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Home My WebLink About219-0721. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: CTCO, N2 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 10,210' N/A Casing Collapse Structural Conductor Surface 2,470 psi Intermediate 4,790 psi Production 7,500 psi 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 Swell Pkr; N/A 4,917' MD / 4,718' TVD; N/A 9,914' 10,120' 9,825' Kenai Tyonek Gas Pool 1 / Beluga-Up Tyonek Gas 16" 10-3/4" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Unit (KU) 24-05BCO 510C Same 9,908'4-1/2" ~2,158 psi 10,206' N/A Length January 30, 2026 N/A 10,206' Perforation Depth MD (ft): 5,973' See Attached Schematic 6,890 psi 5,210 psi 120' 5,744' 120' 1,580' Size 120' 7-5/8"5,973' 1,580' MD Hilcorp Alaska, LLC Proposed Pools: N/A TVD Burst N/A 8,430 psi 1,550' Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEE A028142 219-072 50-133-20683-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Stefan Reed, Operations Engineer AOGCC USE ONLY Tubing Grade: stefan.reed@hilcorp.com 206-518-0400 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: m n P s 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 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2026.01.19 17:25:10 - 09'00' Noel Nocas (4361) 326-036 By Grace Christianson at 8:55 am, Jan 20, 2026 DSR-1/22/26A.Dewhurst 21JAN26BJM 26Jan26 10-404 X CT BOP test to 3500 psi CTCO/PERF Well: KU 24-05B Jan 2026 Well Name: KU 24-05B API Number: 50-133-20683-00-00 Current Status: Producing Gas Well Permit to Drill Number: 219-072 First Call Engineer: Stefan Reed (907) 777-8433 (O) (206) 518-0400 (C) Second Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Max Expected BHP: ~3,000psi @ 8,422 TVD (from offset wells) Max Potential Surface Pressure: ~2,158psi (0.1psi/ft gas gradient) Applicable Frac gradient: 0.63psi/ft using FIT from 7/12/19 Shallowest Perf Depth: 2,158psi/(0.63-0.1) = 4,072 TVD Top of Pools per CO 510C: Top of Beluga/Upper Tyonek is 4,894 MD (4,696 TVD) Top of Tyonek is 9127 MD (8841 TVD) Brief Well Summary KU 24-05B was drilled and completed in August 2019 as a 4-1/2 monobore targeting the Tyonek D sands. In June 2020, well was commingled between Beluga/Upper Tyonek Gas Pool with the Tyonek Gas Pool 1. The well produced at ~1mmscfd at a slow decline to ~ 700mscfd in 2024. In February of 2025 coil fished a slickline tool string and cleaned out to 8,574 to return base rate. Recently the well has died and remained shut-in. The purpose of this work/sundry is to perform a coil tubing clean out to clear any sand bridges/obstruction and perf/reperf sands in the Beluga/Upper Tyonek Notes Regarding Wellbore Condition Coil cleaned out to 8,574 CTM in 2025, hard tag Tight spot at ~7,608 Coil Clean Out Procedure 1. MIRU Coil Tubing 2. Test BOPs to 250psi low/3500psi high a. Provide 24-hour notice to AOGCC for witness 3. MU/RIH with motor/mill 4. Clean out well as deep as possible using 6% KCL. 5. MU and RIH w/ nozzle assembly. 6. Circulate out fluid w/ N2 7. Pressure up well to ~2500psi w/ N2 8. RDMO Eline Procedure 9. MIRU Eline 10. PT PCE 250/3500psi 11. Ops bleed N2 from well as directed by OE/RE for desired perforating pressure by zone (typically targeting 20% underbalance) 12. Perforate proposed intervals bottoms up per table below: Use the frac pressure from the 7-5/8" shoe, 14 ppg Use MPSP. Since the proposed perfs are between existing perfs, this isn't necessary for this well. -bjm CTCO/PERF Well: KU 24-05B Jan 2026 Below are proposed targeted sands in order of testing (bottom/up), but additional sand may be added depending on results of these perfs, between the proposed top and bottom perfs Sands Top MD Btm MD Top TVD Btm TVD FT TY ±7,476 ±7,483 ±7,220 ±7,227 ±7 UT 1B ±7,674 ±7,680 ±7,414 ±7,420 ±6 TY 75-8 ±7,830 ±7,857 ±7,567 ±7,594 ±27 TY 76_7 ±7,918 ±7,922 ±7,654 ±7,658 ±4 TY 76-7 ±7,931 ±7,937 ±7,666 ±7,672 ±6 TY84-6B ±8,704 ±8,736 ±8,423 ±8,455 ±32 Tyk D1 ±8,999 ±9,125 ±8,714 ±8,838 ±126 13. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. a. Record initial and 5/10/15 minute tubing pressures after firing b. Reperf any zones per RE/GEO discretion. c. Pending well production, all perf intervals may not be completed d. If necessary, use nitrogen to pressure up well during perforating e. Above perfs will be shot in the Beluga/Upper Tyonek governed by CO 510C 14. RD E-Line Unit and turn well over to operations for production. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Coil BOP Schematic 4. Standard Nitrogen Procedure _____________________________________________________________________________________ Updated by SAR 06-10-25 SCHEMATIC Kenai Gas Field Well: KU 24-05B PTD: 219-072 API: 50-133-20683-00-00 PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Pool Date Status MB8 6,208'6,219'5,976'5,987'11'Blga/Upr Ty 8/25/21 Open MB9 6,309'6,317'6,075'6,083'8'Blga/Upr Ty 8/25/21 Open LB1X 6,331'6,338'6,096'6,103'7'Blga/Upr Ty 8/25/21 Open LB1B 6,403'6,415'6,167'6,179'12'Blga/Upr Ty 8/25/21 Open LB1D 6,522'6,532'6,284'6,294'10'Blga/Upr Ty 8/25/21 Open LB1E 6,539'6,544'6,300'6,305'5'Blga/Upr Ty 8/25/21 Open LB1F 6,5676,5816,3276,34114 Blga/Upr Ty 11/12/20 Open LB1F 6,6046,6186,3646,37814 Blga/Upr Ty 11/12/20 Open LB2C 6,7346,7396,4916,4965 Blga/Upr Ty 11/12/20 Open LB2C 6,7616,7726,5176,52811 Blga/Upr Ty 11/12/20 Open LB2D 6,7806,7906,5366,54610 Blga/Upr Ty 11/11/20 Open LB2E 6,8296,8346,5846,5895 Blga/Upr Ty 11/11/20 Open LB2E 6,861'6,867'6,614'6,620'6'Blga/Upr Ty 8/25/21 Open LB3C 7,0017,0226,7526,77321 Blga/Upr Ty 11/11/20 Open LB4 7,0687,0756,819'6,826'7Blga/Upr Ty 8/09/21 Open LB4 7,083 7,0876,834' 6,838'4Blga/Upr Ty 8/09/21 Open LB4A 7,094' 7,106' 6,844' 6,856' 12' Blga/Upr Ty 7/26/21 Open LB4C 7,158' 7,164' 6,907' 6,913' 6' Blga/Upr Ty 7/26/21 Open LB4C 7,164 7,170 6,913 6,919 6Blga/Upr Ty 8/09/21 Open LB5A 7,282' 7,300' 7,029' 7,047'18Blga/Upr Ty 6/12/20 Open TY72-8 7,516' 7,533' ±7,260' ±7,2' 17' Blga/Upr Ty 7/26/21 Open TY73-2 7,595' 7,606' 7,336' 7,347' 11 Blga/Upr Ty 6/12/20 Open UT 1C 7,755' 7,762' 7,494' 7,501' 6 Blga/Upr Ty 6/12/20 Open TY84-6B 8,704' 8,736' 8,423' 8,455' 32 Blga/Upr Ty 6/10/20 Open D2 9,165' 9,190' 8,882' 8,908' 25 Tyonek 8/16/19 Open D3A 9,446' 9,463' 9,156' 9,173' 17 Tyonek 8/15/19 Open D3B 9,492' 9,516' 9,202' 9,226' 24 Tyonek 8/15/19 Open D4B 9,660' 9,686' 9,368' 9,399' 26 Tyonek 8/15/19 Open D4D 9,737' 9,754' 9,446' 9,462' 17 Tyonek 8/15/19 Open Z M M L L L L L L L L L L L L L L L L TY TY U TY D CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 109 / X-56 / Weld 16Surf 120 10-3/4Surface 45.5 /L-80 / TXP BTC 9.950Surf 1,580 7-5/8"Intermediate 29.7 / L-80 / W563 6.875Surf 5,973 4-1/2"Production 12.6 / L-80 / TXP BTC 3.958Surf 10,206 JEWELRY DETAIL No Depth Item 1 4,9174-1/2 Swell Packer OPEN HOLE / CEMENT DETAIL 10-3/4 220 BBLs of cement in 13.5 Hole. Returns to Surface (50% excess) 7-5/8" 9-7/8 Hole: 174bbls 12# class A lead cement pumped followed by 31bbls of 15.3# Class A tail cement. Full returns throughout job. 40bbls spacer ahead of cement. Trace spacer returned back to surface. 7/11/19 Radial CBL shows ToC at ~1550 MD 4-1/2 6-3/4 Hole: 150bbls 12.5# lead cement pumped followed by 35.4bbls of 15.3# tail cement. 4.6bbl losses throughout job. 7/30/19 Radial CBL shows ToC at ~5030 MD. Volumetrics suggest ToC could be as high as 3500 MD. Light cement may be hard to pick up on CBL. Note: Comingled production from Tyonek and Beluga/Upper Tyonek pools. Requires a production log each calendar year, and not more than 13 months between logs per CO 510B: Last ran:July 2022 _____________________________________________________________________________________ Updated by SAR 01-16-26 PROPOSED Kenai Gas Field Well: KU 24-05B PTD: 219-072 API: 50-133-20683-00-00 PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Pool Date Status MB8 6,208'6,219'5,976'5,987'11'Blga/Upr Ty 8/25/21 Open MB9 6,309'6,317'6,075'6,083'8'Blga/Upr Ty 8/25/21 Open LB1X 6,331'6,338'6,096'6,103'7'Blga/Upr Ty 8/25/21 Open LB1B 6,403'6,415'6,167'6,179'12'Blga/Upr Ty 8/25/21 Open LB1D 6,522'6,532'6,284'6,294'10'Blga/Upr Ty 8/25/21 Open LB1E 6,539'6,544'6,300'6,305'5'Blga/Upr Ty 8/25/21 Open LB1F 6,5676,5816,3276,34114 Blga/Upr Ty 11/12/20 Open LB1F 6,6046,6186,3646,37814 Blga/Upr Ty 11/12/20 Open LB2C 6,7346,7396,4916,4965 Blga/Upr Ty 11/12/20 Open LB2C 6,7616,7726,5176,52811 Blga/Upr Ty 11/12/20 Open LB2D 6,7806,7906,5366,54610 Blga/Upr Ty 11/11/20 Open LB2E 6,8296,8346,5846,5895 Blga/Upr Ty 11/11/20 Open LB2E 6,861'6,867'6,614'6,620'6'Blga/Upr Ty 8/25/21 Open LB3C 7,0017,0226,7526,77321 Blga/Upr Ty 11/11/20 Open LB4 7,068 7,0756,819' 6,826'7Blga/Upr Ty 8/09/21 Open LB4 7,083 7,0876,834' 6,838'4Blga/Upr Ty 8/09/21 Open LB4A 7,094' 7,106' 6,844' 6,856' 12' Blga/Upr Ty 7/26/21 Open LB4C 7,158' 7,164' 6,907' 6,913' 6' Blga/Upr Ty 7/26/21 Open LB4C 7,164 7,170 6,913 6,919 6Blga/Upr Ty 8/09/21 Open LB5A 7,282' 7,300' 7,029' 7,047'18Blga/Upr Ty 6/12/20 Open TY ±7,476 ±7,483 ±7,220 ±7,227±7 Blga/Upr Ty TBD Proposed TY72-8 7,516' 7,533' 7,260' 7,276' 17' Blga/Upr Ty 7/26/21 Open TY73-2 7,595' 7,606' 7,336' 7,347' 11 Blga/Upr Ty 6/12/20 Open UT1B ±7,674 ±7,680 ±7,414 ±7,420±6 Blga/Upr Ty TBD Proposed UT 1C 7,755' 7,762' 7,494' 7,501' 6 Blga/Upr Ty 6/12/20 Open TY75-8 ±7,830 ±7,857 ±7,567 ±7,594±27 Blga/Upr Ty TBD Proposed TY76-7 ±7,918 ±7,922 ±7,654 ±7,658±4 Blga/Upr Ty TBD Proposed TY76-7 ±7,931 ±7,937 ±7,666 ±7,672±6 Blga/Upr Ty TBD Proposed TY84-6B 8,704' 8,736' 8,423' 8,455' 32 Blga/Upr Ty 6/10/20 Open TY84-6B 8,704' 8,736' 8,423' 8,455' ±32 Blga/Upr Ty TBD Proposed D1 ±8,999 ±9,125 ±8,714 ±8,838±126 Blga/Upr Ty TBD Proposed D2 9,165' 9,190' 8,882' 8,908' 25 Tyonek 8/16/19 Open D3A 9,446' 9,463' 9,156' 9,173' 17 Tyonek 8/15/19 Open D3B 9,492' 9,516' 9,202' 9,226' 24 Tyonek 8/15/19 Open D4B 9,660' 9,686' 9,368' 9,399' 26 Tyonek 8/15/19 Open D4D 9,737' 9,754' 9,446' 9,462' 17 Tyonek 8/15/19 Open Z M M L L L L L L L L L L L L L L L L TY TY U U TY TY TY TY TY D CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 109 / X-56 / Weld 16Surf 120 10-3/4Surface 45.5 /L-80 / TXP BTC 9.950Surf 1,580 7-5/8"Intermediate 29.7 / L-80 / W563 6.875Surf 5,973 4-1/2"Production 12.6 / L-80 / TXP BTC 3.958Surf 10,206 JEWELRY DETAIL No Depth Item 1 4,9174-1/2 Swell Packer OPEN HOLE / CEMENT DETAIL 10-3/4 220 BBLs of cement in 13.5 Hole. Returns to Surface (50% excess) 7-5/8" 9-7/8 Hole: 174bbls 12# class A lead cement pumped followed by 31bbls of 15.3# Class A tail cement. Full returns throughout job. 40bbls spacer ahead of cement. Trace spacer returned back to surface. 7/11/19 Radial CBL shows ToC at ~1550 MD 4-1/2 6-3/4 Hole: 150bbls 12.5# lead cement pumped followed by 35.4bbls of 15.3# tail cement. 4.6bbl losses throughout job. 7/30/19 Radial CBL shows ToC at ~5030 MD. Volumetrics suggest ToC could be as high as 3500 MD. Light cement may be hard to pick up on CBL. STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: CTCO, N2 Development Exploratory 3. Address:Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 10,210 feet N/A feet true vertical 9,914 feet N/A feet Effective Depth measured 10,120 feet 4,917 feet true vertical 9,825 feet 4,718 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)N/A N/A N/A N/A Packers and SSSV (type, measured and true vertical depth)Swell Pkr; N/A 4,917' MD 4,718' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date:Contact Name: Contact Email: Authorized Title:Contact Phone: Stefan Reed, Operations Engineer 325-130 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 N/A stefan.reed@hilcorp.com 206-518-0400 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' 2 0450 0 11670 48 Production Liner 5,973' 10,206' measured TVD 7-5/8" 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-072 50-133-20683-00-00 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: FEE A028142 Kenai Gas Field / Tyonek Gas Pool 1 & Beluga/Upper Tyonek Gas Pool Kenai Unit (KU) 24-05B Plugs Junk measured LengthCasing Structural 5,744' 9,908' 5,973' 10,206' 120'Conductor Surface Intermediate 16" 10-3/4" 120' 1,580' 4,790psi 7,500psi 5,210psi 6,890psi 8,430psi 1,580'1,550' Burst Collapse 2,470psi p k ft t Fra O s 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 7:47 am, Jun 17, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.06.16 15:48:41 - 08'00' Noel Nocas (4361) DSR-6/18/25 RBDMS JSB 062725 BJM 9/23/25 Page 1/1 Well Name: KEU KU 24-05B Report Printed: 6/11/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Wellbore API/UWI:50-133-20683-00-00 Field Name:Kenai Gas Field State/Province:ALASKA Permit to Drill (PTD) #:219-072 Sundry #: Rig Name/No: Jobs Actual Start Date:3/6/2025 End Date: Report Number 1 Report Start Date 3/17/2025 Report End Date 3/18/2025 Last 24hr Summary PTW, JSA with Fox Energy and Operations. MIRU CTU 10 with 2.0" coil. Spot and rig upright supply tank and difuser tank. BOPE test witness was waived by Jim Regg. Test BOPE 250/3500 psi. Test time 1500-1730 hrs. RIg up twin 50 bbl batch mixer tank. Trouble shoot e start fault. Spot in KCL trailer. Report Number 2 Report Start Date 3/18/2025 Report End Date 3/19/2025 Last 24hr Summary 24 hr incident free operations. PTW, JSA with crew. SIMOPS with G&I facility to help aid in building 300 bbl of 6% KCL. Makue uip fishing BHA with hydraulic release over shot. Stab on well PT stack 250/3500 psi. RIh snubbing closed choke 1300 psi WHP. Perform weight check 3500' 21K, 6850' 32K,, Dry tag TOF @ 7587" CTMD. SL report TOF est. 7144'. PIck up heavy 10K over string weight. Latched SL fish neck. continue to move OOH with 5-10K consistent over pulls. Tag up at surface. Discuss plan town. RIH to drop fish off for slick line. 2610' CTMD setting down weight -5k. Look to be setting down on the remaining 300' of SL wire. pressure up on BHA and relsease Thru tubing hydraulic over shot. POOH to surface. BLow reel dry. SDFN. Report Number 3 Report Start Date 3/19/2025 Report End Date 3/20/2025 Last 24hr Summary Dragged fish from tag depth at 2634' SL/2653'KB to final depth of 2584' SL/ 2603'KB. RU pollard Slick line with .125" wire and JD overshot. PT stack 250/3500 psi. 1300 psi wp. RIH for dry tag. Tagged and latched fish profile 2634'. Made multiple runs. Not able to pop fish free. Moved up hole 40'. RDMO slick line. Report Number 4 Report Start Date 3/20/2025 Report End Date 3/21/2025 Last 24hr Summary PTW, JSA with crew. Fire equipment. Pick injector head and lubricator. make up YJOS fishing BHA. Hold tailgate meeting for SIMOPS with Pollard wireline crane. Pick riser and stab ontop of BOPE and flange up. MU flange x bowen ontop of riser. Stab injector and 30' lubricator ontop riser and BOP stack. Fluid pack well stack. PT 250/3500 psi. Bleed lubricator down to 1300 psi. Open well. Initial WHP 1500 psi. Bleed gas cap to open top tank. RIH and park above TOF at 2500'. Pick up clean at 17.5K. Online down CT taking returns up CT annuli through choke. Control choke needle and seat to hold back pressur while bleeding gas and circulating 6% KCL. RIH tag TOF @ 2613' CTMD. 36 bbls of 6% pumped. Multiple attempts to latch with hydraulic release no luck. Pushed fish to 2625' CTMD. POOH to surface to check BHA . Tagged up. close well and pop off. overshot fishing profile clean and in set position. Call town to discuss. Rig down CTU 10. MIRU pollard wireline with .160 wire. PT 250/3500 Latched fish @ 2615' KB, move fish up to 456' KB dragging heavy. Discuss with OE. Plant O/S on Fish @ 456' KB Report Number 5 Report Start Date 3/21/2025 Report End Date 3/22/2025 Last 24hr Summary Fox CTU. PJSM and PTW. MU fishing tools. PT PCE 250/3500 psi. RIH w/ 2-7/8" CTC, Jar, Disc., @ 3.63" OD 4" Hyd GS OAL 11'. Observe minor Wt loss @ 481' CTM. Appears fish sliding in hole. Stop @ 500' and POH w/ little to no drag. Recovered slickline tool string and ~300'' ball of wire. Swing coil clear of well and RU slickline w/ wire grab and 3.85" wire finder. Fish 4' of wire from tree. ~15' of wire from Tbg hanger,RIH w/ same. Note fluid level @ 6380'. Drifted tbg clean. Tag @ 7501' SLM (7520' MD) POH. Rig down and release Pollard Slickline. Report Number 6 Report Start Date 3/22/2025 Report End Date 3/23/2025 Last 24hr Summary Fox CTU. PJSM and PTW. Pick up injector and lubricator. MU tools. PT PCE 250/3500 psi. WHP 1700 psi. RIH w/ 2" CTC, 2.125" checks, 2.0" 1.5 MT x 1" MT XO, and 1.75" JSN. OAL 2.5'. Start circulating gas out w/ 6% KCL from 6425' (fluid level @ 6380). 1:1 returns. Start FCO from 7450' (SL tag 7500') @ 2 bpm @ 2000 psi CTP. Start w/ 100' bites and 5 bbls gel sweeps. Little solids in returns. Extend to 200' bites and 200' wiper trips. Cleanout to @ 8574'. Hard tag. Work down to 8605'. Gel sweep @ nozzle, make 200' wiper trip and RBIH. Set down @ 8520'. PU clean but unable to RBIH. Continue to PU and losing hole. Final tag @ 8318' CTM. Pump final 5 bbls gel sweep. Start N2 @ 1400 scfm @ 1050 psi CTP. Hold BHP constant @ 1900 psi while circ well to N2. N2 to surface @ 139K SCF away. SD. Recoverd 133 of 138 bbl calc volume. POH. OOH Pressure up well to 2475 PSI. No obvious indication of wire on tools. Stack down lube and injector. SDFN Report Number 7 Report Start Date 3/23/2025 Report End Date 3/24/2025 Last 24hr Summary Pollard SL and Fox CTU 2" coil. PTW/PJSM. RU Sl. RIH w/ 3.75" OD wire finder and wire grab. Tag @ 7581'. No recovery. Pressure up well from 1650 psi to 1750 psi w/ 18K SCF N2. Attempt to works past 7581' w/ 2.75 and 3" drive-down bailers. Note metal marks on bttm 1" of 3" bailer. No progress and no recovery. RD SL and PU coil injector, PT connection 250/2500 psi. RIH w/ 2" CTC, 2.125" checks, 2.0" 1.5 MT x 1" MT XO, and 1.75" JSN. OAL 2.5'. Wt Ck @ 7250' 32K. RIH. Note ~1.5k Wt loss @ 7620' CTM, RIH to 7700' without tagging. Pull ~2K over up to 7620'. Bring well online to tank. Initial WHP 1600 psi. Cont to PU slowly to top of perfs. Flow until methane to surface. Swap to production @ ~275 psi. Well dropped off to 56 psi and zero rate. Swap back to tank. WHP dropped to ~5 psi and ~120 mscfd but no water. On line w/ N2 @ 500 scfm @ 385 psi CTP and RIH from 6100' to 7350'. WHP 50 psi. Recovered 6 bbls water. POH on N2. SD N2 @ 1000'. 