7,312' ±5,637'±5,647'9' UB 7 ±7,339' ±7,349' ±5,671'±5,681'10' UB 7A ±7,538' ±7,562' ±5,863'±5,886'24' MB 1X ±7,581' ±7,593' ±5,904'±5,916'12' MB 1 ±7,671' ±7,678' ±5,991'±5,998’7' MB 2 ±7,727' ±7,747' ±6,045'±6,065'20' MB 3 ±8,059' ±8,078' ±6,366'±6,384'19' MB 4 ±8,145' ±8,160' ±6,449'±6,463'15' MB 7A ±8,272' ±8,286' ±6,571'±6,583'14' LB 1X ±8,641' ±8,653' ±6,925'±6,936'12' LB 1A ±8,658' ±8,663' ±6,941'±6,946'5' NOTE: WLEG at 7886 ft Well Prognosis Well: CLU 14 Date: 11-30-2020 b. Proposed perfs also shown on the proposed schematic in red font. c. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. d. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. e. Use Gamma/CCL to correlate. f. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. g. These sands are governed by Conservation Order 231A. 4) POOH. 5) RD E-Line. 6) Turn well over to production. Note: Once a sand that will produce in commercial quantities is found, the SSSV will be re-set. 7) (Test SSV with-in 5 days of stable production on well, SSSV testing within 14 days of stable production – notify AOGCC 24hrs before testing) E-line Procedure (Contingency): 1. If zone produces sand and/or water or needs to be isolated: 2. MIRU E-line, PT lubricator to 250 psi Low / 3,000 psi High. 3. RIH and set Umbrella plug above offending zone. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic Reset WL SSSV _____________________________________________________________________________________ Updated by DMA 11-18-20 SCHEMATIC Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 109 / X-56 / Weld 15” Surf 120’ 10-3/4” Surface 45.5 / L-80 / TXP BTC 9.950” Surf 3,333’ 7-5/8" Intermediate 29.7 / L-80 / W563 6.875” Surf 6,824’ 4-1/2" Production 12.6 / L-80 / TXP BTC 3.958” 5,365’ 9,800’ TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8” Tubing 6.5 / L-80 / EUE 2.441” Surf 5,391’ 2-7/8” Tubing 6.5 / L-80 / FJ3 2.441” 5,402’ 7,885’ JEWELRY DETAIL No Depth Item 1 507’ SSSV-Halli FXE WL 10/18/20 1A 531’ SSSV-Halliburton NE SRSV 07/28/20 2 2,821’ 7-5/8” Swell Packer 3 5,391’ 4.5” x 5.75” Bullet Tie-Back Seal Assembly 4 5,365’ 7-5/8” X 4-1/2” Baker ZXP 5 7,886’ Wireline Re-entry Guide 07/28/20 OPEN HOLE / CEMENT DETAIL 10-3/4” 329 BBL’s of cement in 13.5” Hole 7-5/8" 219 BBL’s of cement in 9-7/8” Hole 4-1/2" 148 BBL’s of cement in 6-3/4” Hole PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status MB-8/8A 8,028’ 8,042’ 6,336’ 6,350’ 14’ 9/18/2019 Open MB-8/8A 8,058’ 8,078’ 6,366’ 6,384’ 20’ 9/18/2019 Open LB-4 8,565’ 8,577’ 6,852’ 6,863’ 12’ 9/13/2019 Open LB-6 8,642’ 8,654’ 6,926’ 6,937’ 12’ 11/25/2019 Open FISH DETAIL 8,663’ CIBP Debris 08/18/20 Middle Fish RBP Pushed to Bottom 9,659’ CIBP Milled and Pushed to Bottom 09/11/19 _____________________________________________________________________________________ Updated by DMA 11-13-20 PROPOSED SCHEMATIC Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 . .CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 109 / X-56 / Weld 15” Surf 120’ 10-3/4” Surface 45.5 / L-80 / TXP BTC 9.950” Surf 3,333’ 7-5/8" Intermediate 29.7 / L-80 / W563 6.875” Surf 6,824’ 4-1/2" Production 12.6 / L-80 / TXP BTC 3.958” 5,365’ 9,800’ TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8” Tubing 6.5 / L-80 / EUE 2.441” Surf 5,391’ 2-7/8” Tubing 6.5 / L-80 / FJ3 2.441” 5,402’ 7,885’ JEWELRY DETAIL No Depth Item 1 530’ K Valve set to close @ 150 psi 10/18/20 1A 531’ SSSV-Halliburton NE SRSV 07/28/20 2 2,821’ 7-5/8” Swell Packer 3 5,391’ 4.5” x 5.75” Bullet Tie-Back Seal Assembly 4 5,365’ 7-5/8” X 4-1/2” Liner Hanger 5 7,886’ Wireline Re-entry Guide 07/28/20 PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status UB 2 ±6,890' ±6,900' ±5,245' ±5,254' 10' Proposed TBD UB 3 ±6,933' ±6,948' ±5,284' ±5,299' 15' Proposed TBD UB 4 ±7,024' ±7,033' ±5,370' ±5,379' 9' Proposed TBD UB 4A ±7,057' ±7,091' ±5,401' ±5,434' 34' Proposed TBD UB 4B ±7,138' ±7,166' ±5,479' ±5,505' 28' Proposed TBD UB 5A ±7,201' ±7,210' ±5,539' ±5,545' 9' Proposed TBD UB 6 ±7,303' ±7,312' ±5,637' ±5,647' 9' Proposed TBD UB 7 ±7,339' ±7,349' ±5,671' ±5,681' 10' Proposed TBD UB 7A ±7,538' ±7,562' ±5,863' ±5,886' 24' Proposed TBD MB 1X ±7,581' ±7,593' ±5,904' ±5,916' 12' Proposed TBD MB 1 ±7,671' ±7,678' ±5,991' ±5,998’ 7' Proposed TBD MB 2 ±7,727' ±7,747' ±6,045' ±6,065' 20' Proposed TBD MB 3 ±8,059' ±8,078' ±6,366' ±6,384' 19' Proposed TBD MB 4 ±8,145' ±8,160' ±6,449' ±6,463' 15' Proposed TBD MB 7A ±8,272' ±8,286' ±6,571' ±6,583' 14' Proposed TBD LB 1X ±8,641' ±8,653' ±6,925' ±6,936' 12' Proposed TBD LB 1A ±8,658' ±8,663' ±6,941' ±6,946' 5' Proposed TBD MB-8/8A 8,028’ 8,042’ 6,336’ 6,350’ 14’ 9/18/2019 Open MB-8/8A 8,058’ 8,078’ 6,366’ 6,384’ 20’ 9/18/2019 Open LB-4 8,565’ 8,577’ 6,852’ 6,863’ 12’ 9/13/2019 Open LB-6 8,642’ 8,654’ 6,926’ 6,937’ 12’ 11/25/2019 Open FISH DETAIL 8,663’ CIBP Debris 08/18/20 Middle Fish RBP Pushed to Bottom 9,659’ CIBP Milled and Pushed to Bottom 09/11/19 WLEG at 7886' 6824ft 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: N2, K-valve, Install SC-SSSV 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 9,802 feet N/A feet true vertical 8,043 feet 9,659 (fish) feet Effective Depth measured 9,659 feet 2,821 feet true vertical 7,903 feet 2,272 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic 2-7/8" 6.5# / L-80 / EUE 5,391' MD 3,993' TVD Tubing (size, grade, measured and true vertical depth)2-7/8" 6.5# / L80 / FJ3 7,885' MD 6,199' TVD 507' MD/TVD Packers and SSSV (type, measured and true vertical depth)SSSV-Halliburton NE SRSV 527' MD/TVD 2,821' MD/2,234' TVD 5,365' MD/3,975' TVD 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:Ted Kramer Authorized Title:Operations Manager Contact Email: Contact Phone:777-8420 WINJ WAG 1,516 Water-Bbl MD 120' 3,333' 0 2,616' true vertical Packer 4-1/2"9,800' 5,183' 8,041' 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Cannery Loop / Sterling Undefined Gas Pool, Beluga Gas PoolN/A measured TVD Tubing PressureOil-Bbl Cannery Loop Unit (CLU) 14 N/A ADL60569, ADL60568, ADL 324602, Fee Private 6,824' Plugs Junk measured measured STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-078 50-133-02684-00-00 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. 320-076 & 320-362 68 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 3 Liner 530 0 Representative Daily Average Production or Injection Data 950 4,435' Conductor Surface Intermediate Production 6,824' Casing Structural 16" 10-3/4" 7-5/8" Length 120' 3,333' Collapse 2,090psi 4,790psi 7,500psi Burst 8,430psi 120' 6,890psi 3,580psi Swell Pkr; Baker ZXP SSSV-Halli FXE WLR; tkramer@hilcorp.com Senior Engineer:Senior Res. Engineer: Authorized Signature with date: Authorized Name: 0 Casing Pressure t Fra O O 6. A G L PG , R V Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 9:07 am, Nov 23, 2020 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.11.20 16:57:57 -09'00' Taylor Wellman SFD 11/24/202020684 gls 12/20/20 DSR-11/23/2020 RBDMS HEW 11/24/2020 SFD 11/24/2020 Rig Start Date End Date Rig 401 6/11/20 10/31/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name CLU-14 50-133-20684-00-00 219-078 Lay out herculiner & build containment, spot base beam, Hak 401 rig carrier, choke house, fluid pit, fluid pump, koomey house, parts connex, & air compressor with volume tank. R/U pump & air lines, install mud/gas separator, raise roof on mud pits, load pits with water & mix to 6% kcl. Raise & fully scope derrick, secure guy lines, anchor off gironimo line. Hook up choke line to bleed off tbg. Open well, SITP = 1,100 psi. Bleed down 4.5" tbg using manual choke to 35 psi, well continuing to flow. Close in well, test 4.5" x 7-5/8" casing to 2000 psi on chart for 30 minutes. Held same. Tubing pressure built to 750 psi after 1.5 hrs. Decision made to dump additional cement. Order out bailer equipment. R/U AK E-line with lubricator & grease head. P/U 3.75" gr/jb, Attempt to test lubricator, unable to get grease head to pack off & test. Get back up grease pump from Kenai gas field pad. Test lubricator to 250/2,000, held same. Equalize to well & open well same. RIH with 3.75" gr/jb to 7,884'. Log up & tie into RA tag @ 7,784'. Lower gr/jb & tag @ 8,015'. Tag same. POOH to surface with gr/jb. L/D same M/U 2.5" X 30' of cement bailer, bottom fill bailer with 6.4 gallons of cement, RIH to 8,005', dump cement, POOH. Fill 2.5" x 30' bailer with 6.4 gallons of cement, RIH to 7,995'. Dump cement & POOH. Fill 2.5" x 30' bailer with 3.2 gallons of cement, RIH to 7,990'. Dump cement & POOH leaving cement top @ 7,990'. L/D lubricator & break down bailer. Secure well & wait 24 hrs on cement. SITP = 1,200 PSI. 06/11/2020 - Thursday MIRU AK ELINE, REMOVE SOAP LAUNCHER FROM WELL, REHEAD E-LINE, P/U 3.75" GR/JB. TEST LUBRICATOR TO 250/3,000 PSI, RIH SAME WITH GR/JB TO 8,025'. POOH & L/D GR/JB ASSEMBLY P/U 4.5" OBSIDIAN COMPOSITE PLUG ON RED DOT FIRING ASSEMBLY & RIH SAME. TIE IN TO RA TAG @ 7,884', LOWER PLUG & SET SAME @ 8,020' WITH A 110 LB WEIGHT LOSS. LOG UP TO RA TAG @ 7,884', LOWER SETTING TOOL & LIGHTLY TAG PLUG @ SETTING DEPTH OF 8,020'. POOH TO SURFACE & L/D SETTING SLEEVE. P/U 3" X 14' OF CEMENT BAILER, FILL WITH 3.2 GALLONS OF CEMENT & RIH TO 8,020', DUMP CEMENT LEAVING TOC @ 8,015'. POOH & L/D BAILER EQUIPMENT, R/D AK E-LINE, REMOVE WELL HOUSE & SET TO SIDE. ALL HAK 401 RIG & EQUIPMENT MOVED & STAGED ONTO CLU PAD. MECHANICS SERVICED & DRAINED HYDRAULIC OIL FROM HAK 1 KOOMEY UNIT & FILLED WITH FRESH OIL. 06/12/2020 - Friday CIBP not holding Rig Start Date End Date Rig 401 6/11/20 10/31/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name CLU-14 50-133-20684-00-00 219-078 06/13/2020 - Saturday Open well, SITP = 1,425 PSI. Bleed off gas using rig choke & mud/gas separator. Bleed down to 225 psi & shut in well. Pressure @ 350 in 10 minutes. Pressure @ 625 after 25 minutes. Decission made to R/U AK Eline & run spinner log with temp gauge. R/U AK E-line, Surface test spinner logging assembly. Test lubricator to 2,000 psi, open well & RIH to 7,980'. Obtain temperature readings. Readings show plug & cement not holding. Send data to Engineer & POOH to surface. L/D spinner logging assembly, M/U 30' X 2.5" of cement bailer. P/U lubricator & bailer assembly, load bailer with 6.4 gallons of cement. Test lubricator to 2000 psi, equalize to well & open same. RIH to 7,990'. Dump cement & POOH to surface. Reload bailer with 6.4 gallons of cement, test lubricator to 2000 psi, equalize to well & open same, RIH to 6,450' & tag inside of dog leg, work bailer through & continue in hole to 7,630'. Tag inside dog leg, work bailer through & continue in hole to 7,980'. Dump cement leaving cement top @ 7,970'. Pooh to 250', lost ccl & all tool weight shooting line out of hole & wedging end of line inside of grease head. Secure well, SITP = 1200 PSI. L/D lubricator & break down grease head. Wire end wedged inside of grease tube. Work wire out of tube, wire end broken and no indication of rope socket pull out. Call out Pollard slickline & build additional lubricator for fishing operations. Pollard slick line arrived on location @ 21:14 hrs. Spot & R/U Pollard braided line, P/U 65' of lubricator, slick line wrapped around catline while picking up lubricator kincking slick line, lower lubricator to ground. Cut & rehead slick line. P/U lubricator, M/U split skirt 2" jdc overshot , x-o, spang jars, oil jars, knuckle joint, 10' weight bar, rope socket. Test lubricator to 2000 psi, equalize to well, open same. RIH with slick line to 7,965' SLM, tag & latch to fish. P/U & jar on fish (7) times jarring 1,500 lbs over, Tool come free. POOH to surface. Found 2" jdc split skirt shucked & broken. P/U Solid 2" jdc over shot on fishing assembly. RIH & latch fish @ 7,965' SLM. Jar on fish (45) times @ 2,100 lbs over string wt. had no movement. Shear off of jdc, pooh to surface. Decision made to R/D slickline. R/D Pollard slickline, Secure well. SITP = 1,200 PSI. o 7,630'. Tag inside dog leg, work bailer through & continue in hole to 7,980'. Dump cement leaving cement top @ 7,970'. Pooh to 250', lost ccl & all tool weight shooting line out of hole & wedging end of line inside of grease head. Secure well, SITP = 1200 PSI.L/D lubricator & break down grease head. Wire end wedged inside of grease tube. Wo Rig Start Date End Date Rig 401 6/11/20 10/31/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name CLU-14 50-133-20684-00-00 219-078 06/16/2020 - Tuesday Open well, SITP = 1,160 PSI. Bleed off well to 0 psi & monitor. Well static. Shut in well same to monitor build up. R/D HAK 401,R/D electrical lines & wrap same. Perform pre-check derrick inspection, Scope in & lay over derrick, break down pump lines, empty rig tank & prep to move rig to CLU #5RD. 06/14/2020 - Sunday Open well, SITP = 1,425 PSI. Bleed off gas using rig choke & mud/gas separator. Bleed down to 225 psi & shut in well. Pressure @ 350 in 10 minutes. Pressure @ 625 after 25 minutes. Decission made to R/U AK Eline & run spinner log with temp gauge. R/U AK E-line, Surface test spinner logging assembly. Test lubricator to 2,000 psi, open well & RIH to 7,980'. Obtain temperature readings. Readings show plug & cement not holding. Send data to Engineer & POOH to surface. L/D spinner logging assembly, M/U 30' X 2.5" of cement bailer. P/U lubricator & bailer assembly, load bailer with 6.4 gallons of cement. Test lubricator to 2,000 psi, equalize to well & open same. RIH to 7,990'. Dump cement & POOH to surface. Reload bailer with 6.4 gallons of cement, test lubricator to 2,000 psi, equalize to well & open same, RIH to 6,450' & tag inside of dog leg, work bailer through & continue in hole to 7,630'. Tag inside dog leg, work bailer through & continue in hole to 7,980'. Dump cement leaving cement top @ 7,970'. Pooh to 250', lost ccl & all tool weight shooting line out of hole & wedging end of line inside of grease head. Secure well, SITP = 1,200 PSI. L/D lubricator & break down grease head. Wire end wedged inside of grease tube. Work wire out of tube, wire end broken and no indication of rope socket pull out. Call out Pollard slickline & build additional lubricator for fishing operations. Pollard slick line arrived on location @ 21:14 hrs. Spot & R/U Pollard braided line, P/U 65' of lubricator, slick line wrapped around catline while picking up lubricator kincking slick line, lower lubricator to ground. Cut & rehead slick line. P/U lubricator, M/U split skirt 2" jdc overshot , x-o, spang jars, oil jars, knuckle joint, 10' weight bar, rope socket. Test lubricator to 2,000 psi, equalize to well, open same. RIH with slick line to 7,965' SLM, tag & latch to fish. P/U & jar on fish (7) times jarring 1,500 lbs over, Tool come free. POOH to surface. Found 2" jdc split skirt shucked & broken. P/U Solid 2" jdc over shot on fishing assembly. RIH & latch fish @ 7,965' SLM. Jar on fish (45) times @ 2,100 lbs over string wt. had no movement. Shear off of jdc, pooh to surface. Decision made to R/D slickline. R/D Pollard slickline, Secure well. SITP = 1,200 PSI. 07/12/2020 - Sunday PTW, JSA. MIRU SLB CTU 13 with 1.75" Coil. Start BOPE test. 24 hr BOPE test witness notification sent 7/11/20 @ 14:46 hrs. Witness waived by Jim Regg via email on 7/11/20 @ 21:10. Test all rams and valves to 250/4000 psi. BOPE test complete. Continue rigging up SLB coil. Spot in rain for rent supply tank. Bring crane operator to Cruz yard and grab 100 ton crane. Remove compressor from trailer at KGF G&I facility. Swap cranes at CLU-14 from 80 ton to 100 ton. ide to 25 well, outof lubric P/U 65 ator to uckle jo dodog & all to ator & bre pe sock @ 21 cking soi 10 ine, Sur eading "ofcef well & 00 psi, idee well & R gineer & ssem 90'. we Repeat of 6/13 Rig Start Date End Date Rig 401 6/11/20 10/31/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name CLU-14 50-133-20684-00-00 219-078 07/13/2020 - Monday PTW, JSA with SLB coil, Cruz crane op, and Hilcorp wellsite supervisor. Discuss SIMOPS with AK E-line crew working on CLU- 05RD. Fire equipment. Pick injector head. Stack up lubricator. 40' of lubricator made up. Crew used stop work authority. Had a tailgate meeting and decided to do a dry run up to the top of wash pipe sticking out of cellar. SLB coil unit does not have enough hydraulic hoses to reach wellhead with 65' of lubricator. Informed town of delay. Rig down lubricator and injector head. De-mobe SLB CTU 13 from CLU pad to SLB yard. Coil crew installing 40' hydraulic extensions. Test injector head. Inspect for leaks. Mobilize coil unit to CLU. Spot in/rig in. Location secure. SDFN. 07/14/2020 - Tuesday PTW, JSA with SLB , Cruz, and Hilcorp Rep. Fire coil equipment. Adjust crane radius. Pick 30' joint of 3-3/4" wash pipe and lower into cellar. Tie off wash pipe to wellhead stack. Pick injector head and build 7 sticks of lubricator for 65'. Make up Ext. slip CTC for 1.75" CT. Pull test 25K. Continue making up MHA. DFCV, Bi-Di jars, Hyd. disco, dual circ sub. Install PT plate. Fluid pack coil with 32 bbls of lease water. Pressure test MHA to 250/4,500 psi. Make up motor, wash pipe drive sub, 3-3/4" wash pipe, 3-3/4" Ocean wave burn shoe. Stab on well. PT stack 250/4,000 psi. BHA details. Ext. Slip CTC for 1.75" coil 2.13" OD x.75', 2.875" DFCV 2.13" OD x 1.25', 2.8785" Logan Bi-Di Jars 2.13" OD x 5.6', 2.875" Hyd. Disco 2.13" OD x 2.13', 2.875" Dual Circ Sub x 1.2', 2.875" Motor x 12.77', x over 3.08" OD x.41', X over 3.13" OD x.64', Wash pipe drive sub 3.78" OD x 1.76', Wash pipe 3.75" OD x 32', Ocean wave burn shoe 3.8" OD x 5.04' Total 63.55' Burn BHA. Open well. 1,800 psi WHP. RIH bleeding off gas to return tank. Dry tag at 7,945' CTMD. Stack 4k weight break back to string weight. Pick up 3k over. RIH for 2nd dry tag. 7,956' CTMD. 5k down. Weight broke back. Pick up clean. RIH for 3rd dry tag @ 7,966' CTMD. Set 3k down weight slowly coming back. Pick up 4 k over. RIH for 4th dry tag @ 7,975' no weight broke back 5k down. Make 30' of depth from first tag at 7,945' to 4th tag at 7,975'. Fish length is 38.6' With the footage made and over pulls during each pick up it's a good indication that the cement was not setup. Parked with coil at 7,900' Online down Coil to fluid pack well to surface. Bottoms up volume 95 bbls calculated. Pumped 93 bbls to get fluid to surface. well was empty. Broke circulation getting 1:1's. Establish free spin 1.5 bbls/min 3,200 psi. RIH seeing slight motor work at 7,978' CTMD 300 psi of motor work. 7,981' motor work increased to 4,088 psi. 800 psi motor work. 7,983' stack 5k no increase in motor work. Pick up and continue attempts to get past 7,983'. RIH faster and stacked 5k down @ 7,984' weight stack and motor work pressure change together. Neither weight nor coil pressure broke off. Start Bottoms up to clean up any unset cement. 315 bbls total pumped. Shut down pump. RIH from 7,900' not pumping. Stack down 15k on fish to attempt a superman latch. Pick up 7K over string weight. Double block choke. POOH to surface. Tagged up. Shut in well 0 psi tubing pressure. Pop off well and break down tools. Called town to propose plan for the night. Brought out night time crane operator. Leave injector head hanging in the air with 65' of lubricator. Break down burn shoe and wash pipe BHA. Install night cap on BOPE. CTU Rig Start Date End Date Rig 401 6/11/20 10/31/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name CLU-14 50-133-20684-00-00 219-078 07/15/2020 - Wednesday PTW, JSA with SLB coil, Cruz Crane operator, Yellow Jacket tool hand, and Hilcorp Well site Supervisor. Injector head was hanging in air from previous day. Make up Fish BHA. Details: External slip CTC 2.88" OD x.75', DFCV 2.88" OD x 1.25', Logan Bi-Di Jars 2.88" OD x 5.6', Hyd Disco 2.88" OD x 2.13', dual circ sub 2.88" OD x 1.2', 3" Hyd release GS spear 2.88" OD x 1.7', 3" GS profile 2.88" OD x 1.7', x over 3.09" OD x 1.32', Drive sub 3.78" OD x.82', Overshot 3.75" OD x 1.74'. BHA length 18.28'. Stab on well. PT stack 250/4000 psi. Bleed down. Open well and RIH. 0 psi WHP. Displacement at surface. Well still remains fluid packed. Weight check at 7900' 21K. RIH and Tag TOF @ 7960' CTMD. Pu and confirm latched. Pull to 45K or 21K over. Wait for jars to fire. 3.5 minutes to fire jars. Continue to jar at 80% coil limit or 53K. 32K over string weight. jars averaging around 3 minutes to fire. No indication of fish moving. Make 50 jars licks. Pipe fatigue at goose neck on injector head is wearing out. Online down CT at 1.6 bbls/min 3500 psi. Stack 5k down and pick up out of GS profile. POOH to surface. Baited overshot remains on top of fish. 3" GS profile 2.88" OD x 1.7', x over 3.09" OD x 1.32' , series 150 drive sub 3.78" OD x.82', overshot grapple 3.75" OD x 1.74'. Original Fish: 1 7/16" head 1.437" OD x 1.1', weight bar 1.687" OD x 5', CCL 2.125" OD x 1.3', Sub 1.437" OD x 2", bailer 2.5" OD x 31'. Tagged up. Close well. Pop off and break down tools. Cut 50' of pipe to move fatigue down hole. Make up Coil connector and Pull test. Yellow Jacket getting new jar ready at shop. Adding weight bar and accelerator jar for tomorrows run. SDFN. 07/16/2020 - Thursday PTW, JSA with SLB coil. Cruz Crane op, Yellow jacket tool hand, and Hilcorp Wellsite supervisor. Make up new fishing BHA. Previous Fishing had cycled out coil at goose neck. 50' of coil was cut. CT fishing BHA: EXT slip CTC 1.75" ct 2.88" OD x.75', DFCV 2.88" OD x 1.25', Accelerator jar 2.9" OD x 5.9', weight bar 2.88" OD x 8', Logan Bi-Di jars 2.88" OD x 5.6', Hyd Disco 2.88" OD x 2.13', Circ sub 2.88" OD x 1.2', 3" Hydraulic GS 2.7" OD x 1.77' (pull tested CTC 25K. MHA pressure tested 250/4,500 psi Stab on well. PT stack 250/4,000 psi. Open well 0 psi whp. RIH. 7,900' WT check 21K. RIH latch 3" GS profile. Start Jarring sequence. 21K free weight. PU to 52K-55K (31-34K over pulls). Perform 15 jar licks. No movement on fish. Release from GS profile. POOH to surface. Break down GS spear. Make up milling assembly. Same BHA as previously stated from the CTC to Circ sub. Installed motor 2.88" OD x 12.77', X over 2.75" OD x.72', x over 2.0" OD x.69', Tapered mill 1.89" OD x.95'. Stab on well. Fluid pack to return tank and confirm motor is spinning in lubricator. PT stack 250/4,000 psi. RIH. Weight check 7900' 21K. RIH tag top of baited over shot at 7965' Stack lightly at 3k down. Pick up 10K over at 30K. Overshot still latched on top of fish rope socket. Attempt 5 jar licks no luck. Stack 3k down online down CT at 1.5 bbls/min. Release from GS. POOH to surface. Discuss with tool hand options going forward. Suggested running a fishing spear to grab inside of 3" GS body. Tagged up at surface. Close master and swab valve. Pop off well. Break down 3" GS and spear fishing assembly. Install night cap. Location secure. Night crane watch on location. SDFN. Rig Start Date End Date Rig 401 6/11/20 10/31/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name CLU-14 50-133-20684-00-00 219-078 07/18/2020 - Saturday PTW, JSA with SLB coil, Cruz Crane op, YJOS tool hand. Discuss Making up long tools and suspended loads. pick injector head stab. 60' of lubricator (PT MHA 250/4000) (pull test CTC 25K) Make up fishing BHA: Ext CTC 2.88" OD x.75', DFCV 2.88" OD x 1.25', Accelerator jars 2.9" OD x 5.9', Weight bar 2.88" OD x 8', Bi-Di Jars 2.88" OD x 7', Hyd Disconnect 2.88" OD x 2.13', Dual circ sub 2.88" OD x 1.2', 2.875" Motr 2.88" Od x 12.77', X over 3.08" OD x.41', x over 3.13" OD x.64', X over 3.11" OD x.62', ITCO spear 2.29" OD x 1.7'. total 42.37' Stab on well. PT stack 250/4,000 psi. Open well RIH (ITCO spear pinned with 3/8" bolt so it won't release when turning to the right) RIH 7850' weight check 21K. Free spin 1.5 bbls/min 3680 psi. RIH weight 3300 lbs. Set -15K down at 7,958' Small down jar lick. Pick up clean no engagement of fish profile. Continue attempts to Latch fish. Saw a few small 4k over pulls. RIH tag fish while pumping and motor stalls. Shut down pump. Stack 15K down. Can't get engagement of spear wickers into 3" GS profile sub. POOH to surface to check out spear. Tagged up. Close master and swab. Pop off well. Inspect tools. Found 3/8" bolt /shear screw on ITCO spear sheared. This is the reason we were unable to latch fish. Spear was in the release position. Discussed welding Anti shear pads on ITCO spear. Tool hand depart for shop to weld spear. YJOS welding anti shear pads on ITCO spear. Make up North Road modified ITCO spear. ID of internal fish neck on 3" GS baited sub 2.3". ITCO spear catch range 2.289"-2.329". Stab on well. PT stack 250/4000 psi. Open well RIH. Fluid pack coil at 7,800' Weight check 21K up. RIH dry tag 7,958' CTMD. Stack 15K down. No engagement. Make multiple attempts to latch profile. RIH at 60 ft/min stacking 20K down. Attempt to latch by rotating into it. Made it 1' deeper and stacked at 7,966'. Pick up over. Engaged in profile. Work up and down to get a good bite on wickers. Stack 15k down. Online and stall pump. Slowly pick up while motor stalled to rotate overshot off rope socket. POOH to surface. Tagged up. Pop off well. Confirmed fish recovered. Overshot and 3" Gs profile bait sub removed from top of fish rope socket. Break down BHA and stack down lubricator. Set down injector head. Install night cap on BOPE. Location secure. SDFN. 07/19/2020 - Sunday PTW, JSA with crew. Fire equipment. Make up 65' of lubricator. Yellow jacket bringing out sub to enable us to run overshot in string. Make up BHA. EXT slip CC, DFCV, Bi-Di Jars, Hyd Disconnect, Dual circ sub, motor, x over, Overshot top sub, Overshot Extension, Grapple bowl, wash pipe, burn shoe. BHA 68.27'. Stab on well. PT stack 250/4,000 psi. RIH. Wt check 21K @ 7,900'. Dry tag TOC/Fish @ 7,983' CTMD. Pick up clean. Online with pump at 1.5 bbls/min 3,400 psi. RIH stall motor @ 7,981'. Start millling from 7,981'. Having hard stalls at 7,182' -7,182.3'. Continue milling 7,982.3' - 7,983'. Tool may be laying to the low side causing burn shoe to wedge into side of bailer and casing wall. Hard stalls like metal. Making better hole. Continue milling from 7,983'- 7,988' CTMD. POOH to surface. Max mill depth 7,988'. Pick up and dry tag 7,988' to confirm. Tagged surface. Break down shoe to inspect. Shut down equipment for the night. Install night cap on BOPE. CTU Rig Start Date End Date Rig 401 6/11/20 10/31/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name CLU-14 50-133-20684-00-00 219-078 Transport 18 trailer loads of equipment & rig carrier from BCU-09 to Francis 01. R/D flow line, Lay out felt & herculiner, spot base beam. Unload rig & spot same, unload trailers & spot fluid tank, pump, koomey house, transformer, rig storage containers, diesel tank, & pusher's house. Perform rig & derrick pre lift inspection. Lift & fully scope derrick. After derrick was scoped it was noticed that rod man basket was stuck & jammed into the rod fingers. Inspected & found that block pushed basket up & broke square tubing. Called & reported to engineer & safety rep, Matt Hogge. Remove man basket & hoist down same. Incident under RCRA investigation. R/U pump lines, secure guy lines, run electrical, get rig into compliance to begin well ops. 07/23/2020 - Thursday Hold PJSM, review JSA's w/ crew. MIRU YellowJacket wireline truck and lubricator. P/U gauge ring junk basket, test lubricator t/ 3,000psi. RIH to 5,449' tag same. work junk bakset gauge ring. unable to make any hole. POOH t/ surface. recovered oil absorbant pad. RIH t/ 8,100' w/ junk basket gauge ring. POOH w/ same. Clean basket. P/U & RIH w/ CIBP, GAMMA RAY, & CCL. Log on depth & perform tie in, set cibp at 8,005'. POOH P/U 3.5" X 30' dump bailer, load w/ sand, RIH t/ 8,005'. Dump sand. Top of sand estimated @ 7,985'. POOH Fill hole w/ 2bbls of 6% KCL fluid, P/U 1-11/16" tbg punch 5ft of shot, RIH w/ same t/ 5,353', punch holes f/ 5,353' t/ 5,358'. POOH w/ same. R/D Yellow jacket. R/U pump lines, break circulation pumping down tbg, pump & displace tbg & annulus with 225 bbls of clean 6% kcl. Secure well & rest crew. 07/20/2020 - Monday PTW, JSA. Start BOPE test. 24hr BOPE test witness notification sent 7/19/2020 @ 1,657. Witness waived Via phone call to Jim Regg. Test all rams and valves 250/ Vac truck adding slick additive to fluid. Stab on well with Burn shoe assembly. PT stack 250/3,500 psi. Open well 0 psi. RIH Wt check at 7,900' 21K. 3,400 lbs. RIH wt. Dry tag at 7,985' CTMD. Online down coil 2 bbls/min 2,600 psi. Start milling at 7,984.5' CTMD stalled 5 times from 7,984.5'-7,996.6' CTMD. Continue milling from 7,996.6' (estimated end of fish depth from previous tags). Top of fish 7,965'48' CTMD Bottom of fish 8,004.08' CTMD. Milled to 8,011.623' stalled out. Shut down pump and let pressure drop. Pick up to see if we have the fish latched in the overshot above burn shoe. Pull 32K 11K over normal weight. POOH to surface. Tagged up. Close master and swab. Pop off well. E-line bailer recovered. Break down fish. Break down BHA and wash pipe. Stack down lubricator. Set injector on craddle. Install night cap on BOPE stack. Location secure. SDFN. 07/21/2020 - Tuesday PJSM Start equipment. Pick injector head stab lubricator. Make up BHA External slip CTC, DFCV, Logan Bi di jars, Hyd. Disco, dual circ sub, motor, 5 blade concave junk mill 3.75" OD. RIH. Weight check 21K at 7,900'. Dry tag 10k down at 8,006' CTMD. PU establish motor parameters. 2.0 bbls/min at 2,600 psi. Start milling 8,006' CTMD. Hard stalls. Milling plug at 8,038' CTMD to 8,039' CTMD. Thorough plug pusn to bottom. Cant get past 8,673.5' CTMD. Continue to work mill at 8,673.5' CTMD. Can't make any progress. After stalls pulling 30k over to pop free. POOH to surface to check mill. Tagged up. Marks on mill look as if we were cutting into metal on casing at 8,673.5' CTMD. Hard stalls from 8,671'-8,673'. Mill has deep gouges in it. Possibly casing damage. Rig down SLB CTU 13. Crews will de-mobe in the AM. 07/22/2020 - Wednesday Rig Start Date End Date Rig 401 6/11/20 10/31/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name CLU-14 50-133-20684-00-00 219-078 Held PTSM review JSA'S with personnel Open well, well static. Make up WLEG onto 2-7/8" 6.5# fj3 joint #1. WLEG box not shouldering up with pin. Get second WLEG from tuboscope. M/U same & RIH. Tbg not shouldering up with 1,000 ft/lbs of recommended max make up torque. Discuss with Hilcorp engineer & EZ GO FJ3 pipe specialist. Decission made to move forward making up pipe until pipe is shouldered. TIH picking up 2-7/8" 6.5# FJ3 EZ GO flush joint tbg. Torqueing connections to 1,800-2,000 ft/lbs to shoulder out pipe. Total of 76 jts of flush joint picked up, depth = 2,483'. R/U Pollard slick line. RIH with 2.336" GR to 488', tag & work thru tight spots @ 488', 1,174', 1,272', & 1,337'. Continue RIH to EOT @ 2,483', POOH & worked spang thru tight spots @978', 944', 717', 520', 488', & 94'. R/D Pollard wireline P/U Baker seal assembly & M/U same, continue TIH picking up 2-7/8" eue production tbg to 4,469'. Total of 63 jts of 2-7/8" EUE tbg ran in hole. Secure well & rest crew. 07/25/2020 - Saturday Hold PTSM & review JSA'S Continue working hold down pins & tightening gland nuts to create seal. Void test bope to 4,500 psi, held same. Call out state witness Austin Mcleod for witnessed bope test Test hydril, vbr ram, blind ram, choke & kill line valves, & choke manifold to 250/4,500 on chart for 5 minutes each test. VBR rams was tested with 2-7/8" and 4.5" tubulars. Perform Koomey draw down test. Initial manifold psi = 2,975, after function = 2,025 psi. 200 psi obtained in 37 seconds, full recovery in 195 seconds. All test good. Break down test joints, R/U McCoy tongs, P/U 4.5" handling tools, spot L/D machine & control line spooler, P/U & M/U landing joint, back out hold down pins. Pull hanger off seat at 45k, pull seals free & L/D hanger. fan shroud on pipe wrangler engine cooler come apart. R/D pipe wrangler & R/U pipe racks to L/D 4.5" tbg manually. Continue POOH laying down 4.5" production tbg & spooling control line. L/D SCSSV. Secure well & rest crew Depth @1,800= 4,850'. 07/26/2020 - Sunday Hold PTSM, review JSA'S with personnel Move pipe racks, service rig, Spot & R/U pipe wrangler. Continue POOH with 4.5" 12.6# tbg, total of 160 jts of 4.5" tbg, (3) pup jts, scssv, & seal assembly layed down. Move all 4.5" pipe onto trailers, L/D 4.5" handling tools, R/D McCoy tongs, R/U Foster tongs, P/U 2-7/8" handling equipment, M/U X-O subs onto TIW, Off load & Lay out 2-7/8" FJ3 as well as 2-7/8" EUE production tbg, SLM all tbg. Load pipe racks. Secure well & rest crew. 07/27/2020 - Monday 07/24/2020 - Friday Perform PJSM, go over JSA's w/ crew. Open well, well static, R/U pump lines on IA and perform casing test @ 2,000psi, chart for 30 min. Set BPV w/ NOS rep. N/D tree, clean flange @ tbg hanger. Install Dart. N/U 11" Yellow jacket spacer spool, mud cross, double ram bop dressed with blind ram & 2-7/8" x 5" vbr, & hydril. R/U rig floor and install hand rails. M/U test jts, change fittings on accumulator hoses, hook up same, pressure up accu. and function rams, annular and HCR. Install 2- 7/8" test jt. Perform draw down test. Fill stack w/ water. Attemp to perform shell test to 4,500 psi. Fluid continuously bypassing tbg hanger into IA. Secure well for the night, NOS well head tech to be on location in morning. Rig Start Date End Date Rig 401 6/11/20 10/31/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name CLU-14 50-133-20684-00-00 219-078 08/17/2020 - Monday PTW, JSA MIRU SLB CTU 13 with 1.75" CT. 24 hr BOPE test notification sent 8/17/2020 @ 0726 hrs. Witness waived by Jim Regg 8/17/2020 @ 10:25 hrs. 07/28/2020 - Tuesday Held PTSM & review JSA'S with personnel. Continue P/U & RIH with 2-7/8" EUE tbg. Install SCSSV with control line, to surface. Sting in with Baker seal assembly landing out no go with 5k down. Space out tbg, Install hanger & make final tie-in with SCSSV control line. Land out tbg setting 4k compression on seals, 25k landed on hanger. P/U weight = 42k. WLEG depth = 7,886.08', Seal assembly locator sub top = 5,391.50', FJ3 tbg top = 5,401.62'. Run down hold down pins, perform IA test to 2,000 psi on chart for 30 minutes. (Test good) R/D foster tongs 2-7/8" handling equipment, stair ways, hand rails, & rig floor. Set bpv, N/D hydril, double ram bop, choke & kill line, & mud cross. N/U 11" x 4" production tree, tie in scssv control line, test void to 5000 psi. Held same. Rest crew. 07/29/2020 - Wednesday Hold PTSM & review JSA'S with personnel. Perform derrick L/D inspection. Scope in & fully L/D derrick onto carriage, wrap cables & prep carriage for road transport. R/D fluid pump lines, electrical, PVT & gas detection, Clean mud pits, load & secure all equipment onto trailers, roll up herculiner & clean location. Haul 6 trailer loads of equipment to SRU 241-33. finish running tubing...RDMO 401 Rig Start Date End Date Rig 401 6/11/20 10/31/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name CLU-14 50-133-20684-00-00 219-078 08/18/2020 - Tuesday PTW, JSA with crew. Pick injector head and 2x 11' lubricators. Make up Yellow Jacket thru tubing tools. Install 2.25" OD x.75' External slip connector, 2.125" OD x 5.6' Logan Bi-Di Jars, 2.125" OD x 1.58' Hyd. Disconnect. Pull tested coil connector 25k. PT MHA 250/4,500 psi. Install 2.125" OD x 1.08' Dual circ sub. 2.125" OD x 10.5' motor, 2.125" OD x 3.37 Hailey under reamer, x over 2.11" OD x.32', 4 bladed junk mill 2.3" OD. Flowed through motor in return tank to check function of under reamer blades. Noticed a decent amount of fluid flowing from between motor body and bit box. Swapped out for back up motor and tested with same issue. Dispatche 2 more motors from YJOS shop. Made calls to motor rebuild facility out of Houston Texas. Was told the Abaco power ends were designed to flow this way for bearing cooling. 3rd motor did not blow out grease and had less fluid volume between motor body and bit box. Running number 3. Stab on well. PT stack 250/4,000 psi. Bleed down. Open well and RIH. Initial WHP 0 psi. Dry tag at 7,987' CTMD. PU come online down CT with produced water at 1.4 bbls/min 3678 psi circ pressure. RIH wash sand from 7,987' to 8,005.7' CTMD. Milling on CIBP in 4.5" casing @ 8003.8' CTMD. Milled thorough plug with 4 stalls. Through plug at 8,006.8' Push /mill plug down hole. Stall at 8,030', 8,644' and last stall at 8,663' CTMD. Pulled heavy a few times from 8,663' CTMD. Note: previous CIBP milled from 8,006' CTMD and pushed to 8,648'. Could not make any hole. With smaller mill we were able to mill/push remaining plug debris to 8,663' CTMD. LB6 perfs 8,642'-8,654'. CIBP's below perfs. Cooling down N2. Pick up coil to above perfs at 8,000' and park. Drop 9/16" ball followed with 5 bbls of produced water. PT N2 lines 250/4,000 psi. Chase ball to seat with N2. 4,210 psi sheared circ sub. Returns picking up. 40,000 scf pumped to shear. (430 gallons). Unload well from 8,000'. N2 at surface. RIH and tag 8,663' CTMD. Parked at 8,663' and unloaded. Pumping 1,300 scf/min PU to 8,000' and run back in to 8,663' CTMD and continued to unload. No signs of gas on the monitor. WHP while unloading 65 psi average. 300 gallons of N2 remaining. Start POOH pumping 800 scf/min. After 85 bbls returned mostly N2 at surface but consistent stream of fluid returns. Noticed a change from clean water to grey water at 85 bbls returned. PTW, JSA with crew MIRI SLB CATU 13 with 1.75" coil. Spot return tanks and manlift. 24 hr bope test witness notification sent 8/19/20 @1358. Witness waived via email from Jim Regg 8/19/2020 1653 hrs. Test BOPE. All rams and valves tested 250/4,000 psi. Accumulator draw down test complete. Continued to monitor for LEL on meter. No sign of gas. 4,000' from surface N2 pump out. Continue to bleed N2 from well to open top tank. Tagged up. Close master and swab valve. SITP 201 psi.Break down BHA. Under reamer blades intact and show signs of milling. Rig down CTU 13. Turn well over to production. SDFN. Crew ready to mobilize to next well in the AM. Total fluid pumped: 289 bbls. Wellbore fluid returned: 80 bbls. Fluid from formation returned: 25 bbls.Total SCF pumped : 233,349 (2,506 gal). 08/20/2020 - Thursday CTU Rig Start Date End Date Rig 401 6/11/20 10/31/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name CLU-14 50-133-20684-00-00 219-078 10/17/2020 - Saturday Hold safety meeting with crews. JSA and Permit to work. MIRU SLB CTU 13 with 1.75" coil. Spot rain for rent supply and return tanks. Load with 6% KCL returns from Kalotsa 5. 65 bbls. Dilute with 2 loads of produced water. 195 bbls loaded in supply tank. 24 hour BOPE test witness notification sent 10/16/2020 @ 13:16. Witness waived via email from Jim Regg 10/16/2020 @ 13:31. Pressure test and record all rams and valves to 250/4,000 psi. Perform Koomey draw down test. BOPE test good. Location walk around complete. SDFN. 08/21/2020 - Friday Previous info. E-Line ran in hole and found fluid level at 500'. Tagged fill at 5,295'. Plan was to set a 5.5" CIBP at 5,680'. PTW, JSA Pick Injector head and lubricator. Make up BHA. 1.9" OD roll on coil connector, 1.75" OD DFCV, 2.0" OD MBT, 1.9" OD Down jet nozzle. BHA length 5.87'. Stab on well. PT stack 250/4,000 psi. Open well. RIH. 0 psi WHP. CT pipe displacement produced returns to surface at 3,500'. Dry tag 5,320' CTMD. Pick up clean. Online down CT and fill reel. Circulate to surface and check for 1:1 returns. Max pump rate with lease water down CT is only 1.4 bbls/min. Not enough AV's to carry solids. Cool down N2. Online with N2 900 scf/min. N2 and fluid returns to surface. RIH perform nitrified foam cleanout from 5,320' to top of cement at 6,433' CTMD. Returns showing 30-40% solids. Perform 4 wiper trips while cleaning out. RIH tag 6,433' CTMD. Calculate and determine N2/fluid rates and pressures. Fluid level at 500' with 0 psi whp puts hydrostatic pressure at perfs 2,061 psi. Well is static. Adjust N2, fluid rate, choke position to keep well balanced or slightly over balanced. N2 rate at 900 scf/min, fluid rate at.8 bbls/min choke between 890 psi and 980 psi. Circ pressure 2,660 psi. Equivalent pump rate 1.82 bbls/min 3.74 ppg, 2,089 psi hydrostatic returns cleaning up chase last bottms up to surface. Close choke. WHP 860 psi. Offline with N2 pump 50 bbls down 5.5" casing. Online with N2 2,000 scf/min. Tagged up at surface. Shut down N2 pump. Close swab vavle. SITP 2,285 psi. Total SCF pumped 336,231 (3,611 gallons). Bleed remaining N2 from coil. Pop off well. Stack down. Pollard spotted up awaiting crane. Move SLB lubricator box. Rig up Pollard slick line. Stab on well. Pressure up lubricator. O ring cut on lubricator. Stack down and replace O ring. Stab on well. PT stack. RIH with 3" dd bailer. WHP 1,838 psi. Slick line said they saw FL at 3,300'. SL tagged 6,310' RKB. POO to surface. SLB will leave N2 pump and liquid nitrogen on location. 3,200 gallons. Shut in well. Rig down SL. Rig down SLB CTU 13. 08/22/2020 - Saturday Sign in. Mobe to location. PTW, JSA and SIMOPS w/AKE-Line and SLB N2. PT AKE-Line lubricator to 250 psi low and 3,500 psi. TB - 725 psi. Worked on rental crane. Tightened flange bolts. RIH w/GPT tool and tie into Yellow Jacket perf log. Run correlation log and send to town. Told log was on depth. Could not find fluid level. Found soupy fluid. Ran log from 5,575' to 6,025' and found soapy fluid at 5,800' but found no solid fluid. POOH. RIH w/ 4.212" CIBP and tie into GPL log. Run correlation log and sent to town. Get ok to set plug at 5,680' with 1700 psi on tubing. Set plug at 5,680'. Pick up 30' and went back down and tagged. POOH. Setting tool looked good. Good set. RIH w/ 2-7/8" x 5' HC Razor, 6 spf, 60 deg phase and tied into GPT log. Told log was needed to shift log up 4'. Shifted log up and spotted gun from 5,663' to 5,668'. Fired gun with 1,667' 5 min - 1,693 psi, 10 min - 1,700 psi and 15 min - 1,704 psi. POOH. All shots fired and gun was dry. Rig down equipment and turn well over to field. Rig Start Date End Date Rig 401 6/11/20 10/31/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name CLU-14 50-133-20684-00-00 219-078 Conduct equipment checks. PJSM on conducting Nitrogen blowdown and moving fluids. Head up coil with slim-line connector. Stab on with lubricator, pressure test to 3,500 psi. RIH with coil down to 5,000'. Use Nitrogen to displace fluid from well. Very dirty initial returns from 2-7/8" tubing. Cleaned up as coil moved down to tubing tail. Exit tubing tail, take small bites into liner until below perfs, reach 8,900' md. Returns are mixed very dirty, somewhat clean and very little entrained gas. POH continuing to blow down. Pull to surface, pop off and lay down equipment. Rig Down coil unit and prep for move to BCU-19RD. Secure well, turn over to Operations. 10/18/2020 - Sunday PTW, JSA. Pick injector head stab 20' lubricator. Make up YJOS MHA. Ext. slip connector 2.13" OD, 2.125" DFCV, 2.125" Logan Bi-Di jars, 2.125" Hyd Disco. (pull test CT connector 25k) Pressure test MHA 250/4,500 psi. Continue to install BHA components. 2.125" Dual Circ Sub, 2.125" motor, 2.11" x over sub, 2.30" 4 blade concave insert mill. BHA length 21.18'. Stab on well. PT stack 250/4,000 psi. Close wing valve and bump up SSSV control line pressue to 3,000 psi and double block and flag. Open master swab. Initial WHP 1900 psi. RIH. Crack choke and bleed down WHP. 1900' stacking 8k and then weight breaks back. Possibly pushing something down hole. Online with pump at min rate. (9/4/20 slick line hard tag at 4,846'). Hard tag with coil at 3,585'. Pick up clean. Increase pump rate to 1.2 bbls/min RIH and passed through previous tag with no indication of obstruction. Continue in hole. Increased motor work of 500 psi but no weight loss at 5,267' CTMD. Change out with ROB. Erratic milling with pressure spikes and weight indications. Set down and make several attempts to mill through 7,860' md. Increase rate from 1.0 bpm to 1.3, stack down. Two stall events but finally pushed / milled / washed through and exit tubing tail. Sent in BOP test notice to AOGCC at 1215 pm on 10/18/2020 for well BCU-19RD. Tag up at 8,070', no indication of why. Pick up clean, move down with increased pump rate and slower running speed, push / wash through. One other minor weight and pressure increase but push right through. Tag at 9,683' coil measured depth. Pick up off bottom to 9,640', circulate 9/16" steel ball around to open circ sub. Chase ball with Nitrogen. With Nitrogen moving down coil, attempt to pick up and coil is stuck. Able to move down, cannot pick up. Jars not firing, stuck above BHA. Swap back to fluid, circulate down coil. Normal PUW 8.5k, pull to ~50k, no movement. Mix 10bbl hi-vis pill. Pump down hi-vis pill. Move coil down and stab into bottom as pill exits BHA, immediately begin picking up. Steady movement by coil, PUW 32- 37k during pickup. Continue picking up hole with hi-vis pill sweeping across perf zones. Slow pulling speed as BHA enters into tubing. Significant overpull from 8000' up through 7,600', ~ every 30' (over torqued connections?). Begin Nitrogen flow. POH with workstring to surface while flowing Nitrogen to blow down well (did not go back below tubing tail). Lay down BHA, secure well. Coordinate with Pad Operator to flow well overnight. 10/19/2020 - Monday Rig Start Date End Date Rig 401 6/11/20 10/31/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name CLU-14 50-133-20684-00-00 219-078 10/31/2020 - Sunday Obtain Work permit, RU SL unit, PT Lubricator to 250 psi low/ 2,500 psi high RIH W/ 2.33" GAUGE RING TO 504' WLM TAG SSSV PROFILE - FLAG WIRE - POOH. RIH W/ 2.29" GAUGE RING TO 507' WLM BOBBLE THROUGH TO 510' WLM - MAKE SEVERAL PASSES RIH W/ HALIBURTON LOCK OUT TOOL TO 495'WLM - PICK UP WEIGHT - 150 LBS - CONT IN HOLE, SET DOWN AT 507'WLM - TAP DOWN - BEGIN PUMPING METHANOL - PRESSURE UP TO 950 PSI. SET DOWN AT 507'WLM - TAP DOWN - BEGIN PUMPING METHANOL - PRESSURE UP TO 950 PSI. PUMP PRESSURE "BREAKS OVER" - SHUT DOWN PUMP - JAR DOWN 50 TIMES TO LOCK OUT SSSV. RIH W/ COMMUNICATION TOOL TO 506' WLM - 3400 PSI ON CONTROL LINE - BEGIN JARRING Down 10 times. POOH. PIN SSSV TO XLINE - PRONG ON XLINE STRIPPED THREADS - STANDBY FOR ALTERNATE TOOLS. RIH W/ 2-7/8" XLINE W/ PRONG W/ SSSV TO 490'WLM - PURGE CONTROL LINE - CONTINUE IN HOLE TO 506' WLM WT TO SET SSSV - PRESSURE UP ON CONTROL LINE (4000 PSI) HOLDS - SHEAR OFF. POOH. SHUT SSSV - PERFORM CLOSURE TEST - BLEED TUBING FROM 1,000 PSI TO 100 PSI - HOLDS BEGIN GETTING GAS BACK TO TANK ON SSSV PUMP - SHUT IN. PRESSURE UP ON SSSV TO 4,000 PSI - HOLDS PRESSURE SSSV OPENS - CONTROL LINE WILL NOT BLEED TO 0 PSI - APPEARS TO BE A ONE WAY LEAK ON UPPER SET OF V PACKING.BLEED TO 0 PSI - APPEARS TO BE A ONE WAY LEAK ON UPPER SET OF V PACKING. RIH W/ GS W/ 7' PRONG TO 507'WLM - WT PULL SSSV - OOH W/ SSSV IN GOOD CONDITION - ADD 1 PIECE OF V PACKING TO EACH STACK - PACKING MEASURES 2.38''. RIH W/ XLINE W/ PRONG W/ SSSV TO 506'KB WT SET VALVE - PRESSURE UP ON CONTROL LINE SHEAR OFF - POOH - OOH - CAN NOT BLEED CONTROL TO 0 PSI DISCUSS OPERATIONS W/ CO. REP. - CONTINUE TO BLEED OFF CONTROL LINE PRESSURE -PERFORM CLOSURE TEST ON SSSV - PASS. DOES NOT TRACK CONTROL LINE FUNCTION TEST SSSV - OPERATES PROPERLY - BLEED CONTROL LINE PRESSURE - TUBING. RIG DOWN W/L - SECURE WELL - RETURN TO PRODUCTION TO FLOW MOB TO PWL SHOP. SET SSSV _____________________________________________________________________________________ Updated by DMA 11-18-20 SCHEMATIC Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 109 / X-56 / Weld 15” Surf 120’ 10-3/4” Surface 45.5 / L-80 / TXP BTC 9.950” Surf 3,333’ 7-5/8" Intermediate 29.7 / L-80 / W563 6.875” Surf 6,824’ 4-1/2" Production 12.6 / L-80 / TXP BTC 3.958” 5,365’ 9,800’ TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8” Tubing 6.5 / L-80 / EUE 2.441” Surf 5,391’ 2-7/8” Tubing 6.5 / L-80 / FJ3 2.441” 5,402’ 7,885’ JEWELRY DETAIL No Depth Item 1 507’ SSSV-Halli FXE WL 10/18/20 1A 531’ SSSV-Halliburton NE SRSV 07/28/20 2 2,821’ 7-5/8” Swell Packer 3 5,391’ 4.5” x 5.75” Bullet Tie-Back Seal Assembly 4 5,365’ 7-5/8” X 4-1/2” Baker ZXP 5 7,886’ Wireline Re-entry Guide 07/28/20 OPEN HOLE / CEMENT DETAIL 10-3/4” 329 BBL’s of cement in 13.5” Hole 7-5/8" 219 BBL’s of cement in 9-7/8” Hole 4-1/2" 148 BBL’s of cement in 6-3/4” Hole PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status MB-8/8A 8,028’ 8,042’ 6,336’ 6,350’ 14’ 9/18/2019 Open MB-8/8A 8,058’ 8,078’ 6,366’ 6,384’ 20’ 9/18/2019 Open LB-4 8,565’ 8,577’ 6,852’ 6,863’ 12’ 9/13/2019 Open LB-6 8,642’ 8,654’ 6,926’ 6,937’ 12’ 11/25/2019 Open FISH DETAIL 8,663’ CIBP Debris 08/18/20 Middle Fish RBP Pushed to Bottom 9,659’ CIBP Milled and Pushed to Bottom 09/11/19 NOTE: TR SSSV initially failed. 1.Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Install SSC-SSSV 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): 9,802'8,663' Casing Collapse Structural Conductor Surface 2,090psi Intermediate 4,790psi Production 7,500psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG 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 10, 2020 2-7/8" 9,800' Perforation Depth MD (ft): 6,824' See Attached Schematic 4,435'8,041'4-1/2" 16" 10-3/4" 120' 7-5/8"6,824' 3,333'3,580psi 120' 2,616' 5,183' 120' 3,333' 6.5# / L-80 TVD Burst 7,885' 8,430psi MD 6,890psi Length Size CO 231 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 ADL60569, ADL60568, ADL 324602, Fee Private 219-078 50-133-20684-00-00 Cannery Loop Unit (CLU) 14 Cannery Loop / Sterling Undefined Gas Pool, Beluga Gas Pool COMMISSION USE ONLY Authorized Name: Tubing Grade: 6.5# / L-80 Tubing MD (ft): 5,391' See Attached Schematic tkramer@hilcorp.com 8,043'9,659'7,903'~1850psi N/A Swell Pkr; SSSV-Halliburton NE SRSV 2,821' MD (2,234' TVD); 531' MD/TVD Perforation Depth TVD (ft):Tubing Size: 2-7/8" m n P 66 t V Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 10:04 am, Aug 28, 2020 320-362 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.08.27 22:14:57 -08'00' Taylor Wellman Install SSC-SSSVV 10-404 SFD 8/28/2020 K-valve DSR-8/31/2020gls 8/31/20 *Witnessed SVS test within 5 days of K valve installation. Comm. 8/31/2020 JLC 8/31/2020 RBDMS HEW 8/31/2020 Well Prognosis Well: CLU 14 Date: 8-27-2020 Well Name:CLU 14 API Number:50-133-20684-00-00 Current Status:Producing Gas Well Leg:N/A Estimated Start Date:September 10 th 2020 Rig:401 Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:219-078 First Call Engineer:Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) Second Call Engineer:Ryan Rupart (907) 777-8503 (O) (907) 301-1736 (C) AFE Number: Maximum Expected BHP:~ 2,400 psi @ 6,937 TVD (Based on normal gradient) Max. Potential Surface Pressure:1850 psi Measured SI tubing pressure Brief Well Summary CLU 14 was recently worked over to install a velocity string. As part of this installation a new SSSV was placed in the tubing string at 531’. Once the well was brought on line, it was discovered that the SSSV would not function. A camera was ran to observe the valve as it was functioned from surface but no movement in the sleeve was observed. The purpose of this work/sundry is to install a subsurface controlled subsurface safety valve (SSC-SSSV) in accordance with Guidance Bulletin 10-004. Notes Regarding Wellbore Condition x Casing PT’d to 3,500 psi on 8/20/2019 SSC-SSSV Suitability Evaluation: Well historic parameters Gross Gas 1.5 mmcfd Gross Fluid 19 BPD FTP 150psig Temp 100F This safety valve will be setup with a trip pressure of ~100 psig. We will hold backpressure on the well with the production choke to maintain a normal FTP of ~150 psig (Header pressure is 100psi). To test the valve we will open the production choke, lowering the FTP and trip the SSC-SSSV. To reset the valve the well will be pressured up to above the trip pressure then gradually reopened to the normal operating range. Procedure: 1. MIRU Slick-line, PT lubricator to 2,500 psi Hi 250 Low. 2. RIH and set the subsurface controlled subsurface safety valve. 3. Turn well over to production. 4. Conduct a SVS test within 14 days after stabilized flow. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic K-valve 5 (normal header press =100psi) _____________________________________________________________________________________ Updated by DMA 08-27-20 SCHEMATIC Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 109 / X-56 / Weld 15” Surf 120’ 10-3/4” Surface 45.5 / L-80 / TXP BTC 9.950” Surf 3,333’ 7-5/8" Intermediate 29.7 / L-80 / W563 6.875” Surf 6,824’ 4-1/2" Production 12.6 / L-80 / TXP BTC 3.958” 5,365’ 9,800’ TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8” Tubing 6.5 / L-80 / EUE 2.441” Surf 5,391’ 2-7/8” Tubing 6.5 / L-80 / FJ3 2.441” 5,402’ 7,885’ JEWELRY DETAIL No Depth Item 1 531’ SSSV-Halliburton NE SRSV 07/28/20 2 2,821’ 7-5/8” Swell Packer 3 5,391’ 4.5” x 5.75” Bullet Tie-Back Seal Assembly 4 5,365’ 7-5/8” X 4-1/2” Liner Hanger 5 7,886’ Wireline Re-entry Guide 07/28/20 OPEN HOLE / CEMENT DETAIL 10-3/4” 329 BBL’s of cement in 13.5” Hole 7-5/8" 219 BBL’s of cement in 9-7/8” Hole 4-1/2" 148 BBL’s of cement in 6-3/4” Hole PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status MB-8/8A 8,028’ 8,042’ 6,336’ 6,350’ 14’ 9/18/2019 Open MB-8/8A 8,058’ 8,078’ 6,366’ 6,384’ 20’ 9/18/2019 Open LB-4 8,565’ 8,577’ 6,852’ 6,863’ 12’ 9/13/2019 Open LB-6 8,642’ 8,654’ 6,926’ 6,937’ 12’ 11/25/2019 Open FISH DETAIL 8,663’ CIBP Debris 08/18/20 Middle Fish RBP Pushed to Bottom 9,659’ CIBP Milled and Pushed to Bottom 09/11/19 _____________________________________________________________________________________ Updated by DMA 08-27-20 PROPOSED SCHEMATIC Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 109 / X-56 / Weld 15” Surf 120’ 10-3/4” Surface 45.5 / L-80 / TXP BTC 9.950” Surf 3,333’ 7-5/8" Intermediate 29.7 / L-80 / W563 6.875” Surf 6,824’ 4-1/2" Production 12.6 / L-80 / TXP BTC 3.958” 5,365’ 9,800’ TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8” Tubing 6.5 / L-80 / EUE 2.441” Surf 5,391’ 2-7/8” Tubing 6.5 / L-80 / FJ3 2.441” 5,402’ 7,885’ JEWELRY DETAIL No Depth Item 1 530’ K Valve set to close @ 150 psi 1A 531’ SSSV-Halliburton NE SRSV 07/28/20 2 2,821’ 7-5/8” Swell Packer 3 5,391’ 4.5” x 5.75” Bullet Tie-Back Seal Assembly 4 5,365’ 7-5/8” X 4-1/2” Liner Hanger 5 7,886’ Wireline Re-entry Guide 07/28/20 OPEN HOLE / CEMENT DETAIL 10-3/4” 329 BBL’s of cement in 13.5” Hole 7-5/8" 219 BBL’s of cement in 9-7/8” Hole 4-1/2" 148 BBL’s of cement in 6-3/4” Hole PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status MB-8/8A 8,028’ 8,042’ 6,336’ 6,350’ 14’ 9/18/2019 Open MB-8/8A 8,058’ 8,078’ 6,366’ 6,384’ 20’ 9/18/2019 Open LB-4 8,565’ 8,577’ 6,852’ 6,863’ 12’ 9/13/2019 Open LB-6 8,642’ 8,654’ 6,926’ 6,937’ 12’ 11/25/2019 Open FISH DETAIL 8,663’ CIBP Debris 08/18/20 Middle Fish RBP Pushed to Bottom 9,659’ CIBP Milled and Pushed to Bottom 09/11/19 K-valve Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: doudean@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: DATE 8/20/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL CLU 14 (219-078) Halliburton PRESS TEMP 8/29/2019 PPROF 9/24/2019 CBL 10/11/2019 Please include current contact information if different from above. Received by the AOGCC 08/24/2020 PTD: 2190780 E-Set: 33676 Abby Bell 08/24/2020 STATE OF ALASKA Reviewed By: J(-"� OIL AND GAS CONSERVATION COMMISSION P.I. Supry X 4 7OZ-0 BOPE Test Report for: CANNERY LOOP UNIT 14 =11 Comm Contractor/Rig No.: Hilcorp 401 PTD#:� 2190780 DATE: 7/25/2020 ' Inspector Austin McLeod Insp Source Operator: Hilcorp Alaska, LLC Operator Rep: Bobby Harrington Rig Rep: Chad Johnson Inspector Type Operation: WRKOV Sundry No: Test Pressures: Inspection No: bopSAM200726113125 Type Test: INIT 320-076 Rams: Annular: Valves: MASP: 250/4500 / 250/450250/4500✓ 1760 / Related Insp No: TEST DATA MISC. INSPECTIONS: MUD SYSTEM: P/F ACCUMULATOR SYSTEM: 0 NA P/F 0_ Visual Alarm Time/Pressure P/F Location Gen.: P - Trip Tank NA - NA System Pressure 2975 - P " Housekeeping: P Pit Level Indicators NA NA - Pressure After Closure 2075 P ' PTD On Location P Flow Indicator -NA_ NA - 200 PSI Attained 37 P " Standing Order Posted P ' Meth Gas Detector P " P Full Pressure Attained 175 P Well Sign P--' H2S Gas Detector P P Blind Switch Covers: All stations - P " Drl. Rig P " MS Misc NA NA Nitgn. Bottles (avg): 62000 - P ' Hazard Sec. P--' P — Inside Reel Valves 0 NA ACC Misc 0 NA Misc NA Check Valve 0 NA FLOOR SAFTY VALVES: BOP STACK: Quantity P/F Upper Kelly 0 NA Lower Kelly 0_ NA Ball Type 2 P - Inside BOP 2 P FSV Misc 0 NA BOP STACK: CHOKE MANIFOLD: Quantity Size P/F Quantity P/F Stripper 0 NA No. Valves 8 - P_ Annular Preventer 1 11" P - Manual Chokes 2 P #1 Rams I 2-7/8"x5" _ P_ y Hydraulic Chokes __ 0 - _ NA #2 Rams 1 ' Blinds 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 1- 2-1/16" - P Quantity P/F HCR Valves 1 ' 2-1/16" P — Inside Reel Valves 0 NA Kill Line Valves 3 2-1/16" P Check Valve 0 NA BOP Misc 0 NA Number of Failures: 0 ✓ Test Results Remarks: 2-7/8" & 4-1/2" joints. Annular on 2-7/8", VBR's on both. New Yeflowjacket stack. Test Time 4.5 THE STATE OIALASKA GOVERNOR MIKE DUNLEAVY Taylor Wellman Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 v .00gcc.olaska.gov Re: Cannery Loop Field, Sterling Undefined Gas and Beluga Gas Pools, CLU 14 Permit to Drill Number: 219-078 Sundry Number: 320-076 Dear Mr. Wellman: Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Jessiewski Commissioner DATED this 2.6 day of February, 2020. IBDMStn'' FEB 2 5 2020 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 RECEIVED FEB 12 Z020 97-S t( z of Z. 0 A0r,r.r.. 1. Type of Request: Abandon El Plug Perforations El Fracture Stimulate ❑ Repair Well ❑ (6%Operations shutdown ❑ -Js V4 Suspend ❑ Perforate ❑ Other Stimulate E] Pull Tubing ❑v LC Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Nitrogen ❑� 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development Q Stratigraphic ❑ Service ❑ 219-078 . 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-133-20684-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 231 Will planned perforations require a spacing exception? Yes ❑ No ❑� Cannery Loop Unit (CLU) 14 9. Property Designation (Lease.Number): . 10. Field/Pool(s): , , ADI -60565, ADI -60568, ADL 324602, Fee Private Cannery Loop / Sterling Undefined Gas Pool, Beluga Gas Pool it. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 9,802' 8,043' 9,659' 7,903' -1,760 psi N/A CIBP @ Bun 9,659' Casing Length Size MD TVD Burst Collapse Structural Conductor 120' 16" 120' 120' Surface 3,333' 10-3/4" 3,333' 2,616' 3,580psi 2,090psi Intermediate 6,824' 7-5/8" 6,824' 5,183' 6,890psi 4,790psi Production 4,435' 4-1/2" 9,800' 8,041' 8,430psi 7,500psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 4-1/2" 12.69 L-80 5,381' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Swell Pkr; SSSV-Halliburton TRSV-NE 2,821' MD (2,234' TVD); 527' MD/TVD 12. Attachments: Proposal Summary Wellbore schematic A Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Strati ra hic g p ❑ Development Service ❑ 14. Estimated Date for 15. Well Status after proposed work: April 1, 2020 Commencing Operations: OIL [:]WINJ ❑ WDSPL F-1Suspended❑ GAS ❑� WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Taylor Wellman 907-777-8449 Contact Name: Ted Kramer 907-777-8420 Authorized Title: Operations MagaW Contact Email: tkramer hilcor .corn Contact Phone: 777-8420 Authorized Signature: Date: Z 10 y» COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 4161 30 0 - �// ❑ Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance Other: {L 3c�70 P s ,: AO P '�� R MSS FEB 2 5 2020 Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No Subsequent Form Required: APPROVED BY ^` Approved by: % COMMISSIONER THE COMMISSION Date: a av-� V r� RGINeA� SubsinForm and Form 1 03 Revised 412017 Approved applicati n Id the date of approval. gnachmentmn Duplicate U FIilmrp Alaska, LL, Well Prognosis Well: CLU 14 Date: 02-07-2020 Well Name: CLU 14 API Number: 50-133-20684-00-00 Current Status: Producing Gas Well Leg: N/A Estimated Start Date: April 1, 2020 Rig: 0 Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 219-078 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (C) Second Call Engineer: Taylor Wellman (907) 777-8449 (0) (907) 947-9533 (C) AFE Number: Maximum Expected BHP: - 2,395 psi @ 6,349' TVD (Initial Reservoir Pressure from RFT) Max. Potential Surface Pressure: - 1,760 psi (Based upon the Initial Res. Press. and a 0.10 psi/ft gas gradient to surface) Brief Well Summary CLU 14 is a grass roots development well that was drilled and completed in August 2019, targeting gas sands in the Beluga and Sterling formations. The well is currently completed with a 4-1/2" tubing string tied into a 4-1/2" liner (basically a 4-1/2" mono -bore). The purpose of this Sundry is to install a 2-7/8" Velocity String to help keep the well unloaded. 71, ig Notes Regarding Wellbore Condition: • Casing Pressure Tested to 3,500 psi on 8/20/2019. 4-1/2" Production String Pressure Tested to 3,500 psi on tubing / 2,500 psi on annulus on 8/21/2019. Safety Concerns: • Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job). r • Ensure all crews are aware of stop work authority. k „Pre -Rig Procedure: " b`f Sr ,'f,O1) MIRU E -Line and pressure control equipment. Pressure test (PT) lubricator to 250 psi Low/ 3,000 psi High. 2) PU & RIH with 4-1/2" Retrievable Bridge Plug (RBP) to 8,020' (+/-). Set same depth & POOH. 3) PU & RIH with 4-1/2" Tubing Punch to 5,360'. Punch 4' of holes from 5,360'- 5,355'. POOH & RD E -line. 4) RU Pump Truck. Circulate the wellbore with 8.4 ppg brine (through the punched holes at 5,360'-5,355'). Rig 401 Procedure: Tsi GSsi .M j P Zbn�� y-5 ��6 5) MIRU workover rig 401. (C -A I r) 6) Notify AOGCC 24 hours in advance of test to extend the opportunity to witness. 7) Set back pressure valve. ZSR 8) ND wellhead, NU 13-5/8" BOP and test to 250 psi low & 3,000 psi high, annular to 250 psi low & 3,900Tpsi pe, high. Record accumulator pre -charge pressures and chart tests. V a) Perform Test. b) Test VBR rams on 2-7/8" and 4-1/2" test joints. c) Submit completed form 10-424 to AOGCC within 5 days of BOPE test. H Hileara Alaska, LLI Well Prognosis Well: CLU 14 Date: 02-07-2020 9) PU on 4-1/2" tubing string, unseating it from the 7-5/8" x 4-1/2" liner hanger. 10) POOH with 4-1/2" tubing, laying down SSSV and tubing. 11) PU & RIH with 2-7/8" tubing string (including SSSV), to just above the 4-1/2" liner hanger (@5,365'). 12) Sting seal assembly into the 7-5/8" x 4-1/2" liner hanger. a) Note: 2-7/8" Flush Joint tubing tail below the seal assembly with bottom of tail @ –8,005' MD. _r1 13) ND BOP & NU wellhead (& PT). �—� p�e55ue �, 1 n 14) Move off rig 401. �oo� S ` /30 Coiled Tubing Unit Procedure: Q P� 15) MIRU Coiled Tubing Unit (CTU), onto the 2-7/8" tubing. 16) RIH with 1-3/4" coiled tubing to –8,000'. 17) RU Nitrogen (N2) and blow the 8.4 ppg brine out of the tubing. RD N2. 18) POOH with coiled tubing. P 414 19) RIH with coiled tubing to un -seat the RBP at "'8,020'. 20) Unseat RBP and push to bottom of hole. 21) POOH with coiled tubing, leaving thePJIP arthe bottom of the hole. 22) RDMO CTU. 23) Blow down Nitrogen. 24) Return well to service. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. BOPE Schematic 4. CTU BOPE Schematic S. Standard Well Procedure–N2 Operations 6. RWO Sundry Revision Change Form n uitcor. A6.k., LLC m z9,W (MD)/8,043' (M) P8m=9W (MD)/7,9V (ND) SCHEMATIC (O Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm 16" Conductor 109/X-56/Weld 15" Surf 120' 10-3/4" Surface 45.5 A-80/TXP BTC 9.950" Surf 3,333' 7-5/8" Intermediate 29.7/L -80/W563 6.875" Surf 6,824' 4-1/2" Production 12.6 / L-80 / TXP BTC 3.958" 5,365' 9,800' TUBING DETAIL Size Type Wt/Grade/Conn ID Top Btm 4-1/2" Tubing 12.6/L80/IBT 3.98" Surf 5,381' JEWELRY DETAIL No F Depth Item 1 1 527' SSSV 2 2,821' 7-5/S" Swell Packer 3 5,365' 7-5/8" X 4-1/2" Liner Hanger OPEN HOLE/ CEMENT DETAIL 10-3/4" 329 BBL's of cement in 13.5" Hale 7-5/8" 219 BE of cement in 9-7/8" Hole 4-1/2" 1 148 BBL's of cement in 6-3/4" Hole PERFORATION DETAIL one Top(MD) I Btm(MD) Top(TVD) Btm(TVD) Amt Date Status 1-8/8A 8,028' 8,042' 6,336' 1 6,350' 14' 9/18/2019 Open V 8/8A 8,058' 8,078 6,366' 1 6,384' 20' 9/18/2019 Open 4 8,565' 8,577' 6,852' 1 6,863' 12' 9/13/2019 Open 6 8,642' 8,654' 6,926' 1 6,937' 12' 11/25/2019 Open 7ish: CIBP milled and pushed to >ottom @ 9,659' MD (09/11/19) Updated by PMW 01-10-20 PROPOSED SCHEMATIC Hflcorp Alaska. LLC W®: MSL• air Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 'TAIL TD c9,W(MD)/4Wf M) PBTD x0T (MD) / 7,W (TVD) onn ID Top Btm 'eld 15" Surf 120' r BTC 9.950" Surf 3,333' 563 6.875" Surf 6,824' �BTC 3.958" 5,365' 9,800' TAIL onn ID Top Btm JE 2.441" Surf 5,365' 13 2.441" 5,365' 8,005' FAIL r fie -Back Seal Assembly er Hanger iuide ENT DETAIL ile ole ole AIL VD) Amt Date Status 0' 14' 9/18/2019 Open 4' 20' 9/18/2019 Open 3' 12' 9/13/2019 Open 7' 12' 1 11/25/2019 Open Updated by PMW 01-10-20 YELLOWACKET OILFIELD SERVICES 13-5/8" 5M DOUBLE BOP STACK A FORGED ANNULAR 3-5/8!'5M IWS DOUBLE RAM BOP 7/8" TO 5" VBR RAMS IN TOP BORE LIND RAMS IN BOTTOM BORE 4-1-16" 5M GATE VALVES 4-1/16" X 2-1/16" DSA ON ENDS TO CO -FLEX 11" 5M DSA TOTAL STACK HEIGHT 106.3 INCLUDING BOTTOM DSA OPEN AND CLOSE DATA OPEN ICLOSE 13-5/8" 5M ANNULAR 17.41 23.58 13-5/8" 5M RAMS PER CAVITY 4.7 5.34 4-1/16" 5M HCR 1 0.611 0.52 KM.P WH P: 2.1502 x 2-11 Flanged V. (Manual 2-1/16 1OK 10K Range (Main Coil Tubing BOP Coiled Tubing HR580 Injector Head & Gooseneck Weight = 12,850 lbs 4.1/16" tOK Conventional Stripper 5K 0062 Lubricator SK 0062 x 4-1/16" 10K Flange 4-1/16" 10K Combi BOP Top Set BWi hear Second Set: MpNSlip 4.1/1 fi" 10K Flow Crass Manual 2x2 Valve 1:2" 1502 x 2-1/16° 10K Range Manual 2x2 Valve 2:2-1116" 1OK x2-1/16° 10K Rage Manual 2x2 Valve 3: 2-1116° tOK x2 -1/1S -10K Range Manual 2x2 Valve 4:2° 1502 x 2-1/16" 1OK Rage 4.1/16" 10K x Wellhead Adapter Flange Wellhead STANDARD WELL PROCEDURE leorp Alaska. LLC NITROGEN OPERATIONS 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. 30.) 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 02 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. 12/08/2015 FINAL vl Page 1 of 1 Hilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well: Cannery Loop Unit 14 (PTD 219-078) Sundry #: XXX -XXX Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) "first call' engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? Y/ N HAK Prepared By Initials HAK Approved By Initials AOGCC Written Approval Received (Person and Date) Approval: Prepared: Asset Team Operations Manager Date First Call Operations Engineer Date DATA SUBMITTAL COMPLIANCE REPORT 1/31/2020 Permit to Drill 2190780 Well Name/No. CANNERY LOOP UNIT 14 Operator Hilcorp Alaska LLC API No. 50-133-20684-00-00 MD 9802 TVD 8043 Completion Date 8/21/2019 Completion Status 1 -GAS Current Status 1 -GAS UIC No REQUIRED INFORMATION / L tL l Mud Log loo .p " 1 0D 1411 Samples No,//Directional Survey Yes DATA INFORMATION List of Logs Obtained: ROP/DGR/ADR/CTN/ALD/ABG/MD,ALD/DGR/ADR/CTN/ABG/TVD, Mud Logs,HES CBL,Pollard CBLs,SLB Sonic, XPT (from Master Well Data/Logs) Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval OHI Type Med/Frmt Number Name Scale Media No Start Stop CH Received Comments ED C 31282 Digital Data 10 9805 9/30/2019 Electronic Data Set, Filename: CLU-14.1as ED C 31282 Digital Data 9/30/2019 Electronic File: CLU 14 Nabors AM Report 07-25- 2019.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU 14 Nabors AM Report 07-26- 2019.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU 14 Nabors AM Report 07-27- 2019.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU 14 Nabors AM Report 07-28- 2019.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU 14 Nabors AM Report 07-29- 2019.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU 14 Nabors AM Report 07-30- 2019.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU 14 Nabors AM Report 07-31- 2019.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU 14 Nabors AM Report 08-01- 2019.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU 14 Nabors AM Report 08-02- 2019.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU 14 Nabors AM Report 08-03- 2019.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU 14 Nabors AM Report 08-04- 2019.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU 14 Nabors AM Report 08-05- 2019.pdf AOOCC Page I of Friday, January 31, 2020 DATA SUBMITTAL COMPLIANCE REPORT 1/31/2020 Permit to Drill 2190780 Well Name/No. CANNERY LOOP UNIT 14 MD 9802 TVD 8043 Completion Date 8/21/2019 ED C 31282 Digital Data ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data Operator Hilcorp Alaska LLC API No. 50-133-20684-00-00 Completion Status 1 -GAS Current Status 1 -GAS UIC No 9/30/2019 Electronic File: CLU 14 Nabors AM Report 08-06- 2019.pdf 9/30/2019 Electronic File: CLU 14 Nabors AM Report 08-07- 2019.pdf 9/30/2019 Electronic File: CLU 14 Nabors AM Report 08-08- 2019.pdf 9/30/2019 Electronic File: CLU 14 Nabors AM Report 08-09- 2019.pdf 9/30/2019 Electronic File: CLU 14 Nabors AM Report 08-10- 2019.pdf 9/30/2019 Electronic File: CLU 14 Nabors AM Report 08-11- 2019.pdf 9/30/2019 Electronic File: CLU 14 Nabors AM Report 08-12- 2019.pdf 9/30/2019 Electronic File: CLU 14 Nabors AM Report 08-13- 2019.pdf 9/30/2019 Electronic File: CLU 14 Nabors AM Report 08-14- 2019.pdf 9/30/2019 Electronic File: CLU 14 Nabors AM Report 08-15- 2019.pdf 9/30/2019 Electronic File: CLU 14 Nabors AM Report 08-16- 2019.pdf 9/30/2019 Electronic File: CLU 14 Nabors AM Report 08-17- 2019.pdf 9/30/2019 Electronic File: CLU 14 Nabors AM Report 08-18- 2019.pdf 9/30/2019 Electronic File: CLU14.dbf 9/30/2019 Electronic File: clu14.hdr 9/30/2019 Electronic File: CLU14.mdx 9/30/2019 Electronic File: clul4r.dbf 9/30/2019 Electronic File: clul4r.mdx 9/30/2019 Electronic File: CLU14 SCL.DBF 9/30/2019 Electronic File: CLU14_SCL.MDX 9/30/2019 Electronic File: CLU14 tvd.dbf AOGCC Page 2 of 8 Friday, January 31, 2020 DATA SUBMITTAL COMPLIANCE REPORT 113112020 Permit to Drill 2190780 Well Name/No. CANNERY LOOP UNIT 14 Operator Hilcorp Alaska LLC API No. 50-133-20684-00-00 MD 9802 TVD 8043 Completion Date 8/21/2019 Completion Status 1 -GAS Current Status 1 -GAS UIC No ED C 31282 Digital Data 9/30/2019 Electronic File: CLU14_tvd.mdx ED C 31282 Digital Data 9/30/2019 Electronic File: CLU 14 - Final Well Report.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU -14 - Sin Drilling Dynamics Log MD.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU -14 - Sin Drilling Dynamics Log TVD.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU -14 - Sin Formation Log MD.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU -14 - Sin Formation Log TVD.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU -14 - Sin Gas Ratio Log MD.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU -14 - Sin Gas Ratio Log TVO.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU -14 - Sin LWD Combo Log MD.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU -14 - Sin LWD Combo Log TVD.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU -14 - Drilling Dynamics Log MD.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU -14 - Drilling Dynamics Log TVD.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU -14 - Formation Log MO.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU -14 - Formation Log TVD.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU -14 - Gas Ratio Log MD.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU -14 - Gas Ratio Log TVD.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU -14 - LWD Combo Log MD.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU -14 - LWD Combo Log TVD.pdf ED C 31282 Digital Data 9/30/2019 Electronic File: CLU -14 - Sin Drilling Dynamics Log MD.tif ED C 31282 Digital Data 9/30/2019 Electronic File: CLU -14 - Sin Drilling Dynamics Log TVD.tif AOGCC Page 3 of 8 Friday, January 31, 2020 DATA SUBMITTAL COMPLIANCE REPORT 1/31/2020 Permit to Drill 2190780 Well Name/No. CANNERY LOOP UNIT 14 MD 9802 ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C TVD 8043 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data 31282 Digital Data Completion Date 8/21/2019 Operator Hilcorp Alaska LLC API No. 50-133-20684-00-00 Completion Status 1 -GAS Current Status 1 -GAS UIC No 9/30/2019 Electronic File: CLU -14 - Sin Formation Log MD.tif 9/30/2019 Electronic File: CLU -14 - Sin Formation Log TVD.tif 9/30/2019 Electronic File: CLU -14 - 5in Gas Ratio Log MD.tif 9/30/2019 Electronic File: CLU -14 - 51n Gas Ratio Log TVD.tlf 9/30/2019 Electronic File: CLU -14 - 5in LW D Combo Log MD.tif 9/30/2019 Electronic File: CLU -14 - 5in LW D Combo Log TVD.tif 9/30/2019 Electronic File: CLU -14 - Drilling Dynamics Log MD.tif 9/30/2019 Electronic File: CLU -14 - Drilling Dynamics Log TVD.tif 9/30/2019 Electronic File: CLU -14 - Formation Log MD.tif 9/30/2019 Electronic File: CLU -14 - Formation Log TVD.tif 9/30/2019 Electronic File: CLU -14 - Gas Ratio Log MD.tif 9/30/2019 Electronic File: CLU -14 - Gas Ratio Log TVD.tif 9/30/2019 Electronic File: CLU -14 - LW D Combo Log MD.tif 9/30/2019 Electronic File: CLU -14 - LW D Combo Log TVD.tif 9/30/2019 Electronic File: CLU 14 Show Report 5635- 5670.pdf 9/30/2019 Electronic File: CLU 14 Show Report 5775- 5840.pdf 9/30/2019 Electronic File: CLU 14 Show Report 5855- 5905.pdf 9/30/2019 Electronic File: CLU 14 Show Report 6600- 6671.pdf 9/30/2019 Electronic File: CLU 14 Show Report 6672- 6770.pdf 9/30/2019 Electronic File: CLU 14 Show Report 6785- 6835.pdf AOGCC Page 4 of 8 Friday, January 31, 2020 DATA SUBMITTAL COMPLIANCE REPORT 1/31/2020 Permit to Drill 2190780 Well Name/No. CANNERY LOOP UNIT 14 MD 9802 TVD 8043 Completion Date 8/21/2019 ED C 31282 Digital Data ED C 31282 Digital Data ED C 31282 Digital Data ED C 31282 Digital Data ED C 31282 Digital Data ED C 31282 Digital Data I ED C 31282 Digital Data Log 31282 Log Header Scans ED C 31292 Digital Data ED C 31292 Digital Data ED C 31292 Digital Data ED C 31292 Digital Data ED C 31292 Digital Data ED C 31292 Digital Data ED C 31292 Digital Data ED C 31292 Digital Data ED C 31292 Digital Data ED C 31292 Digital Data ED C 31292 Digital Data ED C 31292 Digital Data ED C 31292 Digital Data ED C 31292 Digital Data ED C 31292 Digital Data Operator Hileorp Alaska LLC API No. 50-133-20684-00-00 Completion Status 1 -GAS Current Status 1 -GAS UIC No 9/30/2019 Electronic File: CLU 14 Show Report 7520- 7595.pdf 9/30/2019 Electronic File: CLU 14 Show Report 7724- 7766.pdf 9/30/2019 Electronic File: CLU 14 Show Report 8030- 8105.pdf 9/30/2019 Electronic File: CLU 14 Show Report 8400- 8494.pdf 9/30/2019 Electronic File: CLU 14 Show Report 8542- 8584.pdf 9/30/2019 Electronic File: CLU 14 Show Report 8637- 8665.pdf 9/30/2019 Electronic File: CLU 14 Show Report 9622- 9719.pdf 0 0 2190780 CANNERY LOOP UNIT 14 LOG HEADERS 128 9802 10/4/2019 Electronic Data Set, Filename: CLU 14 LWD Final.las 10/4/2019 Electronic File: CLU 14 LWD Final MD.cgm 10/4/2019 Electronic File: CLU 14 LWD Final TVD.cgm 10/4/2019 Electronic File: CLU 14 Surveys.xlsx 10/4/2019 Electronic File: CLU 14_DSR.txt 10/4/2019 Electronic File: CLU 14 GIS.txt 10/4/2019 Electronic File: CLU -14 - Definitive Survey Report.pdf 10/4/2019 Electronic File: CLU-14_Plan.pdf 10/4/2019 Electronic File: CLU-14_VSec.pdf 10/4/2019 Electronic File: CLU 14 LWD Final MD.emf 10/4/2019 Electronic File: CLU 14 LWD Final TVD.emf 10/4/2019 Electronic File: CLU 14 LWD Final MD.pdf 10/4/2019 Electronic File: CLU 14 LWD Final TVD.pdf 10/4/2019 Electronic File: CLU 14 LWD Final MD.tif 10/4/2019 Electronic File: CLU 14 LWD Final TVD.tif AOGCC Page 5 of 8 Friday, January 31, 2020 DATA SUBMITTAL COMPLIANCE REPORT 1/31/2020 Permit to Drill 2190780 Well Name/No. CANNERY LOOP UNIT 14 Operator Hilcorp Alaska LLC MD 9802 TVD 8043 Completion Date 8/21/2019 ED C 31292 Digital Data ED C 31292 Digital Data Log Electronic Data Set, Filename: (2855) CLU -14, 31292 Log Header Scans ED C 31293 Digital Data ED C 31293 Digital Data Log 31293 Log Header Scans ED C 31684 Digital Data ED C 31684 Digital Data ED C 31684 Digital Data Log 31684 Log Header Scans Log 2190780 CANNERY LOOP UNIT 14 LOG 31685 Log Header Scans ED C 31685 Digital Data ED C 31685 Digital Data ED C 31685 Digital Data ED C 31685 Digital Data ED C 31685 Digital Data ED C 31685 Digital Data ED C 31686 Digital Data Completion Status 1 -GAS 0 0 6740 1693 0 0 9692 5390 0 0 0 0 6728 9778 API No. 50-133-20684-00-00 Current Status 1 -GAS UIC No 10/4/2019 Electronic File: E1v1FView3_1.zip 10/4/2019 Electronic File: Readme.t# 2190780 CANNERY LOOP UNIT 14 LOG HEADERS 10/4/2019 Electronic Data Set, Filename: (2855) CLU -14, CBL, 8-9-19, Field Log.las 10/4/2019 Electronic File: (2855) CLU -14, CBL, 8-9-19, Field Log.pdf 2190780 CANNERY LOOP UNIT 14 LOG HEADERS 12/13/2019 Electronic Data Set, Filename: CLU 14_C B L_2 9A U G 19.1 a s 12/13/2019 Electronic File: CLU14_CBL 29AUG19.pdf 12/13/2019 Electronic File: CLU14_CBL_29AUG19_img.tif 2190780 CANNERY LOOP UNIT 14 LOG HEADERS 2190780 CANNERY LOOP UNIT 14 LOG HEADERS 12/13/2019 Electronic File: Hilcorp_CLU 14_Run1_GRCorrelationt_L04Up_0 6Aug19.dlis 12/13/2019 Electronic File: Hilcorp_CLU 14_Runl _G RCorrelation2_L08Up_0 6Aug19.dlis 12/13/2019 Electronic File: Hilcorp_CLU 14_Run 1 _Sta002_06Aug 19.dIis 12/13/2019 Electronic File: Hilcorp_CLU 14_Run1_Sta003_06Aug19.dlis 12/13/2019 Electronic File: Hilcorp_CLU 14_Run1_Sta004_06Aug19.dlis 12/13/2019 Electronic File: Hilcorp_CLU14_Run1_CoreReport_06Aug19_FIN AL.pdf 12/13/2019 Electronic Data Set, Filename: Hilcorp_CLU 14_Run2_Main_15Aug 19.las AOGCC — - - - Page 6 of 8 - — - Friday, January 31, 20201 DATA SUBMITTAL COMPLIANCE REPORT 1/31/2020 Permit to Drill 2190780 Well Name/No. CANNERY LOOP UNIT 14 Operator Hilcorp Alaska LLC API No. 50-133-20684-00-00 MD 9802 TVD 8043 Completion Date 8/21/2019 Completion Status 1 -GAS Current Status 1 -GAS UIC No ED C 31666 Digital Data 9344 9804 12/13/2019 Electronic Data Set, Filename: Hilcorp_CLU14_Run2_Repeat _15Aug19.las ED C 31686 Digital Data 12/13/2019 Electronic File: Hilcorp_CLU 14_ Run2_Main_15Aug 19.dlis ED C 31686 Digital Data 12/13/2019 Electronic File: Hilcorp_CLU 14_Run2_Repeat_15Aug 19.dlis ED C 31686 Digital Data 12/13/2019 Electronic File: Hilcorp_CLU 14_Run2_Caliper_15Aug19_FINAL. Pdf ED C 31686 Digital Data 12/13/2019 Electronic File: Hilcorp_CLU 14_Run2_SonicScanner_l5Aug 19_ FINAL.Pdf Log 31686 Log Header Scans 0 0 2190780 CANNERY LOOP UNIT 14 LOG HEADERS Well Cores/Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments INFORMATION RECEIVED Completion Report GY Production Test Informatiolp/ NA Geologic Markers/Tops OY COMPLIANCE HISTORY Completion Date: 8/21/2019 Release Date: 7/19/2019 Description Directional / Inclination Data 0 Mechanical Integrity Test Information Y / NA Daily Operations Summary YO Date Comments Mud Logs, Image Files, Digital Datab NA Composite Logs, Image, Data FilesOY Cuttings Samples Y, Core Chips Y /® Core Photographs Y / 10 Laboratory Analyses Y / O AOGCC Page 7 of 8 Friday, January 31, 2020 DATA SUBMITTAL COMPLIANCE REPORT 1/31/2020 Permit to Drill 2190780 Well Name/No. CANNERY LOOP UNIT 14 Operator Hilcorp Alaska LLC MD 9802 TVD 8043 Completion Date 8/21/2019 Completion Status 1 -GAS Current Status 1 -GAS Comments: Compliance Reviewed By: r API No. 50-133-20684-00-00 UIC No Date: 117 I I 7�0 ZD AOGCC Page 8 of 8 Friday, January 31, 2020 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION GAS WELL OPEN FLOW POTENTIAL TEST REPORT 1a. Test: LZJ Initial Annual U Special ib. Type Te sC Stabilized Non Stabilized Lj Multipoint Constant Time ❑ Isochronal Q Other: Nodal 2. Operator Name: 5. Date Completed: 11. Permit to Drill Number: Hllcorp Alaska, LLC 9/24/2019 219-078 3. Address: 6. Date TD Reached: 12. API Number: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 August 13, 2019 50- 133-20684-00-00 4a. Location of Well (Governmental Section): 7. KB Elevation above MSL (feet): 13. Well Name and Number: Surface: 232' FSL, 275' FEL, Sec 7, T5N, R11 W, SM, AK 38.4' CLU 14 Top of Productive Horizon: S. Plug Back Depth(MD+TVD): 14. Field/Pool(s): 1501' FSL, 1 800'FEL, Sec 8, T5N, RI 1W, SM, AK 9,669 MD / 7,903' TVD Cannery Loop Unit I Total Depth: Beluga Gas Pool 9. Total Depth (MD + TVD): 1950' FSL, 1966' FEL, Sec 8, T5N, RI 1W, SM, AK 9,802' MD / 8,043' TVD 4b. Location of Well (State Base Plane Coordinates NAD 27): 10. Land Use Permit: 15, Property Designation: Surface: x- 272696 y- 2388581 Zone- 4 NIA FEE ADI -60569, ADI -60568, ADL324602 TNI: x- 276483 y- 2389870 Zone- 4 16. Type of Completion (Describe): Total Depth: x- 276323 y- 2390323 Zone- 4 4-1/2" Production String, Perforated 17. Casing Size Weight per foot, Ib. I.D. in inches Set at ft. 19. Perforations: From To 4-1/2" 12.6 3.958 9,800 8,028-8,042 8,058-8,078 18. Tubing Size Weight per foot, Ib. I.D. in inches Set a18. 8,565-8,577 4-1/2" 12.6 3.98 5,381 20. Packer set at ft: 21. GOR cllbbl: 22. API Liquid Hydrocardbons: 23, Specific Gravity Flowing Fluid (G): 2,821 24a. Producing through: 241h. Reservoir Temp: 24c. Reservoir Pressure: 24d. Barometric Pressure (Pa): ❑ Tubing ❑✓ Casing 113 F° 1872 psia Q Datum 6,600 NDSS psia 25. Length of Flow Channel (L): Vertical Depth (H): Gg: % CO': % Ni: % HiS: Prover: Meter Run: Taps: 0.06 0 0 26. FLOW DATA TUBING DATA CASING DATA Prover Choke Pressure Diff. Temp. Pressure Temp. Pressure Temp. Duration of Flow No. Line X Orifice psig Hw F° psig F° psig F° Hr. Size (in.) Size (in.) 1. x 2. X 3. x 4. x 5. x Basic Coefficient Flow Temp. Pressure Gravity Factor Super Comp. Rale of Flow No. (24 -Hour) h Factor Pm Fg Factor Or Mcfd Fb or Fp Ft Fpv 1. 2. 3. 4. 5. for Separator for Flowing No. Temperature Pr Tr z Gas Fluid T Gg G 1. 2. 3. Critical Pressure 4. Critical Temperature 5, Form 10-421 Rev. 7/2009 CONTINUED ON REVERSE SIDE Submit in Duplicate Pc Pc' Pf Pf No. Pt p Tp Pw s Ps Pse Pf2_ z 1. 2. 3. 4. 5. 25. AOF (Mcfd) 1,544 n Remarks: CLU -14 is flowing from the MB -818A& L84 sands. The IPR curves were created using Jones & Multi -rate C & N, each with the same resulting AOF. Test data from 1/28/2020 was used for matching the data. Due to water influx/production, we are unable to Conduct a'3 - point' multi -rate test - as choking back the well may cause It to load up. The reservoir pressure [I872psi), is from a PBU test taken on 10/4/2019. I hereby certifyKattl e for g i g is true and correct to the best of my knowledge. Engineer Date,//� Signed Title Reservoir DEFINITIONS OF SYMBOLS AOF Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producin face were reduced to zero psia Fb Basic orifice factor Mcfd/Phi/ m Fp Basic critical flow prover or positive choke factor Mcfd/psia Fg Specific gravity factor, dimensionless Fpv Super compressibility factor= 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 Recommended procedures for tests and calculations may be found in the Manual of Back- Pressure Testing of Gas Wells, Interstate Oil Compact Commission, Oklahoma City, Oklahoma. Form 10-421 Revised 7/2009 Side 2 0:\Alaska\Fields\Cannery Loop\Wells\CLU 14\PROSPER\CLU-14_Prosper_01-28-2020_AOF-Analysis.Out Page 1 ######################################## # INFLOW PERFORMANCE DATA (GAS WELL) # ######################################## Reservoir Model MultiRate C and n Reservoir Pressure 1871.67 (psig) Reservoir Temperature 110.00 (deg F) Water -Gas Ratio 11.00 (STB/MMscf) Condensate Gas Ratio 0 (STB/MMscf) Absolute Open Flow (AOF) 1.544 (MMscf/day) Gas Rate Pressure (MMscf/day) (psig) 1.540 100.00 ++++++++++++++++++++++++++++++++++++++++++++++++++++++ + MULTIRATE TEST DATA AND DERIVED MODEL PARAMETERS + ++++++++++++++++++++++++++++++++++++++++++++++++++++++ C 0.015373 (Mscf/day/psi2) n 0.76352 O:\Alaska\Fields\Cannery Loop\Wells\CLU 14\PROSPER\CLU-14_Prosper_01-28-2020 AOF-Analysis.Out Page 2 +++++++++++++++++++++ + IPR -TEST DATA + +++++++++++++++++++++ Gas Pressure Date Comment Rate (FBHP) Status (MMscf/day) (psig) 0:\Alaska\Fields\Cannery Loop\Wells\CLU 14\PROSPER\CLU-14_Prosper_01-28-2020_AOF-Analysis.Out ######################################## # INFLOW PERFORMANCE DATA (GAS WELL) # ######################################## Reservoir Model Jones M&G Skin Model Enter Skin By Hand Reservoir Pressure 1871.50 (psig) Reservoir Temperature 110.00 (deg F) Water -Gas Ratio 11.00 (STB/MMscf) Condensate Gas Ratio 0 (STB/MMscf) Absolute Open Flow (AOF) 1.546 (MMscf/day) Reservoir Permeability 4.15 (md) Reservoir Thickness 40.0 (feet) Drainage Area 120.0 (acres) Dietz Shape Factor 30.4 Wellbore Radius 0.35 (feet) Perforation Interval 40.00 (feet) Calculated Non -Darcy Coefficent (Beta) 4217743360 Page 1 0:\Alaska\Fields\Cannery Loop\Wells\CLU 14\PROSPER\CLU-14_Prosper_01-28-2020_AOF-Analysis.Out Page 2 ++++++++++++++++++++++++++++++++++++++ + MECHANICALIGEOMETRICAL SKIN DATA + ++++++++++++++++++++++++++++++++++++++ Skin 30 0:\Alaska\Fields\Cannery Loop\Wells\CLU 14\PROSPER\CLU-14_Prosper_01-28-2020_AOF-Analysis.Out Page 3 +++++++++++++++++++++++++++++ + IPR Calculation Results + +++++++++++++++++++++++++++++ dP dP dP Sand Sand dP dP dP dP Total Total Completion Completion Control Control Perforation Damage Penetration Deviation Perforation Damage Rate Pressure Temperature Skin Skin Skin Skin Skin Skin Skin Skin Skin Skin Skin Skin (MMscf/day) (psig) (deg F) (psi) (psi) (psi) (psi) (psi) (psi) (psi) le -5 1871.67 110.00 0 0 0 0 0 0 0 0 0 0 0.081288 1851.62 109.65 0 0 0 0 0 0 0 0 0 0 0.16257 1821.56 109.12 0 0 0 0 0 0 0 0 0 0 0.24384 1785.63 108.49 0 0 0 0 0 0 0 0 0 0 0.32512 1744.86 107.76 0 0 0 0 0 0 0 0 0 0 0.4064 1699.68 106.94 0 0 0 0 0 0 0 0 0 0 0.48768 1650.26 106.03 0 0 0 0 0 0 0 0 0 0 0.56896 1596.57 105.03 0 0 0 0 0 0 0 0 0 0 0.65023 1538.46 103.92 0 0 0 0 0 0 0 0 0 0 0.73151 1475.65 102.70 0 0 0 0 0 0 0 0 0 0 0.81279 1407.72 101.35 0 0 0 0 0 0 0 0 0 0 0.89407 1334.07 99.84 0 0 0 0 0 0 0 0 0 0 0.97534 1253.86 98.15 0 0 0 0 0 0 0 0 0 0 1.057 1165.90 96.23 0 0 0 0 0 0 0 0 0 0 1.138 1068.44 94.00 0 0 0 0 0 0 0 0 0 0 1.219 958.76 90.26 0 0 0 0 0 0 0 0 0 0 1.300 832.26 82.91 0 0 0 0 0 0 0 0 0 0 1.382 679.97 73.52 0 0 0 0 0 0 0 0 0 0 1.463 478.73 60.28 0 0 0 0 0 0 0 0 0 0 1.544 1.32 31.14 0 0 0 0 0 0 0 0 0 0 Penetration Deviation Rate Skin Skin (MMscf/day) le -5 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0:\Alaska\Fields\Cannery Loop\Wells\CLU 14\PROSPER\CLU-14_Prosper_01-28-2020_AOF-Analysis.Out Page 4 0.081288 0 0 0.16257 0 0 0.24384 0 0 0.32512 0 0 0.4064 0 0 0.48768 0 0 0.56896 0 0 0.65023 0 0 0.73151 0 0 0.81279 0 0 0.89407 0 0 0.97534 0 0 1.057 0 0 1.138 0 0 1.219 0 0 1.300 0 0 1.382 0 0 1.463 0 0 1.544 0 0 Total Skin : 0 ( = Entered + Perforation + Damage + Deviation + Partial Penetration ) Completion Skin : 0 (= 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) : +++++++++++++++++++ + End of Report + +++++++++++++++++++ [2— IPR-Calc:ResuBs-Pressor 2-41-- IPR-Calc:Resulls Temperaaxe 2 ■ IPR-Calc:Data-TestPresswe 2 ■ IPR-Wk:Dab-Pressure ....__•.............................................................................+-........................._........_._......._.... 110 1.850 ____ •_ •... ............. .----------------------------•------------------'--- 108 ........................................................ 1,800 106 1,750 104 1,700 ...................................... ....................................•--------•----------------------------------------------------- 102 1,650----------------------------------------•••------•--------------------- --- ------------ --------------------------------------------------- 100 1,600 98 1,550 96 1,500 ------------------------------------------------------ ---------- ......................... ..-_......... _--------------------------------------- 94 1,450...... ................................ ................ ................ .....................................---------------------------------4.92 90 1,400 BB 1,350 1,300 1 ..................................................................................... ....................... ......................... 86 1,250----_-••------------------------------•---------•-•------------------------ _..._..____......._..... .B 1,200 so 1,150 1,100 .............................................................................................j...................__.._............._._.__...... 76 1.050 n 74 a 1,000 j 72 'm m 950 am ...............................................•__•__.._......___.......__................_.._....................---............-.- 70 900 68_ 850•••------------------------------------------------------------------------------------------------------------------------------------- 66 r 800 \\\ 64 v 750- ---------------------------------------------------------------------------------------------------------------------------- --------y........ 62 700 0 60 650 ----------- --------- --------- ------------------ _----------------------- -................................ 0.0 ...................... ......L...__. 58 600 56 550.................. .---------------------- .................. ........................................... .......... 0 ......... 0........... ---1..... 54 500 52 450------ ------------- ----------------- •-.--__.-.------ .___........... ___._------ _------- ____.. 50 48 400 ` __...._.--••---------------•------•------....4_.. 46 350-------------------------------------------------------------- ................................. 1 � 300 42 250 ------------------ -------------- --------------------------- -------------------- -------------- w..._.._......--••----""•-•--------------_----- 4-• 200 40 ......................................i.....___.....___......____...____.......__....._ _ 36 ----------------- 150 MuItlR� POM[ 1 100 34 0 Q 1 Rate (MMscf/day) O:\Alaska\Fields\Cannery Loop\Wells\CLU 14\PROSPER\CLU-14_Prosper_01-28-2020_AOF-Analysis.Out Page 1 ........................................ I..... SYSTEM SENSITIVITY ANALYSIS - Input Data . Top Node Pressure : 75.00 (psig) Water Gas Ratio : 2.00 (STB/MMscf) Condensate Gas Ratio : 0 (STB/MMscf) Surface Equipment Correlation : Hydro -2P Vertical Lift Correlation : Petroleum Experts 2 Solution Node : Bottom Node Rate Method : Automatic - Linear Left -Hand Intersection : DisAllow PE5 Stability Flag : No O:\Alaska\Fields\Cannery Loop\Wells\CLU 14\PROSPER\CLU-14_Prosper_01-28-2020_AOF-Analysis.Out Page 2 ########################################### # SYSTEM SENSITIVITY ANALYSIS - Results # ########################################### dP First Gas Water VLP IPR Total dP dP dP Completion Total WeIlHead WeIlHead Node dP dP Rate Rate Pressure Pressure Skin Perforation Damage Completion Skin Skin Pressure Temperature Temperature Friction Gravity (MMscf/day) (STB/day) (psig) (psig) (psi) (psi) (psi) (psi) (psig) (deg F) (deg F) (psi) (psi) 0.0015443 0.0030886 2949.12 1871.56 0 0 0 0 0 0 75.00 32.00 32.00 9.1421e-7 2874.12 0.082676 0.16535 1768.35 1851.17 0 0 0 0 0 0 75.00 32.12 32.12 0.29766 1693.06 0.16381 0.32762 797.99 1821.06 0 0 0 0 0 0 75.00 32.23 32.23 1.04 721.94 0.24494 0.48988 647.20 1785.11 0 0 0 0 0 0 75.00 32.34 32.34 0.94335 571.26 0.32607 0.65214 547.42 1744.36 0 0 0 0 0 0 75.00 32.46 32.46 1.14 471.28 0.4072 0.81441 475.69 1699.22 0 0 0 0 0 0 75.00 32.57 32.57 1.43 399.26 0.48834 0.97667 421.52 1649.85 0 0 0 0 0 0 75.00 32.68 32.68 1.79 344.73 0.56947 1.1 379.21 1596.22 0 0 0 0 0 0 75.00 32.79 32.79 2.21 302.00 0.6506 1.3 345.36 1538.19 0 0 0 0 0 0 75.00 32.91 32.91 2.68 267.68 0.73173 1.5 317.77 1475.48 0 0 0 0 0 0 75.00 33.02 33.02 3.19 239.57 0.81286 1.6 294.95 1407.66 0 0 0 0 0 0 75.00 33.13 33.13 3.76 216.19 0.89399 1.8 275.86 1334.14 0 0 0 0 0 0 75.00 33.25 33.25 4.38 196.48 0.97513 2.0 259.73 1254.09 0 0 0 0 0 0 75.00 33.36 33.36 5.04 179.69 1.056 2.1 246.01 1166.32 0 0 0 0 0 0 75.00 33.47 33.47 5.75 165.26 1.137 2.3 234.25 1069.09 0 0 0 0 0 0 75.00 33.59 33.59 6.51 152.75 1.219 2.4 224.13 959.71 0 0 0 0 0 0 75.00 33.70 33.70 7.31 141.83 1.300 2.6 215.38 833.63 0 0 0 0 0 0 75.00 33.81 33.81 8.15 132.23 1.381 2.8 189.87 681.97 0 0 0 0 0 0 75.00 33.92 33.92 13.72 101.15 1.462 2.9 178.79 482.02 0 0 0 0 0 0 75.00 34.04 34.04 18.60 85.18 1.543 3.1 170.74 48.33 0 0 0 0 0 0 75.00 34.15 34.15 23.94 71.79 Total Maximum Maximum Maximum PE5 Erosional Maximum Turner Gas NoSiip Erosional C Grain Erosion Corrosion Stability Velocity Turner Velocity Rate Velocity Velocity Factor Diameter Rate Rate Flag Flag Velocity Flag (MMscf/day) (ft/sec) (ft/sec) (inches) (0.001 inches/year) (0.001 inches/year) (ft/sec) 0:\Alaska\Fields\Cannery Loop\Wells\CLU 14\PROSPER\CLU-14_Prosper_01-28-2020_AOF-Analysis.Out 0.0015443 0.020962 608.814 0.013772 0.0001 No 25.379 No 29.450 Yes Yes 0.082676 1.499 704.406 0.85107 0.0001 No 29.980 Yes 0.16381 3.075 716.865 1.71607 0.00058442 No 30.267 Yes 0.24494 4.686 723.608 2.59016 0.0016257 No 30.455 Yes 0.32607 6.314 728.012 3.46909 0.0034185 No 30.589 Yes 0.4072 7.953 731.170 4.35104 0.0061419 No 30.691 Yes 0.48834 9.601 733.565 5.23505 0.0099867 No 30.778 Yes 0.56947 11.258 735.618 6.12188 0.015083 No 30.842 Yes 0.6506 12.915 737.121 7.00835 0.021582 No 30.895 Yes 0.73173 14.575 738.368 7.89565 0.029638 No 30.940 Yes 0.81286 16.237 739.422 8.78361 0.039311 No 30.978 Yes 0.89399 17.901 740.325 9.6721 0.050754 No 31.012 Yes 0.97513 19.567 741.107 10.561 0.063997 No 31.041 Yes 1.056 21.234 741.791 11.4503 0.079102 No 31.066 Yes 1.137 22.902 742.394 12.3398 0.096099 No 31.089 Yes 1.219 24.572 742.929 13.2295 0.11502 No 31.110 Yes 1.300 26.241 743.407 14.1195 0.13589 No 31.270 Yes 1.381 28.225 747.118 15.1113 0.19454 No 31.263 Yes 1.462 29.871 746.964 15.9959 0.24422 No 31.258 Yes 1.543 31.519 746.855 16.8812 0.29664 Page 3 0:\Alaska\Fields\Cannery Loop\Wells\CLU 14\PROSPER\CLU-14_Prosper_01-28-2020_AOF-Analysis.Out .................... . Solution Point Gas Rate : 1.520 (MMscf/day) Oil Rate : 0 (STB/day) Water Rate : 3.0 (STB/day) Liquid Rate : 3.0 (STB/day) Solution Node Pressure : 173.06 (prig) dP Friction : 22.40 (psi) dP Gravity : 75.64 (psi) dP Total Skin : 0 (psi) dP Perforation : 0 (psi) dP Damage: 0 (psi) dP Completion : 0 (psi) Completion Skin : 0 Total Skin : 0 Wellhead Liquid Density : 62.448 (Ib/ft3) Wellhead Gas Density : 0.2805 (Ib/ft3) Wellhead Liquid Viscosity : 1.7744 (centipoise) Wellhead Gas Viscosity : 0.010602 (centipoise) Wellhead Superficial Liquid Velocity : 0.0022868 (ft/sec) Wellhead Superficial Gas Velocity : 31.236 (ft/sec) Wellhead Z Factor : 0.98428 Wellhead Interfacial Tension : 70.6617 (dyne/cm) Wellhead Pressure : 75.00 (psig) Wellhead Temperature : 34.12 (deg F) First Node Liquid Density : 62.448 (Ib/f:3) First Node Gas Density : 0.2805 (Ib/ft3) First Node Liquid Viscosity : 1.7744 (centipoise) First Node Gas Viscosity : 0.010602 (centipoise) First Node Superficial Liquid Velocity : 0.0022868 (ft/sec) First Node Superficial Gas Velocity : 31.236 (ft/sec) First Node Z Factor : 0.98428 First Node Interfacial Tension : 70.6617 (dyne/cm) First Node Pressure : 75.00 (psig) First Node Temperature : 34.12 (deg F) Page 4 0:\Alaska\Fields\Cannery Loop\Wells\CLU 14\PROSPER\CLU-14_Prosper_01-28-20Z0_AOF Analysis.Out Page 5 +++++++++++++++++++ + End of Report + +++++++++++++++++++ STATE OF ALASKA ALAbr✓A OIL AND GAS CONSERVATION COMMIaSION REPORT OF SUNDRY WELL OPERATIONS ,��:: M JAN 15 2320 1. Operations Abandon LJ Plug Perforations U Fracture Stimulate LJ Pull Tubing Li Operations shutdown LJ ❑❑ Performed: Suspend ❑ Perforate ❑✓ Other Stimulate ❑ Alter Casing ❑ Change Approved Program Plug for Redrill Elerforate New Pool E3 Repair Well El Re-enterSusp Well ❑ Other: 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska, LLC Development ❑✓ Stratigraphic❑ Exploratory ❑ Service ❑ 219-078 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, 6. API Number: AK 99503 50-133-20684-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL60569, ADI -60568, ADL 324602, Fee Private Cannery Loop Unit (CLU) 14 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Cannery Loop / Sterling Undefined Gas Pool, Beluga Gas Pool 11. Present Well Condition Summary: Total Depth measured 9,802 feet Plugs measured N/A feet true vertical 8,043 feet Junk measured 9,659 (fish) feet Effective Depth measured 9,659 feet Packer measured 2,821 feet true vertical 7,903 feet true vertical 2,272 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 120' 16" 120' 120' Surface 3,333' 10-3/4" 3,333' 2,616' 3,580psi 2,090psi Intermediate 6,824' 7-5/8" 6,824' 5,183' 6,890psi 4,790psi Production 4,435' 4-1/2" 9,800' 8,041' 8,430psi 7,500psi Liner Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth) 4-1/2" 12.6# / L80 5,381' MD 3,986' TVD Swell Pkr; 2,821' MD 2,234' TVD Packers and SSSV (type, measured and true vertical depth) SSSV-Halli TRSV-NE 527' MD 527' TVD 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13 Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation:1 0 2226 0 46 328 Subsequent to operation:1 0 1811 0 0 88 14. Attachments (required per 20 AAC 25.070, 25.071, a 25.283) 15. Well Class after work: ❑✓ Exploratory[] Development ❑✓ Service ❑ Stratigraphic ❑ Daily Report of Well Operations 16. Well Status after work: Oil Gas L✓j WDSPL LJ Copies of Logs and Surveys Run ❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 319-523 Authorized Name: Bo York 777-8345 Contact Name: Ted Kramer Authorized Title: Operations Manager vbrrtact Email: tkramer(dhilcoro.com Authorized Signature: - Date: mac".. 1cLJ Contact Phone: 777-8420 Form 10-404 Revi4ed4/2017 o,�. /•z-zE, 3gpMS JAN 16 2020 Submit Original Only Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date CLU -14 Completion E -Line 50-133-20684-00-00 1 219-078 11/25/19 11/25/19 Daily Operations. 11/25/2019 - Monday Spot Equipment. PTW and JSA. Rig up lubricator and PT to 250 psi low and 3000 psi high. RIH w/GPT tool and 2.75" GR and tag at 9391'. Found fluid level at 8600'. Run correlation log and send to town. RIH w/2.75" x12' Razor HC, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Ran a revised correlation log that picked up RA marker at 8770'. We didn't go that deep the first log because the line wt was pretty high for that depth. Sent that revised correlation log to town. Got ok to pert the LB -6 zone from 8642' to 8654', Spotted and fired gun with well flowing 1.647 million at 82 psi. After 5 min - 1.284 million at 67.5 psi. 10 min - 764K at 61.6 psi. 15 min -1.532 million at 125.7 psi and at 20 min - 2.024 million at 109 psi. POOH. All shots fired. Gun was wet. Rig down lubricator and equipment. Turn well back over to field. At 1615 hrs well flowing 1.845 million at 84.1 psi. n Iilwm Alaska, LLC RPB. MSL =38.4' TD=9,802'(MD)/ 8,043' (TVD) PBTD=9,659' (MD) / 7,903' (TVD) SCHEMATIC CASING DETAIL Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 Size Type Wt/ Grade/ Conn ID Top Btm 36" Conductor 109/X-56/Weld iS" Surf 120' 10-3/4" Surface 45.5/1.40/TXPSTC 9.950" Surf 3,333' 7-S/8" Intermediate 29.7 / L-80 / W563 6.875" Surf 6,824' 4-1/2" Production 12.6/L-80/TXP BTC 3.958" 5,365' 9,800' TUBING DETAIL Size Type Wt/Grade/Conn ID Top Stm 4-1/2" Tubing12.6/L80/IBT 7-5/8" Swell Packer 3.98" Surf 5,381' JEWELRY DETAIL No Depth Item 1 527' SSSV 2 2,821' 7-5/8" Swell Packer 3 5,365' 7-5/8" X 4-1/2" Liner Hanger OPEN HOLE / CEMENT DETAIL 10-3/4" 329 BBVs of cement in 13.5" Hole 219 BBVs of cement in 9-7/8" Hole 148 BBL's of cement in 6.3/4" Hole PERFORATION DETAII Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status AB -8/8A 8,028' 8,042' 6,336' 6,350' 14' 9/18/2019 Open AS -8/8A 8,058' 8,078' 6,366' 6,384' 20' 9/18/2019 Open B-4 8,565' 8,577' 6,852' 6,863' 12' 9/13/2019 Oen B-6 8,642' 8,654' 6,926' 6,937' 12' 11/25/2019 Open Fish: CIBP milled and pushed to bottom @ 9,659' MD (09/11/19) Updated by PMW 01-10-20 DATE 12/12/2019 De A Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 CLU 14 (219-078) HALLIBURTON CDi: 31684 CLU14 CBL29AUG19 CLU14_CBL -29AUG19 CLU14 CBL 29AUG19_img 219078 RECEIVED DEC 13 2019 AOGCC SCHLUMBERGER CD 2: MSCT-GR o Hilcorp CLU14-Runt CoreReport_06Aug19 FINALS 3 1 6 8 5 r Hilcorp CLU14-Run2_Caliper_15Aug19_FINAL L+ Hilcorp CLU14 Runt SonicScanner_15Aug19_FINAL 3 16 86 Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Cannery Loop Field, Sterling Undefined Gas Pool, CLU 14 Permit to Drill Number: 219-078 Sundry Number: 319-523 Dear Mr. York: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 w .aogcc.olaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, r Price Chair DATED this Aky of November, 2019. 3BML4!' NOV 18 2019 SCANNED NOV 2 5 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 2n AAC 95 280 RECEIVED NOV 13 2019 AOGCC 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate 0 • Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Nitrogen Q 2. Operator Name: 4. Current Well Class: 5. Pennit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development 0 • Stratigraphic ❑ Service ❑ 219-078 ' 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-133-20684-00-00 . 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 231 , ❑ Q Cannery Loop Unit (CLU) 14 Will planned perforations require a spacing exception? Yes No 9. Property Designation (Lease Number): 10. Field/Pool(s): _ ADL60569, ADI -60568, ADL 324602, Fee Private Cannery Loop / Sterling Undefined Gas Pool, Beluga Gas Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 9,802' 8,515' 9,642' 7,886' -2,341 psi N/A N/A Casing Length Size MD TVD Buret Collapse Structural Conductor 120' 16" 120' 120' Surface 3,300' 10-3/4" 3,300' 2,598' 5,210psi 2,480psi Intermediate 6,732' 7-5/8" 6,732' 5,104' 6,890psi 4,790psi Production 4,242' 4-1/2" 9,802' 8,515' 8,430psi 7,500psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic N/A N/A N/A Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Swell Pkr; SSSV-Halliburton TRSV-NE 2,800' MD/2,261TVD; 527' MDTVD 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: November 25, 2019 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑✓ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Bo York 777-8345 Contact Name: Christina Twogood Authorized Title: Operations Manager Contact Email: ctwolgood0hilcorp.corn Contact Phone: 777-8443 Authorized Signature: Date: - %� comfidlissioN USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ---r o Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: IBDMS -L�-'NOV 18 2019 Post Initial Injection MIT Req'd? Yes [-]No ❑ Spacing Ex%tionRequired? Yes ❑ NoSubsequent Form Required: (, "- 'y(3H APPROVED BYApprovetl 1' �-' COMMISSIONER THE COMMISSION Date: v IJ b0 ( /j js -11 n D I Submit Form and 4o3 R vised 4 2017 Approved application is vol r of approval. / �� f!tlachments it Duplicate 0 Hileorp Alaska, M Well Prognosis Well: CLU #14 Date: 11-12-2019 Well Name: CLU #14 API Number: 50-133-20684-00-00 Current Status: Producing Gas Well Leg: N/A Estimated Start Date: November 25`^, 2019 Rig: N/A Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 219-078 First Call Engineer: Christina Twogood (907) 777-8443 (0) (907) 378-7323 (C) Second Call Engineer: I Ted Kramer (907) 777-8420 (0) (985) 867-0665 (C) AFE Number: Maximum Expected BHP: —3,035 psi @ 6,946' TVD (Based on normal gradient of 0.43 psi/ft and the lowest perforation) Max. Potential Surface Pressure: —2,341 psi @ 6,946' TVD (Based on expected BHP and gas gradient to surface (0.10 psi/ft)) Brief Well Summary CLU #14 is a grass roots development well that was drilled and completed in August 2019 targeting gas sands in the Beluga and Sterling formation. The purpose of this work/sundry is to perforate to the Lower Beluga LB -6 Sand. Notes Regarding Wellbore Condition L --z=,- / Soy / • Slickline tag and make gauge ring run prior to starting work. CIL sfVr -T- sr9w '� Safety Concerns 10 1S'#7 • Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. • Considertank placement based on wind direction and current weather forecast (venting Nitrogen during this job) • Ensure all crews are aware of stop work authority E -Line Procedure 1. MIRU E -Line and pressure control equipment. PT lubricator to 250 psi Low / 3,000 psi High. 2. RIH with GPT tool and find fluid level. If fluid level is over the depth to shoot the new perfs, discuss using Nitrogen with the Operations Engineer. Discuss fluid level with Operations Engineer before proceeding to compare to previous fluid level. 3. If needed, RU Nitrogen Truck and pressure up on well to push water back into formation. Use GPT tool to confirm fluid level is below interval to pert. 4. RU perfguns. 5. RIH and perforate the following intervals: zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt LB -6 +8,642' +8,654' +6,934' +6,946' 12' Well Prognosis Well: CLU #14 Date: 11-12-2019 a. Well will be shot flowing. b. Proposed perfs also shown on the proposed schematic in red font. c. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. d. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. e. Use Gamma/CCL to correlate. f. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. g. These sands are governed by Conservation Order 231. 6. POOH. 7. RD E -Line. 8. Turn well over to production. (Test SSV with -in 5 days of stable production on well —notify AOGCC 24hrs before testing) E -line Procedure (Contingency): 1. if zone produces sand and/or water or needs to be isolated., 2. MIRU E -line, PT lubricator to 250 psi Low / 3,000 psi High. 3. RIH and set 4-1/2" CIBP at depth above zone. Or 4. RIH and set 4-1/2" Casing Patch across the zone. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Standard Well Procedure — N2 Operations 0 corp Alaska, LLC RIB: M3=38.4' TD =9,802' (NA) / 8,0=3' (TVD) PBTD=9,669' (M[)) / 7,903' (TVD) jCHEMATIC CASING DETAIL Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 Size Type Wt/Grade/Conn ID Top Btm 16" Conductor 1D9/X-56/Weld 15" Surf 120' 10-3/4" Surface 45.5 /L-80 / TXP BTC 9.950" Surf 3,333' 7-5/8" Intermediate 29.7/L -80/W563 6.875" 1 Surf 6,824' 4.1/2" Production 12.6 / L-80 / TXP BTC 3.958" 5,365' 9,800' TUBING DETAIL Size Type I Wt/Grade/Conn I ID I Top I Btm 4-1/2" Tubing 12.6/1.80/1117 1 3.98" 1 Surf 1 5,381' JEWELRY DETAIL No Depth Item 1 527' SSSV 2 2,821' 7-5/8" Swell Packer 3 5,365' 7-5/8" X 4-1/2" Liner Hanger PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(ND) 8tm(ND) Amt Date Status MB -8/8A 8,028' 8,042' 6,336' 6,349' 14' 9/18/2019 Open MB-818A 1 8,058' 8,078 6,365' 6,384' 20' 9/18/2019 Open LB -4 1 8,565' 8,577' 6,851' 6,863' 12' 1 9/13/2019 1 Open OPEN HOLE / CEMENT DETAIL 10.3/4" 329 BBL's oT cement in 13.5" Hole 7-5/8" 219 BBL's of cement in 9-7/8" Hole 4-1/2" 1 148 BBL's of cement in 63/4" Hole Updated by CMT 11-12-19 0 1lflcoru Alaska. [,LC RKB: M5L=38.4' PROPOSED SCHEMATIC CASING DETAIL Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 Size Type Wt/Grade/Conn ID I Top Btm 16" Conductor 109/X-56/Weld 15" Surf 120' �r. Surface 45.5/L-80/TXP BTC 9.950" Surf 3,333' 7-5/8" Intermediate 29.7/L -80/W563 6.875" Surf 6,824' 4-1/2" Production 12.6 / L-80 / TXP BTC 3.958" 1 5,365' i 2 9/13/2019 Open LB -6 8,642' 8,654' n. .ti 6,945' 12' Proposed Proposed 113/4' 4R 31 ti• ' 7-5/8 n�aa. nese. PROPOSED SCHEMATIC CASING DETAIL Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 Size Type Wt/Grade/Conn ID I Top Btm 16" Conductor 109/X-56/Weld 15" Surf 120' 10-3/4" Surface 45.5/L-80/TXP BTC 9.950" Surf 3,333' 7-5/8" Intermediate 29.7/L -80/W563 6.875" Surf 6,824' 4-1/2" Production 12.6 / L-80 / TXP BTC 3.958" 1 5,365' 9,800' TUBING DETAIL Size Type Wt/Grade/Conn 10 Top Btm 4-1/2" Tubing 12.6/L80/IBT 3.98" Surf 5,381' JEWELRY DETAIL No Depth Item 1 527' SSSV 2 2,821' 7-5/8" Swell Packer 3 5,365' 7-5/8" X 4-1/2" Liner Hanger PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) Amt Date Status MB -8/8A 81028' 8,042' 6,336' 6,349' 14' 9/18/2019 Open MB -8/8A 8,058' 8,078' 6,365' 6,384' 20' 9/18/2019 Open LB -4 8,565' 8,577' 6,851' 6,863' 12 9/13/2019 Open LB -6 8,642' 8,654' 6,934' 6,945' 12' Proposed Proposed OPEN HOLE / CEMENT DETAIL 10-3/4" 329 BBL'S of cement in 13.5" Hole ¢112" 7-5/8" 219 BBL's of cement in 9-7/8" Hole 1 t 1 4-1/2" 1 146 BBL's of cement in 6-3/4" Hole TD=9,802'(MD)/8,043' (TVD) PBTD =9,669' (MD) / 7,903' (ND) Updated by CMT 11-12-19 STANDARD WELL PROCEDURE ❑ilcurp Alaska. LIX NITROGEN OPERATIONS 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/CO2/02 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 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. 12/08/2015 FINALv1 Page 1 of 1 STATE OF ALASKA ' Al ASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a. Well Status: Oil ❑ Gas R] . SPLUG ❑ Other ❑ Abandoned ❑ Suspended 20AAc 25.105 20AAC 25.110 GINJ ❑ WINJ ❑ WAG[-] WDSPL ❑ No. of Completions: _I 1b. Well Class: Development Exploratory ❑ Service ❑ Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Date Comp., Susp., or Aband.: Qj Z(/ZpJq 14.13 ril Drill Number / Sundry. 219-078)319-372, 319-404, 319-417 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: July 27, 2019 15. bar: 50-133-20684-00-00 4a. Location of Well (Governmental Section): Surface: 232' FSL, 275' FEL, Sec 7, T5N, R11 W, SM, AK Top of Productive Interval: 1501' FSL, 1800' FEL, Sec 8, T5N, R71 W, SM, AK Total Depth: 1950' FSL, 1966' FEL, Sec 8, T5N, R11 W, SM, AK 8. Date TD Reached: August 13, 2019 16. Well Name and Number: CLU 14 9. Ref Elevations: KB: 38.4' • .GL: 20.4' BF:20.4' 17. Field / Pool(s): Cannery Loop Unit Beluga Gas Pool 10. Plug Back -Depth MD/TVD: - 9,669' MD / 7,903' TVD 18. Property Designation: FEE ADL60569, ADL60568, ADL324602 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 272696 y- 2388681 ' Zone- 4 - TPI: x- 276483 y- 2389870 Zone- 4 Total Depth: x- 276323 y- 2390323 Zone- 4 11. Total Depth MDITVD: ' 9,802' MD / 8,043' TVD - 19. DNR Approval Number: LOCI 78-156 12. SSSV Depth MD/TVD: 527' MD / 527' TVD 20. Thickness of Permafrost MDIfVD: N/A 5. Directional or Inclination Survey: Yes LJJ (attached) No Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: N/A (ft MSL) 21. Re-drill/Lateral Top Window MID/TVD: N/A 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary / � % ' Qle �, ROP DGR ADR CTN ALD ABG MD / ALD DGR ADR CTN ABG TVD, Mud Logs, HES CBL 8-29-19, Pollard CBLs B-9-191@E8.25-19,yS�Lg5 .Soncanner, XPT OCT 21 2019 23. CASING, LINER AND CEMENTING RECORD T. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING WGRADE FT TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 16" 109# X-56 Surface 138' Surface 138' Driven Driven 10-3/4" 45.5# L-80 Surface 3,333' Surface 2,616' 13-1/2" L - 640 sx / T - 270 sx 92 bbls 7-5/8" 29.7# L-80 Surface 6,824' Surface 5,182' 9-7/8" L - 400 sx / T - 260 sx 4-1/2" 12.6# L-80 5,365' 9,800' 3,975' 8,041' 6-3/4" L - 287 sx / T - 85 sx 24. Open to production or injection? Yes ❑v . No ❑ If Yes, list each interval open (Ml of Top and Bottom; Perforation Size and Number; Date Perfd): **Please see attached schematic for perforation detail** COMPLETION D Z Za�1 VElRIF .— —4L11 - GSA _i—PRODUCTION 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 4-1/2" 5,381' 5,372' MD / 3,980' TVD Liner Top Packer 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes No Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. TEST Date First Production: 9/14/2019 Method of Operation (Flowing, gas lift, etc.): Flowing Date of Test: 9/24/2019 Hours Tested: 24 Production for Test Period Oil -Bbl: 0 Gas -MCF: 4303 - Water -Bbl: 0 Choke Size: N/A Gas -Oil Ratio: N/A Flow Tubing Press. 1145 Casing Press: 0 Calculated 24 -Hour Rate -.* Oil -Bbl: 0 Gas -MCF: 4303 Water -Bbl: 0 Oil Gravity - API (corr): N/A Form 10407 Revised 512017 Zr 7C�CTINUED ON�A�GF� RgDMSI&OCT 2 2 20195,® ORIGINALon�y� �/ .? / A l� 28. CORE DATA Conventional Core(s): Yes ❑ No Q Sidewall Cores: Yes Q No ❑ If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. Will submit full analysis upon completion. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑� If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top N/A N/A Attach separate pages to this form, if needed, and submit detailed test Permafrost - Base Top of Productive Interval MB -8/8A 8,028' 6,335' information, including reports, per 20 AAC 25.071. ST Al 4,027' 3,079' ST Bt 5,740' 4,242' STC 6,527' 4,904' UBX 6,788' 5,149' UB P 7,480' 5,807' MB 8 8,007' 6,316' MB 8A 8,057' 6,364' LB 4 8,537' 6,825' Formation at total depth: Tyonek 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Reports. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Monty Myers Contact Name: Cody Dinger Authorized Title: Drilling Manager Contact Email: Cdin er hilc .C011l Contact Phone: 777-8389 Authorized Signature: Date: I• Z I 2 C INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 1 a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1b: Well Class - Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 19: Reportthe Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY -123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination suryey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10-407 Revised 5/2017 Submit ORIGINAL Only aB�ro Akelca. u.c RKM M5L-3&4' i%A Mil }4 ularar, 3W q � 4-1/2- IM -%P l 0 o:J TD -9,8V (MDI / 8,043' (VD) PB1D=9,669' (MD) / 7,903' (TVD) Cannery Loop SCHEMATIC Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 • CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm 4-1/2" 16" Conductor 109/X-56/Weld 15" Surf 120' 14' 10-3/4" Surtace 45.5 /L-80 /TXP BTC 9.950" Surf 3,333' 6,384' 7-5/8" Intermediate 29.7 / L-80 / W563 6.875" Surf 6,824' i 4-1/2" Production 12.6 / L-80 / TXP BTC 3.958" 5,365' 9,800' TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 4-1/2" Tubing 12.6/1.80/I11T 3,98" Surf 5,381' JEWELRY DETAIL No Depth Item 1 527' SSSV 2 2,821' 7-5/8" Swell Packer 3 5,365' 7-5/8" X 4-1/2" Liner Hanger PFRFr1RATInN nFTAII Zone Top(MD) Btm(MD) Top(TVD) Stm(TVD) Amt Date Status MB -8/8A 8,028' 8,042' 6,336' 6,349' 14' 9/18/2019 Open MB -8/8A 8,058' 8,078' 6,365' 6,384' 20' 9/18/2019 Open LB -4 8,565' 8,577' 6,851' 6,863' 12' 9/13/2019 Open OPEN HOLE / CEMENT DETAIL 30-3/4" 329 BBL's of cement in 13.5" Hole 7-5/8" 219 BBL's of cement in 9-7/8" Hole 4-1/2" 1 148 BBL's of cement in 6-3/4" Hole Updated by CID 10-1-19 U Well Name: CLU 014 Field: Cannery Loop Unit County/State: KPB, Alaska (LAT/LONG): ovation (RKB): API #: 50-133-20684-00-00 Spud Date: 712 712 01 9 Job Name: 1912716D CLU 14 Drilling Contractor HEC 169 AFE #: Hilcorp Energy Company Composite Report rrcy Activity Date 7/23/2019 Loaded and transported doghouse/water tank, both pump skids, all three pit modules, boiler skid, gen 1-2 skid, topdrive HPU skid to cannery loop. Spotted cranes and removed derrick from carrier, removed carrier from sub, removed sub from pony walls. Loaded and transported carrier, pony walls;sub base and cranes to cannery loop pad from KGF. At Cannery Loop pad, set pony walls on well 14, spotted cranes and set sub base on pony walls, set carrier on sub, set doghouse and gen 1-2 skids, transported gen 3, set derrick on carrier, set iron roughneck, raised dog house, set topdrive HPU,;raised windwalls on derrick board, set all three pit modules, transported catwalk, set both pump skids, set boiler skid, set centrifuge on it's stand, transported service shacks.;Conlinue hooking up interconnects electric, air, mud and hydraulic, raise ph rook, prep and raise derrick and pin to floor, set generator #3 had production do line locate to drive ground rods, prep diverter assembly, prep derrick to be scoped;N/U diverter assembly, continue powering up the rig and hooking up interconnects, hook up degasser, spot 3rd party support modules, continue to prep derrick to scope; Hauled 0 bbis solids to KGF G&I Cumulative Solids 0 bbls Hauled 0 bbis Fluid to KGF G&I Cumulative Fluid 0 bbis Daily Losses down Hole 0 bbls Cumulative Losses Down Hole 0 bbls Daily Metal 0lbs Cumulative Metal 0 lbs 7/24/2019 Set bulk fuel tank, cont NU diverter, cont prep to scope derrick, RD office trailers and transport from KGF to Cannery Loop pad, spot and set up trailers, scoped up derrick, Handy Berm on loc berming around rig, cont working on comm's, cont transporting misc equipment and mud product from KGF to ourlocation. Set catwalk, RU lower torque tube in derrick, leveled derrick, set upright water tank, set cement silo, set poorboy degasser skid, install vent pipe on degasser vessel, replace oil pan gasket on #1 pump motor, PU topdrive and secured to blocks.;Finished installing top drive, hooked up hydraulics and service loop then function tested, function test knife valve, not opening, break off diverter line, clean up valve until function freely, take on water to pits function test equipment, R/U floor handling equipment, function test iron roughneck„Welding on shaker #1 cracks in shaker bed, drove ground rods f/ generators and office trailers, install diverter vent line, continue unloading trailers, build mud dock, take on water to pits function test pumps and PVT system, change out degasser vacuum pump, dress pumps w/ 5.5” liners/swabs.;Hauled 0 bbis solids to KGF G&I Cumulative Solids 0 bbls Hauled 0 bbis Fluid to KGF G&I Cumulative Fluid 0 bbls Daily Losses down Hole 0 bbis Cumulative Losses Down Hole 0 bbis Daily Metal 0lbs 7/25/2019 Cumulative Metal 0lb Cont installing diverter vent line, cont installing new oil pan gasket and oil pan on pump #1 engine, offload water from pits (used to function test equipment), attended spud meeting with rig team, service Reps, Drilling Engineer, Reservoir Engineer and Geologist. Swaco Rep removed shipping blocks;from centrifuge, greased same and checked rotation. Dressed shakers with 120'5, started transporting spud mud from G&I to rig, installed short mousehole, checked pulsation dampeners, Peak shipped out big crane and empty floats, filled boiler with water and fired up same, brought in DP and HWDP,;offloaded and staged BHA tools, RU gas trap and umbilical, cleaned and organized location. Installed 14" ID wear ring. Gave AOGCC and Total Safety 24 hour notice for diverter function test.;P/U and Stand Back DP 37 stands, Tag bottom 128' f/ rig floor, continue organizing yard and moving remaining equipment f/ KGF.;Test Mud Lines, pump through pop offs, Finish rig acceptance check list, peak transporting pipe f/ other location, perform PM on Draworks and catwalk, Function Knife valve.;P/U 12 jts of DP 17 jts of HWDP and Jars Rack back in derrick.;Hauled 0 bbis solids to KGF G&I Cumulative Solids 0 bbls Hauled 90 bbis Fluid to KGF G&I Cumulative Fluid 90 bbis Daily Losses down Hole 0 bbls Cumulative Losses Down Hole 0 bbis Daily Metal 0lbs Cumulative Metal 0lbs 7/26/2019 Checked topdrive torque, flooded mudlines, stand pipe and topdrive, tested same at 2350 psi, closed annular on jnt 4 1/2" DP, topped off with water and set 30 min to ensure bag holding (OK). Total Safety installed gas detection equipment and calibrated sensors, added oil to #1 pump engine and test;ran same with no issues. Received 10 3/4" surface casing, offloaded and racked same. AOGCC Rep on location at 10:00 to witness diverter function test.;Measured diverter vent line, measured to closest ignition source, placed connex and empty 40 yard dumpster in front of east fence to buffer fence and road as per AOGCC Rep, tested PVT's and gas alarms, had a fail/pass on one 1-12s sensor antenna, replaced antenna and passed. Had fail pass on knife;valve opening time of 30 seconds. Tied knife valve into choke HCR koomey lines and placed remote diverter into auto mode (knife valve opens when annular closes), knife valve opening at 2 seconds in this mode. Performed draw down test. AOGGC Rep satisfied with diverter function test.;Accepted rig at 12:00 him on 7-26-19.;AOGCC now requiring us to contact North Pacific Seafood cannery and City of Kenai to alert them of possible road closure if rig goes on diverter. Notified HSE Rep John Coston and Production Foreman Chad Johnson who then spoke with North Pacific Seafoods cannery manager about direction of diverter.;vent line and obtained contact info in case of road closure due to rig diverting gas or wellbore fluids. Drilling Environmental Compliance notified City of Kenai of direction of diverter vent line in case of city owned road closure due to rig diverting gas or wellbore fluid.;Rig received approval to spud well from Hilcorp Drilling Manager at 15:10 on 7-26- 19.;Staged bit and motor on catwalk and PU same. Flooded conductor with spud mud and had leak at diverter "T" to knife valve connection. Tightened flange, drained stack below "T" and functioned knife valve with no issue. Flooded stack and had no leaks. MU 131/2" Kymera bit jetted with 6 x 13's, scribed;motor with an RFO of 142.8 degrees. We were then informed by Drilling manager to stand down on spudding well until further notice, while Drilling Manager attempts to satisfy AOGCC further requirement's (IE: notification matrix, evacuation plan for 140 cannery employees, step by step procedure for;for notifications and method of road closure should CLU #14 go on diverter, description to AOGCC, North Pacific Seafoods, and other residents of the access road for eliminating ignition sources in the event of a methane cloud displacing to their place of business).;Stand by with bit parked at 110', while waiting on approval to spud, staged large "Rig on Divertet" sign at cannery road/beach access road/cannery loop pad #1 intersection, with contact info (IE: spill notification hotline number, rig office number, Drilling Manager and Drilling Environmental;Specialist numbers). Wait on AOGCC and Kenai Borough to Approve drilling plan and emergency action plan.;Decision made to change diverter orientation while waking on stale approval, receive diverter pieces from KGF, and Cifo, break down diverter and install 22° elbows in diverter line to make it parallel with the road to the east side of the pad rather than intersecting it.; Hauled 0 bbls solids to KGF G&I Cumulative Solids 0 bbis Hauled 0 bbls Fluid to KGF G&I Cumulative Fluid 90 bbls Daily Losses down Hole 0 bbis Cumulative Losses Down Hole 0 bbis Daily Metal 0lbs Cumulative Metal 0 lbs 7/27/2019 Cont bolting up diverter vent line sections and armored elbow. Received 640 sx 12# lead cement in Halliburton silo. AOGCC Rep Jeff Jones on location at 10:30 to inspect vent line reconfiguration (now turns to the north toward open marsh and trees, no roads in line of fire).;Obtained measurements, function tested annular and knife valve, topped off top of annular with water and set 30 min, annular held water. Received verbal approval from AOGCC Rep Jeff Jones to spud well at 11:15 on 7-27-19. Notified Drilling Manager and received approval to spud well from him.;Spudded CLU-14 at 128' at 11:30. Drilled from 128'to 332', wob 500 lbs to 1 K, 453 gpm-817 psi, 55 rpm-2500 ft/lbs on bott torque, 80 to 160 ft/hr ROP, MW 8.8 ppg. At 332' CBU one time.;Pulled up hole on elevators from 332' to 112' and PU 6 3/4" NM flex DC's, up wt 28K off bottom. TIH on elevators to 329', dwn wt 27K just off bottom. MU topdrive and filled pipe.;Cont drilling 13 1/2" surface hole from 332' to 549', wob 2-5K, 450 gpm-1010 psi, 12 to 92 psi diff, 200 to 600 ft/hr ROP sliding, MW 9.0 ppg/vis 290. Started kicking off at 332' md, building to 48° and azmuth of 78" by 1602' md. Started running centrifuge at 332'.;Cont drilling 13 1/2" hole from 549 to 1354' 5-12k WOB 425 gpm 1120 psi 55 PRM 4500 tq on 2500 tq off 9.1 ppg MW Sliding to build angle 3050' per stand Distance to plan 5.75' 5.74' high .41' Ieft.;Short trip f/ 1354' tt 360' No Hole issues observed PUW 44k SOW 40K.;Service rig and top drive, Check oil in floor motor.;RIH f/ 360' U 1354' No hole issues Observed, Kelly up and wash last stand to bottom 17.5 bbls calc disp 15.3 bbls act disp.;Drill 13 1/2" Hole f/ 1354't/ 1460'5-8k WOB 425 gpm 1140 psi 50 rpm 5k tq on 3k tq off 9.1ppg mw 39k PUW 34k SOW 36k ROT 100 psi Diff.;Hauled 235 bbis solids to KGF G&I Cumulative Solids 235 bbis Hauled 170 bbls Fluid to KGF G&I Cumulative Fluid 260 bbis Daily Losses down Hole 0 bbls Cumulative Losses Down Hole 0 bbis Daily Metal 0 lbs Cumulative Metal 0lbs 7/28/2019 Cont drillinc 13''A" surface hole from 1460' to 1913', sliding wob 3-12K, 452 gpm-1318 psi, 70 to 154 psi diff, 15 to 255 ft/hr ROP. Rotating wob 4-5K, 455 gpm 1344 psi, 60 rpm-6500 to 7400 ft/lbs on bott torque, 140 fl/hr ROP, MW 9.0/vis 98, BGG 4 units.;Cont drilling 1316." surface hole from 1913' to 2348', sliding wob 1-3K, 535 gpm-1740 psi, 56 to 155 psi diff, 140 to 175 fl/hr ROP. Rotating wob 3-8K, 551 gpm-1861, 70 rpm-6400 to 7100 fulbs on bott torque, 84 to 160 R/hr ROP, MW 9.1/vis 156, BGG 1 unit. Obtained Survey.;Backreamed one stand up hole, racked back. On one pump and started a 20 bbl hi-vis nutplug drill-n slide sweep around, on two pumps with sweep in DP. Rotated and reciprocated alternating stopping points. No increase with sweep to surface. 506 gpm-1693 psi, 50 rpm-4800 ft/lbs off bott torque.;Pulled up hole on elevators from 2285' to 1356' with no issue, S/O to 1418' and parked for rig service.;Serviced rig and topdrive.;TIH on elevators from 1418' to 2230' washing last stand to bottom. PIU 46k SIO 42k.;Cont drilling 13 W' surface hole from 2348' to 2847', Rotating wob 3-8K, 551 gpm-1680psi, 70 rpm-6400 to 9150 ft/lbs on bott torque, 84 to 160 ft/hr ROP,sliding wob 1-3K, 535 gpm-1740 psi, 56 to 155 psi diff, 140 to 175 ft/hr ROP MW 9.1/vis 156, BGG 4 unit.;Hauled 285 bbls solids to KGF G&I Cumulative Solids 520 bbis Hauled 190 bbis Fluid to KGF G&I Cumulative Fluid 450 bbis Daily Losses down Hole 0 bbis Cumulative Losses Down Hole 0 bbls Daily Metal 0lbs Cumulative Metal 0lbs 7/29/2019 Cont drilling 13 1/2" surface hole from 2847' to TD at 3346'. Rol web 7K, 544 gpm-1933 psi, 65 rpm -8820 f albs on boll torque, 100 to 168 ft/hr ROP, MW 9.1/vis 98, BGG 1 unit, max gas 10 units. At 3346' obtained survey then backrsamed one stand up hole and racked that stand back.;On one pump, pumped a 20 bbl hi -vis nutplug condet sweep down drill string, then on two pumps circulated sweep around + an additional bottoms up. Had no increase in cuttings to surface. Rotated ands reciprocated alternating stopping points. 