60K N2 away. OOH Recovered 17 bbls water. FLow well to tank until methane @ surface. Roll into production @ 175 psi WHP. Stack down and SDFN. Report Number 8 Report Start Date 6/4/2025 Report End Date 6/5/2025 Last 24hr Summary Decision made by reservoir team not to pursue perforations at this time. _____________________________________________________________________________________ Updated by SAR 06-10-25 SCHEMATIC Kenai Gas Field Well: KU 24-05B PTD: 219-072 API: 50-133-20683-00-00 PERFORATION DETAIL Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Pool Date Status MB8 6,208'6,219'5,976'5,987'11'Blga/Upr Ty 8/25/21 Open MB9 6,309'6,317'6,075'6,083'8'Blga/Upr Ty 8/25/21 Open LB1X 6,331'6,338'6,096'6,103'7'Blga/Upr Ty 8/25/21 Open LB1B 6,403'6,415'6,167'6,179'12'Blga/Upr Ty 8/25/21 Open LB1D 6,522'6,532'6,284'6,294'10'Blga/Upr Ty 8/25/21 Open LB1E 6,539'6,544'6,300'6,305'5'Blga/Upr Ty 8/25/21 Open LB1F 6,567’6,581’6,327’6,341’14 Blga/Upr Ty 11/12/20 Open LB1F 6,604’6,618’6,364’6,378’14 Blga/Upr Ty 11/12/20 Open LB2C 6,734’6,739’6,491’6,496’5 Blga/Upr Ty 11/12/20 Open LB2C 6,761’6,772’6,517’6,528’11 Blga/Upr Ty 11/12/20 Open LB2D 6,780’6,790’6,536’6,546’10 Blga/Upr Ty 11/11/20 Open LB2E 6,829’6,834’6,584’6,589’5 Blga/Upr Ty 11/11/20 Open LB2E 6,861'6,867'6,614'6,620'6'Blga/Upr Ty 8/25/21 Open LB3C 7,001’7,022’6,752’6,773’21 Blga/Upr Ty 11/11/20 Open LB4 7,068’7,075’6,819'6,826'7’Blga/Upr Ty 8/09/21 Open LB4 7,083’7,087’6,834'6,838'4’Blga/Upr Ty 8/09/21 Open LB4A 7,094'7,106'6,844'6,856'12'Blga/Upr Ty 7/26/21 Open LB4C 7,158'7,164'6,907'6,913'6'Blga/Upr Ty 7/26/21 Open LB4C 7,164’7,170’6,913’6,919’6’Blga/Upr Ty 8/09/21 Open LB5A 7,282'7,300'7,029'7,047'18’Blga/Upr Ty 6/12/20 Open TY72-8 7,516'7,533'±7,260'±7,2'17'Blga/Upr Ty 7/26/21 Open TY73-2 7,595'7,606'7,336'7,347'11 Blga/Upr Ty 6/12/20 Open UT 1C 7,755'7,762'7,494'7,501'6 Blga/Upr Ty 6/12/20 Open TY84-6B 8,704'8,736'8,423'8,455'32 Blga/Upr Ty 6/10/20 Open D2 9,165'9,190'8,882'8,908'25 Tyonek 8/16/19 Open D3A 9,446'9,463'9,156'9,173'17 Tyonek 8/15/19 Open D3B 9,492'9,516'9,202'9,226'24 Tyonek 8/15/19 Open D4B 9,660'9,686'9,368'9,399'26 Tyonek 8/15/19 Open D4D 9,737'9,754'9,446'9,462'17 Tyonek 8/15/19 Open Z M M L L L L L L L L L L L L L L L L TY TY U TY D CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 109 / X-56 / Weld 16”Surf 120’ 10-3/4”Surface 45.5 /L-80 / TXP BTC 9.950”Surf 1,580’ 7-5/8"Intermediate 29.7 / L-80 / W563 6.875”Surf 5,973’ 4-1/2"Production 12.6 / L-80 / TXP BTC 3.958”Surf 10,206’ JEWELRY DETAIL No Depth Item 1 4,917’4-1/2” Swell Packer OPEN HOLE / CEMENT DETAIL 10-3/4”220 BBL’s of cement in 13.5” Hole. Returns to Surface (50% excess) 7-5/8" 9-7/8” Hole: 174bbls 12# class A lead cement pumped followed by 31bbls of 15.3# Class A tail cement. Full returns throughout job. 40bbls spacer ahead of cement. Trace spacer returned back to surface. 7/11/19 Radial CBL show’s ToC at ~1550’ MD 4-1/2” 6-3/4” Hole: 150bbls 12.5# lead cement pumped followed by 35.4bbls of 15.3# tail cement. 4.6bbl losses throughout job. 7/30/19 Radial CBL show’s ToC at ~5030’ MD. Volumetrics suggest ToC could be as high as 3500’ MD. Light cement may be hard to pick up on CBL. Note: Comingled production from Tyonek and Beluga/Upper Tyonek pools. Requires a production log each calendar year, and not more than 13 months between logs per CO 510B:Lastt ran:: JJulyy 20222 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: CTCO, N2 2.Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6.API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 10,210'N/A Casing Collapse Structural Conductor Surface 2,470 psi Intermediate 4,790 psi Production 7,500 psi 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 Swell Pkr; N/A 4,917' MD / 4,718' TVD; N/A 9,914'10,120'9,825' Kenai Beluga-Up Tyonek Gas / Tyonek Gas 16" 10-3/4" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Unit (KU) 24-05BCO 510C Beluga-Up Tyonek Gas 9,908'4-1/2" ~1,356 psi 10,206' N/A Length March 16, 2025 N/A 10,206' Perforation Depth MD (ft): 5,973' See Attached Schematic 6,890 psi 5,210 psi 120' 5,744' 120' 1,580' Size 120' 7-5/8"5,973' 1,580' MD Hilcorp Alaska, LLC Proposed Pools: N/A TVD Burst N/A 8,430 psi 1,550' Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEE A028142 219-072 50-133-20683-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Stefan Reed, Operations Engineer AOGCC USE ONLY Tubing Grade: stefan.reed@hilcorp.com 206-518-0400 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: m n P s 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 325-130 By Gavin Gluyas at 9:45 am, Mar 07, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.03.07 09:36:08 - 09'00' Noel Nocas (4361) Variance to 20 AAC 25.112(g)(2) approved. See below. Must have 1.5 x wellbore volume of kill weight fluid on location while fishing lost wireline & toolstring due to possibility of sticking wire and toolstring across tree and compromising master valve during tool recovery. DSR-3/10/25 3416 psi after new perfs. -bjm A.Dewhurst 10MAR25 X CT BOP test to 3500 psi. BJM 3/10/25 10-404 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.03.11 13:34:31 -08'00'03/11/25 RBDMS JSB 031125 Fish/CTCO Well: KU 24-05B Date: 2/25/25 Well Name: KU 24-05B API Number: 50-133-20683-00-00 Current Status: Producing Gas Well Permit to Drill Number: 219-072 First Call Engineer: Stefan Reed (907) 777-8433 (O)(206) 518-0400 (C) Second Call Engineer: Chad Helgeson (907) 777-8405 (O)(907) 229-4824 (C) Max Expected BHP: ~1,973psi @ 6,167’ TVD (2017 RFT data from offset well KU 14-05 in LB-1B sand) Max Potential Surface Pressure: ~1,356psi (0.1psi/ft gas gradient) Applicable Frac gradient: 0.63psi/ft using FIT from 7/12/19 Shallowest Perf Depth: 1356psi/(0.63-0.1) = 2,558’ TVD Top of Pools per CO 510C: Top of Beluga/Upper Tyonek is 4,894 MD (4,696’ TVD) Top of Tyonek is 9127’ MD (8841’ TVD) Brief Well Summary KU 24-05B was drilled and completed in August 2019 as a 4-1/2” monobore targeting the Tyonek D sands. In June 2020, well was commingled between Beluga/Upper Tyonek Gas Pool with the Tyonek Gas Pool 1. The well produced at ~1mmscfd at a slow decline to ~ 700mscfd in 2024. Recently the rate dropped to ~300 mscfd. Slickline attempted to bail sand to regain rate but lost the tool string w/ ~300’ of wire. The well is currently shut in until the tools can be retrieved. The purpose of this work/sundry is to retrieve the slickline tool string and wire and perform a coil tubing clean out to clear any sand bridges/obstructions, plug off the Tyonek sands and perforate the D1 and TY-84-6B sands. Hilcorp requests a variance from 20 AAC 25.112(g)(2) to not pressure test the pool isolation plug due to open perfs above the plug set depth. Notes Regarding Wellbore Condition x Slickline tool string @ 7144’ x 7608’ known tight spot Coil Fishing Procedure 1. MIRU Coil Tubing 2. Test BOP’s to 250psi low/3500psi high a. Provide 24-hour notice to AOGCC for witness 3. MU/RIH with fishing BHA 4.Once fish is moving, discuss w/ WSL and OE plan forward: a.Pump off fish to recover downhole b.Or, POOH, space out BHA across tree valves and hang fish off at surface in the master valve Slickline Procedure 5. MIRU Slickline. M/U Slickline PCE on to coil BOPs 6.PT PCE 7. Retrieve fish from downhole/master valve 8.Fish any remaining wire 9. RDMO Slickline Variance approved. -bjm Pressure at 8832' TVD = 4300 psi. MPSP = 3416 after new perfs are added. See 10Mar25 email from Stefan Reed. -bjm In June 2020, well was commingled between Beluga/Upper Tyonek Gas Pool with the Tyonek Gas Pool 1. Fish/CTCO Well: KU 24-05B Date: 2/25/25 Coil Clean Out procedure 10. RIH w/ nozzle clean out assembly 11. Clean out well as deep as possible using 6% KCL. Use N2 as necessary. 12. If any obstructions: a. POOH b. M/U Motor/Mill c. RIH Attempt to mill obstructions d. Complete clean out to ~9250’ e. POOH 13. MU and RIH w/ nozzle clean out assembly. 14. Circulate out fluid w/ N2 15. Pressure up well to ~2500psi w/ N2 16. RDMO Eline Procedure 17. MIRU Eline, PT PCE 18. Set CIBP @ ~9,155’ 19. Dump bail ~25ft of cement (~16gal) on top of plug. 20. RIH Tag TOC to confirm depth a. Provide 24hr notice to AOGCC to witness tag 21. Perforate proposed intervals bottoms up per table below: Pool Sands Top MD Btm MD Top TVD Btm TVD FT Beluga/ Upper Tyonek TY84-6B ±8,704’ ±8,736’ ±8,423’ ±8,455’ ±32’ Beluga/ Upper Tyonek Tyk D1 ±8,999’ ±9,125’ ±8,714’ ±8,838’ ±126’ 22. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. a. Record initial and 5/10/15 minute tubing pressures after firing b. Reperf any zones per RE/GEO discretion. c. Above perfs will be shot in the Beluga/Upper Tyonek governed by CO 510C 23. RD E-Line Unit and turn well over to operations for production. Eline Procedure (Contingency) If any zone produces sand and/or water or needs to be isolated: 24. MIRU Eline. PT PCE 25. Run GPT to find fluid level 26. RUN N2 or use gas and push fluid below perfs as needed. (Verify fluid depth w/ GPT) 27. Set CIBP to isolate zone Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Coil BOP Schematic 4. Fish Diagram 5. Standard Nitrogen Procedure PT PCE to 3500 psi. -bjm _____________________________________________________________________________________ Updated by SAR 24-Feb-25 SCHEMATIC Kenai Gas Field Well: KU 24-05B PTD: 219-072 API: 50-133-20683-00-00 PERFORATION DETAIL Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Pool Date Status MB8 6,208'6,219'5,976'5,987'11'Blga/Upr Ty 8/25/21 Open MB9 6,309'6,317'6,075'6,083'8'Blga/Upr Ty 8/25/21 Open LB1X 6,331'6,338'6,096'6,103'7'Blga/Upr Ty 8/25/21 Open LB1B 6,403'6,415'6,167'6,179'12'Blga/Upr Ty 8/25/21 Open LB1D 6,522'6,532'6,284'6,294'10'Blga/Upr Ty 8/25/21 Open LB1E 6,539'6,544'6,300'6,305'5'Blga/Upr Ty 8/25/21 Open LB1F 6,567’6,581’6,327’6,341’14 Blga/Upr Ty 11/12/20 Open LB1F 6,604’6,618’6,364’6,378’14 Blga/Upr Ty 11/12/20 Open LB2C 6,734’6,739’6,491’6,496’5 Blga/Upr Ty 11/12/20 Open LB2C 6,761’6,772’6,517’6,528’11 Blga/Upr Ty 11/12/20 Open LB2D 6,780’6,790’6,536’6,546’10 Blga/Upr Ty 11/11/20 Open LB2E 6,829’6,834’6,584’6,589’5 Blga/Upr Ty 11/11/20 Open LB2E 6,861'6,867'6,614'6,620'6'Blga/Upr Ty 8/25/21 Open LB3C 7,001’7,022’6,752’6,773’21 Blga/Upr Ty 11/11/20 Open LB4 7,068’7,075’6,819'6,826'7’Blga/Upr Ty 8/09/21 Open LB4 7,083’7,087’6,834'6,838'4’Blga/Upr Ty 8/09/21 Open LB4A 7,094'7,106'6,844'6,856'12'Blga/Upr Ty 7/26/21 Open LB4C 7,158'7,164'6,907'6,913'6'Blga/Upr Ty 7/26/21 Open LB4C 7,164’7,170’6,913’6,919’6’Blga/Upr Ty 8/09/21 Open LB5A 7,282'7,300'7,029'7,047'18’Blga/Upr Ty 6/12/20 Open TY72-8 7,516'7,533'±7,260'±7,2'17'Blga/Upr Ty 7/26/21 Open TY73-2 7,595'7,606'7,336'7,347'11 Blga/Upr Ty 6/12/20 Open UT 1C 7,755'7,762'7,494'7,501'6 Blga/Upr Ty 6/12/20 Open TY84-6B 8,704'8,736'8,423'8,455'32 Blga/Upr Ty 6/10/20 Open D2 9,165'9,190'8,882'8,908'25 Tyonek 8/16/19 Open D3A 9,446'9,463'9,156'9,173'17 Tyonek 8/15/19 Open D3B 9,492'9,516'9,202'9,226'24 Tyonek 8/15/19 Open D4B 9,660'9,686'9,368'9,399'26 Tyonek 8/15/19 Open D4D 9,737'9,754'9,446'9,462'17 Tyonek 8/15/19 Open Z M M L L L L L L L L L L L L L L L L TY TY U TY D CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 109 / X-56 / Weld 16”Surf 120’ 10-3/4”Surface 45.5 /L-80 / TXP BTC 9.950”Surf 1,580’ 7-5/8"Intermediate 29.7 / L-80 / W563 6.875”Surf 5,973’ 4-1/2"Production 12.6 / L-80 / TXP BTC 3.958”Surf 10,206’ JEWELRY DETAIL No Depth Item 1 4,917’4-1/2” Swell Packer OPEN HOLE / CEMENT DETAIL 10-3/4”220 BBL’s of cement in 13.5” Hole. Returns to Surface (50% excess) 7-5/8" 9-7/8” Hole: 174bbls 12# class A lead cement pumped followed by 31bbls of 15.3# Class A tail cement. Full returns throughout job. 40bbls spacer ahead of cement. Trace spacer returned back to surface. 7/11/19 Radial CBL show’s ToC at ~1550’ MD 4-1/2” 6-3/4” Hole: 150bbls 12.5# lead cement pumped followed by 35.4bbls of 15.3# tail cement. 4.6bbl losses throughout job. 7/30/19 Radial CBL show’s ToC at ~5030’ MD. Volumetrics suggest ToC could be as high as 3500’ MD. Light cement may be hard to pick up on CBL. Note: Comingled production from Tyonek and Beluga/Upper Tyonek pools. Requires a production log each calendar year, and not more than 13 months between logs per CO 510B:Lastt ran:: JJulyy 20222 Slickline tool string w/ ~300’ of wire @ 7144’ SLM. See WSRs Feb-2025 _____________________________________________________________________________________ Updated by SAR 03-07-25 PROPOSED Kenai Gas Field Well: KU 24-05B PTD: 219-072 API: 50-133-20683-00-00 PERFORATION DETAIL Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Pool Date Status MB8 6,208'6,219'5,976'5,987'11'Blga/Upr Ty 8/25/21 Open MB9 6,309'6,317'6,075'6,083'8'Blga/Upr Ty 8/25/21 Open LB1X 6,331'6,338'6,096'6,103'7'Blga/Upr Ty 8/25/21 Open LB1B 6,403'6,415'6,167'6,179'12'Blga/Upr Ty 8/25/21 Open LB1D 6,522'6,532'6,284'6,294'10'Blga/Upr Ty 8/25/21 Open LB1E 6,539'6,544'6,300'6,305'5'Blga/Upr Ty 8/25/21 Open LB1F 6,567’6,581’6,327’6,341’14 Blga/Upr Ty 11/12/20 Open LB1F 6,604’6,618’6,364’6,378’14 Blga/Upr Ty 11/12/20 Open LB2C 6,734’6,739’6,491’6,496’5 Blga/Upr Ty 11/12/20 Open LB2C 6,761’6,772’6,517’6,528’11 Blga/Upr Ty 11/12/20 Open LB2D 6,780’6,790’6,536’6,546’10 Blga/Upr Ty 11/11/20 Open LB2E 6,829’6,834’6,584’6,589’5 Blga/Upr Ty 11/11/20 Open LB2E 6,861'6,867'6,614'6,620'6'Blga/Upr Ty 8/25/21 Open LB3C 7,001’7,022’6,752’6,773’21 Blga/Upr Ty 11/11/20 Open LB4 7,068’7,075’6,819'6,826'7’Blga/Upr Ty 8/09/21 Open LB4 7,083’7,087’6,834'6,838'4’Blga/Upr Ty 8/09/21 Open LB4A 7,094'7,106'6,844'6,856'12'Blga/Upr Ty 7/26/21 Open LB4C 7,158'7,164'6,907'6,913'6'Blga/Upr Ty 7/26/21 Open LB4C 7,164’7,170’6,913’6,919’6’Blga/Upr Ty 8/09/21 Open LB5A 7,282'7,300'7,029'7,047'18’Blga/Upr Ty 6/12/20 Open TY72-8 7,516'7,533'±7,260'±7,2'17'Blga/Upr Ty 7/26/21 Open TY73-2 7,595'7,606'7,336'7,347'11 Blga/Upr Ty 6/12/20 Open UT 1C 7,755'7,762'7,494'7,501'6 Blga/Upr Ty 6/12/20 Open TY84-6B 8,704'8,736'8,423'8,455'32 Blga/Upr Ty 6/10/20 Open D1 ±8,999’±9,125’±8,714’±8,838’±126 Blga/Upr Ty TBD Proposed D2 9,165'9,190'8,882'8,908'25 Tyonek 8/16/19 Isolated D3A 9,446'9,463'9,156'9,173'17 Tyonek 8/15/19 Isolated D3B 9,492'9,516'9,202'9,226'24 Tyonek 8/15/19 Isolated D4B 9,660'9,686'9,368'9,399'26 Tyonek 8/15/19 Isolated D4D 9,737'9,754'9,446'9,462'17 Tyonek 8/15/19 Isolated Z M M L L L L L L L L L L L L L L L L TY TY U TY D CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 109 / X-56 / Weld 16”Surf 120’ 10-3/4”Surface 45.5 /L-80 / TXP BTC 9.950”Surf 1,580’ 7-5/8"Intermediate 29.7 / L-80 / W563 6.875”Surf 5,973’ 4-1/2"Production 12.6 / L-80 / TXP BTC 3.958”Surf 10,206’ JEWELRY DETAIL No Depth Item 1 4,917’4-1/2” Swell Packer 2 9,155’CIBP w/ 25ft of cement OPEN HOLE / CEMENT DETAIL 10-3/4”220 BBL’s of cement in 13.5” Hole. Returns to Surface (50% excess) 7-5/8" 9-7/8” Hole: 174bbls 12# class A lead cement pumped followed by 31bbls of 15.3# Class A tail cement. Full returns throughout job. 40bbls spacer ahead of cement. Trace spacer returned back to surface. 7/11/19 Radial CBL show’s ToC at ~1550’ MD 4-1/2” 6-3/4” Hole: 150bbls 12.5# lead cement pumped followed by 35.4bbls of 15.3# tail cement. 4.6bbl losses throughout job. 7/30/19 Radial CBL show’s ToC at ~5030’ MD. Volumetrics suggest ToC could be as high as 3500’ MD. Light cement may be hard to pick up on CBL. Client:Lease: Address: Field Parish OCS-G Platform: Company Man Well Number: Phone Type of Operation: Item Tool Description C/T To Surface Tool O/D Tool I/D Length Fish Neck Connection Asset No. 1 rope socket 1.75'' 6'' 1.75'' 2 stem 1.75'' 5' 1.75'' 3 stem 1.75'' 5' 1.75'' 4 knuckle joint 1.75'' 10" 1.75'' 5 oil jars 1.75'' 3' 1.375'' 6 long stroke spang jars 1.75'' 7' 1.75'' 7 pump bailer 2.50'' 12' 1.75'' Total Length of B.H.A. :- (Meters) 37.00 (Feet) B.H.A Prepared by : Date : (B.H.A. #1 ) (Run #1 )Mike 28-Apr-19 Hilcorp 41-7 KFG POLLARD WIRELINE 2-22-2025 BAIL KU 24-05B STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: N2 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 10,210'N/A Casing Collapse Structural Conductor Surface 2,470 psi Intermediate 4,790 psi Production 7,500 psi 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 FEE A028142 219-072 50-133-20683-00-00 Hilcorp Alaska, LLC Proposed Pools: N/A TVD Burst N/A 8,430 psi 1,550' Size 120' 7-5/8"5,973' 1,580' MD See Attached Schematic 6,890 psi 5,210 psi 120' 5,744' 120' 1,580' September 6, 2023 N/A 10,206' Perforation Depth MD (ft): 5,973' 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Unit (KU) 24-05BCO 510B Beluga-Up Tyonek Gas 9,908'4-1/2" ~3,418 psi 10,206' N/A Length Swell Pkr; N/A 4,917' MD / 4,718' TVD; N/A 9,914'10,120'9,825' Kenai Beluga-Up Tyonek Gas / Tyonek Gas 16" 10-3/4" See Attached Schematic 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 9:45 am, Nov 08, 2023 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.08.23 16:57:07 - 08'00' Noel Nocas (4361) CT BOP test to 3500 psi 10-404 SFD 11/8/2023 September 6, 2023 DSR-11/15/23 Perforate BJM 11/14/23*&:JLC 11/16/2023 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.11.16 10:25:21 -09'00'11/16/23 RBDMS JSB 111623 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: N2 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 10,210' N/A Casing Collapse Structural Conductor Surface 2,470 psi Intermediate 4,790 psi Production 7,500 psi 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 FEE A028142 219-072 50-133-20683-00-00 Hilcorp Alaska, LLC Proposed Pools: N/A TVD Burst N/A 8,430 psi 1,550' Size 120' 7-5/8"5,973' 1,580' MD See Attached Schematic 6,890 psi 5,210 psi 120' 5,744' 120' 1,580' September 6, 2023 N/A 10,206' Perforation Depth MD (ft): 5,973' 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Unit (KU) 24-05BCO 510B Beluga-Up Tyonek Gas 9,908'4-1/2" ~3,418 psi 10,206' N/A Length Swell Pkr; N/A 4,917' MD / 4,718' TVD; N/A 9,914' 10,120' 9,825' Kenai Beluga-Up Tyonek Gas / Tyonek Gas 16" 10-3/4" See Attached Schematic 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 10:55 am, Aug 25, 2023 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.08.23 16:57:07 - 08'00' Noel Nocas (4361) Well Prognosis Well: KU 24-05B Date: 8/23/23 Well Name: KU 24-05B API Number: 50-133-20683-00-00 Current Status: Producing Gas Well Permit to Drill Number: 219-072 Regulatory Contact: Donna Ambruz 777-8305 First Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Second Call Engineer: Jake Flora (907) 777-8442 (720) 988-5375 (C) Max Expected BHP: ~ 4,301 psi @ 8,832 TVD (Based on RFT data in 43-07Y) Max. Predicted Surface Pressure: ~ 3,418 psi (0.10 psi/ft gas gradient) Brief Well Summary KU 24-05B was drilled and completed in August 2019 as a 4-1/2 monobore targeting the Tyonek D sands. In June 2020, well was commingled between Beluga/Upper Tyonek Gas Pool with the Tyonek Gas Pool 1. The well is current producing ~ 500 mcfd from the Beluga/Upper Tyonek Sands. The purpose of this work/sundry is to plug back the Tyonek Gas Pool add rate by perforating the Tyonek D1 sands in the Beluga/Upper Tyonek Gas Pool. Notes Regarding Wellbore Condition Monobore 4-1/2 completion Max deviation is 19 deg @ 4734 SL tagged bottom @ 9,785 on 7/20/22 Max predicted pressure based on 3 wells where pressures were collected in same sand with RFT tools while drilling in 2017 (KU 11-07X, KBU 32-06, & KBU 43-07Y) Other pressures across proposed perfs range from 1,228 psi 4,267 psi Pool Tops in KU 24-06B based on KU 21-6 reference well in CO 510B - Tyonek Gas Pool: 9,126 MD E-Line Procedure 1. SI well (allow to build for at least 24hrs prior to Eline) 2. MIRU N2 Unit and tank, test to 4,000 psi 3. MIRU E-line, PT lubricator to 250 psi low and 4,000 psi high 4. PU GPT and RIH to confirm fluid depth 5. Pressure up well with N2 to push fluid away 6. Set CIBP @ ±9,155 (log plug tag verify it is set) 7. Dump 25ft of cement (16 gal) on top of plug. (Pool isolation plug) Contingency CT Procedure if unable to push fluid below 9,155 after setting plug a. MIRU CTU, 24hr notice for BOP test b. Conduct BOP test to 250psi Low / 3500psi High c. RIH and unload water with N2 d. RDMO CT e. Trap N2 pressure on tubing per OE recommendation for perforating f. MIRU E-line and pressure control equipment g. PT lubricator to 250psi low / 4,000 psi High Well Prognosis Well: KU 24-05B Date: 8/23/23 8. Perforate Upper Tyonek sand with phased perf guns with the well shut-in per the table below: Proposed Perforated Intervals Pool Sand Top, MD ft Bottom, MD ft Top, TVD ft Bottom, TVD ft Total ftg, MD Beluga/Upper Tyonek Tyk D1 ±8,999 ±9,125 ±8,714 ±8,838 ±126 a. Proposed perfs also shown on the proposed schematic in red font. b. Send the correlation pass to the Reservoir Engineer (Reid Edwards), and Geologist (Daniel Yancey) for confirmation. c. Verify PTs are open to SCADA before perforating. Record tubing pressures at 5, 10 and 15 minutes after each perforating run. d. These sands are in the Beluga/Upper Tyonek Gas Pool per CO 510B. 9. RDMO e-line. 10. Turn well over to production. Contingency if Upper Tyonek D1 sand is not productive: i. MIRU E-line and pressure control equipment ii. PT lubricator to 250psi low / 3,500 psi High iii. RIH and set CIBP at ~8,975 iv. RDMO, turn well over to production v. Follow coil contingency to lift well with N2 if the well does not recover on its own. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Standard Nitrogen Procedure _____________________________________________________________________________________ Updated by DMA 08-23-23 SCHEMATIC Kenai Gas Field Well: KU 24-05B PTD: 219-072 API: 50-133-20683-00-00 PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Pool Date Status MB8 6,208'6,219'5,976'5,987'11'Blga/Upr Ty 8/25/21 Open MB9 6,309'6,317'6,075'6,083'8'Blga/Upr Ty 8/25/21 Open LB1X 6,331'6,338'6,096'6,103'7'Blga/Upr Ty 8/25/21 Open LB1B 6,403'6,415'6,167'6,179'12'Blga/Upr Ty 8/25/21 Open LB1D 6,522'6,532'6,284'6,294'10'Blga/Upr Ty 8/25/21 Open LB1E 6,539'6,544'6,300'6,305'5'Blga/Upr Ty 8/25/21 Open LB1F 6,5676,5816,3276,34114 Blga/Upr Ty 11/12/20 Open LB1F 6,6046,6186,3646,37814 Blga/Upr Ty 11/12/20 Open LB2C 6,7346,7396,4916,4965 Blga/Upr Ty 11/12/20 Open LB2C 6,7616,7726,5176,52811 Blga/Upr Ty 11/12/20 Open LB2D 6,7806,7906,5366,54610 Blga/Upr Ty 11/11/20 Open LB2E 6,8296,8346,5846,5895 Blga/Upr Ty 11/11/20 Open LB2E 6,861'6,867'6,614'6,620'6'Blga/Upr Ty 8/25/21 Open LB3C 7,0017,0226,7526,77321 Blga/Upr Ty 11/11/20 Open LB4 7,0687,0756,819'6,826'7Blga/Upr Ty 8/09/21 Open LB4 7,083 7,0876,834' 6,838'4Blga/Upr Ty 8/09/21 Open LB4A 7,094' 7,106' 6,844' 6,856' 12' Blga/Upr Ty 7/26/21 Open LB4C 7,158' 7,164' 6,907' 6,913' 6' Blga/Upr Ty 7/26/21 Open LB4C 7,164 7,170 6,913 6,919 6Blga/Upr Ty 8/09/21 Open LB5A 7,282' 7,300' 7,029' 7,047'18Blga/Upr Ty 6/12/20 Open TY72-8 7,516' 7,533' ±7,260' ±7,2' 17' Blga/Upr Ty 7/26/21 Open TY73-2 7,595' 7,606' 7,336' 7,347' 11 Blga/Upr Ty 6/12/20 Open UT 1C 7,755' 7,762' 7,494' 7,501' 6 Blga/Upr Ty 6/12/20 Open TY84-6B 8,704' 8,736' 8,423' 8,455' 32 Blga/Upr Ty 6/10/20 Open D2 9,165' 9,190' 8,882' 8,908' 25 Tyonek 8/16/19 Open D3A 9,446' 9,463' 9,156' 9,173' 17 Tyonek 8/15/19 Open D3B 9,492' 9,516' 9,202' 9,226' 24 Tyonek 8/15/19 Open D4B 9,660' 9,686' 9,368' 9,399' 26 Tyonek 8/15/19 Open D4D 9,737' 9,754' 9,446' 9,462' 17 Tyonek 8/15/19 Open Z M M L L L L L L L L L L L L L L L L TY TY U TY D CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 109 / X-56 / Weld 16Surf 120 10-3/4Surface 45.5 /L-80 / TXP BTC 9.950Surf 1,580 7-5/8"Intermediate 29.7 / L-80 / W563 6.875Surf 5,973 4-1/2"Production 12.6 / L-80 / TXP BTC 3.958Surf 10,206 JEWELRY DETAIL No Depth Item 1 4,9174-1/2 Swell Packer OPEN HOLE / CEMENT DETAIL 10-3/4 220 BBLs of cement in 13.5 Hole. Returns to Surface (50% excess) 7-5/8" 9-7/8 Hole: 174bbls 12# class A lead cement pumped followed by 31bbls of 15.3# Class A tail cement. Full returns throughout job. 40bbls spacer ahead of cement. Trace spacer returned back to surface. 7/11/19 Radial CBL shows ToC at ~1550 MD 4-1/2 6-3/4 Hole: 150bbls 12.5# lead cement pumped followed by 35.4bbls of 15.3# tail cement. 4.6bbl losses throughout job.7/30/19 Radial CBL shows ToC at ~5030 MD. Volumetrics suggest ToC could be as high as 3500 MD. Light cement may be hard to pick up on CBL. Note: Comingled production from Tyonek and Beluga/Upper Tyonek pools. Requires a production log each calendar year, and not more than 13 months between logs per CO 510B: Last ran:July 2022 _____________________________________________________________________________________ Updated by CAH 08-23-23 PROPOSED Kenai Gas Field Well: KU 24-05B PTD: 219-072 API: 50-133-20683-00-00 PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Pool Date Status MB8 6,208'6,219'5,976'5,987'11'Blga/Upr Ty 8/25/21 Open MB9 6,309'6,317'6,075'6,083'8'Blga/Upr Ty 8/25/21 Open LB1X 6,331'6,338'6,096'6,103'7'Blga/Upr Ty 8/25/21 Open LB1B 6,403'6,415'6,167'6,179'12'Blga/Upr Ty 8/25/21 Open LB1D 6,522'6,532'6,284'6,294'10'Blga/Upr Ty 8/25/21 Open LB1E 6,539'6,544'6,300'6,305'5'Blga/Upr Ty 8/25/21 Open LB1F 6,5676,5816,3276,34114 Blga/Upr Ty 11/12/20 Open LB1F 6,6046,6186,3646,37814 Blga/Upr Ty 11/12/20 Open LB2C 6,7346,7396,4916,4965 Blga/Upr Ty 11/12/20 Open LB2C 6,7616,7726,5176,52811 Blga/Upr Ty 11/12/20 Open LB2D 6,7806,7906,5366,54610 Blga/Upr Ty 11/11/20 Open LB2E 6,8296,8346,5846,5895 Blga/Upr Ty 11/11/20 Open LB2E 6,861'6,867'6,614'6,620'6'Blga/Upr Ty 8/25/21 Open LB3C 7,0017,0226,7526,77321 Blga/Upr Ty 11/11/20 Open LB4 7,0687,0756,819'6,826'7Blga/Upr Ty 8/09/21 Open LB4 7,083 7,0876,834' 6,838'4Blga/Upr Ty 8/09/21 Open LB4A 7,094' 7,106' 6,844' 6,856' 12' Blga/Upr Ty 7/26/21 Open LB4C 7,158' 7,164' 6,907' 6,913' 6' Blga/Upr Ty 7/26/21 Open LB4C 7,164 7,170 6,913 6,919 6Blga/Upr Ty 8/09/21 Open LB5A 7,282' 7,300' 7,029' 7,047'18Blga/Upr Ty 6/12/20 Open TY72-8 7,516' 7,533' ±7,260' ±7,2' 17' Blga/Upr Ty 7/26/21 Open TY73-2 7,595' 7,606' 7,336' 7,347' 11 Blga/Upr Ty 6/12/20 Open UT 1C 7,755' 7,762' 7,494' 7,501' 6 Blga/Upr Ty 6/12/20 Open TY84-6B 8,704' 8,736' 8,423' 8,455' 32 Blga/Upr Ty 6/10/20 Open D1 ±8,999 ±9,125 ±8,714 ±8,838±126 Blga/Upr Ty TBD Proposed D2 9,165' 9,190' 8,882' 8,908' 25 Tyonek 8/16/19 Isolated D3A 9,446' 9,463' 9,156' 9,173' 17 Tyonek 8/15/19 Isolated D3B 9,492' 9,516' 9,202' 9,226' 24 Tyonek 8/15/19 Isolated D4B 9,660' 9,686' 9,368' 9,399' 26 Tyonek 8/15/19 Isolated D4D 9,737' 9,754' 9,446' 9,462' 17 Tyonek 8/15/19 Isolated Z M M L L L L L L L L L L L L L L L L TY TY U TY D CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 109 / X-56 / Weld 16Surf 120 10-3/4Surface 45.5 /L-80 / TXP BTC 9.950Surf 1,580 7-5/8"Intermediate 29.7 / L-80 / W563 6.875Surf 5,973 4-1/2"Production 12.6 / L-80 / TXP BTC 3.958Surf 10,206 JEWELRY DETAIL No Depth Item 1 4,9174-1/2 Swell Packer 2 9,155CIBP w/ 25ft of cement OPEN HOLE / CEMENT DETAIL 10-3/4 220 BBLs of cement in 13.5 Hole. Returns to Surface (50% excess) 7-5/8" 9-7/8 Hole: 174bbls 12# class A lead cement pumped followed by 31bbls of 15.3# Class A tail cement. Full returns throughout job. 40bbls spacer ahead of cement. Trace spacer returned back to surface. 7/11/19 Radial CBL shows ToC at ~1550 MD 4-1/2 6-3/4 Hole: 150bbls 12.5# lead cement pumped followed by 35.4bbls of 15.3# tail cement. 4.6bbl losses throughout job.7/30/19 Radial CBL shows ToC at ~5030 MD. Volumetrics suggest ToC could be as high as 3500 MD. Light cement may be hard to pick up on CBL. 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. Well Prognosis Well: KU 24-05B Date: 8/23/23 Well Name: KU 24-05B API Number: 50-133-20683-00-00 Current Status: Producing Gas Well Permit to Drill Number: 219-072 Regulatory Contact: Donna Ambruz 777-8305 First Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Second Call Engineer: Jake Flora (907) 777-8442 (720) 988-5375 (C) Max Expected BHP: ~ 4,301 psi @ 8,832’ TVD (Based on RFT data in 43-07Y) Max. Predicted Surface Pressure: ~ 3,418 psi (0.10 psi/ft gas gradient) Brief Well Summary KU 24-05B was drilled and completed in August 2019 as a 4-1/2” monobore targeting the Tyonek D sands. In June 2020, well was commingled between Beluga/Upper Tyonek Gas Pool with the Tyonek Gas Pool 1. The well is current producing ~ 500 mcfd from the Beluga/Upper Tyonek Sands. The purpose of this work/sundry is to plug back the Tyonek Gas Pool add rate by perforating the Tyonek D1 sands in the Beluga/Upper Tyonek Gas Pool. Notes Regarding Wellbore Condition x Monobore 4-1/2” completion x Max deviation is 19 deg @ 4734’ x SL tagged bottom @ 9,785’ on 7/20/22 x Max predicted pressure based on 3 wells where pressures were collected in same sand with RFT tools while drilling in 2017 (KU 11-07X, KBU 32-06, & KBU 43-07Y) Other pressures across proposed perfs range from 1,228 psi – 4,267 psi Pool Tops in KU 24-06B based on KU 21-6 reference well in CO 510B - Tyonek Gas Pool: 9,126’ MD E-Line Procedure 1. SI well (allow to build for at least 24hrs prior to Eline) 2. MIRU N2 Unit and tank, test to 4,000 psi 3. MIRU E-line, PT lubricator to 250 psi low and 4,000 psi high 4. PU GPT and RIH to confirm fluid depth 5. Pressure up well with N2 to push fluid away 6. Set CIBP @ ±9,155’ (log plug tag verify it is set) 7. Dump 25ft of cement (16 gal) on top of plug. (Pool isolation plug) Contingency CT Procedure if unable to push fluid below 9,155’ after setting plug a. MIRU CTU, 24hr notice for BOP test b. Conduct BOP test to 250psi Low / 3500psi High c. RIH and unload water with N2 d. RDMO CT e. Trap N2 pressure on tubing per OE recommendation for perforating f.MIRU E-line and pressure control equipment g.PT lubricator to 250psi low / 4,000 psi High o plug back the Tyonek Gas Pool a y perforating the Tyonek D1 sands in the Beluga/Upper Tyonek Gas Pool. Well Prognosis Well: KU 24-05B Date: 8/23/23 8. Perforate Upper Tyonek sand with phased perf guns with the well shut-in per the table below: Proposed Perforated Intervals Pool Sand Top, MD ft Bottom, MD ft Top, TVD ft Bottom, TVD ft Total ftg, MD Beluga/Upper Tyonek Tyk D1 ±8,999’ ±9,125’ ±8,714’ ±8,838’ ±126’ a. Proposed perfs also shown on the proposed schematic in red font. b. Send the correlation pass to the Reservoir Engineer (Reid Edwards), and Geologist (Daniel Yancey) for confirmation. c. Verify PTs are open to SCADA before perforating. Record tubing pressures at 5, 10 and 15 minutes after each perforating run. d. These sands are in the Beluga/Upper Tyonek Gas Pool per CO 510B. 9. RDMO e-line. 10. Turn well over to production. Contingency if Upper Tyonek D1 sand is not productive: i. MIRU E-line and pressure control equipment ii. PT lubricator to 250psi low / 3,500 psi High iii. RIH and set CIBP at ~8,975’ iv. RDMO, turn well over to production v. Follow coil contingency to lift well with N2 if the well does not recover on its own. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Standard Nitrogen Procedure _____________________________________________________________________________________ Updated by DMA 08-23-23 SCHEMATIC Kenai Gas Field Well: KU 24-05B PTD: 219-072 API: 50-133-20683-00-00 PERFORATION DETAIL Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Pool Date Status MB8 6,208'6,219'5,976'5,987'11'Blga/Upr Ty 8/25/21 Open MB9 6,309'6,317'6,075'6,083'8'Blga/Upr Ty 8/25/21 Open LB1X 6,331'6,338'6,096'6,103'7'Blga/Upr Ty 8/25/21 Open LB1B 6,403'6,415'6,167'6,179'12'Blga/Upr Ty 8/25/21 Open LB1D 6,522'6,532'6,284'6,294'10'Blga/Upr Ty 8/25/21 Open LB1E 6,539'6,544'6,300'6,305'5'Blga/Upr Ty 8/25/21 Open LB1F 6,567’6,581’6,327’6,341’14 Blga/Upr Ty 11/12/20 Open LB1F 6,604’6,618’6,364’6,378’14 Blga/Upr Ty 11/12/20 Open LB2C 6,734’6,739’6,491’6,496’5 Blga/Upr Ty 11/12/20 Open LB2C 6,761’6,772’6,517’6,528’11 Blga/Upr Ty 11/12/20 Open LB2D 6,780’6,790’6,536’6,546’10 Blga/Upr Ty 11/11/20 Open LB2E 6,829’6,834’6,584’6,589’5 Blga/Upr Ty 11/11/20 Open LB2E 6,861'6,867'6,614'6,620'6'Blga/Upr Ty 8/25/21 Open LB3C 7,001’7,022’6,752’6,773’21 Blga/Upr Ty 11/11/20 Open LB4 7,068’7,075’6,819'6,826'7’Blga/Upr Ty 8/09/21 Open LB4 7,083’7,087’6,834'6,838'4’Blga/Upr Ty 8/09/21 Open LB4A 7,094'7,106'6,844'6,856'12'Blga/Upr Ty 7/26/21 Open LB4C 7,158'7,164'6,907'6,913'6'Blga/Upr Ty 7/26/21 Open LB4C 7,164’7,170’6,913’6,919’6’Blga/Upr Ty 8/09/21 Open LB5A 7,282'7,300'7,029'7,047'18’Blga/Upr Ty 6/12/20 Open TY72-8 7,516'7,533'±7,260'±7,2'17'Blga/Upr Ty 7/26/21 Open TY73-2 7,595'7,606'7,336'7,347'11 Blga/Upr Ty 6/12/20 Open UT 1C 7,755'7,762'7,494'7,501'6 Blga/Upr Ty 6/12/20 Open TY84-6B 8,704'8,736'8,423'8,455'32 Blga/Upr Ty 6/10/20 Open D2 9,165'9,190'8,882'8,908'25 Tyonek 8/16/19 Open D3A 9,446'9,463'9,156'9,173'17 Tyonek 8/15/19 Open D3B 9,492'9,516'9,202'9,226'24 Tyonek 8/15/19 Open D4B 9,660'9,686'9,368'9,399'26 Tyonek 8/15/19 Open D4D 9,737'9,754'9,446'9,462'17 Tyonek 8/15/19 Open Z M M L L L L L L L L L L L L L L L L TY TY U TY D CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 109 / X-56 / Weld 16”Surf 120’ 10-3/4”Surface 45.5 /L-80 / TXP BTC 9.950”Surf 1,580’ 7-5/8"Intermediate 29.7 / L-80 / W563 6.875”Surf 5,973’ 4-1/2"Production 12.6 / L-80 / TXP BTC 3.958”Surf 10,206’ JEWELRY DETAIL No Depth Item 1 4,917’4-1/2” Swell Packer OPEN HOLE / CEMENT DETAIL 10-3/4”220 BBL’s of cement in 13.5” Hole. Returns to Surface (50% excess) 7-5/8" 9-7/8” Hole: 174bbls 12# class A lead cement pumped followed by 31bbls of 15.3# Class A tail cement. Full returns throughout job. 40bbls spacer ahead of cement. Trace spacer returned back to surface. 7/11/19 Radial CBL show’s ToC at ~1550’ MD 4-1/2” 6-3/4” Hole: 150bbls 12.5# lead cement pumped followed by 35.4bbls of 15.3# tail cement. 4.6bbl losses throughout job.7/30/19 Radial CBL show’s ToC at ~5030’ MD. Volumetrics suggest ToC could be as high as 3500’ MD. Light cement may be hard to pick up on CBL. Note: Comingled production from Tyonek and Beluga/Upper Tyonek pools. Requires a production log each calendar year, and not more than 13 months between logs per CO 510B:Lastt ran:: JJulyy 20222 _____________________________________________________________________________________ Updated by CAH 08-23-23 PROPOSED Kenai Gas Field Well: KU 24-05B PTD: 219-072 API: 50-133-20683-00-00 PERFORATION DETAIL Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Pool Date Status MB8 6,208'6,219'5,976'5,987'11'Blga/Upr Ty 8/25/21 Open MB9 6,309'6,317'6,075'6,083'8'Blga/Upr Ty 8/25/21 Open LB1X 6,331'6,338'6,096'6,103'7'Blga/Upr Ty 8/25/21 Open LB1B 6,403'6,415'6,167'6,179'12'Blga/Upr Ty 8/25/21 Open LB1D 6,522'6,532'6,284'6,294'10'Blga/Upr Ty 8/25/21 Open LB1E 6,539'6,544'6,300'6,305'5'Blga/Upr Ty 8/25/21 Open LB1F 6,567’6,581’6,327’6,341’14 Blga/Upr Ty 11/12/20 Open LB1F 6,604’6,618’6,364’6,378’14 Blga/Upr Ty 11/12/20 Open LB2C 6,734’6,739’6,491’6,496’5 Blga/Upr Ty 11/12/20 Open LB2C 6,761’6,772’6,517’6,528’11 Blga/Upr Ty 11/12/20 Open LB2D 6,780’6,790’6,536’6,546’10 Blga/Upr Ty 11/11/20 Open LB2E 6,829’6,834’6,584’6,589’5 Blga/Upr Ty 11/11/20 Open LB2E 6,861'6,867'6,614'6,620'6'Blga/Upr Ty 8/25/21 Open LB3C 7,001’7,022’6,752’6,773’21 Blga/Upr Ty 11/11/20 Open LB4 7,068’7,075’6,819'6,826'7’Blga/Upr Ty 8/09/21 Open LB4 7,083’7,087’6,834'6,838'4’Blga/Upr Ty 8/09/21 Open LB4A 7,094'7,106'6,844'6,856'12'Blga/Upr Ty 7/26/21 Open LB4C 7,158'7,164'6,907'6,913'6'Blga/Upr Ty 7/26/21 Open LB4C 7,164’7,170’6,913’6,919’6’Blga/Upr Ty 8/09/21 Open LB5A 7,282'7,300'7,029'7,047'18’Blga/Upr Ty 6/12/20 Open TY72-8 7,516'7,533'±7,260'±7,2'17'Blga/Upr Ty 7/26/21 Open TY73-2 7,595'7,606'7,336'7,347'11 Blga/Upr Ty 6/12/20 Open UT 1C 7,755'7,762'7,494'7,501'6 Blga/Upr Ty 6/12/20 Open TY84-6B 8,704'8,736'8,423'8,455'32 Blga/Upr Ty 6/10/20 Open D1 ±8,999’±9,125’±8,714’±8,838’±126 Blga/Upr Ty TBD Proposed D2 9,165'9,190'8,882'8,908'25 Tyonek 8/16/19 Isolated D3A 9,446'9,463'9,156'9,173'17 Tyonek 8/15/19 Isolated D3B 9,492'9,516'9,202'9,226'24 Tyonek 8/15/19 Isolated D4B 9,660'9,686'9,368'9,399'26 Tyonek 8/15/19 Isolated D4D 9,737'9,754'9,446'9,462'17 Tyonek 8/15/19 Isolated Z M M L L L L L L L L L L L L L L L L TY TY U TY D CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 109 / X-56 / Weld 16”Surf 120’ 10-3/4”Surface 45.5 /L-80 / TXP BTC 9.950”Surf 1,580’ 7-5/8"Intermediate 29.7 / L-80 / W563 6.875”Surf 5,973’ 4-1/2"Production 12.6 / L-80 / TXP BTC 3.958”Surf 10,206’ JEWELRY DETAIL No Depth Item 1 4,917’4-1/2” Swell Packer 2 9,155’CIBP w/ 25ft of cement OPEN HOLE / CEMENT DETAIL 10-3/4”220 BBL’s of cement in 13.5” Hole. Returns to Surface (50% excess) 7-5/8" 9-7/8” Hole: 174bbls 12# class A lead cement pumped followed by 31bbls of 15.3# Class A tail cement. Full returns throughout job. 40bbls spacer ahead of cement. Trace spacer returned back to surface. 7/11/19 Radial CBL show’s ToC at ~1550’ MD 4-1/2” 6-3/4” Hole: 150bbls 12.5# lead cement pumped followed by 35.4bbls of 15.3# tail cement. 4.6bbl losses throughout job.7/30/19 Radial CBL show’s ToC at ~5030’ MD. Volumetrics suggest ToC could be as high as 3500’ MD. Light cement may be hard to pick up on CBL. STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 09/02/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20220902 Well API #PTD #Log Date Log Company Log Type Notes AOGCC Eset # END 3-11 50029218480000 188087 8/1/2022 Halliburton CALIPER + Report KALOTSA 4 50133206650000 217063 7/18/2022 Halliburton PPROF + Processing KBU 22-06Y 50133206500000 215044 7/14/2022 Halliburton PPROF + Processing KTU 24-06H 50133204900000 199073 7/21/2022 Halliburton PPROF + Processing KU 24-05B 50133206830000 219072 7/20/2022 Halliburton PPROF + Processing MPU C-24A 50029230200100 209134 7/28/2022 Halliburton COIL FLAG MPU I-17 50029232120000 204098 7/19/2022 Halliburton FREEPOINT NS-10 50029229850000 200182 7/23/2022 Halliburton CALIPER + Report NS-32 50029231790000 203158 7/24/2022 Halliburton CALIPER + Report PBU 18-02C 50029207620300 213009 7/14/2022 Halliburton CAST/CBL PBU C-10B 50029203710200 211092 7/15/2022 Halliburton PPROF + Processing PBU L5-03 50029236230000 219033 7/25/2022 Halliburton PPROF + Processing Please include current contact information if different from above. T36973 T36974 T36975 T36976 T36977 T36978 T36979 T36980 T36981 T36982 T36983 T36984 KU 24-05B 50133206830000 219072 7/20/2022 Halliburton PPROF + Processing Kayla Junke Digitally signed by Kayla Junke Date: 2022.09.07 11:00:16 -08'00' Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 10/27/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 24-05B (PTD 219-072) Perf 08/22/2021 Please include current contact information if different from above. 