554 gpm-2023 psi, 80 rpm -7250 ft/lbs off bott torque.; Flow check = static, pulled up hole on elevators from 3283' to 306' with no issue. Up wt on bottom 68K.;Serviced rig and topdrive. Appears well is taking 2 bph static Ioss.;TIH on elevators from 306' to 3343' with no issues.;Pump 201bbl hi vis nut plug & condet sweep @ 240 gpm, Circ. hole clean @ 550gpm while rotating and reciprocating drill string @ 70rpm , 1900 psi, 7800 ft/lbs trq, 0% increase in cuttings @ btm up.;Flow check (well static), Pull out of the hole on elevators from 3281't/bha, rack back hwdp & i stand of flex collars, lay down directional bha, grade kymera bib. Roller Cone Grade 1 -1 -WT -A -E -1 -NO -TO. PDC Grade 1-1-WT-A-X-I-CT- TD.;clean & clear rig floor, suck out cellar, Pull wear ring, spot Weatherford casing running equipment.; H auled 281 bbis solids to KGF G&I Cumulative Solids 801 bbis Hauled 404 bbis Fluid to KGF G&I Cumulative Fluid 854 bbis Daily Losses down Hole 0 bbis Cumulative Losses Down Hole 0 bbis Daily Metal 4lbs Cumulative Metal 4 lbs 7/30/2019 Set up rig's backup tongs and fill up line, staged centralizers and casing, held PJSM with Weatherford and rig crew.;MU 10 3/4" shoe track, filled pipe and checked floats (OK) Cont PU single in hole with 45.5* L-80 TXP casing to 1352', getting considerable amounts of fine sand on shakers. Top filling every 3 joints, tripping in slow to reduce pushing mud away. At 1352' Weatherford power unit blowing smoke;out exhaust, MU drive sub/circ swedge and topdrive.;CO power unit while CBU at 139 gpm-44 psi, up wt 68K, dwn wt 40K, lot's of sand on shakers until 700 strokes beyond bottoms up (1368 strokes). Down pump and removed circ swedge.; Resumed PU single in hole with 10 3/4" casing from 1352' to 2886' and set down solid numerous times. Up wt 110K, dwn wt 35K at this point. No issue no sticking when PU on string.;MU circ swedge 20' in the air and MU topdrive. Broke circ at 3.5 bph-80 psi, getting good returns. Reciprocated string staging pump rete up to 175 gpm then 225 gpm, worked string down to 2899'. With this section cleaned up parked at 2897' and swapped to long bails, circ at 139 gpm-0 psi, 25% flow.; Initially a good amount of fine sand on shakers but cleaned up pretty quick. At time of shut down (4910 strokes) shakers were pretty ciean.;Down pump, broke off topdrive and circ swedge, MU swedge in next joint, washed two more joints down with no issue to 2986, then oont PU single in on elevators to last joint down at 3312'. MU landing joint/hanger, RD Weatherford longs, cleared rig floor, MU topdrive on landing jnt and broke;circ at 139 gpm-40 psi. S/O and washed down landing hanger, shoe at 3339. PU 3' and parked string. Up wt 110K, dwn wt 35K. Removed Weatherford false table and slips from rig floor.;Staged pump up to 206 gpm-0 psi -30% flow, BGG 1 unit. Started shipping excess spud mud to G&I, spotted Halliburton cementers. Held PJSM with Halliburton and rig team. Loaded plugs in launcher, shut down pump and broke off topdrive. MU plug launcher and hardline to rig floor.; Halliburton loaded lines with 5 bbis water and checked for leaks. Halliburton pressure tested lines at 500 low 3490 high, good tests. Halliburton pumped 55 bbis 10.5 ppg Spacer at 4 bpm and shut down. Halliburton dropped bottom plug and pumped 272 bible (640 sx) 12 ppg Class A lead cement at 5 bpm followed bv 57 bbis 270 sx 15.8 ppq Class A tail cement at 4 bipm. Halliburton dropped top R!y.1 then displaced with 9.1 ppg Spud Mud at 6 bpm. Slowed to 2 bpm with 20 bbl to go. Did bump the plug 312 bible into displacement (calculated 313 bbis), held 1352 psi (FSP of 675 psi) for 3 minutes, bled;off and floats held. Bled back 2 bbis to truck. Had 55 bbis Spacer returns to surface and 92 bbis lead cement to surface. )Wed LCM to both lead and tail cement at 1/4 ppb. Mix water temp 68 deg. Pumped 50% excess on both lead and tail. Lost 15 bbis during displacement. RecN[`,'tmcated string 1 x per;minute throughout the job. Up wt 120K, dwn wt decreased from 60K to 40K and could not land the hanger (3' shy) 123 bbls into displacement. PU and parked string 6' high as per wellhead Rep. CIP at 02:10 hrs, 7-31-19. RD and released Halliburton while wellhead Rep went after emergency slips.; Left plug launcher on landing joint with valves open, to monitor for any u-tubing.;Start RD diverter vent line and flow line, in prep to lift stack and set emergency slips, hauling off cement, spacer and spud mud. Cont monitoring outlet on plug launcher for any sign of u-tubing.;Hauled 53 bbis solids to KGF G&I Cumulative Solids 854 bbis Hauled 393 bbis Fluid to KGF G&I Cumulative Fluid 1247 bbis Hauled 92 bbl cement to KGF G&I Cumulative 92 bbis Daily Losses down Hole 33 bbis Cumulative Losses Down Hole 69.5 bbls Daily Metal 0 lbs 7/31/2019 Cumulative Metal 4 lbs Removed flow line, 4 way chains, ventline and knife valve from diverter "T", RU bridge cranes to lift stack. Raised diverter stack 14" in prep to install emergency slips. Uad 4 outlets oe conductor and nofinM slight flaw jpg from nnmjlki= Stabbed stack back on wellhead, hotbolted with 4;nuts and installed knife valve on "T". Notified Drilling Manager and Engineer while installing remaining nuts on bolts. Flow increased to 15 bph over 30 min and to 50 bph over another hour while installing flowline, ventline and 4 way chains.;Whh stack secure, flooded with 9.1 spud mud and monitored 30 min, well static. Monitored a total of 4 hours with no change, removed plug launcher. PU ran in conduit string alongside hanger (6' off seat) and tagged fairly firm cement at 57 1/2' down from ria floor. LD conduit string, drained stack;and monitored 30 min. Initial flow = .25 bph, over 30 min = .18 bph of 8.9 ppg water. Flooded stack again up to top of annular and notified/updated Drilling Engineer. Obtained 8 sx quickcrete and staged at cellar, called out wellhead Rep.;Disconnected ventline from knife valve, w line from riser, RU bridge cranes, removed all but 4 nuts from base of stack. Once wellhead Rep arrived, drained stack, vac'd out cellar box, removed last 4 �\ uts and raised stack 14". Monitoring siight;flow from 4" outlet at A4 bph. Found casing coupler to be 2" too low to allow slips to clamp around pipe. Pulled from 80K to 280K and gained a good inch, but still not room enough to get slips in place. Wellhead Rep removed spacer ring from slip assembly reducing height by an inch, cut and removed;ring gasket from wellhead flange, removed studs from OSA dumped 7 sx quickcrete into wellhead and flushed bowl with water (with quickcrete in wellbore had no more flow at all), worked slip assembly around casing and latched with no issue, worked slip assembly down into bowl. SIO on casing and;engaged slips with +I- 95K. Called out welder to out and dress casing stub.;RD diverter ventline and knife valve. Welder made rough cut on 10.75" casing, Continue nippling down diverter stack and DSA.;Welder make final cut and bevel on 10.75" casing (5.25") from top of starter head, Install multibowl, Test neck seals 500psi - 2000psi (pass), Attempt to test void to 500psi , Rig up Peak crane and continue nippling up BOP equipment.;Hauled 16 bbls solids to KGF G&I Cumulative Solids 870 bbls Hauled 349 bbis Fluid to KGF G&I Cumulative Fluid 1596 bbis Hauled 5 bbl cement to KGF G&I Cumulative 97 bbis Daily Losses down Hole 33 bbis Cumulative Losses Down Hole 69.5 bbis Daily Metal 0lbs Cumulative Metal 4 lbs 8/1/2019 MU choke hose to catwalk, kill hose to kill line in mezz. Staged BOP cradle near catwalk, spotted Peak crane, swung BOP stack to cellar entrance and transitioned to bridge cranes. RD released crane. Installed test plug in wellhead, stabbed BOP stack and secured. Installed drip pan, flow Oser;and flow line, MU choke and kill lines on mud cross, chained off stack. Installed cellar grating and cleaned up cellar area.;Swapped to short bails and mechanic serviced topdrive. Flooded stack and surface lines, function tested. Shipped out excess 10 3/4" casing and Weatherford casing equipment. Replaced electrical plug on test pump. Brought in pipe bunks of DP. Shell tested stack, choke line and choke manifold.;LD test jnt and plug, RU on kill line with chart recorder. Pumped 3.33 bbls and tested 10 3/4" surface casing at 2600 psi for 30 min on chart. Good test. Bled off and RD test equipmem.;Replaced IBOP actuator on topdrive. Racked and tallied 4 1/2" DP for PU and rack back.;Pick up and rack back 122 joints of 4.5" DP 30 joints at a time.;Screw in to joint of drill pipe, hang off blocks and TDS, Cut and slip 71' of drill line. Unhang blocks & install weight indicators, zero ton miles on Pason.;Clean and clear rig floor after picking up drill pipe, clean suction and discharge screens in mud pump #1 and #2, check pulsation dampeners on mud pumps, pulsation dampener #1 - 600psi, pulsation dampener #2 - 500psi.;Rig up test equipment and purge air in preparation to test BOP equipment on 4.5" test joint.;Hauled 0 bbls solids to KGF G&I Cumulative Solids 870 bbls Hauled 0 bbls Fluid to KGF G&I Cumulative Fluid 1596 bbls Hauled 0 bbl cement to KGF G&I Cumulative 97 bbls Daily Losses down Hole 0 bbls Cumulative Losses Down Hole 69.5 bbls Daily Metal O lbs /t J (1 - Cumulative Metal 4lbs �} �j 8/2/2019 Installed test plug and test joint flooded stack and surfaceltest lines shell tested stack, choke line and choke manifold in prep for test. Removed 4" ball valves from conductor outlets and capped off outlets. AOGCC Rep Austin McCloud and Total Safety Rep on location at 08:OO.;Tested all BOPE at 250/3500 psi, annular at 25012500 psi, all tests held 5 min each. Tested gas alarms, flow show and gain/loss alarms. Had to replace chart recorder sensor during test #3, no component failures. Inspected rig pump valves and seats, no issues. Offloaded 3 trailers 7 5/8" casing.;Drained stack, removed test plug, installed 10" ID wear ring. Blew down choke manifold and choke line. RD test equipment. Staged BHA components at catwalk, held PJSM with Sperry Reps on PU and handle BHA.;PU 7" motor with 1.5° bend, MU Kymera 9 718" bit jetted with 4x13's and 2x14's, PU float sub, DM, DGR, ILS, ADR, PWD, ALD, CTN and TM collars, MU topdrive.;Plugged in and uploaded MWD tools, shallow pulse tested (OK), loaded sources.;RIH with 6 3/4" NM Flex DC's, PU Swaco Well Commander, XO, HW DP, Jars and HWDP for a total BHA length of 754.35'.;Cont TIH on 4 1/2" DP from 754' to 1675" and filled pipe, cont TIH on DP to 3238'. Tagged cement @ 3238'.;Drill out cement from 3238'to 3245' FC @ 3245', Drill out cement from 3245' to 3333', Shoe @ 3333', Drill cement from 3333' to 3346.;Drill 20' of new hole from 3346' to 3366', GPM-450,WOB -2k, RPM -40, TRQ-9100, SPP-1650psi.;Circulate bottom up prior to displacing well to 9.Oppg 6% KCL, 450 -GPM 35 -RPM.; Displace spud mud from well with 9.Oppg 6% KCL mud, displace well @ 6bpm.;Circulate and condition KCL mud until even 9.Oppg is observed at shakers while rigging up to FIT test.:FIT test to 12.5ppg EMW, Test mud weight is 9.Oppg, test pressure = 478psi, Pump 35gl and bled back 18.75gi.;Circulate and condition mud @ 61bpm while cleaning spud mud from pit #7.;Drill from 3366' to 3390' RPM -40, GPM -470, TRQ-7300, WOB-4K.;Hauled 9bbl solids to KGC G&I Cumulative Solids 879bb[s Hauled 81bbls Fluid to KGF G&I Cumulative Fluid 1677 bbls Hauled 0 bbl cement to KGF G&I Cumulative 97 bbls Daily Losses down Hole 0 bbis Cumulative Losses Down Hole 69.5 bbls Daily Metal O lbs Cumulative Metal 4 lbs - 8/3/2019 Directionally drilled 9 7/8" intermediate hole from 3366'to 3858'. Rot web 2-5K, 472 gpm-1194 psi, 40 rpm -6900 ft/Ibs on bolt torque, 130 to 180 fUhr ROP. Sliding web 3-5K, 468 gpm-1163 psi, 34 psi diff, 150 to 160 R/hr ROP. MW 8.9/vis 43., ECUs at 9.1 ppg. Racked and tallied 7 518" casing.;Cont drilling from 3858' to 4286'. Rot web 3-5K, 475 gpm-1368 psi, 80 rpm -8650 R/Ibs on bott torque, 90 to 160 R/hr ROP. Sliding web 3K, 470 gpm-1247 psi, 137 psi diff, 69 to 125 ft/hr ROP, MW 9.1/vis 44, ECUs at 9.3 ppg, BGG 13 units, max gas 15 units. Pumped sweep at 3977' with no increase.;Cont drilling from 4286to 4348'. Rot web 3K, 500 gpm-1546 psi, 80 rpm -8500 flies on bott torque, 129 R/hr ROP, MW 9.1/vis 40, ECUs at 9.5 ppg, BGG 19 units.;Obtained survey then CBU for wiper trip. 474 gpm-1298 psi, 60 rpm -7900 ft/lbs off bolt torque. No increase in cuttings at bottoms up.;Back ream 1 stand from 4348'to 4286, Wiper trip from 4286' to 3309', P/11 -78k SIO-, No tight spot or overpull was observed on trip.;Grease crown and Top Drive, Service Drawworks, Inspect driveline bolts, Change O -Ring on service loop Iine.;Tdp in the hole from 3356' to 4286, Wash and ream last stand to bottom from 4286' to 4348'.;Drill from 4348' to 4384', Rot web 3-5K, 500 gpm-1600 psi, 80 rpm -8650 ft/lbs on bott torque, 90 to 160 ft/hr ROP. Sliding web 3K, 498 gpm-1669psi, 75 psi diff, 69 to 150 ft/hr ROP, MW 9.251vis 41, ECUs at 9.52 ppg, Pump sweep 500gpm 80rpm while drilling ahead @ 4384'.;Circulate sweep out of the hole while mad passing slide @ 100ft/hr, 500gpm 80rpm (Sweep came back 300stkes late with zero increase in cuttings).;Drill from 4384' to 4973', Rot web 3-5K, 500 gpm-1650 psi, 80 rpm 8650 ft/lbs on bott torque, 90 to 160 fUhr ROP. Sliding web 3K, 500 gpm-1669psi, 75-100 psi diff, 80 to 150 R/hr ROP, MW 9.25/vis 49. ECUs at 9.42ppg.; Hauled 89 bbl solids to KGC G&I Cumulative Solids 968bbls Hauled 656 bbls Fluid to KGF G&I Cumulative Fluid 2333 bbls Hauled 0 bbl cement to KGF G&I Cumulative 97 bbls Daily Losses down Hole 0 bbls Cumulative Losses Down Hole 69.5 bbis Daily Metal 8lbs Cumulative Metal 12 lbs I 8/4/2019 Cont drilling 9 7/8" intermediate hole from 4973' to 5527'. Rot web 6-7K, 498 gpm-1659 psi, 80 rpm -9600 ft/lbs, on bott torque, 25 to 150 R/hr ROP. Sliding web 3 to 6K, 503 gpm-1679 psi, 71 to 160 psi diff, 125 R/hr ROP. MW 9.2/vis 50, ECD's 9.5 ppg, BGG 35 units, max 50 units.;Obtained survey on bottom. CBU 1 time at 497 gpm-1588 psi, 80 rpm -10,600 ft/lbs off bott torque.; Pulled up hole on elevators from 5527' to 4346', up wt 94K, then S/O and parked string at 4410'. No issue pulling up hole.;Serviced rig and topdrive. Flushed centrifuge with water during wiper trip. Changed beacon light bulb in derrick and greased crown.;TIH on elevators from 4410' to 5017' and set down twice. MU topdrive and washed/reamed down 2 stands to 5153' at 450 gpm-1300 psi, 40 rpm with no issue. Cont TIH on elevators to last stand, filled pipe and washed down to 5527'. No more issue tripping on elevators.;Cont drilling from 5527' to 5590'. Sliding web 4K, 496 gpm-1763 psi, 100 psi diff, 100 R/hr ROP. Rotating woe 4K, 502 gpm-1824 psi, 80 rpm -11,100 fulbs on bott torque, 105 Whr ROP. MW 9.2/vis 44, ECD's at 9.5 ppg, BGG 13 unks.;Cont drilling from 5590' to 5963'. Sliding web 6K, 492 gpm-1790 psi, 135psi diff, 118 ft/hr ROP. Rotating wob 4K, 504 gpm-1865 psi, 80 rpm-11,100-13,500ft/lbs on bott torque, 175 ft/hr ROP. MW 9.2/vis 44, ECUs at 9.6 ppg, BGG 51 units.;Cont drilling from 5963'to 6212 '. Sliding web 6K, 483 gpm-1780 psi, 135psi diff, 140 ft/hr ROP. Rotating web 4K, 504 gpm-1865 psi, 80 rpm-11,100-13,500R/ibs on bott torque, 175 R/hr ROP. MW 9.2/vis 44, ECUs at 9.49 ppg, BGG 7 units.;Hauled 202 bbl solids to KGC G&I Cumulative Solids 1170bb1s Hauled 238 bbis Fluid to KGF G&I Cumulative Fluid 2571 bbls Hauled 0 bbl cement to KGF G&I Cumulative 97 bbls Daily Losses down Hole 0 bbls Cumulative Losses Down Hole 69.5 bels Daily Metal 0lbs Cumulative Metal 12 lbs 8/5/2019 Cont directional drilling 9 7/8" hole from 6212' to 6547'. Sliding web 3-4K, 491 gpm-1829 psi, 152 psi diff, 114 to 150 ft/hr ROP. Rot web 5K, 491 gpm-1804 psi, 65 rpm -12,200 ft/lbs on bott torque, 100 to 170 ft/hr ROP. MW 9.2/vis 50, ECUs at 9.5 ppg, BGG 6 units, max gas 17 units.;Cont drilling 9 7/8" hole Rom 654T to TD at 6753' and/5123'tvd. Sliding web 1-3K, 493 gpm-1852 psi, 140 to 218 psi diff, 156 R/hr ROP. Rotating web 5K, 492 gpm-1923 psi, 65 rpm - 12,800 ft/lbs on bott torque, 145 R/hr ROP. MW 9.2/vis 45, ECD's at 9.5 ppg, BGG 85 units, max gas 413 units.;Madd Passed slide interval. After obtaining survey and sending in log's, town requested we go deeper for proper coverage of Cengsa storage sand. Cont drilling another 82'to TO at 6835' md/5200'tvd. Obtained survey and SPR's at 6835. Max gas 627 units.;Cont circulating wellbore clean while waiting on approval of TD depth from town at 496 gpm-1818 psi, 65 RPM -13000 R/Ib off bott torque. Received SLB a -line logging tools and equipment, received rig fuel. MW 9.2/vis 46, ECUs at 9.5 ppg, BGG 65 unks.;Pulled up hole on elevators from 6835' to 3333' with no increase in overpull or drag.;Service rig and top drive and drawworks while circulating bottoms up @ 330gpm spp-680psi.;Trip in the hole from 3333' to 6630', Set down 15k @6630', Wash and ream last 2 stands to btm (6835), Lay down working joint.;Pump hi -vis sweep and circulate bottoms up @400 gpm 60 -rpm 3000-spp 12-13k -trq, No increase of cutting were observed at the shakers.; Flow check well (static), Pump dry job, Install wiper rubber and pull out of the hole on elevators from 6832'to 5000', P/U 117K SIO 61 K.;Hauled 127 bbl solids to KGC G&I Cumulative Solids 1297bbis Hauled 128 bbis Fluid to KGF G&I Cumulative Fluid 2699 bbls Hauled 0 bbl cement to KGF G&I Cumulative 97 bbis Daily Losses down Hole 0 bbls Cumulative Losses Down Hole 69.5 bbls Daily Metal 8 lbs C�J� Cumulative Metal 20 lbs 8/612019 Cont POOH from 5000' to Sperry TM collar, MU XO and topdrive, held PJSM with Sperry and rig crew on source removal.;Pull nuke sources, plugged in and read MWD data, removed topdrive, LD remaining BHA to mudmotor. Fill motor with water and flush/drain same. Removed Kymera bit. Bit graded roller cone side: 1 -1 -WT -A -E -2 -NO -TD / PDC side: 1 -3 -BT -G -X -2 -CT -TD. Hole took 8 bbls over calculated entire trip.;Clean and clear rig floor and catwalk while SLB spotting a -line unit (mounted on long trailer).;RU SLB sheaves and wire, MU MSCT (mechanical sidewall coring tool) tool string and function test. MU core tube and disc tube.;RIH with MSCT on a -line to 6,600', correlated to open hole logs. Obtained samples from 6246' up to 5471'(42 stations), no hole issues while obtaining samples, still losing 1 bbl per/hr to hole, started POOH w/ E -line MSCT tool.;Held PTSM, crew change, finished POOH w/ E -line sidewall coring tool (MSCT), broke down coring tool, discovered we only had cores samples 1-8 & 11-16, due to coring barrel was packed off & jammed up wl loose sand & mud;called town and decision was made to clean up and re -run MSCT tool and obtain remaining core samples.;Finished cleaning & R/U SLB MSCT E -line tool, RIH to recover samples 9 & 10 and 18 through 42, re -correlated to open hole logs, set on depth @ 5930' to obtain sample #9 cont. to monitor well (loss rate 1 bbl per/hr.).;Finished obtaining samples 9 & 10, moved up hole and started working on samples 18 through 42, obtained samples 18-27 and SLB's MSCT tool started jamming up, made decision to POOH to inspect tool, currently POOH w/ MSCT tool,;while logging changed MP liners to 5", checked pulsation dampener pressures, flushed & cleaned centrifuge, changed Biters on rig HPU, adjusted winch on skate, and worked on housek 'ping & painting around the rig.; Hauled 35 bbl solids to KGC G&I Cumulative Solids 1332bb1s Hauled 40 bbls Fluid to KGF G&I Cumulative Fluid 2739 bbls Hauled 0 bbl cement to KGF G&I Cumulative 97 bbls Daily Losses down Hole 0 bbls Cumulative Losses Down Hole 69.5 bbis Daily Metal 0 lbs Cumulative Metal 20 lbs 1 c) 8/712019 Cont POOH with SLB a -line and MSCT tool string, from 5000', after making second run at sidewall cores and experiencing tool issues. At surface recovered 12 more samples for a total of 26 out of 42. Prepped to make third run but a -line crew was shut down by a -line manager due to being timed out.; Notified Drilling Manager. RD released SLB e-Iine.;MU cleanout BHA as follows: 9 7/8" Smith 5 blade PDC (Hilcorp owned), bit sub, XO, IBS, NM flex DC's, HWDP and jars. TIH to 3331' filling pipe at 2487'. Up wt 60K, own wt 40K.;At 3331', just inside surface casing, CBU 1 time at 458 gpm-716 psi. Had a max of 14 units gas. No increase in cuttings to surface at bottoms up.;Cont trip in open hole to 6777' and MU topdrive. Washed last stand down while pumping sweep into drill string. No issues tripping on elevators to bottom.;Went on two pumps and circ at 484 gpm-1248 psi, 80 rpm -11,700 Wiles off bottom torque. Up wt 80K, own wt 60K, rot wt 75K. Had 100% increase in cuttings to surface with sweep, pumped an additional bottoms up until shakers cleaned up. Max gas at bottoms up was 140 units.;Pulled up hole from 6839. MU topdrive and backreamed first three stands up hole due to what appeared to be differential sticking. Pumped next three stands up hole with no rotation. Started pulling on elevators and had no issues F/6406'-T/shoe,;cont. POOH to BHA #3, Calculated displacement for the trip on 4.5 DP=42.3 bbis, Actual displacement --46.1, 3.8 bbls over for the trip. Still seeing a 1 bph loss rate to the hole.;Held PTSM, crew change, cont. POOH racking back HWDP in the derrick, UD remaining of BHA #3, re -run PDC bit grade= 1 -3 -BT -G -X -1 -CT -TD, cleaned & cleared rig floor, removed all BHA components off catwalk while monitoring the well, gave Weatherford casing crew 2 hr. notice,;Drained stack, pulled wear ring w/ test plug & test it., set test plug, removed lest jt., isolated koomey bottles & bled off koomey manifold, opened upper pipe ram doors, removed 4.5" VBR's and installed 7-5/8" hard body rams, closed ram doors & energized koomey.;P/U test jt. & M/U to test plug, filled stack wl water, R/U testing equip, test #1 annular 250 psi Low, 2500 psi High (ok), test #2 upper pipe rams (7-5/8") 250 psi Low 3500 psi High (ok), pulled test plug, RID testing equip at current time.;Hauled 20 bbl solids to KGC G&I Cumulative Solids 1352 bbls Hauled 30 bbls Fluid to KGF G&I Cumulative Fluid 2769 bbls Hauled 0 bbl cement to KGF G&I Cumulative 97 bbis Daily Losses down Hole 24 bbis Cumulative Losses Down Hole 93.5 bbls Daily Metal O Has Cumulative Metal 20 lbs 8/8/2019 Dummy ran hanger, RU Weatherford casing equipment, staged centralizers, held PJSM with Weatherford crew and rig crew.;MU 7 5/8" shoe track, filled pipe and checked float equipment (OK), PU and singled in hole from 85' to 3330' filling on the flY top filling every 5 joints with 7 518" L-80 29 7# Wedge 563 casing.;At 3330', just above surface shoe, MU circ swedge/topdrive and CBU 1 time at 227 gpm-131 psi. Max gas 13 units at bottoms up. Up wt 68K, Own wt 50K.;Cont PU single in hole with 7 5/8" casing from 3330'to 6801'. MU landing joint with wellhead Rep, S/O and tagged 7' of fill. MU circ swedge and / R (/ topdrive, broke circ, at 5 bpm washed down slowly and set down to 50K. Finally broke loose and landed hanger on depth, up wt 138K, dwn wt 70K.;Cont r(' circulating at 249 gpm-332 psi, removed Weatherford equipment from rig floor, removed short bails, installed long bails, staged Halliburton pump truck and bulk •� (� trucks. Max gas at bottoms up = 62 units. Loaded plug in cement head, shut down pumps, broke out drive sub, installed cement head;on landing jt. R/U 0 cement manifold to cement head, rig pump, & cement truck, broke circ. through cement head @ 5 bpm/ 370 psi.;Had PTSM, crew change, held PJSM wl rig crew, Peak, & Halliburton cementers, shut down rig pump, cementers pumped 5 bols of water to flush & load lines, pressure tested lines 914 psi Low 4500 psi High (ok), mixed & pumped 39 bbis of 10.5 ppg spacer iop 4.5 bpm (420 psi shutdown) shut down dropped bottom plug, pumped 159 blots of lead 12 Dog class A cement Cd 5.5 born 400-188 psi), followed by 59 bbls of tail 15.3 Pon class A cement 0 3.5 bpm (173 psi), dropped top plug and displaced w/ 285 bbis of 9.3 ppg 6% KCL PHPA mud @ 6 bpm (139-1000 ps), slowed pump to 2 bpm;and bumped plug @ 305 bbis, held 1793 psi for 3 min (Float held), had FCP of 1080, bled back 2.5 bbis to truck, had .25 ppb of LCM in both lead & tail & pumped 25% excess on both lead & tail, lost during the job. CIP @ 02:45.;Cleaned up & washed cement lines, UD cement head, cement manifold, & hard lines, broke out landing jt. from casing hanger, drained stack, P/U & M/U test it, XO, & pack off setting tool, currently installing intermediate pack off.; Hauled 0 bbl solids to KGC G&I Cumulative Solids 1352 bbis (lam Hauled 0 blots Fluid to KGF G&I Cumulative Fluid 2769 bbls Hauled 0 bbl cement to KGF G&I Cumulative 97 bbls S Daily Losses down Hole 0 bbls`� Cumulative Losses Down Hole 93.5 bbis Daily Metal O lbs Cumulative Metal 20 lbs 8/9/2019 Tested packoff at 500 f/5 min, 5000 f/10 min. During finishing up RILD's on packoff, BOP stack/conductor sunk about 2-3 inches, breaking the weld on cellar box floor to conductor, and resting lower rams on cellar grating. Notified Drilling Manager.;Swapped upper rams back to 2 7/8" x 5" variables, called out D&D welders, sent mechanic after two sheets 3/4" steel at 147 yard. Loaded and shipped Weatherford casing equipment.;Tested upper rams and annular at 250/3500 f/5 min each, good tests. Shipped excess Sperry tools. Swapped topdrive to short bails. Racked and tallied 4 1/2" DP in yard.;Welders cut out floor plates and gussets for cellar box, shipped out excess mud, cleaned pits and took on water for new mud. Replaced pony rod seals on pump #2, pod #3. Welders -re-welded conductor to cellar floor pan, installed 3/4" floor plates and gussets, Pollard a -fine on location at 17:OO,;spotted unit and staged equipment on rig floor. RU Pollard a -line, MU tool string to CBL 7 5/8" casing.;Pollard a -line RIH, welders cont welding out floor plates and gussets, cont mixing mud.;Cont. welding on conductor/cellar (finished up @ 20:30), cont. CBL logs w/ E -line , E -line tagged up @ 6720 WLM, 18' high, cont. mixing 350 batch of 6% KCL PHPA mud, completed PM's on MP 1&2 motors, gear ends, & fluid ends, also DW motor & brake bands, cont. to work on painting hand rails on rig.;POOH w/ E -line CBL logging tools, RID Pollard E -line, sent logs to town (good).;R/U test equip., performed 7-5/8" casing test to 3500 psi for 30 min test on chart (ok), staged BHA #4 tools on catwalk, installed wear ring.;Held PTSM, crew change, UD test jt. & wear ring instillation tool, P/U & WU 6-314" PDC 5 bladed bit, 1.5 degree bend motor, & MWD tools, uploaded MWD tools, performed shallow pulse test, installed sources, P/U & MU rest of BHA #4 at current time.;Hauted 25 bbl solids to KGC G&I Cumulative Solids 1377 bola Hauled 480 bbls Fluid to KGF G&I Cumulative Fluid 3249 bbls Hauled 0 bbl cement to KGF G&I Cumulative 97 bbis Daily Losses down Hole 0 bbls Cumulative Losses Down Hole 161.5 bbis Daily Metal O lbs Cumulative Metal 20 lbs Y21 8/1012019 Ran remainder of HW DP for a total BHA length of 741'. R I H from drillers side of derrick to 2415', PU singled in hole 104 jnts 41%" DP to 5644', cont TIH from off side of derrick to 6724' and tagged cement. MU topdrive and filed pipe.;Drilled cement, wiper plugs, shoe track, ralhole and 20' new formation to 6855'. Rot web 1 K, 215 gpm-1229 psi, 30 rpm -11,900 ft/lbs on bott torque. Once into new formation increased to 3K wob, 252 gpm-1423 psi, 40 rpm -12,000 ft/lbs torque, 90 to 130 ft/hr ROP. Stalled motor 4 or 5 limes;drilling shoe track.;CBU one time at 200 gpm-1004 psi, 30 rpm -12,500 ft/lbs off batt torque. Max gas 64 units at bolt up. Reamed through shoe track numerous times. at bottoms up pulled into casing and parked for FIT. RU test equipment.; Purged air from test hoses and kill line. Pumped 35 gallons and achieved 870 psi pumping down drill string and backside. Held 10 min, pressure bled to 751 psi. Bled back 30 gallons, RD test equipment, blew down test hoses. Achieved a 12.5 EMW with 9.3 ppg MW.; Drilled 6 314" hole from 6855' to 6880', rot web 4-51K, 245 gpm-1516 psi, 40 rpm - 12,900 Wiles on bott torque, 96 to 130 ft/hr ROP, MW 9.2/vis 43, ECD's at 10 ppg, BGG 7 units.;Cont drilling from 688U to 7010', 250 GPM -1541 psi, 60 RPM. TQ -12.5 K, WOB-5K, P/U-120K S/0-50 K, ROT -76K. Slide-6944'to 6965' (mad pass @ 195 fph).; Driller and DD having trouble trying to slide drill. Motor stalling each time bit makes contact with bottom. Pason auto driller/drew-works spools off too much line and spuds bit. Set drill string in slips, shut down floor motor, inspected brake linkage and made some minor adjustments to brake bands,;inspected brake linkage and component's. Appears brake handle driveline spline gear to sub base is worn and good amount of play, might be causing delay in auto driller reaction. May be the cause of spudding bit and stalling of mud motor numerous times, enough to damage mud motor slator.;Seems ok while rotating on bottom, but cannot slide. Notified Drilling Engineer, discussed issues w/ mud motor, decision was made to POOH to inspect bit & motor for damage.; Held PTSM, crew change, CBU & started POOH racking back in the derrick F/7010' to BHA #4, racked back HWDP, flex collar, & remove sources, down loaded MWD tools, currently UD MWD tools. Distance to well plan -7.45' 7.4' High .8' left Total bit K -revs 35.10.;Hauled 0 bbl solids to KGC G&I Cumulative Solids 1377 bbis Hauled 45 bbls Fluid to KGF G&I Cumulative Fluid 3294 bbls Hauled 0 bbl cement to KGF G&I Cumulative 97 bbis Daily Losses down Hole 0 bbls Cumulative Losses Down Hole 161.5 bbis Daily Metal 25 Ilea Cumulative Metal 45 lbs 8/11/2019 LD ADR and TM collars, the Drillers side extend arm on topdrive broke at the weld, rectangular tube stock to pad eye connection. Topdrive was extended out about half way to LD tool. Removed broken items, Tool Push retrieved replacement arms from BA yard. Replaced both arms.;Pulled motor and bit to floor, no and play in motor shaft, bit graded a 1 -3 -BT -G -X -1 -CT -PR. LD motor and bit. Hale on trip tank taking .46 bph. Staged new motor and bit on catwalk.;Made an adjustment to brake linkage idler shaft in sub base toward dog house allowing more spline gear coverage, which eliminated pretty much all loose play in brake linkage from doghouse to draw-works.;PU Sperry 4 3/4" motor, adjusted to 1.5° bend, MU Kymera KM322X bit, MU DM and ADR collars, scribed and oriented, RFO = 88.32°, MU GM, ALD and CTN collars, oriented nuke offset, MU PWD and TM collars, shallow pulse tested and loaded sources. RIH remaining BHA to 740'.;TIH from derrick to 6633' filling pipe every 2509. No issues with draw -works brakes. MU topdrive and filled pipe. Up wl 116K, dwn wt 541K.;Blew down topdrive to allow service on mud line pressure sensor, MU on drill string again, hung blocks, cut and slipped 67' of drill line. Calibrated block height and hook load. Completed PM's on crown & blocks.;Exited casing shoe at 6824, filled pipe and washed last stand F/6633' -T/7010', GPM -200 SPP -1030 psi RPM -30 TQ - 12k P/U-124K 51O -601K ROT -75K.; Resumed drilling 6 3/4" hole F/7010' -T/ 7194, mad passing all slides. GPM -250 SPP -1730 psi RPM -60 TQ -13.8K WOB- 5/10 P/U-120K S/O-55K ROT-75K.;Held PTSM, crew change, cont. drilling 6 314" hole F17194' -T/ 7327'. GPM -250 SPP -1870 psi RPM -60 TQ -13.8K WOB- 10 PIU -126K S1OA8K ROT-70K.;Cont. drilling 6 3/4" hole F/7327' -T/ 7436', pumped 20 bbl Hi -Vis sweep w/ walnut & condet, had a 100% increase in cutting, cont. drilling ahead F/7436' to current of depth 7625, max gas 1132 units. GPM -256 SPP -2046 psi RPM -60 TQ -14.5K WOB-7 PIU -126K SIO -50K ROT - 70K.; Distance to well plan=8.47' 8.28' High 1.78' Low K-revs=69.00.;Hauled 0 bbl solids to KGC G&I Cumulative Solids 1377 bbis Hauled 0 bbis Fluid to KGF G&I Cumulative Fluid 3294 bbis Hauled 0 bbl cement to KGF G&I Cumulative 97 bbis Daily Losses down Hole 0 bbis Cumulative Losses Down Hole 161.5 bats Daily Metal 10 Iles Cumulative Metal 55 lbs 8/12/2019 Cont drilling 6 3/4" hole from 7625'to 7996'. Sliding web 5K, 250 gpm-1859 psi, 142 psi diff, 54 to 130 R/hr ROP. Rol web 2-3K, 250 gpm-1826 psi, 60 rpm - 14,700 ft/lbs on bott torque, 122 ft/hr ROP, MW 9.5/vis 45, ECD's at 10.4 ppg, BGG 24 units, max gas 974 units.;Pumped a 20 bbl hi -vis nutplug sweep around at 250 gpm-1760 psi, 65 rpm -14,800 to 16,600 fit/lbs off bott torque. Had 100% increase in cuttings with sweep to surface, cont circ until clean at shakers. Obtained survey and SPR's.;Pulled up hole from 7996' to 7007' on elevators and no issues. Hole in good shape. Up wt 148K, dwn wt 56K at bottom. S/O to 7065' and parked.;Serviced rig and topdrive, checked brake linkages, all OK. Offloaded and racked 131 jnts 4 1/2" liner. Drifted same.;TIH on elevators from 7065'to 7940' wfth no issue. Down wt 50K. MU last stand, filled pipe and washed/reamed to bottom at 7996'.;Resumed drilling 6 3/4" hole from 7996' to 8225'. Rot web 3-10K, 246 gpm-1826 psi, 60 rpm -15,600 ft/lbs on bott torque, 150 ft/hr ROP. Sliding wob 5K, 250 gpm-1930 psi, 287 psi diff, 93 fuhr ROP, MW 9.41vis 46, ECD's at 10.4 ppg, BGG 27 units, max gas 2068 units.;Cont drilling from 8225' to 85591, GPM -260 SPP -2210 psi RPM -60 TQ - 16.5/17.5K P/U-130K SIO -58K ROT -82K , added 1 drum of 776 tube to help w/ the torque, average ROP=59 fph, pumped 20 bbl Hi -vis sweep wl walnut & condet @ 8531', had a 100% increase in cuftings.;Held PTSM, crew change, cont. directional drilling 6-3/4" hole F/85591 -T/8780', GPM -260 SPP -2278 psi RPM -60 TQ -16.5/17K WOB-10113K PIU -1 35K S/0 -58K ROT -84K DIFF-600.;Cont. directional drilling 6-3/4" hole F/8780' to current depth of 8929', GPM -245 SPP -2153 psi RPM -60 TQ -16.5/17K WOB-81K P/U-135K S/0 -581K ROT -84K DIFF -537, added 1/2 drum of 776 tube to reduce TQ.;Distance to well plan -11.5' 7.82' Low 8.45' Right, Max gas 1441 units for the last 12 hrs., average ROP for the last 24 hrs. 54 fph. K-revs=271.; Hauled 45 bbi solids to KGC G&I Cumulative Solids 1469 bbis Hauled 45 bbis Fluid to KGF G&I Cumulative Fluid 3387 bbis Hauled 0 bbl cement to KGF G&I Cumulative 97 bbls Daily Losses down Hole 12 We Cumulative Losses Down Hole 173.5 bbls Daily Metal 6 lbs Cumulative Metal 61 lbs 8/13/2019 Cont drilling 63/4" hole from 8929'to 9054'. 8K wob, 247 gpm-2242 psi, 65 rpm -17,700 ft/lbs on bott torque, 100 ft/hr ROP, MW 9.5/vis 45, ECD's at 10.6 ppg, BGG 23 units, max gas 432 units.;Pumped a 20 bbl hi -vis nutplug sweep around at 258 gpm-1800 psi, 65 rpm -19,700 ff/lbs off bott torque, MW 9.5/vis 45, ECD's at 10.5 ppg, BGG 25 units. 100 % increase in cuttings to surface. Circulated until clean at shakers.; Pulled up hole from 9054' to 7999' on elevators with no issue, hole in good shape, up wt 140 to 146K, parked string at 7999'.;Service rig and topdrive.;R I H from 7999' to 8990' on elevators, Wash Last stand to bottom.;Continue Drilling Ahead f/ 9054't/ 9371'250 gpm 2300 psi 60 rpm 15-19k tq 10-14k WOB Sliding and madd passing every stand t/ 9363' 10.7 ppg ECD 80 units gas avg 10 fph avg ROP.;Continue Drilling Ahead F/ 9371'T/ 9802' TD, GPM -250 SPP -2200/2375 psi RPM -60, TQ -16-191(, WOB-8/13K, P/U-150K S/0 -64K ROT -91K, cont. to add 776 lube to help reduce TQ, max gas 776, pumped 20 bbl Hi -Vis sweep w/ walnut & condet.;Held PTSM, crew change, cont. to circ. sweep around, had 50% increase in cuttings upon return, flow check (ok), performed wiper trip F/9802'- T/6702' (shoe), wl no issues & got correct calculated hole fill during trip.;Serviced rig, inspected drive line bolts & brakes, greased TD, blocks, crown, & brake linkage, flow check (ok), TIH F/6702' -T/9678', washed last std. to bottom @ 9802' (TD), had 40' of fill on bottom, pumped 20 bbl Hi -vis sweep w/ walnut & condet, currently pumping around sweep.;P/U-136K SIO -64K ROT -92K. Got calculate pipe displacement after TIH, Distance to well plan -27.97' 27.7' Low 3.85' Left, average ROP for the last 18 hm. 48.6 fph. , total K -revs on bit --443, max gas 1043 units.;Hauled 45 bbl solids to KGC G&I Cumulative Solids 1514 bible Hauled 45 bbls Fluid to KGF G&I Cumulative Fluid 3432 bbls Hauled 0 bbl cement to KGF G&I Cumulative 97 We Daily Losses down Hole 10 bbis Cumulative Losses Down Hole 183.5 bible Daily Metal 0lbs Cumulative Metal 61 lbs 8/14/2019 Continue circulating HI Vis Sweep around 250 gpm 1950 psi, @ 1800 strokes gas units spiked t/ 5000 units and hole unloaded 200% increase in cuttings, slowed pump rate until manageable on shakers, finished circulationg sweep out of the hole 50% increase in cuttings on bottoms up, shakers cleaned up;after an additional 2000 silks, flow check well static.;POOH on elevators f/ 9802' t/ shoe @ 6810' No hole issues hole took correct fill.;Flow check well static, pump 20 bbl dry job.;POOH f/ 6810't/ 740'.;Stand back and UD BHA, unload sources, download MWD, UD BHA Components break bit graded 1 -1 -CT -G -E -IN -ER -TD, UD Remaining BHA components, clean and clear floor.;R/U SLB E -line unit, held PJSM, hung sheaves, PIU & WU SLB XPT tool while monitoring well, loss rate @ 1.75 bph, RIH w/ SLB XPT tool T/8647' w/ no issues, started acquiring formation pressures from 16 stations F/8647' -T/7028', while logging cleaned radiators on rig.;equip., inspected MP 1 & 2, cleaned suctionidischarge screens and MP suction manifolds, checked & recharged pulsation dampeners, opened and cleaned bowl on centrifuge & greased, inspected shaker beds, greased choke manifold, performed formation pressure test on stations 1-6 F18647'- T/8043'.;Held PTSM. crew change, cont. w/ first run of XPT logs on stations 7-16 F/8025'-7028', finished up first 16 stations of XPT logging, received second run of logging station from geologist (29 stations).;Sent data to geologist, received second run of XPT stations (29), RIH w/ XPT tool T/9267', started logging 29 stations F/9267' -T/6983', current loss rate .5 bbl per/hr. , currently working on station #5 of run 92, while cont. with cleaning, housekeeping & painting while logging.; Hauled 45 bbl solids to KGC G&I Cumulative Solids 1559 bbls Hauled 45 bbls Fluid to KGF G&I Cumulative Fluid 3477 bbls Hauled 0 bbl cement to KGF G&I Cumulative 97 bbls Daily Losses down Hole 12 bbls Cumulative Losses Down Hole 195.5 bbls Daily Metal 4.6 lbs Cumulative Metal 65.6 lbs 8/15/2019 Continue Logging secondary pressure stops w/ XPT logging tool f/ 8765' U 7675' geologist requested more stops, continue logging as per goo and SLB, Hole is in good shape no issues static loss rate .5 bph 16 units of background gas, Rig crews painting and and doing PM's and workorders.;Housekeeping and general maintenance, on rig equipment, changed filter housing on air intake.;Cont. E -line logging w/ XPT tool while cont. to paint hand rails, remove 90's from steam lines in mezzanine, POOH F/7013' w/ SLB XPT tool, finished up wl secondary pressure stops on second run, (69 stations), total stations for both runs were 85 stations F/9267' -T/6983', finished POOH, UD SLB.;XPT tool, monitored hole while PIU & M/U SLB dipole sonic E -line tool, static losses .75 bbls/hr., shallow tested tool (ok), started RIH w/ dipole sonic tool to bottom.;Held PTSM, crew change, cont. RIH to bottom @ 9772' WLM, POOH w/ SLB dipole sonic E -line tool, logging F/9772'to shoe. current static loss rate .5 bph.;Finished logging up to shoe w/ dipole sonic tool, POOH w/ sonic tool, currently UD SLB dipole sonic tool.;Hauled 0 bbl solids to KGC G&I Cumulative Solids 1559 bbls Hauled 0 bbls Fluid to KGF G&I Cumulative Fluid 3477 bbis Hauled 0 bbl cement to KGF G&I Cumulative 97 bbls Daily Losses down Hole 13 bbls Cumulative Losses Down Hole 208.5 bbis 2uDaily Metal 4.6 lbs mul tie Metal 65.61b 8/16/2019 Pull wear ring set test plug , R/U to test BOP's, fill stack and lines, bleed air from lines, shell test stack.;Test BOP'S w/ 4.5" test it U 250/3500 psi f/ 5 min each, test Annular upper lower and blind rams, HCR and Man choke and kill, Auto and Man IBOP, CMV 1-13, Electric and Man Choke, Kill Line demco, TIW and Dart, Perform Accumulator DrawDown test, State Inspector Jim Regg Waived Whness.;Test PVT and pit sensors, Total safety tested gas alarms.;R/D test equipment, Pull test plug set wear ring, Blow down lines, Line up for normal drilling operalions.;M/U Clean Out BHA # 6 RIH w/ BHA out of derrick U 167' Draworks motor Shut down.;Trouble Shoot draworks, lug on battery was burned off, wire shorting out, starter was seized and fried, wait on starter from ware house, replaced starter, restart floor motor.;Continue RIH w/ Clean Out BHA # 6 F/126' -T11248' filled pipe gas & flow started climbing, slowed pump to idle, circulated gas OOH. max gas at BU 4502 units, flow check (ok), cont. RIH F/1248' -T/2490'(20 stds.), filled pipe, gas & flow started climbing again,;slowed pump to idle, had max gas of 4998 units at BU. circulated out gas, flow check (ok), cont. TIH F/2490' -T/3729', filled pipe & CBU, had max gas of 4940 units at BU, circulated out gas, flow check (ok), cont. TIH F/3729'-T/4966'.;Filled pipe & CBU, had max gas of 4678 units at BU, circulated out gas, flow check (ok), cont. TIH F/4966' -T/5594'. P/U-115K S/0-48K.;Held PTSM, crew change, cont. TIH F/5594' -T/6754', filled pipe, gas & flow started climbing again, slowed pump to idle, had max gas of 4998 units at BU. circulated out gas, flow check (ok), pipe displacement for the trip up to this point was 8.7 bbls over calculated.;Cont. TIH F/6754' -T/8040', started to get incorrect pipe , filled pipe & established flow, shut down, flow check, loss rate @ 1 bph., resumed pumping, gas & flow started climbing again, slowed pump to idle, had max gas of 2688 units at BU, circulated out gas,;cont. TIH F/8060' to current depth of 8566', static loss rate= .5 blah, pumping loss rate=l bph.;Hauled 0 bbl solids to KGC G&I Cumulative Solids 1559 bbls Hauled 0 bbls Fluid to KGF G&I Cumulative Fluid 3477 bats Hauled 0 bbl cement to KGF G&I Cumulative 97 bbls Daily Losses down Hole 6.2 bbls .S Cumulative Losses Down Hole 214.7 bbls 1 y i Daily Metal 0 Ibs R L Cumulative Metal 65.6 lbs V 8/17/2019 Continue Running in the hole f/ 8566' t/ 9757' Tag up on fill set 20k down.;Wash and ream to bottom @ 9802' stage pumps t/ 250 gpm 550 psi 50 rpm 19.5k tq Pump Hi Vis sweep around, when sweep came back had a 200 % increase in cuttings and gas spiked t/ 5000 units, circulate until shakers cleaned up and gas dropped back to normal 10450 stks, started adding lube and spotted;on the backside in the open hole, flow check well static.;POOH on elevators H 9802' U shoe @ 6824' , no hole issues, Flow Check Well Static, pump Dry Job.;POOH f/ 6824' U 4788' standing back pipe in derrick.;Sewice rig, fixed leak on iron roughneck & changed out top clamp cylinder, greased & cleaned DW, R/U to UD DP, reversed elevators, R/U vac unit & football stand in mouse hole and staged thread protectom.;POOH UD singles and vacuuming footballs through each jt. F/4850' -T/628' (134 jts. total), L/D 17 jts. of HWDP & jars, broke off XO's & UD same. UD rest of BHA #6, broke rerun PDC bit, bit graded 1 -3 -BT -G -X -I -CT -TD, monitored hole on trip tank, static loss= .5 bph.;Cleared & cleaned rig floor, R/U Weatherford casing equip, held PJSM w/ rig crew, Weatherford & Baker, while working on cleaning phs.;P/U & M/U shoe track, flash lighting & baker locking each jt., filled shoe track w/ mud & checked floats equip. (ok), cont. RIH w/ 4.5" TXP BTC 12.6 ppf L-80 casing F/shoe track -T/494%; Held PTSM, crew change, cont. RIH w/ 4.5" TXP BTC 12.6 ppf L-80 casing & running RA marker its. every 500' from bottom (6 total RA its.), filling on the fly & topping of every 10 jts. w/ mud, F/494' -T/4385', @ 4390' P/U-35K S/0-25K.;Swapped over elevators to 4.5" OF, held PJSM over P/U & M/U hanger, WU HRD-E ZXP liner hanger F/4390' -T14439, mixed & installed pal mix, waiting 30 min for pal mix to set up at current time.;Hauled 20 bbl solids to KGC G&I Cumulative Solids 1579 bbls Hauled 50 bbls Fluid to KGF G&I Cumulative Fluid 3527 bible Hauled 0 bbl cement to KGF G&I Cumulative 97 bbls Daily Losses down Hole 0 bbls Cumulative Losses Down Hole 214.7 bbls Daily Metal 0lbs Cumulative Metal 65.6 Ibis 8/18/2019 P/U XO and stand of DP circulate liner volume 3 bpm 90 psi.;Continue RIH w/ 4.5" Liner as per Detail f/ 4435't/ 6657' hole giving correct displacement.;Circulate bottoms up staging pumps t/ 5 bpm 260 psi, max gas 269 units.;Continue RIH w/ 4.5" Casing as per detail U 6657' V 9796' tag fill 6' off bottom . PUW 92k SOW 48k.;Wash to bottom @ 9802' tag up P/U 2' V 9800' and circulate and condition f/ cement job, stage pumps t/ 5 bpm 530psi pumped 10360 stks Max gas 5000 unks.;R/U cement head as per baker rep, M/U cement lines and manifold spot in cementers and R/U.;Set Liner Hanger as per Baker Rep, drop 1 318 ball and pump to seat CD 2.7 bpm, turn pump off and on as to not slam ball into ball seat, ball on seat @ 1540 stks blow seat 1850 psi calc 1277', drop 15/8" ball and pump U seat @ 2.7 bpm function same ball on seat @ 919 stks blow seat 1744 psi.;PJSM w/ cementers, fill lines 5 bbls H2O and PT U 500 low 4200 high, pump 25 bbls 10 ppa spacer, 125 bbls cement. 23 bbls tail drop wiper dart pump down seen latch at 73.8 bbls continue pumping in plug bumped @ 134bbis FCP 1150 Pressure up V 2550 psi held f/ 5 min, bled off checked floats.;bled back 1 bbl, CIP 2000 hm, wash up Halliburton lines V cuttings tote, Lost all returns @ 124 bbls into displacement calculated 30 bbls lost during cemenLipb.; P/U 6' to dogs out on running tool, set down 44k 1 seen shear on liner top packer, P/U and rotate to confirm set, set down 50k while rotating x2, PIU and pull pack off from liner top Top of liner @ 5372.46.;R/U j L and reverse circulate cement and spacer @ 5 bpm 225 psi, 10.4 ppg spacer and trace cement seen over board 58 bbls to cuttings tank.;Flushed all lines, R/D Halliburton cementing equip., lined up stack/stand pipe, opened bag, flow check (ok), racked back cement head & 1 jt. of 4.5" DP in derrick.;POOH w/ 4.5" DP racking back in derrick F/5305' -T/3628', getting calculated hole fill on trip out. P/U-52K.;Held PTSM, crew change, cont. POOH F/3628' -T/1160', slip & cut 80' of drill line, serviced rig -inspected driveline bolts, brake pads, brake linkage &, kickback rollers, greased- TD, swivel blacks & crown. changed out clutch control on drillers panel, worked on cleaning pit for 3% KCL change over.;Cont. POOH F/1160' to liner hanger running tool, UD running tool, inspected tool for indication of set (ok), broke down Baker cement head & UD, cont. to work on cleaning pits, cleared catwalk of tools.; Drained stack, pulled wear ring, WU test jt. & test plug, set test plug, currently R/U to test 2-7/8" on annular & upper pipe rams, 250 psi Low & 3500 psi High.;Hauled 20 bbl solids to KGC G&I Cumulative Solids 1599 bbls Hauled 330 bbls Fluid to KGF G&I Cumulative Fluid 3847 bbls Hauled 0 bbl cement to KGF G&I Cumulative 97 able Daily Losses down Hole 30 bbls Cumulative Losses Down Hole 244.7 bbls Daily Metal 0lbs Cumulative Metal 65.6 be R/U and Test Upper Rams and Annular w/ 2 7/8" test jt to 250/3500 psi f/ 5 min each.; RID test equipment, R/U and test Casing U 3500 psi f/ 30 min RID Lines.;R/U Weatherford casing tongs and bring all clean out components t/ rig floor, load pipe racks w/ 2 7/8" work string, held PJSM, cont. cleaning pit for displacement.;PW & M/U 4" PDC bit , bit sub, 4.5" Swaco multiback scraper, X2 XO's back to 2-7/8' HT Pac pipe, , cleaning off threads and rabbiting pipe, finished cleaning pits, started building 530 bbls of 3% KCL brine.;Started singling w/ 2-7/8" HT Pac of the walk, cleaning off threads and rabbiting pipe, TIH F/15.37'-T4469, S/0-27K. finished building brine, R/U displacement manifold for pill train, built barakeen & Hi-vis pills & loaded onto trucks, built caustic pill & left in pill pft.;P/U a total of 144 jts of 2-7/8" HT Pac, XO, P/U X2 7-5/8" Swaco multiback scrapers, XO to 4.5" CDS-40 DP, RID Weatherford equip, cont. TIH to top of 4.5 liner @ 5372', eased down through liner top with no issues or bobbles, cont. RIH to top of I.C. 8/0-32K.;Cont. RIH w/ 4.5" DP T/9654, Kelley up, washed down & tagged LC @ 9674', set down 4K to verify tag, CBU X2, GPM-110 SPP-1000 psi, staged pump up to GPM-250 SPP-2180 psi P/U-90K S/0- 58K.;Held PTSM, crew change, cont. to CBU, held PJSM on brine displacement, pumped pill train- 25 bbl caustic pill, 25 bbl Barakleen pill, 25 bbl Hi-vis pill, followed by 3% KCL brine, brine came back after pumping 404 bbls, shut down pumps, cleaned possum belly, under shakers, & ditch to trip tank,;filled pill pit N1 3% KCL brine, R/U vacuum stand in mouse hole, spotted vac truck & run vac line to stand.;Started POOH F/9674', LID singles, vacuuming footballs through pipe & cleaning threads & re-doping, current depth of 6419', cont. to vac out and clean pits. Changing over to completion AFE at 06:00 today.;Hauled 20 bbl solids to KGC G&I Cumulative Solids 1619 bbls Hauled 345 bbls Fluid to KGF G&I Cumulative Fluid 4232 bbls Hauled 0 bbl cement to KGF G&I Cumulative 97 bbls Daily Losses down Hole 30 bbls Cumulative Losses Down Hole 244.7 bbls Dailv Metal 0 lbs Hilcorp Energy Company Composite Report Well Name: CLU 014 Field: Cannery Loop Unit County/State: KPB, Alaska (LAT/LONG): avation (RKB): API #: 50-133-20684-00-00 Spud Date: Job Name: 1912716C CLU 14 Completion Contractor AFE #: 1912716C AFE $: Activity Date _. "WW -5 Ops Sumrnary ,. ,.: k 4�N.,. 8/20/2019 Continue POOH UD DP f/ 6419' it 4537' UD Scrapers begin L/D 2 7/8" Pae Pipe, f/ 4537' t/ Surface Clean and clear floor change over handling equipment, stage tubing on racks, PJSM on running completion, RIH w/ 4.5" IBT Completion as per detail t/4846, Make up SSV with Baker Rep, Hook up control line with Pollard, Test Control line to 5000psi„Continue running 4.5" IBT liner from 4845' to 5394.40' tagged up on no-go, lay down joint 162 and 161, Space out with 10.19' and 4.21' pup joints, space out depth 5381.04 btm of mule shoe 1' off of tag P/U 46k S/O 34k,Circulate surface to surface (3337stks) 3% KCL with F 1`.L� rO� Baracor 100 and Barascav D @ 5bpm, 10-15psi,Land out 4.5" IBT in well head as per Hilcorp Wellhead Rep. Run in lock down screws,Rig up test equipment, Test 4.5" IBT tubing to 3500psi for 30 minutes on chart and test backside to 2500psi for 30 minutes on chart., Terminate control line, Remove XO from landing joint, Break out landing joint from hanger, Install back pressure valve,Rig Down Weatherford Equipment, Bleed pressure off accumulator, 8/21/2019 N/D Flow Line and flow box, and riser, Remove choke and Will lines, Tie on to stack and pick off well.,Clean well head, M/U tree and tighten flanges, fill and test void and seals V 250/ 5000 psi f/ 10 min, pull b v set two and test tree t/ 250/5000 f/ 10 min, remove TWC set BPV secure well head. Release rig @1200 hrs,R/D top drive and rig floor, disconnect pits and pumps start pulling wires for the back yard, disconnect auxiliary shacks, peak hauling shrapnel to gas field and beaver creek, prep derrick to scope down, hoist BOP stack into shipping cradle,Scope down derrick, Un -spool drill line and tie up lines in the derrick, tie up Kelly hose in the derrick, Unhook iron roughneck, Remove exhaust stack off of floor motor, lower degasser,lower pit roofs, lay derrick on headache rack, Pull derrick raising cylinders, Pull Derrick pins, lay over gas buster and remove vent,Rig down catwalk and prep for move, clean out cellar box, unhook misc. electric around the rig, pressure wash derrick and sub, unhook accumulator lines, remove handy berm, rig down total safety alarms, prep for trucks @ 07:OOhrs •t 8/29/2019 PJSM, Rig up Halliburton E -line unit and crane. M/U and test CCL, Gamma, centralizers, and CBL tools. Verify well is bled off and SSSV is open. MIV lubricator to tree., RIH with CCL, Gamma, centralizers, and CBL tools to 9,642Ft and tagged up. Log from 9,642fi to 5,400ft at 60ft/min. POOH from 5,400ft and send logs to town.,R/D Halliburton E -line unit, crane and associated equipment, 9/9/2019 PTW and JSA. Spot, R/U, and inspect equipment. R/U lubricator and associated equipment test to 250psi low 3000psi . Found a leaking O -Ring in the rr lubricator, O -Ring was replaced. Retest lubricator to 250psi low, 3000psi TEST GOOD,Well shut-in with Opal. RIH with Gamma, CCL and Legacy Oil Tools 3.5" OD bridge plug (P/N 000-3500-002). Logged from 8800ft to 8300ft and sent log to Taylor Childers for correlation. Shifted the depth 911 and set bridge plug C at 8605ft. Tagged plug and verified it was set. POOH,UD plug running tools and M/U 3.375"OD, 3Ft perf gun with 6spf 60deg phasing. 18 shots of 22.7gr Geodynamics big hole charges 0.74" hole, 7" penetration (EC2-33A2331). RIH and tag plug at 8605ft. Log up to 81008 and send log to town for correlation -Discuss with town about being overbalanced while perforating. Decision made to not perforate while overbalanced., POOH from 860511. UD 311 loaded gun. Rig down equipment, clean up work area and shut in well for the nklht. 9/10/201p, PTW, JSA with SLB and Cruz., MIRU SLB CTU 13 with 1.75" CT. Lay pit liner. Spot coil unit, Pump truck, Iron rack, lubricator box, choke skid, crane. 4' Move in 2x rain for rent tanks. Load rain for rent tanks with 300 bible of lease water. Rig up 4.06" Combi BOPE.,Start BOPE test. 24 hr BOPE lest witness notification send 919/19 @ 10:37 AM. Witness waived by Jim Regg 9/9/19 @ 4:25 PM. Function test BOPE. Draw down test. Pressure test all rams and valves to 250/4000 psi for 5 minutes. BOPE test passed.,3000 gallons of N2 on order. Call out Yellow Jacket tool had for thru tubing motor and mill for Ifollowina da . SLB fuel equipment. Location walk around complete. SDFN. 9/11/2019 PTW, JSA with SLB coil Cruz Crane operators and Yellow Jacket tool hand. Discuss SIMOPS with Halliburton E -line., Fire equipment. Pick injector head stab 2x 11' lubricators. Dress 1.75" coil. Make up Yellow Jacket tools/MHA . Pull test external slip coil connector to 10k then 25k. Fluid pack reel with 33.8 bbls of lease water. Pressure test MHA to 250/3500 psi.,Continue making up milling BHA. External slip coil connector 2.88" OD x .85', DFCV 2.88" OD x 1.26, TJ Hydraulic Disconnect 2.88" OD x 2.13', CircSub 2.88" OD x 1.20' ( 9/16" Ball seat), 2-7/8" Abaco Motor 2.88 " OD x 12.76', Concave 5 bladed junk mill 3.83" OD x.93' BHA overall length= 19.12'. Stab on well. PT stack 250/4000 psi.,Open upper master and swab 23.5 turns. RIH 0 psi WHP. Open choke for pipe displacement. Drytag CIBP at 8607.2' CTMD. Pickup clean. Online down CT at 1.3 bbls/min 2500 psi free spin.,Attempt to mill CIBP. Stacking weight at 8607.2' No increase in motor work. Stack 5k down. Motor did not stall. Pickup 30'. Increase rate to 1.9 bbls/min 4250 psi Circ pressure. RIH 30 It/min 5k down at 8607.2' Motor would not show an increase in pressure or stall. POOH to surface. ton inspect motor.,Break down 2 7/8" motor. Motor is wore out. Motor can rotate both directions by hand. Swap motors. Install 2.125" OD motor. Stab on well. PT stack 250/4000 psi., RIH . Tag CIBP 8604.9. Pickup. 1.3 bbls/min @ 3200 psi. Start milling CIBP. Hard stall at 8607.4' Picked up and RIH past 8607.4' Chasing remainina plug to S ematic PBTD is 9642'. Tagged PBTD with CT @ 9669 CTMD. Pickup 3' off bottom. Continue circulating remaining bottoms up. Shut down pump and drop 9/16" circ sub ball for N2 blow down. Circulate 33.8 bbls to land ball on seat. Ball did not seat. Pump another 33.8 bbl reel volume. Ball never pressured upon seat to open circ sub., POOH to surface to inspect why circ sub would not open. Total fluid circulated for CIBP milling run 343 bole. Tagged up. Close upper master and swab., Popoff well. Break down Motor. 9/16" ball recovered. Ball was on top of motor. Break down remaining BHA. Set injector head on back deck. Install night cap on BOPE. Inspect Circ sub. 9116" ball will land on seat. Pushed ball with metal rod and it will pass through circ sub seat profile without shearing set screws. Wrong ball size was dropped., all secure. Location walk around complete. SDFN 9/12/2019 PTW, JSA,Pick injector head. Stab 11' lubricator. Make up slim roll on dimple connector, 2x straight joints, ball drop reverse out nozzle. 1.75" BHA x 8.3' long. Pressure lest lubricator 250/4000.,RIH . Cool down N2 pump. @ 2300' CTMD online with N2 down 4.5" production tubing taking returns up coil. 9,650' Park CT. Unloading wellbore 152 bbls returned to surface. N2 at return tank.,POOH to surface. Close choke. 3187 P$I WHP. Shut down N2 pump. 258,000 SCF pumped . 2,770 gallons of N2 pumped. At surface. Bleed down wellhead . 1687 psi SITP.,Rig down CTU 13. 9/13/2019 Spot Equipment. PTW and JSA. Rig up lubricator and HLB didn't have enough grease to PT with Sent man to shop to get e -line grease Took 1-1/2 hrs for that. Pressure test to 250 psi low and 3000 psi high. TP -1620 psi,RIH w/GPT tool and tie into CBL log. Tag at 9659'and FL at 9598'. Run correlation log and sent to town. Was told log was 8' to 10' high same as CBL.,RIH w/2 -7/8"x12' HC Razor, 6 spf,60 deg phase and tie into CBL. Shift log down V. Ran correlation log and send to town. Told was 3' deep so change ped depths to 8565' to 8577' without shifting log. Spotted shot from 8565' to 8577' and fired gun with 1613 psi on tubing. After 5 min - 1618psi, 10 min- 1618.39 psi and 15 min - 1621.8 psi. POOH.,AII shots fired and gun was wet.,Rig down lubricator and turn well over to field. TP -1646.1 911 812 01 9 Sign in. Mobe to location. Rig up Lubricator. PT to 250 psi low and 2500 psi high. TP - 1750 psi,RIH w/GPT and tie into CBL log. Found fluid at 7456' with 1850 psi on well. Call SLB N2 to come out with pump truck. Had approx. 800 to 1000 gals of N2. SLB showed up at 1340 hrs and rig up hard lines. PT to 250 psi low and 4500 psi high. Started pressuring up well at 1000 scf. Pushed fluid from 7456' to 7793' with 3720' psi on tubing and run out of N2. Waited approx. 30 min and found FL at 7920'and 8050' after another,30 min. Another 30 min and was at 8130' with 3984 psi. POOH. Get blow down tank ready.,RIH w/2- 7/8"x2O' HC Razor, 6 spf, 60 deg phase and tie into CBL log. Run correlation log and send to town. Get ok to pert from 8058'to 8078' with 2000 psi on tubing. Spot gun and bleed tubing down to 2025 psi. Fire gun with 2025 psi on tubing. After 5 min - 2050 psi, 10 min - 2055.6 psi and 15 min - 2057 psi. POOH. All shots fired & gun was dry.,RIH w/2 -7/8"x14' HC Razor, 6 spill, 60 deg phase and tie into CBL log. Run correlation log and send to town. Was 4' off with log so change pert depth to 8028' to 8042' with 2068.3 psi on tubing. Spotted and fired gun. After 5 min -2065.5 psi, 10 min - 2064.6 psi and 15 min - 2060.9 psi. POOH. All shots fired and gun was dry.,Rig down lubricator and turn well over to field. 0 NOTE: AKE-Line will probably not get out of there shop until around 2;30 am after cleaning tools and loading up cenen plug. I will check with them and see how they feel about bringing equipment out and rigging up at least tomorrow and getting a fresh star the next day on BCU -18. I don't want to get caught up working late and have the office people work late also. 9/24/2019 PTW, JSA and SIMOPS w/Pollard Slickline. Spot and rig up lubricator. Had to go back to shop and get a cross-over for tool string. Put tool string together. PT to 250 psi low and 3000 psi high.,RIH w/PLT tools and log down to 7950'. Run 40 fpm down log from 7950' to 8620'. Run 80 fpm up and down log from same depth. Run up and down log at 120 fpm. Make 5 min stops below Peds and 10 min above each pert zone.. Run down and tag bottom at 9632'. Looks like middle zone is making the most gas. I sent the PDF log to town. HLB will send LAS etc.,Rig down lubricator and turn the well back over to field. Hilcorp Alaska, LLC Kenai C.I.U. Cannery Loop Unit #1 Pad Cannery Loop Unit 14 501332068400 Sperry Drilling Definitive Survey Report 25 September, 2019 HALLIBURTON Sperry Drilling Companv: Hilcorp Alaska, LLC Project: Kenai C.I.U. Site: Cannery Loop Unit #1 Pad Well: Cannery Loop Unit 14 Wellbore: Cannery Loop Unit 14 Desipn: CLU 14 Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survev Calculation Method: Database: Well Cannery Loop Unit 14 Plan @ 38.40usft (HEC 169) Pian @ 38.40usft (HEC 169) True Minimum Curvature NORTH US + CANADA 'roject Kenai C.I.U. lap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level ieo Datum: NAD 1927 (NADCON CONUS) Usinq Well Reference Point lap Zone: Alaska Zone 04 Usino geodetic scale factor yyeg Cannery Loop Unit 14 Lonqitude: Magnetics Well Position -NIS 0.00 usft Northing: 2,388,681.6710 usft Map +EI -W 0.00 usft Easting: 272,696.8380 usft Position Uncertainty 0.50 usft Wellhead Elevation: 0.00 usft Wellbore Cannery Loop Unit 14 Lonqitude: Magnetics Model Name Sample Data Declination BGGM2018 8/3/2019 Map Dip Angle Field Strength Design CLU 14 7346 Audit Notes: +N/ -S +E/ -W Version: 1.0 Phase: ACTUAL Vertical Section: Depth From (TVD) -N/-S (°) (usft) (usft) (usft) 18.00 0.00 trill rillo-) 1111 Survey Tool Name Survey Program Date 9/25/2019 From To (usft) (usft) Survey (Wellbore) 100.00 9,649.00 Gvrodata Gvm Survevs (Cannery Loop Survey 15.34 Latitude: 60° 31' 56.4397 N Lonqitude: 151" 15'43.4654 W Ground Level: 20.40 usft Map Map Dip Angle Field Strength V) (nD 7346 55.196.09093971 Tie On Depth: 18.00 -E/-W Direction (usft) (°) 0.00 60.81 Tool Name Description Survey Dale 2_Gyro-NS-CT_Drill pipe H037Ga: Continuous on wireline in ddll pipe 08/25/2019 Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) 1ft1 trill rillo-) 1111 Survey Tool Name 18.00 0.00 0.00 18.00 -20.40 0.00 0.00 2,388,681.67 272,696.84 0.00 000 UNDEFINED 100.00 0.04 21689 100.00 61.60 -0.02 -0.02 2,388,681.65 272,696.82 0.05 -0.03 2_Gyro-NS-CT_Dnll pipe (1) 125.00 0.06 220.89 125.00 86.60 -004 -0.03 2,388,681.63 272,696.81 0.08 -0.05 2_Gym-NS-CT_Ddll pipe (1) 150.00 0.06 213.27 150.00 111.60 -0.06 -0.05 2,388,681.61 272,696.79 0.03 -0.07 2_Gym-NS-CT_Dnll pipe (1) 175.00 0.10 210.74 175.00 136.60 -0.09 -0.07 2,388,681.58 272,696.77 0.16 -0.10 2_Gyro-NS-CT_Dnll pipe (1) 200.00 0.11 216.40 200.00 161.60 -0.13 -0.09 2,388,681.54 272,696.75 0.06 -0.14 2_Gym-NS-CT_DHII pipe (1) 225.00 0.06 205.10 225.00 186.60 -0.16 -0.11 2.388.681.51 272,696.72 0.21 -0.17 2_Gyro-NS-CT_DHII pipe (1) 250.00 0.04 172.79 250.00 211.60 -0.18 -0.11 2.388.681.49 272,696.72 0.14 -0.19 23yro-NSCT_Drill pipe (1) 275.00 0.05 84.59 275.00 236.60 -0.19 -0.10 2,388,681.49 272,696.73 0.25 -0.18 2_Gyre-NS-CT_Dnll pip. (1) 30000 0.08 113.05 300.00 261.60 -0.19 -0.08 2,388,681.48 272,696.76 0.17 -0.16 2_Gym-NS-CT_Dnll pipe (1) 325.00 0.23 76.56 325.00 286.60 -0.19 -0.01 2,388,681.48 272,696.82 0.69 -0.10 2_Gym-NS-CT_Dnll pipe (1) 350.00 0.71 79.24 350.00 311.60 -D.15 0.19 2,388,681.52 272,697.03 1.92 0.09 2Gym-NS-CT_Dnll pipe 11) 375.00 1.26 82.92 375.00 336.60 -0.09 0.61 2,388,681.57 272.697.45 2.21 0.50 2_Gym-NS-CT_Drlli pipe (1) 400.00 1.89 84.58 399.99 361.59 -0.01 1.30 2,388,681.63 272,698.14 2.53 1.13 2_Gym-NS-CT_Dnll pipe (1) 9252019 5:44:52PM Page 2 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well Cannery Loop Unit 14 Proiect: Kenai C.I.U. TVD Reference: Plan @ 38.40usft (HEC 169) Site: Cannery Loop Unit #1 Pad MD Reference: Plan @ 38.40usft (HEC 169) Well: Cannery Loop Unit 14 North Reference: True Wellbore: Cannery Loop Unit 14 Survey Calculation Method: Minimum Curvature Design: CLU 14 Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +E[ -W Northing Easting DLS Section (usft) (°) (°) lush) (usft) (usit) (usft) (11*1 fill (°710P) 1171 Survey Tool Name 425.00 2.&1 84.05 424.97 386.57 0.08 2.26 2,388,681.71 272,699.10 2,60 2.01 2_Gym-NS-CT_Drill pipe(1) 450.00 3.50 85.01 449.93 411.53 0.21 3.57 2,388,681.81 272,700.41 3.85 3.22 2_Gym-NS-CT_poll pipe(1) 475.00 3.93 85.66 474.88 436.48 0.34 5.19 2,388,681.91 272,702.03 1.73 4.69 2_Gyro-NS-CT_Dnll pipe (1) 500.00 4.42 86.29 499.81 461.41 0.47 7.00 2,38$682.00 272,703.85 1.97 6.34 2_Gy.