11/02/2021 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: N2 / Patch 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 10,210 feet N/A feet true vertical 9,914 feet N/A feet Effective Depth measured 10,120 feet 4,917 feet true vertical 9,825 feet 4,918 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)N/A N/A N/A N/A Packers and SSSV (type, measured and true vertical depth)Swell Pkr; N/A 4,917' MD 4,918' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Ryan Rupert Authorized Title:Operations Manager Contact Email: Contact Phone:777-8503 WINJ WAG 961 Water-Bbl MD 120' 1,580' 0 Oil-Bbl measured true vertical Packer 4-1/2"10,206' 5,744' 9,908' measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Kenai Gas Field / Tyonek Gas Pool 1 & Beluga/Upper Tyonek Gas PoolN/A measured TVD Tubing Pressure 730 Kenai Unit (KU) 24-05B N/A FEE A028142 5,973' Plugs Junk STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-072 50-133-20683-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-347 82 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 10 Authorized Signature with date: Authorized Name: 8 Casing Pressure Liner 1,247 0 Representative Daily Average Production or Injection Data 120' 1,580' 5,973' 10,206' Conductor Surface Intermediate Production 7,500psi Casing Structural 16" 10-3/4" 7-5/8" Length 6,890psi 5,210psi Collapse 2,470psi 4,790psi ryan.rupert@hilcorp.com Senior Engineer:Senior Res. Engineer: Burst 8,430psi 120' 1,550' t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.09.10 14:05:35 -08'00' Taylor Wellman (2143) By Meredith Guhl at 8:13 am, Sep 13, 2021 RBDMS HEW 9/13/2021 SFD 9/20/2021DSR-9/13/21BJM 11/2/21 Rig Start Date End Date 7/26/21 8/22/21 07/29/2021 - Thursday Arrive @ gas plant. Sign permits & JSA. Continue to location. RU SL unit. PT SL PCE to 250 psi low and 2,500 psi. High. TP - 100 psi. Can't RIH. Close swab valve. Bleed off lubricator. Pull lubricator off @ tool trap. Adjust tool trap spring & arm. RIH w/ 10' 1-7/8" weight bar / 1-7/8" jars / 1-7/8" long spangs / 3.71" gauge ring. Tag @ 8,720'. Work tools. Continue RIH. Tag @ 9,455'. Work tools. Continue RIH. Tag @ 9,746'. Work tools. Continue RIH. Tag @ 9,981.8' RKB. POOH. Pull over 400lbs. Work tools. Pull heavy for 200'. Continue POOH. RIH w/ 10' 1-7/8" weight bar / 1-7/8" long spangs / PL tools. Log up 1st pass 9,780' to 6,500'. Log down 2nd pass 6,500' to 9,780'. Log up 3rd pass 9,780' to 6,500'. Log down 4th pass 6,500' to 9,780'. Log up 5th pass 9,780' to 6,500'. Log down 6th pass 6,500' to 9,780'. (17:08) 1st stationary stop @ 9,780'. (17:37) 2nd stationary stop @ 8,950'. (18:08) 3rd stationary stop @ 6,500'. POOH. DL PL tools. Data Good. Rig down SL. Pick up barrels and return to base. 07/26/2021 - Monday Sign in. Mobe to location. PTW and JSA. Spot equipment and rig up lubricator. Start PT, ad a o-ring failure. Replaced O- ring, PT to 250 psi low and 2,500 psi high. Arm gun. RIH w/ 2-7/8" x 17' (TY-72-8) gas gun HC, 6 spf, 60 deg phase and tie into OHL. Send log to town. Told to add 3' to log. Added 3' and spotted and fired gun from 7,516' to 7,533' w/77psi FTP/944K. After 5 min - 78 psi/974K, 10 min - 78 psi- 983K and 15 min - 77 psi/952K. RIH w/two guns on switches. 2 guns to be fired is 2-7/8” x 12’ (LB4C) HC gas gun, 6 spf,60 deg phase, switch 3d gun is 2-7/8” x 6’ (LB4A) HC gas gun, 6 spf, 60 deg phase and tie in to OHL. Ran correlation log that covered both zones LB4C – 7,158’ to 7,170’ and 7,094’ to 7,100’ and send to town. Told to add 5’ and that would be good for both zones. Added 5’ and spotted 2d gun LB4C with top shot at 7158' and fired gun. After 5 min – 74.3 psi/970K, 10 min – 74.3 psi/976K and 15 min – 74.3 psi/971K. Pull up and spotted gun 3. LB4A with top shot at 7,094’. Fired gun w/74 psi/967.5K. After 5 min – 74 psi/985K, 10 min – 73.5 psi/962K and 15 min – 73 psi/943K. POOH, all shots fired/gun wet. Upon reviewing gun at surface, realized that BHA was made up out of order. Top shot of 6' gun was at 7,158' MD and top shot of 12' gun at 7,094' MD. Actual depths perf'd were LB4C from 7,158'-7,164' (6') and LB4A from 7,094'-7,106' MD. Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 24-05B 50-133-20683-00-00 219-072 fired gun from 7,516' to 7,533' Actual depths perf'd were LB4C from 7,158'-7,164' (6') and LB4A from 7,094'-7,106' MD. Rig Start Date End Date 7/26/21 8/22/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 24-05B 50-133-20683-00-00 219-072 Sign in. Mobe to location. Spot equipment. PTW and JSA. Rig up lubricator. PT to 250 psi low and 2,500 psi high. 76 psi/1mm. RIH w/ 2-7/8" x 6' HC, gas gun, 6 spf, 60 deg phase and tie into perf log dated 7-26-21. Run correlation log and send to town. Town said to add 5' to log. Added 5' and spotted gun from 7,164' to 7,170' w/78 psi and 999K Rate. Fired gun. After 5 min - 79 psi/1036 mcf. After 10 min - 77 psi /964K and 15 min - 77psi/974K. All shots fired/Gun Wet. RIH w/ 2-7/8" x7' (Gun #3, 7,068' to 7,075') HC, 6 spf, 60 deg phase , switches, 2-7/8" x 4' (#2 gun, 7,083' to 7,087') HC, 6 spf, 60 deg phase and tie into perf log. Run correlation log and send to town. Get ok to shoot both guns. Spot and fire gun #2 from 7,083' to 7,087' w/78psi/ 1,062 mcf, 5 min - 79psi/ 1,067 mcf,10 min - 78 psi/ 1,064 mcf and 15 min - 78/ 1,074 mcf. Pull up to Gun #3. Spotted and fired Gun #3 from 7,068' to 7,075'. Didn't act like it fired. POOH. and both guns didn't fire. Called gun loader out and he found a bad ground wire on switch. Replace all components. RIH w/ 2-7/8" x7' (Gun #3, 7,068' to 7,075') HC, 6 spf, 60 deg phase , switches, 2-7/8" x 4' (#2 gun, 7,083' to 7,087') HC, 6 spf, 60 deg phase and tie into perf log. Run correlation log and send to town. Get ok to shoot both guns. Spot and fire gun #2 from 7,083' to 7,087' w/76.8 psi/ 1,104.8 mcf, 5 min - 77.3 psi/ 1,112mcf, 10 min - 77.5 psi/ 1,101 mcf. and 15 min - 15 min - 77.9 psi/ 1,092 mcf. Spotted and fired Gun #3 from 7,068' to 7,075' w/78.25 psi/ 1,088.49 mcf, 5 min - 79.2psi/ 1,102 mcf, 10 min - 77.7 psi/ 1,073.1mcf and 15 min - 76.9 psi/ 1,078.8mcf. POOH. All shots fired on both guns (2 & 3)/Both guns wet. Rig down lubricator and equipment. Clean up work area. Turn well over to field. 08/22/2021 - Sunday Spot equipment. PTW and JSA. Rig up lubricator PT 250 psi low and 2,500 psi high. Well flowing 71 psi/1 mil. RIH w/#1 gun, 2-7/8" x 6' gas HC, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Told to add 1'. Added 1' spot and fire gun from 6,861' to 6,867' w71.8/1.036 mill. After 5 min -78.2/1.230 mil, 10 min - 79.3/1.291 mil and 15 min - 78.6/1.272 mil. Pull up to 6,690' and logged 6,340'. Send log in to town. Told to add 1 fi'. Spot #2 gun from 6,539' to 6,544' (LB1E). Fired gun with 78.5 psi/1.272mil. After. 5 min - 77.9/1.259 mil, 10 min - 77.9/1.250mil, and 15 min - 77.7/1.247mill. Spot Gun #3 from 6,522' to 6,532' and fire gun w/77.6/1.243. After 5 min - 85/1.467 mil, 10 min- 83.6/1,422mil and 15 min - 83.6/1. POOH. All three guns fired/Guns wet. RIH w/2 gas guns w/switches. Gun #4, 2-7/8" x 12' HC, 6 spf,60 deg phase (LB1B) and Gun #5, 2-7/8" x 7' HC, 6 spf, 60 deg phase (LB1X). Run correlation log and send to town. Get ok to perf both 4 and 5 gun. Spot and fire Gun #4 (LB1B) w/ 87.7/1.557mil from 6,403' to 6,415'. After 5 min - 88.s/1.568 mil, 10 min - 87.7/1.550 mil and 15 min - 87.5/1.544 mil. Run up hole and spot Gun #5. Shot LB1X from 6,331- 6,338 (7'). Fired gun with 87.7/1.542 mil. After 5 min 85/1.499 mil, 10 min - 84.4/1.448 and 15 min - 84.2/1.446mil. POOH. All shots fired and gun was wet. RIH w/2 gas guns w/switches. Gun #6, 2-7/8" x 8' HC, 6 spf,60 deg phase (MB 9) and Gun #7, 2-7/8" x 11' HC, 6 spf, 60 deg phase (MB 8). Run correlation log and send to town. Get ok to perf both zones. Spotted and shot gun #6 6,309' to 6,317' w/87.4/1.525 mil. After 5 min- 87.1/1.519 mil, 10 min - 87/1.510 mil and 15 min - 87/1.508Mil. Pull up to MB 8 sand Gun #7. Spot and fire from 6,208' to 6,219' w/87/1.509. After 5 min -. 85.1/1.485mil, 10 min - 84.2/1.441mil and 15 min - 84/1.430. POOH. All shots fired/gun wet. Rig down lubricator and equip and turn well back over to field. 08/09/2021 - Monday shot gun #6 6,309' to 6,317' w fire gun from 6,861' to 6,867' 6,522' to 6,532' and fire gun w Spot and fire Gun #4 (LB1B) w/ 87.7/1.557mil from 6,403' to 6,415'. Spotted and fired Gun #3 from 7,068' to 7,075' Shot LB1X from 6,331- 6,338 (7'). Fired gun w Spot and fire gun #2 from 7,083' to 7,087' w fire from 6,208' to 6,219' Spot #2 gun from 6,539' to 6,544' (LB1E). Fired gun w gun from 7,164' to 7,170' _____________________________________________________________________________________ Updated by DMA 08-27-21 SCHEMATIC Kenai Gas Field Well: KU 24-05B PTD: 219-072 API: 50-133-20683-00-00 PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Pool Date Status MB8 6,208' 6,219' 5,976' 5,987' 11' Blga/Upr Ty 8/25/21 Open MB9 6,309' 6,317' 6,075' 6,083' 8' Blga/Upr Ty 8/25/21 Open LB1X 6,331' 6,338' 6,096' 6,103' 7' Blga/Upr Ty 8/25/21 Open LB1B 6,403' 6,415' 6,167' 6,179' 12' Blga/Upr Ty 8/25/21 Open LB1D 6,522' 6,532' 6,284' 6,294' 10' Blga/Upr Ty 8/25/21 Open LB1E 6,539' 6,544' 6,300' 6,305' 5' Blga/Upr Ty 8/25/21 Open LB1F 6,567’ 6,581’ 6,327’ 6,341’ 14 Blga/Upr Ty 11/12/20 Open LB1F 6,604’ 6,618’ 6,364’ 6,378’ 14 Blga/Upr Ty 11/12/20 Open LB2C 6,734’ 6,739’ 6,491’ 6,496’ 5 Blga/Upr Ty 11/12/20 Open LB2C 6,761’ 6,772’ 6,517’ 6,528’ 11 Blga/Upr Ty 11/12/20 Open LB2D 6,780’ 6,790’ 6,536’ 6,546’ 10 Blga/Upr Ty 11/11/20 Open LB2E 6,829’ 6,834’ 6,584’ 6,589’ 5 Blga/Upr Ty 11/11/20 Open LB2E 6,861' 6,867' 6,614' 6,620' 6' Blga/Upr Ty 8/25/21 Open LB3C 7,001’ 7,022’ 6,752’ 6,773’ 21 Blga/Upr Ty 11/11/20 Open LB4 7,068’ 7,075’ 6,819' 6,826' 7’ Blga/Upr Ty 8/09/21 Open LB4 7,083’ 7,087’ 6,834' 6,838' 4’ Blga/Upr Ty 8/09/21 Open LB4A 7,094' 7,106' 6,844' 6,856' 12' Blga/Upr Ty 7/26/21 Open LB4C 7,158' 7,164' 6,907' 6,913' 6' Blga/Upr Ty 7/26/21 Open LB4C 7,164’ 7,170’ 6,913’ 6,919’ 6’ Blga/Upr Ty 8/09/21 Open LB5A 7,282' 7,300' 7,029' 7,047' 18’ Blga/Upr Ty 6/12/20 Open TY72-8 7,516' 7,533' ±7,260' ±7,2' 17' Blga/Upr Ty 7/26/21 Open TY73-2 7,595' 7,606' 7,336' 7,347' 11 Blga/Upr Ty 6/12/20 Open UT 1C 7,755' 7,762' 7,494' 7,501' 6 Blga/Upr Ty 6/12/20 Open TY84-6B 8,704' 8,736' 8,423' 8,455' 32 Blga/Upr Ty 6/10/20 Open D2 9,165' 9,190' 8,882' 8,908' 25 Tyonek 8/16/19 Open D3A 9,446' 9,463' 9,156' 9,173' 17 Tyonek 8/15/19 Open D3B 9,492' 9,516' 9,202' 9,226' 24 Tyonek 8/15/19 Open D4B 9,660' 9,686' 9,368' 9,399' 26 Tyonek 8/15/19 Open D4D 9,737' 9,754' 9,446' 9,462' 17 Tyonek 8/15/19 Open Z M M L L L L L L L L L L L L L L L L TY TY U TY D CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 109 / X-56 / Weld 16” Surf 120’ 10-3/4” Surface 45.5 /L-80 / TXP BTC 9.950” Surf 1,580’ 7-5/8" Intermediate 29.7 / L-80 / W563 6.875” Surf 5,973’ 4-1/2" Production 12.6 / L-80 / TXP BTC 3.958” Surf 10,206’ JEWELRY DETAIL No Depth Item 1 4,917’ 4-1/2” Swell Packer OPEN HOLE / CEMENT DETAIL 10-3/4” 220 BBL’s of cement in 13.5” Hole. Returns to Surface (50% excess) 7-5/8" 9-7/8” Hole: 174bbls 12# class A lead cement pumped followed by 31bbls of 15.3# Class A tail cement. Full returns throughout job. 40bbls spacer ahead of cement. Trace spacer returned back to surface. 7/11/19 Radial CBL show’s ToC at ~1550’ MD 4-1/2” 6-3/4” Hole: 150bbls 12.5# lead cement pumped followed by 35.4bbls of 15.3# tail cement. 4.6bbl losses throughout job. 7/30/19 Radial CBL show’s ToC at ~5030’ MD. Volumetrics suggest ToC could be as high as 3500’ MD. Light cement may be hard to pick up on CBL. Note: Comingled production from Tyonek and Beluga/Upper Tyonek pools. Requires a production log each calendar year, and not more than 13 months between logs per CO 510B: Last ran: 7/4/20 LB4 7,068’ 7,075’6,819'6,826'7’Blga/Upr Ty 8/09/21 Open LB4 7,083’ 7,087’6,834'6,838'4’Blga/Upr Ty 8/09/21 Open LB4A 7,094' 7,106'6,844'6,856'12' Blga/Upr Ty 7/26/21 Open LB4C 7,158' 7,164'6,907'6,913'6'Blga/Upr Ty 7/26/21 Open LB4C 7,164’ 7,170’6,913’6,919’6’Blga/Upr Ty 8/09/21 Open L L L ,,,,g/p y //p LB2E 6,861' 6,867'6,614'6,620'6'Blga/Upr Ty 8/25/21 Open L TY72-8 7,516' 7,533'±7,260'±7,2'17'Blga/Upr Ty 7/26/21 Open TY MB8 6,208'6,219'5,976'5,987'11'Blga/Upr Ty 8/25/21 Open MB9 6,309'6,317'6,075'6,083'8'Blga/Upr Ty 8/25/21 Open LB1X 6,331'6,338'6,096'6,103'7'Blga/Upr Ty 8/25/21 Open LB1B 6,403'6,415'6,167'6,179'12'Blga/Upr Ty 8/25/21 Open LB1D 6,522'6,532'6,284'6,294'10'Blga/Upr Ty 8/25/21 Open LB1E 6,539'6,544'6,300'6,305'5'Blga/Upr Ty 8/25/21 Open MMM M L L L L p( )()p( )() David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-5245 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt and return one copy of this transmittal. Received By: Date: Hilcorp North Slope, LLC Date: 08/25/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL: KU 24-05 Completion Record Perf (PTD 219-072) FTP Folder Contents: Log Print Files and LAS Data Files: Please include current contact information if different from above. 37' (6HW Received By: 08/30/2021 By Abby Bell at 3:29 pm, Aug 25, 2021 David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422 Received By: Date: DATE: 08/10/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 24-05B (PTD 219-072) Production Profile 07/29/2021 Please include current contact information if different from above. 37' (6HW eceived By: 08/10/2021 By Abby Bell at 3:53 pm, Aug 10, 2021 David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-5245 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt and return one copy of this transmittal. Received By: Date: Hilcorp North Slope, LLC Date: 08/05/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL KU 24-05B (PTD 219-072) FTP Folder Contents: Log Print Files and LAS Data Files: Please include current contact information if different from above. eceived By: 08/05/2021 37' (6HW By Abby Bell at 12:59 pm, Aug 05, 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: ____N2 / Patch_______ 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): 10,210'N/A Casing Collapse Structural Conductor Surface 2,470 psi Intermediate 4,790 psi Production 7,500 psi 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: Ryan Rupert Operations Manager Contact Email: Contact Phone: 777-8503 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 ryan.rupert@hilcorp.com 9,914'10,120'9,825'~1357 psi N/A Swell Pkr; N/A 4,917' MD / 4,718' TVD; N/A Perforation Depth TVD (ft):Tubing Size: COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEE A028142 219-072 50-133-20683-00-00 KU 24-05B Kenai Gas Field / Tyonek Gas Pool 1 and Beluga/Upper Tyonek gas Pool Length Size CO 510B Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY N/A TVD Burst N/A 8,430 psi MD 6,890 psi 5,210 psi 120' 1,550' 5,744' 120' 1,580' 9,908'4-1/2" 16" 10-3/4" 120' 7-5/8"5,973' 1,580' 10,206' Perforation Depth MD (ft): 5,973' See Attached Schematic 10,206' 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: July 27, 2021 N/A m n P 66 t _ c Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 8:21 am, Jul 13, 2021 321-347 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.07.12 22:27:30 -08'00' Taylor Wellman (2143) BJM 7/21/21 DSR-7/13/21 10-404X DLB 07/13/2021 dts 7/22/2021 JLC 7/22/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.07.22 10:58:07 -08'00' RBDMS HEW 7/22/2021 Well Name:KU 24-05B API Number:50-133-20683-00-00 Current Status:Flowing Gas Well Leg:N/A Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:219-072 First Call Engineer:Ryan Rupert (907) 777 8503 (O)(907) 301-1736 (C) Second Call Engineer:Ted Kramer (907) 777-8420 (O)(985) 867-0665 (C) Max. Expected BHP:~ 1,973 psi @ 6,167’ TVD 2017 RFT data from offset well KU 14-05 in LB-1B sand Max. Potential Surface Pressure:~ 1357 psi Using 0.10psi/ft gas gradient to surface Well Summary: KU 04-05B has existing comingled production between the Tyonek and Beluga/Upper Tyonek pools. Perfs are proposed below to increase production from the well. All perfs proposed below fall within the Beluga/Upper Tyonek pool. This pool is currently open in the well, along with the Tyonek pool below. As part of the comingling agreement (CO 510B), an initial production log was obtained 7/4/20. A follow up production log must be obtained no later than 8/4/21, and data reported to state no later than 30 days after acquisition. The production log may be ran before or after these perfs, depending on timing. TBD. The well is currently making 1000 mcf and no water. The objective of this work is to add production to the well from the Beluga/Upper Tyonek pool. Notes: -Min ID: 3.833” (drift diameter of 4-1/2” tubing) -Max inclination: 20 degrees at 4734’ MD -Drifts o 11/12/20: EL perf’d 7 intervals with 2-7/8” guns while well was flowing. Didn’t go below 7021’ MD. No issued o 7/4/20: HAL production log. Stopped at 9780’ MD. No tag o 6/10/20: Pulled up 26’ and got stuck after shooting 8704’ – 8734’ MD. Ended up pulling free from ropesocket, and left fish downhole. SL successfully fished tool from 8687’ MD the next day. They made it down to 8720’ MD with a 3.85” gauge ring, but couldn’t get any deeper (had to jar loose). The gun run on 6/13/20 also stuck briefly, but came free.No need to go below 8000’ MD for this job. Safety Concerns x Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect, and people could enter. x Consider tank placement based on wind direction and current weather forecast (venting nitrogen during this job). x Ensure all crews are aware of stop job authority. an initial production log was obtained 7/4/20. A follow up production log must be obtained no later than 8/4/21, E-Line Procedure 1. MIRU E-Line and pressure control equipment. 2. PT lubricator to 250 psi Low / 2,500 psi High. 3. Rig up perf gun (Likely 2-7/8” 4-6 spf) 4. RIH and perforate the sand listed in the table below, per Geo/RE. Sand Top (MD)Btm (MD)Top (TVD)Btm (TVD)FT MB 8 ±6,208'±6,219'±5,976'±5,987'11' MB 9 ±6,309'±6,317'±6,075'±6,083'8' LB1X ±6,331'±6,338'±6,096'±6,103'7' LB1B ±6,403'±6,415'±6,167'±6,179'12' LB1D ±6,522'±6,532'±6,284'±6,294'10' LB1E ±6,539'±6,544'±6,300'±6,305'5' LB1F ±6,567'±6,582'±6,327'±6,342'15' LB2E ±6,861'±6,867'±6,614'±6,620'6' LB4 ±7,068'±7,075'±6,819'±6,826'7' LB4 ±7,083'±7,087'±6,834'±6,838'4' LB4A ±7,094'±7,100'±6,844'±6,850'6' LB4C ±7,158'±7,170'±6,907'±6,919'12' TY_72_8 ±7,516'±7,533'±7,260'±7,277'17' Consult with OE for what WHP to use. May be shot while flowing or SI. TBD Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. a.Use Gamma/CCL to correlate. b. Record initial and 5/10/15 minute tubing pressures after firing c. Consult with RE/Geo between each perf interval: a. Trudi Hallett (RE): 301-6657 b. Ben Siks (Geo): 229-0865 d.All perforations in table above are located in the Beluga/UpperTyonek Gas Pool based on Conservation Order No. 510B. 5. RD E-Line Unit and turn well over to production. Contingency EL Plug or Patch 1. MIRU E-line, PT lubricator to 250 psi low / 3,500 psi high 2. RIH W/ GPT tool and find fluid level 3. RU Nitrogen Truck a. Push water back into formation b. Use GPT tool to confirm water level is below interval to perf c. Consult OE for pressure to leave on well for perforating 4. Once fluid level is below interval to isolate, MU 4-1/2” patch or plug 5. RIH and set plug or patch per OE. 6. RD E-Line Unit and turn well over to production. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Standard Well Procedure – N2 Operations _____________________________________________________________________________________ Updated by CRR 7-9-21 SCHEMATIC Kenai Gas Field Well:KU 24-05B PTD:219-072 API: 50-133-20683-00-00 PERFORATION DETAIL Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Pool Date Status LB 1F 6,567’6,581’6,327’6,341’14 Blga/Upr Ty 11/12/20 Open LB 1F 6,604’6,618’6,364’6,378’14 Blga/Upr Ty 11/12/20 Open LB 2C 6,734’6,739’6,491’6,496’5 Blga/Upr Ty 11/12/20 Open LB 2C 6,761’6,772’6,517’6,528’11 Blga/Upr Ty 11/12/20 Open LB 2D 6,780’6,790’6,536’6,546’10 Blga/Upr Ty 11/11/20 Open LB 2E 6,829’6,834’6,584’6,589’5 Blga/Upr Ty 11/11/20 Open LB 3C 7,001’7,022’6,752’6,773’21 Blga/Upr Ty 11/11/20 Open LB_5A 7,282'7,300'7,029'7,047'18 Blga/Upr Ty 6/12/20 Open TY 73_2 7,595'7,606'7,336'7,347'11 Blga/Upr Ty 6/12/20 Open UT 1C 7,755'7,762'7,494'7,501'6 Blga/Upr Ty 6/12/20 Open TY 84_6B 8,704'8,736'8,423'8,455'32 Blga/Upr Ty 6/10/20 Open D2 9,165'9,190'8,882'8,908'25 Tyonek 8/16/19 Open D3A 9,446'9,463'9,156'9,173'17 Tyonek 8/15/19 Open D3B 9,492'9,516'9,202'9,226'24 Tyonek 8/15/19 Open D4B 9,660'9,686'9,368'9,399'26 Tyonek 8/15/19 Open D4D 9,737'9,754'9,446'9,462'17 Tyonek 8/15/19 Open Z L L L L L L L LB TY U TY D CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 109 / X-56 / Weld 16”Surf 120’ 10-3/4”Surface 45.5 /L-80 / TXP BTC 9.950”Surf 1,580’ 7-5/8"Intermediate 29.7 / L-80 / W563 6.875”Surf 5,973’ 4-1/2"Production 12.6 / L-80 / TXP BTC 3.958”Surf 10,206’ JEWELRY DETAIL No Depth Item 1 4,917’4-1/2” Swell Packer OPEN HOLE / CEMENT DETAIL 10-3/4”220 BBL’s of cement in 13.5” Hole. Returns to Surface (50% excess) 7-5/8" 9-7/8” Hole: 174bbls 12# class A lead cement pumped followed by 31bbls of 15.3# Class A tail cement. Full returns throughout job. 40bbls spacer ahead of cement. Trace spacer returned back to surface.7/11/19 Radial CBL show’s ToC at ~1550’ MD 4-1/2” 6-3/4” Hole: 150bbls 12.5# lead cement pumped followed by 35.4bbls of 15.3# tail cement. 4.6bbl losses throughout job.7/30/19 Radial CBL show’s ToC at ~5030’ MD.Volumetrics suggest ToC could be as high as 3500’ MD. Light cement may be hard to pick up on CBL. Note: Comingled production from Tyonek and Beluga/Upper Tyonek pools. Requires a production log each calendar year, and not more than 13 months between logs per CO 510B: Last ran: 7/4/20 _____________________________________________________________________________________ Updated by CRR 7-9-21 PROPOSED SCHEMATIC Kenai Gas Field Well:KU 24-05B PTD:219-072 API: 50-133-20683-00-00 PERFORATION DETAIL Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Pool Date Status MB 8 ±6,208'±6,219'±5,976'±5,987'11'Blga/Upr Ty TBD Proposed MB 9 ±6,309'±6,317'±6,075'±6,083'8'Blga/Upr Ty TBD Proposed LB1X ±6,331'±6,338'±6,096'±6,103'7'Blga/Upr Ty TBD Proposed LB1B ±6,403'±6,415'±6,167'±6,179'12'Blga/Upr Ty TBD Proposed LB1D ±6,522'±6,532'±6,284'±6,294'10'Blga/Upr Ty TBD Proposed LB1E ±6,539'±6,544'±6,300'±6,305'5'Blga/Upr Ty TBD Proposed LB 1F 6,567’6,581’6,327’6,341’14 Blga/Upr Ty 11/12/20 Open LB 1F 6,604’6,618’6,364’6,378’14 Blga/Upr Ty 11/12/20 Open LB 2C 6,734’6,739’6,491’6,496’5 Blga/Upr Ty 11/12/20 Open LB 2C 6,761’6,772’6,517’6,528’11 Blga/Upr Ty 11/12/20 Open LB 2D 6,780’6,790’6,536’6,546’10 Blga/Upr Ty 11/11/20 Open LB 2E 6,829’6,834’6,584’6,589’5 Blga/Upr Ty 11/11/20 Open LB2E ±6,861'±6,867'±6,614'±6,620'6'Blga/Upr Ty TBD Proposed LB 3C 7,001’7,022’6,752’6,773’21 Blga/Upr Ty 11/11/20 Open LB4 ±7,068'±7,075'±6,819'±6,826'7'Blga/Upr Ty TBD Proposed LB4 ±7,083'±7,087'±6,834'±6,838'4'Blga/Upr Ty TBD Proposed LB4A ±7,094'±7,100'±6,844'±6,850'6'Blga/Upr Ty TBD Proposed LB4C ±7,158'±7,170'±6,907'±6,919'12'Blga/Upr Ty TBD Proposed LB_5A 7,282'7,300'7,029'7,047'18 Blga/Upr Ty 6/12/20 Open TY_72_8 ±7,516'±7,533'±7,260'±7,277'17'Blga/Upr Ty TBD Proposed TY 73_2 7,595'7,606'7,336'7,347'11 Blga/Upr Ty 6/12/20 Open UT 1C 7,755'7,762'7,494'7,501'6 Blga/Upr Ty 6/12/20 Open TY 84_6B 8,704'8,736'8,423'8,455'32 Blga/Upr Ty 6/10/20 Open D2 9,165'9,190'8,882'8,908'25 Tyonek 8/16/19 Open D3A 9,446'9,463'9,156'9,173'17 Tyonek 8/15/19 Open D3B 9,492'9,516'9,202'9,226'24 Tyonek 8/15/19 Open D4B 9,660'9,686'9,368'9,399'26 Tyonek 8/15/19 Open D4D 9,737'9,754'9,446'9,462'17 Tyonek 8/15/19 Open Z M M L L L L L L L L L L L L L L LB TY_ TY U TY D CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16"Conductor 109 / X-56 / Weld 16”Surf 120’ 10-3/4”Surface 45.5 /L-80 / TXP BTC 9.950”Surf 1,580’ 7-5/8"Intermediate 29.7 / L-80 / W563 6.875”Surf 5,973’ 4-1/2"Production 12.6 / L-80 / TXP BTC 3.958”Surf 10,206’ JEWELRY DETAIL No Depth Item 1 4,917’4-1/2” Swell Packer OPEN HOLE / CEMENT DETAIL 10-3/4”220 BBL’s of cement in 13.5” Hole. Returns to Surface (50% excess) 7-5/8" 9-7/8” Hole: 174bbls 12# class A lead cement pumped followed by 31bbls of 15.3# Class A tail cement. Full returns throughout job. 40bbls spacer ahead of cement. Trace spacer returned back to surface.7/11/19 Radial CBL show’s ToC at ~1550’ MD 4-1/2” 6-3/4” Hole: 150bbls 12.5# lead cement pumped followed by 35.4bbls of 15.3# tail cement. 4.6bbl losses throughout job.7/30/19 Radial CBL show’s ToC at ~5030’ MD.Volumetrics suggest ToC could be as high as 3500’ MD. Light cement may be hard to pick up on CBL. Note: Comingled production from Tyonek and Beluga/Upper Tyonek pools. Requires a production log each calendar year, and not more than 13 months between logs per CO 510B: Last ran: 7/4/20 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. 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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: 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): 10,210'N/A Casing Collapse Structural Conductor Surface 2,470 psi Intermediate 4,790 psi Production 7,500 psi 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 9,914'10,120'9,825'~ 2,735 psi N/A Swell Pkr; N/A 4,917' MD / 4,718' TVD; N/A Perforation Depth TVD (ft): Tubing Size: COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEE A028142 219-072 50-133-20683-00-00 Kenai Unit (KU) 24-05B Kenai Gas Field / Tyonek Gas Pool 1 Length Size CO 510A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY N/A TVD Burst N/A 8,430 psi MD 6,890 psi 5,210 psi 120' 1,550' 5,744' 120' 1,580' 9,908'4-1/2" 16" 10-3/4" 120' 7-5/8"5,973' 1,580' 10,206' Perforation Depth MD (ft): 5,973' See Attached Schematic 10,206' 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: 11/15/2020 N/A 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 10:37 am, Nov 04, 2020 320-468 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.11.03 15:02:44 -09'00' Taylor Wellman DSR-11/4/2020 displace 10-404 Alter Casing X GAS Downhole commingling authorized by CO 510A, production allocation must be done in accordance with Rule 5(b). DLB Other: N2 & Upper Tyonek/Beluga Perforate f DLB 11/04/2020 gls 11/6/20Comm. 11/6/2020 dts 11/6/2020 JLC 11/6/2020 RBDMS HEW 11/12/2020 Well Prognosis Well: KU 24-05B Date: 10/27/2020 Well Name: KU 24-05B API Number: 50-133-20683-00-00 Current Status: Producing Gas Well Leg: N/A Estimated Start Date: 11/15/2020 Rig: E-Line Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 219-072 First Call Engineer: Jake Flora (907) 777-8442 (720) 988-5375 (C) Second Call Engineer: Ted Kramer (907) 777-8420 (985) 867-0665 (C) AFE Number: Max Expected BHP (LB 3C): ~ 3038 psi @ 6752’ TVD Based on 0.45psi / ft gradient Max. Potential Surface Pressure: ~ 2735 psi BHP minus gas gradient (0.10psi/ft) Brief Well Summary KU 24-05B was drilled and completed in August 2019 as a 4-1/2” monobore targeting the Tyonek D sands. In June 2020, 3 Upper Tyonek and 1 Lower Beluga sand was added with no incremental rate add. The well is currently making right at 1 MMCFD. The purpose of this work/sundry is to add rate by perforating multiple intervals in the Lower Beluga sands and commingle the Upper Tyonek / Beluga Gas Pool with the Tyonek Gas Pool. Notes Regarding Wellbore Condition Max deviation is 19 deg @ 4734’ 6/13/2020 Perforated 7282-7300’ with 2-7/8” gun E-Line Procedure 1. MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 4,000 psi High. 2. RIH with GPT tool and find fluid level. If fluid is over the depth of the new perfs, discuss using Nitrogen to depress the fluid into the perfs with the Operations Engineer. 3. RU 2-7/8” perf guns. 4. With the well flowing RIH and perforate the following intervals from the bottom up: Zone Sand Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Middle Beluga MB 8 +6,208’ +6,219’ +5,976’ +5,987’ 11’ Lower Beluga LB 1B +6,403’ +6,415’ +6,166’ +6,178’ 12’ Lower Beluga LB 1D +6,522’ +6,532’ +6,283’ +6,293’ 10’ Lower Beluga LB 1E +6,539’ +6,544’ +6,299’ +6,304’ 5’ Lower Beluga LB 1F +6,567’ +6,582’ +6,327’ +6,342’ 15’ Lower Beluga LB 1F +6,604’ +6,618’ +6,364’ +6,378’ 14’ Lower Beluga LB 2C +6,734’ +6,739’ +6,491’ +6,496’ 5’ Lower Beluga LB 2C +6,761’ +6,772’ +6,517’ +6,528’ 11’ Lower Beluga LB 2D +6,780’ +6,790’ +6,536’ +6,546’ 10’ Lower Beluga LB 2E +6,829’ +6,834’ +6,584’ +6,589’ 5’ Lower Beluga LB 3C +7,001’ +7,022’ +6,752’ +6,773’ 21’ Downhole commingling authorized by CO 510A - DSR 11/4/2020 (N2 SOP review) Well Prognosis Well: KU 24-05B Date: 10/27/2020 a. Final Perf tie-in sheet will be provided in the field for exact perf intervals. b. Use GR/CCL to correlate against Open Hole Log provided by Geologist. Send the correlation pass to the following for confirmation. Reservoir Engineer Trudi Hallett 907.301.6657 Geologist Ben Siks 907.229.0865 c. All perforations in table above are located in the Upper Tyonek / Beluga Gas Pool based on Conservation Order 510A. d. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. e. Record 5, 10 and 15 minutes pressures after firing guns. 5. POOH. 6. RD E-Line. 7. Turn well over to production. (Test SSV with-in 5 days of stable production on well – notify AOGCC 24hrs before testing) Contingency if any zone produces sand or water 1. MIRU E-Line. 2. RIH and set 4-1/2” Casing Patch or set 4-1/2” CIBP above the zone and dump 35’ of cement on top of the plug. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Standard Well Procedure – N2 Operations _____________________________________________________________________________________ Updated by DMA 06-24-20 SCHEMATIC Kenai Gas Field Well: KU 24-05B PTD: 219-072 API: 50-133-20683-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 109 / X-56 / Weld 16” Surf 120’ 10-3/4” Surface 45.5 /L-80 / TXP BTC 9.950” Surf 1,580’ 7-5/8" Intermediate 29.7 / L-80 / W563 6.875” Surf 5,973’ 4-1/2" Production 12.6 / L-80 / TXP BTC 3.958” Surf 10,206’ JEWELRY DETAIL No Depth Item 1 4,917’ 4-1/2” Swell Packer OPEN HOLE / CEMENT DETAIL 10-3/4” 220 BBL’s of cement in 13.5” Hole. Returns to Surface (50% excess) 7-5/8" 205 BBL’s of cement in 9-7/8” Hole. Est TOC @ 1,550’ MD (0% excess) 4-1/2” 185 BBL’s of cement in 6-3/4” Hole. Est TOC @ 2,934’ (10% excess) PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status LB_5A 7,282' 7,300' 7,029' 7,047' 18 6/12/20 Open TY 73_2 7,595' 7,606' 7,336' 7,347' 11 6/12/20 Open UT 1C 7,755' 7,762' 7,494' 7,501' 6 6/12/20 Open TY 84_6B 8,704' 8,736' 8,423' 8,455' ±32 6/10/20 Open D2 9,165' 9,190' 8,882' 8,908' 25 8/16/19 Open D3A 9,446' 9,463' 9,156' 9,173' 17 8/15/19 Open D3B 9,492' 9,516' 9,202' 9,226' 24 8/15/19 Open D4B 9,660' 9,686' 9,368' 9,399' 26 8/15/19 Open D4D 9,737' 9,754' 9,446' 9,462' 17 8/15/19 Open swell packer _____________________________________________________________________________________ Updated by TRH 10-15-2020 Proposed Kenai Gas Field Well: KU 24-05B PTD: 219-072 API: 50-133-20683-00-00 TD =10,210’(MD) / 9,914’(TVD) 16” RKB: MSL = 18.6’ 4-1/2” 10-3/4” 7-5/8” 1 LB 5A TY 73_2 UT 1C TY 84_6B PBTD =10,120’(MD) / 9,825’(TVD) D2 D3A D3B D4B D4D MB 8 LB 1B LB 1D LB 1E LB 1F LB 1F LB 2C LB 2C LB 2D LB 2E LB 3C CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 109 / X-56 / Weld 16” Surf 120’ 10-3/4” Surface 45.5 /L-80 /TXP BTC 9.950” Surf 1,580’ 7-5/8" Intermediate 29.7 /L-80 / W563 6.875” Surf 5,973’ 4-1/2" Production 12.6 / L-80 / TXP BTC 3.958” Surf 10,206’ JEWELRY DETAIL No Depth Item 1 4,917’ 4-1/2” Swell Packer OPEN HOLE / CEMENT DETAIL 10-3/4” 220 BBL’s of cement in 13.5” Hole. Returns to Surface (50% excess) 7-5/8" 205BBL’s of cement in 9-7/8” Hole.Est TOC @ 1,550’ MD (0% excess) 4-1/2” 185BBL’s of cement in 6-3/4” Hole. Est TOC @ 2,934’(10% excess) PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status MB 8 +6,208’+6,219’+5,976’+5,987’+11 TBD Proposed LB 1B +6,403’+6,415’+6,166’+6,178’+12 TBD Proposed LB 1D +6,522’+6,532’+6,283’+6,293’+10 TBD Proposed LB 1E +6,539’+6,544’+6,299’+6,304’+5 TBD Proposed LB 1F +6,567’+6,582’+6,327’+6,342’+15 TBD Proposed LB 1F +6,604’+6,618’+6,364’+6,378’+14 TBD Proposed LB 2C +6,734’+6,739’+6,491’+6,496’+5 TBD Proposed LB 2C +6,761’+6,772’+6,517’+6,528’+11 TBD Proposed LB 2D +6,780’+6,790’+6,536’+6,546’+10 TBD Proposed LB 2E +6,829’+6,834’+6,584’+6,589’+5 TBD Proposed LB 3C +7,001’+7,022’+6,752’+6,773’+21 TBD Proposed LB_5A 7,282' 7,300' 7,029' 7,047' 18 6/12/20 Open TY 73_2 7,595' 7,606' 7,336' 7,347' 11 6/12/20 Open UT 1C 7,755' 7,762' 7,494' 7,501' 6 6/12/20 Open TY 84_6B 8,704' 8,736' 8,423' 8,455' ±32 6/10/20 Open D2 9,165' 9,190' 8,882' 8,908' 25 8/16/19 Open D3A 9,446' 9,463' 9,156' 9,173' 17 8/15/19 Open D3B 9,492' 9,516' 9,202' 9,226' 24 8/15/19 Open D4B 9,660' 9,686' 9,368' 9,399' 26 8/15/19 Open D4D 9,737' 9,754' 9,446' 9,462' 17 8/15/19 Open +6,327’+6,342’+15 TBD Proposed LB 1F +6,604’+6,618’+6,364’+6,378’+14 TBD Proposed LB 2C +6,734’+6,739’+6,491’+6,496’+5 TBD Proposed LB 2C +6,761’+6,772’+6,517’+6,528’+11 TBD Proposed LB 2D +6,780’+6,790’+6,536’+6,546’+10 TBD Proposed LB 2E +6,829’+6,834’+6,584’+6,589’+5 TBD Proposed LB 3C +7,001’+7,022’+6,752’+6,773’+21 TBD Proposed MB 8 +6,208’+6,219’+5,976’+5,987’+11 TBD Proposed LB 1B +6,403’+6,415’+6,166’+6,178’+12 TBD Proposed LB 1D +6,522’+6,532’+6,283’+6,293’+10 TBD Proposed LB 1E +6,539’+6,544’+6,299’+6,304’+5 TBD Proposed LB 1F +6,567’+6,582’ 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. Samuel Gebert Hilcorp Alaska, LLC GeoTech Assistant 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: 11/03/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 24-05B (PTD 219-072) Injection Profile 05/14/2020 ANALYSIS FIELD DATA Please include current contact information if different from above. Received by the AOGCC 11/03/2020 Abby Bell 11/04/2020 PTD: 2190720 E-Set: 34174 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 7/27/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 24-05B (PTD 219-072) Please include current contact information if different from above. Received by the AOGCC 07/27/2020 PTD: 219072 E-Set: 33626 Abby Bell 07/27/2020 Holly Tipton Hilcorp Alaska, LLC Regulatory Tech 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 7/06/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL Production logs as required by Rule No. 5 of CO 510A for KBU 43-07Y and KU 24-05B are saved in the following folders on the AOGCC FTP Site: Please include current contact information if different from above. Received by the AOGCC 07/07/2020 Abby Bell 07/07/2020 PTD: 2190720 E-Set: 33476 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 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 10,210 feet N/A feet true vertical 9,914 feet N/A feet Effective Depth measured 10,120 feet 4,917 feet true vertical 9,825 feet 4,918 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)N/A N/A N/A N/A Packers and SSSV (type, measured and true vertical depth)Swell Pkr; N/A 4,917' MD 4,918' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Ted Kramer Authorized Title:Operations Manager Contact Email: Contact Phone:777-8420 WINJ WAG 929 Water-Bbl MD 120' 1,580' 0 Oil-Bbl measured true vertical Packer 4-1/2"10,206' 5,744' 9,908' measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Kenai Gas Field / Tyonek Gas Pool 1N/A measured TVD Tubing Pressure 640 Kenai Unit (KU) 24-05B N/A FEE A028142 5,973' Plugs Junk STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-072 50-133-20683-00-00 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. 320-219 65 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 10 Authorized Signature with date: Authorized Name: 10 Casing Pressure Liner 1,133 0 Representative Daily Average Production or Injection Data 120' 1,580' 5,973' 10,206' Conductor Surface Intermediate Production 7,500psi Casing Structural 16" 10-3/4" 7-5/8" Length 6,890psi 5,210psi Collapse 2,470psi 4,790psi tkramer@hilcorp.com Senior Engineer:Senior Res. Engineer: Burst 8,430psi 120' 1,550' 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 8:31 am, Jun 29, 2020 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.06.26 16:14:36 -08'00' Taylor Wellman SFD 7/2/2020gls 9/21/20 RBDMS HEW 6/29/2020 Perforate DSR-6/29/2020 Rig Start Date End Date E-Line 6/10/20 6/12/20 PTW and JSA. Rig up lubricator. Wait on Tri-Plex. PT lubricator to 250 psi low and 4,000 psi high. RIH w/ 2-7/8" x 7' HC Razor 6 SPF, 60 deg phase and tie into OHL. Run correlation log and send to town. Get ok to perforate Gun 3 from 7,755' to 7,762' with well flowing 1 million at 70 psi. Spotted and fired gun. Pulled up 3' and was stuck. Pull 1,000 lb over tool wt and waited about 10 min and tools came free. POOH. Tools pretty much packed with formation mud. All shots fired/gun had mud RIH w/ 2-7/8" x 11' HC Razor 6 SPF, 60 deg phase and tie into OHL. Run correlation log and send to town. Get ok to perforate Gun 4 from 7,595' to 7,606' with well shut in. Spotted and fired gun with 647 psi. After 15 min pressure was 647.4 psi. OOH. All shots fired gun had mud. RIH w/ 2-7/8" x18' HC Razor 6 SPF, 60 deg phase and tie into OHL. Run correlation log and send to town. Get ok to perforate Gun 5 from 7,282' to 7,300' with well shut in .Spotted and fired gun with 647 psi. After 15 min pressure was 647.4 psi. OOH. All shots fired gun dry. Rig down lubricator and equipment. Turn well over to field. 06/10/2020 - Wednesday PTW and JSA. Spot equipment and rig up lubricator. PT to 250 psi low and 4,000 psi high. Well flowing 903K/68 psi. RIH w/GPT tool and tie into CBL. Go past proposed perfs to 9,000'. Ran GPT log and showed no fluid. POOH RIH w/ 2-7/8" x 2' HC Razor, 6 spf, 60 deg phase and tie into OHL. Ran correlation log and send to town. Get ok to perf from 8,734' to 8,736' w/flow 903K/68.6 psi. Spotted and fired gun. After 5 min - 890K/69.1 psi, 10 min - 888K/69.4 psi, 15 min - 892K/69.7 psi and 25 min - 946K/71.5 psi POOH all shots fired/gun was wet. RIH w/ 2-7/8" x 30' HC Razor, 6 spf, 60 deg phase and tie into OHL. Ran correlation log and send to town. Get ok to perf from 8,704' to 8,734' w/flow 909K/70 psi. Spotted and fired gun. Picked perf gun up 26' and stuck tools. Could not go up or down. Call town and discussed. Joe with AKE-Line came out. Worked tools for 1.5 hrs or so and didn't do any good. Started picking up 100 lb more on line tension every time we worked Worked line from 2,400 lbs to 3,200 lbs and line pulled out of rope socket. Rope socket is at 8,665' and bottom tool is at 8,707'. Pulled out of hole and got clean pull out of rope socket. Rig down equipment and turn wellback over to field. Slickline will be here in am to fish tools. 06/11/2020 - Thursday ARRIVE ON LOCATION MEET W/ BILLY SIGN IN PERMIT JSA. RIG UP 160 WIRE W/ 75' LUB. P/T LUB. TO 2,000 PSI FAILED C/O O-RING TEST AGAIN - GOOD TEST RIH W/ 4-1/2'' GR W/ G-BAIT SUB & 2'' OVER SHOT TO 8,687'KB. SIT W/ TOOL BEAT DOWN 20 TIMES LATCH 5 JAR LICKS UP TO 2,000# CAME FREE. POOH - GR PIN SHEARED. RIH W/ 4-1/2'' PRGS TO 8,687'KB LATCH BAIT SUB W/ TOOL 3 JAR LICKS UP TO 2,500# CAME FREE. POOH W/ FISH. Lay down fish. Got all line and tools out of hole, Rig back up lubricator and 3" GR. RIH w/3.85" GR and tag at 8.710' wlm KB. Spudded down and went thru bridge down to 8.720'. Picked up and had to jar loose. POOH. Rig down lubricator and turn well over to field. Will bring well on and if it looks ok will be perforating in morning. 