-NS-CT_OHll pipe(1) 525.00 5.60 86.28 524.72 Ml132 0.61 9.18 2,388,682.10 272,706.03 4.72 8.31 2_Gyro-NS-CT_Drill pipe(4) 550.00 634 86.57 549.57 511.17 0.77 11.86 2,388,682.22 272,708.71 4.56 10.73 2_Gyro-NS-CT_Drill pipe(1) 575.00 7.85 86.13 574.37 535.97 0.98 15.03 2,388,682.36 272,711.88 4.45 13.60 2_Gyro-NS-CT_Drill pipet) 600.00 9.32 85.45 599.09 560.69 1.25 1875 2,388,68256 272,715.61 5.89 16.98 2_Gyro-NS-CT_13611 pipe (1) 625.00 10.32 84.38 623.72 585.32 1.63 23.00 2,388,682.86 272,719.86 4.07 20.87 2_Gyro-NS-CT_Dri11 pipe (1) 650.00 11.93 82.02 648.25 609.85 2.21 27.79 2,388,683.35 272,724.66 6.69 25.34 2_Gyro-NS-CT_poll pipe (1) 675.00 13.47 80.84 672.64 634.24 3.03 33.22 2,388,684.07 272,730.11 625 30.48 2_Gyro-NS-CT_DO pipe (1) 700.00 14.94 80.18 696.87 658.47 4.05 39.27 2,388,684.96 272,736.18 5.92 36.26 2_Gyro-NS-CT_DHII pipe (1) 725.00 15.79 79.95 720.98 682.58 5.19 45.79 2,388,685.98 272,742.72 3.41 42.51 2_Gyro-NS-CT_Dn1I pipe (1) 750.00 16.08 79.91 745.02 706.62 6.39 52.55 2,388,687.05 272,749.50 1.16 48.99 2_Gym-NS-CT_Drill pipe (1) 775.00 16.32 79.99 769.03 730.63 7.61 59.42 2,388,688.14 272,756.39 0.96 55.58 2_Gyro-NS-CT_DHII pipe (1) 800.00 16.75 80.34 792.99 754.59 8.82 66.43 2,388,689.22 272,763.42 1.77 62.30 2_Gyro-NS-CT_DHII pipe (1) 82500 17.22 80.77 816.90 778.50 10.02 73.63 2,388,690.28 272,770.65 1.95 69.17 2_Gyro-NS-CT_Drill pipe (1) 850.00 17.71 81.16 840.75 802.35 11.20 81.04 2,388,691.31 272,778.08 2.02 76.21 2_Gyru-NSCT_DHII pipe (1) 875.00 18.42 81.79 864.52 826.12 12.35 88.71 2,388,692.31 272,785.77 2.95 83.47 2_Gyro-NS-CT_DHll pipe (1) 900.00 19.30 82.33 888.17 84877 13.46 96.71 2,386,69328 272,793.79 359 91.00 2_Gyro-NS-CT_Drill pipe(1) 925.00 20.49 81.95 911.68 873.28 14.63 105.14 2,388,694.28 272,802.24 4.79 98.92 2_Gyro-NS-CT Drill pipe(1) 950.00 21.47 81.65 935.02 896.62 15.90 114.00 2,388,695.38 272,811.12 3.94 107.28 2_Gyro-NS-CT_DHll pipe (1) 975.00 22.24 81.35 958.23 919.83 17.28 123.21 2,388,696.58 272,820.35 3.11 115.99 2_Gyro-NS-CT_Drill pipe(1) 1,000.00 23.42 80.61 981.27 942.87 18.80 132.78 2,388,697.92 272,829.95 4.86 125.09 2_Gym-NS-CT_DHll pipe(1) 1,025.00 24.48 80.01 1,004.12 965.72 20.51 142.79 2,388,699.44 272,839.99 4.35 134.66 2_Gyro-NS-CT_DHll pipe (1) 1,050.00 25.43 79.73 1,026.78 988.38 22.37 153.17 2,388,701.10 272,850.40 3.83 144.63 2_Gyro-NS-CT_Drill pipe (1) 1,075.00 26.46 79.61 1,049.26 1,010.86 24.33 163.93 2,388,702.85 272,861.20 4.13 154.98 2_Gyro-NS-CT_DHII pipe (1) 1,100.00 27.58 79.69 1,071.53 1,033.13 26.37 175.10 2,388,704.68 272,872.41 4.48 165.73 2_Gym-NS-CT_DHll pipe (1) 1,125.00 28.92 79.64 1,093.55 1,055.15 28.49 186.74 2,388,706.57 272,884.09 5.36 176.92 2_Gy.p NS -CT Dell pipe (1) 1,150.00 29.89 79.65 1,115.33 1,076.93 30.70 198.82 2,388,708.55 272,896.20 3.88 188.54 2_Gyro-NS-CT_Dnll pipe (1) 1,175.00 31.04 79.86 1,136.88 1,098.48 32.95 211.29 2,388,710.56 272,908.71 4.62 200.53 2_Gyro-NS-CT_Drill pipe (1) 1,200.00 32.25 80.29 1,158.16 1,119.76 35.21 224.21 2,388,712.57 272,921.67 4.92 212.91 2_Gyro-NS-GT_Drill pipe (1) 1,225.00 33.38 80.70 1,179.17 1,140.77 37.45 237.57 2,388,714.55 272,935.08 4.61 225.67 2_Gyro-NS-CT_Drill pipe(1) 1,250.00 34.68 81.27 1,199.89 1,161.49 39.64 251.39 2,388,716.48 272,948.93 5.35 238.80 2_Gyro-NS-CT_DHll pipe(1) 1,275.00 35.62 81.63 1,220.33 1,181.93 41.78 265.62 2,388,718.35 272,963.20 3.85 252.27 2 Gyro-NS-CT_DHII pipe(1) 1,300.00 36.27 82.00 1,240.57 1,202.17 43.87 280.15 2,388,720.16 272,977.77 2.74 265.97 2_Gyro-NS-CT_Orr pipe (1) 1,325.00 36.69 82.08 1,260.67 1,222.27 45.93 294.87 2,388,721.93 272,992.52 1.69 279.82 2_Gyro-NS-CTDriII pip. (1) 1,350.00 37.43 82.20 1,280.62 1,242.22 47.99 309.79 2,388,723.70 273,007.48 2.97 293.86 2_Gyro-NS-CT_Drill pipe (1) 1,375.00 38.91 82.50 1,300.28 1,261.88 50.04 325.11 2,388,725.47 273,022.83 5.97 308.23 2_Gym-NS-CT DHll pipe (1) 1,400.00 40.28 82.54 1,319.54 1,281.14 52.12 340.90 2,388,727.24 273,038.67 5.48 323.03 2_Gyro-NS-CT_0611 pipe It) 925/2019 5:44:52PM Pace 3 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hiicorp Alaska, LLC Local Coordinate Reference: Well Cannery Loop Unit 14 Proiect: Kenai C.I.U. TVD Reference: Plan Q 38.40usft (HEC 169) Site: Cannery Loop Unit#1 Pad MD Reference: Plan Q 38.40usft (HEC 169) Well: Cannery Loop Unit 14 North Reference: True Wellbore: Cannery Loop Unit 14 Survev Calculation Method: Minimum Curvature Design: CLU 14 Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +E/ -W Northing Easting DLS Section (usft) (') r) (usft) (usft) (usft) (usft) III) Iftl ('lion.) Iftl Survey Tool Name 1425.00 41.81 82.46 1,338.40 1,30000 54.26 357.18 2,388,729.07 273,054.98 6.12 338.28 2_Gym-NS-CT DHIl pipe (1) 1,450.00 42.69 82.47 1,356.90 1,318.50 56.46 373.84 2,388,730.95 273,071.68 3.52 353.91 2_Gyro-NS-CT_Ddll pipe (1) 1,475.00 43.50 82.29 1,375.16 1,336.76 58.73 390.77 2,386,732.89 273,088.65 3.28 369.79 2_Gyro-NS-CT_)nll pipe (1) 1,500.00 44.48 81.95 1,393.14 1,354.74 61.11 407.97 2,388,734.94 273,105.89 4.03 385.97 2_Gyro-NS-CT_Dnll pipe(1) 1,525.00 45.40 81.37 1,410.84 1,372.44 63.67 425.44 2,388,737.17 273,123.41 4.03 402.47 2_Gyro-NS-CT_Dnll pipe (1) 1,550.00 46.06 80.97 1,428.29 1,389.89 66.42 443.13 2,388,739.58 273,141.15 2.88 419.25 2_Gyro-NS-CT_DHll pipe (1) 1,575.00 46.54 80.71 1,445.56 1,407.16 69.30 460.98 2,388,742.11 273,159.04 2.06 436.23 2_Gyro-NS.CT_DHll pipe (1) 1,600.00 46.99 80.70 1,462.69 1,424.29 72.24 47895 2,388,744.71 273,177.07 1.80 453.36 2_Gym-NS-CT_DHll pipe (1) 1,625.00 47.18 80.68 1,479.71 1,441.31 75.20 497.02 2,388,747.32 273,195.19 0.76 470.58 2_Gym-NS-CT_Drill pipe (1) 1,650.00 47.49 80.50 1,496.65 1,458.25 78.21 515.16 2,388,749.98 273,213.38 1.35 487.88 2_Gym-NS-CT_Drill pipe (1) 1,675.00 47.70 80.26 1,513.51 1,475.11 81.29 533.36 2,388,752.72 273,231.63 1.10 505.27 2_Gym-NS-CT_DHII pipe (1) 1,700.00 47.78 80.06 1,530.32 1,491 92 84.45 551.59 2,388,755.53 273,249.92 0.67 522.73 2_Gym-NS-CT_DHII pipe (1) 1,725.00 47.86 80.01 1,547.11 1,508.71 87.66 569.83 2,388,758.38 273,268.22 0.35 540.22 2_Gyro-NS-CT_poll pipe (1) 1,750.00 47.94 79.99 1,563.87 1,525.47 90.88 588.10 2,388,761.25 273,286.55 0.33 557.74 2_Gyro-NS-CT_D611 pipe (1) 1,775.00 48.03 79.88 1,580.60 1,542.20 94.13 606.39 2,388,764.15 273,304.89 0.49 575.29 2_Gyro-NS-CT_DHII pipe (1) 1,800.00 48.08 79.71 1,597.32 1,558.92 97.42 624.69 2,388,767.09 273,323.25 0.54 592.87 2_Gyro-NS-GT_DHII pipe (1) 1,825.00 48.12 79.59 1,614.01 1,575.61 100.76 642.99 2,388,770.08 273.341.62 0.39 610.48 2_Gym-NS-CT_DHll pipe (1) 1,850.00 48.22 79.64 1,630.68 1,592.28 104.12 66122 2,388,773.09 273,360.00 0.43 628.12 2_Gym-NS-CT_DHll pipe (1) 1,875.00 48.28 79.60 1,647.33 1,608.93 107.48 679.66 2,388,776.09 273,378.41 0.27 645.77 2_Gym-NSCT_DHll pipe (1) 1,900.00 48.28 79.62 1,663.97 1,62557 110.85 698.02 2,388,779.11 273,396.82 0.06 663.44 2_Gym-NS-CT_poll pipe (1) 1,925.00 48.06 79.55 1,680.64 1,642.24 114.21 716.34 2,388,782.12 273,415.21 0.90 681.07 2_Gym-NS-CT_DH1I pipe (1) 1,950.00 47.79 79.58 1,697.39 1,658.99 117.58 734.59 2,388,785.13 273,433.52 1.08 698.64 2_Gym-NS-CT_poll pipe (1) 1,975.00 47.36 79.69 1,714.26 1,675.86 120.90 752.74 2,388,788.10 273,451.73 1.75 716.11 2_Gym-NS-CTDHli pipe (1) 2,000.00 46.99 79.56 1,731.25 1,692.85 124.20 770.78 2,388,791.06 273,469.82 1.53 733.47 2_Gyro-NS-CT_DHII pipe (1) 2,025.00 46.87 79.31 1,748.33 1,709.93 127.55 788,73 2,388,794.06 273,487.84 0.87 750.77 2_Gyro-NS-CT_Ddll pipe (1) 2,050.00 46.92 79.06 1,765.41 1,727.01 130.97 806.66 2,388,797.14 273,505.83 0.76 768.09 2_Gyro-NS-CT_Drill pipe (1) 2,075.00 47.06 79.02 1,782.46 1,744.06 134A5 824.61 2,3881 273,523.84 0.57 785.46 2_Gym-NS-CT_DHll pipe (1) 2,100.00 46.61 78.99 1,799.56 1,761.16 137.92 842.51 2,388,803.41 273,541,80 1.80 802.78 2_Gym-NS-CT_D1rll pipe (1) 2,125.00 46.24 79.28 1,816.80 1,77840 141.34 860.29 2,388,806.48 273,559.65 1.70 819.97 2_Gym-NSCT_Drill pipe (1) 2,150.00 46.53 79.41 1,834.04 1,795.64 144.69 878.08 2,388,809.48 273,577.50 1.22 837.14 2_Gyro-NSCT_DHll pipe (1) 2,175.00 47.05 79.49 1,851.16 1,812.76 148.02 895.99 2,388,812.48 273,595.47 2.09 854.40 2_Gym-NS-CT_DHII pipe (1) 2,200.00 47.60 79.71 1,868.11 1,829.71 151.34 914.07 2,388,815.45 273,613.61 2.29 871.80 2_Gym-NS-CT_Doll pipe(1) 2,225.00 47.83 79.82 1,884.93 1,846.53 154.63 932.27 2,388,818.38 273,631.87 0.98 889.29 2_Gyro-NS-CT_DHII pipe (1) 2,250.00 47.76 79.72 1,901.72 1,863.32 157.91 950.50 2,388,821.32 273,650.15 0.41 906.81 2_Gym-NS-CT_DHII pipe (1) 2,275.00 48.05 79.58 1,918.48 1,880.08 161.25 968.75 2,388,824.30 273,668.46 1.23 924.36 2_Gyro-NS-CT_DHll pipe(1) 2,300.00 48.52 79.50 1,935.12 1,896.72 164.64 987.10 2,388,827.34 273,686.87 1.90 942.04 2_Gym-NSCT_DHll pipe (1) 2,325.00 49.04 79.42 1,951.59 1,913.19 168.08 1,005.59 2,388,830.42 273,705.42 2.09 959.85 2_Gym-NSCT_DHll pipe(1) 2,350.00 49.32 79.41 1,967.93 1,929.53 171.55 1,024.18 2,388,833.54 273,724.08 1.12 9F.79 2_Gyro-NS-CT_Doll pipe (1) 2,375.00 49.37 79.52 1,984.22 1,945.82 175.02 1,042.83 2,388,836.65 273,742.79 0.39 995.75 2_Gym-NS-CT_DH1l pipe (1) 2,400.00 48.81 79.70 2,000.59 1,962.19 178.43 1,061.41 2,388,839.70 273,761.43 2.31 1,013.64 2_Gyro-NS-CT_Dn1l pipe (1) 9/252019 5:44:52PM Page 4 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Companv: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well Cannery Loop Unit 14 Proiect: Kenai C.I.U. TVD Reference: Plan @ 38.40usft (HEC 169) Site: Cannery Loop Unit #1 Pad MD Reference: Plan @ 38.40usft (HEC 169) Well: Cannery Loop Unit 14 North Reference: True Wellbore: Cannery Loop Unit 14 Survev Calculation Method: Minimum Curvature Desiqn: CLU 14 Database: NORTH US+CANADA Survey 9252019 5:44'52PM Pace 5 COMPASS 5000.15 Build 91 Map Map vertical MD Inc Azi TVD TvDSS +NIS +EI -W Northing Easting DIS Section (usft) (°) (°) (-it) (usft) (usft) (usft) (fn !ttl (°/f 00') 1111 Survey Tool Name 2,425.00 48.56 79.80 2,017.10 1,978.70 181.77 1,079.89 2,388,84269 273,779.97 1.04 1,031.40 2_Gyro-NSCT_Dnll pipe (1) 2,450.00 48.94 79.63 2,033.58 1,995.18 185.09 1,098.39 2,388,845.66 273,798.53 1.52 1,049.17 2_Gyro-NSCT_Drill pipe (1) 2,475.00 49.47 79.75 2,04991 2,011.51 188.45 1,117.02 2,388,848.65 273,817.22 2.13 1,067.07 2_Gym-NSCT_Drill pipe (1) 2,500.00 49.99 79.69 2,066.07 2,027.67 191.85 1,135.79 2,388,851.70 273.836.05 2.09 1,085.12 2_Gym-NSCT_Dn1l pipe (1) 2,525.00 50.37 79.78 2,082.08 2,043.68 195.27 1,154.68 2,388,854.76 273,855.00 1.54 1,103.28 2_Gyro-NS-CT_Dd1l pipe (1) 2,550.00 50.19 79.80 2,098.06 2,059.66 198.68 1,17360 2,388,857.80 273,873.99 0.72 1,121.46 2_Gyro-NSCT_Dnil pipe (1) 2,575.00 50.23 79.92 2,114.06 2,075.66 202.O6 1,192.51 2,388,860.82 273.892.96 0.40 1,139.62 2_Gyro-NSCT_Drill pipe (1) 2,600.00 50.22 79.84 2,130.05 2,091.65 20544 1,211.43 2,386,863.83 273,911.93 025 1,15778 2_Gyro-NS-CT_Drill pipe (1) 2,825.00 50.19 79.86 2,146.05 2,107.65 208.82 1,230.34 2,388,866.85 273,930.90 0.13 1,175.94 2_Gyro-NS-CT_Dnll pipe (1) 2,650.00 50.12 79.95 2,162.07 2,123.67 212.19 1,249.23 2,388,869.85 273,949.86 0.39 1,194.08 2_Gyro-NS-CT_Ddll pipe (1) 2,675.00 50.15 80.00 2,178.09 2,139.69 215.53 1,268.13 2,388,872.83 273,968.82 0.19 1,212.20 2_Gyrp-NS-CT_Drill pipe (1) 2,700.00 50.04 80.05 2,194.13 2,155.73 218.85 1,287.02 2,388,875.79 273,987.76 0.47 1,230.31 2_Gyro-NS-CT_Dnll pip. (1) 2,725.00 49.90 80.14 2,210.21 2,171.81 222.14 1,305.88 2,388,878.72 274,006.68 0.62 1,248.38 2_Gyro-NS-CT_Dnll pipe (1) 2,750.00 49.98 80.17 2,226.30 2,187.90 225.41 1,324.73 2,388,881.63 274,025.59 0.33 1,266.43 2_Gyro-NS-CT_Ddi pipe (1) 2,775.00 50.13 80.06 2,242.35 2,20395 228.70 1,343.61 2,388,884.56 274,044.53 0.69 1,284.52 2_Gyro-NS-CT_Drill pipe (1) 2,800.00 50.00 80.00 2,258.40 2,220.00 232.02 1,362.49 2,388,887.51 274,063.47 0.55 1,302.62 2_Gyn NS-CT_Dn1l pipe (1) 2,825.00 49.81 79.83 2,274.50 2,236.10 235.37 1,381.32 2,388,890.50 274,082.36 0.92 1,320.69 2_Gyro-NS-CT_Drill pipe (1) 2,850.00 49.66 79.50 2,290.66 2,252.26 238.79 1,400.09 2,388,893.56 274,101.19 1.17 1,338.75 2_Gyro-NS-CT_Mill pipe (1) 2,875.00 49.74 79.18 2,306.83 2,268.43 242.32 1,418.82 2,388,896.73 274,119.99 1.03 1,356.83 2_Gyro-NS-CT_Drill pipe (1) 2,800.00 49.66 78.72 2,323.00 2,284.60 245.98 1,437.54 2,388,900.02 274,138.77 1.44 1,374.94 2_Gyro-NS-CT_Dnll pipe (1) 2,925.00 49.19 78.23 2,339.26 2,300.86 249.77 1,456.14 2,388,903.46 274,157.44 2.40 1,393.04 2 -Gy. -NS -CT Drill plpe(1) 2,950.00 48.62 78.00 2,355.69 2,317.29 253.65 1,474.58 2,388,906.99 274,175.95 2.38 1,411.02 2_Gyro-NSCT_Dri1l pipe (1) 2,975.00 48.10 77.97 2,372.31 2,333.91 257.54 1,492.85 2,388,910.52 274,194.29 2.08 1,428.87 2_Gyro-NSCT_Ddll pipe (1) 3,000.00 47.82 78.05 2,389.05 2,350.65 261.40 1,511.01 2,388,914.03 274,21253 1.14 1,446.61 2_Gyro-NSCT_Drill pipe (1) 3,025.00 47.70 78.10 2,405.85 2,367.45 265.22 1,529.12 2,388,917.51 274,230.70 0.50 1,464.29 2_Gyro-NS-CT_Drill pipe (1) 3,050.00 47.85 78.20 2,422.65 2,38425 269.02 1,547.24 2,388,920.96 274,248.89 0.67 1,481.96 2_Gyro-N8-CT_Dnll pipe (1) 3,075.00 47.66 76.25 2,439.46 2,401.06 272.80 1,565.36 2,388,924.39 274,267.08 0.77 1,499.62 2_Gym-NS-CT_Ddll pipe (1) 3,100.00 47.08 78.43 2,456.39 2,417.99 276.52 1,583.37 2,388,927.76 274,285.16 2.38 1,517.16 2_Gyro-NS-CT_Dnll pipe (1) 3,125.00 46.51 78.47 2,473.51 2,435.11 280.16 1,601.23 2,388,931.07 274,303.08 2.28 1,534.52 2_Gyro-NS-CT_Dnll pipe (1) 3,150.00 46.38 78.49 2,490.73 2,452.33 283.78 1.618.98 2,388,934.34 274,320.90 0.52 1,551.78 2_Gyro-NS-CT_Dnll pipe (1) 3,175.00 46.57 78.42 2,507.95 2,469.55 287.41 1,636.74 2,388,937.63 274,338.72 0.79 1,569.06 2_Gyro-NS-CT_Drill pipe (1) 3,200.00 46.66 78.42 2,525.12 2,486.72 291.06 1,654.54 2,388,940.93 274,356.59 0.36 1,586.38 2 Gyro-NS-CT_Dnll pipe (1) 3,225.00 46.62 78.35 2,542.29 2,503.89 294.72 1,672.34 2,388,944.25 274,374.46 0.26 1,603.70 2_Gyro-NS-CT_Dn1l pipe (1) 3,250.00 46.87 78.28 2,559.42 2,521.02 298.41 1,690.17 2,388,947.60 274,392.35 1.02 1,621.07 2_Gyro-NS-CT_Drill pipe (1) 3,275.00 47.10 78.28 2,576.47 2,538.07 302.12 1,708.07 2,388,950.97 274,410.32 0.92 1,638.50 2_Gyro-NS-CT_Dnll pipe (1) 3,300.00 47.02 78.22 2,593.50 2,555.10 305.85 1,725.99 2,388,954.35 274,428.30 0.37 1,655.96 2_Gyro-NS-CT_Drill pipe (1) 3,325.00 46.40 78.32 2,61D.65 2,572.25 309.55 1,743.81 2,388,957.71 274,446.19 2.50 1,673.32 2_Gyro-NS-CT_Dnll pipe(1) 3,350.00 46.03 78.47 2,627.95 2,58955 313.18 1,761.49 2,388,961.00 274,463.93 1.54 1,690.53 2_Gyro-NS-CT_Dnll pipe (1) 3,375.00 46.35 76.59 2,645.25 2,606.85 316.76 1,779.17 2,388,964.24 274,481.68 1.33 1,707.71 2_Gyn NS-CT_Ddll pipe (1) 3,400.00 46.77 78.81 2,662.44 2,624.04 320.32 1,796.97 2,388,967.46 274,499.54 1.80 1,724.99 2_Gyn NS-CT_Dnll pipe(1) 9252019 5:44'52PM Pace 5 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Coordinate Reference: Well Cannery Loop Unit 14 Project: Kenai C.I.U. TVD Reference: Plan @ 38.40usft (HEC 169) Site: Cannery Loop Unit #1 Pad MD Reference: Plan @ 38.40usft (HEC 169) Well: Cannery Loop Unit 14 North Reference: True Wellbore: Cannery Loop Unit 14 Survev Calculation Method: Minimum Curvature Design: CLU 14 Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Ari TVD TVDSS +NIS +E/ -W Northing Easting DLS Section (usft) (') (1) (usft) (usft) (usft) (usft) lift iftl (°/fee•) rft) Survey Tool Name 3,425.00 47.23 79.25 2,679.49 2,641.09 323.80 1,814.92 2,388,970.59 274,517.56 2.25 1,742.36 2_Gyro-NS-CT_Dn1l pipe (1) 3,450.00 47.51 79.58 2,696.42 2,658.02 327.18 1,833.00 2.388,973.62 274,535.70 1.48 1,759.79 2_Gyro-NS-CT_Dnll pipe (1) 3,475.00 48.02 79.70 2,713.23 2,674.83 330.51 1,851.21 2,388,976.60 274,553.97 2.07 1,7T7.31 2_Gyro-NS-CT_Dnl pipe (1) 3,500.00 48.48 79.74 2,729.87 2,691.47 333.83 1,869.56 2,388,979.58 274,572.38 1.84 1,794.95 2_Gyro-NS-CT_Dnll pipe (1) 3,525.00 48.59 79.82 2,746.43 2,708.03 337.16 1,887.99 2,388,982.55 274,590.87 0.50 1,812.67 2_Gyro-NS-CT_Drill pipe(1) 3,550.00 48.90 79.85 2,762.91 2,724.51 340.48 1,90fi 19 2,388,985.51 274,609.43 1.24 1,830.44 2_Gyro-NS-CT_Dnll pipe (1) 3,575.00 49.32 79.96 2.779.28 2,740.88 343.79 1,925.10 2,388,988.46 274,68.10 1]1 1,848.29 2_ Gyro4lS-CT_Drill pipe (1) 3,600.00 49.24 79.92 2,795.59 2,757.19 347.10 1,943.76 2,388,991.42 274,64681 0.34 1,866.20 2 Gyro-NS-CT_Ddll pipe (1) 3,625.00 48.82 79.83 2,811.98 2,773.58 350.42 1,962.34 2,388,994.38 274,665.46 1.70 1,884.04 2_Gym-NS-CT_Dnll pipe (1) 3,650.00 48.73 79.91 2,828.46 2,790.06 353.72 1,980.85 2,388,997.33 274,684.03 0.43 1,901.81 2_Gyro-NS-CT_Drill pipe(1) 3,675.00 49.11 80.01 2,844.88 2,806.48 357.01 1,99941 2,389,000.26 274,702.64 1.55 1,919.61 2_Gyro-NSCT_Dnll pipe (1) 3,700.00 49.43 80.02 2,861.20 2,822.80 360.29 2,018.06 2,389,003.18 274,721.36 1.28 1,937.50 2_Gym-NS-CT_Dnll pipe (1) 3,725.00 49.03 80.13 2,877.52 2,839.12 363.56 2,036.71 2,389,006.09 274,740.07 1.63 1,955.38 2_Gym-NS-CT_Drill pipe (1) 3,750.00 48.33 80.35 2,894.03 2,855.63 366.74 2,055.22 2,389.008.92 274,758.63 2.88 1,973.08 2_Gyro-NS-CT_Dnll pipe (1) 3,775.00 48.00 80.37 2,910.70 2,872.30 369.86 2,073.58 2,389,011.68 274,777.05 1.32 1,990.63 2_Gyro-NS-CT_Dnll pipe (1) 3,800.00 47.49 80.26 2,927.51 2,889.11 372.97 2,091.82 2,389,014.44 274]95.34 2.07 2,008.08 2_Gym-NS-CT_0611 pipe (1) 3,825.00 47.38 80.11 2,944.42 2,906.02 376.11 2,109.96 2,389,017.23 274,813.54 0.62 2,025.45 2Gyro-NS-CT_Drill pipe (1) 3,850.00 47.79 80.24 2,961.29 2,922.89 379.26 2,128.15 2,389,020.03 274,831.78 1.68 2,042.86 2_Gym-NS-CT_Ddll pipe (1) 3,875.00 48.27 80.10 2,978.00 2,939.60 382.43 2,146.47 2,389,022.88 274,850.15 1.96 2,060.40 2_Gym-NS-CT_Drill pipe (1) 3,900.00 48.48 79.97 2,994.61 2,956.21 385.67 2,164.87 2,389,025.74 274,868.62 0.93 2,078.04 2_Gyro-NS-CT_Dnll pipe (1) 3,925.00 48.15 79.90 3,011.24 2,972.84 388.93 2,183.25 2.389.028.65 274,887.06 1.34 2,095.68 2_Gym-NS-CT_Dnll pipe (i) 3,950.00 48.09 79.88 3,027.93 2,989.53 392.20 2,201.58 2,389,031.56 274,905.44 0.25 2,113.27 2_Gym-NS-CT Dnll pipe (1) 3,975A0 48.42 79.84 3,044.57 3,006.17 395.48 2,219.94 2,389,034.49 274,923.86 1.33 2,130.90 2_Gym-NS-CT Dni pipe (1) 4,000.00 46.99 79.92 3,061.07 3,022.67 398.78 2,238.43 2,389,037.44 274,942.41 2.29 2,148.66 2_Gyro-NS-CT_Dn1l pipe (1) 4,025.00 49.44 79.81 3,077.40 3,039.00 402.11 2,257.06 2,389,040.41 274,961.11 1.83 2,166.55 2_Gyro-NS-GT_Dn1l pipe (1) 4.050.00 48.94 79.56 3,093.74 3,055.34 405.50 2,275.68 2,389,043.44 274,979.78 2.14 2,184.45 2_Gym-NS-CT_Drill pipe (1) 4,075.00 48.41 79.64 3,110.25 3,071.85 408.89 2,294.15 2,389,046.47 274,998.31 2.13 2,202.23 2_Gyro-NS-CT_Ddll pipe (1) 4,100.00 47.81 79.57 3,126.94 3,088.54 412.25 2,312.45 2,389,049.48 275,016.67 2.41 2,219.84 2_Gym-NS-CT_Drill pipe (1) 4,125.00 47.31 79.50 3,143.81 3,105.41 415.60 2,330.59 2,389,052.48 275,034.88 2.01 2,237.32 2_Gyro-NS-CT_Dril pipe (1) 4,150.00 47.50 79.53 3,160.73 3,122.33 418.95 2,348.69 2,389,055.48 275,053.03 0.77 2,254.75 2_Gyro-NS-CT_Dnll pipe (1) 4,175.00 47.93 79.63 3,177.55 3,139.15 422.29 2,366.88 2,389,058.48 275,071.28 1.75 2,272.26 2_Gyro-NS-CT_Dnll pipe (1) 4,200.00 48.40 79.67 3,194.23 3,155.83 425.64 2,385.20 2,389,061.47 275,089.67 1.88 2,289.89 2_Gyro-NS-CT_Dnll pipe (1) 4,225.00 48.50 79.87 3,210.81 3,172.41 42896 2,403.62 2,389,064.44 275,108.14 0.72 2,307.58 2_Gyro-1,18-CT_Dnll pipe (1) 4,250.00 48.08 80.14 3,227.44 3,18904 432.20 2,422.00 2,389,067.33 275.126.58 1.86 2,325.21 2_Gym-NS-CT_Drill pipe(1) 4,275.00 48.42 80.20 3,244.09 3,205.69 435.39 2,440.37 2,389,070.16 275,145.01 1.37 2,342.81 2_Gyro-NS-CT_Drll pipe (1) 4,300.00 49.03 80.39 3,260.58 3,222.18 438.55 2,458.89 2,389,072.97 275,163.59 2.51 2,360.52 2_Gyro-NS-CT_D611 pipe (1) 4,325.00 49.44 80.30 3,276.90 3,238.50 441.73 2,477.56 2,389,075.79 275,182.31 1.66 2,378.36 2_Gym-NS-CT_Ddll pipe (1) 4,350.00 49.33 80.04 3,293.18 3,254.78 444.97 2,496.26 2,389,078.67 275,201.07 0.90 2,396.27 2_Gym-NSCT_Dnll pipe (1) 4,375.00 48.59 79.39 3,309.59 3,271.19 448.33 2,514.81 2,389,081.68 275,219.68 3.55 2,414.11 2_Gyro-NS-CT_Dnll pipe (i) 4,400.00 47.86 78.77 3,326.25 3,287.85 451.87 2,533.12 2,389,084.86 275,238.05 3.46 2,431.81 2_Gyro-NS-CT_Dnll pipe (1) 9/252019 5:44:52PM Paas 6 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Companv: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well Cannery Loop Unit 14 Proiect: Kenai C.I.U. TVD Reference: Plan @ 38.40usft (HEC 169) Site: Cannery Loop Unit#1 Pad MD Reference: Plan @ 38.40usft (HEC 169) Well: Cannery Loop Unit 14 North Reference: True Wellbore: Cannery Loop Unit 14 Survey Calculation Method: Minimum Curvature Design: CLU 14 Database: NORTH US+CANADA Survey 9/252019 5:44:52PM Pape 7 COMPASS 5000.15 Build 91 Map Map Vertical MD Inc Azi TVD TVDSS +NlS +El -W Northing Easting OLS Section (usft) (,) (1) (usft) (usft) (usft) (usft) Iftl Ito (`1100] Iftl Survey Tool Name 4,425.00 46.62 78.13 3,34322 3,304,82 455.54 2,551.10 2,389,088.19 275,256.10 5.30 2,449.30 2_Gyro-NS-CT_Drill pipe(1) 4,450.00 46.32 77.88 3,360.44 3,32204 459.31 2,568.83 2,389,091.61 275,273.90 1.40 2.466.62 2_Gyro-NS-CT_Doll pipe (1) 4,475.00 46.70 T7.89 3,377.65 3,33925 463.11 2,586.56 2,389,095.08 275,291.70 1.52 2,483.95 2_Gyro-NS-CT_Dnll pipe (1) 4,500.00 47.38 77.89 3,394.68 3,356.28 466.95 2.604.45 2,389,098.57 275,309.66 2.72 2,501.44 2Gyro-NS-CT_Dnll pipe (1) 4,525.00 48.00 77.94 3,411.51 3,373.11 470.82 2,622.53 2,389,102.09 275,327.81 2.411 2,519.11 2_Gyro-NS-CT_Ddll pipe (1) 4,550.00 48.49 78.06 3,428.16 3,389.76 474.70 2,640.77 2,389,105.62 275,346.12 1.99 2,536.93 2_Gyrg-NS-CT_Drill pipe(1) 4,575.00 48.84 78.10 3,444.67 3,406.27 478.58 2,659.14 2,389,109.15 275,364.56 1.41 2,554.85 2_Gyro-NS-CT_Dnll pipe (1) 4,600.00 48J4 78.33 3,461.14 3,422.74 482.42 2,677.55 2,389,112.63 275,383.04 0.80 2,572.80 2_Gyro-NS-CT_DHII pipe (1) 4,625.00 48.37 78.68 3,477.69 3,439.29 486.15 2,695.92 2,389,116.01 275,401.47 1.81 2,590.65 2_Gyro-NS-CT_DHll pipe(1) 4,650.00 47.82 78.98 3,494.39 3,455.99 489]6 2,714.17 2,389,119.27 275,419.79 2.37 2,608.35 2_Gyro-NS-CT_Dnll pipe (1) 4,675.00 47.00 79.39 3,511.30 3,472.90 493.21 2,732.25 2,389,122.38 275,437.93 3.50 2,625.81 2_Gym-NS-CT_0611 pipe (1) 4,700.00 47.00 79.46 3,528.35 3,489.95 496.57 2,750.22 2,389,125.39 275,455.96 0.20 2,643.14 2_Gyro-NS-CT_Dnll pipe (1) 4,725.00 47.24 79.68 3,545.37 3,506.97 499.88 2,768.24 2,389,128.36 275,474.04 1.16 2,660.49 2_Gyro-NS-CT_Drill pip. (1) 4,750.00 47.66 79.72 3,562.27 3,523.87 503.18 2,786.36 2,389,131.30 275,492.22 1.68 2,677.91 2_Gyro-NS-CT_Doll pipe (1) 4,775.00 48.16 79.76 3,579.03 3,540.63 506.48 2,804.61 2,389,134.25 275,510.53 200 2,695.46 2_Gyro-NS-CT_Doll pipe (1) 4,800.00 48.72 79.92 3,595.61 3,557.21 509.78 2,823.03 2,389,137.20 275,529.01 2.29 2,713.15 2_Gym-NS-CT_DH1I pipe (1) 4,825.00 49.15 80.02 3,612.04 3,573.64 513.06 2,841.59 2,389,140.13 275,547.62 1.75 2,730.95 2_Gyra-NS-CT_Drill pipe (1) 4,850.00 49.06 80.43 3,628.40 3,590.00 516.27 2,860.21 2,389,142.98 275,566.31 1.29 2,748.77 2_Gym-NS-CT_DHll pipe (1) 4,875.00 1826 80.87 3,644+86 3,60645 519.33 2,878.79 2,389,145.68 275,584.94 2.08 2,766.48 2_Gyro-NS-CT_DHll pipe (1) 4,900.00 48.16 81.45 3,661.45 3,623.05 522.20 2,897.26 2,389,14820 275,603.46 2.65 2,784.01 2_Gyn>NS-CT_Drill pipe (1) 4,925.00 47.69 81.84 3,678.20 3,639.80 524.90 2,915.62 2,389,150.54 275,621.87 2.21 2,801.36 2_Gym-NS-CT_DHll pipe (1) 4,950.00 47.43 81.98 3,695.07 3,656.67 527.50 2,933.89 2,389,152.79 275,640.18 1.12 2,818.57 2 Gyro-NS-CT_Doll pipe (1) 4,975.00 46.94 82.03 3,712.06 3,673.66 530.05 2.952.05 2,389,154.99 275,658.39 1.97 2,835.67 2 Gyro -NS -CT Drill pipe (1) 5,000.00 46.60 81.96 3,729.18 3,690.78 532.58 2,970.09 2,389,457.18 275,676.47 1.38 2,852.65 2_Gyro-NS-CT_Doll pipe (1) 5,025.00 46.74 81.95 3,746.34 3,707.94 535.13 2,988.09 2,389,159.38 275,694.52 0.56 2,869.61 2_Gyro-NS-CT_DHII pipe (1) 5,050.00 47.05 81.99 3,763.42 3,725.02 537.68 3,006.17 2,389,161.58 275,712.64 1.25 2,886.64 2_Gyro-NS-CT_DHII pipe (1) 5,075.00 47.52 82.08 3,780.38 3,741.98 540.22 3,024.36 2,389,163.78 275,730.88 1.90 2,903.76 2_Gyn NS-CT_Drill pipe (1) 5,100.00 48.09 82.07 3,797.17 3,758.77 542.78 3,042.70 2,389,165.98 275,749.27 2.28 2,921.02 2_Gyn-NS-CT_DHll pipe (1) 5,125.00 48.63 82.09 3,813.78 3,775.38 545.35 3,061.21 2,389,168.20 275,767.82 2.16 2,938.43 2_Gyro-NS-CT_DHli pipe (1) 5,150.00 48.54 81.87 3,830.32 3,791.92 547.97 3,079.77 2,389,170.46 275,786.43 0.75 2,955.91 2_Gyro-NS-CT_Drill pipe (1) 5,175.00 47.96 81.49 3,846.97 3,808.57 550.67 3,098.23 2,389,172.80 275,804.93 2.58 2,973.34 2_Gyro-NS-CT_Drill pipe (1) 5,200.00 47.77 81.17 3,863.74 3,825.34 553.46 3,116.56 2,389,175.24 275,823.31 1.22 2,990.70 2_Gyro-NS-CT_Ddll pipe (1) 5,225.00 47.29 80.46 3,880.62 3,842.22 556.40 3,134.76 2,389,177.84 275,841.56 2.84 3,008.03 2_Gy.-NS-CT_Drill pipe (1) 5,250.00 46.89 79.90 3.897.64 3,859.24 559.53 3,152.80 2,389,180.61 275,859.66 2.29 3,025.30 2_Gyro-NS-CT_DHII pipe (1) 5,275.00 47.28 79.73 3,914.66 3,876.26 562.77 3,170.82 2,389,183.50 275,8T.74 1.64 3,042.62 2_Gyrg-NS-CT_DHll pipe (1) 5,300.00 47.78 79.71 3,931.54 3,893.14 566.06 3,188.97 2,389,186.44 275,895.94 2.00 3,060.06 2_Gyn,NS-CT_Dnl1 pipe (1) 5,325.00 48.26 79.45 3,948.27 3,909.87 569.42 3,207.24 2,389,189.45 275,914.28 2.07 3,077.66 2_Gyo,NS-CT_DHll pipe(1) 5,350.00 48.03 78.75 3,964.95 3,926.55 572.94 3,225.53 2,389,192.62 275.932+0 2.28 3,095.34 2_Gyro-NS-CT_Drill pipe (1) 5,375.00 47.64 77.91 3,981.73 3,943.33 676.69 3,243.68 2,389,196.02 275,950.84 2.94 3,113.01 2_Gyro-NS-CT_Drill pipe (1) 5,400.00 47.33 77.51 3,998.62 3,960.22 5WA1 3,261.68 2,389,199.60 275,968.92 1.71 3,130.64 2Gyro-NS-CT_DHll pipe (1) 9/252019 5:44:52PM Pape 7 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well Cannery Loop Unit 14 Project: Kenai C.I.U. TVD Reference: Pian @ 38.40usft (HEC 169) Site: Cannery Loop Unit #1 Pad MD Reference: Plan @ 38.40usft (HEC 169) Well: Cannery Loop Unit 14 North Reference: True Wellbore: Cannery Loop Unit 14 Survey Calculation Method: Minimum Curvature Design: CLU 14 Database: NORTH US+CANADA (Survey Map Map Vertical MD Inc Azi TVD TVDSS +NiS +FJ -W Northing Easting DLS Section (usft) (`) (') (usft) (usft) (usft) (usft) ft fall (•1100•) trill Survey Tool Name 5,425.00 46.91 77.17 4,015.64 3,977.24 584.62 3,279.56 2,389,203.27 275,986.87 1.95 3,148.20 2_Gyro-NS-CT_Drill pipe (1) 5,450.00 46.92 77.15 4,032.71 3,994.31 588.68 3,297.36 2,389,206.99 276,004.74 0.07 3,165.72 2_Gym-NS-CT_Dnll pipe (1) 5,475.00 45.86 77.37 4,049.96 4,011.56 592.67 3,315.01 2,389,210.64 276,022.47 4.29 3,153.08 2_Gyro-NS-CT_Dnli pipe (1) 5,500.00 45.77 77.42 4,067.38 4,028.98 596+59 3,332.51 2,389,214.21 276,040.04 0.39 3,200.26 2_Gyro-NS-CT_Drill pipe (1) 5,525.00 45.09 77.07 4,084.92 4,046.52 600.52 3,349.88 2,389,217.81 276,057.48 2.90 3,217.34 2_Gyro-NS-CT_Drill pipe (1) 5,550.00 44.06 75.95 4,10233 4,064.33 604.61 3,36694 2,389,221.58 276,074.61 5.18 3,234.23 2_Gyro-NSCT_Dnll pipe (1) 5,575.00 43.43 75.24 4,120.79 4,082.39 608.91 3,383.68 2,389,225.55 276,091.44 3.19 3,250.95 2_Gyro-NS-CT_Drill pipe (1) 5,600.00 42.72 74.51 4,139.06 4,10066 61336 3,400.17 2,389,229.69 276,108.00 3.47 3,267.51 2_Gyro-NS-0T_Drill pipe (1) 5,625.00 42.39 73.99 4,157.47 4,119.07 617.95 3,416.44 2,389,233.97 276,124.36 1.93 3,283.95 2_Gyro-NS-CT_Drill pipe (1) 5,650.00 42.30 73.73 4,175.95 4,137.55 622.63 3,432.61 2,389,238.34 276,140.62 0.79 3,300.36 2_Gyro-NS-CT_Drill pipe (1) 5,675.00 42.42 73.62 4,194.42 4,156.02 627.37 3,448.78 2,389,242.76 276,156.87 0.56 3,316.78 2_Gyro-NS-CT_Ddll pipe (1) 5,700.00 42.60 73.55 4,212.85 4,174.45 632.14 3,464.98 2,389,247.22 276,173.16 0.74 3,333.26 2_Gym-NS-CT_Ddll pipe (1) 5,725.00 42.28 72.65 4,231.30 4,192.90 637.04 3,481.13 2,389,251.81 276,189.40 2.75 3,349.74 2_Gyro-NS-CT_Drill pipe (1) 5,750.00 42.47 72.05 4,249.77 4,211.37 642.15 3,497.18 2,389,256.61 276,205.55 1.79 3,366.25 2_Gyro-NS-CT_Drill pipe (1) 5,775.00 42.73 71.97 4,268.17 4,229.77 647.38 3,513.28 2,389,261.53 276,221.74 1.06 3,382.85 2_Gyro-NS-CT_Dnil pipe (1) 5,800.00 43.39 71.77 4,286.44 4,248.04 652.69 3,529.50 2,389,266.53 276,238.06 2.70 3,399.60 2_Gyro-NS-CT_Drill pipe (1) 5,825.00 43.52 71.49 4,304.59 4,265.19 658.11 3,545.82 2,389,271.64 276,254.48 0.93 3,416.49 2Gyro-NS-CTDHII pipe (1) 5,850.00 43.21 70.75 4,322.76 4,284.36 663.66 3,562.06 2,389,276.88 276,270.82 2.38 3,433.38 2_Gyro-NS-CT_DHII plpe (1) 5,875.00 42.73 69.65 4,341.05 4,302.65 669.44 3,578.09 2,389,282.34 276,286.96 3.56 3,450.19 2_Gyro-NSCT_Drill pipe (1) 5,900.00 42.49 69.19 4,359.45 4,321.05 675.39 3,593.94 2,389,287.98 276,302.92 1.57 3,466.92 2_Gyro-NS-CT_Drill pipe (1) 5,925.00 40.73 67.69 4,378.14 4,339.74 681.48 3,609.38 2,389,293.78 276,318.47 8.09 3,483.37 2_Gyro-NS-CT_Dnll pipe (1) 5,95000 39.69 66.80 4,397.24 4,358.84 687.72 3,624.26 2,389,299.74 276,333.47 4.75 3,499.41 2_Gym-NS-CT_Drill pipe (1) 5,975.00 38.52 65.58 4,416.64 4,378.24 694.09 3,638.69 2,389,305.82 276,348.02 5.60 3,515.11 2_Gyrc-NS-CT Drill pipe (1) 6,000.00 37.80 64.49 4,436.29 4,397.89 700.60 3,652.69 2,389,312.07 276,362.14 3.94 3,530.51 2Gyro-NS-CT_Dnll pipe (1) 6,025.00 37.07 64.29 4,456.14 4,41274 707.17 3,666.39 2,389,318.37 276,375.97 2.96 3,545.68 2_Gyro-NS-CT_Drift pip- (1) 6,050.00 35.27 64.11 4,476.33 4,437.93 713.59 3,679.68 2,389,324.54 276,389.37 7.21 3,560.41 2_Gyro-NS-CT_Drill pipe (1) 6,075.00 33.95 63.94 4,496.90 4,458.50 719.81 3,692.44 2,389,330.51 276,402.25 5.29 3,574.59 2_Gym-NS-CT_DH1I pipe (1) 6,100.00 32.73 63.71 4,517.79 4,479.39 725.87 3.704.77 2,389.336.33 276,414.70 4.91 3,588.31 2_Gyro-NS-CT_Drill pipe (1) 6,125.00 31.24 63.39 4,538.99 4,500.59 731.77 3,716.63 2,389,342.00 276,426.66 6.00 3,601.53 2_Gyro-NS-CT_Drill pipe (1) 6,150.00 30.16 62.42 4,560.49 4,522.09 737.58 3,727.99 2,389,347.60 276,438.13 4.75 3,614.29 2_Gyro-NS-CT_Drill pipe (1) 6,17500 29.05 61.16 4,582.22 4,543.82 743.42 3,738.88 2,389,353.22 276,449.13 5.09 3,626.64 2_Gyro-NSCT_Drill pipe (1) 6,200.00 27.98 59.27 4,604.19 4,565.79 749.34 3,749.23 2,389,358.95 276,459.60 5.60 3,638.57 2_Gyro-NS-CT Drill pipe (1) 6,225.00 27.12 57.14 4,626.36 4,587.96 755.43 3,759.06 2,389,364.84 276,469.54 5.23 3,650.12 2_Gym-NS-CT_Drill pipe (1) 6,250.00 26.32 54.80 4,648.69 4,610.29 761.72 3,768.38 2,389,370.95 276,478.97 5.29 3,661.32 2_Gyro-N6-CT_Ddll pipe (1) 6,275.00 25.34 52.41 4,671.19 4,632.79 768.18 3,777.15 2,389,377.24 276,487.87 5.72 3,672.12 2_Gyro-NS-CT_Drill pipe (1) 6,300.00 24.77 50.66 4,693.84 4,655.44 774.76 3,785.44 2,389,383.66 276,496.28 3.74 3,682.57 2_Gyro-NS-CT_DHII pipe (1) 6,325.00 24.19 48.37 4,716.59 4,678.19 781.48 3.793.31 2,389,390.23 276,504.29 4.45 3,692.73 2_Gyro-NS-CT_DnII pipe (1) 6,350.00 23.65 46.54 4,739.44 4,701.04 788.34 3,800.78 2,389,396.94 276,511.88 3.67 3.702.59 2Gyro-NS-CT_Drill pipe (1) 6,375.00 22.91 44.40 4,762.41 4,724.01 795.26 3,807.83 2,389,403.73 276,619.06 4.49 3,712.12 2_Gyro-NSCT_Drill pipe (1) 6.400.00 22.26 41.73 4,785.49 4,747.09 802.27 3,814.38 2,389,410.61 276,525.75 4.86 3,721.26 2_Gyro-NSCT_DHll pipe (1) 91252019 5:44:52PM Pape 8 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcom Alaska, LLC Local Coordinate Reference: Well Cannery Loop Unit 14 Proiect: Kenai C.I.U. TVD Reference: Plan @ 38.40usfl (HEC 169) Site: Cannery Loop Unit#1 Pad MD Reference: Plan @ 38.40usf1(HEC 169) Well; Cannery Loop Unit 14 North Reference: True Wellbore: Cannery Loop Unit 14 Survey Calculation Method: Minimum Curvature Design: CLU 14 Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azl TVD TVDSS +NIS +E/ -W Northing Fasting DLS Section (usft) (") (') (usft) (usft) (usft) (usft) /ft1 Ili (.110P) tft) Survey Tool Name 6,425.00 21.78 39.68 4,808.67 4,770,27 809.38 3,820.50 2,389,417.60 276,532.00 3.62 3,730.06 2_Gym-NS-CT_Dail pipe (1) 6,450.00 21.37 37.20 4,831.92 4,79352 816.57 3,826.21 2,389,424.69 276,537.85 4.00 3,738.56 2_Gyro-NS-CT_Drill pipe (1) 6,475.00 21.15 34.73 4,855.22 4,816.82 823.91 3,831.54 2,389,431.92 276,543.31 3.69 3,746.79 2_Gym-NS-CT_13611 pipe (1) 6,500.00 20.99 32.43 4,878.54 4,840.14 831.39 3,836.51 2,389,439.31 276,548.43 3.37 3,754.78 2_Gyro-NS-CT_Dr61 pipe (1) 6,525.00 20.49 28.52 4,901.93 4,863.53 839.02 3,841.00 2,389,446.84 276,553.06 5.89 3,762.41 2 -Gyro -NS -CT Drill pipe (1) 6,550.00 20.45 26.99 4,925.35 4,886.95 846.76 3,845.07 2,389,454.50 276,557.28 215 3,769.74 2_Gyro-NS-CT_Drill pipe (1) 6,575.00 20.17 24.28 4,948.79 4,910.39 854.58 3,848.82 2,389,462.25 276,561.18 3.93 3,776.83 2_Gyro-NS-CT_13rill pipe (1) 6,600.00 20.09 21.98 4,972.27 4,933.87 862.49 3,852.20 2,389,470.09 276,564.71 3.18 3,783.64 2_Gyro-NS-CT_Drill pipe (1) 6,625.00 20.03 19.98 4,995.75 4,957.35 870.49 3,85527 2,389,478.03 276,567.94 2.75 3,790.23 2_Gym-NS-CT_DNll pipe(1) 6,65000 19.90 15.22 5,019.25 4,980.85 878.62 3,857.85 2,389,486.11 276.570.67 6.52 3,796.44 2_Gym-NS-CT_Drill pipe (1) 6.675.00 19.90 13.29 5,042.76 5,004.36 886.87 3,859.95 2,389,494.32 276,572.92 2.63 3,802.29 2_Gym-NS-CT_Dnll pipe (1) 6,700.00 20.15 10.03 5,066.25 5,027.85 895.25 3.861.68 2,389,502.66 276,574.81 4.58 3,807.89 2_Gya NS-CT_DHll pipe (1) 6,725.00 20.30 7.53 5,089.71 5,051.31 903.79 3,862.99 2,389,511.18 276,576.30 3.51 3,813.21 2Gyro-NS-GT_Drill pipe (1) 6,750.00 20.45 5.70 5,113.14 5,074.74 912.43 3,864.00 2,389,519.80 276,5T7.46 2.62 3,818.30 2_Gym-NS-CT_Drill pipe (1) 6,775.00 20.16 1.77 5,136.59 5,098.19 921.09 3,864.56 2,389,528.44 276,578.20 5.58 3,823.01 2_Gyro-NS-CT_DH1l pipe (1) 6,800.00 20.20 359.84 5,16005 5,121.65 929.71 3,864.68 2,389,537.06 276,578.48 2.67 3,827.32 2_Gym-NS-CT_DHll pipe (1) 6,825.00 20.17 358.12 5,183.52 5,145.12 938.33 3,864.53 2,389,545.68 276,578.49 2.38 3,831.40 2_Gym-NS-CT_Drill pipe(/) 6,850.00 20.34 357.46 5,206.97 5,168.57 946.98 3,864.20 2,389,554.33 276,578.33 1.14 3,835.32 2_Gyro-NS-CT_DHll pipe (1) 6,875.00 2035 356.76 5,230.41 5,19201 955.66 3,863.76 2,389,563.02 276,578+05 0.97 3,839.17 2_Gyro-NS-CT_DHll pipe (1) 6,90000 20.48 356.75 5,253.84 5,215.44 964.37 3,863.27 2,389,571.74 276,577.73 0.52 3,842.99 2_Gym-NS-CT_DHll pipe (1) 6,925.00 20.53 356.11 5,277.26 5,238.86 973.11 3,862.72 2,389,580.48 276,577.35 0.92 3,846.77 2_Gyro-NS-CT_Ddil pipe (1) 6,950.00 20.48 353.12 5,300.68 5,262.28 981.82 3,861.90 2,389,589.21 276,576.70 4.19 3,850.31 2 Gyro-NS-CT_Drill pipe (1) 6,975.00 20.34 352.27 5,324.11 5,285.71 990.47 3,860.79 2,389,597.88 276,575.75 1.31 3,853.56 2_Gym-NS-CT_Drill pipe (1) 7,000.00 20.05 350.43 5,347.57 5,309.17 999.00 3,859.49 2,389,606.44 276.574.62 2.79 3,856.59 2_Gyro-NS-CT_DH1I pipe (1) 7,025.00 19.26 348.95 5,371.11 5,332.71 1,007.28 3,857.99 2,389,614.73 276,573.28 3.73 3,859.31 2_Gyro-NS-CT_Dnll pipe (1) 7,050.00 18.83 347.56 5,394.75 5,356.35 1,015.26 3.856.33 2,389,622.75 276,571.n 2.50 3,861.76 2_Gyro-NS-CT_Drill pipe(1) 7,075.00 17.83 344.45 5,418.48 5,380.08 1,022.89 3,854.44 2,389,630.41 276,570.02 5.59 3,863.82 2_Gyro-NS-CT_Dn11 pipe (1) 7,100.00 17.42 343.21 5,442.30 5,403.90 1,030+16 3,852.33 2,389,637.72 276,568.06 2.22 3,865.53 2_Gyro-NS-CTDrill pipe (1) 7,125.00 16.83 340.74 5,466.20 5,427.80 1,037.16 3,850.05 2,389,644.76 276,565.92 3.75 3,866.96 2_Gym-NS-CT_DHll pipe(1) 7,150.00 16.55 340.16 5,490.14 5,451.74 1,043.93 3,847.65 2,389,651.57 276,563.64 1.30 3,868.16 2_Gyro-NS-CTDnll pipe (1) 7,175.00 16.52 339.75 5,514.11 5,475.71 1,050.61 3,845.21 2,389,658.30 276,561.33 0.48 3,869.29 2_Gyro-NS-CT_Drill pipe (i) 7,200.00 16.55 339.17 5,538.07 5,499.67 1,057.27 3,842.72 2,389,665.01 276,558.97 0.67 3,870.36 2_Gym-NS-CT_Drill pipe (1) 7,225.00 16.66 338.76 5,562.03 5,523.63 1,063.94 3,840.15 2,389,671.73 276,556.53 0.64 3,871.37 2_Gym-NS-CT_D611 pipe (1) 7,250.00 16.71 338.08 5,585.98 5,547.58 1,070.61 3,837.51 2,389,678.45 276,554.02 0.81 3,872.32 2_Gyro-NS-CT_DHII pipe (1) 7,275.00 16.81 337.42 5,609.92 5,571.52 1,077.29 3,634.78 2,389,685.18 276,551.42 0.86 3,873.19 2 Gym-NS-CT_DHII pipe (1) 7,300.00 16.40 336.41 5,633.87 5,595.47 1,083.86 3,831.98 2,389,691.80 276,548.74 2.01 3,873.95 2_Gyro-NS-CT DHII pipe (1) 7,325.00 16.15 335.89 5,657.87 5,619.47 1,090.27 3,829.15 2,389,698.26 276,546.03 1.16 3,874.61 2_Gyro-NS-CT_Dn1l pipe (1) 7,350.00 16.06 334.90 5,681.89 5,64349 1,096.57 3,826.26 2,389,704.62 276,543.27 1.16 3,875.16 2_Gym-NS-CT_DHll pipe (1) 7,375.00 16.14 334.46 5,705.91 5,667.51 1,1D2.84 3,823.30 2,389,710.94 276,540.42 0.58 3,875.63 2_Gym-NS-CT_pill pipe (1) 7,400.00 16.16 333.53 5,729.92 5,691.52 1,109.09 3,820.25 2,389,717.25 276,537.50 1.04 3,876.01 2_Gyro-NS-CT_DHll pipe (1) 9/25/2019 5:44:52PM Pam 9 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Companv: Proiect; Site; Well: Wellbore: Design: Hilcorp Alaska, LLC Kenai C.I.U. Cannery Loop Unit 111 Pad Cannery Loop Unit 14 Cannery Loop Unit 14 CLU 14 Local Coordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well Cannery Loop Unit 14 Plan @ 38.40usft (HEC 169) Plan @ 38.40usft (HEC 169) True Minimum Curvature NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/,S +E/ -W Northing Easting DLS Section (usft) (1) (') (usft) (usft) (usft) (usft) Ike (k) (91001 Ift) Survey Tool Name 7,425.00 16.15 332.71 5,753.94 5,715.54 1,115.29 3,817.10 2,389,723.51 276,534.47 0.91 3,876.30 2_Gym-NS-GT_Drill pipe (1) 7,450.00 16.11 332.20 5,777.95 5,739.55 1,121.45 3,813.89 2,389,729.73 276,531.38 0.59 3,876.49 2_Gyro-NS-CT_Dnll pipe (1) 7,475.00 15.79 33147 5,801.99 5,763.59 1,127.51 3,810.65 2,389,735.85 276,528.25 1.51 3,876.62 2_Gyro-NS-CT_Drill pipe (1) 7,500.00 15.15 332.73 5,826.09 5,767.69 1,133.40 3,807.53 2,389,741.80 276,525.24 2.69 3,876.77 2_Gyro-NS-CT_Drill pip. (1) 7,525.00 14.92 334.04 5,850.23 5,811.83 1,139.20 3.804.62 2,389,747.65 276,522.45 1.64 3,877.06 2_Gyro-NS-CT_Drill pipe (1) 7,55000 14.83 336.41 5,874.39 5,835.99 1,145.02 3,801.93 2,389,753.53 276,519.87 2.46 3,877.55 2_Gyro-NS-CT_Dnll pipe (1) 7,575.00 14.91 337.87 5,898.55 5,860.15 1,150.93 3,799.44 2,389,759.48 276,517.50 1.53 3,878.26 2_Gyro-NSCT_Dnli pipe (1) 7,600.00 14.91 337,98 5,922.71 5,884.31 1,156.89 3,797.02 2,389,765.49 276,515.19 0.11 3,879.06 2_Gym-NS-CT_Dill pipe (1) 7,625.00 14.70 339.80 5,946.88 5,908.48 1,162.85 3,794.72 2,389,771.49 276,513.01 2.04 3,879.95 2_Gym-NS-CT_Drill pipe (1) 7,650.00 14.84 340.38 5,971+06 5,93266 1,168.85 3,792.55 2,389,777.52 276,510.95 0.81 3,880.98 2_Gym-NSCT_Drill pipe (1) 7,675.00 14.76 342.62 5,995.23 5,95693 1,174.90 3,790.53 2,389,783.62 276,509.04 2.31 3,882.16 2_Gym-NSCT_Dn1l pipe (1) 7,700.00 14.80 343.47 6,019.40 5,981.00 1,181.00 3,788.67 2,389,789.75 276,507.30 0.88 3,883.52 2_Gym-NSCT_Dill pipe (1) 7,725.00 14.95 343.40 6,043.56 6,005.16 1,187.15 3,786.84 2,389,795.94 276,505.59 0.60 3,884.92 2_Gym-NS-CT_Drill pipe (1) 7,750.00 15.06 343.37 6,067.71 6,029.31 1,193.35 3,784.99 2,389.802.17 276,503.86 0.44 3,886.33 2_Gyro-NS-CT_Dn1l pipe (1) 7,775.00 15.02 343.60 6,091.65 6,053.45 1,199.57 3,783.14 2,389,808.43 276,502.13 0.29 3,887.75 2_Gym-NS-CT_Ddll pipe (1) 7,800.00 14.87 342.65 6,116.01 6,077.61 1,205.74 3,781.27 2,389,814.63 276,500.38 1.15 3,889.13 2_Gym-NS-CT_Dell pipe (1) 7,825.00 14.93 342.45 6,140.17 6,101.77 1,211.88 3,779.34 2,389,820.80 276,498.57 0.32 3,890.43 2_Gym-NS-CT_Dnll pipe (1) 7,850.00 14.87 341.77 6,164.33 6,125.93 1,217.99 3,777.37 2,389,826.95 276,496.71 0.74 3,891.69 2_Gym-NS-CT_Dn1l pipe (1) 7,875.00 14.69 341.33 6,188.50 6,150.10 1,22404 3,775.35 2,389,833.04 276,494.81 0.85 3,892.88 2_GWc-NS-CT_Drill pipe (1) 7,900.00 14.76 341.13 6,212.68 6,174.28 1,230.06 3,773.31 2,389,839.09 276,492.88 0.35 3,894.03 2_Gyro-NS-CT_Dnll pipe (1) 7,925.00 14.93 340.98 6,236.84 6,198.44 1,236.12 3,771.23 2,389,845.19 276,490.92 0.70 3,895.17 2_Gyro-NS-CT_Dnll pip. (1) 7,950.00 15.20 341.95 6,260.99 6,222.59 1,242.28 3,769.16 2,389,851.39 276,488.97 1.48 3,896.37 2_Gyro-NS-CT_Drill pip. (1) 7,975.00 15.35 342.56 6,285.10 6,246.70 1,248.55 3,767.15 2,389,657.70 276,487.09 0.88 3,897.68 2_Gym-NS-CT_Dnll pipe (1) 8,000.00 15.85 342.21 6,309.18 6,270.78 1,254.96 3,765.12 2,389,864.14 276,485.18 2.04 3,899.03 2_Gym-NSCT_Dn1l pipe (1) 8,025.00 16.11 342.03 6,333.22 6,294.82 1,261.51 3,763.01 2,389,870.73 276,483.19 1.06 3,900.38 2_Gym-NSCT_Drill pip. (1) 8,050.00 16.32 341.36 6,357.22 6,318.82 1,268.14 3,760.81 2,389,877.40 276,481.12 1.13 3,901.70 2_Gyro-NSCT_Drill pipe (1) 8,075.00 16.50 340.61 6,381.20 6,342.80 1,274.81 3,758.51 2,389,884.12 276,478.95 1.11 3,902.94 2_Gyro-NS-CT_Dnll pipe (1) 8,100.00 16.50 340.10 6,405.17 6,366.77 1,281.50 3,756.12 2,389.890.85 276,476.69 0.58 3,904.12 2 Gym-NSCT_Dill pipe (1) 8,125.00 16.41 339.38 6,429.15 6,390.75 1,288.15 3,753.67 2,389,897.54 276,474.37 0.89 3,905.22 2_Gyro-NS-GT_D611 pipe (1) 8,150.00 16.20 338.66 6,453.14 6,414.74 1,294.70 3,751.16 2,389,904.14 276,471.98 1.17 3,906.22 2_Gym-NS-CT_Dn1l pipe (1) 8,175.00 16.06 338.17 6,477.16 6,438.76 1,301.16 3,748.60 2,369,910.65 276,469.55 0.78 3,907.14 2_Gyro-NS-CT_Dri1l pip. (1) 8,200.00 15.79 337.63 6,501.20 6,462.80 1,30252 3,746.04 2,389,917.06 276,467.10 1.14 3,908.00 2_Gyro-NS-CT_Dill pipe (1) 8,225.00 15.68 337.64 6,525.26 6,486.86 1,313.79 3,743.47 2,389,923.38 276,464.66 0.49 3,908.82 2_Gyro44S-CT_Drill pipe (1) 8,250.00 15.37 336.65 6,549.35 6,510.95 1,319.96 3,740.87 2,389,929.59 276,462.18 1.63 3,909.56 2 Gyro-NS-CT_Drill pipe (1) 8,275.00 15.39 336.41 6,573.46 6,535.06 1,326.04 3,738.23 2,389,935.72 276,459.65 0.27 3,910.22 2_Gym-NS-CT_Dill pipe (1) 8,300.00 15.53 337.10 6,597.55 6,559.15 1,332.16 3,735.60 2,389,941.90 276,457.14 0.92 3,910.91 2_Gym-NSCT_Drill pipe (1) 8,325.00 15.68 338.20 6,621.63 6,583.23 1,338.38 3,733.04 2,389,948.16 276,454.70 1.33 3,911.71 2_Gym-NSCT_Drlll pipe (1) 8,35000 15.81 338.71 6,645.69 6,607.29 1,344.69 3,730.55 2,389,954.52 276,452.33 0.76 3,912.61 2_Gym-NSCT_Drill pipe (1) 8,375.00 16.11 340.14 6,669+73 6,631.33 1,351.13 3,728.13 2,389,961.00 276,450.04 1.98 3,913+64 2_Gyro-NS-CT_Dn1l pipe (1) 8,400.00 16+03 341.05 6.693.75 6,65535 1,357.65 3,725.84 2,389,967.57 276,447.87 1.06 3,914.82 2_Gyra-NS-CT_Drill pipe (1) 9/25/2019 5:44:52PM Pace 10 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well Cannery Loop Unit 14 Project: Kenai C.I.U. TVD Reference: Plan @ 38.40usft (HEC 169) Site: Cannery Loop Unit #1 Pad MD Reference: Plan @ 38.40usft (HEC 169) Well: Cannery Loop Unit 14 North Reference: True Wellbore: Cannery Loop Unit 14 Survey Calculation Method: Minimum Curvature Design: CLU 14 Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +EI -W Northing Easting DLS Section (usft) (1) r) (usft) (usft) (usft) (usft) (ft1 !ftl (-Ilan-) fR) Survey Tool Name 8,425.00 16.04 342.60 6,717.78 6,679.38 1,364.21 3,723.68 2,389,974.17 276,445.84 1.71 3,916.14 2_Gyro-NS-CT_Drill pipe (1) 8,450.00 15.94 344.92 6,741.81 6,703.41 1,370.83 3,721+76 2,389,980.82 276,444.04 2.59 3,917.68 2_Gyro-NS-CT_0611 pipe (1) 8,475.00 16.07 345.51 6,765.84 6,727.44 1,377.49 3,720.00 2,389,987.51 276,442.41 0.83 3,919.40 2_Gym-NS-CT_Dnll pipe (1) 8,500.00 16.77 346.90 6,789.82 6,751.42 1,384.35 3,718.31 2,389,994.41 276,440.86 3.21 3,921.27 2_Gym-NS-CT_Drill pipe (1) 8,525.00 17.19 347.23 6,813.73 6,775.33 1,391.47 3,716.68 2,390,001.55 276,439.36 1.72 3,923.32 2_Gyra-NS-CT_Drill pipe (1) 8,550.00 17.17 347.08 6,837.62 6,79922 1,398.67 3,715.04 2,390,008.78 276,437.86 0.19 3,925.40 2_Gym-NS-CT_Dnll pipe (1) 8,575.00 17.14 345.96 6,861.51 6,823.11 1,405.84 3,713.32 2,390,015.98 276,436.28 1.33 3,927.39 2_Gyro-NS-CT_Drill pipe (1) 8,60000 16.99 34515 6,88540 6,847.00 1,412.95 3,711.53 2,390,023.13 276,434.62 0.65 3,929.30 2_Gyro-NS-CT_Ddll pipe (1) 8,625.00 16+71 345.56 6,909.33 6,870.93 1,419.97 3,709.73 2,390,030.18 276,432.96 1.14 3,931.15 2_Gyro-NS-CT_DrIl pipe (1) 8,650.00 16.27 344.93 6,933.30 6,894.90 1,426.84 3,707.92 2,390,037.08 276,431.29 1.90 3,932.92 2_Gyro-NS-CT_DHII pipe (1) 8,675.00 16.01 344.13 6,957.32 6,918.92 1,433.53 3,706.07 2,390,043.81 276,429.57 1.37 3,934.57 2_Gyn NS-CT_DNII pipe (1) 8,700.00 15.59 344.13 6,981.37 6,942.97 1,440.08 3,704.21 2,390,050.39 276,427.83 1.68 3,936.14 2_Gyn,NS-CT_Dnll pipe (1) 8,725.00 15.81 344.10 7,005.44 6,967.04 1,446.59 3,702.36 2,390,056.93 276,426.10 0.88 3,937.70 2_Gyn NS-CT_Drill pipe (1) 8,750.00 16.19 343.99 7,029.47 6,991.07 1,453.21 3,700.46 2,390,063.59 276,424.34 1.52 3,939.27 2_Gyn NS-CT_Drill pipe (1) 8,775.00 16.71 343.09 7,053.45 7,015.05 1,460.00 3,698.46 2,390,070.42 276,422.46 2.32 3,940.83 2_Gyro-NS-CT_Drill pipe (1) 8,800.00 17.38 342.20 7,077.35 7,038.95 1,467.00 3,696.27 2,390,077.45 276,420.41 2.88 3,942.33 2_Gyro-NS.CT_Drill pipe (1) 8,825.00 17.60 341.12 7,101.19 7,062.79 1,474.13 3,693.91 2,390,084.63 276,418.18 1.57 3,943.75 2_Gyro-NS-CT_Drill pipe (1) 8,850.00 17.46 339.97 7,125.03 7,086.63 1,481.23 3,691.40 2,390,091.77 276,415.81 1.49 3,945.02 2_Gymo NS -CT Drill pipe (1) 8,875.00 17.17 339.82 7,148.90 7,110.50 1,488.21 3,688.84 2,390,098.81 276,413.39 1.17 3,946.20 2_Gyro-NS-CT_Dnll pipe (1) 8,900.00 16.72 339.57 7,172.82 7,134.42 1,495.05 3,68631 2,390,105.69 276,410.99 1.82 3,947.32 2_Gyro-NS-CT_Dnll pipe (i) 8,925.00 16.94 339.51 7,196.74 7,158.34 1,501.83 3,683.78 2,390,112.52 276,408.59 0.88 3,948.42 2_Gyro-NS-CT_DOI]pipe(1) 8,95000 17.13 338.95 7.220+65 7,182.25 1,508.68 3,681.18 2,390,119.41 276,406.13 1.00 3,949.49 2_Gym.NS-CT_Drill pipe (1) 8,975.00 16.86 338.61 7,244.56 7,206.16 1,515.49 3,678.54 2,390,126.28 276,403.61 1.15 3,950.51 2_Gym-NS-CT_Drill pipe (1) 9,000.00 16.53 338.39 7,268.50 7,230.10 1,522.17 3,675.91 2,390,133.01 276,401+11 1.34 3,951.47 2Gyro-NS-CT_Drill pipe (1) 9,025.00 16.15 338.04 7,292.49 7,254.09 1,528.70 3,673.30 2,390,139.59 276,398.62 1.57 3,952.37 2_Gyro-NS-CT_Dnil pipe (1) 9,050.00 16.28 338.66 7,316.50 7,278.10 1,535.19 3,670.72 2,390,146.12 276,396.17 0.87 3,953.29 2_Gyro-NS-CT_Drill pipe (1) 9,075.00 16.54 339.34 7,340.48 7,302.08 1,641.78 3,668.79 2,390,152.76 276,393.77 1.29 3,954.30 2_Gyro-NS-CT_Drill pipe (1) 9,100.00 16.50 340.22 7,364.45 7,326.05 1,548.46 3,665.73 2,390,159.48 276,391.44 1.01 3,955.41 2_Gyro-NS-CT_Drill pipe (1) 9,125.00 16.76 341.41 7,388.40 7,350.00 1,555.21 3,663.38 2,390,166.26 276,389.22 1.71 3,956.65 2_Gyro-N&CT_DHII pipe (1) 9,150.00 16.69 341.83 7,412.34 7,373.94 1,562.04 3,661.12 2,390,173.15 276,387.08 0.56 3,958.00 2_Gym-NS-CT_Drill pipe (1) 9,175.00 16.88 341.78 7,436.28 7,397.88 1,568.90 3.658+86 2,390,180.05 276,384.96 0.75 3,959.38 2_Gyro-NS-CT_Dull pe (1) 9,200.00 16.91 341.34 7,460.20 7,421.80 1,575.79 3,658.56 2,390,186.98 276,382.80 0.53 3,960.73 2_Gyro-NS-CT_Dill pipe (1) 9,225.00 16.90 340.80 7,484.12 7,445.72 1,58267 3,654.20 2,390,193.91 276,380.57 063 3,962.03 2_Gyro-NS-CT_COO pipe (1) 9,250.00 17.51 339.79 7,508.00 7,469.60 1,589.63 3,651.71 2,390,200.91 276,378.21 2.72 3,963.24 2_GyroNS-CT_Ont pipe(1) 9,275.00 17.77 338.41 7,531.83 7,493.43 1,596.71 3,649.01 2,390,208.04 276,375.64 1.97 3,964.33 2_Gyro-NS-CT_Drill pipe (1) 9,300.00 17.41 337.42 7,555.66 7,517.26 1,603.71 3,646.17 2,390,215.09 276,372.94 1.87 3,965.27 2_Gyro-NS-CT_Drill pipe (1) 9,325.00 17.05 336.62 7,579.53 7,541.13 1,610.52 3,643.28 2,390,221.96 276,370.18 1.72 3,966.07 2_Gy.NS-CT_Drill pipe (1) 9,350.00 16.53 336.98 7,603.47 7,565.07 1,617.16 3,640.43 2,390,228.65 276,367.46 2.12 3,966.82 2_Gyrc-NS-CT_Dnll pipe (1) 9,375.00 16.11 336.82 7,627.46 7,589.06 1,623.62 3,637.68 2,390,235.17 276,364.83 1.69 3,967.57 2_Gyrc-NS-CT_Will pipe (1) 9,400.00 15.63 336.04 7,651.51 7,613.11 1,629.89 3,634.94 2,390,241.49 276,362.22 2.10 3,968.24 2_Gyro-NS-CT_Drill pipe (1) 9/25/2019 5:44:52PM Pape 11 COMPASS 5000.15 Build 91 Company: Hilcorp Alaska, LLC Project: Kenai C.I.U. Site: Cannery Loop Unit #1 Pad Well: Cannery Loop Unit 14 Wellbore: Cannery Loop Unit 14 Design: CLU 14 Survey MD Inc Azi TVD TVDSS (usft) (I (°) (usft) (usft) 9,425.00 15.46 335.58 7,675.59 7,637.19 9,450.00 15.08 335.38 7,699.71 7,661.31 9,475.00 14.58 334.66 7,723.88 7,685.48 9,500.00 14.15 334.70 7,748.10 7,709.70 9,525.00 13.81 334.40 7,772.36 7,733.96 9,550.00 13.35 334.30 7,796.66 7,758.26 9575.00 12.98 333.62 7,821.00 7,782.60 9,600.00 12.55 333.01 7,645.38 7,806.98 9,625.00 12.12 332.84 7,869.81 7,831.41 9,649.00 11.70 332.80 7,893.29 7,854.89 9,802.00 11.70 332.80 8,043.11 8,0(4.71 Halliburton Definitive Survey Report -NIS (usft) 1,636.00 1,641.99 1,647.79 1,653.40 1,658.85 1,664.14 1,669.26 1,674.19 1,678.95 1,683.36 1,710.95 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well Canner/ Loop Unit 14 Plan @ 38.40usft (HEC 169) Plan @ 38.40usft (HEC 169) True Minimum Curvature NORTH US + CANADA Checked By: Benjamin Hand�-_'•"`-_ Approved By: Chelsea Wright ; Date: 9/25/2019 9/25/2019 5:44:52PM Pace 12 COMPASS 5000.15 Build 91 Map Map Vertical +E/ -W Northing Easting DLS Section (usft) Ift1 fftt (°/100-) ft Survey Tool Name 3,632.20 2,390,247.65 276,359.59 0.84 3,968.82 2_Gyro-NS-CT_Dnll pipe (1) 3,629.46 2,390,253.69 276,356.97 1.53 3,969.36 2 Gyre-NS-CT_DO pipe (1) 3,626.76 2,390,259.54 276,354.38 2.13 3,969.83 2_Gy10-NS-CT_Drill pipe (1) 3,624.11 2,390,265.20 276,351.84 1.72 3,970.25 2_GyroNS-CT_Dn1l pipe (1) 3,621.52 2,390,270.70 276,349.35 1.39 3,970.64 2_Gyu NS-GT_Drill pipe (1) 3,618.97 2,390,276.04 276,346.91 1.84 3,971.01 2_Gyro-NS-CT_DO pipe (1) 3,616.48 2,390,281.20 276,344.51 1.60 3,971.32 2_Gyro-NS-CT_Drill pipe (1) 3,614.00 2,390,286.18 276,342.13 1.80 3,971.56 2_Gyro-NS-CT_Dn1l pipe (1) 3,611.55 2,390,290.98 276,339.79 1.73 3,971.76 2_Gyn,NS-CT_Ddil pipe (1) 3,609.30 2,390,295.43 276,337.61 1.75 3,971.93 2_Gyro-NS-CT_Ddll pipe (1) 3,595.12 2,390,323.29 276,323.96 0.00 3,973.01 PROJECTEDto TD Checked By: Benjamin Hand�-_'•"`-_ Approved By: Chelsea Wright ; Date: 9/25/2019 9/25/2019 5:44:52PM Pace 12 COMPASS 5000.15 Build 91 Lease & Well No. County Hilcorp Energy Company CASING & CEMENTING REPORT CLU 014 KPB State Alaska Supv. CASING RECORD Surface � TO 3,346.00 Shoe Depth: 3,333.14 No. Jts. Delivered 86 No. Jts. Run PBTD: Date Run 30Jul-19 R Pederson / B Davis 81 No. Jts. Returned 5 Csg Wt. On Hook: 140,000 Csg Wt. On Slips: 95,000 Rotate Csg Yes X No Fluid Description: Spud Mud Liner hanger Info (Make/Model): Liner hanger test pressure: Centralizer Placement: Type Float Collar: Weatherford Type of Shoe: Bullnose _ Recip Csg X Yes No No. Hrs to Run: Casing Crew: 10 Ft. Min. Liner top Packer?: Floats Held 12 1/JnelFnrinM 9.1 PPG Yes X No X Yes No Casing (Or Liner) Detail Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top Shoe 113/4 1 TXP BTC I Weatherford 1.88 3,333.14 3,331.26 2 Casing 103/4 45.5 L-80 TXP BTC Tenaris 82.25 3,331.26 3,249.01 Float Collar 113/4 TXP BTC Weatherford 1.50 3,249.01 3,247.51 79 Casing 103/4 45.5 L-80 TXP BTC Tenaris 3,227.23 3,247.51 21.00 Emergency Slips 16 1 Cactus 0.80 23.40 22.60 Csg Wt. On Hook: 140,000 Csg Wt. On Slips: 95,000 Rotate Csg Yes X No Fluid Description: Spud Mud Liner hanger Info (Make/Model): Liner hanger test pressure: Centralizer Placement: Type Float Collar: Weatherford Type of Shoe: Bullnose _ Recip Csg X Yes No No. Hrs to Run: Casing Crew: 10 Ft. Min. Liner top Packer?: Floats Held 12 1/JnelFnrinM 9.1 PPG Yes X No X Yes No Spud Mud Density (ppg) 9.1 Rate (bpm): 5 Volume (actual / calculated): 312/313 (psi): 675 Pump used for disp: Halliburton Bump Plug? X Yes No Bump press 1352 ig Rotated? _Yes X No Reciprocated? X Yes _No % Returns during job 100 ant returns to surface? X Yes _ No Spacer returns? X Yes —No Vol to Surf: 92 ent In Place At: 2:10 Date: 7/31/2019 Estimated TOC: 23 od Used To Determine TOC: Returns to Surface Post Job Calculations: Calculated Cmt Vol @ 0% excess: 221.01 Total Volume cmt Pumped: _ Cmt returned to surface: 92 Calculated cement left in wellbore: 237 OH volume Calculated: 210.34 OH volume actual: 225 Actual % Washout: www.weliez.net WellEz Information Management LLC ver KY�9 .r`i I eM CEMENTING REPORT Shoe @ 3333.14 FC @ 3,247.51 Top of Liner Preflush (Spacer) Type: Clean Spacer Density (ppg) 10.5 Volume pumped (BBLs) 55 Lead Slurry I Type: Vedcem Lead Sacks: 640 Yield: 2.41 Density (ppg) 12 Volume pumped (BBLs) 272 Mixing / Pumping Rate (bpm): 5 Tail Slurry i w Type: Swift Cam Tail Sacks: 270 Yield: 1.18 Density (ppg) 15.8 Volume pumped (BBLs) 57 Mixing / Pumping Rate (bpm): 4 w r Post Flush (Spacer) rc Type: Density (ppg) Rate (bpm): Volume: LL Spud Mud Density (ppg) 9.1 Rate (bpm): 5 Volume (actual / calculated): 312/313 (psi): 675 Pump used for disp: Halliburton Bump Plug? X Yes No Bump press 1352 ig Rotated? _Yes X No Reciprocated? X Yes _No % Returns during job 100 ant returns to surface? X Yes _ No Spacer returns? X Yes —No Vol to Surf: 92 ent In Place At: 2:10 Date: 7/31/2019 Estimated TOC: 23 od Used To Determine TOC: Returns to Surface Post Job Calculations: Calculated Cmt Vol @ 0% excess: 221.01 Total Volume cmt Pumped: _ Cmt returned to surface: 92 Calculated cement left in wellbore: 237 OH volume Calculated: 210.34 OH volume actual: 225 Actual % Washout: www.weliez.net WellEz Information Management LLC ver KY�9 .r`i I eM Lease & Well No. County KPB Hilcorp Energy Company CASING & CEMENTING REPORT State Alaska Supv. CASING RECORD Intermediate � Tn A Au no Fhnc ncnth A A94 49 PBTD: Date Run 8 -Aug -19 R Pederson / J Richardson Csg Wt. On Hook: 125,000 Type Float Collar: Halliburton No. Hrs to Run: Casing (Or Liner) Detail Csg Wt. On Slips: Type of Shoe: Bullnose Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top _Yes X No Shoe 85/8 Floats Held X Yes _ No Wedge 563 Halliburton 2.38 6,824.42 6,822.04 2 Casing 75/8 29.7 L-80 Wedge 563 Tenaris 80.95 6,822.04 6,741.09 Float Collar 85/8 Wedge 563 Halliburton 2.46 6,741.09 6,738.63 96 Casing 75/8 29.7 L-80 Wedge 563 Tenaris 3,902.46 6,738.63 2,836.17 -DARIQL' t 75/8 29.7 L-80 Wedge 563 Tenaris 3.87 2,836.17 2,832.30 'W Packer 95/8 Wedge 563 Baker 11.74 2,832.30 2,820.56 Pup Joint 75/8 29.7 L-80 Wedge 563 Tenaris 4.36 2,820.56 2,816.20 69 Casing 7 5/8 29.7 L-80 Wedge 563 Tenaris 2,793.59 2,816.20 22.61 Pup Joint 75/8 29.7 L-80 Wedge 563 Tenaris 1.15 22.61 20.50 Hanger 103/4 1 Acme 0.96 21.46 20.50 Csg Wt. On Hook: 125,000 Type Float Collar: Halliburton No. Hrs to Run: 12.5 Csg Wt. On Slips: Type of Shoe: Bullnose Casing Crew: Weatherford Rotate Csg Yes X No Recip Csg _ Yes X No Ft. Min. 9.3 PPG Fluid Description: 6% KCL w Type: Class A Liner hanger Info (Make/Model): Liner top Packer9: _Yes X No Liner hanger test pressure: g Floats Held X Yes _ No Centralizer Placement: 1 per joint, first 55 jnts, 1 every 4th joint for 18 jnts, total 73 centralizers. L.I CEMENTING REPORT FC @ 6,738.00 Top of Liner Density (ppg) 10.5 Volume pumped (BBLs) 39 Sacks: 400 Yield: Volume pumped (BBLs) 159 Mixing / Pumping Rate (bpm): Sacks: 260 Yield: Volume pumped (BBLs) 59.3 Mixing / Pumping Rate (bpm): Density (ppg) Rate (bpm): Volume: 5.5 3.5 : 6% KCL PHPA Density (ppg) Shoe @ 6824 6 Volume (actual / calculated): Preflush (Spacer) (psi): 1080 Pump used for disp: Type: Bump Plug? X Yes No Lead Slurry 1g Rotated? _Yes X Type: Class Yes X No % Returns during job Density (ppg) 12 ant returns to surface? Tail Slurry w Type: Class A _Yes ant In Place At: 2:45 Density (ppg) 15.3 w Post Flush (Spacer) g Type: LL S �� CEMENTING REPORT FC @ 6,738.00 Top of Liner Density (ppg) 10.5 Volume pumped (BBLs) 39 Sacks: 400 Yield: Volume pumped (BBLs) 159 Mixing / Pumping Rate (bpm): Sacks: 260 Yield: Volume pumped (BBLs) 59.3 Mixing / Pumping Rate (bpm): Density (ppg) Rate (bpm): Volume: 5.5 3.5 : 6% KCL PHPA Density (ppg) 9.3 Rate (bpm): 6 Volume (actual / calculated): 305/309 (psi): 1080 Pump used for disp: Halliburton Bump Plug? X Yes No Bump press 1 1g Rotated? _Yes X No Reciprocated? Yes X No % Returns during job 85 ant returns to surface? X No Spacer returns? _Yes X No Vol to Surf: _Yes ant In Place At: 2:45 Date: 8/9/2019 Estimated TOC: 2,800 ad Used To Determine TOC: CBL �(�T 1 C�...r_ T44,1 --st S �� L.I A4D Post Job Calculations: Calculated Cmt Vol @ 0% excess: 163.8 Total Volume cmt Pumped: 218.3 Cmt returned to surface: 0 Calculated cement left in wellbore: 218.3 OH volume Calculated: 133 OH volume actual: 146.9 Actual % Washout: 10 www.weliez.net WellEz Information Management LLC ver 04818br Hilcorp Energy Company CASING R CEMENTING REPORT Lease 8 Well No. Type Float Collar: Innovex CLU 014 Casing (Or Liner) Detail Csg Wt. On Slips: Date Run 1&Aug-19 County KPB State Alaska Sup, JRiley /J Richardson THD Make CASING RECORD Bottom Top Liner lop Packer?: Shoe Liner � Floats Held TXP BTC TO 9,802.00 Shoe Depth: 9,800.00 9,800.00 PBTD: Liner 41/2 No. As. Delivered 125 No. Jts. Run 101 No. As. Returned 24 9,798.65 Fig. Delivered 5,124.00 Fig. Run 4,390.00 Fig. Returned 984.00 Length Measurements W/O Threads Fig. Cut JL Innovex Ftg. Balance 9,715.96 9,714.57 RKB 18.00 RKB to BHF 21.56 IRKS to CHF L-80 RKB to THF Csg Wt. On Hook: 35,000 Type Float Collar: Innovex No. Hrs to Run: Casing (Or Liner) Detail Csg Wt. On Slips: Type of Shoe: Innovex Setting Depths As. Component Size Wt. Grade THD Make Length Bottom Top Liner lop Packer?: Shoe 5 r m Floats Held TXP BTC Innovex 1.35 9,800.00 9,798.65 2 Liner 41/2 12.6 L-80 TXP BTC Tenaris 82.69 9,798.65 9,715.96 FCP (psi): 1150 Float collar 5 Casing Rotated? TXP BTC Innovex 1.39 9,715.96 9,714.57 1 Liner 41/2 12.6 L-80 TXP BTC Tenaris 41.46 9,714.57 9,673.11 Ball catcher 41/2 TXP BTC Baker 1.13 9,673.11 9,671.98 Landing collar 5 TXP BTC Baker 1.06 9,671.98 9,670.92 8 Liner 41/2 12.6 L-80 TXP BTC Tenaris 323.96 9,670.92 9,346.96 1 RA -A marker 41/2 12.6 L-80 TXP BTC Tenaris 40.95 9,346.96 9,306.01 12 Liner 41/2 12.6 L-80 TXP BTC Tenaris 495.16 9,306.01 8,810.85 1 RA -B marker 41/2 12.6 L-80 TXP BTC Tenaris 41.48 8,810.85 8,769.37 11 Liner 41/2 12.6 L-80 TXP BTC Tenaris 451.55 8,769.37 8,317.82 1 RA -C marker 41/2 12.6 L-80 TXP BTC Tenaris 39.82 8,317.82 8,278.00 11 Liner 41/2 12.6 L-80 TXP BTC Tenaris 448.70 8,278.00 7,829.30 1 RA -D marker 41/2 12.6 L-80 TXP BTC Tenaris 40.83 7,829.30 7,788.47 11 Liner 41/2 12.6 L-80 TXP BTC Tenaris 448.15 7,788.47 7,340.32 1 RA -E marker 41/2 12.6 L-80 TXP BTC Tenaris 40.81 7,340.32 7,299.51 12 Liner 41/2 12.6 L-80 TXP BTC Tenaris 489.54 7,299.51 6,809.97 1 RA -F marker 41/2 12.6 L-80 TXP BTC Tenaris 40.99 6,809.97 6,768.98 33 Liner 41/2 12.6 L-80 TXP BTC Tenaris 1,359.01 6,768.98 5,409.97 Flex -lock linerhange 7 4.5 TXP Baker 37.51 5,409.97 5,372.46 Csg Wt. On Hook: 35,000 Type Float Collar: Innovex No. Hrs to Run: 14 Csg Wt. On Slips: Type of Shoe: Innovex Casing Crew: Weatherford Rotate Csg Yes X No Recip Csg Yes X No 70 Fl. Min. 9.6 PPG Fluid Description: 6% KCL PHPA Type: Class Sacks: 85 Yield:_ Liner hanger Info (Make/Model): Flex -lock liner hanger Liner lop Packer?: X Yes No Liner hanger test pressure: r m Floats Held X Yes _ No Centralizer Placement: Ran 107 centralizers rc Type: Density (ppg) CEMENTING REPORT Shoe @ 9800 FC @ 9,714.57 Top of Liner 5372.46 ush (Spacer) Spacer Density (ppg) 10.5 Volume pumped (BBLs) Post lob Calculations: Calculated Cmt Vol @ 0% excess: W Total Volume cmt Pumped: 147.9 Cml returned to surface: 1 Calculated cement left in wellbore: 146.9 OH volume Calculated: 131.7 OH volume actual: 144.8 Actual % Washout: 10 www.wellez.net WeIIEZ Information Management LLC ver_04818br 25 Type: Class Sacks: 287 Yield: Density (ppg) 12 Volume pumped (BBLs) 125 Mixing / Pumping Rate (bpm): _ Tail Slurry w Type: Class Sacks: 85 Yield:_ Q Density (ppg) 15.3 Volume pumped (BBLs) 23 Mixing / Pumping Rate (bpm): - r m Post Flush (Spacer) rc Type: Density (ppg) Rate (bpm): Volume: _ LL Displacement: Type: 6% KCL PHPA Density (ppg) 9.6 Rate (bpm): 5 Volume (actual / calculated): 13. FCP (psi): 1150 Pump used for disp: Halliburton truck Bump Plug? X Yes No Bump press Casing Rotated? X No Reciprocated? _Yes X No % Returns during job 90 Cement returns to surface? _Yes _Yes X No Spacer returns? _Yes X No Vol to Surf: Cement In Place Al: Da 20:00 Wt; 8/1812019 Estimated TOC: 5550' Method Used To Determine TOC: BL') Post lob Calculations: Calculated Cmt Vol @ 0% excess: W Total Volume cmt Pumped: 147.9 Cml returned to surface: 1 Calculated cement left in wellbore: 146.9 OH volume Calculated: 131.7 OH volume actual: 144.8 Actual % Washout: 10 www.wellez.net WeIIEZ Information Management LLC ver_04818br 25 DATE 10/04/2019 Debi- Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 Halliburton Final Data 3 1 2 9 2 CD 1 : ROP DGR ADR CTN ALD ABG MD ALD DGR ADR CTN ABG TVD Pollard CD 2: CBL 3 1 2 9 3 Please include current contact information if different from above. RECEIVED OCT 0 4 2019 AOGCC 219073 Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: \1 ,J� 11 Vl n V � I Date: DATE 9/26/2019 219078 Deb... Oudean Hilcorp Alaska, LLC 3 1 2 8 2 GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 Mudlog Data CD 1 : FINAL WELL DATA: DAILY REPORTS FINAL WELL REPORT GAS RATIO LOG 2IN/SIN MD/TVD DRILLING DYNAMICS 2IN/SIN MD/TVD FORMATION LOG 2IN/SIN MD/TVD LWD COMBO LOG 2IN/5IN MD/TVD RECEIVED SEP 3 0 2019 AOGCC Daily Reports 9/26/201912:33 PM File folder DML Data 9/26/2019 12.3-4 PM File folder Final Well Report 9/26/201912:34 PM File folder LAS Data 9/26/201912:34 PM File folder Log PDFs 9/215/2019 12:32 PM File folder Log TIFFs 9/26/201912:33 PM File folder Show Reports 9/26/201912:33 PM File folder Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 IN THE STATE °fALASKA GOVERNOR MIKE. DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www. a o g c c. a l o s k o. g o v Re: Cannery Loop Field, Sterling Undefined Gas and Beluga Gas Pool, CLU 14 Permit to Drill Number: 219-078 Sundry Number: 319-417 Dear Mr. York: Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, ,per/ C.T Jessie L. Chmielowski Commissioner DATED this 13 day of September, 2019. RBDMS A� SEP 16 2019 SCAN INEJ `:EP 1 7 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 9n AAc 95 9A0 SEP 12 20i3 GC J t a'" "',d"-+ � e� ' 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 ❑ Aller Casing ❑ Other: Nitrogen 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development 21. Sfratigraphic ❑ Service ❑ 219-078 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-133-20684-00-00 ' 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 231 Will planned perforations require a spacing exception? Yes ❑ No u Cannery Loop Unit (CLU) 14 • 9. Property Designation (Lease Number): 10. Field/Pool(s): ADI -60569, ADI -60568, ADL 324602, Fee Private Cannery Loop / Sterling Undefined Gas Pool, Beluga Gas Pool - 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth ND (ft): Effective Depth MD: Effective Depth ND: MPSP (psi): Plugs (MD): Junk (MD): 9,802' 8,515' 9,642' 7,886' –2,342 psi N/A N/A Casing Length Size MD ND Burst Collapse Structural Conductor 120' 16" 120' 120' Surface 3,300' 10-3/4" 3,300' 2,598' 5,210psi 2,480psi Intermediate 6,732' 7-5/8" 6,732' 5,104' 6,890psi 4,790psi Production 4,242' 4-1/2" 9,802' 8,515' 8,430psi 7,500psi Liner Perforation Depth MD (ft): Perforation Depth ND (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic N/A N/A N/A Packers and SSSV Type: Packers and SSSV MD (ft) and ND (ft): Swell Pkr; N/A 2,800' MD/2,261ND; N/A 12. Attachments: Proposal Summary r Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development ❑� Service ❑ 14. Estimated Date for15. Well Status after proposed work: Commencing Operations: Septembe2019 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Bo York 777-8345 Contact Name: Christina Twogood Authorized Title: Operations Manager Contact Email: CtwO ood hilcor .Com Contact Phone: 777-8443 Authorized Signature. Date: ' I �o h COMMISSI N USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: n L4 I —r1 ElPlug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance Other: ,IBDMS±`'SEP 1 61019 Post Initial Injection MIT Req'd? Yes ❑ No ❑ - )AA Spacing Exception Required? Yes No F2/ Subsequent Subsequent Form Required: ! El APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Sf Aidflubl�►4�rdrll�€3A�n� �� l� vt 131 or ubmk Farm and Form 03 Revised 4/2077 Approved applicatio I t r date of approval. Aftachme is in Duplicate . re;A; y.z iy K Hileorp Alaska, LLC IN RIB: MSL =38' IG 3/4" } - 7-5/8" 4-W' I SCHEMATIC CASING DETAIL Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 109/X-56/Weld 15" Surf 120' 10-3/4" Surface 45.5/L-80/TXP BTC 9.950" Surf 3,300' 7-5/8" Intermediate 29.7/L -80/W563 6.875" Surf 6,732' 4-1/2" Production 12.6 / L-80 / TXP BTC 3.958" 5,400' 10,385' TUBING DETAIL Size I Type I Wt/Grade/Conn ID I Top I Btm 4-1/2" I Tubing I 12.6/L.80/IBT 3.98" Surf t5,400' JEWELRY DETAIL No Depth Item 1 ±5,400' Tie Back String 2 ±500' SSSV 3 2,804 7-5/8" Swell Packer 4 5,400 7-5/8" X 4-1/2" Liner Hanger OPEN HOLE/ CEMENT DETAIL y., 30 219 BBL's of cement in 13.5" Hole. Returns to Surface (0%excess) 7-5/8" 171 MCI of cement in 9.7/8" Hole. Est TOC @ 2,300' (0% excess) 4-1/2" 1 125 BBL's of cement in 6-3/4" Hole. Est TOC @ 5,400' (0% excess) 2 TD =9,802' (MD) / 8,051' (ND) PBTD=9,642' (MD) / 7,886' (TW) Updated by CMT 09-11-19 0 mry Alae4n, LLC RKB: MSL =38' Cannery Loop PROr-OSED SCHEMATIC Well: CLU#14 PTD: 219-078 API: 50-133-20684-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID III Btm 16" 2 109/X-56/Weld 3 10-3/4' 120' - Surface 45.5 /L-80 / TXP BTC "a 4 i 7-5/8' 3,304 7-5/8" Intermediate 29.7/L -80/W563 ma3 Surf T ru a bB dan 4-1/2" m 12.6/L-80/TXP BTC 1.81111 A 5,400' marc Proposed ma13 M13 -8/8A U11 B2 Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 109/X-56/Weld 15" Surf 120' 10-3/4" Surface 45.5 /L-80 / TXP BTC 9.950" Surf 3,304 7-5/8" Intermediate 29.7/L -80/W563 6.875" Surf 6,732' 4-1/2" Production 12.6/L-80/TXP BTC 3.958" 5,400' 10,385' TUBING DETAIL Size Type I Wt/ Grade/ Conn ID Top Btm 4-1/2" 1 Tubing I 12.6/L80/IBT 3.98" Surf +5,400' JEWELRY DETAIL No Depth Item 1 :5,400' Tie Back String 2 ±500' SSSV 3 2,800' 7-5/8" Swell Packer 4 5,400' 7-5/8" X 4-1/2" liner Hanger PERFORATION DETAIL Zone Top(MD) Stm(MD) Top(TVD) Btm(TVD) Amt Date Status M13 -1/1X +7,520' +7,600' +5,853' +5,931' 80' Proposed TBD M13-3 +7,660' +7,690' +5,989' +6,018' 30' Proposed TBD M13-4 +7,720' +7,760' +6,047' +6,085' 40' Proposed TO M13 -8/8A +8,010' +8,100' +6,327' +6,413' 90' Proposed TO MB -10 ±8,243' ±8,293' ±6,523' ±6,570' 50' Proposed TBD MB -11A ±8,309' ±8,359' ±6,585' ±6,632' 50' Proposed TBD MB -11C ±8,358' ±8,408' ±6,631' ±6,678' S0' Proposed TBD MB -13 +8,430' +_8,450' +6,731' +6,750' 20' Proposed TBD LB -1 ±8,442' ±8,492' ±6,710' ±6,757' S0' Proposed TBD LB -2 ±8,464' ±8,514' ±6,731' ±6,778' 50' Proposed TBD LB -4 +8,530' +8,590' +6,827' +6,884' 60' Proposed TBD LB -6 +8,640' +8,660' +6,932' +6,951' 20' Proposed TO LB -10 ±8,730' ±8,780' ±6,981' ±7,028' 50' Proposed TBD LB -11 18,784' ±8,834' ±7,031' ±7,078' 5T Proposed TBD LB -13 ±8,858' ±8,908' ±7,101' ±7,148' 50' Proposed TO LB -19 ±9,196' ±9,246' ±7,418' ±7,465' 50' Proposed TBD LB -24 ±9,394' ±9,444 ±7,604' ±7,651' 50' Proposed TBD LB -0 .,4 1A13 /� • I L&19 u3-24 OPEN HOLE/ CEMENT DETAIL rJ 10.3/4" 219 BBL's of cement In 13.5" Hole. Returns to Surface (0% excess) 4„ xR a • 7L 7-5/8" 171 BBL's of cement in 9-7/8" Hole. Est TOC @ 2,300' (0% excess) 4-1/2" 125 BBUs of cement in 6-3/4" Hole. Est TOC @ 5,400' (0% excess) TD =10,385' (MD) / 8,6W (TVD) PBTD=10,300 (MD)/8,515' (TVD) Updated by CMT 09-11-19 0 Hilcom Alaska, M Well Prognosis Well: CLU #14 Date: 9-11-2019 Well Name: CLU #14 API Number: 50-133-20684-00 Current Status: New Grassroots Well Leg: N/A Estimated Start Date: September 18th, 2019 Rig: Coil Unit Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 219-078 First Call Engineer: Christina Twogood (907) 777-8443 (0) (907) 378-7323 (C) Second Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 903-0341 (C) AFE Number: Maximum Expected BHP: —3,038 psi @ 6,951' TVD (Based on normal gradient of 0.43 psi/ft and the lowest perforation) Max. Potential Surface Pressure: —2,342 psi @ 6,951' TVD (Based on expected BHP and gas gradient to surface (0.10psi/ft) Brief Well Summary CLU #14 is a grass roots development well that was drilled and completed in August 2019 targeting gas sands in the Beluga and Sterling formation. The purpose of this work/sundry is to perforate to LB -6, LB -2, MB -13, MB -8/8A, MB -4, MB -3 and MB -1/1X sands. ' Notes Regarding Wellbore Condition • Slickline tag and make gauge ring run prior to starting work. � W �T Safety Concerns v' ' J , •k • Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. • Considertank placement based on wind direction and current weatherforecast (venting Nitrogen during this job) • Ensure all crews are aware of stop work authority E -Line Procedure 1. MIRU E -Line and pressure control equipment. PT lubricator to 250 psi Low/ 3,000 psi High. 2. RIH with GPT tool and find fluid level. If fluid level is over the depth to shoot the new perfs, discuss using Nitrogen with the Operations Engineer. Discus fluid level with Operations Engineer before proceeding to compare to previous fluid level. 3. If needed, RU Nitrogen Truck and pressure up on well to push water back into formation. Use GPT tool to confirm fluid level is below interval to perf. 4. RU wireline guns. K Mears Alaska. M 5. RIH and perforate the following intervals: Well Prognosis Well: CLU #14 Date: 9-11-2019 Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status MB -1/1X +7,520' +7,600' +5,853' +5,931' 80' Proposed TBD MB -3 +7,660' +7,690' +5,989' +6,018' 30' Proposed TBD MB -4 +7,720' +7,760' +6,047' +6,085' 40' Proposed TBD MB -8/8A +8,010' +8,100' +6,327' +6,413' 90' Proposed TBD MB -13 +8,430' +8,450' +6,731' +6,750' 20' Proposed TBD LB -6 +8,640' +8,660' +6,932' +6,951' 20' Proposed TBD a. Discuss surface pressure during perf with operations engineer for different intervals. b. Proposed perfs also shown on the proposed schematic in red font. c. Previously approved perf intervals shown on the proposed schematic in purple font. d. Final Perfs tie-in sheet will be provided in the field for exact pert intervals. e. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. f. Use Gamma/CCL to correlate. g. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. h. These sands are governed by Conservation Order 231. i. Sand intervals maybe grouped or shot one at a time and flow tested to the system. If a sand makes water, then a plug or an isolated patch may be set prior to moving up to the next sand interval. 6. POOH. 7. RD E -Line. 8. Turn well over to production. (Test SSV with -in 5 days of stable production on well - notify AOGCC 24hrs before testing) E -line Procedure (Contingency): 1. If any zone produces sand and/or water or needs isolated 2. MIRU E -line, PT lubricator to 250 psi Low/ 3,000 psi High. 3. RIH and set 4-1/2" CIBP at depth above zone. Or 4. RIH and set 4-1/2" Casing Patch across the zone. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Standard Well Procedure - N2 Operations 11 STANDARD WELL PROCEDURE llllcorp Alaska. LIX NITROGEN OPERATIONS 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 02 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. 12/08/2015 FINAL vl Page 1 of 1 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Bo York Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage. Alaska 99501-3572 Main: 907.279.1433 Fax 907.276.7542 www.00gcc.olaska.gov Re: Cannery Loop Field, Sterling Undefined Gas Pool, Beluga Gas Pool, CLU 14 Permit to Drill Number: 219-078 Sundry Number: 319-404 Dear Mr. York: Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Jessie L. Chmielowski Commissioner DATED this (D day of September, 2019. .ABDMS� SEP 0 9 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug Perforations Q • Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate Q • 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: Hilcorp Alaska, LLC Exploratory ❑ Development Q Stratigraphic ❑ Service ❑ 219-078 ' 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-133-20684-00-00 7. If perforating: e`� r-�Hc�r 7.v ¢{C. 2S. DSS 8. Well Name and Number: -�C% What Regulation or Conservation Order governs well spacing in this pooli grl.. cam„ CO 231 9-/ Will planned perforations require a spacing exception? Yes ❑ No Q Cannery Loop Unit (CLU) 14 9. Property Designation (Lease Number): - 10. Field/Pool(s): ADL60569: ADL60568, ADL 324602, Fee Private Cannery Loop / Sterling Undefined Gas Pool, Beluga Gas Pool ' 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 9,802' 8,515' 9,642' 7,886' -2,314 psi N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 120' 16" 120' 120' Surface 3,300' 10-3/4" 3,300' 2,598' 5,210psi 2,480psi Intermediate 6,732' 7-5/8" 6,732' 5,104' 6,890psi 4,790psi Production 4,242' 4-1/2" 9,802' 8,515' 8,430psi 7,500psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic N/A N/A N/A Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Swell Pkr; N/A 2,800' MD/2,261' TVD; N/A 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development ❑r Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: September 9, 2019 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Be York 777-8345 Contact Name: Christina Twogood Authorized Title: Operations M er Contact Email: ctwo ood hIIcor .Com I LI Icl Contact Phone: 777-8443 ' /� 1i C� �O Authorized Signatur Date: 1 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: u Ot4 I _ Plug Integrity ❑ BO`P �[BMechanical Integrity Test ❑ Location Clearance ❑ Other: t yvUJ />7/� /-3 L'f ' T'FS% C c -r6 -4j RBDMS I� SEP 0 9 2019 Post Initial Injection MIT Req'd? Yes No ®, / ' / `� ke 10-41()-7 �c-�..,�� Spacing Exception Required? Yes El No Subsequent Form Required: / YV�'• LLL - APPROVED BY Approved by: '�-d tom.. COMMISSIONER THE COMMISSION Date: I C ` ' III �/ � � V y � Submit Form and Form 10403 Revised 4/ 7 Approved application a i 'TTMMMInnI n h9frFfrrl ate of approval. Attachments in Duplicate K Hllc• A]"].. LI1 Well Prognosis Well: CLU 14 Date: 9-4-2019 Well Name: CLU 14 API Number: 50-133-20684-00-00 Current Status: New Grassroots Well Leg: N/A Estimated Start Date: September 91h 2019 Rig: Coil Unit Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 219-078 First Call Engineer: Christina Twogood (907) 777-8443 (0) (907) 378-7323 (C) Second Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 903-0341 (C) AFE Number: Maximum Expected BHP: - 3,000 psi @ 6,865' TVD (Based on normal gradient) Max. Potential Surface Pressure: — 2,314 psi @ 6,865' TVD (Based on expected BHP and gas gradient to surface (0.10psi/ft) Brief Well Summary CLU 14 is a grass roots development well that was drilled and completed in August 2019 targeting gas sands in the Beluga and Sterling formation. The purpose of this work/sundry is to perform a remedial squeeze across (3) zones by setting a CIBP, perforating the production string and squeezing cement on coil for each zone; then mill through the cement and CIBPs; and run a CBL. (Electronic copy of CBL to be sent to AOGCC when completed). Notes Regarding Wellbore Condition • Well will be filled with 3% KCL • Casing PT'd to 3,500 psi on 8/20/2019 • Production String PT'd to 3,500 psi on tubing / 2,500 psi on annulus on 8/21/2019 Safety Concerns • Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job) Ensure all crews are aware of stop work authority E -Line Plug & Perf Procedure 1. MIRU E -Line and pressure control equipment. PT lubricator to 250 psi Low / 3,000 psi High. 2. RIH and set 4-1/2" CIBP at depth below zone. 3 S�j Z Iry 3. RU perf guns. V K Halm" Alaska, M C 4. RIH and perforate the following intervals: Well Prognosis Well: CLU 14 Date: 9-4-2019 Zone Sand Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT SPF Beluga MB -1X/1 7520 7523 5845 5848 3 6 Beluga MB -1X/1 7597 7600 ✓ 5919 5922 3 6 Beluga M13 -8/8A 8020 8023 6328 6331 3 6 Beluga MB -8/8A 8087 8090 6392 6395 3 6 Beluga LB -4 1 8540 8543 6827 6830 3 6 Beluga LB -4 1 8577 8580 ✓1 68 3 6 and MB -1X/1 intervals may be shot separately to allow for to proceed one sand at a time. b. Proposed perfs also shown on the proposed schematic in red font. c. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. d. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. e. Use Gamma/CCL to correlate. f. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. g. These sands are governed by Conservation Order 231. . 5. POOH. S 6. RD E -Line. Coiled Tubing Procedure 1. MIRU Coiled Tubing. PT BOPE to 250 psi Low / 4,000 psi High. Notify AOGCC 24 hrs in advance of BOP test. 2. Make up MHA. Stab on well and PT lubricator to 250 psi Low / 4,000 psi High. 3. RU cement equipment. 4. RIH and tag top of CIBP at set depth. Circulate 3% KCI. Pick up a few feet above CIBP and begin injectivity test to determine amount of cement required. 5. Batch mix cement and begin pumping spacer and cement. As cement exits the nozzle, begin pulling up coiled tubing. Once all cement has been placed, pick up above cement plug, clean out coil and POOH. 6. Close CT x Tubing annulus and pressure up in 500 psi increments until squeeze and cement plug have been placed. POOH. 7. Wait for cement to set to minimum compressive strength for tag. Zone Sand Top (MD) I Btm (MD) I Top (TVD) Btm (TVD) I FT Beluga MB -1X/1 7520 7600 5845 5922 80 Beluga MB -8/8A 8020 8090 6328 6395 70 Beluga LB -4 8540 8580 6827 6865 40 a. LB -4, MB -8/8A and MB -1X/1 intervals will be cemented one sand at a time. 8. RU Slickline. RIH with GR and tag top of cement. RD Slickline. `9. RD cement equipment. 10. R eat E -Line Procedure Steps 1-6 and Coiled Tubing Procedure Steps 1-9 for each subsequent sand. 3 54N1)5 Well Prognosis Well: CLU 14 llikoq, AI.A., LL pate: 9-4-2019 once all (3) zones have been plugged perforated, cemented and tagged: 11. MU Mill and Motor BHA. 12. RIH and mill cement plugs, CIBPs and cleanout. 13. Circulate hole clean with 2 bottoms up. Ensure any rubber or cement is free from the hole. 14. POOH w/ coil. LD BHA. 15. RD Coiled Tubing. E -Line CBL Procedure 1. MIRU E -Line and pressure control equipment. PT lubricator to 250 psi Low / 3,000 psi High. 2. PU and RIH with CBL from PBTD to the 4-1/2" Liner Top. C 3. POOH and RD E -Line. Ch (4 F," ` "� Attachments: ,t A—©( (✓ 1. Current Well Schematic 2. Proposed Well Schematic 3. Standard Well Procedure—N2 Operations 3l; - S) Ov` dw¢�r� B HileorP Alaska, LLC RKB: MSL= 38' 16 SCHEMATIC CASING DETAIL Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 Size Type Wt/Grade/Conn ID I Top I Btm 16" Conductor 109/X-56/Weld 15" Surf 120' 10-3/4" Surface 4S.S/L-80/TXPBTC 9.950" Surf 3,300' 7-5/8" Intermediate 29.7/L -80/W563 6.875" Surf 6,732' 4-1/2" Production 12.6 / L-80 / TXP BTC 1958- 5,400' 10,385' 1 JEWELRY DETAIL No Depth Item 1 2,800' 7-5/8" Swell Packer 2 1 5,400' 1 7-5/8-X4-1/2' Liner Hanger 4 1/7' To =10,395' (MD) 8,6W (TVD) PBTD=10,300 (MD)/ 8,515 (ND) OPEN HOLE / CEMENT DETAIL 10-3/4" 219 BBL's of cement in 13.5" Hole. Returns to Surface (0% excess) 7-5/8" 171 BBL's of cement in 9-7/8" Hole. Est TOC @ 2,300' (0% excess) 4-1/2" 125 BBL's of cement in 6-3/4" Hole. Est TOC @ 5,400 (D% excess) Updated by DMA 08-09-19 11 Hilrnru :11�ska. LLC. RKB: MSL = 38' ' 163/4 7-5/8" 4V,7. MB-bvi r atwl PROs JSED SCHEMATIC CASING DETAIL Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 109/X-56/Weld 15" Surf 120' 10-3/4" Surface 45.5 /L-80 / TXP BTC 9.950" Surf 3,300' 7-5/8" Intermediate 29.7 / L-80 / W563 6.875" Surf 1 6,732' 4-1/2" Production 12.6 / L-80 / TXP BTC 3.958" 5,400' 1 10,385' TUBING DETAIL Size Type Wt/Grade/Conn ID I Top Btm JEWELRY DETAIL No Depth Item 1 ±5,400' Tie Back String 2 ±500' SSSV 3 2,800' 7-5/8" Swell Packer 4 5,400' 7-5/8" X 4-1/2" Liner Hanger CEMENTED PERFORATION DETAIL Zone Sand To op(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status Beluga MB -1X/1 17,520' ±7,523' 15,845' ±5,848' 3' Proposed TBD Beluga MB -1X/1 ±7,597' ±7,600' ±5,919' ±5,922' 3' Proposed TBD Beluga M13 -8/8A 18,020' ±8,023' ±6,328' ±6,331' 3' Proposed TBD Beluga MB -8/8A ±8,087' ±8,090' ±6,392' ±6,395 3' Proposed TBD Beluga LB -4 ±8,540' ±8,543' ±6,827' ±6,830' 3' Proposed TBD Beluga LB -4 ±8,577 ±8,580' ±6,862' ±6,865' 3' Proposed TBD 7 `� p,�jS OPEN HOLE / CEMENT DETAIL ROW 10-3/4" ?12 BBL's of cement In 13.5" Hole. Returns to Surface (0% excess) Mm 7-5/8" 171 BBL's of cement in 9-7/8" Hole. Est TOC @ 2,300' 10% excess) 4-1/2" 125 BBL's of cement in 6-3/4" Hole. Est TOC @ 5,400' (0% excess) LB -4 L&4 To --9,802,' (ND)/8,051'MM) PBTD=9,647 (MD) / 7,886' (TW) Updated by CMT 09/04/19 11 STANDARD WELL PROCEDURE II Hemp Alaska. LLC NITROGEN OPERATIONS 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 02 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. 12/08/2015 FINAL vl Page 1 of 1 7900 I� a 7950 8050 8550 i,6q mz :M 8700 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olcska.gov Re: Cannery Loop Field, Sterling Undefined Gas and Beluga Gas Pool, CLU 14 Permit to Drill Number: 219-078 Sundry Number: 319-372 Dear Mr. York: Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Commissioner f� DATED thio day of August, 2019. RBDMS AJAUG 1 91019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 9n AAC 95 280 r� rrm 11� "rj , fiq; RECCE"��E AUG 13 240101 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 w/N2 ❑� 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development Q • Stratigraphic ❑ Service ❑ 219-078 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-133-20684-00-00 7. If perforating: 77 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? COf.rV Cannery Loop Unit (CLU) 14 • Will planned perforations require a spacing exception? Yes ❑ No o - 9. Property Designation (Lease Number): 10, Field/Pool(s): ADL60569, ADL60568, ADL 324602, Fee Private Cannery Loop / Sterling Undefined Gas Pool, Beluga Gas Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 10,385' 8,600' 10,300' 8,515' -2,541 psi N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 120' 16" 120' 120' Surface 3,300' 10-3/4" 3,300' 2,598' 5,210psi 2,480psi Intermediate 6,732' 7-5/8" 6,732' 5,104' 6,890psi 4,790psi Production 4,985' 4-1/2" 1 10,385' 8,535' 1 8,430psi 7,500psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic N/A I N/A N/A Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Swell Pkr; N/A 2,800' MD/2,261' TVD; N/A 12. Attachments: Proposal Summary Wellbore schematic 141 13. Well Class after proposed work: , Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Straligraphic ❑ Development ❑✓ Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: August 25, 2019 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Bo York 777-8345 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramer(rphilcoro.com Contact Phone: 777-8420 1 L /TA k1 Authorized Signature: Date: COMMISSIO SE ONLY Conditions of approval: Notify Commission that a representative may witness Sundry Number: Cl— ` I ��n Plug Integrity ❑ O� t L� Mechanical Integrity Test E] Location Clearance El(/ ERI/ Other: "( D / r5L ✓�p � 6c lr DO.:i Sb_4- al p�-) RBDMS«qUG 19 2019 Post Initial Injection MIT Req'd? Yes ❑ No ❑ _ �/ d L Spacing Exception Required? Yes 5k No G Subsequent Form Required: AHE OVED BY gj ( t �`/ Q( MMISS Approved by: COMMISSIONER THE COMMISSION Date: / l✓ Il. DIlj I e 1 1 �� I A A L ��i�/� .ice Submit Form and orm 10-409/ eN I d /2017 Approved a liciL.Wl'i 5 r f 21�•,,�11nHf m the date of approva(�. /11,// ,[..� Attachments in Duplicate In f il..m Alaska. LLQ Well Prognosis Well: CLU #14 Date: 8-7-2019 Well Name: CLU #14 API Number: 50-133-20684-00 Current Status: New Grassroots Well Leg: N/A Estimated Start Date: August 25`^ 2019 Rig: Coil Unit Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 219-078 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (C) Second Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 903-0341 (C) AFE Number: 1912716C Maximum Expected BHP: — 3,308 psi @ 7,697' TVD (Based on normal gradient of 0.43 psi/ft and the lowest perforation) Max. Potential Surface Pressure: — 2,541 psi @ 7,697' TVD (Based on expected BHP and gas gradient to surface (0.10psi/ft) Brief Well Summary CLU #14 is a grass roots development well targeting gas sands in the Beluga and Sterling formation. This new well anticipated to reach TD 8-18-2019 The purpose of this work/sundry is to run 4-1/2" tieback string W/SSSV, evaluate cement, jet the well dry with CT, and perforate. Notes Regarding Wellbore Condition • Well will be filled with 6% KCL • Slickline tag and make gauge ring run prior to starting work. • E -line will complete CBL prior to starting sundry work. Electronic copy of CBL to be sent to AOGCC when completed. Safety Concerns • Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. • Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job) • Ensure all crews are aware of stop work authority Drill Rig RIH 4-1/2" Tieback and SSSV Procedure (start of Sundry work) 1. PU 4-1/2" Tie -back string and PBR seals. 2. RIH with 4-1/2" Tie -back string /seals, Install SSSV at 500' MD. 3. RIH with tieback string and control line to SSSV, sting into the liner hanger. 4. Land the Tie -back string. 5. MIT -IA (7-5/8" x 4-1/2") will be performed to 2,500 psig for 30 minutes Coiled Tubing Procedure (start of Sundry work) 1. MIRU Coiled Tubing, PT BOPE to 4,000 psi Hi 250 Low. Notify AOGCC 24 hrs. in advance of BOP test. If slickline or a -line tags cement shallower than proposed lower most planned perforation, Follow steps 1-6; otherwise, go to step S. U Hilraro Alaska, LL Well Prognosis Well: CLU #14 Date: 8-7-2019 2. MU Mill and Motor BHA. 3. RIH and mill cement and cleanout. 4. Circulate hole clean with 2 bottoms up, ensure any rubber or cement is free from the hole. 5. RU N2 pumping unit. 6. Drop ball and come online with N2 and jet well dry. • Estimated volume of displaced 6% KCI is 143 bbls. 7. RIH w/ coiled tubing and jet nozzle BHA and tag PBTD. 8. PU 5ft and displace well fluids with Nitrogen. • Estimated volume of displaced 6% KCI is 143 bbls. 9. Once well is dry, verify desired surface pressure to leave on well with Operations Engineer (OE). 10. POOH w/ coil. LD BHA. 11. RD Coiled Tubing. E -Line Procedure 12. MIRU a -line and pressure control equipment. PT lubricator to 3,500 psi Hi 250 Low. Note that the well is pressurized with nitrogen. • If necessary, bleed pressure down as requested by the OE to establish a drawdown on the formation. C dL 13. PU run CBL fmm PBTD to the 4-1/2" Liner top, POOH 14. PU RIH W/perfguns. jZvw�� C& 15. Proposed Perforated Intervals 4-0 — C'G(' Zone To (MD) Base MD MB -10 8243 8293 MB -11A 8309 8359 MB -11C 8358 8408 LB -1 8442 8492 LB -2 8464 8514 LB -10 8730 8780 LB -11 8784 8834 LB -13 8858 8908 LB -19 9196 9246 LB -24 9394 9444 a. Proposed perfs. also shown on the proposed schematic in red font. b. Final Perls 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. f. These sands are governed by Conservation Order 231. g. 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 isolated patch may be set prior to moving up to the next sand interval. 16. POOH. 17. RD e -line. Well Prognosis Well: CLU #14 nilcura Alaska, LL Date: 8-7-2019 18. Turn well over to production. (Test SSV with -in 5 days of stable production on well — notify AOGCC 24hrs before testing) E -line Procedure (ContineencV): 1. if anyzone produces sand and/or water or needs isolated 2. MIRU E -line, PT lubricator to 3,500 psi Hi 250 Low. 3. RIH and set 4-1/2" CIBP at depth above zone. Or 4. RIH and set 4-1/2" Casing Patch across the zone. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Standard Well Procedure—N2 Operations B pOq, Alaska, LLC. RKB: M5L = 38' 16' ' 1P3/4" - 7-5/8" 2 TD =10,385' (MD) / 8,600' (TVD) P91D=10,300' (MD)/8,515' (ND) 0 SCHEMATIC CASING DETAIL Cannery Loop Well: CLU #14 PTD: 219-078 API: 50-133-20684-00-00 Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 109/X-56/Weld 15" urf Surf 120' 10-3/4" Surface 45.5 /L-80 / TXP BTC 9.950" S 3,300' 7-5/8" Intermediate 29.7/L -80/W563 6.875" Surf 6,732' 4-1/2" Production 12.6 / L-80 / TXP BTC 3.958" 5,400' 10,385' JEWELRY DETAIL No Depth Item 1 2,800' 7-5/8" Swell Packer 2 5,400' 7-5/8" X 4-1/2" Liner Hanger OPEN HOLE/ CEMENT DETAIL 10-3/4" 219 BBL's of cement in 13.5" Hole. Returns to Surface (0% excess) 7-5/8" 171 BBCs of cement in 9-7/8" Hole. Est TOC @ 2,300' (0% excess) 4-1/2" 125 BBL's of cement in 6-3/4" Hole. Est TOC @ 5,400' (0% excess) Updated by DMA 08-09-19 K corn Alaeka. LLC RIB: MS1.=38' 4u2' 1 TD =10,385' (MD) / 8,600 (ND) PBTD=10,3W (MD)/8,515' (TVD) Cannery Loop PROPOSED SCHEMATIC Well: CLU#14 PTD: 219-078 API: 50-133-20684-00-00 CASING DETAIL Size Type r ID Top Btm 16" Conductor 109/X-56/Weld 3 Surf 120' 30-3/4" Surface 45.5 /L-80 / TXP BTC 9.950" Surf 3,30d 7-5/8" ;n 10.3/4" 6.875" Surf 6,732' ,1 Production 12.6 / L-80 / TXP BTC 3.958" 5,400' 10,385' TBD LB -1 ±8,442' ±8,492' k% ±6,757' 50' TBD LB -2 ±8,464' ±8,514' ±6,731' ±6,778' 50' d TBD LB -10 ±8,730' ±8,780' ±6,981' ±7,028' 50' d TBD L8-11 ±8,784' ±8,834' ±7,031' ±7,078' S0' d TBD B±7,01'±7,148' S0' d TBD L8-19 ±9,196' ±9,246' ±7,418' ±7,465' SO' Proposed TBD u, 1 ±9,394' ±9,444 ±7,604' 1 ±7,651' 1 i, I Proposed TBD ?rt. s' 7-5/8" rn { H810 M3 -11A 1811C LB -1 L&2 LB 10 UB 11 LB -13 LB -19 - LB -24 4u2' 1 TD =10,385' (MD) / 8,600 (ND) PBTD=10,3W (MD)/8,515' (TVD) Cannery Loop PROPOSED SCHEMATIC Well: CLU#14 PTD: 219-078 API: 50-133-20684-00-00 CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm 16" Conductor 109/X-56/Weld 15" Surf 120' 30-3/4" Surface 45.5 /L-80 / TXP BTC 9.950" Surf 3,30d 7-5/8" Intermediate 29.7/L -80/W563 6.875" Surf 6,732' 4-1/2" Production 12.6 / L-80 / TXP BTC 3.958" 5,400' 10,385' TUBING DETAIL Size Type Wt/Grade/Conn ID Top I Btm 4-1/2" Tubing 16.6/S-135/CDS40 3.826" Surf ±5,400' JEWELRY DETAIL No Depth Item 1 ±5,400' Tie Back String 2 ±Seo' SSSv 3 2,8W 7-5/8" Swell Packer 4 5,400' 7-5/8" X 4-1/2" Liner Hanger PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) AmtKDateStatus MB -10 ±8,243' ±8,293' ±6,523' ±6,570' 50' d TBDMB-11A ±8,309' ±8,359' ±6,585' ±6,632' 50' d TBD MB -11C ±8,358' ±8,408' ±6,631' ±6,678' 50' TBD LB -1 ±8,442' ±8,492' ±6,710' ±6,757' 50' TBD LB -2 ±8,464' ±8,514' ±6,731' ±6,778' 50' d TBD LB -10 ±8,730' ±8,780' ±6,981' ±7,028' 50' d TBD L8-11 ±8,784' ±8,834' ±7,031' ±7,078' S0' d TBD B±7,01'±7,148' S0' d TBD L8-19 ±9,196' ±9,246' ±7,418' ±7,465' SO' Proposed TBD LB -24 1 ±9,394' ±9,444 ±7,604' 1 ±7,651' 1 S0' I Proposed TBD OPEN HOLE / CEMENT DETAIL 10-3/4" 219 BBL's of cement in 13.5" Hole. Returns to Surface (0% excess) 7-5/8" 17188L's of cement in 9-7/8" Hole. Est TOC @ 2,300' (096 excess) 4-1/2" 1 125 BBUs of cement in 6-3/4" Hole. Est TOC @ 5,400'(0% excess) Updated by DMA 08-09-19 Cannery Loop PROPOSED SCHEMATIC Well: CLU #14 PTD: 219-078 Hilcorp Alaekn, LI.0 API: 50-133-20684-00-00 CASING DETAIL RIB: MSL =38' TD =10,385' (MD) / 8,600' (TVD) PBTD=10,300 INC) / 8,515' (ND) Size Type Wt/Grade/Conn ID Top Btm 16" Conductor 109/X-56/Weld 15" Surf 120' 1D-3/4" Surface 45.5 /L-80 / TXP 8TC 9.950" Surf 3,300' 7-5/8" Intermediate 29.7/L -80/W563 6.875" Surf 6,732' 4-1/2" Production 1 12.6 / L-80 / TXP BTC 3.958" 5,400' 10,385' TUBING DETAIL Size Type Wt/ Grade/ Conn ID I Top Btm 4-1/2" Tubing 16.6/5-135/CDS40 3.826" Surf ±5,400' JEWELRY DETAIL No Depth Item 1 ±5,400' Tie Back String 2 ±500' SSSV 3 2,800' 7-5/8' Swell Packer 4 5,400' 7-5/8" X 4-1/2" Liner Hanger PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status MB -30 ±8,243' ±8,293' ±6,523' ±6,570' 50' Proposed TBD MB -11A ±8,309' ±8,359' ±6,585' ±6,632' 50' Proposed TBD MB -11C ±8,358' ±8,408' ±6,631' ±6,678' 50' Proposed T80 LB -1 ±8,442' ±8,492' ±6,710' ±6,757' 50' Proposed TBD LB -2 ±8,464' ±8,514' ±6,731' ±6,778' 50' Proposed TBD LB -10 ±8,730' ±8,780' ±6,981' ±7,028' 50' Proposed TBD LB -11 ±8,784' ±8,834' ±7,031' ±7,078' 50' Proposed TBD LB -13 ±8,858' ±8,908' ±7,101' ±7,148' 50' Proposed TBD LB -19 ±9,196' ±9,246' ±7,418' ±7,465' S0' Proposed TBD Le -24 ±9,394' ±9,444 ±7,604' ±7,651' S0'i Proposed TBD OPEN HOLE / CEMENT DETAIL 10-3/4" ?12L'! of cement in 13.5" Hole. Returns to Surface (0% excess) 7-5/8" 171 BBL's of cement in 9-7/8" Hole. Est TOC @ 2,300' (0% excess) 4-1/2" 125 BBCs of cement in 6-3/4" Hole. Est TOC @ 5,400' (0% excess) Updated by DMA 08-09-19 STANDARD WELL PROCEDURE Ililcnrp Alaska, 1.1.1: NITROGEN OPERATIONS 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 02 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. 12/08/2015 FINAL v1 Page 1 of 1 Schwartz, Guy L (CED) From: Schwartz, Guy L (CED) Sent: Tuesday, August 13, 2019 3:31 PM To: David Gorm Subject: RE: PTD- 219-078 CLU #14 Run Tie -Back String Dave , Approval granted to run the tubing completion as proposed below. The well may not be perforated until you have a sundry approved. Update your MOC form as required. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 Guy Schwartz at (907-793-1226) or (Guy.schwartz@alasko.aov). From: David Gorm <dgorm@hilcorp.com> Sent: Tuesday, August 13, 2019 1:45 PM To: Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Subject: PTD- 219-078 CLU #14 Run Tie -Back String Guy Looking for approval to run the 4-1/2" tie back string/PBR seals with the SSSV set at 500' MD with the drilling rig. Please see attached proposed schematic. General Planned procedure. Drill Rig RIH 4-1/2" Tieback and SSSV Procedure (start of Sundry work) 1. PU 4-1/2" Tie -back string and PBR seals. 2. RIH with 4-1/2" Tie -back string /seals, Install SSSV at 500' MD. 3. RIH with tieback string and control line to SSSV, sting into the liner hanger. 4. Land the Tie -back string. 5. MIT -IA (7-5/8" x 4-1/2") will be performed to 2,500 psig for 30 minutes Thanks, David Gorm Drilling Engineer Hilcorp Alaska Office: 907-777-8333 Cell: 505-215-2819 The information Contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. 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 STATE °fALASKA GOVERNOR MIKE DUNLEAVY Monty Myers Drilling Manager Hilcorp Alaska, LLC. 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 w .aogcc.alaska.gov Re: Cannery Loop Field, Sterling and Beluga Undefined Gas Pool, CLU 14 Hilcorp Alaska, LLC. Permit to Drill Number: 219-078 Surface Location: 232' FSL, 275' FEL, Sec. 7, T5N, Rl IW, SM, AK Bottomhole Location: 2199' FSL, 2055' FEL, Sec. 8, T5N, RI 1W, SM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced service well. The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce is contingent upon issuance of a conservation order approving a spacing exception. Hilcorp Alaska, LLC. assumes the liability of any protest to the spacing exception that may occur. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, !J ssle L. Chmielowski Commissioner DATED this I I day of July, 2019. RECOVER STATE OF ALASKA SKA OIL AND GAS CONSERV ION JUN U 3 2013 PERMIT TO DRIL REVISED 20 AAC 25 00 '> ^ 1 a. Type of Work: 1 b. Proposed Well Class: Exploratory - Gas Service - WAG LJService - Disp E]ic. Specify i1 well is .propose& for: Drill ❑I ' 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: S. Bond: Blanket Q . Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 • CLU 14 ' 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 10,386' TVD: 8,600' ' Cannery Loop Unit Sterling Undefin/ed 67k.'- , 4a. Location of Well (Governmental Section): 7. Property Designation: rLc_ FriO41/! Surface: 232' FSL, 275' FEL, Sec 7, T5N, R11 W, SM, AK ADL60569, ADL60568,AM ' V"L7 -� 6q--,'f"CCr 8. DNR Approval Number: ,, s- r 7, p`% 13. Approkfirmate Spud Date: ,-- Top of Productive Horizon: 931' FSL, 2114' FEL, Sec 8, T5N, R11 W, SM, AK LOCI 78-156 6/28/2019 9. Acres in Property: 14. Distance to Nearest Property: Total Depth: 2199' FSL, 2055' FEL, Sec 8, T5N, R11 W, SM, AK 1048 2312' to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 38.4 - 15. Distance to Nearest Well Open Surface: x-272696 • y- 2388681 • Zone -4 GL / BF Elevation above MSL (ft): 20.4 to Same Pool: 2146'to CLU -06 16. Deviated wells: Kickoff depth: 400 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 48 degrees Downhole: 3870 Surface: 3010 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade I Coupling Length MD TVD MD TVD (including stage data) Cond 16" 109# X-56 Weld 120' SurfaceSurface 120' 120' Driven 13-1/2" . 10-3/4" 45.5# L-80 TXP BTC 3,300' Surface Surface 3,300' 2,601' L - 1534 ft3 / T - 315.9 ft3 9-7/8" 7-5/8" 29.7# L-80 W563 6,732' Surface Surface 6,732' 5,100' L - 722.1 ft3 / T - 257.9 ft3 6-3/4" 4-1/2" - 12.6# L-80 TXP BTC 1 4,985' 5,400' 4,005' 10,385' 8,600' L - 636.7 ft3 / T - 77.7 ff3 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Stmctural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Hydraulic Fracture planned? Yes ❑ No ❑� 20. Attachments: Property Plat Q BOP Sketch 8 Drilling Program Time v. Depth Plot e Shallow Hazard Analysis B 8 Diverter Sketch Seabed Report Drilling Fluid Program r 20 AAC 25.050 requirements 4 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: David Gorm Authorized Name: Monty Myers Contact Email:dcorm hilcom.com Authorized Title: Drilling Manager Contact Phone: 777-8333 FoK MortY M Yfia-$ %/ 4 Authorized Signature: Date: �/� Commission Use Only Permit to Drill f� AP umber: �7r�� // �[ Permit Approval See cover letter for other Number: ��' C'7 n3 - 3 "-lJ•-�W�T �C�_Z�� / Date: requirements. /gas hydrates, or gas contained in shales: IT Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane ❑ ''J ��-� Samples req'd: Yes ❑ No L—.j/ Mud log mq'd: Yes o Ly] Other: y-5.6 ,p 5 - 3 D � 3 HzS measures: Yes ❑ No Directional svy req'd: Yes o ❑ C� Inclination Yes 1-1No lei/ )C C g L lip L J ' /t 7SXbL Spacing exception req'd: Yes No ❑ -only svy req'd: ❑ ❑ I J Post initial injections MIT req'd: Yes No B 400 C Sa pp r � r...vv.� 4-a (/ I r APPROVED BY Approved by: i` COMMISSIONER THE COMMISSION Date: Submit Form and 0-4 Re sed 5/2017 T e mi is valid for h f h to gravel per 20 AAC 25.005(g) Attachments in uplicate 3� Hilcorp Alaska, LLC CLU #14 Drilling Program Cannery Loop W Approved by: David W Gorm Revision 1 June 2019 CLU Drilling Procedure Hilcorp Ena ��PmY Contents 1.0 Well Summa 2 2.0 Management of Change Information............................................................................................3 3.0 Tubular Program: ......................................................................................................................... -4 4.0 Drill Pipe Information: ................................................................................................................... 4 5.0 Internal Reporting Requirements..................................................................................................5 6.0 Planned Wellbore Schematic..........................................................................................................6 7.0 Drilling / Completion Summary.....................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications.....................................................................8 9.0 R/U and Preparatory Work..........................................................................................................10 10.0 N/U 21-1/4" 2M Diverter...............................................................................................................11 11.0 Drill 13-1/2" Hole Section.............................................................................................................14 12.0 Run 10-3/4" Surface Casing.........................................................................................................18 13.0 Cement 10-3/4" Surface Casing...................................................................................................21 14.0 BOP N/U and Test.........................................................................................................................L4 15.0 Drill 9-7/8" Hole Section...............................................................................................................25 16.0 Run 7-5/8" Intermediate Casing..................................................................................................30 17.0 Cement 7-5/8" Cement Procedure...............................................................................................33 18.0 Drill 6-3/4" Hole Section...............................................................................................................36 19.0 Run 4-1/2" Production Long String.............................................................................................41 20.0 Cement 4-1/2" Production Long String.......................................................................................44 21.0 Completions...................................................................................................................................46 22.0 BOP Schematic..............................................................................................................................47 23.0 Wellhead Schematic......................................................................................................................48 24.0 Days Vs Depth................................................................................................................................49 25.0 Formation Tops.............................................................................................................................50 26.0 Anticipated Drilling Hazards.......................................................................................................51 27.0 Rig Layout......................................................................................................................................54 28.0 FIT Procedure................................................................................................................................55 29.0 Choke Manifold Schematic...........................................................................................................56 30.0 Casing Design Information...........................................................................................................57 31.0 9-7/8" Hole Section MASP............................................................................................................58 32.0 6-3/4" Hole Section MASP............................................................................................................59 33.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................60 34.0 Surface Plat (As Built) (NAD 27).................................................................................................61 35.0 Offset MW vs TVD Chart .............................................................................................................62 36.0 Drill Pipe Information...................................................................................................................63 37.0 Directional Program(WP12)........................................................................................................65 CLU #14 Drilling Procedure Hilcorp Energy Company 1.0 Well Summary Well CLU 414 Pad & Old Well Designation CLU #14 is a grass roots well on Pad 91 Planned Completion Type Perforated Target Reservoirs Sterling B sands and Beluga sands Planned Well TD, MD / TVD 10,385' MD / 8,600' TVD PBTD, MD / TVD 10,295 MD / 8510' TVD Surface Location Governmental 232' FSL, 275' FEL, Sec 7, T5N, RI IW, SM, AK Surface Location (NAD 27) X=272696.838, Y=2388681.671 Surface Location (NAD 83) X=1412722.164, Y=2388435.821 Top of Productive Horizon (Governmental) 931' FSL, 2114' FEL, Sec 8, T5N, RI IW, SM, AK TPH Location AD 27 X = 276159, Y = 2389307 BHL (Governmental) 2199' FSL, 2055' FEL, Sec 8, T5N, RI 1 W, SM, AK BHL AD 27 X = 276239, Y = 2390573 AFE Number 1912716 AFE Drilling Das 30 AFE Drilling Amount $5,700,000 Maximum Anticipated Pressure (Surface) 3010 psi Maximum Anticipated Pressure Downhole/Reservoir 3870 psi Work String 4-1/2" 16.64 S-135 CDS-40 KB Elevation above MSL: 38.4 ft GL Elevation above MSL: 20.4 8 BOP Equipment 11" 5M T3 -Energy Annular BOP 11" 5M T3 -Energy Double Ram 11" 5M T3 -Energy Single Ram Page 2 Revision 1 June 2019 CLU #14 Drilling Procedure xilcorp Enm C2jx 2.0 Management of Change Information H Hilcorp Alaska, LLC xilcotp �. Changes to Approved Permit to Drill Date: 5-6-2019 Subject: Changes to Approved Permit to Drill for CLU #14 File #: CLU #14 Drilling and Completion Program Any modifications to CLU #14 Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be coyamtWOCAe he BL/M/ and AOGCC. Sec Page Date Procedure Change Approved Approved ByB Approval: Prepared: Drilling Manager Date Drilling Engineer Date Page 3 Revision 1 June 2019 CLU Drilling Procedure Hileorp E-0 �� 3.0 Tubular Program: Cond 16" 15" - - 109 X-56 Weld 13-1/2" 10-3/4". 9.95" 9.875" 11.75" 45.5 L-80 TXP BTC 5210 2480 1040 9-7/8 7-5/8 6.875" 6.75" 8.5" 29.7 L-80 W563 6890 4790 683 6-3/4" 4-1/2" • 3.958" 3.833" 5" 12.6 L-80 TXP BTC 8430 7500 288 4.0 Drill Pipe Information: f7I) Grade Conn Burst Collapse Tension Y/ft) — - - -- (P-5� (Psi) (k -lbs) All 4.5" 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 4 Revision 1 June 2019 CLU Drilling Procedure Hilcorp 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellez. • Report covers operations from 6am to 6am • 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. • Ensure time entry adds up to 24 hours total. • 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 • Submit a short operations update each work day to dgortn@hilcorp.com, mmyers@hileorp.com and cdinger@hilcorp.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam 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 • 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: 0:907-777-8477 C:907-350-9439 Notify Drlg Manager 1. Monty M Myers: O: 907-777-8431 C: 907-538-1168 Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally • Send final "As -Run" Casing tally to d orm hilcorppom mmyers@—hileorp.com hilcorp.com and cdineer@hilcgM.com 5.6 Casing and Cut report • Send casing and cement report for each string of casing to dgormkhilcorp.com, mmyers hilcorp.com and cdinger@hilcorp.com Page 5 Revision 1 June 2019 n CLU #14 Drilling Procedure Hi1COIp En Cam2 6.0 Planned Wellbore Schematic CanneryLoop PROPOSED SCHEMATIC Well: CLU #14 PTD:TBD Hikoro.Uad.a. LLC Ir Z � 18' L CASING DETAIL y 3 Flf •S pfy JEWELRY DETAIL No Type Wtj Grade/Cann ID Top BtmCondunor 2 TBD 109/X-56/Weld IV Suit 126'65.5/L-8017WOTC9950 K SAW 7-5/8' X 4-3/2' Liner Hanger Surf 3,300' IMer�aEe Pmdtl ion 12.6/L-80 /TXP BTC 3.958" S,A00- 10,385' y 3 Flf •S pfy JEWELRY DETAIL No Depth Item 1 5,40D' Tie Back Wine 2 TBD SSSV 3 2,800' 7-5/8" Swell Padrer 4 SAW 7-5/8' X 4-3/2' Liner Hanger OPEN HOLE/ CEMENT DETAIL 143/4' 219 BBL's of cement in 13.5" Hole. Returns to Surface (0%exces) 7-S/8' 171 BBL's of wmaM in 9-7/B' Hole. Est TDC @ 2300'(0% e=4MM 4-1/2• 125 BWs of mmeM in 6-3/4' Hole- Est TOC Lw S w' (0%e ew) �° SYav wv slur` -T✓ J4100 qa, 5kpo5 �L/ Y a $ a I2 Page 6 Revision 1 June 2019 CLU #14 Drilling Procedure Hilcorp Enemy C211T 7.0 Drilling / Completion Summary CLU #14 is a grass roots development well from Pad #1 in the Cannery Loop Field targeting the Sterling B sands and Beluga sands. The base plan is an "S" tum wellbore, kicking off at 350' MD and building to 48 deg, then dropping back to 16 deg starting at 5,471' MD, then drilling a 16 deg tangent to TD at 10,385' MD. - Drilling operations are expected to commence approximately June 28", 2019. The Hilcorp Rig # 169 will be used to drill and partially complete the wellbore. A workover rig will follow behind to install the tbg/SSSV/packer and perforate thru-tbg. Surface casing will be run to 3,300 MD and cemented to surface to ensure protection of surface water. 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 Ins 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 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 21-1/4" x 2M diverter. 3. Drill 13-1/2" hole to 3,300' MD. Run and cmt 10-3/4" surface casing. 4. N/D diverter, N/U & test 11" x 5M T3 -Energy BOP. 5. Drill 9-7/8" intermediate hole section to 6,732' MD. Run and cmt 7-5/8" intermediate casing. 6. Drill 6-3/4" production hole section to 10,385' MD. Run and curt 4-1/2" production liner. Reservoir Evaluation Plan: 1. Surface hole: Mud loggers will generate a mud log.` r�d� L) l� orf 2. Intermediate hole: LWD: GR + Res + Den/Neu (Triple Com o). Mud loggers will generate a mud log. 3. Production hole: LWD: GR + Res + Den/Neu (Triple Combo). Mud loggers will generate a mud log. Page 7 Revision 1 June 2019 CLU Drilling Procedure Hilcorp E�v C—PW 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling and completion of CLU #14. Ensure to provide AOGCC 24 hrs notice prior to testing BOPS. • The initial test of BOP equipment will be to 250/3500 psi & subsequent tests of the BOP equipment will be to 250/3500 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • 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. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system" • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements" • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: • None at this time. Page 8 Revision 1 June 2019 CLU Drilling Procedure Hilcorp E.ew C. ' Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure si 13-1/2" 21-1/4" x 2M Hydril MSP diverter Function Test Only • 1 I" x 5M T3 -Energy (Model 7082) Annular BOP Initial Test: 250444909'-6!psi) • 11" x 5M T3 -Energy Double Ram (Annular 2500 psi) o Blind ram in btm cavity • Mud cross 9-7/8" 11" x 5M T-3 Energy Single Ram • 3-I/8" 5M Choke Line Subsequent Tests: e 3SV • 2-1/16" x SM Kill line 250/49ee • 3-1/8" x 2-1/16" 5M Choke manifold (Annular 2500 psi) • Standpipe, floor valves, etc aE • Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). • Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: • Well control event (BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPS. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: jim.reg&@alaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guuy.schwartz@alaska.gov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / Email: melvin.rixse@alaska.&ov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: victoria.loepogalaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectorsna alaska.gov Test/Inspection notification standardization format: hiip7Hdoa.alaska.gov/oac/forms/TestWitnessNotif.htmI Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 Revision 1 June 2019 F H Hilcorp Ex Czix 9.0 R/U and Preparatory Work CLU #14 Drilling Procedure 9.1 Set 16" conductor at 112' below ground level (120' RKB). Additional depth is required to isolate the shallow gravel beds in the area. 9.2 Dig out and set impermeable cellar. 9.3 Install 16-3/4" 3M "A" section. Ensure to orient wellhead so that tree will line up with flowline later. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of rig. 9.6 R/U Hilcorp Rig # 169, spot service company shacks, spot & R/U company man & toolpusher offices: 9.7 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.8 Mix mud for 13-1/2" hole section. 9.9 Set test plug in wellhead prior to N/U diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.10 Install 5-1/2" liners in mud pumps. • HHF-1000 Pumps 1000 mud pumps are rated at 3633 psi (85%) / 333 gpm (100%) with 5- 1/2" liners. Page 10 Revision 1 June 2019 U Hilcorp Enema C..p , CLU #14 Drilling Procedure 10.0 N/U 21-1/4" 2M Diverter 10.1 N/U 21-1/4" Hydril MSP 2M diverter System. • N/U 16-3/4" 3M x 21-1/4" 2M DSA (Hilcorp) on 16-3/4" 3M wellhead. • NIU 21-1/4" diverter "T". • Knife gate, 16" diverter line. 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: • A prohibition on vehicle parking. A prohibition on ignition sources or running equipment. A prohibition on staged equipment or materials. Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set 15.375" ID wearbushing in wellhead. Page I 1 Revision 1 June 2019 H HiImrp En� com�y CLU #14 Drilling Procedure 10.5 Rig and Diverter Line Orientation on CLU #14: Tv. SECTION 7, T5N, R11W, S.M. AK / `10' UnUTY EASEMENT TRACT A KEN/ TOIT U N0.10 moi CLU NO�,S ®L=N 20=----ZS" LU NO.8 BURIED iLOWLu, 1 CLU NOARD IMIC CLU NO.5 i i i ItLU NOX i--21� ---�/ BUD .3L, i i i —A 97 CLU NO.7 IWATER LINE LBURIED 5'f —AL1— �kA.• Page 12 Revision 1 June 2019 0 OV 4 H Hilcorp Encs C2i 10.6 Diverter Schematic Annular Preventer Diverter Tee, 21 '%" x 2M w116" ANSI 150 16-'/," 3M x 21-1:" 2M 16'/: 3M Casing head Assy CLU #1a Drilling Procedure Page 13 Revision 1 June 2019 CLU Drilling Procedure Hilcorp E.w Compal 11.0 Drill 13-1/2" Hole Section 11.1 P/U 13-1/2" directional drilling assy: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Bit TFA should be —0.7 to 0.75 int. We need to pump at 500 - 550 gpm to clean the hole effectively. • Workstring will be 4.5" 16.69 S-135 CDS40 11.2 Hydraulics Summary: Page 14 Revision 1 June 2019 Est Open Depth- Hole Size Pump Rate Standpipe hole AV MW ECD TFA MD (ft) (in) (gpm) Pressure (psi) (fpm) (ppg) (ppg) (int) BHA MM+MWD+25 0-3,300' 13-1/2" 550 1800 85 9.0 9.3 0.739 HWDP Page 14 Revision 1 June 2019 CLU Drilling Procedure Hilco Comprp anergy aq 11.3 Primary bit will be the 13-1/2" Hughes Christensen Kymera Hybrid Bit KM633. Hughes Christensen Kymera'" Hybrid Bits Best of Both Warlds Designed to take wMittage of the best anributes of bods, Kymaa combines roller cone and Bled cutla elunents. 1, l, Ivoved Dirwional G>tRml Relative t6 PDC bits, Kymera gewoles k woverall torque and minimized torque fiWantions to impmvetrml face control and reduce vibrations. La wNibratian The unique design of Kymaa bits provides an stable trilling pletfam that mhigan s vibation prescm in rolkr PIN' em•-Iranmcros Nner nwlface amrml Superior direnimal bit for motor err Intaly applications with betty Coalface control and steembi1h) than a PIX. Pasta and More Durable When drilling imat iklod and hankr fonmtiom, miatisv to PDC bits. this miqucdksign provides incased -i durability in uansition mnm and stnoother, lastadrilling in had ruck. Bit Spmilintbuns Nwba of Bkdes, Cones 3.3 Manny Carla Siff 0-75 in (19] mm) Cma Quantity (Ttnal, Facel (35,23) Cm,W Structure (Inner. Hal Gau6e)Dach1'DachWwbide Number of Nozzles 6SP Fixod TFA O sq.in (O sti mm) Bruning! Seal Package Jwnul %.Insert + sawk Encrow MFS n PRDDUC"I' OVERVIEW Gasnre f Adakaup I.engd3 5,7 in (116.1 mm)+ 17?li in 1138 mm I Bit Breaker 17 Connection 6.5; p Re), Pin ]I:-nn4d PI-4pSM-lb l5a3- Makeuprt ue m1 554tNm1 73 raid Wga ml 417-J6 aka-InIsrn- gp pl 4N.1 Apprac ShippiW W'cig)rt316 lbs (156.9 kg) Ref. Pan Number SI 1"0 Oprrating Rrirannxndatiuns' 11• -dromic raw net I Ratan and Mu6n Appheadon5. Mac 1A:5e1a tot Nit, 6a klb (?6 m x UN) Page 15 Revision 1 June 2019 CLU Drilling Procedure Hilcorp Emu C -W -FY 11.4 13-1/2" directional assy: COMPONENT DATA Item .r ID Gauge Weight Top Bottom Length Cumulative Description (in) (in) (in) (li Connection Connection (ft) Length (ft) 1 ancone 8.750 3.438 13.500 173.30 P 6-518" REG 0.96 0.96 2 8" SpenyDn71 Lobe 475 - g ODO 5.000 121.08 B 6-518" REG B 6-518" REG 32.08 33.04 5.3 still Btm Sleeve Stabilizer 13.250 3 B" DM Collar 7.810 3.500 147.40 B 6-5+8" REG P 6-518" REG 9.00 42.04 4 8" DGR Collar 7 8.000 1.920 142.70 B 6-518" REG P 6-518" REG 4.55 46.59 5 8" EW R -P4 Collar V B-000 2.000 151.00 B 6-516" REG P 6-518" REG 12.19 5878 6 8" HCIM Collar 8.D00 1-920 1 1 149.90 B 6-518" REG P 6-518" REG 4.97 63.75 7 8" TM Collar 7.830 3.250 151.20 B 6-518" REG P 6-5(8" REG 9.07 72.82 8 8' Flex Collar 7.750 2-875 138.64 B 6-518" REG P 6-5/8" REG 30.00 10282 9 8' Flex Collar 7.500 2.875 128.44 B 6.516" REG P 6.518" REG 2922 13204 10 8" Bottle Neck XO 7.875 3.063 140.89 B 4-112" IF P 6-518" REG 3.52 135.56 11 6 3/4' Flex Collar 6.813 2.875 102.10 B 4-1/2" IF P 4.1/2" IF 30.00 165.56 12 6 314' Flex Collar 6.688 2.875 97.58 B 4112" IF P 44/2" IF 30.38 195.94 13 4 112"IF x CDS-40 X- 6.150 2.687 81.91 B 4.5" CDS P 4112" IF 2.57 198.45 Over Sub 40 14 2 Jnts 4.5" CDS-40 4.500 2-613 33.02 61.36 259.81 HWOP 15 CDS40 x 412"IF X- 6200 2.687 83.56 B 4112" IF P 4.5" CDS 2.50 26231 Over Sub 40 16 6 1/4" Jars 6250 2250 91.01 B 4112" IF P 4112" IF 31.79 294.10 17 4 112' IF x CDS40 X- 6-470 2-687 92.72 B 4.5" CDS P 4-112" IF 2.65 296.75 Over Sub 40 18 15 Jnts 4.5" CDS40 4 500 2813 36.86 459.91 756.66 HWDP 756.66 Bit Number Nozzles : 3x16,tx14 Bit size tarn) :13.500 TFA (int) :0.7394 Manufacturer Dull Grade In Model Dull Grade Out Serial Number 11.5 4-1/2" Workstring & HWDP & Jars 11.6 Begin drilling out from 16" conductor at reduced flow rates to avoid broaching the conductor. 11.7 Drill 13-1/2" hole section to 3,300' MD / 2,601' TVD. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Pump at 550 gpm. This gives us an annular velocity of 85 fpm, which is borderline for effective hole cleaning. Ensure shaker screens are set up to handle this flowrate. Page 16 Revision 1 June 2019 n Hileorp E.cW C.�Y CLU #14 Drilling Procedure • Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • Make wiper trips every 500' or every couple days unless hole conditions dictate otherwise. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. Keep API fluid loss < 10. • TD the hole section in a good shale between 3300'— 3,500' MD. • Take MWD surveys every stand drilled (60' intervals). 11.8 13-1/2" hole mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg. MD Totco 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: 1VID System Formulation: AQUAGEL/freshwater spud mud Product Mud � Viscosity PV YP API FL LGS 15 - 20 ppb t 0.1 ppb (8.5 — 9.0 pH) BARAZAN D+ as needed BAROID 41 as required for 8.8 — 9.5 ppg k 120' — 3,300' 8.8 — 9.5 250 - 85 40 - 20 55 - 25 <10 <15% System Formulation: AQUAGEL/freshwater spud mud Product Concentration Fresh Water 0.905 bbl soda Ash 0.5 ppb AQUAGEL 15 - 20 ppb caustic soda 0.1 ppb (8.5 — 9.0 pH) BARAZAN D+ as needed BAROID 41 as required for 8.8 — 9.5 ppg PAC -L /DEXTRID LT if required for <10 FL ALDACIDE G 0.1 ppb 11.9 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16" conductor shoe. 11.10 TOH with the drilling assy, handle BHA as appropriate. Page 17 Revision 1 June 2019 CLU Drilling Procedure Hilcorp Energy ,2,T 12.0 Run 10-3/4" Surface Casing 12.1 R/U and pull 15.375" wearbushing. 12.2 R/U Weatherford 10-3/4" casing running equipment. • Ensure 10-3/4" BTC x CDS 40 XO on rig floor and M/U to FOSV. • R/U fill -up line to fill casing while running. • Ensure all casing has been drifted on the location prior to running. Be sure to count the total # of joints on the location before running. Keep hole covered while R/U casing tools. 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 • (1) Shoe joint w/ float shoe bucked on (thread locked). • (1) Joint with coupling thread locked. • (1) Joint with float collar bucked on pin end & thread locked. • Install (2) centralizers on shoe joint over a stop collar. 10' from each end. • Install (1) centralizer, mid tube on thread locked joint and on FC joint. • Ensure proper operation of float equipment. 12.5 Continue running 10-3/4" surface casing • Fill casing while running using fill up line on rig floor. • Use "API Modified" thread compound. Dope pin end only w/ paint brush. • M/U connections to the base of the triangle stamped on the pin end. Note M/U torque values required to achieve this position. Estimated torque to reach base of triangle: 22,630 ft -lbs. • 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. • Install (1) centralizer every other joint to 300'. Do not run any centralizers above 300' in the event a top out job is needed. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 10-3/4" BTC Estimated M/U Torque Casing OD Est Torque to Reach Trianele Base 10-3/4" 22,630 ft -lbs Page 18 Revision 1 June 2019 CLU Drilling Procedure Hileorp Ena Cnmpeoy TXPC BTC ... 101Tr21316 PIPF BODY DATA GEOMETRY a7sx 11.750 in Min. NUB OWSIdC Gumpty Y0.7SO h dr 4950 n. Type 1hlcl,ness Well Ttdukness 0,p8 s. (.pnn4Nion 00 PERFORMANCE COUFUNO Op[lon Owl. LBO npsr 13141 AIM&andrd is. 5:d. Brown Typs PIPF BODY DATA GEOMETRY a7sx 11.750 in 'S_mi A1Vm;-s 45.5ltr. 11 M Grade LAO dr 4950 n. Type DAN REGULAR 00 T.*e* m API PERFORMANCE COUFUNO PIPE BOGY PERFORMANCE dual Red I5 ?aM Red AIM&andrd is. 5:d. Brown 2nJ Eid tdO OKC LA 2nd BeM:. Brown Casing 3A Band. - 31d Pari - Ih. 41hB2ne W,."ivlOo 11.750 in 'S_mi A1Vm;-s 45.5ltr. 11 oIr lia^ivl 10 4950 n. Ml ihkkne% DAN Plor Er4 NYytl s416[e<k 00 T.*e* m API PERFORMANCE PERFORMANCE 14ns.r L'Bd!rc4 _ �1CW, Ealy 4lrtd ElNMfFi tdO OKC LA o9avml Ykdd 52101.E SVY5 BOND ie I C'jkvS 2476 v1 Ih. CDPIPICCT10N' DA'.A GEOMETRY r.vadkvcu 11.759 k`. Cmpi'k,LrWq MIMS,% cosasnn�Iu a.ax.. ht :A LOY, sera n. Corttmor.)OPW REGULAR PERFORMANCE 14ns.r L'Bd!rc4 _ �1CW, Janl YRk' S:79 -4h 1460044.10.'1: Ink*'nl i'remme (apeYl �' 7210880pR Ih. [a�pmsscO EnezBcy ICA% f,wn;w:ion 3YC'gln 1046e80aNICC Mae. Al:exadL Bu'd.g 342001 n lbs Extsrvl-Yessleo Capa[rt4 2478.404 pv MAKE-UP TORQUES kinmun 201t0 i4bs 071m.m 2263411 krs Ria<mum 24"ll lA5 OPERATION LIMIT TORQUES -- L:pe2ing'uq,n _ S724P1,.Ibs +'ek l�ue Ws0011{a ki—.... Page 19 Revision 1 June 2019 H Hilc T F.ncigy Company CLU #14 Drilling Procedure 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. w�RrjDo` 12.11 After circulating, lower string and land hanger in wellhead again. Page 20 Revision I June 2019 U HilmT c Company E. 13.0 Cement 10-3/4" Surface Casing CLU #14 Drilling Procedure 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. • How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. • Which pump will be utilized for displacement, and how fluid will be fed to displacement PUMP. • Positions and expectations of personnel involved with the cmt operation. • Document efficiency of all possible displacement pumps prior to cement job. 13.2 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.3 Pump 5 bbls 10 ppg spacer. Test surface cmt lines. Pump remaining volume of spacer. 13.4 Drop bottom plug. Mix and pump cmt per below recipe. 13.5 Cement volume based on annular volume + 50% open hole excess. Job will consist of lead & tail, TOC brought to surface. ai Estimated Total Cement Volume: Section: LEAD: 16" Conductor x 10-3/4" casing annulus: LEAD: 13-1/2" OH x 10-3/4" Casing annulus: Total LEAD: TAIL: 13-1/2" OH x 10-3/4" Casing annulus: TAIL: 10-3/4" Shoe track: Total TAIL: Calculation: Vol Vol (ft3) (BBLS) 120' x .106 bpf = 12.8 71.6 SX (2800' —120') x .065 bpf x 1.5 = 260.43 1462.2 273.2 1534 (3300'-2800') x .065 bpf x 1.5 = 48.6 272.8 80 x .096 bpf = 7.68 43.1 56.28 315.9 Page 21 Revision 1 June 2019 n CLU Drilling Procedure Hilcorp Evc Czlx Cement Slurry Design: 13.7 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. 13.8 After pumping cement, drop top plug and displace cement with 9.0 ppg 6% KCl/EZ MUD/BDF- 976 drilling fluid (mud to be used on next hole section). 13.9 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.10 Displacement calculation: V/ 3220' x .0962 bpf= 309 bbls 011'- 13.11 l" 13.11 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.12 Do not over -displace by more than 1/2 shoe track volume. Total volume in shoe track is 8.7 bbls. 13.13 Be prepared for cement returns to surface. If cmt returns are not observed to surface, be prepared to run a temp log between 6 —18 hours after CIP. 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. Page 22 Revision 1 June 2019 Lead Slurry (2800' MD to surface) Tail Slurry (3300' to 2800' MD) System VARICEM (TM) CEMENT BONDCEM (TM) SYSTEM Density 12 1 b/ga 1 15.8 lb/gal Yield 2.386 ft3/sk ✓ 1.215 ft3/sk i Mixed Water 14.11 gal/sk 5.44 gal/sk Expected Thickening 3:42 HR:MIN 3:47 HR:MIN Code Description Concentration Code Description Concentration Typel Cement 94 lb/sk Typel Cement 94 lb/sk Additives WeIlLife 1094 Monofilament fiber 0.21% BWOC WeIlLife 1094 Monofilament fiber o 0.20% BWOC 13.7 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. 13.8 After pumping cement, drop top plug and displace cement with 9.0 ppg 6% KCl/EZ MUD/BDF- 976 drilling fluid (mud to be used on next hole section). 13.9 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.10 Displacement calculation: V/ 3220' x .0962 bpf= 309 bbls 011'- 13.11 l" 13.11 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.12 Do not over -displace by more than 1/2 shoe track volume. Total volume in shoe track is 8.7 bbls. 13.13 Be prepared for cement returns to surface. If cmt returns are not observed to surface, be prepared to run a temp log between 6 —18 hours after CIP. 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. Page 22 Revision 1 June 2019 H HilcOIp E.m Compavy CLU #14 Drilling Procedure 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: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface & volume • Note time cement in place • Note calculated top of cement • 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 d orm e,hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 23 Revision I June 2019 H Hilcorp 14.0 BOP N/U and Test 14.1 N/D the diverter. ctu #14 Drilling Procedure 14.2 N/U wellhead assy. Install packoff 10-3/4" P -seals. Test to 3000 psi. 14.3 N/U 11" x 5M T3 -Energy BOP as follows: • BOP configuration from Top down: 11" x 5M T3 -Energy annular BOP/11" x 5M T3 -Energy Model 6011i double ram /11" x 5M mud cross/11" x 5M T3 -Energy Model 6011i single ram • Double ram should be dressed with 2-7/8 x 5" VBRs in top cavity, blind ram in btm cavity. ©� • Single ram should be dressed with 2-7/8 x 5" VBRs. • N/U bell nipple, install flowline. • Install (1) manual valves & (1) HCR valve on kill side of mud cross. • 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). • Test BOP to 250/3500 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. Ensure to leaves—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% KCI/PHPA drilling fluid for 9-7/8" hole section. 14.8 Set 10" ID wearbushing in wellhead. 14.9 Rack back as much 4-1/2" DP in derrick as possible to be used while drilling the hole section. 14.10 Install 5" liners in mud pumps. HHF-1000 Pumps are rated at 3457 psi (80%) with 5" liners and can deliver 306 gpm at 120 spm. This will allow us to drill the 9-7/8" hole section with (1) mud pump. Page 24 Revision 1 June 2019 U Hilcorp En� C=Wy CLU #14 Drilling Procedure 15.0 Drill 9-7/8" Hole Section Yk j< 15.1 Prior to WILT 9-7/8" directional assembly, test casing against blind rams to 2600 psi / 30 min. 15.2 P/U below 9-7/8" directional drilling assy: 10141. COMPONENT DATA Itern .. ID Gauge Weight Top Bottom Length Curnutative Desiziption Seriall Number [i n) (in) (in) (Ibpq Connection Connection (ft) Length (ft) 1 9 778' PDC 7.600 1 3.000 1 9.875 1 130.51 P 6.58' REG 0.90 090 2 r soerr trill Lobe 7,18 - 7 000 4-952 93.13 B 4-117 IF B &W REG 27.30 281A B6n Sleev_Oe StabAzer 9.6255 3 6 314' DM Collar 6.740 3.125 103.40 B4 -1171F P 4-1/7IF 920 37.40 4 8 N4' DGR Cdlar 6.760 1.920 97.80 B 4117 IF P 41.71F 6.42 43.82 5 6 3W EWR-F4 Codar 6.730 2.000 104.3D 641171F P 4-V2' IF 12.10 55.92 6 Inline Srbtlizer (IQ $-S:I 6.730 1920 9.500 111.37 B 4112' IF P 4-1/7 IF 1.95 57.87 7 6 314' PWD 6.730 1.905 96.30 B 4-117 IF P 41/2' IF 6.43 64.30 B 6 aW HCIM C063r 6.750 1.920 101.70 B 4-117 IF P 4-V2' 1F 6.59 70.89 9 6314"ALD Collar 6.750 1.920 8.062 104-30 B4 -1171F P4-1!2'IF 18.42 89.31 Stabilizer B.D152 - _ 10 6 39* CTN Godar 6.720 1.905 1111M B 4117 IF P 41!2' IF 11.84 101.15 11 634'TMCollar 6.850 3.250 99.70 B4 -1171F P4 -1/2 -IF 10.02 111.17 12 6 314' Flex Co9ar 6.813 2.875 10210 B 41171F P 41/2' IF 30.00 141.17 13 6 3'4' Flex Cour 6.688 2.875 97.58 B 4117 IF P 442' IF 30.38 171.55 14 41!2' IF x COS -40 X- 6.150 2.687 61.91 B 4-5" CDS P 411c' !F 2.51 174.06 Over Sub 40 15 2 Jnts 4.5' CDS-40 4.500 2.813 33.02 61.36 235.42 HWDP 16 6200 2.887 83.56 641171EP 4Y COS 2.50 237.92 Over Sub 40 17 6 1!'4' Jars 6250 2.250 91.01 B 4117 IF P 41!2' IF 31.79 289.71 18 4 1;2'1F x CDS-40 X- 6.470 2.687 92.72 B 4- " O6 P 41,12' IF 2.65 272.35 Over Sub 19 4.500 2.813 36.86 459.91 732.27 HWOP 73227 15.3 Ensure BHA components have been inspected previously. 15.4 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 15.5 Bit TFA should be -.955 in2. We need to pump at -450 - 500 gpm to clean the hole effectively. Have the directional driller run hydraulics calculations to confirm optimum TFA. Page 25 Revision 1 June 2019 n Hilcorp Enew care my 15.6 Primary bit will be the Baker Hughes 9-7/8" Kymera. Hughes Christensen Kymera`" Hybrid Bits 9.875 in. (250.8 mm) KMX524 I) t of tkab War]& Doigned m rake advmlhge ulthe he attributes of rns- boot, Kymm combines roller role and fexed caru caner dones. Impmvtd Dirartirx Contra) Rebrisx to PDC bis, K)K5.Setas lover oveWl torque and minumized wrquc RllctumionsW impm. rats amiml and reduce vArnliom. I.a.a . ilrawr, The rnique lesiLm ofKyto" bas presides an stable drilling p lulonn that miigaaes vibrmitm Mmsl in wiser c PDC emineens[mts. eetnr molfsec voorrul superior directions) bit for motor or rotor) appllctai" with hebm tmifsu vara" m d stecrabiliy than a P Faster and More Durnbk When drilling interbedded mrd hada hmuriva, rebtivx 4r PDC bib, Ibis ulsips design pnvid s irnxa¢M durability In transition zaaes and smo,r&Y, fasttr drilling in hard ruck. Iii) N11111t,.11 ler a rr a�ls.s NmnberofEIhdes, Canes 4.2 Primwv Goner Sim 0.625 in 05.9mm) Cutter gtwLity(TaaL Face) (38.22) C.king Smxsure (Iona, Deet. GaugelCm)cCmieCmbi& Nesnb.Yot No"3ei Fixed TPA „_ Inpp SealIukitpe 4 CSP. I A 0.301 rq.i.(193.55 N.mmt k urnol -Insert r Single F•+ragi. MPS CLU #14 Drilling Procedure PRODUCT ICT O V GR\'7F. W Gnnge ) Makeup Len6A 6 in (152A mm)/ 15347 in(Sg9.g Ilan s Bit Breaker F connection 6-x'6 Reg Pin Ref. Put Number X23211 f ld—Hatt I, 1— uTnEmmis' IhAr.,.nn rL.r�'ra.ra(NnlM ardN4'urch(eNkNlnnl.M-. YelaN (In Iia: 40\I61111n fl tAlV) Page 26 Revision 1 June 2019 a rr a�ls.s al.l-4Dasn.miPrA- MakeupTaque sr .Knurl It..F-�b rye. wl ut. x.am.re lSio. 5h N e[Nm: .Approm. ShilVinF WciuMS16lb*(9gkg) Ref. Put Number X23211 f ld—Hatt I, 1— uTnEmmis' IhAr.,.nn rL.r�'ra.ra(NnlM ardN4'urch(eNkNlnnl.M-. YelaN (In Iia: 40\I61111n fl tAlV) Page 26 Revision 1 June 2019 CLU Drilling Procedure Hib Caa orp E.mM 15.7 9-7/8" hole section mud program summary: Primary weighting material to be used for the hole section will be Calcium Carbonate to minimize solids. We will have barite on location to weight up the active system 1ppg above highest anticipated MW in the event of a well control situation. 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 logger's office. System Type: 9.0 — 9.5 ppg 6% KCl/EZ MUDBDF-976 fresh water based drilling fluid. Properties: MD Mud u ht Viscosity Plastic Yield Point pH HPHT 0.2 ppb (9 pH) Wei3,300- 1.25 ppb (as required 18 YP) Viscosity 2 - 4 ppb EZ MUD DP 0.75 ppb DEXTRID LT 9.0-9.5 40-53 15-25 15-25 8.5-9.5 <_ 11.0 6,732' BAROID 41 as required for a 9.0 — 9.5 ppg ALDACIDE G 0.1 ppb BARACOR 700 1 ppb 15.8 15.9 Product Concentration Water 0.905 bbl KCl 22 ppb (29 K chlorides) Caustic 0.2 ppb (9 pH) BARAZAN D+ 1.25 ppb (as required 18 YP) BDF-976 2 - 4 ppb EZ MUD DP 0.75 ppb DEXTRID LT 1-2 ppb PAC -L 1 ppb BARACARB 5/25/50 15 - 20 ppb (5 ppb of each) BAROTROL/Soltex 2 — 4 ppb as needed BAROID 41 as required for a 9.0 — 9.5 ppg ALDACIDE G 0.1 ppb BARACOR 700 1 ppb BARASCAV D 0.5 ppb maintain per dilution rate TIH, Conduct shallow hole test of MWD and confirm LWD functioning properly. Continue in hole and tag TOC. Note depth tagged on AM report. /i 15.10 Drill out plugs and shoe track. Clean out rat hole and drill an additional 20' of new formation. `4 \ 15.11 CBU and condition mud for FIT. 15.12 Conduct FIT to 12.5 ppg EMW. Page 27 Revision I June 2019 H Hilcorp cow,,2,T CLU #14 Drilling Procedure 15.13 Triple combo LWD will be run in 9-7/8" hole section: -,/ • Gamma Ray (DGR: Combined Gamma Ray) • Resistivity (EWR: Shallow/Med/Deep) • Density (DEN: Bulk Density) • Neutron (NEU: Thermal neutron porosity) • Density Image, dip picks, and additional engineer for same. 15.14 Drill 9-7/8" hole section to 6,732' MD / 5,100' TVD. ' • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Pump at 450 - 500 gpm. Ensure shaker screens are set up to handle this flowrate. • Utilize inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • Make wiper trips every 500' or every couple days unless hole conditions dictate otherwise. If tight hole is encountered, screw in and begin backreaming connections until hole conditions improve. Shales in the Beluga formations are notorious for swelling and causing tight hole. Most of the time, backreaming them on a short trip is the only solution. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. • Take MWD surveys every other stand drld. Surveys can be taken more frequently if deemed necessary /ilasf s•>i 'ur.�, '� �u:-cmr��is a.� Com/ c'�,�s+a ��4s� • The Cingsa gas storage reservoir will be pert6trated at 4,879' TVD and exited at 4,970' TVD. Keep a close eye on gains or losses while drilling through this section. Page 28 Revision 1 5 6 S-66 JP - N` A June 2019 H HilmwE .w Compmy CLU #14 Drilling Procedure 16.0 Run 7-5/8" Intermediate Casing 16.1 R/U and pull 10" ID wear bushing. Install and test 7-5/8" casing ram in top ram cavity. Test to 250/3500 psi. 16.2 R/U 7-5/8" casing running equipment. • Ensure 7-5/8" W563 x CDS-40 XO on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 16.3 PIU 7-5/8" 29.7# L-80 W563 shoe joint, visually verify no debris inside joint. 16.4 Continue M/U & thread locking the shoe track assy consisting of: • (1) Float shoe joint w/ float shoe bucked on. Install (2) bow spring centralizers at 10' from each end over a stop collar. • (1) Baker locked joint. Install (1) centralizer mid tube over a stop collar. • (1) Float collar joint w/ float collar bucked on pin end. Install (1) centralizer mid tube over a stop collar. • Ensure proper operation of float shoe and float collar. 16.5 Run 7-5/8" 29.74 L-80 W563 casing. • Fill casing while running using fill up line on rig floor. • Use "API Modified" thread compound. Dope pin end only w/ paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Install centralizers over couplings on every joint to 5600' MD for cement isolation of ✓ CINGSA storage sand and upper sterling B sands. • Install centralizers over couplings on every 4" joint above 5600' MD to 10-3/4" shoe at 3,300' MD. • Install 7-5/8" Swell Packer at 2,800' (-500' inside the 10-3/4" surface casing). 16.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.7 Slow in and out of slips. 16.8 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 approx 10 — 20' above TD. 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. Page 30 Revision 1 June 2019 H Hilcorp Edgy Compmy Wedge 563® CLU #14 Drilling Procedure ...,,... 10/1912018 Ootdde Diammsr 7,010 in Min. Wall 876+t 0-8a C.nc m.r: GD Opt.h REGULAR Thickness taOAl'. 100.0. 4M" I')GreaeM g'0 Internal Pressure Cepaciy Mad, nllmsalyo Bendin,, ,Ola.WO Pay 48 '1100fl MAKE-UP TORQUES Type 1 Wall Thickness 0,376 m. pnnecllon OD REGULAR 8,001". 00ce,rn � Ma hum o Option OPERATION LIMIT TORQUES LOURaIG pVC &GOY O Vhq Tcraue 30000 n -Cs 8by Rea 1st Bana-Rea Grade LBO Type OnIt Apt standard iel Rand arms. MJ Rand: klninum 14600 a -Ars 2M Bud: - Brown Type Casing 1,d8e d - 3rd Band - dN Rai: - PIPE BODY DATA GEOMETRY Nammm GD T.pssrt Nnmmal WegM "Ja lesh Dnh 0.75n. Nominal ID GATS n. Wal Thickness OATSm Ffaih End Ws,N 80.06 pU8 00 TJ dc. o. d AN PERFORMANCE Bacy Yew SNenam M.1aca His lhm..IYeM an P,I SINS BOOOOpei Collapse /TOO p. CONNECTION DATA GEOMETRY Chch.nn OD &Gap'. Cnupinp Length l.}!'m. Cnmtnkn ID "75 in Makeup Lose PERFORMANCE COW n Thr abper. ix. 0-8a C.nc m.r: GD Opt.h REGULAR Tenon Eptiss, Compromen EF whey Eslemal hesauie C,." taOAl'. 100.0. 4M" j,.N Yield SOc.gm ComOrassian ShonplM1 Couple Face Load GNAOox1000 hs GOA00 0000 o: 055000pe Internal Pressure Cepaciy Mad, nllmsalyo Bendin,, ,Ola.WO Pay 48 '1100fl MAKE-UP TORQUES M1Bnlmem 8,001". 00ce,rn to3WRJ0s Ma hum 151W llaOs OPERATION LIMIT TORQUES O Vhq Tcraue 30000 n -Cs YIeMTcn. 6!000 flJhs BUCK -ON klninum 14600 a -Ars Madmum low ops 7-5/8" W563 Estimated M/U Torque Casing OD Est Torque to Reach Triangle Base 7-5/8" 10,300 ft -lbs Page 31 Revision 1 June 2019 i CLU Drilling Prococ edure Hilcorp 16.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 16.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat (slightly) to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 16.11 Continue circulating until required properties achieved for cmt operations. 16.12 After circulating, lower string and land hanger in wellhead again. Page 32 Revision 1 June 2019 CLU Drilling Procedure Hilcrp E.�,2, 17.0 Cement 7-5/8" Cement Procedure 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. • How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. • Which pump will be utilized for displacement, and how fluid will be fed to displacement PUMP. Positions and expectations of personnel involved with the cmt operation. Document efficiency of all possible displacement pumps prior to cement job. 17.2 Pump 5 bbls 10.0 ppg spacer. Close low torque on plug dropping head, test surface cmt lines to 4000 psi. 17.3 Pump remaining 20 bbls 10.0 ppg spacer. 17.4 Mix and pump slurry per below design: Section: Calculation: Vol (BBLS) Vol (ft3) LEAD: 10-3/4 " CSG x 7-5/8" csg (3300'-2300') x .040 bpf= 40 224.58 ft3 9-7/8" OH x 7-5/8" csg: (5,632-3300') x .038 bpf = 88.6 497.54 f13 Total Lead: 128.6 bbls 722.12 ft3 TAIL: 9-7/8" OH x 7-5/8" csg: (6,732' — 5,632') x .038 b f = 41.8 234.69 R3 7-5/8" CSG Shoe Track 90' x .046 b f = 4.1 23.24 ft3 Total Tail: 45.9 bbls 257.93 ft3 Page 33 Revision 1 June 2019 3or' S� �2 b$Sx µD H Hilcorp EneW C=pmy CLU #14 Drilling Procedure 17.6 After pumping cement, drop top plug and displace cement with 9.2 ppg 6% KCI/EZ MUDBDF- 976 drilling fluid (mud to be used on next hole section). 17.7 Use the cement unit to displace with as volumes can be tracked much more accurately. Displacement calcs: • 6,642' x .0459 bpf = 305 bbls. 17.8 Monitor returns closely while displacing cement. Adjust pump rate if necessary. 17.9 Do not over -displace by more than 1/2 shoe track volume. Total volume in shoe track is 4.1 bbls 17.10 There should be no cmt returns to sur e. TOC is planned to be at 2,300' MD. 17.11 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. Page 34 Revision 1 June 2019 Lead Tail System VARICEM (TM) CEMENT EXPANDACEM (TM) SYSTEM Density 12 Ib/gal 15.3 Ib/gal Yield 2.386 ft3/sk / 1.237 ft3/sk v Mixed Water 14.11 gal/sk 5.55 gal/sk Expected Thickening 6:28 HR:MIN 3:52 HR:MIN Code Description Concentration Code Description Concentration Typel Cement 94 lb/sk Type1 Cement 94 lb/sk Additives WeIlLife 1094 Monofilament fiber 0.21% BWOC WeIlLife 1094 Monofilament fiber 0.20% BWOC 17.6 After pumping cement, drop top plug and displace cement with 9.2 ppg 6% KCI/EZ MUDBDF- 976 drilling fluid (mud to be used on next hole section). 17.7 Use the cement unit to displace with as volumes can be tracked much more accurately. Displacement calcs: • 6,642' x .0459 bpf = 305 bbls. 17.8 Monitor returns closely while displacing cement. Adjust pump rate if necessary. 17.9 Do not over -displace by more than 1/2 shoe track volume. Total volume in shoe track is 4.1 bbls 17.10 There should be no cmt returns to sur e. TOC is planned to be at 2,300' MD. 17.11 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. Page 34 Revision 1 June 2019 CLU Drilling Procedure Hilcorp enemy company Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg). • Cement slurry type, lead or tail, volume & weight. • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration. • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid. • Note if casing is reciprocated or rotated during the job. • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold. • Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure. • Note if pre flush or cement returns at surface & volume. • Note time cement in place. • Note calculated top of cement. • Add any comments which would describe the success or problems during the cementjob. Send final "As -Run" casing tally & casing and cement report to dorm ,hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 17.12 R/D cement equipment. Flush out wellhead with FW. 17.13 Back out and L/D landing joint, flush out wellhead with FW. 17.14 M/U pack -off running tool and pack -off to bottom of landing joint. Set casing hanger pack -off. Run in lock downs and inject plastic packing element. Test void to 250/3000 psi for 10 min. 17.15 Lay down landing joint and pack -off running tool. Page 35 Revision 1 June 2019 18.0 Drill 6-3/4" Hole Section CLU #14 Drilling Procedure 18.1 Remove 7-5/8" casing rams from BOP. Install 2-7/8" x 5" VBRs in top cavity. BOP configuration should be (from top down): AnnularNBR/Blind/Mud cross/VBR. 18.2 Test BOPs on 4-1/2" test joint. 18.3 Ensure mud loggers are R/U for the 6-3/4" production hole section. No samples are required for the production hole section. 18.4 Pull test plug, run and set wear bushing. / L 18.5 RU wireline and run a CBL across the 7-5/8" CSG to confirm cement isolation of CINGSA ^ �.,1,� storage sand and Sterling B sands. Review CBL Log with Drilling Engineer and Geologist prior (�to proceeding. a. Q 4O1� GL ler 18.6 Ensure BHA Components hav een inspected previously. Ensure to hhave e ough 4-1/2" DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 18.7 Drift & caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 18.8 Ensure TF offset is measured accurately and entered correctly into the MWD software. 18.9 Confirm that the bit is dressed with a TFA of — 0.393 in2. Have DD run hydraulics models to ensure optimum TFA. We want to pump at 270 gpm. 18.10 Triple combo LWD will be run in 6-3/4" hole section: • Gamma Ray (DGR: Combined Gamma Ray) • Resistivity (EWR: Shallow/Med/Deep) • Density (DEN: Bulk Density) • Neutron (NEU: Thermal neutron porosity) • Density Image, dip picks, and additional engineer for same. Page 36 Revision 1 June 2019 CLU Drilling Procedure Hilc fta Czx 18.11 P/U below 6-3/4" directional drilling assy: COMPONENT DATA Item .. to Gauge Weight Top Bottom Length CumulatIve # Description Serial Number (in) (in) (in) (Ibpo Connection Connection IN Length fft) 1 6 314" PDC 4.680 1.500 6.750 52.60 P 3-112" REG 0.70 0.70 2 4 314' SperryDrill Lobe 4.750 2-794 44.57 B 312" IF 8 3-112" REG 29.70 30.40 516 - 8.3 st 3 4 314' DM Collar 4.710 2.610 4820 B 3-112" IF P 3-112" IF 921 39.61 4 4 314" EWR I DGR ✓ 4.740 1.250 48.20 B 3-1/2" IF P 3-V2" IF 24-40 64.01 5 4 34" ALD Collar 4.720 1.250 5.625 45.50 B 3-112" IF P 3-112" IF 14.35 76.36 Stabilizer 5.625 _- 6 4 314' CTN Collar 4.760 1.250 50.50 B 3-112' IF P 3-112" IF 11.14 89.50 7 4 314" PWD Collar , 4.730 1250 47.90 B 3-12" IF P 3-112' IF 923 98.73 8 4 314' TM Collar 4.680 2.812 46.10 B 312" IF P 3-12" IF 11.13 109.86 9 4 314' NM Flex Collar 4.625 2.313 42.94 B 3-12" IF P 3-12" IF 31.05 140.91 10 4 3!4' NM Flex Collar 4.750 2.313 46.08 B 3-112" IF P 3.12" IF 31.05 171.96 11 X70 (3 112" IF P x 4 112" 5210 2.750 52.41 B 4-5" CDS P 312" IF 1.35 173.31 CDS 40 B) 40 12 4 its x 4 112' H W DP 4.500 2.687 36.86 122.93 296.24 13 4 12" Jar 4.625 2.500 40.53 B 4.40 DS P 4.40 3171 327.95 14 7 jts x 4 12' HW DP 4.500 2.687 36.86 1 214.33 54228 .® 542211 Page 37 Revision 1 June 2019 18.12 Primary bit will 6-3/4" Baker Hughes Kymera KM323. Hughes Christensen Kvinera 'I" FSR Hybrid Bits Best of Both Worlds Designed to take advantage of the best both, Kymera combines roller cone and fixed cutter element Better toolface control Superior directional bit for motor or r applications with better toolface control and steerabil ity that Improved torque control Kymera bits offer unrivaled torque in the toughest formations: even in transition zones torque is with smooth and fast drilling. Higher overall ROP Maintains PDC -equivalent ROP in soft while increasing ROP in harder formations typically drilled h bits. High efficiency in Carbonates Improved cutting strttcmre op' drilling in carbonates for high efficiency. Bit Specifications Number of Blades, Cons 3.2 Primary Cutter Size 0.44 in (11.2 mm) Cutter Quantity (Total. Face) (20,15) CLU #14 Drilling Procedure PRODUCT OVERVIEW Crating Structure (Inner. Hcel, Gaugc)ConicJWedgclDX PDC Number of Nozzles 2 SP, I PORT Fixed TFA 0.11 sq.in (70.97 sq.mm) Joumal wllnscrt I Bearing r Seal Package Single Energizer MFS Gauge; Makeup Length 3.5 in (88.9 mm) 1 9.801 in (248.9 mm) Bit Breaker N Connection 3-1.12 Reg Pin 41+11"Bir Sub 5.2-5.7kft-Ib(7.0-7.7kNm) Makeup Torque 4 114" Bit Sub 6.3-6.9kft-Ib(8.6-9.4kNm) 412"Bit Sub 7.6-8Akft-Ib(l0.3-114kNnu Approx. Shipping Weight53 His (24 kg) Ref. Patz Number X22715 Operating Recommendations* Hydraulic tlnw rate: 250.550gpm (950.2100Ipm). Rotation Sneed: For Rotary aid Motor Applications. May, W'eielu (At nit: 33 ldb (14 m or kdaN) Page 38 Revision l June 2019 H Hilcorp Eue1gy Compuy CLU #14 Drilling Procedure 18.13 TIH to TOC. Shallow test MWD on trip in. Note depth TOC tagged at on AM report 18.14 Conduct casing test to 3500 ps«�i / 30 min. �^ t� C -.5;d il 18.15 Drill out shoe track and additional 20' new formation. CBU and prep for FIT. 18.16 Conduct FIT to 12.5 ppg EMW. , 18.17 Drill 6-3/4" hole to 10,386' MD / 8,600' TVD using above motor assembly. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • See attached mud program for hole cleaning and LCM strategies. • Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. • Adjust MW as necessary to maintain hole stability. • Ensure mud engineer set up to perform HTHP fluid loss. • Maintain HTHP fluid loss < 6. • Take MWD surveys every stand drilled. • Pull wiper trips every 500 — 1000 ft drilled. If tight hole conditions are encountered, screw in with top drive and begin backreaming connections until hole conditions improve. 18.18 6-3/4" hole section mud program summary: Primary weighting material to be used for the hole section will be Calcium Carbonate to minimize solids. We will have barite on location to weight up the active system 1ppg above highest anticipated MW in the event of a well control situation. 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 logger's office. Page 39 Revision 1 June 2019 H Hilcorp Enegy Company CLU #14 Drilling Procedure System Type: 9.2 — 9.8 ppg 6% KCl/EZ MUDBDF-976 fresh water based drilling fluid. Properties: Product Mud Water Plastic KCl 22 ppb (29 K chlorides) Caustic NM BARAZAN D+ Viscosity BDF-976 Yield Point pH HPHT DEXTRID LT Weight PAC -L Visco2'- BARACARB 5/25/50 15 - 20 ppb (5 ppb of each) BAROID 41 as required for a 9.5 —12.2 ppg 9.2-9.8 40-53 15-25 15-25 8.5-9.5 < 11.0 10,385' Product Concentration Water 0.905 bbl KCl 22 ppb (29 K chlorides) Caustic 0.2 ppb (9 pH) BARAZAN D+ 1.25 ppb (as required 18 YP) BDF-976 2 - 4 ppb EZ MUD DP 0.75 ppb DEXTRID LT 1-2 ppb PAC -L I ppb BARACARB 5/25/50 15 - 20 ppb (5 ppb of each) BAROID 41 as required for a 9.5 —12.2 ppg ALDACIDE G 0.1 ppb BARACOR 700 1 ppb BAP ASCAV D 0.5 ppb (maintain per dilution rate 18.19 Hilcorp Geologists will follow LWD log closely to determine exact TD. 18.20 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8" shoe. 18.21 TOH with drilling assy, handle BHA as appropriate. 18.22 Based on wellbore conditions RU Wireline, attempt to run SLB Sonic/RFT open hole log. 18.23 Monitor the well at all times on the trip tank while logging. 18.24 After logging objectives accomplished, pickup a wiper trip BHA and make another run to TD. Circ B/U at TD and TOH. Handle BHA as appropriate. Page 40 Revision 1 June 2019 CLU #14 Drilling Procedure Hilcorp 19.0 Run 4-1/2" Production Liner! �L- 19.1 R/U Weatherford 4-1/2" casing running equipment. • Ensure 4-]/2" TXP BTC x CDS 40 crossover on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure to R/U Tesco or Weatherford CRT so that string can be rotated if necessary while running. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 19.2 P/U shoe joint, visually verify no debris inside joint. 19.3 Continue M/U & thread locking shoe track assy consisting of: • (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). • (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). • (1) Joint with landing collar installed INSIDE pin end. • Centralizers will be installed on shoe joint & FC joint. • Install a centralizer on landing collar joint. Leave centralizers free floating so that they can slide up and down the joint. • Ensure proper operation of float shoe. 19.4 Continue running 4-1/2" production liner to TD. • Fill casing while running using fill up line on rig floor. • Use "API Modified" thread compound. Dope pin end only w/ paint brush. • Install centralizers on every joint to 9,900' MD. Leave the centralizers free floating. Install them on every other joint from 9,900' to 5,600' MD. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 4-1/2" TXP BTC torques Casine OD Minimum Maximum Yield Torque ft -lbs 6,17U 8,800 Page 41 Revision 1 June 2019 PIPE BODY DATA GEOMETRY aPI L#'ERFORMA-NcE—.- CONNECTION DATA GEOMETRY REGVLAR PERFORMANCE :04 D.. 00 KAKE-Ula TORGUrS E0lp7ETt—KTnGN—LwT VORGUE— .. Page 42 Revision 1 June 2019 CLU Drilling Procedure Hilc E� .2.rp TXP� BTC ri c "- ua . Ty N W REGUWI Gape b.: PIPE BODY DATA GEOMETRY aPI L#'ERFORMA-NcE—.- CONNECTION DATA GEOMETRY REGVLAR PERFORMANCE :04 D.. 00 KAKE-Ula TORGUrS E0lp7ETt—KTnGN—LwT VORGUE— .. Page 42 Revision 1 June 2019 CLU #14 Drilling Procedure Hilc �� ,2,,orp 19.5 M/U baker ZXPN HRDE 4-1/2" liner hanger. Position the shoe approx 10 — 20' above TD. Ensure to run enough liner to set liner top at 5,400'MD. Ensure hanger/pkr will not be set in a 7- 5/8" connection. 19.6 Before picking up Baker ZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 19.7 RIH one stand and circulate a minimum of one liner volume. Note weight of liner. 19.8 RIH w/ liner on DP no faster than 1 min / stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 19.9 MU top drive and fill pipe while lowering string every 10 stands. 19.10 Set slowly in and pull slowly out of slips. 19.11 Circulate 1-1/2 drill pipe and liner volume at 7-5/8" shoe prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure. 19.12 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 19.13 Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill casing. 19.14 PIU the curt stand and tag bottom with the liner shoe. P/U 2' off bottom. Note slack -off and pick-up weights. Record rotating torque values at 10, 20, & 30 rpm. 19.15 Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting pressure. Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling fluid by adding water and thinners. 19.16 Reciprocate & rotate string if hole conditions allow. Circulate until hole and mud is in good condition for cementing. Page 43 Revision I June 2019 CLU Drilling Procedure Hilcorp Page 44 Revision 1 June 2019 CLU Drilling Procedure Hileorp 20.0 Cement 4-1/2" Production C ln>;L-/')�' 20.1 Hold a pre job safety meeting over the upcoming cmt operations. Ensure the below is covered during the meeting: • How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. • Which pump will be utilized for displacement, and how fluid will be fed to displacement PUMP. • Positions and expectations of personnel involved with the cmt operation. • Document efficiency of all possible displacement pumps prior to cement job. • Ensure top and bottom plugs are loaded and sized correctly for the tapered production casing. 20.2 Attempt to reciprocate the liner during cmt operations. 20.3 Pump 5 bbls 10.5 ppg MUDPUSH 11 spacer. 20.4 Test surface cmt lines to 4500 psi. 20.5 Pump remaining 20 bbls 10.5 ppg MUDPUSH II spacer. 20.6 Mix and pump slurries per below recipe. Ensure cmt is pumped at designed weight. Section: Calculation: Vol (BBLS) Vol (ft3) LEAD: 7-5/8" CSG x 4-1/2" csg (6,732'-5,400') x.026 bpf= 34.6 194.27 ft3 6-3/4" OH x 4-1/2" csg: (9,885-6,732') x .025 bpf= 78.8 442.43 ft3 Total Lead: 113.4 bbls 636.7 ft3 TAIL: 6-3/4" OH x 4-1/2" csg: 10,385-9,885' x .025 b f= 12.5 70.18 ft3 4-1/2" CSG Shoe Track 90' x .015 b f= 1.35 7.58 ft3 Total Tail: 13.9 bbls 77.76 ft3 Page 45 Revision 1 June 2019 CLU Drilling Procedure Hilcorp E„ copy 20.7 Drop DP dart and displace with 3% KCl. DP - (5,400 ft x 0.0142) = 77 bbls, Liner - (4,985 ft x.01522) = 76 bbls. 20.8 Pump cement at max rate of 5 bbl/min. Reduce pump rate to 3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re -zeroed at this point. 20.9 If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. Reduce pump rate as required to avoid packoff. 20.10 Bump the plug and pressure up to up as required by Baker procedure to set the liner hanger (15% above nominal setting pressure. Hold pressure for 3-5 minutes. 20.11 Slack off total liner weight plus 30k to confirm hanger is set. 20.12 Do not over displace by more than '/2 shoe track (-1 bbls). Shoe track volume is 1.35 bbls. 20.13 Pressure up to 4000 psi to release the running tool from the liner. 20.14 Bleed pressure to zero to check float equipment. 20.15 P/U, verify setting tool is released, and expose setting dogs on top of tieback sleeve. 20.16 Rotate slowly and slack off 50k downhole to set ZXPN. 20.17 Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as required to maintain 500 psi DP pressure while moving pipe until the Page 46 Revision 1 June 2019 Lead (9,885' — 5,400') Tail (10,385'— 9,885') System VARICEM (TM) CEMENT EXPANDACEM (TM) SYSTEM Density 12 lb/gal 15.3 1 b/ga I Yield 2.386 ft3/sk 1.237 ft3/sk Mixed Water 14.11 gal/sk 5.55 gal/sk Expected Thickening 6:28 HR:MIN 3:52 HR:MIN Code Description Concentration Code Description Concentration Typel Cement 94 lb/sk Type1 Cement 94 lb/sk Additives Welllife 1094 Monofilament fiber 0.21% BWOC WeIlLife 1094 Monofilament fiber 0.20% BWOC 20.7 Drop DP dart and displace with 3% KCl. DP - (5,400 ft x 0.0142) = 77 bbls, Liner - (4,985 ft x.01522) = 76 bbls. 20.8 Pump cement at max rate of 5 bbl/min. Reduce pump rate to 3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re -zeroed at this point. 20.9 If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. Reduce pump rate as required to avoid packoff. 20.10 Bump the plug and pressure up to up as required by Baker procedure to set the liner hanger (15% above nominal setting pressure. Hold pressure for 3-5 minutes. 20.11 Slack off total liner weight plus 30k to confirm hanger is set. 20.12 Do not over displace by more than '/2 shoe track (-1 bbls). Shoe track volume is 1.35 bbls. 20.13 Pressure up to 4000 psi to release the running tool from the liner. 20.14 Bleed pressure to zero to check float equipment. 20.15 P/U, verify setting tool is released, and expose setting dogs on top of tieback sleeve. 20.16 Rotate slowly and slack off 50k downhole to set ZXPN. 20.17 Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as required to maintain 500 psi DP pressure while moving pipe until the Page 46 Revision 1 June 2019 U Hilcorp F.ne Co Y CLU #14 Drilling Procedure pressure drops rapidly, indicating pack -off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top) 20.18 Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 20.19 Pick up to the high -rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re -tag the liner top, and circulate the well clean. 20.20 Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 20.21 POOH, LDDP. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. Backup release from liner hanger: 20.22 If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 20.23 NOTE: Some hole conditions may require movement of the drillpipe to "work" the torque down to the setting tool. 20.24 After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set -down weight to shear second set of shear screws. The top sub will drop I- 3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. 20.25 After wellbore has been cleaned out satisfactorily, test casing to 3500 psi / 30 min. Ensure to chart record casing test. C-7 S I Y V C! Casio ps Page 47 Revision 1 June 2019 CLU Drilling Procedure Hi1COTp E� c��y 22.0 BOP Schematic Page 47 Revision 1 June 2019 CLU Drilling Procedure Hilm7Eaa Compavy 23.0 Wellhead Schematic ttU 814 16X10%X25/8X41/2 Valve, Swab, CIW FI 4 M16 5M FE, MWO, EI Valva Upper Ma: CIW-FLS, 41/1651 HWO, EE VW Valve, MCR.[ CIW-N 41/16 SM FE, XWO. EE MulebOwl WeBbead, SMB -11, 11 SM X16 X 3M, w/ 4-21/16 SM 550 SbrtiN bead, s22 -E2 16 X 3M X 36' SOW, w/ 2-21/165M EM CLU N14 BHT4011 , 41/16 SM FE X 65" obs Quck UN66 ��.M•ma �,XaaFE d1 Ate` Page 48 Revision 1 June 2019 H CLU Drilling Procedure Hilcorp E.e Company 24.0 Days Vs Depth 0 2000 4000 a 0 -0 6000 v m m v g 8000 10000 Days Vs Depth 12000 -- - -- 0 5_ _. _. -10 -. __.. 15 20 25 Days Page 49 Revision 1 ed 30 35 40 June 2019 CLU #14 Drilling Procedure Hilcorp Enema Cam2 25.0 Formation Tops EXPECTED 1gD TVO MOSS NORTHING EASIING. TOPNAME UTHOLOGY FLUID Fj�T (m ST -BI sandstone possible gas 5.722 4,228 --1190 2389.320.22 275.218.61 1903 045 ST -82 sandstone 5,830 4,309 -4271 3,389,353.57 276,277.45 1_939 0.45 ST -C-- sandstone CINGSA - gas storage 6.497 4,679 -4841 2.389.569.08 276,519.62 1650 0.34 US-X(Top Upper Beluga) sandstone possible gas 6.802 5,166 -5128 2.389.658.61 276,543.50 1550 0.30 sandstone possible gas 6.816 5.179 -5141 2.389.658 61 276.551.53 1865 0.3B UB -A UB -B sandstone possible gas - 6,831 5,193 -5155 2.389.646.55 276.569.60 1714 0.33 UB sandstone possible gas 6.870 5,230 -5192 2.389.65033 27B,566.60 2144 0.41 -C US -D sandstone possibfe gas 6,905 5,263 .5225 2389.660.10 276,566.01 2369 0.45 UB -E sandstone depleted gas 6,959 5,314 -5276 2,389,642.33 276,512.16 957 0.18 US -F sandstone possible gas _ 7.003 5,355 -5317 2.389.654. f9 27B,524.13 2410 045 UB -G sandstone depleted gas- _ 7,037 5,388 -5350 2,389,878.13 278,560.02 593 0.11 UB -14 sandstone depleted gas 7.059 5,409 -5371 2,389.672.15 276,524.13 595 0.11 M& -1X (Top Middle Beluga) sandstone possible gas _ 7.509 5,840 -5802 2389.740.94 276.526.25 2628 0.45 - dept 8.099 6.406 -6368 2389.843.80 276,519.96 1217 019 MB -8B sandstone , deple 8.125 6,431 -6393 2.389.835.04. 276,515.58 1865 0.29 MB -9 MB -9A sandstone sandstone depleted 8.158 6,463 -6425 2.389.843.&O 276.541.86 1874 _ 029 MB -98 sandstone possible gas 8.193 6,497 -6459 2.389,856.94 276,515.58 2339 0.36 M8-10 sandstone depleted gas 8,243 6,545 -6507 2.389,865.69 278,498.07 916 0.14 MB -11A sandstone depleted gas 8,309 6,808 -6570 2,389,670.09 278,515.61 991 0.15 MS -11C sandstone depleted gas 9,358 6,655 -6617 2.389,878.83 276,541.86 932 0.14 LB -1 (Top LowerBefuga) sandstone depleted gas 8,442 6,735 -6697 2.369.900.73 278,508.82 1953 0.29 LB-2sandstone possible gas 8.464 6,757 -6719 2389.918.25 276,502.45 2838 042 LB -10 __--____. --- sandstone possible gas 8,730 7.012 -6974 2389,953.29 275,546.24 3156 0.45 LB - Ii sandstone possible gas 8.784 7,064 -7026 2389.955.31 276,500.82 3179 0.45 sandstone possible gas 8.858 7,135 -7097 2389.870.80 276.529.72 2569 0.36 LB -13 LB -19 j sandstone possible gas 9.196 7,459 -7421 2390.269.38 276,383.93 2909 0.39 LB -24 I sandstone possible gas 9.394 7,649 -7611 2.390.354.51 276,366.19 _ 3442_ 0.45 UT -1 sandstone _ possible gas 9.659 7,903 -7865 2.390.383.54. 276.326.37 3557 0.45 10,419 8,632 -8594 2390.535.37 276.118.05 691 0.08 UT -96 sandstone _ _ Page 50 Revision 1 June 2019 K Hilc ,zrp 26.0 Anticipated Drilling Hazards 13-1/2" Hole Section: Lost Circulation: CLU #14 Drilling Procedure Ensure adequate amounts of LCM are available. BARACARBsBAROFIBRE/STEELSEALs. Ensure Walnut M plug is also available for more severe lost returns incidents. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of Bara carb 10 & 20 to the active system at 1 — 2 ppb. Hole Cleaning: Maintain rheology w/ gel and gel extender. Sweep hole with 20 barrels mud, add 1.0 ppb BARAZAN D PLUS 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. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. V/ Page 51 Revision 1 June 2019 R 9-7/8" Hole Section: CLU #14 Drilling Procedure Lost Circulation: Ensure adequate amounts of LCM are available. BARACARBs/BAROFIBRE/STEELSEALs. Ensure Walnut M plug is also available for more severe lost returns incidents. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of Bara carb 10 & 20 to the active system at I — 2 ppb. Hole Cleaning: Maintain rheology w/ gel and gel extender. Sweep hole with 20 barrels mud, add 1.0 ppb BARAZAN D PLUS 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: The use of good drilling practices to minimize excessive swab and surge pressure should be employed to reduce the chances for losses and differential sticking. LCM (BARACARBs 5/25/50) should be maintained at elevated concentrations while drilling coals to help strengthen the wellbore. Black products can be used in this interval if there is potential for coal sloughing. If severe losses are encountered consider spotting multiple sized BARACARB pills throughout the loss zone. Pills should consist of both large and small particle size distributions. 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. • Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. • Use asphalt -type additives to further stabilize coal seams. • Increase fluid density as required to control a "running coal. • Emphasize good hole cleaning through hydraulics, ROP and system rheology. In the event that sloughing coal is encountered, consider spotting a 30 ppb Black products pill across the coal seam. The pill can be safely "squeezed" into the coal by closing the bag and applying pressure not to exceed the total annular pressure loss. H2S: H2S is hole section. CINGSA Gas Storage Sand: Obtain recent Wellhead injection pressure on the offset CINGSA wells to estimate the storage sand pressure. Ensure wellbore mud weights are such we remain overbalanced while drilling through the storage sands. Current Estimated sand pressure of 1650 psi (4,879' TVD) 6.5 ppg equivalent. No abnormal pressures or temperatures are present in this hole section. 6-3/4" Hole Section: Lost Circulation: CLU #14 Drilling Procedure Ensure adequate amounts of LCM are available. BARACARBs. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of Bara carb 10 & 20 to the active system at I — 2 ppb. Hole Cleaning: Maintain a YP between 15 - 25 or as needed to achieve adequate hole cleaning. Pump high viscosity sweeps throughout the interval as needed, particularly prior to POH for casing. Optimized mud rheology and flow rate will be the primary mechanisms for achieving hole cleaning in this deviated wellbore. Maximize pipe rotation (ideally > 100 RPM). Wellbore stability: The use of good drilling practices to minimize excessive swab and surge pressure should be employed to reduce the chances for losses and differential sticking. LCM (BARACARBs 5/25/50) should be maintained at elevated concentrations while drilling coals to help strengthen the wellbore. If severe losses are encountered consider spotting multiple sized BARACARB pills throughout the loss zone. Pills should consist of both large and small particle size distributions 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. • Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. • Increase fluid density as required to control a "running coal". • Emphasize good hole cleaning through hydraulics, ROP and system rheology. H2S: 1-12S is not present in this hole section. Page 53 Revision 1 June 2019 CLU Drilling Procedure Hileorp F.nee� Compmy 27.0 Rig Layout Page 54 Revision 1 June 2019 U HilmE.i como�y 28.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: CLU #14 Drilling Procedure 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 55 Revision 1 June 2019 CLU Drilling Procedure �110�0� 29.0 Choke Manifold Schematic Page 56 Revision ] June 2019 w Ell 1.'��';IYi�I• 11•'f-�I�iiil'-`:��_�1, .I�ii1= -ate �rS'• �t o Ink. �=� x':11 �� 1►r ral'� 0c� - �I�rito+.�yl Page 56 Revision ] June 2019 ff Hilcorp CLU #14 Drilling Procedure 30.0 Casing Design Information Calculation & Casing Design Factors DATE: 5-24-2019 WELL: CLU #14 FIELD: Cannery Loop DESIGN BY: David W Gorm Design Criteria: Hole Size 9-718- Mud Density: 9.5 ppg Hole Size 6-3/4- Mud Density: 9.8 ppg Drilling Mode MASP (sec 1): 1785 psi (See attached MASP determination & calculation) MASP (sec 2): 3010 psi (See attached MASP determination & calculation) Collapse Calculation: Section Calculation 1, 2, 3 Normal gradient external stress (0.44 psVft) and the casing evacuated for the internal stress Page 57 Revision 1 June 2019 Casing Section Calculation/Specification 1 2 3 Casing OD 10-314" 7-518" 4-112" Top (MD) 0 0 5,400 Top (TVD) o 0 4,000 Bottom (MD) 3,300 6,732 10,385 Bottom (TVD) 2,600 5,100 8,600 Length 3,300 6,732 4,985 Weight(ppf) 45.5 29.7 12.6 Grade L-80 L-80 L-80 Connection TXP BTC HYD563 TXP BTC Weight w/o Bouyancy Factor (lbs) 150,150 199,940 152,451 Tension at Top of Section (lbs) 150,150 199,940 152,451 Min strength Tension (1000 lbs) 104D 683 288 Worst Case Safety Factor (Tension) 6.93 3.42 1.89' Collapse Pressure at bottom (Psi) 1,170 2,295 3,870 Collapse Resistance w/o tension (Psi) 2,470 4,790 7,500 Worst Case Safety Factor (Collapse) 2.11 2.09 1.94- MASP (psi) 1,785 3,010 3,010 Minimum Yield (psi) 5,210 6,890 8,430 Worst case safety factor (Burst) 2.92 - 2.29 2.80 Page 57 Revision 1 June 2019 U Hilcorp Enm Company CLU #14 Drilling Procedure 31.0 9-7/8" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 9-7/8" Hole Section riUcurp CLU #14 Kenai, Alaska MO TVD Planned Top: 3300 2600 Planned TD: 6732 5100 Anticipated Formations and Pressures: Formation ND Est Pressure Oil/Gas/Wet PPG Grad ST -01 4,228 1903 possible gas 8.70 .45 ST -B2 4,308 1939 gas (on water) 8.7 0.45 ST -C 4,879 1650 CINGSA - gas storage 6.5 0.34 UB -X (Top Upper Beluga) 5,166 1550 possible gas 5.8 0.30 Offset Well Mud Densities Well MW range TOD (TVDI Bottom IND) Date CLU#7 9.5-9.gppg 1 4,970 7,992 2004 CLU #8 9.3 - 9.8 ppg 1 4,940 7,940 2004 CLU #9 9.2 - 9.8 ppg 2,063 8,041 2004 CLU #13 9.0 -10.0 ppg 2,787 7,660 2015 Assumptions: 1. Maximum planned mud density For the 9-7/8" hole section is 9.5 ppg. 2. Calculations assume reservoirs contain 100% gas (worst case). 3. Calculations assume worst case event is complete evacuation of wellbore to gas. 4. Anticipated fracture gradient at 2600' ND =14.4 ppg EM W Fracture Pressure at ID -3/4" shoe considering a full column of gas from shoe to surface: 2600 (ft) x 0.75(psi/ft)= 1950 psi 1950(psi)-[0.1(psi/ft)12600(ft)]= 1690 psi MASP from pore pressure; entire wellbore evacuated to gas from To 5100 (ft) x A5(psi/ft)= 2295 psi 2295(psi)-[O.1(psi/ft)`510D(ft)]= 1785 psi Summary: 1. MASP during Drilling/production mode is governed by SIBHP minus entire wellbore evacuated to gas from TD. Page 58 Revision I June 2019 U Hilc Enagr ComN 32.0 6-3/4" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 6-3/4" Hole Section H 4 KU 24-058 Kenai, Alaska MD TVD Planned Top: 6732 5100 Planned TD: 10385 8600 CLU #14 Drilling Procedure Formation TVD Est Pressure Oil/Gas/Wet PPG Grad UB -A 5,179 1865 possible gas 0.36 UR -B 5,193 1714 possible gas 0.33 UB -C 5,230 2144 possible gas 0.41 UB -1) 5,263 2369 possible gas 0.45 UB -E 5,314 957 depleted gas 0.18 UR -F 5,355 2410 possible gas 0.45 UB -G 5,388 593 depleted gas 0.11 UB -H 5,409 595 depleted gas 0.11 MB -1X (Top Middle Beluga) 5,840 2628 possible gas 0.45 MB -8B 6,406 1217 depleted gas 0.19 MBA 6,431 1 1865 depleted gas 0.29 MB -9A 6,463 1874 depleted gas 0.29 MB -9B 6,497 2339 possible gas 0.36 MB -10 6,545 916 depleted gas 0.14 MB -13A 6,608 991 depleted gas 0.15 MB -11C 6,655 932 depleted gas 0.14 LB -1 (Top Lower Beluga) 6,735 1953 depleted gas 0.29 LB -2 6,757 2838 possible gas 0.42 LB -30 7,012 3156 possible gas 0.45 LB -11 7,064 3179 possible gas 0.45 LB -13 1 7,135 1 2569 possible gas 0.36 LB -19 7,459 2909 possible as 0.39 LB -24 1 7,649 3442 possible gas 0.45 UT -1 1 7,903 3557 possible gas 0.45 UT -98 8,632 691 MAJOR DEPLETION" 0.08 Offset Well Mud Densities Well MW ranee Too ITV01 Bottom iTVDI Date CLU#7 9.5-9.8pp8 4,970 7,992 2004 CLU #8 9.3 - 9.8 ppg 4,940 7,940 2004 CLU #9 1 9.2 - 9.8 ppg 2,063 1 8,041 2004 CLU #13 1 9.0 - 10.0 ppg 2,787 1 7,660 2015 Assumptions: 1. Maximum planned mud density for the 63/4" hole section is 9.8 ppg. 2. Calculations assume reservoirs contain 100% gas (worst case). 3. Calculations assume worst case event is complete evacuation of wellbore to gas. 4. Anticipated fracture gradient at 5,100'TVD = 13.8 ppg EMW Fracture Pressure at 7-5/8' shoe considering a full column of gas from shoe to surface: 5100 (ft) x 0.72(psi/ft)= 3b72 psi 3672 (psi) - 10.1(psi/ft)'5100(ft)]= 1 3162 psi .fit NWSP from pore pressure; entire wellbore evacuated to gas from TO 8600(ft) x 0.45(ps1/ft)=3870 psi 38701psil- 10.1(psifft)•86W(ft)]= 3030 Page 59 Revision I June 2019 W CLU Drilling Procedure Hilcorp Enna,Compas 33.0 Spider Plot (NAD 27) (Governmental Sections) ADL324G04 J Hllcorp Alaska, LLC /ice FEE AOL 60568 I? FEE ADL60569 Hllcorp Alaska, LLC FEE ADL 60569 CLU0 9 � BHLs'� i cLU 5-z §HLA!" 02 ,ao�.�st�9d i ! i CLU Oa BHI —.� I / I ), % Hilcorp Alaska, LLC S005N011 FEE ADL -40568 i i /RG LOOP UNIT !' e 'o 0 0 o e e e em o CLU _I4_TPH i /oe i CLU Si BHiA' pee 000 oo0 0 14 SHL 'C'W C FISHER IESJNC' e S-peeoo^°e----------------- JOSEPH ___-__—_ JOSEPH A COCHRAN o, Y CLU ss eHLf Hllcorp Alaska, LLC m W � � •^ FEE AA -092401 Legend • CLU 14 -SHL a Omer Surface Well Locations James Kenneth Fouts XL CLU 14_TPH • Omer Bottom Hole Locations T CLU 14_BHL - Well Paths QOil and Gas Unit Boundary I 0 300 1.000 1,500 Cannery Loop Unit CLU -14 Well Feet Alaska State Plane Z. 4, NAD27 A wp12 flit n,rp %I -k,, I.IA klap Dale: 5i24f2019 Page 60 Revision 1 June 2019 n Hilcorp E=W Compmy CLU #14 Drilling Procedure 34.0 Surface Plat (As Built) (NAD 27) SECTON 7, T5N, R11W, S.M. AK PROPERTY LINE / `10' UTILITY EASEMENT I / TRACT A KENAI SPIT I I LU NO.10 SUBDIUSION CLU NO.13 NO.2 aG w -20' CLU N0.14 I I AS -BUILT e THIS SURVEY CLU N0.9 i; F�LU NO.8 CLU NO.1RD �LU N0.6 WATER LINE LBURIED 5'1 L— — —=-=r7 —AS— BURIED FLOWLINES I CLU NO.7 0 CLU NO.5 Z ' J w -21' ® w ,' BLDG a a i ' 3 JO m CANNERY ROAD 83' R/W SECTION 7 S7 8 KENAI CITY LIMITS SECTION 18 Si 1 HILCORPALASKA, LLC NORTH C.L.U. NO. 14 WELL AS -BUILT „ SURFACE LOCATION DIAGRAM sne +Sv CANNERY LOOP UNIT NO.1 PAD GRAPHIC SCALE twnuxievurxt:saemwn[vncro umu 0 70 600 r.o.svwssuv+xr,a�w+ SECTION 7, T5N, RI IX S.M. CITY OF KENAI, Ew. wio w ecaw IBlrorp:llasln. LLC 1-2 KENAI PENINSULA BOROUGH, ALASKA 1 Inch = 80 It Page 61 Revision 1 June 2019 H HilwCm11P�Y 35.0 Offset MW vs TVD Chart MW Vs TVD 0 1000 2000 3000 4000 c 5000 I 6000 7000 8000 9000 10000 8 CLU #i4 Drilling Procedure wit 8.5 9 9.5 10 10.5 MW (PpB) Page 62 Revision 1 June 2019 CLU Drilling Procedure Hi1mTF. m Company 36.0 Drill Pipe Information Page 63 Revision 1 June 2019 / SRE 41/211WEIGHT: ---- -- -- COMMHNO 16.6 ENERGY SERVICES GRADE: S1356s/Fr RANGE 11(31.5D DRILL PIPE SPECS CONNECTION: CDS40 _ TUBE NEW PREMIUM IN MM IN MM OD 4.500 114.3 4.365 110.9 WALLTHICKNESS 0.337 8.6 0.270 6.8 !i ID 3.826 97.2 3.826 97.21 FTt9S N -m FT -LBS N -M TORSIONAL STRENGTH 55.453 75.200 43,451 58.900 80% TORSIONAL STRENGTH 44,362 60.200 34.761 47.100 LEIS DAN LBS DAN TENSILE STRENGTH 595,004 265.300 468,297 208.800 PSI KPA PSI KPA INTERNAL PRESSURE CAPACITY 17,693 121.985 16,176 111,530 COLLAPSE CAPACITY 16.769 1 1 5.615 10.959 75.561 IN= MM2 IN, MM= CROSS SECTIONAL AREA BODY 4,407 2844 3.469 2238 CROSS SECTIONAL AREA OD 15.904 10261 14.966 9655 CROSS SECTIONAL AREA ID 11.497 7417 11497 . 7417 IM MMm INm MMm SECTION MODULUS 4.271 69995 3.347 54845 POLAR SECTION MODULUS. 8.543 139989 6.694 109690 TOOL JOINT EW11 RE PREMIUM PSI KPA PSI KPA YIELD STRENGTH 130,000 896.318 130,000 896,318 IN MM M MM OD 5.2500 133.4 5.1198 130.0 ID 2.6875 68.3 2.6875 68-3 PIN LENGTH 1 1 .O 279.4 1 1 ,O 279.4 BOX LENGTH 14.0 355.6 14.0 355.6 rmns N -M FTLEIS NM TORSIONAL STRENGTH 35,400 48.000 34,700 47.100 MAX MAKE-UP TORQUE 22,500 30.500 21.400 29.000 RECOMMENDED MAKE-UP TORQUE 21,200 28.800 20,800 28.200 MIN MAKE-UP TORQUE 19.600 26.600 19,300 26.200 LBS DAN LBS DAN TENSILE STRENGTH 824.400 367.600 804,900 358,900 TOOL JOINT/DRILL PIPE TORSIONAL RATIO 0.64 0.80 DRILL PIPE ASSEMBLY WITH CONNECTION LBS/FT KG/M ADJUSTED WEIGHT 17,87 26.64 FT M APPROXIMATE LENGTH 31.50 9.60 GAL/FT IAm/M FLUID DISPLACEMENT 0273 0.003394 FLUID CAPACITY 0.577 0.007169 IN MM DRIFT SIZE 2.5625 65 Page 63 Revision 1 June 2019 / CLU Drilling Procedure Hilcorp ERS, c.w4r COMBINED LOAD CURVE FOR 4 1/21' S•135 16.6 LBS/FT DRILL PIPE WITH CDS40 CONNECTIONS 9W.000 -, 800.000 i W/ k. 700,000 600.000 im 1l• + ` _. I 5W.00p 400.000 • • ` 300.000 { • • • ` _ . • ` 00 • , 3.000 • • ` • % 100.000 �'i - • -. - 0 30,000 30,000 30,000 40,DM WON 6p000 M•IWd Togw(ft4W) NEW TUBE COMBINED LOAD PREMrt1M TUBE COMBINED LOAD —MANELPTOROIIE �— SHOULDER SEFERATON —PIN YIELD —BOX YIELD Page 64 Revision 1 June 2019 H Hilcorp E..w C.P y 37.0 Directional Program (WP12) CLU #14 Drilling Procedure Page 65 Revision 1 June 2019 Hilcorp Alaska, LLC Kenai C.I.U. Cannery Loop Unit #1 Pad Plan: Cannery Loop Unit 14 Cannery Loop Unit 14 Plan: CLU -14 wp12 Standard Proposal Report 24 May, 2019 HALLIBUATON Sperry Drilling Services f 1 3850 0 x4400 4950 d It: 5500 °°0 End Dir : 1602.23' MD, 1466.18' TVD 13 O° ry0 ry5� O° 00 O 10 3/4" x 13 1/2"' IV 0 Dale: 2015th-23TOo:0o03 Validated: vee version: Depth Fmm Depth To surveylPan Taol 18.00 3300.00 CLU-14wyt2(CemertLw7p U-014) 2 MWD+IFRI+MS+Sag 3300.00 6]32.23 CLU -4 wo12(Cannery Less Un11141 2MWDHFRI+MS+3m Hildorp Alaska, LLC WDPeth TVDasPaM REFERENCE INFORMATION HALLIBURTON - - 8006 MB" a Itia - - - - . 6600 4226.40 4190.00 922.40 5]401 EMCalculation MError 7150 Method: Minimum Curvature climate (N/E) Reference: Well Plan: Cannery Loop Unit 14, True North = 0 906 4079.40 Error System: ISCWSA 6496.47 ST -C Vertical (TVD) Reference: flan @ 38.40usft (HEC 169) Sperry Drilling 5166.40 5179.40 5193.40 5230.40 5128.0 5141.0 5155.00 51920 Scan Method: closest Approach 3D Measured Depth Reference: Plan Q 3840usft (HEC 169) WD TVD6a MD Sue Neme 120.00 81.60 Surface: Pedal Curve 16 16'x24' Calculation Method: Minimum Curvature 5225.80 6906,21 UB.D 2601.16 Warning Method: Error Ratio 330000 10-3/4 Project: Kenai C.I.U. 5314.40 52760 6960.68 UB -E 5100.00 5061.60 Site: Cannery Loop Unit#1 Pad 7-510 7 510' x 9 51a' 5355.40 5317.00 7001.30 SECTION DETAILS Wag: Pian: Cannery Loop Unit 14 sec MD Inc Azl TVD +N/ -a 'El -W 3Ie9 TF.- VSe4 Target AnnutaLun Wellbore: Cannery Loop Unit 14 1 lado 0.00 0.00 1B.o0 000 Goo 0.00 0.00 0.00 Design: CLU 2 36000 0.80 0.00 350.00 o.0 o0o 0.00 0.00 0.0 Starr Dir3°/100': 350'MD,350WD -14 wpi2 3 550.00 6.00 8500 549.63 0.91 10.42 3.00 85.00 9.54 filen Dir 4°/100':550' MD, 549 TIPA1 112659 4 1602.23 48.05 78.57 1466.10 87.14 489.56 400 -7.13 452.43 End Dir :10223' 100,1486.18' Wb 8483.40 5 5501.26 48.05 ]85] 408.]3 661.63 331110 600 0.00 3213.92 Seat OP 3°/100': SSpt?6'M0.40R.]3'ND fi 5]Bt It 4t 00 0100 4201.66710.81 3501.03 3.00 -149.12 3403.82 EnEDir : 57Bi71'MD.492.66'WD 7 583171 41.00 72.00 431040 720.94 3533.03 000 0.00343600 CLU 14 wp11 T132 Swd0ir4°/1C0':5831.71'MD.43104' D MB -10 8 688034 2057 350.11 5240.54 102547 3845.71 4.00 -148.91 3857.49 End Dir : 689034'010, 5249.54'TVD 657000 9 695841 2057 350.11 5310.40 1040.34 304112 000 0.00 3065.16 CLU 14 writ T2_U&E Stan Dir 3°/100': 6956.41' MD, 5310A'IVD r�1 10 7137.00 1633 339.30 5481.79 1103.41 3827.31 300 -146,U 387944 End Dir : 7137.00'MD.548119'TVD 16" x 24" 11 0175.91 16.33 339.38 743040 1839 82 3625.43 0.00 600 3964]9 CLU 14 wp11 T3_aHL T//VT g d 12 0386.32 1633 33930 8600.00 1958 ?B JSOS.SB 0.00 0 0 401546 Total Depth: 10386.32010. 8600'TVD 873201 LB -10 _ _ _ - - _ _ Start Dir 3°/100' : 350' MD, 350'ND WELL DETAILS: Plan: Cannery Loop Unit 14 Ground Level: 20.40 550 500- - - Start Dir4°/100' : 550' MD, 549.63'TVD + 5 NI- +EI -W Northing Fasting Latittutle Longitude 0.00 0.00 2388681.67 272696.84 60° 31' 56.4397 N 151° 15' 43.4654 W f 1 3850 0 x4400 4950 d It: 5500 °°0 End Dir : 1602.23' MD, 1466.18' TVD 13 O° ry0 ry5� O° 00 O 10 3/4" x 13 1/2"' IV 0 Dale: 2015th-23TOo:0o03 Validated: vee version: Depth Fmm Depth To surveylPan Taol 18.00 3300.00 CLU-14wyt2(CemertLw7p U-014) 2 MWD+IFRI+MS+Sag 3300.00 6]32.23 CLU -4 wo12(Cannery Less Un11141 2MWDHFRI+MS+3m O 7064.40 M260 B yy0 7135.40 7097.00 6. 7459.40 7421.00 9 _ ST -81 _ __ --_ -. _StartDir3°/100': 5501.26'MD,4072.73'TVD sr-ez- -OST- End Oil : 5781.71' MD, 4272.66' TVD 7rv.5�is/�' - GA .5 � 4� CLU 14 wp11 T1_132Start Dir4-/100': 5831.71'MD, 4310.47VD BT -D_ - _ - _ - - _ - - 500 UB -x (Top Upper Beluga) 7 5/8 x 9 5/8' 1 UB-A_ ue S - _ End Dir : 6890.34' MD, 5248.54' TVD UB.D- - UBC _ _ _ _ _ - - _ UB -E_ -E - - C - S - _ UB -pi UB.D _ - _ - _ - - - = 000 - - _ _ _ _ Start Dir 3-/100' : 6956.41' MD, 5310.4'TVD MWIX OW Middle Beiute) CLU 14 wp11 T2_UB-E - _ _ _ _ _ _ _ _ _ _ _ _ End Dir : 7137.08' MD, 5481.79' TVD 6050 MB BB WDPeth TVDasPaM MDPaIh Fomwtbn - - 8006 MB" a Itia - - - - . 6600 4226.40 4190.00 922.40 5]401 -- 8500 LO -10 � 7150 4309.404271.00Si5 ST-B2 = 0 906 4079.40 4841.00 6496.47 ST -C CLU 14 wp11 T3_13H 5166.40 5179.40 5193.40 5230.40 5128.0 5141.0 5155.00 51920 6802.82 6818.05 6831.55 607890 UB -x (Tap Upper Betate) UB -A U13-11 UB -C CASING DETAILS WD TVD6a MD Sue Neme 120.00 81.60 1200 16 16'x24' 526340 5225.80 6906,21 UB.D 2601.16 256216 330000 10-3/4 10 3I4' x 1312' 5314.40 52760 6960.68 UB -E 5100.00 5061.60 6732.23 7-510 7 510' x 9 51a' 5355.40 5317.00 7001.30 US -F 6599.14 856014 10385.42 4-112 4la'x 6314' 538040 5350.00 7039.19 UB -G 5409.40 5040.40 640.40 537100 502.00 6388.00 7061.31 750.76 810654 UB -H MB4x (Top Middle estate) MB -08 6431.40 639300 112659 M9-9 8483.40 6425.00 8159.94 MB -9A ° 6497.40 6459.00 8195.38 MB -98 P°O 854640 807.0 8245.38 MB -10 660840 657000 631103 MB -11A 6655.40 6517,00 U60,00 MB -11C 00° 0 0)35.40 6757.40 6697.0 6719.0 8443.37 8466.29 LB -1 Pop Luee Betaga) LB -2 7012.40 8974.0 873201 LB -10 O 7064.40 M260 B yy0 7135.40 7097.00 6. 7459.40 7421.00 9 _ ST -81 _ __ --_ -. _StartDir3°/100': 5501.26'MD,4072.73'TVD sr-ez- -OST- End Oil : 5781.71' MD, 4272.66' TVD 7rv.5�is/�' - GA .5 � 4� CLU 14 wp11 T1_132Start Dir4-/100': 5831.71'MD, 4310.47VD BT -D_ - _ - _ - - _ - - 500 UB -x (Top Upper Beluga) 7 5/8 x 9 5/8' 1 UB-A_ ue S - _ End Dir : 6890.34' MD, 5248.54' TVD UB.D- - UBC _ _ _ _ _ - - _ UB -E_ -E - - C - S - _ UB -pi UB.D _ - _ - _ - - - = 000 - - _ _ _ _ Start Dir 3-/100' : 6956.41' MD, 5310.4'TVD MWIX OW Middle Beiute) CLU 14 wp11 T2_UB-E - _ _ _ _ _ _ _ _ _ _ _ _ End Dir : 7137.08' MD, 5481.79' TVD 6050 MB BB ' M6_9A MB9 _ _ - - 8006 MB" a Itia - - - - . 6600 -MB 11A - - - c S-jiop Lower Beluga{ -' US 2 e- -- 8500 LO -10 � 7150 18-11- LB -13 = 0 906 LB_19- _ - _ - _ - _ - _ - „ - CLU 14 wp11 T3_13H 9500 10000 4 1/2" x 6 3/4" Total Depth : 10386.32' MD, 8600' TVD CLU -14 wp12 DDI = 5.941 T-'rI�I_F ter- FF 1.7 TT'� _T r '- _'r m_T-TAT ---rITr 0 550 1100 1650 2200 2750 3300 3850 4400 4950 5500 6050 6600 7150 7700 Vertical Section at 60.81- (1100 usft/in) NAWBURTON 0 Proje� iai GLU. Site: ;annery Loop Unit #1 Pa Well: Plan: Cannery Loop Unit 4 Wellbore: Cannery Loop lion U Plan: CLU -14 wp12 Stare Dir 3°/100' : 350' MD, 3504 Stan Dir 4'/100': 550' MD, 549.63 -TVD End Dir : 1602.23' MD, 1466.18' TVD 16". 24" 10 3/4" x 13 IR" weu. oernus. vl.a Canrcrylnep I.h;l IJ GounG reM: 10.W ♦Wan nC0 OJp J.m Non6inI. xItu1e Impish ±±8/8681.61 ±MR6&960J 06°31 5 'fi4)9]N I51°I$'J)4654W cewa.0 lwel am.re..: urx vm". c.nn.rvlmnlmi lJ. ]ne xorn ux°ssw�.a� o�oal n"I°"®a J�w:n I�ia�c isr'i um,mlm xamm: uv�m"m rmax. TIS 611, NIII CLU -14w l2 4 IQ" x 6 3/4" Total Depth: 10386.32' MD, 8600'WD \00 9T 50 g500 J3� 150137.08'MD, 5481]9'TVD g500Start Dir56.41' MD, 53 r0:4'TVD 81508000End D'MD, 5248.54 TVD .9,50 5p0 Start Dir 4"/100'.m, 43I0.4'TVD - .000 75/8"x95/8°--- ?6750 End D1' MD, 4272.66 TVD ' SWDir3"/100':5501.26'6'TV[). U _ _ _ _$ CLU 14"I T2_UD. clu 14 Wpu n_ 1800 2100 2000 _]00 3000 UM 3600 3900 4300 Wdod-)East(+) (450 uvIVn) MALLIBl1RTON Project: Kenai C.I.U. .,.%e � Site: Cannery Loop Unit#1 Pao Well: Plan: Cannery Loop Unit 1 Wellbore: Cannery Loop Unit 14 Plan: CLU -14 wp12 ml— cnxNN ,uwP,zl 4rnE'7 C UIJFRYIlpIUATI'OIR C 100 Wat(-)IEasl(+) (150 asfn) t. a'n luT l.nn 41 __ CANNERY I(R1PIIo 01R0 CANNERYr )P L^ TYIeDwI ac si�,yy s 0 313 667 1000 Ill} 166] 2000 Elll E667 lOM 3313 3667 Wcsl(-) 4+) (500 usWin) [anovNl CvmuylnnplmY Oi cloaca HALLIBURTON Database: NORTH US+CANADA Company: Hiicorp Alaska, LLC Project: Kenai C.I.U. Site: Cannery Loop Unit #1 Pad Well: Plan: Cannery Loop Unit 14 Wellbore: Cannery Loop Unit 14 Design: CLU -14 wpl2 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: Cannery Loop Unit 14 TVD Reference: Plan @ 38.40usft (HEC 169) MD Reference: Plan @ 38.40usft (HEC 169) North Reference: True Survey Calculation Method: Minimum Curvature -roject Kenai C.I.U. Jap System: US State Plane 1927 (Exact solution) - System Datum: Mean Sea Level Seo Datum: NAD 1927 (NADCON CONUS) - Using Well Reference Point dap Zone: Alaska Zone 04 - Using geodetic scale factor Site Cannery Loop Unit #1 Pad Site Position: Northing: From: Map Easting: Position Uncertainty: 0.00 usft Slot Radius: Well Plan: Cannery Loop Unit 14 Well Position +N/ -S 0.00 usft Northing: +E/ -W 0.00 usft Easting: Position Uncertainty 0.50 usft Wellhead Elevation: Wellbore Cannery Loop Unit 14 Magnetics Model Name Sample Date BGGM2018 7/1/2019 2,388,631.67usft Latitude: 272,605.07 usft Longitude: 13-3/16" Grid Convergence: 2,388,681.67 usft • Latitude: 272,696.84 usft • Longitude: 0.00 usft Ground Level: Declination (°) Design CLU -14 wp12 Dogleg Audit Notes: Vertical TVD Version: Phase: PLAN Vertical Section: Depth From (TVD) +NIS System (usft) (usft) (°) 18.00 0.00 Plan Sections Measured Dogleg Build Vertical TVD Depth +E/ -W Inclination Azimuth Rate Depth System (usft) (°/100usft) (°) (°) (°) (usft) usft 18.00 0.00 0.00 0.00 0.00 18.00 -20.40 350.00 0.00 0.00 0.00 10.42 350.00 311.60 550.00 85.00 6.00 85.00 4.00 549.63 511.23 1,602.23 661.63 48.05 78.57 0.00 1,466.18 1,427.78 5,501.26 3,501.83 48.05 78.57 -2.34 4,072.73 4,034.33 5,781.71 0.00 41.00 72.00 0.00 4,272.66 4,234.26 5,831.71 -1.93 41.00 72.00 1,048.34 4,310.40 4,272.00 6,890.34 0.00 20.57 350.11 3,827.31 5,248.54 5,210.14 6,956.41 -146.34 20.57 350.11 0.00 5,310.40 5,272.00 7,137.08 1,958.28 16.33 339.38 0.00 5,481.79 5,443.39 9,175.91 16.33 339.38 7,438.40 7,400.00 10,386.32 16.33 339.38 8,600.00 8,561.60 60° 31'55.9300 N 151* 15'45.2801 W -1.10, 60° 31'56.4397 N 1151' 15'43.4654 W 20.40 usft Dip Angle Field Strength (°) (nT) 15.37 73.46 55,201.61790981 Tie On Depth: 18.00 +E/ -W Direction (usft) (I 0.00 60.81 W42019 4:53:45PM Page 2 COMPASS 5000.15 Build 91 Dogleg Build Turn +N/ -S +E/ -W Rate Rate Rate Tool Face (usft) (usft) (°/100usft) (°/100usft) (°/100usft) (°) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.91 10.42 3.00 3.00 0.00 85.00 87.14 469.56 4.00 4.00 -0.61 -7.13 661.63 3,311.78 0.00 0.00 0.00 0.00 710.81 3,501.83 3.00 -2.51 -2.34 -149.12 720.94 3,533.03 0.00 0.00 0.00 0.00 1,025.47 3,845.71 4.00 -1.93 -7.74 -148.91 1,048.34 3,841.72 0.00 0.00 0.00 0.00 1,103.41 3,827.31 3.00 -2.35 -5.94 -146.34 1,639.82 3,625.43 0.00 0.00 0.00 0.00 1,958.28 3,505.58 0.00 0.00 0.00 0.00 W42019 4:53:45PM Page 2 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Kenai C.I.U. Site: Cannery Loop Unit #1 Pad Well: Plan: Cannery Loop Unit 14 Wellbore: Cannery Loop Unit 14 Design: CLU -14 wpl2 Planned Survey Measured Vertical Depth Inclination Azimuth Depth (usft) (_) (I (usft) 18.00 0.00 0.00 18.00 100.00 0.00 0.00 100.00 120.00 0.00 0.00 120.00 16" x 24" 200.00 0.00 0.00 200.00 300.00 0.00 0.00 300.00 350.00 0.00 0.00 350.00 Start Dir 3°/100' : 350' MD, 350'TVD 400.00 1.50 85.00 399.99 500.00 4.50 85.00 499.85 550.00 6.00 85.00 549.63 Start Dir 4°1100' : 550' MD, 549.63'TVD 600.00 7.99 83.21 599.26 700.00 11.98 81.41 697.73 800.00 15.97 80.50 794.75 900.00 19.97 79.95 889.85 1,000.00 23.96 79.58 982.57 1,100.00 27.96 79.31 1,072.46 1,200.00 31.96 79.10 1,159.08 1,300.00 35.96 78.93 1,242.00 1,400.00 39.96 78.79 1,320.83 1,500.00 43.96 78.68 1,395.18 1,602.23 48.05 78.57 1,466.18 End Dir : 1602.23' MD, 1466.18' TVD 1,700.00 48.05 78.57 1,531.54 1,800.00 48.05 78.57 13598.39 1,900.00 48.05 78.57 1,665.24 2,000.00 48.05 78.57 1,732.09 2,100.00 48.05 78.57 1,798.94 2,200.00 48.05 78.57 1,865.79 2,300.00 48.05 78.57 1,932.64 2,400.00 48.05 78.57 1,999.50 2,500.00 48.05 78.57 2,066.35 2,600.00 48.05 78.57 2,133.20 23700.00 48.05 78.57 2,200.05 2,800.00 48.05 78.57 2,266.90 2,900.00 48.05 78.57 2,333.75 3,000.00 48.05 78.57 2,400.60 3,100.00 48.05 78.57 2,467.46 3,200.00 48.05 78.57 2,534.31 3,300.00 48.05 78.57 2,601.16 10 314" x 13 112" 3,400.00 48.05 78.57 2,668.01 3,500.00 48.05 78.57 2,734.86 3,600.00 48.05 78.57 2,801.71 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan: Cannery Loop Unit 14 Plan @ 38.40usft (HEC 169) Plan @ 38.40usft (HEC 169) True Minimum Curvature 2,629.61 352.02 1,780.05 2,696.46 366.76 1,852.95 2,763.31 381.49 1,925.85 2,388,999.48 274,483.24 2,389,012.81 274,556.40 2,389,026.15 274,629.57 0.00 0.00 0.00 1,725.70 1,796.52 1,867.35 524M19 4.53:45PM Page 3 COMPASS 5000.15 Build 91 Map Map TVDss +N/ -S +El -W Northing Easting DLS Vert Section usft (usft) (usft) (usft) (usft) .20.40 -20.40 0.00 0.00 2,388,681.67 272,696.84 0.00 0.00 61.60 0.00 0.00 2,388,681.67 272,696.84 0.00 0.00 81.60 0.00 0.00 2,388,681.67 272,696.84 0.00 0.00 161.60 0.00 0.00 2,388,681.67 272,696.84 0.00 0.00 261.60 0.00 0.00 2,388,681.67 272,696.84 0.00 0.00 311.60 0.00 0.00 2,388,681.67 272,696.84 0.00 0.00 361.59 0.06 0.65 2,388,681.72 272,697.49 3.00 0.60 461.45 0.51 5.87 2,388,682.07 272,702.71 3.00 5.37 511.23 0.91 10.42 2,388,682.38 272,707.28 3.00 9.54 560.86 1.55 16.48 2,388,682.90 272,713.34 4.00 15.14 659.33 3.92 33.64 2,388,684.95 272,730.55 4.00 31.28 756.35 7.74 57.48 2,388,688.31 272,754.45 4.00 53.96 851.45 12.99 87.87 2,388,692.98 272,784.94 4.00 83.05 944.17 19.65 124.67 2,388,698.92 272,821.86 4.00 118.43 1,034.06 27.68 167.70 2,388,706.12 272,865.03 4.00 159.91 1,120.68 37.04 216.75 2,388,714.54 272,914.25 4.00 207.29 1,203.60 47.69 271.58 2,388,724.14 272,969.27 4.00 260.35 1,282.43 59.57 331.92 2,388,734.86 273,029.82 4.00 318.82 1,356.78 72.63 397.48 2,388,746.66 273,095.62 4.00 382.43 1,427.78 87.14 469.56 2,388,759.78 273,167.96 4.00 452.43 1,493.14 101.54 540.83 2,388,772.82 273,239.49 0.00 521.67 1,559.99 116.28 613.72 2,388,786.15 273,312.65 0.00 592.50 1,626.84 131.01 686.62 2,388,799.49 273,385.81 0.00 663.32 1,693.69 145.75 759.51 2,388,812.82 273,458.98 0.00 734.15 1,760.54 160.48 832.41 2,388,826.15 273,532.14 0.00 804.97 1,827.39 175.21 905.31 2,388,839.48 273,605.30. 0.00 875.80 1,894.24 189.95 978.20 2,388,852.82 273,678.46 0.00 946.62 1,961.10 204.68 1,051.10 2,388,866.15 273,751.62 0.00 1,017.45 2,027.95 219.42 1,123.99 2,388,879.48 273,824.79 0.00 1,088.27 2,094.80 234.15 1,196.89 2,388,892.82 273,897.95 0.00 1,159.10 2,161.65 248.89 1,269.78 2,388,906.15 273,971.11 0.00 1,229.92 2,228.50 263.62 1,342.68 2,388,919.48 274,044.27 0.00 1,300.75 2,295.35 278.35 1,415.58 2,388,932.82 274,117.43 0.00 1,371.57 2,362.20 293.09 1,488.47 2,388,946.15 274,190.59 0.00 1,442.40 2,429.06 307.82 1,561.37 2,388,959.48 274,263.76 0.00 1,513.22 2,495.91 322.56 1,634.26 2,388,972.81 274,336.92 0.00 1,584.05 2,562.76 337.29 1,707.16 2,388,986.15 274,410.08 0.00 1,654.87 2,629.61 352.02 1,780.05 2,696.46 366.76 1,852.95 2,763.31 381.49 1,925.85 2,388,999.48 274,483.24 2,389,012.81 274,556.40 2,389,026.15 274,629.57 0.00 0.00 0.00 1,725.70 1,796.52 1,867.35 524M19 4.53:45PM Page 3 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Kenai C.I.U. Site: Cannery Loop Unit #1 Pad Well: Plan: Cannery Loop Unit 14 Wellbore: Cannery Loop Unit 14 Design: CLU -14 wp12 Planned Survey Measured Vertical Depth Inclination Azimuth Depth TVDss (usft) (1) (1 (usft) usft 3,700.00 48.05 78.57 2,868.57 2,830.17 3,800.00 48.05 78.57 2,935.42 2,897.02 3,900.00 48.05 78.57 3,002.27 2,963.87 4,000.00 48.05 78.57 3,069.12 3,030.72 4,100.00 48.05 78.57 3,135.97 3,097.57 4,200.00 48.05 78.57 3,202.82 3,164.42 4,300.00 48.05 78.57 3,269.67 3,231.27 4,400.00 48.05 78.57 3,336.53 3,298.13 4,500.00 48.05 78.57 3,403.38 3,364.98 4,600.00 48.05 78.57 3,470.23 3,431.83 4,700.00 48.05 78.57 3,537.08 3,498.68 4,800.00 48.05 78.57 3,603.93 3,565.53 4,900.00 48.05 78.57 3,670.78 3,632.38 5,000.00 48.05 78.57 3,737.63 3,699.23 5,100.00 48.05 78.57 3,804.49 3,766.09 5,200.00 48.05 78.57 3,871.34 3,832.94 5,300.00 48.05 78.57 3,938.19 3,899.79 5,400.00 48.05 78.57 4,005.04 3,966.64 5,501.26 48.05 78.57 4,072.73 4,034.33 Start Dir 3-1100': 5501.26' MD, 4072.73'TVD 5,600.00 45.52 76.44 4,140.34 4,101.94 5,700.00 43.01 74.09 4,211.95 4,173.55 5,722.40 42.46 73.53 4,228.40 4,190.00 ST -B1 5,781.71 41.00 72.00 4,272.66 4,234.26 End Dir : 5781.71' MD, 4272.66' TVD 5,800.00 41.00 72.00 4,286.47 4,248.07 5,830.38 41.00 72.00 4,309.40 4,271.00 ST -B2 5,831.71 41.00 72.00 4,310.40 4,272.00 Start Dir 4°/100' : 5831.71' MD, 4310.4TVD 5,900.00 38.68 69.74 4,362.83 4,324.43 6,000.00 35.38 66.00 4,442.67 4,404.27 6,100.00 32.21 61.61 4,525.77 4,487.37 6,200.00 29.22 56.39 4,611.75 4,573.35 V6,300.00 26.47 50.16 4,700.19 4,661.79 1 [ 6,400.00 24.05 42.68 4,790.64 4,752.24 J 6,496.47 22.13 34.14 4,879.40 4,841.00 ST -C 6,500.00 22.07 33.80 4,882.67 4,844.27 6,600.00 20.64 23.52 4,975.84 4,937.44 6,700.00 19.89 12.16 5,069.68 5,031.28 6,732.23 19.81 8.37 5,100.00 5,061.60 7 5/8" x 9 5/8" 6,800.00 19.91 0.39 5,163.75 5,125.35 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan: Cannery Loop Unit 14 Plan @ 38.40usft (HEC 169) Plan @ 38.40usft (HEC 169) True Minimum Curvature 5242019 4:53:45PM Page 4 COMPASS 5000.15 Build 91 Map Map +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) (usft) 2,830.17 396.23 1,998.74 2,389,039.48 274,702.73 0.00 1,938.17 410.96 2,071.64 2,389,052.81 274,775.89 0.00 2,009.00 425.70 2,144.53 2,389,066.15 274,849.05 0.00 2,079.83 440.43 2,217.43 2,389,079.48 274,922.21 0.00 2,150.65 455.16 2,290.32 2,389,092.81 274,995.38 0.00 2,221.48 469.90 2,363.22 2,389,106.14 275,068.54 0.00 2,292.30 484.63 2,436.12 2,389,119.48 275,141.70 0.00 2,363.13 499.37 2,509.01 2,389,132.81 275,214.86 0.00 2,433.95 514.10 2,581.91 2,389,146.14 275,288.02 0.00 2,504.78 528.84 2,654.80 2,389,159.48 275,361.18 0.00 2,575.60 543.57 2,727.70 2,389,172.81 275,434.35 0.00 2,646.43 558.30 2,800.59 2,389,186.14 275,507.51 0.00 2,717.25 573.04 2,873.49 2,389,199.48 275,580.67 0.00 2,788.08 587.77 2,946.39 2,389,212.81 275,653.83 0.00 2,858.90 602.51 3,019.28 2,389,226.14 275,726.99 0.00 2,929.73 617.24 3,092.18 2,389,239.47 275,800.16 0.00 3,000.55 631.98 3,165.07 2,389,252.81 275,873.32 0.00 3,071.38 646.71 3,237.97 2,389,266.14 275,946.48 0.00 3,142.20 661.63 3,311.78 2,389,279.64 276,020.56 0.00 3,213.92 677.17 3,382.03 2,389,293.83 276,091.10 3.00 3,282.83 694.88 3,449.53 2,389,310.25 276,158.92 3.00 3,350.39 699.12 3,464.13 2,389,314.20 276,173.59 3.00 3,365.20 710.81 3,501.83 2,389,325.16 276,211.52 3.00 3,403.82 714.52 3,513.25 2,389,328.65 276,223.00 0.00 3,415.59 720.68 3,532.20 2,389,334.45 276,242.07 0.00 3,435.15 720.94 3,533.03 2,389,334.70 276,242.90 0.00 3,436.00 735.26 3,574.37 2,389,348.22 276,284.50 4.00 3,479.07 757.86 3,630.15 2,389,369.75 276,340.70 4.00 3,538.79 782.32 3,680.06 2,389,393.24 276,391.07 4.00 3,594.29 808.51 3,723.85 2,389,418.59 276,435.35 4.00 3,645.29 836.31 3,761.30 2,389,445.66 276,473.33 4.00 3,691.55 865.58 3,792.24 2,389,474.33 276,504.83 4.00 3,732.84 895.08 3,815.78 2,389,503.38 276,528.92 4.00 3,767.77 896.18 3,816.52 2,389,504.46 276,529.69 4.00 3,768.95 927.96 3,834.01 2,389,535.90 276,547.78 4.00 3,799.72 960.77 3,844.63 2,389,568.50 276,559.03 4.00 3,824.99 971.54 3,846.58 2,389,579.22 276,561.19 4.00 3,831.95 994.44 3,848.33 2,389,602.09 276,563.38 4.00 3,844.65 5242019 4:53:45PM Page 4 COMPASS 5000.15 Build 91 HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: Cannery Loop Unit 14 Company: Hilcorp Alaska, LLC TVD Reference: Plan @ 38.40usft (HEC 169) Project: Kenai C.I.U. MD Reference: Plan @ 38.40usft (HEC 169) Site: Cannery Loop Unit #1 Pad North Reference: True Well: Plan: Cannery Loop Unit 14 Survey Calculation Method: Minimum Curvature Wellbore: Cannery Loop Unit 14 Design: CLU -14 wp12 Planned Survey - _- - Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting OLS Vert Section (usft) (1) (1 (usft) usft (usft) (usft) (usft) (usft) 5,128.00 6,802.82 19.92 0.06 5,166.40 5,128.00 995.40 3,848.34 2,389,603.05 276,563.40 4.00 3,845.12 UB -X (Top Upper Beluga) 6,816.65 19.98 358.45 5,179.40 5,141.00 1,000.12 3,848.28 2,389,607.77 276,563.43 4.00 3,847.36 UB -A 6,831.55 20.07 356.73 5,193.40 5,155.00 1,005.22 3,848.06 2,389,612.87 276,563.31 4.00 3,849.66 UB -B 6,870.98 20.38 352.25 5,230.40 5,192.00 1,018.77 3,846.75 2,389,626.45 276,562.26 4.00 3,855.13 UB -C 6,890.34 20.57 350.11 5,248.54 5,210.14 1,025.47 3,845.71 2,389,633.16 276,561.35 4.00 3,857.49 End Dir : 6890.34' MD, 5248.54' TVD 6,900.00 20.57 350.11 5,257.58 5,219.18 1,028.81 3,845.13 2,389,636.51 276,560.83 0.00 3,858.61 6,906.21 20.57 350.11 5,263.40 5,225.00 1,030.96 3,844.75 2,389,638.67 276,560.50 0.00 3,859.33 UB -D 6,956.41 20.57 350.11 5,310.40 5,272.00 1,048.34 3,841.72 2,389,656.10 276,557.80 0.00 3,865.16 Start Dir 3-1100': 6956.41' MD, 5310.47VD 6,960.68 20.46 349.90 5,314.40 5,276.00 1,049.81 3,841.46 2,389,657.58 276,557.57 3.00 3,865.65 UB -E 7,000.00 19.50 347.94 5,351.35 5,312.95 1,062.99 3,838.89 2,389,670.81 276,555.25 3.00 3,869.83 7,004.30 19.39 347.71 5,355.40 5,317.00 1,064.39 3,838.59 2,389,672.21 276,554.97 3.00 3,870.25 UB -F 7,039.19 18.55 345.78 5,388.40 5,350.00 1,075.43 3,835.99 2,389,683.30 276,552.59 3.00 3,873.37 UB -G 7,061.31 18.03 344.47 5,409.40 5,371.00 1,082.14 3,834.21 2,389,690.04 276,550.93 3.00 3,875.08 UB -H 7,100.00 17.15 341.99 5,446.28 5,407.88 1,093.34 3,830.84 2,389,701.30 276,547.78 3.00 3,877.60 7,137.08 16.33 339.38 5,481.79 5,443.39 1,103.41 3,827.31 2,389,711.44 276,544.45 3.00 3,879.44 End Dir : 7137.08' MD, 5481.79' TVD 7,200.00 16.33 339.38 5,542.17 5,503.77 1,119.97 3,821.08 2,389,728.11 276,538.54 0.00 3,882.07 7,300.00 16.33 339.38 5,638.14 5,599.74 1,146.28 3,811.18 2,389,754.60 276,529.14 0.00 3,886.26 7,400.00 16.33 339.38 5,734.11 5,695.71 1,172.59 3,801.28 2,389,781.10 276,519.75 0.00 3,890.45 7,500.00 16.33 339.38 5,830.08 5,791.68 1,198.90 3,791.38 2,389,807.59 276,510.35 0.00 3,894.63 7,510.76 16.33 339.38 5,840.40 5,802.00 1,201.73 3,790.31 2,389,810.44 276,509.34 0.00 3,895.08 MB -1X (Top Middle Beluga) 7,600.00 16.33 339.38 5,926.04 5,887.64 1,225.21 3,781.48 2,389,834.08 276,500.96 0.00 3,898.82 7,700.00 16.33 339.38 6,022.01 5,983.61 1,251.52 3,771.57 2,389,860.58 276,491.56 0.00 3,903.00 7,800.00 16.33 339.38 6,117.98 6,079.58 1,277.83 3,761.67 2,389,887.07 276,482.17 0.00 3,907.19 7,900.00 16.33 339.38 6,213.95 6,175.55 1,304.14 3,751.77 2,389,913.57 276,472.77 0.00 3,911.38 8,000.00 16.33 339.38 6,309.91 6,271.51 1,330.45 3,741.87 2,389,940.06 276,463.38 0.00 3,915.56 8,100.00 16.33 339.38 6,405.88 6,367.48 1,356.76 3,731.97 2,389,966.55 276,453.98 0.00 3,919.75 8,100.54 16.33 339.38 6,406.40 6,368.00 1,356.90 3,731.91 2,389,966.70 276,453.93 0.00 3,919.77 MB -8B 8,126.59 16.33 339.38 6,431.40 6,393.00 1,363.75 3,729.33 2,389,973.60 276,451.48 0.00 3,920.86 Nil 8,159.94 16.33 339.38 6,463.40 6,425.00 1,372.52 3,726.03 2,389,982.43 276,448.35 0.00 3,922.26 MB -9A 524/2019 4:53:45PM Page 5 COMPASS 5000.15 Build 91 Halliburton H A L L I B U R TO N Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: Cannery Loop Unit 14 Company: Hilcorp Alaska, LLC TVD Reference: Plan @ 38.40usft (HEC 169) Project: Kenai C.I.U. MD Reference: Plan @ 38.40usft (HEC 169) Site: Cannery Loop Unit #1 Pad North Reference: True Well: Plan: Cannery Loop Unit 14 Survey Calculation Method: Minimum Curvature Wellbore: Cannery Loop Unit 14 Design: CLU -14 wp12 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +El -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 6,459.00 8,195.36 16.33 339.38 6,497.40 6,459.00 1,381.85 3,722.52 2,389,991.82 276,445.02 0.00 3,923.74 MB -98 8,200.00 16.33 339.38 6,501.85 6,463.45 1,383.07 3,722.06 2,389,993.05 276,444.59 0.00 3,923.94 8,245.38 16.33 339.38 6,545.40 6,507.00 1,395.01 3,717.57 2,390,005.07 276,440.32 0.00 3,925.84 MB -10 8,300.00 16.33 339.38 6,597.82 6,559.42 1,409.38 3,712.16 2,390,019.54 276,435.19 0.00 3,928.12 8,311.03 16.33 339.38 6,608.40 6,570.00 1,412.28 3,711.07 2,390,022.46 276,434.16 0.00 3,928.58 MB -11A 8,360.00 16.33 339.38 6,655.40 6,617.00 1,425.16 3,706.22 2,390,035.44 276,429.56 0.00 3,930.63 MB -11C 8,400.00 16.33 339.38 6,693.78 6,655.38 1,435.68 3,702.26 2,390,046.03 276,425.80 0.00 3,932.31 8,443.37 16.33 339.38 6,735.40 6,697.00 1,447.09 3,697.97 2,390,057.52 276,421.72 0.00 3,934.12 1-13-1 (Top Lower Beluga) 8,466.29 16.33 339.38 6,757.40 6,719.00 1,453.13 3,695.70 2,390,063.60 276,419.57 0.00 3,935.08 LB -2 8,500.00 16.33 339.38 6,789.75 6,751.35 1,461.99 3,692.36 2,390,072.53 276,416.40 0.00 3,936.49 8,600.00 16.33 339.38 6,885.72 6,847.32 1,488.30 3,682.46 2,390,099.02 276,407.01 0.00 3,940.68 8,700.00 16.33 339.38 6,981.69 6,943.29 1,514.61 3,672.55 2,390,125.52 276,397.61 0.00 3,944.87 8,732.01 16.33 339.38 7,012.40 6,974.00 1,523.03 3,669.39 2,390,133.99 276,394.61 0.00 3,946.21 LB40 8,786.19 16.33 339.38 7,064.40 7,026.00 1,537.29 3,664.02 2,390,148.35 276,389.51 0.00 3,948.48 LB -11 8,800.00 16.33 339.38 7,077.65 7,039.25 1,540.92 3,662.65 2,390,152.01 276,388.22 0.00 3,949.05 8,860.17 16.33 339.38 7,135.40 7,097.00 1,556.76 3,656.69 2,390,167.95 276,382.56 0.00 3,951.57 LB -13 8,900.00 16.33 339.38 7,173.62 7,135.22 1,567.23 3,652.75 2,390,178.50 276,378.82 0.00 3,953.24 9,000.00 16.33 339.38 7,269.59 7,231.19 1,593.54 3,642.85 2,390,205.00 276,369.43 0.00 3,957.43 9,100.00 16.33 339.38 7,365.56 7,327.16 1,619.85 3,632.95 2,390,231.49 276,360.03 0.00 3,961.61 9,175.91 16.33 339.38 7,438.40 7,400.00 1,639.82 3,625.43 2,390,251.60 276,352.90 0.00 3,964.79 9,197.79 16.33 339.38 7,459.40 7,421.00 1,645.58 3,623.26 2,390,257.40 276,350.84 0.00 3,965.71 LB -19 9,200.00 16.33 339.38 7,461.52 7,423.12 1,646.16 3,623.05 2,390,257.98 276,350.64 0.00 3,965.80 9,300.00 16.33 339.38 7,557.49 7,519.09 1,672.47 3,613.14 2,390,284.48 276,341.24 0.00 3,969.98 9,400.00 16.33 339.38 7,653.46 7,615.06 1,698.78 3,603.24 2,390,310.97 276,331.85 0.00 3,974.17 9,500.00 16.33 339.38 7,749.43 7,711.03 1,725.09 3,593.34 2,390,337.46 276,322.45 0.00 3,978.36 9,600.00 16.33 339.38 7,845.39 7,806.99 1,751.40 3,583.44 2,390,363.96 276,313.06 0.00 3,982.54 9,700.00 16.33 339.38 7,941.36 7,902.96 1,777.71 3,573.54 2,390,390.45 276,303.66 0.00 3,986.73 9,800.00 16.33 339.38 8,037.33 7,998.93 1,804.02 3,563.63 2,390,416.95 276,294.27 0.00 3,990.92 9,900.00 16.33 339.38 8,133.29 8,094.89 1,830.33 3,553.73 2,390,443.44 276,284.87 0.00 3,995.10 10,000.00 16.33 339.38 8,229.26 8,190.86 1,856.64 3,543.83 2,390,469.93 276,275.47 0.00 3,999.29 10,100.00 16.33 339.38 8,325.23 8,286.83 1,882.95 3,533.93 2,390,496.43 276,266.08 0.00 4,003.47 10,200.00 16.33 339.38 8,421.20 8,382.80 1,909.26 3,524.03 2,390,522.92 276,256.68 0.00 4,007.66 10,300.00 16.33 339.38 8,517.16 8,478.76 1,935.57 3,514.12 2,390,549.41 276,247.29 0.00 4,011.85 10,385.42 16.33 339.38 8,599.14 8,560.74 1,958.04 3,505.67 2,390,572.04 276,239.26 0.00 4,015.42 4112"x6314" - 5,24/2019 4:53:45PM Page 6 COMPASS 5000.15 Build 91 HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: Cannery Loop Unit 14 Company: Hilcorp Alaska, LLC TVD Reference: Easting Plan @ 38.40usft (HEC 169) Project: Kenai C.I.U. MD Reference: (usft) Plan @ 38.40usft (HEC 169) Site: Cannery Loop Unit#1 Pad North Reference: 0.00 True Well: Plan: Cannery Loop Unit 14 Survey Calculation Method: Minimum Curvature Wellbore: Cannery Loop Unit 14 8,599.14 4 1/2" x 6 3/4" 6,732.23 Design: CLU -14 wp12 - Circle (radius 50.00) Planned Survey Measured Vertical CLU 14 wp11 T2 US -E Map Map Depth Inclination Azimuth Depth TVDss +NI -S +E/ -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 8,561.59 10,386.31 16.33 339.38 8,599.99 8,561.59 1,958.28 3,505.58 2,390,572.28 276,239.18 0.00 4,015.46 Total Depth : 10386.32' MD, 8600' TVD 10,386.32 - 16.33 339.38 8,600.00 8,561.60 - 1,958.28 3,505.58 2,390,572.28 276,239.18 0.00 4,015.46 Targets Target Name -hit/miss target Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing Easting -Shape (°) (°) (usft) (usft) (usft) (usft) (usft) CLU 14 wpl1 T3 BHL 0.00 0.00 7,438.40 1,639.82 3,625.43 2,390,251.60 276,352.90 - plan hits tarqet center 10,385.42 8,599.14 4 1/2" x 6 3/4" 6,732.23 5,100.00 7 5/8" x 9 5/8" - Circle (radius 50.00) CLU 14 wp11 T2 US -E 0.00 0.00 5,310.40 1,048.34 3,841.72 2,389,656.10 276,557.80 - plan hits target center - Circle (radius 50.00) CLU 14 wp11 T1 B2 0.00 0.00 4,310.40 720.94 3,533.03 2,389,334.70 276,242.90 - plan hits target center - Circle (radius 50.00) Casing Points Measured Vertical Depth Depth (usft) (usft) Name 3,300.00 2,601.16 10 3/4" x 13 1/2" 120.00 120.00 16" x 24" 10,385.42 8,599.14 4 1/2" x 6 3/4" 6,732.23 5,100.00 7 5/8" x 9 5/8" Casing Hole Diameter Diameter 16-3/4 13-1/2 16 24 4-1/2 6-3/4 7-5/8 9-7/8 5/242019 4.:53:45PM Page 7 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US +CANADA Local Co-ordinate Reference: Company: Hilcorp Alaska, LLC TVD Reference: Project: Kenai C.I.U. MD Reference: Site: Cannery Loop Unit #1 Pad North Reference: Well: Plan: Cannery Loop Unit 14 Survey Calculation Method: Wellbore: Cannery Loop Unit 14 ST -B1 Design: CLU -14 wp12 UB -G Formations Measured Vertical Vertical Local Coordinates Depth Depth Depth SS +N/ -S (usft) (usft) Name 7,061.31 5,409.40 UB -H 8,100.54 6,406.40 MB -8B 5,722.40 4,228.40 ST -B1 7,039.19 5,388.40 UB -G 8,245.38 6,545.40 MB -10 6,960.68 5,314.40 UB -E 8,466.29 6,757.40 LB -2 6,496.47 4,879.40 ST -C 8,126.59 6,431.40 MB -9 5,830.38 4,309.40 ST -B2 8,360.00 6,655.40 MB -11C 9,197.79 7,459.40 LB -19 7,004.30 5,355.40 UB -F 8,860.17 7,135.40 LB -13 6.,831.55 5,193.40 UB -B 8,159.94 6,463.40 MB -9A 6,870.98 5,230.40 UB -C 8,311.03 6,608.40 MB -11A 8,786.19 7,064.40 LB -11 6,802.82 5,166.40 UB -X (Top Upper Beluga) 6,906.21 5,263.40 UB -D 8,732.01 7,012.40 LB -10 8,443.37 6,735.40 LB -1 (Top Lower Beluga) 8,195.36 6,497.40 MB -9B 6,816.65 5,179.40 UB -A 7,510.76 5,840.40 MB -1X (Top Middle Beluga) Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/ -S +E/ -W (usft) (usft) (usft) (usft) 350.00 350.00 0.00 0.00 550.00 549.63 0.91 10.42 1,602.23 1,466.18 87.14 469.56 5,501.26 4,072.73 661.63 3,311.78 5,781.71 4,272.66 710.81 3,501.83 5,831.71 4,310.40 720.94 3,533.03 6,890.34 5,248.54 1,025.47 3,845.71 6,956.41 5,310.40 1,048.34 3,841.72 7,137.08 5,481.79 1,103.41 3,827.31 10,386.31 8,599.99 1,958.28 3,505.58 Halliburton Standard Proposal Report Well Plan: Cannery Loop Unit 14 Plan @ 38.40usft (HEC 169) Plan @ 38.40usft (HEC 169) True Minimum Curvature Dip Dip Direction Lithology (1) (`) Comment Start Dir 3-/100': 350' MD, 350'TVD Start Dir 40/100': 550' MD, 549.63'TVD End Dir : 1602.23' MD, 1466.18' TVD Start Dir 30/100' : 5501.26' MD, 4072.73'TVD End Dir : 5781.71' MD, 4272.66' TVD Start Dir 4°/100' : 5831.71' MD, 4310.4'TVD End Dir : 6890.34' MD, 5248.54' TVD Start Dir 30/100' : 6956.41' MD, 5310.47VD End Dir : 7137.08' MD, 5481.79' TVD Total Depth : 10386.32' MD, 8600' TVD 6=6 a 5/24/2019 4:53:45PM Page 8 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Kenai C.I.U. Cannery Loop Unit #1 Pad Plan: Cannery Loop Unit 14 Cannery Loop Unit 14 CLU -14 wp12 Sperry Drilling Services Clearance Summary Anticollision Report 24 May, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: Cannery Loop Unit #1 Pad -Plan: Cannery Loop Unit 14 -Cannery Loop Unit 14 -CLU-14 wp12 Well Cri.n males: 2,388,681.6] IN, 272,696.84 E (60" 31' 56 44" N, 151° 15' 43.47' W) Datum Height Plan@ 38.40usfl)HEC 169) Scan Range: 0.00 to 10,386.32 usR. Measured Depth. Scan Radius is Unlimited. Clearance Faclorcutoff is Unlimited Max Ellipse Separation is 1,500L0 usfl Derrell. S.rle Factor Applied Version: 5000.15 Build: 91 Scan Type: Scan Type. 2560 HALLIBURTON Sperry Drilling 9ervii HALLIBURTON Anticollision Report for Plan: Cannery Loop Unit 14 - CLU -14 ill Hilcorp Alaska, LLC Kenai C.I.U. Closest Approach 30 Proximity Scan on Current Survey Data (North Reference) 484.76 Reference Design: Cannery Loop Unit #1 Pad - Plan: Cannery Loop Unit 14 - Cannery Loop Unit 14 - CLU -14 wP12 307.15 Scan Range: 0.00 to 10,386.32 usft. Measured Depth. 