06/12/2020 - Friday Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 24-05B 50-133-20683-00-00 219-072 _____________________________________________________________________________________ Updated by DMA 06-24-20 SCHEMATIC Kenai Gas Field Well: KU 24-05B PTD: 219-072 API: 50-133-20683-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 109 / X-56 / Weld 16” Surf 120’ 10-3/4” Surface 45.5 /L-80 / TXP BTC 9.950” Surf 1,580’ 7-5/8" Intermediate 29.7 / L-80 / W563 6.875” Surf 5,973’ 4-1/2" Production 12.6 / L-80 / TXP BTC 3.958” Surf 10,206’ JEWELRY DETAIL No Depth Item 1 4,917’ 4-1/2” Swell Packer OPEN HOLE / CEMENT DETAIL 10-3/4” 220 BBL’s of cement in 13.5” Hole. Returns to Surface (50% excess) 7-5/8" 205 BBL’s of cement in 9-7/8” Hole. Est TOC @ 1,550’ MD (0% excess) 4-1/2” 185 BBL’s of cement in 6-3/4” Hole. Est TOC @ 2,934’ (10% excess) PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status LB_5A 7,282' 7,300' 7,029' 7,047' 18 6/12/20 Open TY 73_2 7,595' 7,606' 7,336' 7,347' 11 6/12/20 Open UT 1C 7,755' 7,762' 7,494' 7,501' 6 6/12/20 Open TY 84_6B 8,704' 8,736' 8,423' 8,455' ±32 6/10/20 Open D2 9,165' 9,190' 8,882' 8,908' 25 8/16/19 Open D3A 9,446' 9,463' 9,156' 9,173' 17 8/15/19 Open D3B 9,492' 9,516' 9,202' 9,226' 24 8/15/19 Open D4B 9,660' 9,686' 9,368' 9,399' 26 8/15/19 Open D4D 9,737' 9,754' 9,446' 9,462' 17 8/15/19 Open LB_5A 7,282'7,300'7,029'7,047'18 6/12/20 Open TY 73_2 7,595'7,606'7,336'7,347'11 6/12/20 Open UT 1C 7,755'7,762'7,494'7,501'6 6/12/20 Open TY 84_6B 8,704'8,736'8,423'8,455'±32 6/10/20 Open _,p//,,, Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.05.29 11:50:34 -08'00' Taylor Wellman By Jody Colombie at 2:30 pm, May 29, 2020 320-219 10-404 DLB 05/29/2020 DSR-5/29/2020 X gls 6/1/20 6/2/2020 dts 6/1/2020 JLC 6/1/2020 RBDMS HEW 6/4/2020 New perf intervals ______ Beluga Tyonek O z �I @ E o V) N @ Q U Q m m Q m Q 0 N N 0� �p ❑ S 0 E r r N rr o U rr m J rr rr 0 � Q Q Y m m Y Y N Y p F z O Q Y w aNN � O tCo Z O Q O LL Z I - � K sm a 2 � Q K O V) Q Q Q Q Q Q Q Q N N p r r N rr rr rr rr rr rr � � r Q Y Y @ Y Y N Y Y YIQN Y w aNN m¢ tCo wS I - am 1<n sN sm a oam laam &2 La0 N 2 U oti0I0c9 2C) U 0 a v ti _ =al =m =M =CL =a =a- =a =a m 0 0 @@ @ N 0 @ vm m m I val N C N m as N I as N E� Ey Et E E E E E t o O(7 m m @a ma ma ma@a @a r r �I ro- ra (7 N (D = Y Y (D Y U r ll CV- C lL r IL r ll r lL r LL r lL r 2- E e- C E• r e' -o -o -a -a .a -a .a 'yX .a o o od oa m(A Nw m X yX yX 6 X m X V N -0 V X V X (/] � fn 4l fn M to Q N N fn O fn r @ N mo mo mo d o w m u cl�o 02 E Y V U O UI O U1 V V% V fn O fn O (/% O U% O U V U ow O U% E o O N 'E -I O �I c O �I *2 - O �I E O SI E O �I c O �I E O mI E O �I E O �I E O �I E O �I E O �I U O U U m U m U m U m U m U m U m U m U m (J m U m m 'm o @ m O @ @ @ @ y @ N W O W O W O W O W O W O W O W O W O W O W O w 0 p m m m m m m m m m m m m j o o O O O O O O O O o O •� O N N N N N N N N_ N N N N N (V N N N N N N N N N N d ¢ m m m m m m m m m m m m __ OU a cO o o a m r O O N N O Q (O N (O LLJ N O O O M M t0 fO Q a N l0 m c w z° I O N J f d m m J N y @ @ is m @ @ @ m m @ @ m y o m ❑ m 0 m ❑ m ❑ m ❑ m 0 m ❑ m ❑ m ❑ m ❑ m ❑ m ❑ E d m m @ @ @ @ @ @ m m @ @ @ m J p O ❑ O p ❑ ❑ ❑ ❑ p ❑ ❑ U« E N N N N N N N N N N N N N C� O m O W 0 z 0 E m E O L E °�a O e U U U U U U U U U U U U J =y m« OQ o 0 O O ❑ ❑ ❑ ❑ ❑ ❑ p ❑ ❑ 3 J0o~ J w w w w w w w w w w w w (4p� qN (l U N M m m m m m y N m m m m m _ 'O_i rn rnrn rn rn W O O rn rn rn O O O r N N N N N N N N N N M l�f M M th M M M M M 00000 000 rn rn W W W W W J J W W w m m 0 O m m m m O 9 M ❑ ❑ ❑ ❑ ❑ ❑ ❑ p Z O 9 9 D .m .2) .p Q Q Q ❑ ❑ .21 ❑ ❑ N N N N N N N s N U U U U p 6 as N as N 4a. 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Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 3 12 8 .� 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/5IN MD/TVD FORMATION LOG 2IN/5IN 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 9/26/201912:34 PM File folder Final Well Report 9/26./201912:34 PM File folder LAS Data 9/26/201912:34 PM File folder Log PDFs 9/26/2019 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,,4Wing anq returning one copy of this transmittal or FAX to 907 777.8337 Received By: j\\�,,� ' ,w 'I, lflp IDate: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 111 9: '_'- W c-� WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a. Well Status: Oil ❑ Gas SPLUG ❑ Other ❑ Abandoned ❑ Suspended[] 20AAC 25,105 20AAC 25A 10 GINJ ❑ WINJ ❑ WAG❑ WDSPL ❑ No. of Completions: _ 1 1b. Well Class: Development Exploratory ❑ Service ❑ Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Daf ornp Susp., or Aband.: 7/ 9e • / 14. Permit to Drill Number/ Sundry: . .219-072/319-349 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: July 1, 2019' Q..'30 • 15. API Number: 50-133-20683-00-00 - 4a. Location of Well (Governmental Section): Surface: 519' FNL, 771' FEL, Sec 7, T4N, R11 W, SM, AK Top of Productive Interval: 389' FSL, 1153' FWL, Sec 5, T4N, R11 W, SM, AK Total Depth: 411' FSL, 1289' FWL, Sec 5, T4N, R11 W, SM, AK 8. Date TO Reached: July 16, 2019 16. Well Name and Number: KU 24-058 9. Ref Elevations: KB: 84.1' GL: 66.1' BF: 66.1' 17. Field / Pool(s): Kenai Gas Field Tyonek Gas Pool 1 ' 10. Plug Back Depth MD/TVD: . 10,120' MD / 9,825' TVD 18. Property Designation: FEE A028142 ' 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 275130 • y- 2361491 ' Zone- 4 TPI: x- 277110 y- 2362248 Zone- 4 Total Depth: x- 277247 y- 2362268 Zone- 4 11. Total Depth MDn VD: . 10,21 O' MD / 9,914' TVD • 19. DNR Approval Number: N/A 12. SSSV Depth MD/TVD: N/A 20. Thickness of Permafrost MDrrVD: N/A 5. Directional or Inclination Survey: Yes t(attached) No El 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 MD/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 BOREHOLE PROFILE LOG, SONIC SCANNER MSIP-PPC-XPT-EDTC, EXPRESS PRESSURE TOOL MSIP-XPT-EDTC, CBL/GR/CCL 7-11-19 & 7-30-19, DGR, EWR-Phase 4, ALD Azimuthal Lithodensity, CTN compensated Thermal Neutron AvL 1 T— )A 23. CASING, LINER AND CEMENTING RECORD WT. PER GRADE SETTING DEPTH MHOLE SIZE CEMENTING RECORD D SETTING DEPTH TVD AMOUNT CASING FT TOP BOTTOM TOP BOTTOM PULLED 16" 109# X-56 Surface 120' Surface 120' Driven Driven 10-3/4" 45.5# L-80 Surface 1,580' Surface 1,550' 13-1/2" L-325 sx/T-370 sx 40 bbls 7-5/8" 29.7# L-80 Surface 5,973' Surface 5,744' 9-7/8" L-430 sx/T-140 sx 4-1/2" 12.6# L-80 Surface 10,206' Surface 9,910' 6-3/4" L - 390 sx / T - 158 sx 24. Open to production or injection? Yes 0 . No ❑ If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Pend): "Please see attached schematic for depth details" Perfd w/ 2-7/8" guns, 6 spf. COMPLETION D TE } 7_Z 20(5 VE --J ED 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) N/A N/A N/A 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes No 21 Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) 1AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: 8/12/2019 Method of Operation (Flowing, gas lift, etc.): Flowing Date of Test: 8/23/2019 Hours Tested: 24 Production for Test Period Oil -Bbl: 0 Gas -MCF: 1062 Water -Bbl: 0 Choke Size: N/A Gas -Oil Ratio: N/A Flow Tubing Press. 0 Casing Press: 0 Calculated 24 -Hour Rate --J� Oil -Bbl: 0 Gas -MCF: 1062 Water -Bbl: 0 Oil Gravity - API (corr): N/A Form 10-407 Revised 5/2017� 7,;'76-19 CONTINUA D Or ��AGE 2 RBDMSL� SEP 1 6 Z�jJ s "D o0 /. /ZA onlG 28. CORE DATA Conventional Core(s): Yes ❑ No ❑� � Sidewall Cores: Yes ❑ No ❑� If Yes, list formations and intervals cored (MD/TVD, Fromlro), 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. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No Q ' If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base N/A N/A Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval 9,165' D2 8,878' information, including reports, per 20 AAC 25.071. Upper Beluga 4,894' 4,696' Midde Beluga 5,541' 5,321' Lower Beluga 6,318' 6,083' Tyonek 7,472' 7,216' Tyonek 1B 7,661' 7,401' Tyonek D2 9,127' 8,841' Tyonek D3 9,391' 9,102' Tyonek D4 9,629' 9,338' Tyonek D4D 9,730' 9,438' 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. I 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: cclin of hllCor .com Authorized Contact Phone: 777-8389 Signature: — Date: 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 tb: 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: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. 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 survey, 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 mrR Alaska. LLL R¢B: MSL =18.6' IT 7-5/8- Kenai Gas Field SCHEMATIC Well: KU 24-05B PTD: 219-072 API: 50-133-20683-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID 4,917' 4-1/2" Swell Packer Date Status 109/X-56/Weld 16" 9,190' 8,882' 10-3/4" Surface 45.5/L-80/TXP BTC 9.950"7-5/8" 23A 4Topstm16"Conductor 9,463' Intermediate 29.7 / L-80 / WS63 6.875"4-1/2" M/15/19 Open D3B Production 12.6/L-80/TXP BTC 3.958" 9,226' 24 L f6 4-1/r j I& TD=10,2181MB) /9,914'(TVD) PBTD=1%12U(M D) /9,825'(m) JEWELRY DETAIL No Depth Item 1 4,917' 4-1/2" Swell Packer RFRFr1RATIr1N nFTAII Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status D2 9,165' 9,190' 8,882' 8,908' 25 8/16/19 Open 23A 9,446' 9,463' 9,156' 9,173' 17 M/15/19 Open D3B 9,492' 9,516' 9,202' 9,226' 24 -� 8/1;'/19 Open D4B 9,660' 9,686' 9,368' 9,399' 26 • 8/15/19 Open D4D 9,737' 9,754' 9,446' 9,462' 17 -` 8/1-5/19 Open Loot 7 Som' r T OPEN HOLE / CEMENT DETAIL 10-3/4" 220 BBL's of cement in 13.5" Hole. Returns to Surface (SO%excess) 7-5/8" 205 BBUs of cement in 9-7/8" Hole. Est TOC @ 1,550' MD (0% excess) 4-1/2" 185 BBUs of cement in 6-3/4" Hole. Est TOC @ 2,934' (10% excess) Updated by CJD 09-9-19 U ..� aN;':r` Ops Summary _ Well Name: KEU KU 24-05B Field: Kenai Gas Field County/State: Kenai, Alaska (LAT/LONG): ovation (RKB): API #: 50-133-20683-00-00 Spud Date: Job Name: 1912715D KU 24-05B Drilling Contractor Hilcorp 169 APE #: APE $: Hilcorp Energy Company Composite Report Actives Date ..� aN;':r` Ops Summary _ 6/23/2019 Cont. scrubbing rig & modules as we pulled them from containment, R/D skate controls, Put MP's back together, pulled lines between pump skids 1, 2, &3, R/D TO VFR & HPU, R/D hand rails on pits, lowered shakers & installed load pins, removed cuttings shoots, equalizer lines, raised walk ways on pits;modules & pined, removed kicker hose from MP to standpipe, pump bleeder lines, & 4 wind walls off rig floor.;Crew change, Held PJSM, removed service loop from derrick in individual pieces, cleaned & coiled in hose baskets w/ crane, removed saddle from derrick, moved premix tank, MP #2, middle mud tank w/ Peak winch truck & power washed skids in containment before leaving location.; Pinned TO to torque tube, hung blocks, slipped drill line on spool, cleaned & prepped rig floor to UD TD, 2" bleeder line, & standpipe S -pipe, removed torque latches from T -bar. Had Peak winch truck move top drive HPU, VFD house,;MP #1, & inside mud tanks w/ shakers, power washed all modules inside containment before leaving Iocation.;Top washed first section of rig mats, P/U individual rig mats, power washed bottom & all 4 sides before loading on trailers, cont. power washing remaining wind walls, rig floor, DW, & sub structure, R/D Pawn, catwalk controls, camera, & misc. power cords.;Power washed underneath rotary table & rig floor, roll up dog house power cables & cont. to work on cleaning ria mats. 6/24/2019 Continue clean and power wash sub, Dwk skid and rig matts (Day crew in 3 hr early take over pan operations & night crew to KU 24 -05B to stay late lay felt liner and rig matte ) set up crane and trucks hauling staged loads to KGF;PJSM Udn TDS ( had issue w/ ODS Pin removal from adaptor plate becket to dog bone) and remove TDS from floor w/ crane. P/up torque tube removal tool and un -Jay & Udn torque tube in individual sections wl crane also had some issues w/ pin s on sections remove T -bar w/crane;Stage all TDS equipment in containment and power wash clean same Mike & James on location to address pin issues w/ TDS R/dn tank farm containment & load timbers and save liner and Police pad #3 resume Power washing and cleaning cellar rig floor and dwks carrier;Remove bopes from bridge cranes and place in containment and clean power wash same w/ crane set up crane #2 finish removing wind walls, raised V - door, R/D TO control panel, prepped to scope derrick, held PJSM, scoped derrick down.;Hung blocks, rolled up tong cables, spool winch lines, held PJSM, unspooled drill line f/ drum, removed drill line from dead man/horse head. prep to UD derrick, cleaned carrier/A-legs, R/D brake linkage/drive shaft, raised brake handle into dog house, performed derrick inspection, lowered derrick;Cont. cleaning sub structure & catwalk, disconnected master cylinders F/ derrick, un- pinned A -legs, shut down & bled down HYD and air, disconnected HYD & air lines, lowered dog house handrails.;cleaned backside of rig mats, re -washed rig floor, DW, & cont. working on cleaning sub & around the rig, sucked out water tank, lowered dog house into rig tank, killed all power to the rig, hooked up power washers to camp gen & water supply to Peak vac truck, continued to power wash cellar & sub;continued to power wash cellar, sub, rig mats. 612512019 Continued to power wash cellar, sub, rig mats.;Trks and cranes on location PJSM, Power wash btm of of choke and skate skid while loading on truck clean role up liner and felt , R/up cranes and remove derrick mans house and fold do wind walls Remove Iron rough neck power wash and place in transport skid & remove torque tube hanging spear; Remove water tank skid w/ tool and dog house and remove power module skid power wash btm skid as needed , reset cranes and remove derrick, dwk skid, and sub clean and power wash each load and load on trucks;Picked & washed pony sub & lest pump, set and secured on trailer for transport, moved sub, derrick, pony walls, carrier to new location, while cont. to clean remaining rig mats, felt, & liner on BCU-04RD.:Moved rig to KU24-05B, spotted pony subs, installed sub structure on pony subs over center of hole w/ crane, installed carrier on sub, R/U HYD lines, installed derrick on carrier, R/U mast cylinders & HYD lines to derrick, pinned A -legs, spotted water tank,;While raising dog house lost HYD cylinder on one of the legs, got crane to assist in raising it & pinned in place, spotted shaker pit.;R/U electrical lines to modules, raised roof on shaker pit, installed camera on dog house, fired generator & powered up lights, removed HYD cylinder in water tank, while cont. to clean up mals & pad at BCU-04RD.;While moving rig to KU 24-05B on Marathon Rd, Peak trk had load come loose and lost a 30 gal partial full drum of (boiler water treatment) @ 11:00 AM on marathon road just before pavement. 6/2 612 01 9 Cont. R/U elec. lines, set pit modules 2 & 3, changed out valve on equalizer line between pits 3 & 4, M/U jumper hoses, equalizer lines, & suction lines, set MP/skids #1 & 2, tied in suction lines, installed jumper & bleeder lines from pumps to pits,;set boiler house & fuel tank w/ liner to build containment, organized tool house & lube room, finished up cleaning mats & liner on BCU-04RD.;Crew change, had Peak trucks & cranes on location, held PJSM, cont. started R/U, bolted Tesco torque tube sections together, cleaned out rig water tank, spotted gen #3, spotted gas buster R/U & stood, R/U crane & spotted choke house/catwalk, R/U power to mud pits, mud pumps,;spotted both office trailers, break shack, crew change shack, & night DSM & expeditors sleeping quarters, and R/U power to all, installed derrick man house, flipped out walls on board & pinned.;Raised V -door & gas buster, installed brake linkage, cont. to bolt up torque tube on the ground, had Handy Berm show up and build containment around rig, re -installed lights on roof of mud pits, removed transport blocks from shakers, raised degasser in pit #4,;installed torque tube in derrick w/ crane while derrick was still UD.;Replaced Sala block from above monkey board, aired up boots on MP suction lines, changed liners from 4.5" to 5.5", organized roughneck room.; Ran Pason cams. patched liner were needed, installed door on degasser, assembled bottom section of torque tube, prepped pad for third party shacks, spotted & plugged in shacks, R/U gas buster, Parson gas detector, & com cables, removed shipping beams from sub. 6/27/2019 Continue r/up operations, adjusted and remounted brake linkage, Rework torque tube mounting hardware. Continue organization of pad, Houseclean and organization of tools and equipment on rig Simops w/ production Forman and lead operator welder on location PJSM start on welding list, repair; Broke weld on derrick finger hinge, weld repair of hyd cylinder mount bracket in water tank, Continue build timber secondary containment of diesel tank, Telecom Gordy on location work on Communications , Canrig out r/up unit and equipment, directional out r/up equipment and chk tools;chase correct tools, Mud man R/up mud lab and flow water well w/ 5 hp mtr cleanup well chk rate +- 100 bbl hr;PTSM w/ crew, crew chg @ PJSM Continue wl rig welding projects, weld cracks in shaker #3, weld bracket on gas buster flow line, fix numerus broken hinges and pins on doors and walk ways, preform derrick inspection and prep to raise derrick, finish installing ground rods.;Raised derrick, lower lowered service loop, Kelley hose, & drill line to floor, cut 75' of drill line, spooled drill line on drum, noticed 2 broken stands in same lay, inspected remaining drill line, unspooled & cut additional 170', total of 245' cut, reinstalled drill line anchor, spooled drill;line on drum, installed DW brake covers, unhung blocks, raised exhaust on DW motor, prepped to scope derrick, moved cal pump pressure washer into tool room, cont. welding projects.;Cont. R/U, PIU lower section of torque tube, pinned to top section, held PJSM, scoped derrick, installed test plug in well head, installed DSA to well head for conductor measurements. R/U to lift torque tube w/ blocks to install longer tumbuckles on hanger cable.;PTSM, crew change, changed out torque tube hang-off turnbuckle in crown for longer one to lower torque tube to height needed to mount T-bar & tumbuckles from torque tube to mast, M/U hard line from pad water well to rig tank & vertical tank, filled vertical tank w/water,;set timbers for 10-3/4" casing, finished installing berm around auxiliary diesel tank, loaded torque bushing/skate onto catwalk, made final adjustment to hang off turnbuckles.; Hung mast turnbuckle mounts on torque tube & attached turnbuckle same, removed Eaton brake guards, mounted gas alarms on pits, M/U TD service loop from HPU to mast connections, installed 4" elbow & bleeder on standpipe, hung off & tied back bridle lines, mounted TD console and replaced;broken gauge, cont. to work on rig acceptance check list, set mud docks & cont. to clean up pad.;While starting to fill our 400 bbls vertical tank @ 11:00 pm, noticed man hatch was leaking, spilled 3-5 gal of fresh water on pad, checked seal & reinstalled & tightened bolts (ok) 6/28/2019 Continue adjusting Torque tube turn buckles, torque tube bushing hanging up on torque tube, wire wheeled paint on torque tube and add shims, prep Eaton brake for rebuild. Secured rig and all hands attended pre-spud at KGF office Resume;Continued to add shims and work bushing till free travel on torque tube, welders back on location, Pooh w/ slick line and r/dn same on 31-06X well, PJSM and establish hot work permit resume working on weld list, unload and rack 10-3/4" csg, spot crane and set centrifuge;Start building first batch of spud mud at G&I. Started tearing down Eaton brake, spotted riser in cellar, started removing all studs from DSA to allowed us to ft test conductor, filled pits w/ water to hydro test tanks, sprayed all areas of welding w/ cold zinc to protect from rust.;Cont. to rebuild Eaton brake, finished removing studs from DSA w/ welder applying heat to free studs, cont. w/ rig welding modifications, re-primed torque tube w/ zinc after removing paint, had Total safety out to check & bump test gas alarms (ok), removed brake linkage, used welder to heat & free;up linkage