2.729 Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Pass - Measured Minimum ®Measured Ellipse c@Measured Clearance Summary Based on Separation Warning Site Name Depth Distance Depth Separation Depth Factor Minimum Comparison Well Name - Wellbore Name - Deaden (usft) (usft) (usft) (usft) usft Cannery Loop Unit Cannery Loop Unit S-3 - Cannery Loop Unit S-3 - CLU Cannery Loop Unit S-3 - Cannery Loop Unit S-3 - CLU Cannery Loop Unit S-3 - Cannery Loop Unit S-3 - CLU Cannery Loop Unit SA - Cannery Loop Unit S4 - CLU Cannery Loop Unit S4 - Cannery Loop Unit S4 - CLU Cannery Loop Unit S5 - Cannery Loop Unit S-5 - CLU Cannery Loop Unit S-5- Cannery Loop Unit S-5 - CLU Cannery Loop Unit #1 Pad Cannery Loop Unit 01 - Cannery Loop Unit 01 - Canne Cannery Loop Unit 01 - Cannery Loop Unit 01 - Canne Cannery Loop Unit 01 - Cannery Loop Unit 01RD - CA Cannery Loop Unit 01 - Cannery Loop Unit 01 RD - CA Cannery Loop Unit 01 - Cannery Loop Unit 01 RDPB1 Cannery Loop Unit 01 - Cannery Loop Unit 01 RDPB1 Cannery Loop Unit 05- Cannery Loop Unit 05 - CLUO( Cannery Loop Unit 05- Cannery Loop Unit 05 - CLUO! Cannery Loop Unit 05 - Cannery Loop Unit 05 - CLUO: Cannery Loop Unit 05 - Cannery Loop Unit 05RD - CL Cannery Loop Unit 05 - Cannery Loop Unit 05RD - CL Cannery Loop Unit 05 - Cannery Loop Unit 05RD - CL Cannery Loop Unit 06 - Cannery Loop Unit 06 - Canne Cannery Loop Unit 06 - Cannery Loop Unit 06 - Canne Cannery Loop Unit 06 - Cannery Loop Unit 06 - Canne Cannery Loop Unit 07 - Cannery Loop Unit 07 - Canne Cannery Loop Unit 07 - Cannery Loop Unit 07 - Canne Cannery Loop Unit 08 - Cannery Loop Unit 08 - Canne Cannery Loop Unit 08 - Cannery Loop Unit 08 - Cents 6,750.00 484.76 6,750.00 307.15 8,693.00 2.729 Clearance Factor Pass - 6.775.00 482.09 6,775.00 306.11 8,69300 2.739 Ellipse Separation Pass - 6.830.19 479.67 6,830.19 308.84 8,693.00 2.808 Centre Distance Pass - 6,450.00 310.34 6,450.00 122.32 8,393.33 1.651 Clearance Factor Pass - 6,479.42 309.11 6,479.42 123.15 8,392.15 1.662 Centre Distance Pass - 6,318.38 330.01 6,318.38 147.85 8,348.75 1.812 Centre Distance Pass - 6,325.00 330.09 6,325.00 147.68 8,348.85 1.810 Clearance Factor Pass - 350.00 110.44 350.00 107.43 353.60 36.729 Ellipse Separation Pass - 10,200.00 1,477.30 10,200.00 1,350.27 9,686.64 11.629 Clearance Factor Pass - 350.00 110.44 350.00 107.43 353.60 36.729 Ellipse Separation Pass - 725.00 147.97 725.00 142.62 728.70 27.622 Clearance Factor Pass - 350.00 110.44 350.00 107.43 353.60 36.729 Ellipse Separation Pass - 725.00 147.97 725.00 142.62 728.70 27.622 Clearance Factor Pass - 712.44 50.75 712.44 44.90 732.61 8.677 Centre Distance Pass - 725.00 5078 725.00 44.84 745.25 8.549 Ellipse Separation Pass - 825.00 53.76 825.00 47.10 845.76 8.075 Cleamnce Factor Pass - 712.44 50.75 712.44 44.90 716.01 8.676 Centre Distance Pass - 725.00 50.78 725.00 44.84 728.65 8.548 Ellipse Separation Pass - 825.00 53.76 825.00 47.10 829.16 8.073 Clearance Factor Pass - 400.30 216.38 400.30 212.99 408.90 63.852 Centre Distance Pass - 750.00 217.84 750.00 211.88 801.38 36.577 Ellipse Separation Pass - 2,825.00 608.44 2,825.00 557.00 2,944.13 11.829 Clearance Factor Pass - 1,030.25 5182 1,030.25 43.95 1,010.96 8.583 Ellipse Separation Pass - 1,050.00 52.02 1,050.00 44.07 1,029.58 6.546 Clearance Factor Pass - 704.16 184.81 704.16 178.91 748.61 31.310 Centre Distance Pass - 725.00 184.96 725.00 178.89 769.55 30.494 Ellipse Separation Pass - 24 May, 2019 - 16:54 Page 2 pis COMPASS HALLIBURTON Hilcorp Alaska, LLC Kenai C.I.U. Anticollision Report for Plan: Cannery Loop Unit 14 - CLU -14 Wp12 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Survey Tool Reference Design: Cannery Loop Unit 01 Pad - Plan: Cannery Loop Unit 14 - Cannery Loop Unit 14 - CLU -14 Wp12 Scan Range: 0.00 to 10,386.32 usft. Measured Depth. 2_MWD+IFRI+MS+Sag Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft 2 MWD+IFRI+MS+Sag Measured Minimum @Measerad Ellipse @Measured Clearance Summary Based on Separation Warning P 9 Site Name Depth Distance Depth Separation Depth Factor Minimum Comparison Well Name -Wellbore Name - Design (usft) (usft) (usft) (usft) usft Cannery Loop Unit 08- Cannery Loop Unit 08-Canne 9,275.00 484.38 9,275.00 380.03 9,369.76 4.642 Clearance Factor Pass - Cannery Loop Unit l3- Cannery Loop Unit 13 -GLUM 800.00 28.81 800.00 22.50 794.34 4.568 Clearance Factor pass - Cannery Loop Unit l3- Cannery Loop Unit l3 -GLUM 807.81 2874 807.81 22.47 801.91 4.578 Ellipse Separated Pass - Survey tool Drouram From To Survey/Plan Survey Tool (usft) (usft) 18.00 3,300.00 CLU -14 wp12 2_MWD+IFRI+MS+Sag 3,300.00 6,732.23 CLU-14wp12 2 MWD+IFRI+MS+Sag 6,732.23 10,386.32 CLU-14wp12 2_MWD+IFRI+MS+Sag Ellipse error terms are correlated across survey tool tiebn points. Calculated ellipses incorporate surface around. Separation is the actual distance between ellipsoids. Distance Between cares is the straight line distance between wellbore centres. Clearenca Factor= Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 24 May, 2919 - 16:54 Page 3 of 5 COMPASS MALLIBIL I F ITON BpsreY Oe1N1nB Project Kenai C.LU. Sile: cannery loop Oi . end Well: Plan: Carvery Lope Unit 14 Wellborn: Camery loop Unit 14 Plan: CLU -14 "12 Ladder I S.F. Pints QD —IC.1JlN�E�RY�L UNR 01- Pat .G65 OO _- I� I r m II � m ar Cannery Loop nil 01 W CLU M13 I o 70.00 U o �— CLU05R +_ y 35.00 i ca 0.00 0 550 1100 1650 2200 2750 3300 FEFERENCE INFOflMATONryry cn (".).l. --tee r -,c n1'E�., un w, irve Nmu MeazumcA.� o- MUM]. IAI.—tA.-Ee IBSI SVP�EY iROONM mM:misn.zarm.onm wne.re: ve. w.M.: na reYm an cUU-U txl[amery L, Um Yl ilA'Sn'IFRt•MSe3ap .10 ,cene x ttW1Jp1)IfineNLap Vrvlje¢fNJMIFA1eMS�9Tp� Measured Depth pElABS%an:CmrylaplSni114 NM I9x)MAaONCQ\U81 AW4e IDneW UwnE le�cl: +A Jtl OW OW x]5%fll6) E73696.BJ 611°)1'564)9)\ I51`li'1]<65JW NO GLOBAL FILTER: Uaine um defimd seNation & 00eltp an" 1800 To 1038632 CASING DETAlls TOO NESS M Sim Nana 12000 01.60 120.00 16 16` Y 14° 1601,16 256]]6 3300.00 1e -3l4 10114"r 1316" 510000 506160 673211 7-519 15 V" 9 5 V oroe �e ne.vn 11 1alR, 4, 4-16 41/2"16314" 8800 Measured Depth STATE OF ALASKA AL ,<A OIL AND GAS CONSERVATION COMM. ION PERMIT TO DRILL 20 AAC 25.005 RECEIVED MAY 16 2,119 1a. Type of Work: Drill ❑✓ ' Lateral ❑ Redrill ❑ Reentry ❑ 1 It. Proposed Well Class: Exploratory -Gas ❑ Stratigraphic Test ❑ Development - Oil ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - WAG ❑ Service - Disp ❑ Service - Win) ❑ Single Zone ❑� ' Service - Supply ❑ Multiple Zone ❑ 1 c. Specify if well is proposed for: Coalbed. Gas ❑ .Gas Hydrates ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: Hilcorp Alaska, LLC 5. Bond: Blanket 0 • Single Well ❑ Bond No. 022035244 11. Well Name and Number: CLU 14 ' 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 6. Proposed Depth: MD: 9,375' • TVD: 7,630' 12. Field/Pool(s): Cannery Loop Unit Kenai Sterling Gas Pool 3 4a. Location of Well (Governmental Section): Surface: 232' FSL, 275' FEL, Sec 7, T5N, R11 W, SM, AK - Top of Productive Horizon: 931' FSL, 2114' FEL, Sec 8, T5N, R11 W, SM, AK Total Depth: 1932' FSL, 1956' FEL, Sec 8, T5N, R11 W, SM, AK 7. Property Designation: ADL60569, ADL60568, ADL324602 8. DNR Approval Number: LOCI 78-156 13. Approximate Spud Date: 6/28/2019 9. Acres in Property: 1048 14. Distance to Nearest Property: 2312' to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): Surface: x-272696 y- 2388681 • Zone -4 10. KB Elevation above MSL (ft): 38.4 GL / BF Elevation above MSL (ft): 20.4 - 15. Distance to Nearest Well Open to Same PoolV2146to CLU -06 16. Deviated wells: Kickoff depth: 400 feet • Maximum Hole Angle: 48 degrees 17. Maximum Potential Pressures in psig (see 20 AAC 225+035) ^�5 Downhole: 3420 - ` Surface: 2Z12,;&-7% 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade I Coupling I Length MD TVD MD TVD (including stage data) Cond 16" 109# X-56 Weld 120' Surface Surface 120' ' 120' jS -Driven 13-1/2" 10-3/4" 45.5# L-80 TXP BTC 3,300' Surface Surface 3,300' 2,562' L - 208+113 / T - 315 ft3 9-7/8" 7-5/8" 29.7# L-80 W563 9,374' Surface Surface 9 4' 7,630' 1606 ft3 19. PRESENT WELL CONDITION SUMMARY (To be comp) ted for Redri nd Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect epth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Hydraulic Fracture planned? Yes ❑ N 20. Attachments: Property Plat O B9011i ve er DiSketch e Drilling Program Seabed Report Time v. Depth PlotShallow B Drilling Fluid Program e Hazard Analysis 20 AAC 25.050 requirementse 21. Verbal Approval: Commission Represents t : Date 22. 1 hereby certify that the foregoing is tr 96and the procedure approved herein will not be deviated from without prior written appr al. Contact Name: David Gorm Authorized Name: Monty Myers Contact Email: 490-m@hilcom.com Authorized Title: Drilling Mane er Contact Phone: 777-8333 Authorized Signal '— Date: S - i 6 . Commission Use Only Permit to Drill _) Q - Number: �� /' PI Number: ��// h 50- 33 L��[v / '"-D Permit Approval Date: See rover letter for other requirements. 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: Other: ✓ 250 ,QSt {X/I SI- Samples req'd: Yes ❑ No[ Mud log req'd: Yes No 'h .J / HzS measures: Yes ❑ No Directional svy req'd: Yes [y� No ❑ —0 41 -4 Spacing exception req'd: Yes ❑ No ❑ Inclination -only svy req'd: Yes ❑ No Q _ nn Post initial injection MIT req'd: Yes ❑ No ❑ APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: R A Submit Form and Form 10-401 Revised 5/2017 'g O/ This permit is valid t d e f approval per 20 AAC 5(g) Attachments in Duplicate Hilcorp Alaska, LLC CLU #14 Drilling Program Cannery Loop W Approved by: David W Gorm Revision 0 May 2019 U Hilcorp En C2ix 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0 11.0 Contents WellSummary .................................... Management of Change Information Tubular Program:....... Drill Pipe Information: CLU #14 Drilling Procedure .......................................................................2 .......................................................................3 ..................................................4 ...................4 InternalReporting Requirements..................................................................................................5 PlannedWellbore Schematic..........................................................................................................6 Drilling / Completion Summary Mandatory Regulatory Compliance / Notifications.....................................................................8 R/U and Preparatory Work..........................................................................................................10 NX21-1/4" 2M Diverter...............................................................................................................11 Drill13-1/2" Hole Section.............................................................................................................14 12.0 Run 10-3/4" Surface Casing.........................................................................................................18 13.0 Cement 10-3/4" Surface Casing...................................................................................................21 14.0 BOP N/U and Test.........................................................................................................................24 15.0 Drill 9-7/8" Hole Section...............................................................................................................25 16.0 Run 7-5/8" Production Casing.....................................................................................................29 17.0 Cement 7-5/8" Cement Procedure ...............................................................................................32 19.0 BOP Schematic..............................................................................................................................35 20.0 Wellhead Schematic......................................................................................................................36 21.0 Days Vs Depth................................................................................................................................37 22.0 Formation Tops.............................................................................................................................38 23.0 Anticipated Drilling Hazards.......................................................................................................39 24.0 Rig Layout......................................................................................................................................41 25.0 FIT Procedure................................................................................................................................42 26.0 Choke Manifold Schematic...........................................................................................................43 27.0 Casing Design Information...........................................................................................................44 28.0 9-7/8" Hole Section MASP............................................................................................................45 29.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................46 30.0 Surface Plat (As Built) (NAD 27).................................................................................................47 31.0 Offset MW vs TVD Chart.............................................................................................................48 32.0 Drill Pipe Information...................................................................................................................49 33.0 Directional Program(WPI I) ........................................................................................................51 U Hilcorp Eos CLL 1.0 Well Summary CLU #14 Drilling Procedure Well CLU #14 Pad & Old Well Designation CLU #14 is a grass roots well on Pad #1 Planned Completion Type Perforated Target Reservoir(s) Sterling B sand and Beluga sands Planned Well TD, MD / TVD 9,374' MD / 7,630' TVD PBTD, MD / TVD 9,294 MD / 7,550' TVD Surface Location (Governmental) 232' FSL, 275' FEL, Sec 7, T5N, RI IW, SM, AK Surface Location (NAD 27) X=272696.838, Y=2388681.671 Surface Location (NAD 83) X=1412722.164, Y=2388435.821 Top of Productive Horizon (Governmental) 931' FSL, 2114' FEL, Sec 8, T5N, RI IW, SM, AK TPH Location (NAD 27) X = 276159, Y = 2389307 BHL (Governmental) 1932' FSL, 1956' FEL, Sec 8, T5N, RI l W, SM, AK BHL (NAD 27) X = 276334, Y = 2390304 AFE Number 1912716 AFE Drilling Das 25 AFE Drilling Amount $4,500,000 Maximum Anticipated Pressure Surface 2212 psi ' Maximum Anticipated Pressure (Downhole/Reservoir) 3420 psi Work String 4-1/2" 16.6# S-135 CDS-40 KB Elevation above MSL: 38 ft ' GL Elevation above MSL: 20 ft BOP Equipment 11" 5M T3 -Energy Annular BOP 11" 5M T3 -Energy Double Ram 11" 5M T3 -Energy Single Ram Page 2 Revision 0 May 2019 CLU Drilling Procedure Hileorp 2.0 Management of Change Information 11 Hilcorp Alaska, LLC xitcotp = Changes to Approved Permit to Drill Date: 5.6-2019 Subject: Changes to Approved Permit to Drill for CLU #14 File #: CLU #14 Drilling and Completion Program Any modifications to CLU #14 Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be rsieeted-te-the BLM and AOGCC. C.4?11 r-e.(lL'rz� cam.-. dU�'z:tic. -I' Ll' /A Sec Page Date Procedure Change Approved Approved By 13 Approval: Prepared: Drilling Manager Drilling Engineer Date Date Page 3 Revision 0 May 2019 CLU Drilling Procedure Hi1COIp c�� mw 3.0 Tubular Program: 4.0 Drill Pipe Information: -Wt Grade Conn Burst Collapse Tension 4.5" 3.826 2.6875" 5.25" 16.6 S-135 �TCDS40 17,693 16,769 468k All easing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Revision 0 May 2019 ID Drift Collapse """"JEWW Tension (in) (in) (psi) (k -lbs) (in) Cond 16" 15" - - 109 X-56 Weld 13-1/2" 10-3/4" 9.95" 9.875" 11.75" 45.5 L-80 T)O�BTC 5210 2480 1040 9-7/8" 7-5/8" 6.875" 6.75" 8.5" 29.7 L-80 W563 6890 4790 683 4.0 Drill Pipe Information: -Wt Grade Conn Burst Collapse Tension 4.5" 3.826 2.6875" 5.25" 16.6 S-135 �TCDS40 17,693 16,769 468k All easing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Revision 0 May 2019 n Hilcorp Enc g Company 5.0 Internal Reporting Requirements CLU #14 Drilling Procedure 5.1 Fill out daily drilling report and cost report on Wellez. • Report covers operations from 6am to 6am • 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. • Ensure time entry adds up to 24 hours total. • 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 • Submit a short operations update each work day to ddgormnhilcorp.com, mmyers@hilco!p.com hilcorp.com and cdinger@hileorp.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam 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 • 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: 0:907-777-8477 0:907-350-9439 • Notify Drlg Manager 1. Monty M Myers: 0: 907-777-8431 C: 907-538-1168 • Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally • Send final "As -Run" Casing tally to dgorm@hilcorp.com, mmyers@hilcorR.com and cdingert7ahilcgM.com 5.6 Casing and Cmt report • Send casing and cement report for each string of casing to dizorrn@hilcorp.com, mmyers@hilcoEp.com hilcorp.com and cdinger(a hilcorp.com Page 5 Revision 0 May 2019 CLU Drilling Procedure Hilcorp Enm C2,7 6.0 Planned Wellbore Schematic n Irlw�,:ua.,la. IAA: R®: M51= 38' 103/4" TD -9,37,r [MD)/7,630 (ND) PHID-9,291' (ND)/ 7.550• WM) Cannery Loop PROPOSED SCHEMATIC Well: CLU #14 PTD: TBD �r CASING DETAIL Size Type Wt/Grade/Conn ID Top Bun 16" CoMwor li 109/X-56/WWd 16" Sort 130' 10-3/d." 5urtace I a S/L�/TXVBTC I 9.950' Suit 3,300' 7-S/8' production I 29.7/L4I0/W563 I 6.875" Surt 9,37x' JEWELRY DETAIL No Depth Item 1 2800' 7-5/8" Swell Packer ��.OPEN MOLE / CEMENT DETAIL 10.3/4' 219 BBC, d cement in 13.5' Hole. Returns to S (face (0%excess) BBL's d cement in 9-]/8' Hde. Est TOC @ 3.300' (0%..) Page 6 Revision 0 May 2019 H Hilcorp 7.0 Drilling/ Completion Summary CLU #14 Drilling Procedure CLU #14 is a grass roots development well from Pad #1 in the Cannery Loop Field targeting the Sterling B sands and Beluga sands. The base plan is an "S" turn wellbore, kicking off at 350' MD and building to 48 deg, then dropping back to 16 deg starting at 5,471' MD, then drilling a 16 deg tangent to TD at 9,374' MD. Drilling operations are expected to commence approximately June 28th, 2019. The Hilcorp Rig # 169 will be used to drill and partially complete the wellbore. A workover rig will follow behind to install the tbg/SSSV/packer and perforate thru-tbg. Surface casing will be run to 3,300 MD and cemented to surface to ensure protection of surface water. 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 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 21-1/4" x 2M diverter. 3. Drill 13-1/2" hole to 3,300' MD. Run and cmt 10-3/4" surface casing. 4. N/D diverter, N/U & test 11"x 5M T3 -Energy BOP. 5. Drill 9-7/8" production hole section to 9,374' MD. Run and cmt 7-5/8" production casing. Reservoir Evaluation Plan: 1. Surface hole: Mud loggers will generate a mud log. /(?LS -r- �� s Zv•l3 2. Production hole: LWD: GR + Res + Den/Neu (Triple Combo). Mud loggers will generate a mud log. Based on production hole conditions will attempt to run Sonic and XPT open hole logs. Page 7 Revision 0 May 2019 CLU #14 Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling and completion of CLU #14. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. • The initial test of BOP equipment will be to 250/3500 psi & subsequent tests of the BOP equipment will be to 250/3500 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • 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 he charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system" • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements" • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: • None at this time. Page 8 Revision 0 May 2019 Summary of BOP Equipment and Test Requirements CLU #14 Drilling Procedure Hole Section Equipment Test Pressure(psi) 13-1/2" 21-1/4" x 2M Hydril MSP diverter Function Test Only • 1 I" x 5M T3 -Energy (Model 7082) Annular BOP Initial Test: 250J46r0 • 1 l" x 5M T3 -Energy Double Ram o Blind ram in him cavity (Annular 2500 psi) • Mud cross 9-7/8" • 11" x 5M T-3 Energy Single Ram • 3-1/8" 5M Choke Line Subsequent Tests: 3Sv • 2-1/16" x 5M Kill line 250/A999- • 3-1/8" x 2-1/16' 5M Choke manifold (Annular 2500 psi) • Standpipe, floor valves, etc • Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). ZlV • Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: • Well control event (BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPS. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: iim.regg@alaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz@alaska.gov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / Email: melvin.rixse@alaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectois@alaska.gov Test/Inspection notification standardization format: hitp://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 Revision 0 May 2019 H Hilcorp Enema 2jx 9.0 R/U and Preparatory Work CLU #14 Drilling Procedure 9.1 Set 16" conductor at 112' below ground level (120' RKB). Additional depth is required to isolate the shallow gravel beds in the area. 9.2 Dig out and set impermeable cellar. 9.3 Install 16-3/4" 3M "A" section. Ensure to orient wellhead so that tree will line up with flowline later. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of rig. 9.6 R/U Hilcorp Rig # 169, spot service company shacks, spot & R/U company man & toolpusher offices. 9.7 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.8 Mix mud for 13-1/2" hole section. 9.9 Set test plug in wellhead prior to NIU diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.10 Install 5-1/2" liners in mud pumps. • HHF-1000 Pumps 1000 mud pumps are rated at 3633 psi (85%) / 333 gpm (100%) with 5- 1/2" liners. Page 10 Revision 0 May 2019 H Hilcorp F.ncW campy 10.0 N/U 21-1/4" 2M Diverter CLU #14 Drilling Procedure 10.1 N/U 21-1/4" Hydril MSP 2M diverter System. • N/U 16-3/4" 3M x 21-1/4" 2M DSA (Hilcorp) on 16-3/4" 3M wellhead. • NIU 21-1/4" diverter "T". • Knife gate, 16" diverter line. 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. --!!- No �- � 1 knpc-� 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: • A prohibition on vehicle parking. A prohibition on ignition sources or running equipment. A prohibition on staged equipment or materials. Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set 15.375' ID wearbushing in wellhead. Page 11 Revision 0 May 2019 10.5 Rig and Diverter Line Orientation on CLU # 14: CLU #14 Drilling Procedure SECTION 7, T5N, R11W, S.M. AK PROPERTY LINE / 10' UTILITY EASEMENT i TRACT A \� KEN/ 701T SUB[ \a I vc4_LU N0.10 CLU N0.�,3 I®I ®LU NO.8 lJ DnnL. CLU NO.9 ® BURIED ELOWIin.-" � �z Q z CLU NOARD CLU NO.5 CLU N0.7 a W I®yLU NO.6 IWATER LINE LBURIED 5't f / BLDG / / 0 09� Page 12 Revision 0 May 2019 H Hilcorp Ems C2'7 10.6 Diverter Schematic Annular Preventer Diverter Tee, 21-'/." x 2M wl 16" ANSI 150 16-3/4" 3M x 21-''/" 2M 16-3/4"3M Casing head Assy CLU #14 Drilling Procedure Page 13 Revision 0 May 2019 U Hilcorp E.c C27 11.0 Drill 13-1/2" Hole Section CLU #14 Drilling Procedure 11.1 P/U 13-1/2" directional drilling assy: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Bit TFA should be —0.7 to 0.75 int. We need to pump at 500 - 550 gpm to clean the hole effectively. Workstring will be 4.5" 16.64 S-135 CDS40 11.2 Hydraulics Summary: (7) V- Page 14 Revision 0 May 2019 Est Open Depth- Hole Size Pump Rate Standpipe hole AV MW ECD TFA MD (ft) (in) (gpm) Pressure (psi) (fpm) (ppg) (ppg) (in2) BHA 1 MM+MWD+25 0 — 3,300' 13-1/2" 550 1800 85 9.0 9.3 0.739 HWDP (7) V- Page 14 Revision 0 May 2019 n Hilcorp E.m Compmy CLU #14 Drilling Procedure 11.3 Primary bit will be the 13-1/2" Hughes Christensen Kymera Hybrid Bit KM633. Hughes Christensen Kymera"m Hybrid Bits Ben of Bath %k M6 Desigmed w take advantage of the ben amibutes or bodx Kymem combines rolls cone and fixed cutin demems Improved Directional Cromnd Relative to PDC bits, Kymera gwalraui, In»rr Overall kv" and milimind torque IWeWmiom to impm%*W free control and rectum vibrations. Lower vibmeim The uniquedesign of "'mem bits provides an smbledrillingplatroan ftmitigates vib C,,m presentmroIk,Ci PDC enviro mens. Korner tonlfuv c,mnol Superior Arecticmal bit for motor Or notary applications with better 1001 face cmmmi and steembility tlmn a P Faster and More Durable When drilling interbedded and harder fnnnatiom relative to PDC bits. this unique design provides increased durability in Imnsition noses and smoothes Fanerddlling in hens rock. Bit Speciliank4ts NunnberafBladeS, Com 3,3 Primary CuOn Six 0.-e5 in t 19.1 mm) CImv Quality (Total, Face) (35,23) Cutting Suucmre (Im ent. Heel, Gaugr)@achl+DaddhCwbuk NumbcrofNoaks 6SP Fixed TFA 0sq.in(0 sq.mm) Bearing i Seal Package Journal »; Insen ( S** Energim MFS PRODUCT' OVERVIEW b.! Gauge i Makeup L. in 5.75 in 1146.1 mm) i 17245 in (433 mm) Bit Breaker F Comnextion 6.58 Reg Pin 1.46 11R'ail5ua ill -4a XV-11,-11,lin 3. Makeup Tongue 42 m ]3N"W Wgee ail 42 1.46 4k6-IhIR4- Ste 63 9N. Aprra Shy W'eight.Wftxs(156.9kg) Ref, Pan Number 511980 Olvrnling ReLVTl11tendat101li' Ileamnlie emu ra4 6361330ppa1(2450.51 W Ipnn. iln NOW) and Motor k1b(216 m orkda%) Page 15 Revision 0 May 2019 H Hilcorp Evc� Campavy 11.4 13-1/2" directional assy: CLU #14 Drilling Procedure COMPONENTDATA Item # Description Serial Number .r (in) to (in) Gauge Weight (in) (Ibpf) Top Bottom Connection Connection Length (ft) Cumulative Length (ft) 1 Tricone 8.750 3.438 13.500 173.30 P 6-518" REG 0.96 0.96 2 8" SpenyDrill Lobe 415 - 5.3 st B.000 5.000 121.08 B 6-518" REG B 6-518" REG 3208. 33.04 Btm Sleeve stabilizer 13250 3 8' DM Collar 7.810 3.500 147.40 B 6-518" REG P 6-518" REG 9.00 4204. 4 8' DGR Collar B.000 1.920 142.70 B 6-518" REG P 6-518" REG 4.55 4659 5 8" EW R -P4 Collar 8.000 2000. 151.00 B 6-518" REG P 6-5/8" REG 12.19 58.78 6 B" HCIM Colar 8.000 1 1.920 1 149.90 IS 6518' REG P6-W8'REGI 4.97 63.75 7 8" TM Collar 7.830 3250 151.20 8 6-5+6" REG P 6.518' REG 9.07 72.82 8 8' Flex Collar 7.750 2.875 138.64 B 6-518' REG P 648" REG 30.00 102.82 9 8" Flex Collar 7.500 2.875 128.44 B 6-518" REG P6 -""REG 2922 132.04 10 8" Bottle Neck XO 7.875 3.063 140.89 B 4-112" IF P 651B' REG 3.52 135.56 11 6 314' Flex Collar 6.813 2.875 102.10 B 4-12" IF P 4-112" IF 30.00 165.56 12 6 314' Flex Collar 6.688 2.875 97.58 B 4-10 IF P 4112" IF 30.38 195.94 13 4 12'IF x CDS-40 X- Over Sub 6.150 2.687 81.91 B 4.5" CDS P 4112" IF 1 40 2.51 198.45 14 2 JntsF4.55' PDS -40 4.500 2.813 33.02 61.36 25981 15 CDS40 x 4 12"IF X- Over Sub 6200 2.687 83.56 B 4-112" IF P 4.5" CDS 40 2.50 262.31 16 6 114' Jars 6250 2250 91.01 B 4-112" IF P4 -171F 31.79 294.10 17 4 112' IF x CDS40 X- Over Sub 6.470 2.687 94.72 B 4.5" CDS P 4.12" IF 40 2.65 296.75 18 15 Jnfs 4.5" CDS-40 HWDP 4.500 2.813 36.86 459.91 75666 756.66 Bit Number Nozzles :3x16.104 Bit Size (M) : 13.500 TFA (in2) : 0.7394 Manufacturer Dull Grade In Model Dull Grade Out Serial Number 11.5 4-1/2" Workstring & HWDP & Jars. 11.6 Begin drilling out from 16" conductor at reduced flow rates to avoid broaching the conductor 11.7 Drill 13-1/2" hole section to 3,300' MD / 2,600' TVD. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Pump at 550 gpm. This gives us an annular velocity of 85 fpm, which is borderline for effective hole cleaning. Ensure shaker screens are set up to handle this flowrate. Page 16 Revision 0 May 2019 H Hilcorp EveW Comp y CLU #14 Drilling Procedure • Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • Make wiper trips every 500' or every couple days unless hole conditions dictate otherwise. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. Keep API fluid loss < 10. • TD the hole section in a good shale between 3300'— 3,500' MD. . • Take MWD surveys every stand drilled (60' intervals). 11.8 13-1/2" hole mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg. MD Totco 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: NID Concentration Viscosity PV YP API FL LGS 15 - 20 ppb Wei ht 0.1 ppb (8.5 — 9.0 pH) BARAZAN D+ as needed BAROID 41 as required for 8.8 — 9.5 ppg 120' — 3,300' 8.8 — 9.5 ' 250- 85 40-20 55-25 <10 <15% System Formulation: AQUAGEL/freshwater spud mud Product Concentration Fresh Water 0.905 bbl soda Ash 0.5 ppb AQUAGEL 15 - 20 ppb caustic soda 0.1 ppb (8.5 — 9.0 pH) BARAZAN D+ as needed BAROID 41 as required for 8.8 — 9.5 ppg PAC -L /DEXTRID LT if required for <10 FL ALDACIDE G 0.1 ppb 11.9 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16" conductor shoe. 11.10 TOH with the drilling assy, handle BHA as appropriate. Page 17 Revision 0 May 2019 12.0 Run 10-3/4" Surface Casing 12.1 R/U and pull 15.375" wearbushing. CLU #14 Drilling Procedure 12.2 R/U Weatherford 10-3/4" casing running equipment. • Ensure 10-3/4" BTC x CDS 40 XO on rig floor and M/U to FOSV. • R/U fill -up line to fill casing while running. • Ensure all casing has been drifted on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while RAJ casing tools. • 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: • (1) Shoe joint w/ float shoe bucked on (thread locked). • (1) Joint with coupling thread locked. • (1) Joint with float collar bucked on pin end & thread locked. • Install (2) centralizers on shoe joint over a stop collar. 10' from each end. • Install (1) centralizer, mid tube on thread locked joint and on FC joint. • Ensure proper operation of float equipment. 12.5 Continue running 10-3/4" surface casing • Fill casing while running using fill up line on rig floor. • Use "API Modified" thread compound. Dope pin end only w/ paint brush. • M/U connections to the base of the triangle stamped on the pin end. Note M/U torque values required to achieve this position. Estimated torque to reach base of triangle: 22,630 ft -lbs. • 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. • Install (1) centralizer every other joint to 300'. Do not run any centralizers above 300' in the event a top out job is needed. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 10-3/4" BTC Estimated M/U Torque Casing OD Est Torque to Reach Triangle Base 10-3/4" 22,630 ft -lbs Page 18 Revision 0 May 2019 J CLU Drilling Procedure Hilcorp m Comp•oy En TXP§ BTC ... 7{LriT7261B GWside Dianateir 10.T90:r. Min. Won $75% DR. 9.794 r. 4s ml 0 9.959 n. ihlckr s 0.4011m (•d Grade Lao dg I'M TrAwnrn AM CYurAw Laglh 10.11M t+. ripe 9.479 r. Well 74lpkness CAN in. 4onn4Cilon RD KEGUL.AR CpT![1A'r iiJ Ceb?r RBGULAR Eudl Wdd Sa.ngn 1040.i01Lu Option 5210 pu COUPUND PIPE BODY CdpsFx 24T9 rsi JD -1 Yak sinvn 1n400n0 sD'J;C awy Red Ie.. 3:yd sped Gtad. Lag Type !• 0,41 API Standard Is, Sara Era" 2DI iAU Cn^Frassaa Err crr_y 140% cwiw�Qon SmNin 1040d0D.1x0 2nd Beni:. Brown Type Casing ld Rand - Nd &atd - Ext-rvi =rcssuz c4raccrf 2470.N9 psi 4th band . PIPP EODY DATA GEOMETRY N: H H11C0)[� �a �eoa CLU #14 Drilling Procedure 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 Revision 0 May 2019 n Hi1COrp en.w c=may 13.0 Cement 10-3/4" Surface Casing CLU #14 Drilling Procedure 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. • How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. • Which pump will be utilized for displacement, and how fluid will be fed to displacement PUMP. • Positions and expectations of personnel involved with the cmt operation. • Document efficiency of all possible displacement pumps prior to cement job. 13.2 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.3 Pump 5 bbls 10 ppg spacer. Test surface cmt lines. Pump remaining volume of spacer. 13.4 Drop bottom plug. Mix and pump cmt per below recipe. 13.5 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 Vol (ft3) _ (BBLS) LEAD: 120' x .106 bpf = 12.8 71.6 16" Conductor x 10-3/4" casing annulus: LEAD: (2800'— 120') x .065 bpf x 1.5 = 261.3 1467.1 bk' 13-1/2" OH x 10-3/4" t3 Sly / l J 604 SA Casing annulus: 7.311 S 274.1 — - g34- j tAvm'�D. TAIL: (3300'-2800') x .065 bpf x 1.5 = 48.6 272.8 13-1/2" OH x 10-3/4" Casing annulus: TAIL: 80 x .096 bpf = 7.68 51ib�k'43.1 10-3/4" Shoe track: Total TAIL: 5�_ 315.9 3 3 ( 00 Page 21 Revision 0 May 2019 CLU Drilling Procedure Hilcorp Enc Czjx Cement Slurry Design: 13.7 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. 13.8 After pumping cement, drop top plug and displace cement with 9.0 ppg 6% KCl/EZ MUD/BDF- 976 drilling fluid (mud to be used on next hole section). 13.9 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.10 Displacement calculation: 3220' x.0962 bpf = 309 bbls 13.11 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.12 Do not over -displace by more than % shoe track volume. Total volume in shoe track is 8.7 bbls. 13.13 Be prepared for cement returns to surface. If cmt returns are not observed to surface, be prepared to run a temp log between 6 —18 hours after CIP. 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. Page 22 Revision 0 May 2019 Lead Slurry (2800' MD to surface) Tail Slurry (3300'to 2800' MD) System VARICEM (TM) CEMENT BONDCEM (TM) SYSTEM Density 12 Ib/gal 15.4 Ib/gal Yield 2.386 ft3/sk 1.215 ft3/sk Mixed Water 14.11 gal/sk 5.44 gal/sk Expected Thickening 3:42 HR:MIN 3:47 HR:MIN Code Description Concentration Code Description Concentration Additives Type1 Cement 94 lb/sk Type1 Cement 94 lb/sk WeIlLife 1094 Monofilament fiber 0.21% BWOC WeIlLife 1094 Monofilament fiber 0.20% BWOC 13.7 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. 13.8 After pumping cement, drop top plug and displace cement with 9.0 ppg 6% KCl/EZ MUD/BDF- 976 drilling fluid (mud to be used on next hole section). 13.9 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.10 Displacement calculation: 3220' x.0962 bpf = 309 bbls 13.11 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.12 Do not over -displace by more than % shoe track volume. Total volume in shoe track is 8.7 bbls. 13.13 Be prepared for cement returns to surface. If cmt returns are not observed to surface, be prepared to run a temp log between 6 —18 hours after CIP. 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. Page 22 Revision 0 May 2019 H Hilcorp Enn Czjx 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. CLU #1a Drilling Procedure 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: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface & volume • Note time cement in place • Note calculated top of cement • 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 dgorm(7a hileorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 23 Revision 0 May 2019 H Hilcorp Enew C=WY 14.0 BOP NIU and Test 14.1 N/D the diverter. ctu #14 Drilling Procedure 14.2 WU wellhead assy. Install packoff 10-3/4" P -seals. Test to 3000 psi. 14.3 N/U 1 I" x 5M T3 -Energy BOP as follows: • BOP configuration from Top down: 11" x 5M T3 -Energy annular BOP/11" x 5M T3 -Energy Model 6011i double ram /11" x 5M mud cross/11" x 5M T3 -Energy Model 6011i single ram • Double ram should be dressed with 2-7/8 x 5" VBRs in top cavity, blind ram in btm cavity. • Single ram should be dressed with 2-7/8 x 5" VBRs. • N/U bell nipple, install flowline. • Install (1) manual valves & (1) HCR valve on kill side of mud cross. • 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). • Test BOP to 250/3500 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • 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 9.2 ppg 6% KCl/PHPA drilling fluid for 9-7/8" hole section. 14.8 Set 10" ID wearbushing in wellhead. 14.9 Rack back as much 4-1/2" DP in derrick as possible to be used while drilling the hole section. 14.10 Install 5" liners in mud pumps. HHF-1000 Pumps are rated at 3457 psi (80%) with 5" liners and can deliver 306 gpm at 120 spm. This will allow us to drill the 9-7/8" hole section with (1) mud pump. Page 24 Revision 0 May 2019 CLU #14 Drilling Procedure 15.0 Drill 9-7/8" Hole Section 15.1 Prior to P/U 9-7/8" directional assembly, test casing against blind rams to 2600 psi / 30 min. 15.2 PIU below 9-7/8" directional drilling assy: COMPONENTDATA lltarn. «. ID Gauge Weight Top Bottom Length CurnuLOjw _ [i n) (in) (in) Obpfj Connedw Connection (ft) Length Ift) 1 9 718' PDC 7.600 3.000 9.875 130.51 P &,IWW REG 0.90 0.90 2 TSperrviO Lobe 718- 6fi.- 7.000 4.952 90.13 B4-V7IF BF`<E'REG 27.30 2820 Bums Sleeve StabTaer 9.625 3 6 XT DM Collar 6-740 3.125 103-43 B 4-112' IF P 4-117' IF 920 37.40 4 6 314' DGR Collar V 6 760 1.920 97.80 B 4-112' IF P 4112' IF 0.42 43.82 5 614' EW'R-P4 CrAar 6.730 2.000 104.30 B 4117 IF P 4-101' IF 12.10 55-92 5 1 Inline Stabilizer (115) 6.730 1.920 1 9.500 111-37 B 4-112" IF P 4-112' IF 1.95 57.87 7 6 314' PWD / 6,730 1.905 96.30 B 4 -VZ- IF P 4-1Z IF 6.43 64.30 8 614' "CIM Co1ar 6.750 1.920 101-70 B 4i12^ IF P 4-112' IF 6.59 70.89 9 6 314' ALD Colla.: 6-750 1921) 8.062 10430 B 4117 IF P 41/2' IF 18.42 89.31 Stabilizer 8.D52 10 - _ 6 3r4' CTN Collar 6,720 1.905 1 G220 B 4 1T IF P 4-V2' IF 11.84 101.15 - 11 6 34" TM Collar 6 P -M 3.25D 49.70 B 4112" IF P 4112' IF 10.02 111.17 12 63W Flex Co4ar 6.813 2.875 10110 B 4112" IF P 4-1/2' IF 30.00 141.17 13 6 3W" Flex Collar 6.688 2.875 97.58 B 4117 IF P 4-112' IF 30.38 171.55 14 41.x2' IF x CDS-40 X- 6-150 2.687 81.91 B 4S CDS P 4112' IF 2.51 174.06 Cher Sub 40 15 2 Jnts 4.5' CDS40 4.500 2.813 33.02 61.36 235.42 HYMP 16 Quer Sub 62DO 2.687 83.56 B 4112" IF P4.5CDS2.50 40 237.92 17 6 114' Jas 6250 2.250 91.01 B 4-17 IF P 410IF 1 31.79 269.71 18 4 1MF r. CDS-40 X- 6-470 2.687 92.72 8 4.5" CDS P 4-1rr IF 2.65 272.36 Over Sub 40 19 1 15 FtWDP 4-500 1 2.813 36.86 1 459.91 732.27 Total 15.3 Ensure BHA components have been inspected previously. 15.4 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 15.5 Bit TFA should be -0.75 - 0.80 int. We need to pump at -450 - 500 gpm to clean the hole effectively. Have the directional driller run hydraulics calculations to confirm optimum TFA. Page 25 Revision 0 May 2019 U Hilcorp Gaeg Com2 15.6 Primary bit will be the Baker Hughes 9-7/8" Kymera. Hughes Christensen Kymera'r" Hybrid Bits Bi l of Bulb A'orldr Doigrmd to LdLe advantage of li a be%1 Aoibcan of bah, Kymera combines rdkr cora and feed curter danrnts tmpmvtd Direerilxv Canlml Relative m PDC b1x K)m gen*1ros kw•n ovensil torque and milhnized unquc fluctuations to imp - face eanaol anti reduce wTumwxas. Lt,,,v, 11w unique design ofKvmen bus porides m stubk drilling Plxform tbnl mhigxes nbmlion prcscnt in mikr c _ I't7C em-irtrlrcwnla. B3 vuwlfam control Superior directional bit ror moor or re+y' apdicatime with beam tmifuce control rand eleervbildy than a P Faster and More Durable %Vhm drilling interbeddal and harder famlxim;mh[iwmPDCbits,IhixuniquedesignAmidesir ewd durability in tmnsdim zones and smoadxr. friar drilling in herd nxk. ISil 1p�Yifiruiticx: Nmber ofBlxles. Cane,, 4,2 prin}an• Cluter Sia 0.625 in( 15.9 mm) Couer (Amm) (Tctel. Facet (38.221 Cutting Stmicture f lnrxr, Ii"L Gauge)Cmicconic•Carbick Ntanber of N.»a a Fixed TFA Umrhg + seat 1'xduge 4 CSP, IA 0301e io(19335 xq.mm) Joumnl wgnsut t Single Pnevgiaa MFS CLU #i4 Drilling Procedure PRODUCT OVFRVIENI, Gage , Makeup Length 6111152.A mm1! 15.343 it. (31199 }m1) Bit Rreaker F Connection 6•3,18 Reg Pin )Ir fin u, 3},1-J0 1464a ly.}- MaSeaPTardne}}a-w suwml MW r a., !11..10 eAn.ib iq.o. Sh ti} NNmI Ar. Sltigritgs Weiah1161ba (9g W Ref. Pat Number 715211 f)sxnfin4 Reucxnnnrukairnrs• 1Mdmullc tla¢ nu.' pNHKn yxn [ I!IN4:nNl ryxn). nnimin�yx�rv+• 1-o114nen ord t4Ynr AtYilcm4nns. R1ia_ W e1Ne r In lilt iY 4N I=1 In n FSNI Page 26 Revision 0 May 2019 n Hilcorp Enew comp y 15.7 9-7/8" hole section mud program summary: CLU #14 Drilling Procedure Primary weighting material to be used for the hole section will be Calcium Carbonate to minimize solids. We will have barite on location to weight up the active system 1ppg above highest anticipated MW in the event of a well control situation. 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 logger's office. System Type: 9.0 — 9.8 ppg 6% KCl/EZ MUD/BDF-976 fresh water based drilling fluid. Properties: NM Mud u ht Viscosity Plastic Yield Point pH HPHT 0.2 ppb (9 pH) Wei3,300- 1.25 ppb (as required 18 YP) BDF-976 2 - 4 ppb EZ MUD DP 0.75 ppb DEXTRID LT 9.0-9.8. 40-53 15-25 15-25 8.5-9.5 < 11.0 9,374' BAR01D 41 as required for a 9.0 — 9.5 ppg ALDACIDE G 0.1 ppb BARACOR 700 1 ppb 15.8 15.9 Product Concentration Water 0.905 bbl KCI 22 ppb (29 K chlorides) Caustic 0.2 ppb (9 pH) BARAZAN D+ 1.25 ppb (as required 18 YP) BDF-976 2 - 4 ppb EZ MUD DP 0.75 ppb DEXTRID LT 1-2 ppb PAC -L 1 ppb BARACARB 5/25/50 15 - 20 ppb (5 ppb of each) BAROTROL/Soltex 2 —4 ppb as needed BAR01D 41 as required for a 9.0 — 9.5 ppg ALDACIDE G 0.1 ppb BARACOR 700 1 ppb BARASCAV D 0.5 ppb (maintain per dilution rate TIH, Conduct shallow hole test of MWD and confirm LWD functioning properly. Continue in hole and tag TOC. Note depth tagged on AM report. 15.10 Drill out plugs and shoe track. Clean out rat hole and drill an additional 20' of new formation. 15.11 CBU and condition mud for FIT. 15.12 Conduct FIT to 12.5 ppg EMW. Page 27 Revision 0 May 2019 H orp Hilc Energy C2 my 15.13 Triple combo LWD will be run in 9-7/8" hole section: • Gamma Ray (DGR: Combined Gamma Ray) - • Resistivity (EWR: Shallow/Med/Deep) • Density (DEN: Bulk Density) • Neutron (NEU: Thermal neutron porosity) • Density Image, dip picks, and additional engineer for same. 15.14 Drill 9-7/8" hole section to 9,374' MD / 7,630' TVD. CLU #14 Drilling Procedure • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Pump at 450 - 500 gpm. Ensure shaker screens are set up to handle this flowrate. • Utilize inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • Make wiper trips every 500' or every couple days unless hole conditions dictate otherwise. If tight hole is encountered, screw in and begin backreaming connections until hole conditions improve. Shales in the Beluga formations are notorious for swelling and causing tight hole. Most of the time, backreaming them on a short trip is the only solution. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. • Take MWD surveys every other stand drld. Surveys can be taken more frequently i deemed necessary." zP sf •�;. S2--) �i e ute it s 15.15 Hilcorp Geologists will follow LWD log closely to determine exact TD. 15.16 At TD pump sweeps, CBU, and pull a wiper trip back to the 10-3/4" shoe. 15.17 TOH with the drilling assembly. 15.18 Based on wellbore conditions RU Wireline, attempt to run Sonic/XPT open hole log. Page 28 Revision 0 May 2019 H Hilcorp Enc �2 16.0 Run 7-5/8" Production Casing CLU #14 Drilling Procedure 16.1 R/U and pull 10" ID wear bushing. Install and test 7-5/8" casing ram in top ram cavity. Test to 250/3500 psi. 16.2 R/U 7-5/8" casing running equipment. • Ensure 7-5/8" BTC x CDS-40 XO on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 16.3 P/U 7-5/8" 29.7# L-80 W563 shoe joint, visually verify no debris inside joint. 16.4 Continue M/U & thread locking the shoe track assy consisting of: • (1) Float shoe joint w/ float shoe bucked on. Install (2) bow spring centralizers at 10' from each end over a stop collar. • (1) Baker locked joint. Install (1) centralizer mid tube over a stop collar. • (1) Float collar joint w/ float collar bucked on pin end. Install (1) centralizer mid tube over a stop collar. • Ensure proper operation of float shoe and float collar. 16.5 Run 7-5/8" 29.7# L-80 W563 casing. • Fill casing while running using fill up line on rig floor. • Use "API Modified" thread compound. Dope pin end only w/ paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Install centralizers over couplings on every other joint to 5000' MD. • Install centralizers over couplings on every 4`h joint above 5000' MD to 10-3/4" shoe at 3,300' MD. 16.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.7 Slow in and out of slips. 16.8 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 approx 10 — 20' above TD. 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. Page 29 Revision 0 May 2019 CLU Drilling Procedure HMI=Energy Comp Wedge 563® .a 10/1912016 7-5/8" W563 Estimated M/U Torque Casing OD Est Torque to Reach Triangle Base 7-5/8" 10,300 ft -lbs Page 30 ' Revision 0 May 2019 Ootsidv 0.amvlor ].628 m. Min. Wail 87.5% Thickness pl G,". LW 4111111110ro Type 1 Wall ThiCknesa 0.378 m ConrocUon OO REGULAR E OMwn CWRJNG PIPE BODY HrJJ Red Isl Hand. Red 1 Grade LBO Typ. I• DMI isPI SlandaW Ivl Band'. Brown 2. Band' 2M Band-. - Brown TYW C .Ing 1d BaM. - 3rd Band. - 4M Sand: PIPE BODY DATA GEOMETRY ndm�nai �D r.au.r. Nominal werem —_ 29.tB lbs% Dnn ars n. Naminsl0 6.875 Y- Wye Thkknsss 0.315ii PlainEMNlei,hi 29.086.% OD Tdeauvx All e ip I PERFORMANCE y �Gp Bp9 YYld 50ewfli miii001bs Inkmal YeM 8890 psi 5MY5 B0000 ps1 Cdlapae 4790 ps I GEOMETRY CnnOPtslCb OD B.S00 n ng llh Cmugeig 938 r Cnrnvri0r.1D &375N. klake, OSOrt 1Meala pnr in 3X C.m .OD op. REGYLAR PERFORMANCE I...n E%.isY, 100➢ #'. JoiM YiekJ S.r[nA[n MAN x1000 hs w V..,. CapeclA' Guam,, L. Campmssan EPkf, ry 140.0Y, Cnmpmsaon 5hvnpin 883.000 rI000 Max. AlI.W Bdndi, 48'11ODn Us ExV_mal pteswre Capacity 4790.000 psi CDugdO Pace Load 13504108 MAKE-UP TORQUES Minimum BBDO RIEz Opl�mum 103001/25 PA.... 151001Ubs OPERATION UMIT TORQUES Ops wg Tp. 38000(:- YeN TC,. 15000 B -0s BUCK -ON 68Mmum ta6002ps LW.imum 18300069 7-5/8" W563 Estimated M/U Torque Casing OD Est Torque to Reach Triangle Base 7-5/8" 10,300 ft -lbs Page 30 ' Revision 0 May 2019 CLU #14 Drilling Procedure 16.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 16.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat (slightly) to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 16.11 Continue circulating until required properties achieved for curt operations. 16.12 After circulating, lower string and land hanger in wellhead again. Page 31 Revision 0 May 2019 U Hilcorp E=W Compmy 17.0 Cement 7-5/8" Cement Procedure CLU #14 Drilling Procedure 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. • How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. • Which pump will be utilized for displacement, and how fluid will be fed to displacement PUMP. • Positions and expectations of personnel involved with the cmt operation. • Document efficiency of all possible displacement pumps prior to cement job. 17.2 R/U cmt head (if not already done so). Ensure flexible shut-off plug supplied by stage tool hand is loaded and ready. 17.3 Pump 5 bbls 12.5 ppg spacer. Close low torque on plug dropping head, test surface cmt lines to 4000 psi. 17.4 Pump remaining 20 bbls 12.5 ppg spacer. 17.5 Mix and pump slurry per below design: Section: Calculation: Vol (BBLS) Vol (ft3) LEAD/TAIL: (9,734-2,300') x .038 bpf = 282.5 1586 ft3 9-7/8" OH x 7-5/8" csg: LEAD/TAIL: 80' x .046 bpf = 3.7 20.8 ft3 7-5/8" Shoe Track: Total Lead/Tail: 286.2 bbls 1606.8 ft3 Page 32 Revision 0 May 2019 (.zk 9 C( -Toe>.,T CLU #14 Drilling Procedure 17.7 After pumping cement, drop top plug and displace cement with 3% KCL. Use the cement unit to displace with as volumes can be tracked much more accurately. Displacement calcs: 9,734' x .0459 bpf = 447 bbls. 17.8 Monitor returns closely while displacing cement. Adjust pump rate if necessary. 17.9 Do not over -displace by more than '/2 shoe track volume. Total volume in shoe track is 3.7 bbls. 17.10 There should be no cmt returns to surface. TOC is planned to be at 2,300' MD. 17.11 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. 17.12 Pressure up again to 3500 psi and hold for 30 min to test production bore. 17.13 R/D cement equipment. Flush out wellhead with FW. 17.14 Back out and L/D landing joint, flush out wellhead with FW. 17.15 M/U pack -off running tool and pack -off to bottom of landing joint. Set casing hanger pack -off. Run in lock downs and inject plastic packing element. Test void to 250/3000 psi for 10 min. 17.16 Lay down landing joint and pack -off running tool. Page 33 Revision 0 May 2019 Lead Tali System VARICE (TV) CEMENT EXPANDACEM (TM) SYSTEM Density 12\11 /gal 15.3 lb/gal Yield 2.38 ft3/sk 1.237 ft3/sk Mixed Water 14.1 al/sk 5.55 gal/sk Expected Thickening 6: HR: IN 3:52 HR:MIN Code Description Concentration Code Description Co ration Type1 Cement 94 Ib/sk Typel Cem 94 lb/sk Additives WeIlLife 1094 Monofilament fiber 0.21% BWOC WeIlLife 1094 Monofilament fiber 0.20% BWOC 17.7 After pumping cement, drop top plug and displace cement with 3% KCL. Use the cement unit to displace with as volumes can be tracked much more accurately. Displacement calcs: 9,734' x .0459 bpf = 447 bbls. 17.8 Monitor returns closely while displacing cement. Adjust pump rate if necessary. 17.9 Do not over -displace by more than '/2 shoe track volume. Total volume in shoe track is 3.7 bbls. 17.10 There should be no cmt returns to surface. TOC is planned to be at 2,300' MD. 17.11 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. 17.12 Pressure up again to 3500 psi and hold for 30 min to test production bore. 17.13 R/D cement equipment. Flush out wellhead with FW. 17.14 Back out and L/D landing joint, flush out wellhead with FW. 17.15 M/U pack -off running tool and pack -off to bottom of landing joint. Set casing hanger pack -off. Run in lock downs and inject plastic packing element. Test void to 250/3000 psi for 10 min. 17.16 Lay down landing joint and pack -off running tool. Page 33 Revision 0 May 2019 CLU Drilling Procedure B1ccm0� Ensure to report the following on wellez: • Pre flush type, volume (bbis) & weight (ppg). • Cement slurry type, lead or tail, volume & weight. • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration. • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid. • Note if casing is reciprocated or rotated during the job. • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold. •, Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure. • Note if pre flush or cement returns at surface & volume. • Note time cement in place. • Note calculated top of cement. • 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 dgormna hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 18.0 Completions 23.1 A separate Sundry will be submitted to the AOGCC that will cover the completion operations for CLU #14 A& 7 (0 3Y( A 2SLZ 30/-- Page 0/-- Page 34 Revision 0 May 2019 H Hilcorp eneW Cao y 19.0 BOP Schematic CLU #14 Drilling Procedure Page 35 Revision 0 May 2019 (3-/t 3/t H Hilcorp 20.0 Wellhead Schematic CLU 114 16X lay. X75/B%41/2 Valve, Swab, CIW F 41136 SM FE,M 0,E Valve, U6ger Ma CI W -F35, 41/16 5 ,WO, EE 6 -In Va[M Maateq CIW-FI 41/165M K. HWO, CF Muhlb Wellhead, WM 22, 115M X 16 K 3M, w/ 421/16 SM 550 StaMM bead, i22 -ET 16%3M X16 -S vv. w/ 2- 21/16 SM EM CLU #14 B kOb, 41/155M FE 6.5" Offi OWck UN. CLU #14 Drilling Procedure JE>M as Jbclb,5 H< J�aSF- W� 9p1 AaSM °�1 Page 36 Revision 0 May 2019 ff Hilcorp E.� C2,7 21.0 Days Vs Depth Days Vs Depth qQ- 0 2000 Io CLU #i4 Drilling Procedure 3 i v 8000 10000 12000__._----- 0 5 10 15 20 Days 25 30 35 40 Page 37 Revision 0 May 2019 22.0 Formation Tops TOP NAME ST -B I Sandsi"e ST -82 sandstone ST -C sandstone VB -X (Tap Llope, Beluga) 6.802 1 andstone 'UB -A passible gas sandstone UB -6 -- 6.870 _ sandstone UB-Csandstone depleted gas 6,959 UB -0 sandstone UB -E sandstone US -F sandstone UB -G sandstone UB -H sandstone MB -IX (Top Middle Befuga) sandstone Mf3-88 sandstone MB -9 sandstone UB -9A _ sandstone M8 -9B sandstone MB -10 sandstone MB -11A sandstone MB -1 is sandstone LB -1 (Top Lower Befuga) sandstone LS -2 sandstone LB t7 sandstone LB 1 _ _sandstone LB 13 sandstone L8 19 sandstone Possible gas 5.722 —,......,-�I Pressure' Ifal 5._829 CiNGSA-gas storage 6.497 possible gas 6.802 possible gas 6.816 passible gas 6,931 possible gas 6.870 possible gas 7 6.905 depleted gas 6,959 possible gas 7_003 depleted gas: _ 737. depleted gas 7,059 possible gas 7.509 depleted gas _ _ 8.099 depleted gas 8,125 depfefed gas 8.158 possible gas 8,193 depleted gas` 8.243 depleted gas 8.309 depleted gas 8,358 de~gasA 8,442 possible gas $464 possible gas 8730 possible gas 8,784 possible gas 8.858 possible gas 9,196 CLU #14 Drilling Procedure M I to I —,......,-�I Pressure' Ifal 4.228 -4190 2,389 320.22 276,218.61 l"', 0.45' 4,308 2,389,353-57 270,277.45 1939 OA5. 4,879 _-4270 -4841 2.389_569.08 _ 276,519.62 _ ??? ??? 5, }116 -5128 2.389,658.51 276,543-50 1550 _ 0.30 5,179 -5141 2.389,658.69 278 551.53 1865 0.36 5,193 -5155 2.389,84655 _276 569.60 _ 1714 0.33 5,230 -5192 276,W40 2144 0.41 5.263 -5225 _2.389,650.33 _ 276 566.01 _ 2369 0.45 5,314 -5276 _2.389.00.18 2,389,642.33 270512-16 957 0-18 5,355 -5317 2389,65419 276524.i3 2410 _ 0.45 5,388 -5350 238_0,678.13 276,500.02 593 _ - _ 0-11 5,409 -5371 2389,872.15 276,524.13 595 0-11 5,840 -5802 2,389 740.94 276,526.25 2628 _ 0.45 6.406 -6368 2.389.843.80_ 276,519.96 1217 _ _ 0.19 6,431 -6393 2.389,835.04 276.515.58 1865 0.29 6,463 -6425 2.389.843.80 276,541.88 1874 019 0,497 -6459 2,389.856.94 _276,515-50 2329 0.3_0 6,545 -6507 2389.865.69 270,49&07 9i6 0.14 6,008 -6570 2,389,870.09 270,516.81 991 0.10 6,655 -6617 2,389,878.63 270,541.80 932 0.14 6,735 -6697 2389.900.73 270,50&62 1953 _ 0.20 6,757 -6719 2.389.918.25 276,502.45 2838 0.42 7.012 -6974 2 389,953 29 276,548-24 3156 045 7,064 -7026 Z389.955.31 278 50882 _ 3179 0-45 �- 7,135 -7097.238&97080 278528722569 0.36 _ 7459 -7421 Z390,289.38 38 276 363 93 2909 0.38 Page 38 Revision 0 May 2019 K Hilo 23.0 Anticipated Drilling Hazards CLU #14 Drilling Procedure 13-1/2" Hole Section: Lost Circulation: Ensure adequate amounts of LCM are available. BARACARBs/BAROFIBRE/STEELSEALs. Ensure Walnut M plug is also available for more severe lost returns incidents. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of Bara carb 10 & 20 to the active system at 1 — 2 ppb. Hole Cleaning: Maintain rheology w/ gel and gel extender. Sweep hole with 20 barrels mud, add 1.0 ppb BARAZAN D PLUS 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/100112 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. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. Page 39 Revision 0 May 2019 9-7/8" Hole Section: Lost Circulation: CLU #14 Drilling Procedure Ensure adequate amounts of LCM are available. BARACARBs/BAROFIBRE/STEELSEALs. Ensure Walnut M plug is also available for more severe lost returns incidents. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of Bara carb 10 & 20 to the active system at 1 — 2 ppb. Hole Cleaning: Maintain rheology w/ gel and gel extender. Sweep hole with 20 barrels mud, add 1.0 ppb BARAZAN D PLUS 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: The use of good drilling practices to minimize excessive swab and surge pressure should be employed to reduce the chances for losses and differential sticking. LCM (BARACARBs 5/25/50) should be maintained at elevated concentrations while drilling coals to help strengthen the wellbore. Black products can be used in this interval if there is potential for coal sloughing. If severe losses are encountered consider spotting multiple sized BARACARB pills throughout the loss zone. Pills should consist of both large and small particle size distributions. 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. • Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. • Use asphalt -type additives to further stabilize coal seams. • Increase fluid density as required to control a "running coal. • Emphasize good hole cleaning through hydraulics, ROP and system rheology. In the event that sloughing coal is encountered, consider spotting a 30 ppb Black products pill across the coal seam. The pill can be safely "squeezed" into the coal by closing the bag and applying pressure not to exceed the total annular pressure loss. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section." Page 40 Revision 0 May 2019 H Hileorp En�,= 24.0 Rig Layout Cn Im Mm MID140 cl.0 #14 Drilling Procedure Page 41 Revision 0 May 2019 U Hilcorp Ems, c��> 25.