adjusting rod, adjusted main brake shaft to align brake bands, reassembled linkage so brake handle was at the correct height, fit tested riser & flow line (ok), P/U riser and silicone ring grove, set back down & installed bolts. Closed out hot work permit w/ production,;drifted 10-3/4" surface casing, brought over 300 bbls from G&I and unloaded into rig pits.;Held PTSM, crew change, finished reassembling Eaton brake & cooling system, cont. working on rig acceptance check list, finished M/U riser to DSA, filled rig water tank, installed flow line. installed two 4" ball valves on conductor for cement job, and tested w/ T-handles (ok).;P/U TD to rig floor & pinned to blocks, removed from cradle, pinned TD to torque bushing, R/U robotics cable, extend frame HYD. , & service lines, appears Kelley hose in long, chasing shorter hose. Cont. to work on rig acceptance check list.;-Hauled 0 bbls solids to KGF G&I Cumulative: 0 bbls -Hauled 28 bible fluids to KGF G&I Cumulative: 28 bbls -Daily downhole losses: 0 bbls Cumulative: 0 bbls -Daily metal: 0 lbs Cumulative: 0 lbs. 6/29/2019 Power up TDS HPU and function test top drive robotics, r/up bails, links, link cylinders and elevators chg out bad hose on compensator link tilt clamps did not fit bails chase clamps and bails issue, Kelly hose also to long chase short hose and unable find key for max torque on control console; PTSM & Crew Chg Remove 64' long Kelly hose and female X female XO and store same in hose box of new 55' Kelly hose, Located set of 8' long bails that link tilt clamps would fit and chg out bails for same. Install new sock on service loop. install 55' Kelly hose and install safety clamp;dry run and adjust same Continue house keeping around rig and pad organization, load 325 sx lead cmt into cmt silo, Pason hand working bugs out or wireless system and total safety tested gas system swaco commission centrifuge (missing dump cute seal);replace broken cable on equalizer line install tarps on mast raise cylinders, and reconnect DS cylinder Inspect Eaton brake, test MP liner lube alanns;installed hobble clamp on bails, clean grabber box, removed dies, and installed new dies along w/ 2 new bolts, cleaned saver sub clamp & double ball valve threads, M/U double ball valve to saver sub, installed clamp & tightened, R/U centrifuge and pump (tested ok), installed elevators on TD,;R/U tongs, staged DP & DC slips on rig floor, changed key switch on TD panel due to no key, functioned tested grabber box & mud saver interlocks (ok), change out TD TQ gauge, greased TD & checked fluid levels, changed swivel oil & change out wash pipe, continued w/ rig acceptance check Iist,;pressure tested both MP suction line bear traps w/ new hammer seals (leaking),; Held PTSM, crew change, discovered issue w/ max torque key switch, replaced same, cut & installed timber across cellar for walkway, cont. working on rig acceptance check list, hung tarp catch can off riser under rotary table, cleaned & inspected tong & slip dies, troubleshoot leaking pump suction;screen caps, found screens to be to long for pods w/ new hammer seal caps, checked pulsation damper psi (ok), clean & organize houses, dressed out monkey board, set up catwalk & pipe racks, loaded HWDP & DP and strap & tally. Cont. to work on rig acceptance check list.;-Hauled 0 bbls solids to KGF G&I Cumulative: 0 bbls -Hauled 100 bbls fluids to KGF G&I Cumulative: 128 bbls -Daily downhole losses: 0 bbls Cumulative: 0 bbls -Daily metal: 0lbs Cumulative: 0 lbs. 6/30/2019 Continue work on rig acceptance chk list. continue w/ house keeping of rig and pad organization Pull test pull and install wear ring found 4 its of hwdp and 2 its dp on rack w/ Worm bits remove bad pipe and repaired liner apron on ODS of pipe rack to cover tubulars Establish hot work;and welder cut do suctions screen in both MP and tested suctions good relabel shakers, repaired leaking water line hose fired boiler and bring to temp on short steam system. installed covers on Eaton brake, hung floor drain hoses and catch tarp around flow nipple . P/up DP mule shoe & DP;Test TDS torque and tong line pull against each other both with in 600 ft/lbs of each other Pason hand trouble shoot hook load and torque issues. Start first batch of 300 bbis of KCUPHPA mud for intermediate mud in pre mix tanks & G&I working on 2nd batch of spud mud;PTSM and crew change open turtle shell and inspect TDS elect componence's and remove moisture install new desiccant bags tight up 37 pin wire grommet seal P/up rabbit and strapping 4-1/2" CDS-40 DP and tag @ 124' RKB and rack back std adjust Kelly hose;Continue p/up DP and rack back same, using rig tongsichain tongs, drifting every it, under TQ each connection to 15K to minimize risk of bending DP, plan is to TQ through each connection w/ TD while drilling, cont. to P/U 4.5" DP.;Connected HYD lines to mast for DP spinners, functioned spinners and C -clip on valve handle was broke, cont. to strap/ tally & P/U 4.5 DP w/ rig tongs/chain tongs,:Repaired spinner handle, P/U 1 std wl rig tongstpipe spinner, had HYD hose pop on TD, shut down & replaced hose, inspected all hoses, built & replaced any in question, had 1/4 cup spill in containment & 1 teaspoon outside of containment, installed plugs in place of damaged iron roughneck sensors,;functioned tested iron roughneck (ok), verified proper TQ of iron roughneck against tongs (ok), cont. to strap/tally & P/U 4.5" DP for a total of 32 stds in derrick & 9 bad jts kicked out w/ scars at top of tool jt near the face of box end. Removed bad its & loaded 17 jts of HWDP on rack.;Strap/tally & P/U HWDP racking back a total of 8 stds in derrick ODS, flooded service line. R/U test pump & purged line, pressure tested service lines to 4000 psi, brought pressure to 2000 psi using MP, pressure leveled out at 1780 psi, shut in 4" valve on pump, brought up to 4000 psi w/ test pump,;held pressure for 10 min, bled down to 3950 psi & held, bled off pressure, RID test equip., B/O mule shoe & UD, pulled 14-1/8" ID wear ring & UD same, counted total pipe on location 375 jts of 4.5" CDS-40 & 21 its of 4.5 HWDP.;Staged BHA #1 at the cat walk, held PJSM w/ DD, P/U 8" 1.5 degree bend on motor, broke of 13.375" stab sleeve, currently M/U 14.375" stab sleeve, finalizing rig acceptance check list @ 6:00 am.: -Hauled 0 bbls solids to KGF G&I Cumulative: 0 bbis -Hauled 3 bbis fluids to KGF G&I Cumulative: 131 bbis -Daily downhole losses: 0 bbis Cumulative: 0 bbls -Daily metal: 0lbs Cumulative: 0 lbs. 7/1/2019 Apt ria (dr 0600 hrs fontinue p/up Bha #1, XO and 14-1/2" bit rih w/ HWDP tag at 114' changed conductor over to spud and dumped water to cutting tank.;P/up shut do do to flow line leaking at air boot at flow nipple and pipe beating in riser chg out air boot and tighten chains.;Drill f/ 114' V 285' wob = 1-3k, gpm 400-450, SPP = 330-400 psi w/ 50-150 diff on btm torque 2-3k and off 1.6k had to stop and reduce ROP and flow rate over whelming shakers at (1 times.;POOH rack back 4 stands of HWDP, UD Cross Over P/U remaining surface BHA, inspect bit, NVU BHA.;M/U B HA RIH V 178' Shallow test tools 500 t }r/ gpm 950 psi , Continue P/U BHA V 285 Get survey 470 gpm 860 psi.,Drill V 285' V 300' Rack back HWDP P/U jars, trouble shoot and reboot Pason �fv System.;Ddil Ahead as per DD/MWD following WP8 f/ 300't/ 1262'500 gpm 1650 psi on 60 RPM 5k tq on.;Drill Ahead as per DD/MWD following WP8 f/ 1262't/ 1586' 560 gpm 1630 psi 80 rpm 4k tq on.;Circulate Hi Vis Sweep around 17 bbis, 550 gpm 1580 psi 80 rpm 4200k tq, shakers cleaned up on bottoms up, no increase in cuttings when sweep came back.;POOH on elevators F 1586' V 73T No hole issues observed, hole took correct fII.;UD Drilling BHA #1 as per DD/MWD V 691.;Hauled 200 bbis solids to KGF G&I Cumulative Solids 200 bbls Hauled 134 bible Fluid to KGF G&I Cumulative Fluid 265 bible Daily Losses down Hole 0 bbls Cumulative Losses Down Hole 0 bbis Daily Metal 0lbs Cumulative Metal 0 lbs Distance to Plan .83' low 2.88' left 7/2/2019 Cont POOH LD BHA #1, Kymera bit graded a i-l.;Cieaned and cleared rig floor.;Staged Weatherford tongs, slips elevators, RU same, removed side plates of skate bucket to accommodate casing size. Held PJSM with fresh crew and Weatherford Reps.;MU first 3 jnts of shoe track top filling on the fly, checked floats (ok). Cont PU single in hole from 125' to 980'. MU circ swedge and CBU at 3 bpm while replacing torque gauge on Weatherford tongs. Still losing 2 bph. Cont PU single in hole from 980' to 1580' with no problem. Centralizer every;other jnt, torqued the TXP BTC connections at 22,630 ft/lbs. Ran a total 38 full jnts. Up wt 60K, dwn wt 54K.;Installed circ swedge, headpin and circ hose. Broke circ at idle (3 bpm) and slowly staged up to 4.5 bpm while changing to tong bails and RU hardline to rig floor. MW in 9.0 ppg/vis 47.;R/D circulating equipment, R/U Cement Head, Load Plugs, M/U circulating equipment V Cementers, Bring Pumps on line and stage pumps V 5 bpm 70 psi, Hold Pre Job Safety Meeting With all hands on Iocation.;Halliburton loaded lines with 5 bbis water and checked for leaks. Halliburton pressure tested lines at 800 low 3000 high, good tests. Halliburton pumped 50 bbls 10.5 ppg Spacer at 4 bpm and shut down. Halliburton dropped bottom plug and pumped 140 bible (325 sx) 12 ppQ Class A lead cement at 4 h 'followed hg 7Q 9 hhl= (1170 sx) 15 R ppg lYacc a tail cement at 4 bpm. Halliburton dropped top plug, then displaced with 142 bbls 9 ppg Spud Mud at 5 bpm. Slowed to 2 bpm with 10 bbl to go. Did bump the plug 142 bbis into displacement (calculated 144 bbis), held 1070 psi (FOP of 472 psi) for 3 minute;bled off and floats held. Bled back 1 % bbis to truck. Had 50 bbls Spacer returns to surface and 43 bbis lead cement to surface. Added LCM to both lead and tail cement at 114 ppb. Mix water temp 75 deg. Pumped 50% excess on both lead and tail. Lost 21 bbls during displacement. Reciprocated string;2 x per minute throughout the job. Up wt 64K Decreased to 54K, dwn wt 41 K at time of landing hanger. CIP at 00:30 hrs, 7-3-19. Blow down drain lines wash up Halliburton, RID Cement Head, Pull Landing jt drain and wash stack.; R/U and Install Pack off, UD Landing Jt.;N/D Riser and flow lines, remove riser f/ cellar;Hauled 156 bbls solids to KGF G&I Cumulative Solids 356 bbis Hauled 260 bbis Fluid to KGF G&I Cumulative Fluid 525 bbls Daily Losses down Hole 18 bbls Cumulative Losses Down Hole 18 bbis Daily Metal 0 be Cumulative Metal 0 lbs 7/3/2019 Cleaned up packoff and conductor flange. Bring in, stab and NU wellhead section. Wellhead Rep tested same at 250 low for 10 min, 3000 high for 10 min. Peak spotted BOP cradle at cellar area, then rolled in and spotted crane.; RU hydraulic hoses to BOP cradle, raise beaver slide to access cellar, raise BOP cradle, RU and pick stack off cradle with crane, transfer BOP stack to cellar bridge cranes. RD and release crane. Lower beaver slide, sting in 1' spacer spool and install on wellhead. Stab BOP stack on spacer spool and;torque bolts with Sweeny wrench. Install kill and choke lines, install shock hose from catwalk to poorboy degasser, install drip pan, install flow riser flange, hook up koomey lines, install grating over cellar box, function test BOP's, level sub base and install 4 way chains to stack, install flow;riser and flow line. SIMOPS: bring on mix water in pits 4-5-6, remove pipe skate winch under catwalk and replace bearings/seals, received 4 trailers of 7 5/8" casing, received two trailers mud products.; Installed test plug and test joint. Flooded surface lines and stack. Purged air from surface equipment. Attempt shell test. Upper variable rams Ieaking.;Open ram doors, Change Upper VBR's, Close ram doors, fill stack w/ water purge system.;Retest rams appear to have air, after 2 tests Upper rams leaking trouble shoot rams, Function rams, retest still leaking, Perform drew down test, Pull test joint, shut blind rams, start BOP test over w/ # 2 test, test lower pipe mms.;Hauled 121 bbls solids to KGF G&I Cumulative Solids 477 bbls Hauled 285 bbls Fluid to KGF G&I Cumulative Fluid 810 bbls Daily Losses down Hole 21 bbls Cumulative Losses Down Hole 39 bbls Daily Metal 0lbs Cumulative Metal 0 lbs 7/4/2019 Tested blinds and choke HCR, set test jnt and tested inside choke, lower rams, topdrive IBOP's, dart, TIW. Opened upper ram doors and checked variable ram sealing elements (ok), Removed door bonnet assembly, replaced inner seal assembly on hydraulic ram shaft, re-assembled and buttoned up doors.;Flooded stack and re-tested upper rams with no issue. Tested kill HCR and inside kill. AOGCC Rep sat sfed wth all tests and left locat on at 11 30Had total two P faillpass tests (upper rams and choke HCR).;Removed test plug and test joint, removed test sub from topdrive.;RU test pump on kill line, purged air from test rr'�11 hose, pumped 1.5 bbls and tested 10 314" surface casing at 2600 psi for 30 min on chart. Good test. Bled off, RD test equipment.;Drained water from BOP \1 stack, blew down choke manifold and choke line, lined up choke manifold for drilling, installed 10" ID wear ring.;MU CDS-40 mule shoe on single, PU singled in hole 45 jnts CDS-40 DP to 1396' (top of wiper plugs at +/- 1493'), MU topdrive.;CBU with both pumps at 319 gpm-60 psi, pumped remaining black water from trip tank into active spud mud system, then refilled with spud mud to POOH.;Tum elevators and transfer HWDP and jars from offside to drill side in derrick.;POOH rack back 22 stands from 1396', turn elevators for PU singles.;PU single in hole 44 jnts CDS-40 DP.;POOH Standing back 22 stands of DP.;Clean and clear floor, Load BHA components onto skate and pipe racks, Bring components to rig floor, Wrap service loop with Omni wrap.;PJSM, WU 9 7/8" Drilling Assy as per DD/MWD, Upload MWD, Shallow test tools @170' with 460 gpm 1450 psi, Load sources.;Change Out leaking ram cylinder on top drive.; RIH w/ BHA f1174' U 732' RI P/U 4.5 " DP off racks U 1354'.; Hauled 0 bbls solids to KGF G&I Cumulative Solids 477 bbls Hauled 0 bbls Fluid to KGF G&I Cumulative Fluid 810 bbls Daily Losses down Hole 0 bbls Cumulative Losses Down Hole 39 bbls Daily Metal 0 lbs Cumulative Metal 0 lbs 7/5/2019 After tagging cement at 1488' (5' above wiper plugs), drilled cement andish track to 15Rn' then drilled rathole and new formation to t8f1R1. 460 gpm-1198 psi, 30 rpm-3000 ft/lbs on bott torque, MV 9.0,,f CD at 9.2 ppg.;CBU one time while prep pits and spacer for displacement. Diverted returns to cuttings box and pumped active pit #7 down followed with 20 bbl spacer from pill pit at 274 gpm-467 psi. With spacer in drill string, shut down lined up pump #2 on pit 4-5-6 with 6% KCL mud, displaced well to new 6% KCL;mud until good mud to surface, shut down pump.;Racked one stand back and parked bit inside Q me=surface casing. RU test pump to mekill to pump down drill string and annulus simultaneously, flooded test hoses. Pit watcher cleaning pit #7 of any remaining spud mud.;With test pump, pumped 17.5 gallons down DP and annulus and achieved 260 psi on chart. Held 10 minutes recording pressure dropeve minute. PSI y dropped to 180 over 10 minutes. Bled ac 0 gallons then RD test equipment.; Latched up stand and exited surface casing with bit, resumed circulating with / one pump staging up pump rate as 120 screens on shakers allowed, until mud warmed and sheared. Initial 136 gpm, 172 gpm, 225 gpm up to 390 gpm-694 psi, 20 rpm-1800 fVlbs off bott torque. Obtaine SPR's with new mud in hole;Directionally drill 9 7/8" hole section from 1606' to 1973', wob 4-5K, 404 gpm-744 C si, 30 rpm-3945 ftllbs on bolt torque, 89 to 140 ft/hr ROP, MW 9.0/vis 51, ECD at 9.3 ppg, BGG 17 units. Drilling loose unconsolidated sand and claystone. nce smart iron was below surface shoe, increased to 80 rpm-;4200 fUlbs torque. BHA was building in rotary .8°/100' and walking left 1 °/100' at initial 30 .� r m.;Directional Drilling from 1973'to 2596520 gpm 1330 psi 60 rpm 4500 tq on 3500 off 3.7k WOB, PUW - 58k SOW - 49k ROT - 53k, ECD - 9.4 ppg a p�� W 1622' footage 77.5 FPH AVG ROP.;CBU 520 gpm 1250 psi 60 rpm 3500 tq cuttings cleaned up on bottoms up ECD dropped U 9.3ppg f/ 9.4ppg.;POOH n elevators If 2595' U 1544' without issues.;Service rig and top drive, check oil in draw works motor, grease blocks.;RIH f/ 1544' U 2535' Fill pipe and wash down U 2595'.;Pump Hi Vis Sweep Resume Directional Drilling f/ 2596112621'520 gpm 1230 psi 60 rppm 4k tq on 3k tq off 3-7k WOB 9.4 ppg ECD, Distance to Plan - 3.49 High 5.99 Left.;Hauled 109 bbls solids to KGF G&I Cumulative Solids 586 bbls Hauled 348 bbls Fluid to KGF G&I Cumulative Fluid 1158 bbls Daily Losses down Hole 0 bbls Cumulative Losses Down Hole 39 bbls Daily Metal 0lbs Cumulative Metal 0lbs 7/6/2019 Cont directionally drilling 9 7/8" hole section from 2621'to 3651'. Rotating wob 3-5K, 523 gpm-1314 psi, 65 rpm-4500 to 5700 fUlbs on bott torque, 145 to 150 R/hr ROP. Sliding wob 5-6K, 477 gpm-1178 psi, 129 psi diff, 130 to 150 fit/hr ROP. MW 9.1/vis 48, ECD's at 9.3 ppg, BGG 12, max gas 62 unfts;Running centrifuge and water on at 15 bph to maintain 9.0 ppg MW while drilling. Drifted and strapped 155 jnts 7 5/8" casing.;CBU at 530 gpm-1339 psi, 60 rpm-4445 ft/lbs off bott torque until clean at shakem.;Pulled up hole on elevators from 3651'to 2660' with no issue.;Service rig and topddve.;TIH on elevators from 2660' to 3591' Wash and ream U bottom @ 3651' at drilling rate 520 gpm 1360 psi 60 rpm 3k tq.;Continue Directionally Drilling If 3651' U 4331' 520 gpm 1475 psi PUW 79K SOW 62K ROT 70k WOB 5-7k, MW 9.1 ppg ECD 9.35ppg EMW, Distance to plan 1.48' High 3.81' Right @ 4244' MD 4078' TVD Slight Losses observed 4.5 bis in 15 min.;Hauled 178 bbls solids to KGF G&I Cumulative Solids 764 bbls Hauled 177 tools Fluid to KGF G&I Cumulative Fluid 1335 bbls Daily Losses down Hole 0 bbls Cumulative Losses Down Hole 39 bbls Daily Metal 0 lbs Cumulative Metal 0 Ib f�if 7/7/2019 Cont drilling 9 7/8" hole section from 4331' to 4580'. Rot wob 4-9K, 515 gpm-1570 psi, 60 rpm -6000 ft/lbs on bot[ torque, 145-150 ft/hr ROP, MW 9.1/vis51, ECD at 9.5 ppg, BGG 40 units, max gas 313 units. Losing 5 bph while drilling. Making wiper trip prior to drilling into P6 C1 Storage Sand.;CBU x 2 at 515 gpm 1440 psi, 60 rpm -5300 it/lbs off bolt torque. ECD's dropped from 9.5 to 9.3 ppg. Obtained SPR's at 4580'.;Pulled up hole on elevators from 4580', up wt 94K, to 3586, slacked off to 3654' and parked for rig service. Calculated hole fill = 6.9 bbls for trip, actual hole fill = 10 bbls.;Service rig and topdrive. Flushed centrifuge. Static loss rate 1.5 bph on trip tank.;TIH from 3654', down wt 67K, to 4516'. MU last stand and filled pipe, washed to bottom and made connection.;Started 20 bbl hi -vis nut plug sweep around, once clear of bit resumed drilling ahead from 458V to 4951' with reduced pump rate and ROP. Had 10% increase in cuttings with sweep to surface, had 46 units trip gas. Rotating wob 6-8K, 492 gpm-1500 psi, 60 rpm -7300 ft/lbs on bott torque, 95 to 130 ft/hr;ROP, MW 9.1/vis 49, ECD's at 9.5 ppg, BGG 25 units, max gas 66 units, loss rate at 3 bph while drilling, drilling in claystone, siltstone and course sand with a trace of coal. No change in parameters when we drilled into the P6—Cl and P6—C2 gas storage sands. Sent AOGCC 24 notice for casing/cement.;Cont drilling from 4951' to 