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: CLU #14 Drilling Procedure 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 42 Revision 0 May 2019 H Hilcorp 26.0 /s/6 /47: Choke Manifold Schematic f L " w/w (r J cl.0 #14 Drilling Procedure i. uwt •m w csxas Page 43 Revision 0 May 2019 U Hilc a� X22rp CLU #14 Drilling Procedure 27.0 Casing Design Information Calculation & Casing Design Factors Hole Size 9-718" DATE: 5-15.2019 WELL: CLU #14 FIELD: Cannery Loop DESIGN BY: David W Gorm n Criteria: Mud Density: 9.8 ppg MASP: 2212 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 Page 44 Revision 0 May 2019 Casing Section Calculation/Specification 1 2 Casing OD 10-314" 7-518" Top (MD) 0 0 Top (TVD) 0 0 Bottom (MD) 3,300 9,375 Bottom (TVD) 2,600 7,630 Length 3,300 9,375 Weight (ppf) 45.5 29.7 Grade L-80 L-80 Connection TXP BTC HYD563 Weight w/o Bouyancy Factor (lbs) 150,150 278,438 Tension at Top of Section (lbs) 150,150 278,438 Min strength Tension (1000 lbs) 1040 683 Worst Case Safety Factor (Tension) 6.93 ✓ 2.45 Collapse Pressure at bottom (Psi) 1,170 3,434 Collapse Resistance w/o tension (Psi) 2,470 4,790 Worst Case Safety Factor (Collapse) 2.11 1.39 MASP (psi) 1,170 2,212 Minimum Yield (psi) 5,210 6,890 Worst case safety factor (Burst) 4.45 3.11 Page 44 Revision 0 May 2019 n HiImTEnergy: 28.0 9-7/8" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 11 9-7/8" Hole Section 1 til,= CLU x14 Kenai, Alaska MD TVD Planned Top: 3300 2600 Planned TD: 9375 7630 Anti ted Formai and Pressures, CLU #14 Drilling Procedure Formation TVD Est Pressure Oil/Ges/Wet PPG Grad ST -BI 4,228 1903 possible gas 8.7 OAS ST -82 4,308 1939 gas ton water) 8.7 0.45 ST{ 4,879 1939 CINGSA- gas storage 7.6 OAO UB -X (Top Upper Belua) 5,166 1550 possible gas S.8 030 USIA 5,179 1865 possible gas 6.9 036 UB -8 5,193 1714 possible gas 6.3 033 UB{ 5,230 2144 Possible gas 7.9 OAi t)" 5,263 2369 possible gas 83 0.45 UB -E 5,314 9S7 depleted gas 3.5 0.18 UB -F 5,355 2410 possible gas 8.7 OAS Ul is 5,388 593 depleted gas 2,1 0011 UB -H 5,409 595 depleted gas 2.1 0.11 MB -1X frop Middle Beluga) 5,840 26M possible gas 8.7 OAS Ma -88 6,406 1217 depleted gas 3.7 0.19 MB -9 6,431 1865 depleled gas 5.6 029 MB -9A 6,463 1874 depleted ges 5.6 029 ME -911 6,497 2339 possible a, 6.9 036 MB -30 6,545 916 depleted gas 2.7 0.14 M13 -11A 6,608 991 depleted gas 2.9 0.15 MB-lic 61655 932 depleted gas 2.7 0.14 LB -1 (Top Lower Beluga) 6,735 1953 depleted gas 5,6 029 113-2 6,757 2838 possible gas 8.1 0.42 LB -30 7,012 3156 possible gas 8.7 0,45 M 11 7,064 3179 possible gas 8.7 OAS LB -13 7,135 2569 possible gas 6.9 036 LB -19 7,459 2909 possible gas 7.5 039 Offset Was Mud Densities Well MW range Top (TVD) Bottom(rVD) Data CLU g7 9.5 - 9.8 ppb 1 4,970 1 7,992 2004 CLU s8 9.3-9-8ppe I 4940 1 7,940 2004 CLU s9 1 9.2-9.8 PPg 1 2,063 81041 2004 CLU 813 1 9.0 -10.0 ppg 1 2.787 71660 2015 Assumptions, 1. Maximum planned mud density for the 9-7/8" hole section is 9.8 ppg. 2. Calculations aswme reservoirs contain 100% gas (worst case). 3. CalcuWtions assume worst case event is complete evacuation of wellbore to gas. 4. Anticipated facture gradient at 2600' TVD = 14.4 poll, EMW Fncture Pressure n 30-3/4• shoe considering a fug colum s a gas ftom alma to surface: 2600(ft) x 0.75(psi/ft)= F 1950 Psi 2950(Psi)-10.1(psi/ft)•26D0(ft))= 1690 psi MASP from pare pressure; entire wellbore evacuated to gas from TO 7630 (ft) x 039(psi/ft)= 2975 psi 2975(psi)-I0-14psilft)•7630(ft))= 2212psi Summary. 1. MASP during Drilling/production mode is governed by SIBHP minus entire wellbore evacuated to gas from TD. Page 45 Revision 0 May 2019 CLU Drilling Procedure Hilcorp Enc,, Company 29.0 Spider Plot (NAD 27) (Governmental Sections) DL324604 Hllcorp Alaska, LLC FEE ADL 60568 / CLU 01Imqdl SH i 1 - % CLU ea eHIA BH'+% / / A 26`02 CLU S -s gHtsf3_---�- / / ,Ab�3917y0 QFEEADL60569 /' CLU Oe---- Hllcorp Alaska, LLC /% I / ,CLU FEE ADL 60569 • ' / '/ CLU-14_BHL CLU S-38HLO / Hllcorp Alasw LLC FEEA�L 60568 S005NO11 W ; .% P R YtOOI'� CLU-14_TPH � e° � � oO000•ee° / i CLU Si aHW 000peo OpppO oo / CLU-14_SHL 6 •C 4Y C FISHER1. dNC' ° e 1 / - ---- -- - -_-_-_ACLU oo - ------ cl.0 to ttira<s � :J i / T- JOSEPH JOSEPHACOCHRAN / = A 2' CLU ss SHL•' Hllcorp Alaska. LLC , --- FEE AA -092401 Legend • CLU -14 SHL • Other Surface Well Locations James Kenneth Foute X CLU-14_TPH • Other Bottom Hole Locations CLU-14_BHL - Well Paths QOil and Gas Unit Boundary Cannery Loop Unit CLU -14 Well wp11 0 500 1,OW 1,509 Feet I Alaska State Plane Zone 4, NAD27 A Map Date- 5/1012019 Page 46 Revision 0 May 2019 H Hilc Evc,gy Company CLU #14 Drilling Procedure 30.0 Surface Plat (As Built) (NAD 27) BE SECTION 7, T5N, ROW, S.M. AK PROPERTY \10' UTILITY EASEMENT --�` / TRACT A KENAI SPIT U NO.10 SUBDIVISION CLU NO.13 N0.2 la 20, -------- CLU NO.14 AS -BUILT e THIS SURVEY ® 0(LU NO.8 CLU N0.9 /, :: . X1 4 CLU NO.1RD �LU NO.6 WATER LINE LBURIED 5'f CANNERY ROAD 83' R/W KENAI CITY LIMITS BURIED FLOWLINES ® p CLU N0.7 CLU NO.5 i / i i i �v0 HILCORP ALASKA, LLC C.L.U. NO. 14 WELL AS -BUILT SURFACE LOCATION DIAGRAM CANNERY LOOP UNIT NO.1 PAD SECTION 7, T5N, R1 1W, S.M. CITY OF KENAI, KENAI PENINSULA BOROUGH, ALASKA SECTION 7 SECTION 18 14 um spy NORTH cacwrv. wv GRAPHIC SCALE ag,1- 2 1 inch = 60 IL Page 47 Revision 0 May 2019 31.0 Offset MW vs TVD Chart MW Vs TVD 0 1000 rzmn; 3000 4000 0 5000 :141 7000 8000 9000 10000 8 8.5 CLU #14 Drilling Procedure 9 10 10.5 Page 48 Revision 0 May 2019 11 H H11COT� fta mw 32.0 Drill Pipe Information CLU #)4 Drilling Procedure Page 49 Revision 0 May 2019 SRE: -4-1 1 /2" --- E OWN WEIGHT: 16.6 LBS/Fr GRADE: S-135 _ RANGE: 11(31, 5') DRILL PIPE SPECS CONNECTION: CDS40 TUBE NEW -- _-- PREMIUM IN MM IN MM OD 4.500 114.3 4.365 110.9 WALLTHICKNESS 0.337 8.6 0.270 6.8 ID 3.826 972 3.826 97.2 Fries N -M FT -LBS NSM TORSIONAL STRENGTH 55,453 75.200 43,451 58.900 80% TORSIONAL STRENGTH 44.362 60.200 34.761 47,100 LBS DAN LBS DAN TENSILE STRENGTH 595,004 265.300 468,297 208,800 PSI KPA PSI KPA INTERNAL PRESSURE CAPACITY 17,693 121.985 16,176 111,530 COLLAPSE CAPACITY 16.769 115,615 10,959 75,561 IN= MM= IN, MM= CROSS SECTIONAL AREA BODY 4.407 2844 3.469 2238 CROSS SECTIONAL AREA OD 15.904 10261 14,966 9655 CROSS SECTIONAL AREA ID 11.497 7417 11.497 7417 IN, MMa IN? MM. SECTION MODULUS 4.271 69995 3.347 54845 POLAR SECTION MODULUS 8.543 139989 6.694 109690 TOOL JOINT EW 11 PREMIUM PSI KPA PSI KPA YIELD STRENGTH 130,000 896,318 130,000 896,318 IN MM IN MM OD 5.2500 133.4 5.1198 130.0 ID 2.6875 683 2.6875 683 PW LENGTH 11.0 279.4 11.0 279.4 BOX LENGTH 14.0 355.6 14.0 355.6 FT4.w NAI Py -LBS NM TORSIONAL STRENGTH 35,400 48.000 34.700 47.100 MAX MAKEUP TORQUE 22,500 30.500 21.400 29,000 RECOMMENDED MAKE-UP TORQUE 21,200 28,800 20,800 28,200 MIN MAKEUP TORQUE 19.600 26.600 19.300 26.200 LHS DAN LBS DAN TENSILE STRENGTH 824,400 367.600 604,900 358,900 TOOL JOINT/DRILL PIPE TORSIONAL RATIO 0.64 0.80 DRILL PIPE ASSEMBLY WITH CONNECTION 1.86/PT KG/M ADJUSTED WEIGHT 17.87 26.64 FT M APPROXIMATE LENGTH 31.50 9.60 GAL/FT M°/M FLUID DISPLACEMENT 0.273 0,003394 FLUID CAPACITY 0.577 0,007169 IN MM DRIFT suElf 2.5625 65 Page 49 Revision 0 May 2019 CLU Drilling Procedure Hi1C01p E.camw•r Page 50 Revision 0 May 2019 COMBINED LOAD CURVE FOR 4 1 /'L" $135 16.6 LBS/FT DRILL PIPE WITH CDS40 CONNECTIONS 900.000 i I 800.000 I � - ]00.000 6W.OW -60 SOO,OW jj�. ` g� • • • • • • • • • •,. ` 9 F 4W.OW • • ` • ` • ` 22M.00` • • , mow I I 0 10,000 201000 30,WO 40,01M SO.OW W.OW Applied T• .Ift4be) NEW TUBE C0M8INED LOAD PREMIUM TUBE COMBINED LOAD —MAKELPTOROUE —SHOULDER SEPMA-DON —PIN YIELD — Box YIELD Page 50 Revision 0 May 2019 ff HilcA7Eva&Y Company 33.0 Directional Program (WPI I) CLU #14 Drilling Procedure Page 51 Revision 0 May 2019 Hilcorp Alaska, LLC Kenai C.I.U. Cannery Loop Unit #1 Pad Plan: Cannery Loop Unit 14 Cannery Loop Unit 14 Plan: CLU -14 wp11 Standard Proposal Report 15 May, 2019 HALLIBURTON Sperry Drilling Services I HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Kenai C.I.U. Site: Cannery Loop Unit #1 Pad Well: Plan: Cannery Loop Unit 14 Wellbore: Cannery Loop Unit 14 Design: CLU -14 wp11 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: Cannery Loop Unit 14 TVD Reference: Plan @ 38.40usft (HEC 169) MD Reference: Plan @ 38.40usft (HEC 169) North Reference: True Survev Calculation Method: Minimum Curvature Project Kenai CJ U, Vertical Map System: US Slate Plane 1927 (Exact solution) Svstem Datum: Mean Sea Level Geo Datum: NAD 1927 WADCON COWLS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Audit Notes: Version: Vertical Section: Plan Sections Measured Depth (usft) 18.00 350.00 550.00 1,603.02 5,471.44 5,782.16 5,832.16 6,908.96 6,955.36 7,100.28 9,174.73 9,374.73 Phase: PLAN Tie On Depth: 18.00 Depth From (rVD) -NIS +EJ -W Direction (usft) (usft) (usft) (I 18.00 0.00 0A0 64.85 Vertical ND Site Cannery Loop Unit #1 Pad Build Turn Site Position: Azimut Northing: 2,388,631.67usft Latitude: 60° 31' 55.9300 N From: Map Easting: 272,605.07ueft Longitude: 151° 15'45.2801 W Position Uncertainty: 0.00 usft Slot Radius: 13-3/16' Grid Convergence: -1.10 ° (usft) ('/10ousft) ('/100usft ('/100usft (°) Well Plan: Cannery Loop Unit 14 18.00 -20.40 0.00 Well Position +N/ -S 0.00 usft Northing: 2,388,681.67 usft Latitude: 60' 31'56.4397 N 0.00 +E/ -W 0.00 usft Easting: 272,696.84 usft Longitude: 151° 15'43.4654 W Position Uncertainty 0.50 usft Wellhead Elevation: 0.00 usft Ground Level: 20.40 usft 6.00 85.00 549.63 511.23 0.91 Wellbore Cannery Loop Unit 14 3.00 0.00 85.00 Magnetics Model Name Sample Date Declination Dip Angle Field Strength 86.56 470.28 4.00 (°) (') (nn -7.03 BGGM2018 4/15/2019 15.43 73.47 55,214,51820882 'I 652.03 Design -- CLU -14 wpll ----- � ---�---- - Audit Notes: Version: Vertical Section: Plan Sections Measured Depth (usft) 18.00 350.00 550.00 1,603.02 5,471.44 5,782.16 5,832.16 6,908.96 6,955.36 7,100.28 9,174.73 9,374.73 Phase: PLAN Tie On Depth: 18.00 Depth From (rVD) -NIS +EJ -W Direction (usft) (usft) (usft) (I 18.00 0.00 0A0 64.85 5115/2019 3:02:13PM Page 2 COMPASS 5000.15 Build 91 Vertical ND Dogleg Build Turn Inclinatio Azimut Depth System +N/ -S +E/ -W Rate Rale Rate Tool Face n h (usft) usft (usft) (usft) ('/10ousft) ('/100usft ('/100usft (°) 0.00 0.00 18.00 -20.40 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 350.00 311.60 0.00 0.00 0.00 0.00 0.00 0.00 6.00 85.00 549.63 511.23 0.91 10.42 3.00 3.00 0.00 85.00 48.08 78.67 1,466.70 1.428.30 86.56 470.28 4.00 4.00 -0.60 -7.03 48.08 78.67 4,051.13 4.012.73 652.03 3,292.62 0.00 0.00 0.00 0.00 41.00 70.00 4,272.66 4,234.26 709.73 3,502.21 3.00 -2.28 -2.79 -142.37 41.00 70.00 4,310.40 4,272.00 720.94 3,533.03 0.00 0.00 0.00 0.00 19.60 349.08 5,266.69 5,228.29 1,033.06 3,844.67 3.88 -1.99 -7.51 -150.19 19.60 349.08 5,310.40 5,272.00 1,048.34 3,841.72 0.00 0.00 0.00 0.00 16.39 339.55 5,448.25 5,409.85 1,091.39 3,829.97 3.00 -2.22 -6.58 -141.95 16.39 339.55 7,438.40 7,400.00 1,639.82 3,625.43 0.00 0.00 0.00 0.00 16.39 339.55 7,630.27 7,591.87 1,692.70 3,605.71 0.00 0.00 0.00 0.00 5115/2019 3:02:13PM Page 2 COMPASS 5000.15 Build 91 HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US+ CANADA Local Co-ordinate Reference: Well Plan: Cannery Loop Unit 14 Company: Hilcorp Alaska, LLC ND Reference: Plan @ 38.40usft (NEC 169) Project: Kenai C.I.U. 200.00 MD Reference: Plan @ 38.40usft (HEC 169) site: Cannery Loop Unit #1 Pad 0.00 North Reference: True Well: Plan: Cannery Loop Unit 14 0.00 Survey Calculation Method: Minimum Curvature Wellbore: Cannery Loop Unit 14 300.00 -261.60 0.00 Design: CLU -14 wp11 272,696.84 0.00 0.00 Planned Survey-� 0.00 0.00 350.00 - Measured Vertical 2,388,681.67 272,696.84 Map Map Depth Inclination Azimuth Depth 7VDss +N/S +E/ -W Northing Easting DLS Vert (usft) (°) (°) (usft) usft (usft) (usft) hush) (usft) 20.40 Section 18.00 0.00 0.00 18.00 20.40 0.00 0.00 2,388,681.67 272,696.84 0.00 0.00 100.00 0.00 0.00 100.00 -61.60 0.00 0.00 2,388,681.67 272,696.84 0.00 0.00 120.00 0.00 0.00 120.00 -81.60 0.00 0.00 2,388,681.67 272,696.84 0.00 0.00 16" x 24" 200.00 0.00 0.00 200.00 -161.60 0.00 0.00 2,388,681.67 272,696.84 0.00 0.00 300.00 0.00 0.00 300.00 -261.60 0.00 0.00 2,388,681.67 272,696.84 0.00 0.00 350.00 0.00 0.00 350.00 -311.60 0.00 0.00 2,388,681.67 272,696.84 0.00 0.00 Start Dir 3-1100': 350' MD, 35l 400.00 1.50 85.00 399.99 -361.59 0.06 0.65 2,388,681.72 272,697.49 3.00 0.61 500.00 4.50 85.00 499.85 461.45 0.51 5.87 2,388,682.07 272,702.71 3.00 5.53 550.00 6.00 85.00 549.63 -511.23 0.91 10.42 2,388,682.38 272,707.28 3.00 9.82 Start Dir 4"/100' : 550' MD, 549.63'TVD 600.00 7.99 83.24 599.26 -560.86 1.55 16.48 2,388,682.90 272,713.34 4.00 15.57 700.00 11.98 81.47 697.73 -659.33 3.91 33.65 2,388,684.93 272,730.55 4.00 32.12 800.00 15.97 80.57 794.75 -756.35 7.70 57.49 2,388,688.27 272,754.46 4.00 55.31 900.00 19.97 80.03 889.85 -851.45 12.91 87.89 2,388,692.90 272,784.96 4.00 85.05 1,000.00 23.97 79.66 982.57 -944.17 19.52 124.70 2,388,698.79 272,821.89 4.00 121.18 1,100.00 27.96 79.39 1,072.46 -1,034.06 27.48 167.75 2,388,705.93 272,865.07 4.00 163.52 1,200.00 31.96 79.19 1,159.08 -1,120.68 36.77 216.81 2,388,714.27 272,914.30 4.00 211.88 1,300.00 35.96 79.02 1,242.00 -1,203.60 47.33 271.65 2,388,723.78 272,969.34 4.00 266.02 1,400.00 39.96 78.89 1,320.83 -1,282.43 59.11 332.02 2,388,734.40 273,029.91 4.00 325.67 1,500.00 43.96 78.77 1,395.17 -1,356.77 72.07 397.60 2,388,746.10 273,095.73 4.00 390.54 1,603.02 48.08 78.67 1,466.70 -1,428.30 86.56 470.28 2,388,759.20 273,168.68 4.00 462.49 End Dir : 1603.02' MD, 1466.7' TVD 1,700.00 48.08 78.67 1,531.48 -1,493.08 100.74 541.04 2,388,772.01 273,239.68 0.00 532.56 1,800.00 48.08 78.67 1,598.29 .1,559.89 115.36 613.99 2,388,785.23 273,312.91 0.00 604.82 1,900.00 48.08 78.67 1,665.10 -1,626.70 129.97 686.95 2,388,798.44 273,386.13 0.00 677.07 2,000.00 48.08 78.67 1,731.91 -1,693.51 144.59 759.91 2,388,811.66 273,459.35 0.00 749.33 2,100.00 48.08 78.67 1,798.72 -1,760.32 159.21 832.87 2,388,824.87 273,532.57 0.00 821.58 2,200.00 48.08 78.67 1,865.53 -1,827.13 173.83 905.83 2,388,838.09 273,605.80 0.00 893.84 2,300.00 48.08 78.67 1,932.34 -1,893.94 188.44 978.79 2,388,851.30 273,679.02 0.00 966.09 2,400.00 48.08 78.67 1,999.15 -1,960.75 203.06 1,051.74 2,388,864.52 273,752.24 0.00 1,038.35 2,500.00 48.08 78.67 2,065.95 -2,027.55 217.68 1,124.70 2,388,877.73 273,825.46 0.00 1,110.60 2,600.00 48.08 78.67 2,132.76 -2,094.36 232.30 1,197.66 2,388,890.95 273,898.68 0.00 1,182.86 2,700.00 48.08 78.67 2,199.57 -2,161.17 246.91 1,270.62 2,388,904.16 273,971.91 0.00 1,255.11 2,800.00 48.08 78.67 2,266.38 -2,227.98 261.53 1,343.58 2,388,917.38 274,045.13 0.00 1,327.37 2,900.00 48.08 78.67 2,333.19 -2,294.79 276.15 1,416.54 2,388,930.59 274,118.35 0.00 1,399.62 3,000.00 48.08 78.67 2,400.00 -2,361.60 290.77 1,489.50 2,388,943.81 274,191.57 0.00 1,471.88 3,100.00 48.08 78.67 2,466.81 -2,428.41 305.38 1,562.45 2,388,957.02 274,264.80 0.00 1,544.13 3,200.00 48.08 78.67 2,533.61 -2,495.21 320.00 1,635.41 2,388,970.24 274,338.02 0.00 1,616.39 3,300.00 48.08 78.67 2,600.42 -2,562.02 334.62 1,708.37 2,388,983.45 274,411.24 0.00 1,688.64 10 3/4" x 131/2" 3,400.00 48.08 78.67 2,667.23 -2,628.83 349.24 1,781.33 2,388,996.67 274,484.46 0.00 1,760.90 3,500.00 48.08 78.67 2,734.04 -2,695.64 363.85 1,854.29 2,389,009.88 274,557.69 0.00 1,833.15 3,600.00 48.08 78.67 2,800.85 -2,762.45 378.47 1,927.25 2,389,023.10 274,630.91 0.00 1,905.41 5/15/2019 3:02:13PM Pace 3 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US + CANADA Company: Hiloorp Alaska, LLC Project: Kenai C.I.U. Site: Cannery Loop Unit #1 Pad Well: Plan: Cannery Loop Unit 14 Wellbore: Cannery Loop Unit 14 Design: CLU -14 wpl1 Planned Survey Measured Map Map Vertical Depth Inclination Azimuth Depth TVDss (usft) r) (usft) (1) (usft) usft 3,700.00 48.08 2,000.20 78.67 2,867.66 -2,829.2E 3,800.00 48.08 2,073.16 78.67 2,934.47 -2,896.07 3,900.00 48.08 2,146.12 78.67 3,001.27 -2,962.87 4,000.00 48.08 2,219.08 78.67 3,068.08 -3,029.6E 4,100.00 48.08 2,292.04 78.67 3,134.89 -3,096.49 4,200.00 48.08 2,365.00 78.67 3,201.70 -3,163.3C 4,300.00 48.08 2,437.96 78.67 3,268.51 -3,230.11 4,400.00 48.08 2,510.91 78.67 3,335.32 -3,296.92 4,500.00 48.08 2,583.87 78.67 3,402.13 -3,363.73 4,600.00 48.08 2,656.83 78.67 3,468.94 -3,430.54 4,700.00 48.08 2,729.79 78.67 3,535.74 -3,497.34 4,800.00 48.08 2,802.75 78.67 3,602.55 -3,564.15 4,900.00 48.08 2,875.71 78.67 3,669.36 -3,630.96 5,000.00 48.08 2,948.66 78.67 3,736.17 -3,697.77 5,100.00 48.08 3,021.62 78.67 3,802.98 -3,764.58 5,200.00 48.08 3,094.58 78.67 3,869.79 -3,831.39 5,300.00 48.08 3,167.54 78.67 3,936.60 -3,898.20 5,400.00 48.08 3,240.50 78.67 4,003.40 -3,965.00 5,471.44 48.08 3,292.62 78.67 4,051.13 -4,012.73 Start Dir 3°/100' : 5471.44' MD, 4051.13'TVD 2,389,274.29 276,022.00 5,500.00 47.40 672.95 77.96 4,070.34 -4,031.94 5,600.00 45.07 692.12 75.34 4,139.51 -4,101.11 5,700.00 42.81 695.73 72.51 4,211.52 -4,173.12 5,717.51 42.42 709.73 71.99 4,224.40 -4,186.00 ST -B7 3,471.85 713.73 3,513.21 2,389,327.87 276,222.94 5,782.16 41.00 720.94 70.00 4,272.66 -4,234.26 End Dir : 5782.16' MD, 4272.66' TVD 2,389,349.51 276,283.78 5,800.00 41.00 760.84 70.00 4,286.13 -4,247.73 5,832.16 41.00 786.61 70.00 4,310.40 -4,272.00 Start Dir 3.8r/100': 5832.16' MD, 4310.471113 - ST -82 5,900.00 38.73 2,389,423.84 67.91 4,362.47 -4,324.07 6,000.00 35.47 2,389,451.45 64.42 4,442.22 -4,403.82 6,100.00 32.33 2,389,480.27 60.34 4,525.23 -4,486.83 6,200.00 29.34 2,389,509.35 55.51 4,611.10 -4,572.70 6,300.00 26.56 2,389,510.18 49.73 4,699.44 -4,661.04 6,400.00 24.06 2,389,541.03 42.77 4,789.86 -4,751.46 6497.27 21.99 2,389,572.68 34.69 4,879.40 -4,841.00 Z�ST -C 0 21.94 2,389,604.99 34.44 4,881.93 -4,843.53 6,600.00 20.32 2,389,605.87 24.65 4,975.23 -4,936.83 6,700.00 19.32 13.57 5,069.34 -5,030.94 6,800.00 19.04 1.77 5,163.83 -5,125.43 6,802.72 19.05 1.45 5,166.40 -5,128.00 UB -X (Top Upper Beluga) Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan: Cannery Loop Unit 14 Plan @ 38.40usft (HEC 169) Plan @ 38.40usft (HEC 169) True Minimum Curvature 5/1512019 3:02:13PM Pette 4 COMPASS 5000.15 Build 91 Map Map +N/ -S +E/ -W Northing Easting DLS Vert (usft) (usft) (usft) (usft) •2,829.26 Section 393.09 2,000.20 2,389,036.31 274,704.13 0.00 1,977.66 407.71 2,073.16 2,389,049.53 274,777.35 0.00 2,049.92 422.32 2,146.12 2,389,062.74 274,850.58 0.00 2,122.17 436.94 2,219.08 2,389,075.96 274,923.80 0.00 2,194.42 451.56 2,292.04 2,389,089.17 274,997.02 0.00 2,266.68 466.18 2,365.00 2,389,102.39 275,070.24 0.00 2,338.93 480.79 2,437.96 2,389,115.60 275,143.46 0.00 2,411.19 495.41 2,510.91 2,389,128.82 275,216.69 0.00 2,483.44 510.03 2,583.87 2,389,142.03 275,289.91 0.00 2,555.70 524.65 2,656.83 2,389,155.25 275,363.13 0.00 2,627.95 539.26 2,729.79 2,389,168.46 275,436.35 0.00 2,700.21 553.88 2,802.75 2,389,181.68 275,509.58 0.00 2,772.46 568.50 2,875.71 2,389,194.89 275,582.80 0.00 2,844.72 583.12 2,948.66 2,389,208.11 275,656.02 0.00 2,916.97 597.73 3,021.62 2,389,221.32 275,729.24 0.00 2,989.23 612.35 3,094.58 2,389,234.54 275,802.47 0.00 3,061.48 626.97 3,167.54 2,389,247.75 275,875.69 0.00 3,133.74 641.59 3,240.50 2,389,260.97 275,948.91 0.00 3,205.99 652.03 3,292.62 2,389,270.41 276,001.22 0.00 3,257.61 656.31 3,313.32 2,389,274.29 276,022.00 3.00 3,278.17 672.95 3,383.58 2,389,289.58 276,092.56 3.00 3,348.84 692.12 3,450.25 2,389,307.47 276,159.59 3.00 3,417.34 695.73 3,461.54 2,389,310.86 276,170.94 3.00 3,429.09 709.73 3,502.21 2,389,324.07 276,211.87 3.00 3,471.85 713.73 3,513.21 2,389,327.87 276,222.94 0.00 3,483.51 720.94 3,533.03 2,389,334.70 276,242.90 0.00 3,504.52 736.54 3,573.62 2,389,349.51 276,283.78 3.88 3,547.89 760.84 3,628.80 2,389,372.75 276,339.41 3.88 3,608.17 786.61 3,678.23 2,389,397.56 276,389.32 3.88 3,663.86 813.72 3,721.67 2,389,423.84 276,433.28 3.88 3,714.71 842.05 3,758.93 2,389,451.45 276,471.07 3.88 3,760.48 871.48 3,789.85 2,389,480.27 276,502.54 3.88 3,800.96 901.02 3,813.68 2,389,509.35 276,526.94 3.88 3,835.10 901.86 3,814.26 2,389,510.18 276,527.54 3.88 3,835.98 933.05 3,832.07 2,389,541.03 276,545.94 3.88 3,865.36 964.92 3,843.20 2,389,572.68 276,557.68 3.88 3,888.97 997.33 3,847.59 2,389,604.99 276,562.68 3.88 3,906.71 998.21 3,847.61 2,389,605.87 276,562.73 3.88 3,907.11 5/1512019 3:02:13PM Pette 4 COMPASS 5000.15 Build 91 HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: Cannery Loop Unit 14 Companv: Hilcorp Alaska, LLC TVD Reference: Plan @ 38.40usft (HEC 169) Project: Kenai C.I.U. MD Reference: Plan @ 38.40usft (HEC 159) Site: Cannery Loop Unit #1 Pad North Reference: True Well: Plan: Cannery Loop Unit 14 Survev Calculation Method: Minimum Curvature Wellbore: Cannery Loop Unit 14 Design: CLU -14 wpl1 Planned Survey --_---_ -�--� - Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NI -S +EI -W Northing Easting DLS Vert (usft) (1) (1 (usft) usft (usft) (usft) (usft) (usft) 5,135.00 Section 6,810.13 19.06 0.57 5,173.40 -5,135.00 1,000.63 3,847.65 2,389,608.29 276,562.81 3.88 3,908.18 UB -A 6,820.71 19.08 359.31 5,183.40 -5,145.00 1,004.09 3,847.65 2,389,611.75 276,562.88 3.88 3,909.64 UB -B 6,858.82 19.24 354.83 5,219.40 -5,181.00 1,016.57 3,847.01 2,389,624.24 276,562.48 3.88 3,914.37 UBC 6,901.22 19.53 349.95 5,259.40 -5,221.00 1,030.51 3,845.14 2,389,638.21 276,560.88 3.88 3,918.60 UB -D 6,908.96 19.60 349.08 5,266.69 -5,228.29 1,033.06 3,844.67 2,389,640.76 276,560.45 3.88 3,919.26 End Dir : 6908.96' MD, 5266.69' TVD 6,955.36 19.60 349.08 5,310.40 -5,272.00 1,048.34 3,841.72 2,389,656.10 276,557.80 0.00 3,923.08 Start Dir 3°1100' : 6955.36' MD, 5310.4'TVD - UB -E 6,996.63 18.64 346.69 5,349.40 -5,311.00 1,061.56 3,838.89 2,389,669.37 276,555.22 3.00 3,926.14 UB -F 7,000.00 18.56 346.49 5,352.59 -5,314.19 1,062.60 3,838.64 2,389,670.42 276,554.99 3.00 3,926.35 7,031.38 17.86 344.49 5,382.40 -5,344.00 1,072.10 3,836.19 2,389,679.96 276,552.72 3.00 3,928.17 UB -G 7,053.41 17.38 343.00 5,403.40 -5,365.00 1,078.50 3,834.32 2,389,686.39 276,550.98 3.00 3,929.20 UB -H 7,100.28 16.39 339.55 5,448.25 -5,409.85 1,091.39 3,829.97 2,389,699.36 276,546.87 3.00 3,930.73 End Dir : 7100.28' MD, 5448.25' TVD 7,200.00 16.39 339.55 5,543.91 .5,505.51 1,117.75 3,820.14 2,389,725.91 276,537.55 0.00 3,933.04 7,300.00 16.39 339.55 5,639.85 .5,601.45 1,144.19 3,810.28 2,389,752.53 276,528.20 0.00 3,935.35 7,400.00 16.39 339.55 5,735.79 -5,697.39 1,170.62 3,800.42 2,389,779.15 276,518.85 0.00 3,937.66 7,500.00 16.39 339.55 5,831.72 -5,793.32 1,197.06 3,790.56 2,389,805.77 276,509.50 0.00 3,939.96 7,514.25 16.39 339.55 5,845.40 -5,807.00 1,200.83 3,789.15 2,389,809.57 276,508.16 0.00 3,940.29 MBAX (Top Middle Beluga) 7,600.00 16.39 339.55 5,927.66 -5,889.26 1,223.50 3,780.70 2,389,832.39 276,500.15 0.00 3,942.27 7,700.00 16.39 339.55 6,023.60 -5,985.20 1,249.94 3,770.84 2,389,859.01 276,490.80 0.00 3,944.58 7,800.00 16.39 339.55 6,119.53 -6,081.13 1,276.38 3,760.98 2,389,885.63 276,481.45 0.00 3,946.89 7,900.00 16.39 339.55 6,215.47 -6,177.07 1,302.81 3,751.12 2,389,912.26 276,472.09 0.00 3,949.20 8,000.00 16.39 339.55 6,311.41 -6,273.01 1,329.25 3,741.26 2,389,938.88 276,462.74 0.00 3,951.51 8,100.00 16.39 339.55 6,407.34 -6,368.94 1,355.69 3,731.40 2,389,965.50 276,453.39 0.00 3,953.82 8,107.35 16.39 339.55 6,414.40 -6,376.00 1,357.63 3,730.67 2,389,967.46 276,452.71 0.00 3,953.99 MB -8B 8,133.41 16.39 339.55 6,439.40 -6,401.00 1,364.52 3,728.10 2,389,974.39 276,450.27 0.00 3,954.59 MB -9 8,161.56 16.39 339.55 6,466.40 -6,428.00 1,371.96 3,725.33 2,389,981.88 276,447.64 0.00 3,955.24 MB -9A 8,200.00 16.39 339.55 6,503.28 -6,464.88 1,382.13 3,721.54 2,389,992.12 276,444.04 0.00 3,956.13 8,205.34 16.39 339.55 6,508.40 -6,470.00 1,383.54 3,721.01 2,389,993.54 276,443.54 0.00 3,956.26 MB -9B 8,253.28 16.39 339.55 6,554.40 -6,516.00 1,396.21 3,716.28 2,390,006.30 276,439.06 0.00 3,957.36 MB -10 1 8,300.00 16.39 339.55 6,599.22 -6,560.82 1,408.56 3,711.68 2,390,018.74 276,434.69 0.00 3,958.44 5/15/2019 3:02:13PM Pace 5 COMPASS 5000.15 Build 91 HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: Cannery Loop Unit 14 Company: Hilcorp Alaska, LLC TVD Reference: Plan @ 38.40usft (HEC 169) Protect: Kenai C.I.U. MD Reference: Plan @ 38.40usft (HEC 169) Site: Cannery Loop Unit #1 Pad North Reference: True Well: Plan: Cannery Loop Unit 14 Survev Calculation Method: Minimum Curvature Wellbore: Cannery Loop Unit 14 Northing Easting DLS Design: CLU -14 wp11 (usft) 46,582.00 Section 2,390,024.62 276,432.63 Planned Survey 3,958.95 2,390,038.49 276,427.75 0.00 3,960.16 2,390,045.36 Measured 0.00 3,960.75 Vertical 276,419.76 0.00 3,962.13 Depth Inclination Azimuth Depth TVDss +NIS +El -W (usft) (°) (°) (usft) usft (usft) (usft) 8,322.08 16.39 339.55 6,620.40 -6,582.00 1,414.40 3,709.50 MB -11A 276,387.94 0.00 3,969.99 2,390,154.48 276,387.01 0.00 8,374.20 16.39 339.55 6,670.40 -6,632.00 1,428.18 3,704.36 MB -11C 3,972.30 2,390,205.09 276,369.24 0.00 3,974.61 2,390,231.71 8,400.00 16.39 339.55 6,695.15 -6,656.75 1,435.00 3,701.82 8,459.67 16.39 339.55 6,752.40 -6,714.00 1,450.78 3,695.93 LB -1 (Top Lower Beluga) 276,334.20 0.00 3,983.26 - plan hits target center 8,483.65 16.39 339.55 6,775.40 -6,737.00 1,457.12 3,693.57 LB -2 8,500.00 16.39 339.55 6,791.09 -6,752.69 1,461.44 3,691.96 8,600.00 16.39 339.55 6,887.03 -6,848.63 1,487.88 3,682.10 8,700.00 16.39 339.55 6,982.96 -6,944.56 1,514.32 3,672.24 8,756.74 16.39 339.55 7,037.40 -6,999.00 1,529.32 3,666.64 LB -10 8,800.00 16.39 339.55 7,078.90 -7,040.50 1,540.75 3,662.38 8,809.90 16.39 339.55 7,088.40 -7,050.00 1,543.37 3,661.40 LB -11 8,885.99 16.39 339.55 7,161.40 -7,123.00 1,563.49 3,653.90 LB -13 8,900.00 16.39 339.55 7,174.84 -7,136.44 1,567.19 3,652.52 9,000.00 16.39 339.55 7,270.77 -7,232.37 1,593.63 3,642.66 9,100.00 16.39 339.55 7,366.71 -7,328.31 1,620.07 3,632.80 9,174.73 16.39 339.55 7,438.40 -7,400.00 1,639.82 3,625.43 9,200.00 16.39 339.55 7,462.65 -7,424.25 1,646.51 3,622.94 9,300.00 16.39 339.55 7,558.58 -7,520.18 1,672.94 3,613.08 9,374.73 16.39 339.55 7,630.27 - -7,591.87 1,692.70 3,605.71 Total Depth: 9374.73' MD, 7630.27' TVD Map Map Northing Easting DLS Vert (usft) (usft) 46,582.00 Section 2,390,024.62 276,432.63 0.00 3,958.95 2,390,038.49 276,427.75 0.00 3,960.16 2,390,045.36 276,425.34 0.00 3,960.75 2,390,061.25 276,419.76 0.00 3,962.13 2,390,067.63 276,417.52 0.00 3,962.68 2,390,071.98 276,415.99 0.00 3,963.06 2,390,098.60 276,406.64 0.00 3,965.37 2,390,125.22 276,397.29 0.00 3,967.68 2,390,140.33 276,391.98 0.00 3,968.99 2,390,151.84 276,387.94 0.00 3,969.99 2,390,154.48 276,387.01 0.00 3,970.22 2,390,174.74 276,379.90 0.00 3,971.98 2,390,178.47 276,378.59 0.00 3,972.30 2,390,205.09 276,369.24 0.00 3,974.61 2,390,231.71 276,359.89 0.00 3,976.92 2,390,251.60 276,352.90 0.00 3,978.64 2,390,258.33 276,350.54 0.00 3,979.23 2,390,284.95 276,341.19 0.00 3,981.54 2,390,304.84 276,334.20 0.00 3,983.26 Targets Target Name -hAlmiss target Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing Easting -Shape 0 (°) (usft) (usft) (usft) (usft) (usft) CLU 14 wpl1 T3 BHL 0.00 0.00 7,438.40 1,639.82 3,625.43 2,390,251.60 276,352.90 - plan hits target center - Circle (radius 50.00) CLU 14 wptt T2_UB-E 0.00 0.00 5,310.40 1,048.34 3,841.72 2,389,656.10 276,557.80 - plan hits target center - Circle (radius 50.00) CLU 14 wp11 T1 B2 0.00 0.00 4,310.40 720.94 3,533.03 2,389,334.70 276,242.90 - plan hits target center - Circle (radius 50.00) 5/152019 3:02:13PM Pam 6 COMPASS 5000.15 Build 91 Halliburton HALLI B U RTO N Standard Proposal Report Database: NORTH US +CANADA Local Co-ordinate Reference: Well Plan: Canner, Loop Unit 14 Companv: Hilcorp Alaska, LLC TVD Reference: Plan @ 38.40usft (HEC 169) Proiect: Kenai C.I.U. MD Reference: Plan @ 38.40usft (HEC 169) Site: Cannery Loop Unit #1 Pad North Reference: True Well: Plan: Cannery Loop Unit 14 Survey Calculation Method: Minimum Curvature Wellbore: Cannery Loop Unit 14 10.42 8,161.56 6,466.40 Design: CLU-14wp11 86.56 8,374.20 6,670.40 Casing Points Measured Vertical Depth Depth (usft) (usft) Name 120.00 120,00 16" x 24" 3,300.00 2,600.42 10 3/4"x 13 1/2' 9,374.73 7,630.28 7 5/8" x 9 7/8" Casing Diameter (1 16 10-3/4 7-5/8 Hole Diameter (111 24 13-1/2 9-7/8 Formations — Depth – Measured Vertical Vertical (usft) Dip Depth Depth Depth SS (usft) Comment Dip Direction (usft) (usft) Name Lithology Start Dir 3-/100': 350' MD, 350'TVD 6,996.63 5,349.40 UB -F 0.91 10.42 8,161.56 6,466.40 MB -9A 1,466.70 86.56 8,374.20 6,670.40 MB -11C 5,471.44 4,051.13 6,802.72 5,166.40 UB -X (Top Upper Beluga) Start Dir 3°/100': 5471.44'MD, 4051.13'TVD 5,782.16 8,107.35 6,414.40 MB -8B 3,502.21 End Dir : 5782.16' MD, 4272.66' ND 8,205.34 6,508.40 MB -9B 720.94 3,533.03 8,756.74 7,037.40 LB -10 5,266.69 1,033.06 6,955.36 5,310.40 UB -E 6,955.36 5,310.40 6,858.82 5,219.40 UB -C Start Dir 3°/100' : 6955.36' MD, 5310.4'TVD 7,100.28 7,514.25 5,845.40 MB -1X (Top Middle Beluga) 3,829.97 End Dir : 7100.28' MD, 5448.25' TVD 6,810.13 5,173.40 UB -A 1,692.70 3,605.71 8,459.67 6,752.40 LB -1 (Top Lower Beluga) 7,031.38 5,382.40 UB -G 8,322.08 6,620.40 MB -11A 6,820.71 5,183.40 UB -B 8;253.28 6,554.40 MB -10 7,053.41 5,403.40 UB -H 8,809.90 7,088.40 LB -11 8,483.65 6,775.40 LB -2 5,832.16 4,310.40 ST -B2 6,901.22 5,259.40 UB -D 8,133.41 6,439.40 MB -9 5,717.51 4,224.40 ST -131 6,497.27 4,879.40 ST -C 8,865.99 7,161.40 LB -13 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/ -S +E/ -W (usft) (usft) (usft) (usft) Comment 350.00 350.00 0.00 0.00 Start Dir 3-/100': 350' MD, 350'TVD 550.00 549.63 0.91 10.42 Start Dir 4-/100': 550' MD, 549.63'TVD 1,603.02 1,466.70 86.56 470.28 End Dir : 1603.02' MD, 1466.7' TVD 5,471.44 4,051.13 652.03 3,292.62 Start Dir 3°/100': 5471.44'MD, 4051.13'TVD 5,782.16 4,272.66 709.73 3,502.21 End Dir : 5782.16' MD, 4272.66' ND 5,832.16 4,310.40 720.94 3,533.03 Stan Dir 3.88°/100': 5832.16' MD, 4310.4'TVD 6,908.96 5,266.69 1,033.06 3,844.67 End Dir :6908.96' MD, 5266.69' TVD 6,955.36 5,310.40 1,048.34 3,841.72 Start Dir 3°/100' : 6955.36' MD, 5310.4'TVD 7,100.28 5,448.25 1,091.39 3,829.97 End Dir : 7100.28' MD, 5448.25' TVD 9,374.73 7,630.27 1,692.70 3,605.71 Total Depth : 9374.73' MD, 7630.27' TVD 5/152019 3:02:13PM Pace 7 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Kenai C.I.U. Cannery Loop Unit #1 Pad Plan: Cannery Loop Unit 14 Cannery Loop Unit 14 CLU -14 wp11 Sperry Drilling Services Clearance Summary Anticollision Report 15 May, 2019 closest Approach 30 Proxial Scan on Current Survey Data iHighside Reference) Reference Design: Cannery Loop Unit 11 Pad -Plan: Cannery Loop Unit 14 - Cannery Loop Unit 14. CLU -14 wpII Well Coordinates: 3,368, 681.69 N, 270,696.84E (60'31'56.44" N, 151' 15' 43.47' Kq Datum Height: Plan Its 38A0usR (HEC 169) Scan Res npe: 0.00 to 9,374.73 ul Measured Depth. Scan Radius Is Unlimited. Clearance Factor cutoff is Unlimited Max Ellipse Separation 151,000.00 us" Geodetic Scale Fac nApplled Version: 5000.15 Build 91 Scan Tvpe'. GLOBAL FILTER APPLIED: All wellil within 20U. 10011000 freference Scan Time: 25.00 HALLIBLIRTON Sperry Drilling Services HALLIBURTON Anticollision Report for Plan: Cannery Loop Unit 14 - CLU -14 wp11 Hileorp Alaska, LLC Kenai C.I.U. Closest Approach 3D Proximity Seaman Current Survey Data (Hlghalde Reference] Reference Design: Cannery Loop Unit #1 Ped -Plan: Cannery Loop Unit 14. Cannery Loop Unit 14 -CW-14 wp11 Soon Range: 0.00 to 9,37473 use. Measured Depth. Scan Radius is Unlimited. Clearance Fad., cutoff is Unlimited- Mex Elnpse Separation is 1,000.00 psa Measure Minimum @Meaaure Ellipse dipMeapre Clearance Summary Based Site Name d Distance d Separation d Factor on Minimum Separation Warning Comparison Well Name - Wellbore Name - Design notal. nam Denrb 6.em petal, Cannery Loop Unit Carmen, Loop Unit S3- Cannery Loop Unit S -3 -CLU 6.72500 4IpISS 6725.00 305.91 8,693.00 2,712 Clearance Factor pass - Cannery Loop Unit S3- Cannery Loop Unit S -3 -CLU 6,7]5.00 47903 6.775.00 30323 8.693.00 2]25 Ellipse Separation Pass- CannervLoop Unit 53- Caatery Loop Unit S -3 -CLU 6,017,91 477.53 6.817.91 305.50 8,69300 Ire Can. Down. Pass - Cannery Loop Unit S4- Cannery Loop Unit SA -CLU 6.450.00 30403 6.450.00 116.21 8,39278 1.619 Clearance Factor Pass - Cannery Loop Unit SA- Cannery Imp Unit S4 -CLU 6,477.49 302.92 6,477.49 117.02 8.391.66 1.629 Centre Distance Pass- Cannery Loop Untl S-5- Cannery Loop Unit S -5 -CLU 6,317.40 33610 6,39.40 154.17 8,347.08 1.047 Centre Distance Pass - Carman, Loop Unit S5 -Carrow Loop Unit S -5 -CLU 632500 33620 6,325.00 153.98 &347.19 1845 Clearance Factor Pass - Cannery Loop Unit #1 Pad Cannery Lapp Unit 01- Cannery Loop Unit 01 -Cann¢ 35000 110.44 35000 107.43 353.60 36,729 EIIIpse Separation Pass - CanneryLow Unit 01- Cannery Loop Unit 01 -Canna 725.00 147.97 72500 142.61 728.70 27.621 Clearance Factor Pass - Connery Loop Unit 01- Cannery Loop Unit 01 RD -CA 35000 in" 350.00 107.43 353.60 36.729 Ellipse Separation pass - Carriers Loop Unit 01- Cannery Loop Unit 01 RD -CA 725.00 147.97 72500 142.61 72870 27.621 Clearance Factor Pass - CanneryLoop Unit 01- Canners Loop Unit O1RDPB1- 350.00 110.44 350.00 107.43 35380 36,729 Ellipse Separation PasO- Centers, Loop Unit 01- Cannery two Unit 01 ROPB1- 72500 14797 725.00 14261 728.70 27.621 Clearance Factor Pass- Cannery Loop Untl 05- Concery two Unit 05-CLU05 712.86 50.74 712.86 44.09 733.03 0.671 Centre Distance Pass - Cannerytwo Unit 05- Cannery Loop Unit 05-CLU05 725.00 5017 72500 44.83 745.25 8.517 Ellipse Separation Pass - CanneryLoop Unit 05- Cannery Loop Unit 05-CLUOS 82500 5372 82500 47.07 84576 8.070 Clearance Factor Pass - Carms"Law Unit 05- Cannery Loop Unit OSRD-CLU 712.86 50.74 712.06 4489 716A3 8,669 Centre Distance Pasa- Cannery Lpop Unit 05- Cannery Loop Unit 0580 -CLU 725.00 son 72500 44.63 720.65 8,545 Ellipse Separation Pass - CanneryLoop Unit 95- Cannery Loop Unit 05RD-CLU 82500 5372 825.00 47.07 829.16 0.069 Clearance Factor Pass- Cartoon Loop Unit 06- Cannery Loop Unit 06 -Canna 400.30 216.38 400.30 212.99 40890 63.852 Centre Distance Pass - Cannery Loop Unit 06- Cannery Lamp Unit 06 -Cane 750.00 29.03 75000 211.88 801.38 36.576 Ellipse Separation Pass - Cannery Loop Unit 06- Cannery Loop Unit 06 -Gonne 2.825.00 610.68 2,825.00 55933 2,943.29 11.892 Clearance Factor Pass - Cannery Loop Unit 07- Cannery Loop Unit 07 -Cane 1,02950 51.83 1,029.50 4396 1,010.22 6.589 Ellipse Separation pass - Cannery Loch Unit 07- Cannery Loop Unit 07 -Carne 1,05000 52.05 1,050.01) 44.10 11029.54 6.551 Clearance Factor Pass- Cannery loop Unit 08- Cannery Loop Unit OB -Cance 70408 18481 704.08 178.91 748.53 31313 Centre Distance Pass - Cannery Loop Unit 08- Cannery Loop Unit 08 -Cane 725.00 184.06 725,00 178.90 76955 6.495 Blipse Separation Pass - 15 May, 2019 . 14:53 Pegs 2 of 5 COMPASS NAL LIBURTON BpeeN O�illlnp A U 0 to Prgecl'. Kenai C.I U. Site: Germany Loo Well: Plan: Cannel WeIIWre: Co.-, Loo Plan: CLU -14 wol Collision Risk Procedures I Collision Avoidance Req. Nol Zone - Stop Drilling NOERRORS Ladder/ S.F. Plots UNIT 2200 2750 3300 CoaE'male(valvV, Refercn-. PWd Aar N N. la.Tw NpM v -Penn rearm e: Pan C ara� Ilse l®1 Meaweca-en., em'. Flann®Y. aealCNK tB81 SufiYF' aamruu Olin To auv 01 iod 1309 WeA CLW<pf1 (GnwylaplkF fol tNND4FR1�NSt5ry P]N090 B]U 73 CZ up111finwyLeq f6n 1413 M//O�.Fg1�Ma�5q 1650 2200 27W 3300 3050 4400 Measured Depth Measured Depth OETAKS'.Pl-C, 1—, Umi 14 NA01917 LNAOOeN MNV51 ALssb ZmtW al Mer. S.W =1 -a:.W N"rnlnr Psse"3 1eno wa.w OCO O I :]386316] 3].11 evP3I SAANIN 151°1 141.4651W Cil Fit.. APPLIEC: NI w 11,amha Within X0'4100/10000 of relneve TVD TVDSS MD Siu N.- 120.00 810'20 00 16 16' x 24" 2606.4^_ 862.02 110000 IOJN 103/4"x 131C" 961025 891.88 9174.73 7-59 959"x92,9' CLU Storage 4 Iib NALLIBURTON Bpenny orilling IQ ND XDo REFERENCE INFORMATION linate (NE) Reference: Well Plan: Cannery Loop Unit 14, Two North Project. Kenai C.I.U. Site: Cannery Loop Unit #1 Pad Well: plan: Cannery Loop Unit 14 Wellbore: Cannery Loop Unit 14 Design: CLU -14 wpll F- g , Hilcorp Alaska, LLC Calculation Method: Minimum Curvature ND XDo REFERENCE INFORMATION linate (NE) Reference: Well Plan: Cannery Loop Unit 14, Two North Error System' ISCWSA NISEnd Dir :1603.02'MD, 1466.TND vertical (ND) Reference: Plan Q 38.40usft(HEC 169) Scan Method: Closest Approach 3D 3300.90 Measured Depth Reference: Plan ® 38.40usft (DEC 169) Error Surface: Pedal Curve 763020 Calculation Meted: Minimum Corral Warning Method. Enor Ratio 7-518 7518'x9718' Be. MD Inc Ain ND -N/-S *E4W Oleg TFane VSeat TarBat MnOtdi 1 18.00 0.00 0.00 18.00 0.00 0.00 0.00 0.00 D.00 2 350000.00 000 350.00 0.00 ODD D.00 0.00 0.00 Start Dir 3°1100': 350'MD, 350'iW 3 550.00 6.00 05.00 me 63 0.91 10.42 3.00 .85.00 982 Statl 094°1100': My MD, 549.63rVD 4 1603.02 48.00 7867 1466.70 06.56 470.20 600 4.03 462.49 End Der: 1603.02' MD, 1461 WD 5 547144 48.08 78.67 4051.13 6111 3292.62 0.00 0.00 3257.61 Stan or 3°1100':547144' MD, 4051.13TVD 65782A6 41.0 70.00 4272.66 709.73 350221 3.00 -142.37 3471.85 End Dir :5782.16' MD, 4272.66' TVD 7 5832.16 41.00 70.00 4310.40 neat 3533.03 0.00 ODD 350652 OLD 14 wp11 T1 B2 SMd or 3.8815832.16 MD. 431 CATVD 8 6908,96 1960. 349 O8 5266.69 1033.05 3844.67 3S8 -15.19 3919.26 End Dir :690896' MD, 5266.69' TVD 9 6855.36 19.60 34808 5310.40 104834 3841]2 000 0.00392308 CLU 14w11 T2 UB -E SMd Dir3°11 W': 5955.36'MD, 51 10 7100.20 16.39 339.55 5448.25 1091.39 3829S7 3.00 -14195 3930.73 End Dlr :710028MD. 5"825"R D 11 9174.73 16.39 339.55 7438.40 163982 362543 000 0003978.64 CLU 14 "It T3 BHL 12 9374.73 16.39 339.55 7630.27 1692.70 3605.71 0.00 000 390326 Total Depth: 937473' M0, 7630,2T TV0 WELL DETAILS: Plan: Cannery Loop Unit 14 Ground Level: 20.40 +N/5 +E/ -W Northing Ealing Latittude Longitude Start Dir 3°/100' : 350' MD, 350'TVD 0.00 0.00 2388681.67 272696.84 60' 31' 56.4397 N 151' 1543 4654 --- 500--- Start Dir 4°/100': 550'MD, 549.63'1 Date 201504-23T000000 Validated'. vee version: Depth From Depth To SurveylPtan 18,00 3300.00 CLU -14"11 (Cannery Loop Unit 14) 330000 074.73 CLU-14wp11(CenneryLaap Unitl4) QQ ND XDo NO55 81 'S MD 12o.00 Size Name 16 16'x24' NISEnd Dir :1603.02'MD, 1466.TND 200042 2562.02 3300.90 104Y4 10314'x131/2' Q 00 ti 763020 7591.88 9374,73 7-518 7518'x9718' 00 tih 00 00 ov QO 10 3/4' x 13 1/2° ST -81 ST.82 C-INu5A CLU 14 wp11 T7_82 3T -D'S 5000 UB -x (Top upper Beluga) Tool TVDPath WDasPath MOPath palmation 4224.40 4186.00 5717.51 ST -61 4310.40 42n.00 5832.16 ST -02 4879.40 4841.00 6497.37 ST -C 5166.40 5120.00 bill UB -x (Top Upper aaeuil l 51736 5135.00 6810.13 US -A 518340 5145.00 6820.71 Ua-8 6219.40 5181.00 605.82 US -C 525940 5221.00 6901.22 US -D $31040 5272.00 6955.36 UB£ 5349.40 $311 D0 6990.83 US -F 5382.40 5344.00 7031.30 UB -O 540340 6365.00 7053.41 UB -H U4540 5807.00 751425 M84x(Top MUtlk Salute) Baia 40 6376.00 0107.35 MB -BB 643940 601.00 813341 MB -9 646640 642800 816156 MB -9A 6508.40 6470.00 820154 MB -99 M54.40 6516.00 8253.20 MBAR 662040 6582.00 522.08 MB -11A 6670.40 6632.00 S3742o MB -11C 875240 6714.00 059.67 LB -1 (Top Lower Belga) fi775.10 6737.00 846385 1-8-2 7037.40 809.00 875674 LB -10 7088.40 7050.00 Mil 90 LB -11 7161.40 7123.00 initis 9 LB -13 00 Start Dir 3° ' ' 4051.13 - TVD : 5471.44MD, 4051.13ND Kenai CLU. Cannery Loop Unit #1 Pad Plan: Cannery Loan Unit 14 End Dir :5782.16- MD, 4272.66' ND Cannery Loop Unit 14 OCLU 14 wp11 -Start Dir 3.88°/100' : 5832.16' MD, 4310.4'ND UBAUS-RUB C UBD' lie- .. IP -F _ _ FUec 5500 UB H CLU 14 wpll T2_UB-E MB -IX (Top Middle Sough) 6000 i0D End Dir : 6908.96' MD, 5266.69' ND Start Dir 3°/100' : 6955.36' MD, 5310.4'ND 7000 End Dir : 7100.28' MD, 5448.25' ND M041a 6500 8000 I MB -81 MBAR "' - - - - - FM8-tp- -}- a 11C... Le -z (Top Laver Bewga) 8500 7000 La -10- - - - L811- - _ _ - . CLU 14 wp11 T3_BH_L 9000 7500 - Total Depth : 9374.73' MD, 7630.27' ND - 75/8'x97!8"----- `375 - - -" CLU -14 wpll UT -1 (Top Upper Tyo.k) 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 Vertical Section at 64.85° (1000 usft/in) HALLa1eU gTON aiCIU,nneryLoop ®rp'ia Unit#1PlPlan: Dir 3/100'6955..TVD Cannery LoopUnit 4 81.60 I±000 : Cannery Loop Unit 14 EDir 6908.96 ' M,5266.69TVD : CLU -14 wp11 x667 10-3H tO W.x1312' 1311 1000 SIan Dir 3°/100': 350' M, 350'V SwnDir4/100':550'M,549.6V Ed Dir : 1603.02' M, 1466]' 16" x 24" W6 of:Tn115: NU:Cameryliop uut 14 frtouiN.-I ±Il.ao +W.S aFI.W NMnmp Bilin, Lkik IenP�' 0°0 oW neet816> ±11.6 ='11u91N ISP lr 41.A coa,ewn whl n.Iarm". �a cmc. a...eylaoum vN®1 (Iwlxekrercc. ®,vnoun M6c lzq I.Lzw GWi:�lAemofM�mm®im�G,°iueW�e Kle91 y00 Ed Dr : 7100.28'M, 5482' Nn Nww MD Siam Name Dir 3/100'6955..TVD 12000 81.60 I±000 16 16'x34' EDir 6908.96 ' M,5266.69TVD 2600.42 2W202 330000 10-3H tO W.x1312' 00 0 76M 28 750180 9374,73 1-518 1..' .1W - EdDir:5782.16M,4272.66'D aJ00 7 5/8'.9 7/8" Tale] Depth: 9374]3' MD, 7630.27 TVD Start Dir 3°/100': 5471.44' MD, 4051.13 -TVD A\\ 9100 CLU I/ wpl I T3 BH Ed Dr : 7100.28'M, 5482' Dir 3/100'6955..TVD X115�0 50 0D EDir 6908.96 ' M,5266.69TVD 12 5 0 00 0 M3M533G4 00'65832DSan Stan Dir 3.88°/1 : 1 , 43104V 0750 - EdDir:5782.16M,4272.66'D aJ00 6r l Start Dir 3°/100': 5471.44' MD, 4051.13 -TVD c $ CLU I4 wpl l TS_UB- 10 3/4" x 13 12" 667 1000 1333 1667 2000 2333 2667 3000 West( -)(Feat(+) (500 osfuin) CLU 1l wyll Tl_ 1 MALLIMURTON Project: Kenai C.I.U. Site: Cannery Loop Unit #1F Well: Plan: Cannery Loop Unit 1 Wellbore: Cannery Loop Unit 14 Plan: CLU -14 w 11 1333 C111 ILIl.. L ' r Mrrkl1M111T 0l pn— CAYA'EA\'I(I(W IiNi 01RWB1 west( -)I t(+) (150 uslVin) cum�s,4 wcst(-pF q+) (500 uswin) L�„ylwv vm�or ays�.s,s sums CLUk11 cannm lu,p Unil as 7 L 919, oto C.4 11 Do OgW 73 47 3667 4000 4333 0 ADL324604 ------------- FEE ADL6056 1-lilcorp Alaska, LI FEE ADI -60564, 7EE AA09�401 i� AD 391575 LI ADL392672 0 11 ADL324602 © ADL -399'90 CLU 12 BHLW CLU 04 CLU 8-1 BHLI &-U 11 Hilcorp Alaska, LLC CLU m FEE ADL 60568 CLU 01RPI CLU S-2 CLU S-3 06 1 Alaska, ADL 605 CLU 10 BP" `I i 1 I � JOSEPH A GOCHRAWVd / ?. CLU S-5 BHL• � ADL31793 Hilcorp Alaska, LLC Kenneth Foute FEE AA -092401 FEE AA092401 H /V W R UNITED CO ADL359153 ADL391792 Hilcorp Alaska, LLC FEE C-605069 1. Legend PATRICK AND DAISY K MCCANP 0 CLU 14_SHL• Other Surface Well Locations KENAI UNIT X CLU 14 TPH — • Other Bottom Hole Locations — CLU 14_BHL -- Well Paths Oil and Gas Unit Boundary , � I 1 0 920 1,840 2,760 Cannery Loop Unit CLU -14 Well Feet N Alaska State Plane Zone 4, NAD27 1IIIrn,1, AIn+La, I I( W p12 Map Date: July 10, 2019 Davies, Stephen F (CED) From: David Gorm <dgorm@hilcorp.com> Sent: Wednesday, June 5, 2019 2:27 PM To: Davies, Stephen F (CED) Cc: Monty Myers; Schwartz, Guy L (CED) Subject: RE: [EXTERNAL] FW: CLU 14 (PTD 219-078) - More Questions and Requests Steve, Correct, the crescent shaped polygons are part of the two leases ADL 324602 and ADL 391790, just the shapefiles are drawing differently since the two leases overlap. Thanks, David Gorm Drilling Engineer Hilcorp Alaska Office: 907-777-8333 Cell: 505-215-2819 From: Davies, Stephen F (CED) [mailto:steve.davies@alaska.gov] Sent: Wednesday, June 5, 2019 12:48 PM To: David Gorm <dgorm@hilcorp.com> Cc: Monty Myers <mmyers@hilcorp.com>; Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Subject: RE: [EXTERNAL] FW: CLU 14 (PTD 219-078) - More Questions and Requests Thank you, David. I received the spacing exception application mid-morning today. Just to make sure that I understand completely, are the two narrow, crescent-shaped polygons that lie on either side of the Kenai River (and have colored fills that are different—to my eye—from the other polygons on the map) part of ADL 324602 and /or ADL 391790? Or do they signify something else? Regards, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC(, State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.daviesrdalaska.gov. From: David Gorm <dgorm@hilcorp.com> Sent: Wednesday, June 5, 2019 11:10 AM To: Davies, Stephen F (CED) <steve.davies@alaska.gov> Cc: Monty Myers <mmyers@hilcorp.com>; Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Subject: RE: [EXTERNAL] FW: CLU 14 (PTD 219-078) - More Questions and Requests Steve, Below in red are the responses to you questions. Thanks, David Gorm Drilling Engineer Hilcorp Alaska Office: 907-777-8333 Cell: 505-215-2819 From: Davies, Stephen F (CED)[mailto:steve.davies@alaska.govl Sent: Tuesday, June 4, 2019 5:44 PM To: David Gorm <dgorm@hilcorp.com> Cc: Monty Myers <mmyers@hilcorp.com>; Schwartz, Guy L (CED) <guy.schwa rtzAalaska.gov> Subject: FW: [EXTERNAL] FW: CLU 14 (PTD 219-078) - More Questions and Requests David, Monty: I'm working through the revised application for CLU 14, and I still have many of the same questions and requests regarding the possible need for a spacing exception to drill, complete and produce this well that were listed in my email dated May 21'x. They are listed again below along with a few additional questions. 1. Please demonstrate that a spacing exception will not be required to drill, complete, and produce CLU 14. For reservoirs within the Sterling Formation The Cannery Loop Unit is governed by CO 231. The Affected Area for Conservation Order No. 231 (CO 231) includes all of Sections 7 and 8, TSN, R11W. CO 231 does not mention the Sterling Formation. For Sections 7 and 8, there are no defined gas pools within the Sterling Formation, so the statewide requirements of 20 AAC 25.055 apply. According to AOGCC records, CLU 6 is open to, and capable of producing from, the Sterling A2, A4, A5, A6, A9 and All sands. CLU 6 appears to lie in the same governmental section as, and within 3000' of, CLU 14. To complete and produce any Sterling reservoirs in CLU 14 will require a spacing exception. Or have I missed something? The Sterling Formation does fall under statewide spacing rules under 20 AAC 25.055. The CLU 06 well however is only open to the Sterling A2 sand, which is not capable of producing. The other sands that were mentioned above were once perfed and tested, but failed to produce. Now all other Sterling sands are plugged off and no longer or never was capable of producing. The Sterling A2 sand was the last sand that was perfed and tested, which failed to produce. The regulations state that "...not more than one well may be drilled to and completed in the same pool on any governmental section..." which CLU 06 does not fall under. This well was drilled to and completed in the Sterling sands long ago, but has since been proven as nonproductive and plugged off. There is no capable production from any of the Undefined Sterling Pool even if we tried again. There hasn't been Sterling production in the Cannery Loop Unit since 2012 because no wells have been able to. For reservoirs within the Beluga Formation Within the Cannery Loop Unit, CO 231 defines and establishes pool rules for the Beluga, Upper Tyonek, or Tyonek "D" Gas Pools—including well spacing requirements of a quarter -quarter section. Please provide a map that displays the planned Beluga perforations in CLU 14 --and in all nearby wells --and demonstrates that CLU 14 will conform to the well spacing requirements of CO 231. The Beluga Gas Pool in the CLU 14 does require a spacing exception. Hilcorp has submitted the spacing exception yesterday 6-4-2019 to AOGCC for the Beluga Gas Pool (see attached). The Beluga Gas Pool is defined in CO 231, Rule 2, and the spacing within this pool is governed by CO 231, Rule 3 and states "A Drilling Unit for the Beluga, Tyonek, or Tyonek "D" Gas Pool is established as the quarter -quarter subdivision of a governmental section..." The CLU 08, CLU 09, and CLU 13 wells are all within the same quarter -quarter section as CLU 14's anticipated productive interval. Hilcorp requested a spacing exception from these wells for CLU 14. Will CLU 14 drill into the Tyonek Formation? It appears as though CLU 14 will stop just short of drilling into the UT -913 sand, which is severely under - pressured. How will Hilcorp prevent inadvertent drilling into this sand? What mitigations measures are planned in the event that this unfortunate event happens? In order to avoid the Upper Tyonek 9B depleted zone, we are going to use LWD logging data to look for the thick stacked coals that mark the transition from Lower Beluga to Upper Tyonek and correlate them to the closest offsets. Once we see the UT -1 (top of the Upper Tyonek), we will be "750 TVD above the UT -913 zone and we will have room to stop drilling before we reach the depleted UT -913 sand. We will be drilling in an area with excellent well control. 2. Regarding the Spider Plot on page 46: There are two narrow, crescent-shaped polygons that lie on either side of the Kenai River that have different colored fills. What leases or features do these polygons represent? The lease numbers ADL 324602 and ADL 391790 both appear slightly above the center of the map. Which polygons do these numbers represent? ADL 324602 is Hilcorp's lease covering all depths, excluding CINGSA Gas Storage interval. ADL 391790 is the CINGSA Gas Storage lease that is owned by Cook Inlet Natural Gas Storage Alaska. These leases overlap each other. Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.daviesPalaska.gov. From: Davies, Stephen F (CED) Sent: Monday, June 3, 2019 2:50 PM To: David Gorm <dgorm@hilcorp.com> Subject: RE: [EXTERNAL] FW: CLU 14 (PTD 219-078) - More Questions and Requests Thank you David. From: David Gorm <dgorm@hilcorp.com> Sent: Monday, June 3, 2019 1:35 PM To: Davies, Stephen F (CED) <steve.davies6Dalaska.9ov>; Schwartz, Guy L (CED) <guv.schwartz@alaska.eov> Subject: RE: (EXTERNAL) FW: CLU 14 (PTD 219-078) - More Questions and Requests Guy/Steve, In regards to the questions to CLU #14 new drill proposed well. We have changed the Casing design for the well from the first proposal and will be submitting the updated drilling procedure this week. Our Landman is currently reviewing the spacing requirements for Beluga and the Sterling. • The table of Formation Tops on page 38 of Hilcorp's Permit to Drill application has the estimated pressure of the Sterling C Gas Storage Pool listed as"???", but on page 38 the pressure of that pool is listed as 7.6 PPG (EMWj. What is the source of this 7.6 ppg value? How and when was it determined? c Current Estimated storage sand pressure will be based off current WH pressure and injection pressures. For current planning purposes was adding 1 ppg over the estimated the storage sand pressure to be based off surface pressures to get the evaluated 7.6 ppg. As we get closer to the drilling date for CLU #14 we will obtain updated wellhead pressures to calculate the storage sand pressures and update plans accordingly. • Is there any chance that over -pressure may be encountered while drilling the gas storage pool? If so, what is the maximum potential downhole pressure? o Do not anticipate over pressure of the storage sand based on current WH pressure readings on the injection wells. We will re-evaluate the pressure when we get closer to the spud date. • The Drilling Hazards section on page 40 does not mention drilling through this gas storage pool. What mitigations measures will be available to the rig crew? How will this potential hazard and mitigation measures be communicated to the rig crew? o We have updated the Drilling hazard section to address the storage sand zone. We will be using the current offset pressures to re-evaluate the estimated sand pressure compared to current planned MW to remain overbalanced. Please describe the top and bottom seals for the gas storage pool in the vicinity of CLU 14 and demonstrate that they effectively isolate the gas storage pool from potential reservoir sands within the overlying Sterling Formation and underlying Beluga Formation. c The overlying potentially productive Sterling reservoirs are isolated by multiple coal seams, shales, as well as water -bearing sandstones between them and the gas storage pool. Additionally, the underlying potentially productive Beluga Sands are isolated from the gas storage pool by interbedded shale and coal seams. Are there any known faults in the vicinity of CLU 14, S-3 or S-4? If so, please provide a structure map showing the downthrown direction and vertical displacement of each fault. o There are no known faults that the S-3 and S-4 encountered while drilling, and I do not anticipate encountering any faults with our proposed CLU 14 well path. How will Hilcorp ensure that the gas storage pool is isolated by cement to eliminate any potential for cross-flow within CLU 14? Will a CBL be utilized to demonstrate the top of cement? Will a stage tool be run in the 7-5/8" casing string should a second stage of cement be needed to ensure isolation of the storage pool? c We have changed the original 2 string casing design to a three string casing design to better optimize future wellbore completion and production. With the change in the casing design we will be landing the 7-5/8" intermediate CSG below the storage sand above the beluga sands. We will centralize the CSG below, above and through the sterling B sands to assist in getting cement isolation between the sands. We will run a CBL across the 7-5/8" casing prior to drilling the 6-3/4" hole section to confirm cement isolation of the storage sand. Please let me know if you any more questions. Thanks, David Gorm Drilling Engineer Hilcorp Alaska Office: 907-777-8333 Cell: 505-215-2819 From: Davies, Stephen F (CED)[mailto:steve.davies@alaska.aovl Sent: Wednesday, May 22, 2019 8:51 AM To: David Gorm <deorm@hilcorp.com> Subject: [EXTERNAL] FW: CLU 14 (PTD 219-078) - More Questions and Requests David, Since Monty is out of the office, I believe that Guy forwarded these questions and requests to you but just to be certain... Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE. This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or Stevedaviesfalaska. gov. From: Davies, Stephen F (CED) Sent: Tuesday, May 21, 2019 9:33 AM To: Monty Myers (mmvers(@hilcorp.com) <mmyers@hilcorp.com> Cc: Schwartz, Guy L (CED) <guv.schwartz@alaska.aov> Subject: FW: CLU 14 (PTD 219-078) - More Questions and Requests Monty, 1. Please demonstrate that a spacing exception will not be required to drill, complete, and produce CLU 14. For reservoirs within the Sterling Formation Hilcorp's Permit to Drill application for CLU 14 lists the Field/Pool as being the Kenai Sterling Gas Pool 3. This is not correct. Kenai Sterling Gas Pool 3 is defined in, and governed by, Conservation Order No. 51OA-Corrected (CO S10A-Corrected). The Affected Area for CO 51OA-Corrected does not include Sections 7 and 8 in T5N, R11W, the Sections that will contain CLU 14. The Cannery Loop Unit is governed by CO 231. The Affected Area for Conservation Order No. 231 (CO 231) includes all of Sections 7 and 8, T5N, R11W. CO 231 does not mention the Sterling Formation. For Sections 7 and 8, there are no defined gas pools within the Sterling Formation, so the statewide requirements of 20 AAC 25.055 apply. According to AOGCC records, CLU 6 is open to, and capable of producing from, the Sterling A2, A4, A5, A6, A9 and All sands. CLU 6 appears to lie in the same governmental section as, and within 3000' of, CLU 14. To complete and produce any Sterling reservoirs in CLU 14 will require a spacing exception. Or have I missed something? For reservoirs within the Beluga Formation Within the Cannery Loop Unit, CO 231 defines and establishes pool rules for the Beluga, Upper Tyonek, or Tyonek "D" Gas Pools—including well spacing requirements of a quarter -quarter section. Please provide a map that displays the planned Beluga perforations in CLU 14 --and in all nearby wells --and demonstrates that CLU 14 will conform to the well spacing requirements of CO 231. Will CLU 14 drill into the Tyonek Formation? 2. Regarding the Spider Plot on page 46: There are two narrow, crescent-shaped polygons that lie on either side of the Kenai River that have different colored fills. What leases or features do these polygons represent? The lease numbers ADL 324602 and ADL 391790 both appear slightly above the center of the map. Which polygons do these numbers represent? Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.daviesPalaska.gov. From: Davies, Stephen F (CED) Sent: Monday, May 20, 2019 4:41 PM To: Monty Myers (mmvers(@hilcorp.com) <mmvers@hilcorp.com> Cc: Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Subject: CLU 14 (PTD 219-078) - Questions Monty, I notice that CLU 14 will be drilled very near to CINGSA's gas storage wells CLU S-3 and CLU S-4, and that CLU 14 will be drilled through the Sterling C Gas Storage Pool. • The table of Formation Tops on page 38 of Hilcorp's Permit to Drill application has the estimated pressure of the Sterling C Gas Storage Pool listed as"???", but on page 38 the pressure of that pool is listed as 7.6 PPG [EMWI. What is the source of this 7.6 ppg value? How and when was it determined? • Is there any chance that over -pressure may be encountered while drilling the gas storage pool? If so, what is the maximum potential downhole pressure? • The Drilling Hazards section on page 40 does not mention drilling through this gas storage pool. What mitigations measures will be available to the rig crew? How will this potential hazard and mitigation measures be communicated to the rig crew? • Please describe the top and bottom seals for the gas storage pool in the vicinity of CLU 14 and demonstrate that they effectively isolate the gas storage pool from potential reservoir sands within the overlying Sterling Formation and underlying Beluga Formation. • Are there any known faults in the vicinity of CLU 14, S-3 or S-4? If so, please provide a structure map showing the downthrown direction and vertical displacement of each fault. • How will Hilcorp ensure that the gas storage pool is isolated by cement to eliminate any potential for cross-flow within CLU 14? Will a CBL be utilized to demonstrate the top of cement? Will a stage tool be run in the 7-5/8" casing string should a second stage of cement be needed to ensure isolation of the storage pool? The "Yes/No" boxes regarding intent to hydraulically fracture (in the middle of the Permit to Drill form) were not checked. Does Hilcorp intend to hydraulically fracture CLU 14? Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, Including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged Information. The unauthorized review, use or disclosure of such Information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.daviesOalaska.eov. The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please not4 the sender immediately by return e-mail and permanently delete the copy you received. 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. TRANSMITTAL LETTER CHECKLIST WELL NAME: L'4_('t1 PTD: ,Z�`%--C)-7e Development _ Service _ Exploratory _ Stratigraphic Test Non--Conventionaall. -/iCQ_( C,-/ ^ � POOL: ��,�t�' d��itieh' FIELD: �� j�/� Kla Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. API No. 50 - (If last two digits , Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69 In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - _-) from records, data and logs acquired for well name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. C m an Name) Operator assumes the liability of any protest to. the acing that may ^e/xcep/t,i,on occur. k& KA i L/Z_ All dry ditch sample sets submitted tS'Ne—AOGVCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals throng tar et zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements er Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, sus ension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool KENAI C.L.U., BELUGA GAS - 449575 KENAI C.L.U., STERLING UND Wall Name: CANNERY LOOP UNIT 14 Program DEV Well bore seg ❑ PTD#: 2190780 Company HilcorrpAlaska LLC Initial Class/Type DEV/PEND GeoArea 820 _ Unit 10320 On/Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ _ ___ _ _ _ _ _ _ _ __ _ _ NA 2 Lease number appropriate. . . . . . ....... _ _ _ _ _ _ _ Yes _ ..... Surface location in ADL 60569;. portion of well passes thru ADL 391790; 3 Unique well. name and number _ _ _ . _ .. _ . _ - - _ - - - - - - - - _ - - - - - Yes _ _ _ . _ _ _ TO in ADL 60568, - - - 4 Well located in a_defined pool - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes ...... Sterling reseryoirs are in an undefined pool, Kenai CLU, Sterling Undefined. Gas.- 449578..... 5 Well located proper distance from drilling unit.boundary _ _ _ Yes _ _ _ _ _ _ _ Beluga reservoirs. lie within the Kenai CLU,_ Beluga Gas - 449575.. 6 Well located proper distance from other wells _ _ _ _ ... _ _ _ _ _ _ _ _ _ No........ SPACING EXCEPTION NEEDED; Exception decision approved 7/17/2019. 7 Sufficient acreage available in-drilling unit. _ _ _ _ _ _ _ _ Yes . .......... 8 If deviated, is wellbore plat included _ _ _ _ - - - Yes .......... 9 Operator only affected party- _ - - _ _ _ No------- 10 Operator has. appropriate_ bond in force - - - - - - _ _ _ _ Yes ............... 11 Permit can be issued without conservation order- - - - - - - _ _ _ _ No_ Appr Date 12 Permit can be issued without administrative approval _ _ .. .. . ........... Yes SFD 7/17/2019 13 Can permit be approved before 15-day wait _ . _ . _ _ _ .......... . . . . Yes 14 Well located within area and strata authorized by. Injection Order # (put. 10# in.mmments)(For- Yes 15 All wells.within 1/4. mile area-of review identified (For service well only).............. . Yes 16 Pre-produced injector; duration of pre production Less than 3 months (For service well only) _ _ Yes 17 Nonconven, gas conforms to AS31,05,030U.1.A),(j,2.A-D) .. _ Yes 18 Conductor stringprovided- - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes _ _ _ 16" oonductor set at 120 ft Engineering 19 Surface.casing-protects all known- USDW$ ___ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ _ Surface casing set at 3300 ft._ Will be fully cemented. . 20 CMT vol adequate to circulate on conductor & surf.csg - - - - - - _ _ _ Yes 21 CMT-vol adequate to tie-in long string to surf osg.. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes .. _ _ 7 5/8" will be cement. back to surface casing and use Swell packer for monitor JA (Cement Packer) 22 CMT-will cover all known productive horizons _ _ . . . . .................. Yes ..... CINGSA storage sands at 4800' TVD> running CBL to verify iso[ation, before drilling out production section. 23 Casing designs adequate for C-T, B &_permafrost- - - - - . ............. Yes - - - - - - BTC supplied.. 24 Adequate tankage of reserve pit . _ _ _ ........ Yes . Rig has steel tanks. All waste will be transported to KGF G &.I. 25 If a re-drill, has.a 10-403 for abandonment been approved .......... . ... . . NA 26 Adequate wellbore separation proposed _ _ Yes _ _ _ _ _ _ _ _ No issues with close approach :...drilling thru. Sterling.0 storage sands. _ _ _ _ .... 27 If diverter required, does it meet regulations ... _ _ _ _ _ _ _ Yes Appr Date 28 Drilling fluidprogramschematic & equip Jist.adequateYes ..... Max form pressure= 3870-psi- (8.7_ppg EMW) Will drill with 9.2 - 9,8. pp9 mud. GLS 6/19/2019 29 BOPEs, do they meet regulation _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes ....... rig 169 has 11" BOPE .5000 psi WR 30 BOPE press rating appropriate; fest to.(put psig in comments)_ _ _ _ _ _ _ _ _ _ _ _ _ Yes ..... _ _ MASP = 3000_psi -will test BOPS to 3500 psi_ _ .................... _ ......... _ 31 Choke. manifold complies w/APLRP-53 (May 84). . . . . .................... Yes 32 Work will occur without operation shutdown - - - - - - - - -------- - - - - - - - - - - - - Yes _ _ _ Sundry requried to complete and, perforate we[I.. CBL to TOC in 7 5/8" 33 Is presence of 1-12S gas probable. . . . ......... . .. . . . . _ _ _ _ _ _ _ No _ Not expected 34 .Mechanical condition of wells within A013 verified (For service well only) .. _ _ _ _ _ _ NA- 35 Permit. can be issued w(o hydrogen sulfide measures - - - - - _ _ _ _ _ _ _ _ Yes _ _ _ H2S is not expected based on nearby wells_ Geology 36 Data presented on potential overpressure zones.. _ _ _ _ _ _ _ Yes . .. Pressure gradients in intermediate- and production intervals expected to varyfrom 2,1 to 8:7.ppg. LCM_and _ Appr Date 37 Seismic analysis of shallow gas zones_ - - - - - - - - - - .NA - - - - - barite will beavailableonsite to handle anyunder-or oyar,pressure encountered as - - - SFD 6/5/2019 38 Seabed condition survey (if off-shore) __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA _ _ discussed on pages 51 to 53: Well will pass thru the.CINGSA gas. storage reservoir. 39 Contact name/phone for weekly-progress reports [exploratory only] - - - - - - - - - ---- NA _ _ _ _ That storage reservoir wiltbelso[ated by casing and cement. Geologic Engineering Public Well will drill through the CINGSA Sterling Gas Storage reservoir, which will be immediately isolated using 7.5/8" casing and 'Salo r: Date: Commissioner: Date Commissioner Date cement, with confirmation from a CBL (see pages 29, 36, and 52 of application). SFD