5576490 gpm 1650 psi 60 rpms 7500 tq on 6000 tq off, PUW 98k SOW 74k ROT 88k,9.1 ppg, 9.5 ECD, Sliding as per DD and Mad Passing Slides, BGG 40 units, Distance to Plan .97 low 9.71 Right.;Hauled 131 bbls solids to KGF G&I Cumulative Solids 895 bbls Hauled 130 bbls Fluid to KGF G&I Cumulative Fluid 1465 bbls Daily Losses down Hole 208 bbls Cumulative Losses Down Hole 72 bbls Daily Metal 2 lbs Cumulative Metal 2 Has 7/8/2019 Drilled 9 7/8" hole from 5575' to 5639' and worked pipe while pumping sweep out of hole. Had a max of 576 units gas with sweep to surface and a 10% increase in cuttings. Cont drilling ahead from 5639' to TO at 5980', sliding wob 6-9K, 487 gpm-1610 psi, 148 to 235 psi diff, 36 to 100 ft/hr ROP.;Rotating wob 14-15K, 490 gpm-1686 psi, 70 rpm -7400 to 10,200 ft/lbs on bott torque, 20 to 150 ft/hr ROP, MW 9.3/vis 48, ECD's at 9.6 ppg, BGG 33 to 137 units. Distance to Plan 3.29' High 5.27' Right.;Received 430 sacks lead cement in silo. Loss rate while drilling was down to 2.5 bph. At TO obtained survey and racked back one stand to allow full stroke during sweep.;PU kelly int, pumped 20 bbl hi -vis nutplug sweep around at 480 gpm-1539 psi, 70 rpm -5700 ft/lbs off bott torque, MW 9.3/vis 47, BGG 28 units. Had 10% increase in cuttings to surface with sweep, circ until clean on shakers.;Obtained SPR's, flow checked (slight drop) then started pulling up hole on elevators for wiper trip to shoe, from 5978' to 1633' (surface shoe at 1580'). Up wt coming off bottom 115K. Had a 15K overpull at 4740' and a 20K overpull at 4660'. Did not have to work pipe through those, just straight;pulled. Received our three joints of shoe track and float equipment.;Sewiced rig, draw -works and topdrive.;CBU 1 time at 489 gpm-1009 psi, 40 rpm -2179 ft/lbs off bold torque, BGG 7 units, out side the shoe. No increase in cuttings at bottoms up.;TIH on elevators from 1633' to 5801' Set down 20k, Attempt U work through unable, Kelly up and wash and ream through tight spot 450 gpm 1500 psi 30 rpm 5k tq, tight spot was gone, Continued washing remaining 3 stands to bottom @ 5980' pipe was getting hung up on the down stroke out of slips.;Pump Hi Vis Sweep w/ Nut plug Marker 490 gpm 1550 psi 30 rpm 5k tq Sweep back on time 10% increase in cuttings, Circulate until shakers cleared up 16835 stks , Flow Check well static slight drop, Pump 17 bbls Dry Job.;POOH on Elevators f/ 5980' t/ 732' No hole issues observed Calc Hole fill 36.1 Actual 42.8.;Stand Back HWDP and UD Collars, Unload sources.;Hauled 131 bbls solids to KGF G&I Cumulative Solids 1026 bbls Hauled 130 bbls Fluid to KGF G&I Cumulative Fluid 1595 bbls Daily Losses down Hole 65 bbls Cumulative Losses Down Hole 273 bbls Daily Metal 0lbs Cumulative Metal 2lbs 7/9/2019 Held PJSM, removed nuke sources; plugged in and down loaded MWD data.;LD TM, ALD, HCIM, PWD, EW R -P4, DGR and DM collars, drained motor and broke off Kymera bit. Bit graded as follows: Roller Cones 1 -1 -WT -A -E -1 -NO -TD, PDC 1 -3 -ST -G -X -1 -NO -TD. 39.9 him on bit, 604.50 K -Revs. LD bit and motor.;Clean and clear rig floor, drain BOP stack. PU 7 5/8" test jnt and MU retrieval tool, pulled wear ring, set test plug, swapped upper rams from variables to 7 51 " solid body, Flood stack, RU test equipment and chart recorder. Test annular at 250/2500 psi, test upper rams at 250/4000 psi for 5 min each.;RD test Ip equipment, pull test plug, LD test jnt. PU landing jnt/hanger and dummy run, LD same.; RU Weatherford casing equipment, staged centralizers and casing, RU 0 fill up line, held PJSM.;PU and MU shoe track, filled pipe and checked floats (OK). Cont PU single in hole with 7 5/8" 99 lie I -Rn Wedge s63 Intermediate casing. Torqued to 10,300 ft/lbs. Top filling on the fly, topping off every ten jnts. t/ 3233'.;Circulate and condition mud f/ 9.5ppg U 9.1+ppg avg loss rate 7 bph adding water and running cent to drop MW.;Continue RIH w/ 7 5/8" Casing as per detail filling every jt topping off every 10 jts U 5924'tag fill setting down 40k no over pull PIU clean 140k.;M/U circ assembly M/U top drive wash down 139 gpm 250 psi f/ 5924' t/ 5953' no over pull observed fill washing away.;Circulate 139 gpm 200 psi 9.1 ppg in 9.35 ppg out while changing handling equipment, remove short bails and install long bails and circ. swedge on landing it, UD Circ swedge, WU Landing Jt.; Hauled 0 bbls solids to KGF G&I Cumulative Solids 1026 bbls Hauled 0 bbls Fluid to KGF G&I Cumulative Fluid 1595 bbls Daily Losses down Hole 74 bbls Cumulative Losses Down Hole 347 bbls Daily Metal 0lbs Cumulative Metal 2 lbs C4J -7 7/10/2019 MU topdrive and circ swedge on landing jnt, broke circ at 139 gpm-74 to 209 psi, wash down slowly and clean out fill from 5950' to hanger on seat putting shoe at 5973.47'. Up wt 142K, dwn wt 100K.;Conl circ at 139 gpm-106 psi with hanger 1' off seat. RD and released Weatherford casing equipment. Staged pump rate up slowly to 5 bpm with minimal losses, MW down to 9.2 ppg. Held PJSM with Halliburton cement crew, Peak and rig team. Down pump and landed hanger. RU hardline to floor.;Broke off topdrive and circ swedge, Loaded plugs in plug launcher and MU same on landing jnt. MU manifold on rig floor, MU cleanup hose to cuttings box.;Halliburton loaded lines with 5 bbis water and checked for leaks. Halliburton pressure tested lines at 920 low 5200 high, good tests. Halliburton pumped 40 bbis 10.5 ppg Spacer at 4 bpm 255 psi and shut down Halliburton drooped bottom plug and Bumped 174 bbis (430 sx112 ppg Class A lead cement;at 4-5 bpm 216 to 163 psi, followed by 31 bbis (140 sx) 15.3 ppg Class A tail cement at 4 bpm 300 psi. Halliburton dropped top plug, then displaced with 270 bbls 9.2 ppg 6% KCL Mud at 4.5 to 6 bpm 77 to 118 psi. Slowed to 2 bpm with 20 bbls to go. Bumped the plug 270 bbis into displacement;(calculated 270.7 bbls), held 1590 psi (FCP of 980 psi) for 3 minutes, bled off and floats held. Bled back 2 bbls to truck. Had a trace of Spacer returns to surface, had no lead cement to surface. Added LCM to both lead and tail cement at 114 ppb. Mix water temp 75 deg. Pumped 20% excess on both;lead and tail. Had 100% returns throughout the job. Did not reciprocate string due to tight tolerance between hanger OD and ID of BOP stack. Up wt 130K, dwn wt 88K at time of landing hanger. CIP at 11:45 hrs, 7-10-19.;Wash up pump truck to cuttings box, RD hardline from rig floor, removed plug launcher and clean/clear rig floor.;Pulled landing jnt, MU packoff assembly, RIH and set same. Wellhead Rep RILD's and tested void at 250/5000 psi for 10 min each. Good tests. LD landing jnt. Opened upper annulus valve.;PU 4 1/2" test jnt and test plug, set test plug in wellhead. Bled off koomey unit, opened upper ram doors and swapped 7 5/9' rams with 2 7/8" x 5" variables. Buttoned up ram doors. CO long bails back to short bails on topdrive.;Flooded stack and test hoses, purged air from BOP cavities. Tested annular at 250/2500 psi, tested upper rams at 250/4000 psi for 5 min each test. Pulled test plug and set wear ring, closed annulus valve.;P/U and RIH w/ 4 1/2" CDS-40 DP t/ 4903'.;Move HWDP in Derrick.; Hose leaking on top drive compensator, Change out.; POOH f/ 4903'1/ surface standing back in derrick.; Pull wear ring and ID, Install wear ring, PIU NM flex DC's, jnt HWDP and jars, stand back in derrick.;Hauled 67 bbis solids to KGF G&I Cumulative Solids 1093 bbis Hauled 554 bbis Fluid to KGF G&I Cumulative Fluid 2149 bbis Daily Losses down Hole 24 bbis Cumulative Losses Down Hole 371 bbls Daily Metal 0lbs Cumulative Metal 2 lbs 1(2019 Rack back NM DC's and jars. MU motor, DM and slim phase 4 collars, scribe and rack back. PU, MU and racked back all but three items of BHA. Calibrated 0v block height, changed mud pumps from 5 1/2" to 5" swabs/liners. Pollard a -line on location at 10:30, spotted unit alongside catwalk.;Held PJSM with Pollard crew and rig crew, RU sheaves, MU tool string consisting of CCL, centralizers, 3.25" sector bond tool with temp, gamma ray. RIH with bond log assembly and tagged up at 5845' W LM. Logged up hole from 5845' to 1300'. TOC estimated at 1550' POOH, RD released Pollard e-Iine.;RU test equipment to kill line and purged air, closed blinds pressured up and tested 7 5/8" Intermediate casing at 3500 psi for 30 min on chart. Pumped 140 gallons (3.33 bbis) to achieve 3500 psi. Good test, bled off and RD test equipment.;PU single jnt, MU topdrive, set in slips and hung topdrive. Slipped and cut 75' of drill line. Calibrated hookload and block height, LD single jnt.;Latched up on motor, DM and slim phase collars. MU 63/4" HDBS PDC jetted with 6x 10's, M/U Remaining BHA components, Upload MWD, Shallow pulse test tools 250 gpm 900 psi, Load Sources, RIH w/ BHA f/ derrick U 730' -;Continue RIH f/ 730' t/ 5819' filling DP every 20 C stands.;Oblain Parameters, Wash and ream 207 gpm 920 psi 40 rpm 6k tq f/ 5819' 1:15885' Tag cement, Drill cement and float equipment U 5980' 3-71k WOB PUW 186 SOW 166 ROT 178.;Drill 20' of new hole f/ 5980' t/ 6000'w/ 3-7k WOB 205 gpm 1150 psi 40 rpm 6700 tq, circulate bottoms up f/ FIT.;Hauled 0 bbls solids to KGF G&I Cumulative Solids 1093 bbis Hauled 0 bbis Fluid to KGF G&I Cumulative Fluid 2149 bbis Daily Losses down Hole 0 bbis Cumulative Losses Down Hole 371 bbis lCumulativa Daily Metal 0lbs Metal 2 fibs 7/12/2019 Cont to CBU at 204 gpm-1028 psi, 45 rpm -6500 R/Ibs off bolt torque, up wt 77K, dwn wt 72K, MW 9.3/vis 43, BGG 3 units.;Pulled into and parked bit inside 7 5/8" casing at 5970', RU test pump on mezz kill, pumped water to purge air from test hoses. Closed upper rams and pumped 42.5 gallons to achieve 1410 psi With 9.3 ppg mud and held 10 minutes. Pressure bled to 1360 psi over 10 minutes. Good FIT of 14.0 ppq. Bled;off 42 gallons and RD test /i equlpment.;Resumed drilling 6 3/4" hole from 6000' to 6561'. Rotating web 5-6K, 304 gpm-1867 psi, 60 rpm -7800 to 8500 Nibs on bott torque, 120 to 130 R/hr ROP, increased MW to 9.7/vis45, ECUs at 10.5 ppg, BGG 18 units, max gas 465 units. Production had RU slickline on 31-06x, located near end of doghouse/;water tank, to bail sand from that wellbore. Appears shckline broke through a bridge and gas shove their bailer up hole and wadded up their wire. `xA lickline pulled tool to surface and ran into wellhead 400' early, which parted their wire. With tool string and wire stuck across wellhead valves and;wireline valve, they could not shut in well. Wire was pulled by hand from top of lubricator and packoff pumped closed. Production put well on line to flow and reduce ell ore pressure. Discussed options with town, decision made to CBU and pull drill string up to shoe incase of rig shut down for gas;venting by duction.;CBU at 299 gpm-1693 psi, 30 rpm -7200 fit/lbs off bott torque. Shut down and flow checked, well static.;Pulled up hole from 6561' on elevators, up 3 08K. had a 20K over pull at 6310' and a 25K overpull at 6290' (coals). Rest of trip went good. Parked bit at 5975' and MU topdrive.;Circ at low rate, but Ol• P ugh to detect pulse on MWD tools. 150 gpm-583 psi. Production waiting on delivery of Hilcorp hotoil truck from Swanson River. Baroid and Peak building u bbis 3% KCL brine for Production to pump and kill 31-06x, Hot oil truck arrived spot in, PJSM and pumped 140 bbis 3% KCL;monitor well, built U 600 psi J'- in 3 hrs, production bled off through test separator, then put on open top tank U Monitor flow rate bled off no flow, shut in well monitor pressure build up 6 psi , Continue wait on production to secure well 31-06X before resuming drilling operations.;Hauled 63 bbis solids to KGF G&I Cumulative Solids 1156 bbls Hauled 62 bbis Fluid to KGF G&I Cumulative Fluid 2211 bbis Daily Losses down Hole 0 bbls Cumulative Losses Down Hole 371 bbis Daily Metal 0lbs Cumulative Metal 2 Has 7/13/2019 Cont to circulate at low rate with bit just outside shoe while waiting on Pollard and field Operators to check status of 31-06x. Replaced swab on #1 pump, cleaning throughout the rig.;Staged Hilcorp hotoil truck as 31-06x, held PJSM, RU and pumped 40 bbls 3% KCL down 4 XV monobore, shut down bled off 30 psi to production bleed tank. Well static. Monitored well 2 more hours, well on vac. Closed wireline valves on Pollard lubricator, against slickline tool string and lifted;lubricator/toolstring off and out of wellhead with Pollard boom truck. Removed excess wire from wellhead and closed master valves.;TIH from 5975' to 6503' with no issue, dwn wt 65K. At 6503' MU last stand, filled pipe and washed to bottom at 6561'.;Resumed drilling 6 3/4" hole from 6561' to 6902'. Rot wob 7K, 308 gpm-2203 psi, 70 rpm -8100 to 9500 ft/lbs on bott torque, 150 R/hr ROP. Sliding wob 4K, 303 gpm-2121 psi, 245 to 370 psi diff, 100 ft/hr ROP, MW 9.8 to 10.0/vis 43, ECD's 10.7 to 10.9 ppg, BGG 60, max gas 320 units.;Cont drilling from 6902'to 7555' 282 gpm 2270 psi 60 rpm 9k tq on 7500 tq off 3-5k WOB 10.1 ppg ECD 11.27 ppg PUW 105k SOW 70k Rot 85k 150 fph ROP, Distance to Plan 5.74' Low 1.66' Left.;Circulate bottoms up, shakers cleaned up.;POOH on elevators f/ 7555' t/ 6515' Work through tight spots pulling 30k over @ 7284', 7157',6988',6970' 6909', 6797' to 6787'.;Hauled 0 bbls solids to KGF G&I Cumulative Solids 1156 bbls Hauled 0 blols Fluid to KGF G&I Cumulative Fluid 2211 bbls Daily Losses down Hole 0 bbis Cumulative Losses Down Hole 371 bbls Daily Metal 0lbs Cumulative Metal 2 Ib 7/14/2019 Serviced rig and topdrive at 6515'.;TIH on elevators from 6515'to 7268' and set down numerous times. MU topdrive and washed/reamed down to 7300'. TIH to 7555', filled pipe and started a 20 bbl hi -vis nut plug sweep around.;Circulated sweep around at 295 gpm-2150 psi, 40 rpm -8582 ft/Ilos off bot[ torque. Had a good amount of cuttings prior to bottoms up, then 10% increase with sweep to surface.;Drill 6 314" hole from 7555' to 7803'. Rot wob 4-6K, 291 gpm-2286 psi, 60 rpm -9100 ft/lbs on bott torque, 140 ft/hr ROP, MW 10.21vis 48, ECD's at 11.2 ppg, BGG 13 units, max gas 560 units. Coni to dust up mud weight, running water at 6 bph. No sliding. Claystone, siltstone, sand and trace of coal.;Drill 6 3/4" hole from 780T to 8182' md/7912' tvd. Rot wob 3-15K, 285 gpm-2697 psi, 65 rpm -9500 ft/lbs on bott torque, 20 to 130 ft/hr ROP. Sliding wob 8 to 16K, 269 gpm-2363 psi, 400 to 500 psi diff, 18 to 96 ft/hr ROP, MW 10.6/vis 59, ECD's at 12.0 ppg, BGG 50 units, max gas 2342 units.;Drill 6 3/4" hole from 8182' to 8488', 280 gpm 3020 psi 60 rpm 9k tq on 7500 tq off 5-15k WOB 13-50 avg ROP 11.1 ppg ECD 12.6 ppg Max gas 958 units.;Pump Hi Vis Sweep, Madd Pass while circulating around No increase in cuttings when sweep came back Obtain Slow Pump Rates.;POOH on Elevators f/ 8488't/ 7848' Pulled tight 30k over worked a few times Kelly Up and BROOH U 7555' 240 gpm 40 rpm.; Hauled 83 bbls solids to KGF G&I Cumulative Solids 1295 bbls Hauled 84 bbls Fluid to KGF G&I Cumulative Fluid 2351 bbls Daily Losses down Hole 0 bbls Cumulative Losses Down Hole 371 bbls Daily Metal 0 lbs Cumulative Metal 2 Has 7/15/2019 Cont pulling up hole on elevators to from 7555' to 7434'.;Sewiced rig and topdrive, inspected driveline bolts and brake Iinkage.;TIH on elevators from 743W to 8321' with no issue. At 8321' set down a couple times, MU topdrive, filled pipe, washed and reamed down to 8488' at 262 gpm-2450 psi, 40 rpm.;Resumed drilling 6 3/4" hole from 8488' to 8641', rot wob 3-13K, 277 gpm-2830 psi, 70 rpm -10,000 fUlbs on bott torque, 11 to 120 ft/hr ROP, MW 11.1/vis 52, ECD's at 12.3 ppg, BGG 55 units, max gas 2533 units at bottoms up after wiper trip to bottom. Added 1 drum NXS lube to suction pit.;Cont drilling 6 314" hole from 8641' to 8879', rot wob 8-11 K. 277 gpm-2915 psi, 75 rpm -9839 ft/lbs on bott torque, 46 to 94 R/hr ROP. Sliding wob 12K, 277 gpm-3079 psi, 389 to 428 psi diff, 18 to 100 ft/hr ROP, increased MW from 11.1 to 11.3 ppg/vis53, ECD's at 12.4 ppg, BGG 177, max 831 units.;Pumped 20 bbl hi -vis nutplug condet sweep at 8823' to see if ROP changed. Seemed to help for a while with ROP.;Cont drilling 6 3/4" hole from 8879' to 9049', pumped a 21 bbl Hi -vis sweep w/ walnut & condet @ 8947', had 5% increase in cuttings, got SPR's. P/U-110K S/O-821K ROT -82K GPM -280 SPP -2947 psi WOB-5/15K T/Q-9/11 K RPM -80/60 Max gas of 1287 units. Cleaned suction header on MP #1 while off Iine.;Cont. drilling 6 3/4" hole F/9049' -T/9304', lost swab in MP #2 (blue lightning), switched to MP #1, cont. drilling ahead F/9304' -T/9416' short trip depth. P/U-110 S/0-82 ROT -96 WOB-10 GPM -280 RPM -60 SPP -2900 psi Diff -350.; Pumped a 20 bbl Hi -vis sweep w/ walnut, due to higher back ground gas, made decision to weight up system to 11.5 ppg before wiper trip at current time. Distance to well plan 20.33' 18.53' Low 8.36' Right.;Hauled 84 bbls solids to KGF G&I Cumulative Solids 1379 blots Hauled 84 bbls Fluid to KGF G&I Cumulative Fluid 2435 bbls Daily Losses down Hole 0 bbls Cumulative Losses Down Hole 371 bbls Daily Metal 0 b Cumulative Metal 2lbs 7/16/2019 Cont to circ 20 bbl hi -vis nutplug sweep around and cont to circ and increase mud weight from 11.3 to 11.5 ppg. 281 gpm-2611 psi, 70 rpm -9417 ft/lbs off bolt torque, BGG 43 units.;Obtained SPR's at 9416' with 11.5 ppg mud in/out. Pull wiper trip from 9416' up to 9223' and pulled 30K over. Pumped up hole with no issue. Pulled on elevators up to 8710' and had 25K overpull. Pumped up hole to 8674', then pulled on elevators to 8469' with no issue. Initial up wt 124K.;Sewiced rig and topdrive, greased crown.;TIH on elevators from 8489' to 9354' with no issue. MU last stand, MU topdrive, filled pipe, washed reamed to bottom at 9416'.;Cont drilling 6 3/4" hole from 9416'to 9480' 264 gpm 2450 psi 55 rpm 10900 tq on 9000 off 11.5 ppg 12.68 ppg ECD 10k WOB PUW 110k SOW 82k ROT 96k.;Continue Drilling 6 3/4" Hole H 9480' tf9700' 265 GPM 2640 PSI 75 RPM 12000 tq on 10000 tq off 11.55 ppg 12.5 ppg ECD 6-10k WOB.;Cont. drilling 6 3/4" hole F/9700' -T/9947'@ 265 -GPM -2795 PSI 80 -RPM WOB-5-12K TQ -11/12.5K, Max gas -310 units, P/U-122K S/O-91 K ROT- 104K.;Held PTSM, crew change, cont. drilling 6 3/4" hole F/9947' to TD @ 10,210', pumped 20 bbl Hi -Vis sweep w/ walnut. GPM -265 WOB-10 RPM -70 SPP - 2800 psi DIFF -480 PIU -124K S/0 -88K ROT -104K Max gas 1004 units. Distance to well plan 28.02' 27.44' High 5.68' Right.; Hauled 56 bbls solids to KGF G&I Cumulative Solids 1435 bbls Hauled 56 blots Fluid to KGF G&I Cumulative Fluid 2491 bbls Daily Losses down Hole 0 bbls Cumulative Losses Down Hole 371 bbls Daily Metal 0 lbs Cumulative Metal 2 lb 711712019 Finish Circulating out Hi Vis Sweep, No increase in cuttings on bottoms up.;POCH on elevators f/ 10210' t/ 9954' started overpulling 40k, Kelly up and pump out of the hole 250 gpm f/ 9954' V 9414' able to pull on elevators pull V 9414' V 7376' started over pulling 30-401k Pull out w/ pumps f/ 7376' t/ 6783' Pulling tight and packing off.;Circulate bottoms up while reciprocating pipe, 250 gpm 2100 psi 40 rpm no increase in cuttings on bottoms up.;POOH wl pumps 250 gpm 2100 psi it 6783't/ 6318' able to pull on elevators U 59801.;Service rig and top drive.;RIH f/ 5980' U 7303'took weight unable to work down 40k set down, Kelly up fill pipe Wash and Ream through tight spot until able to slide trough freely, Continue RIH V 7303't/ 8896' set down took weight 30k unable to work through, Kelly up and fill pipe Wash and ream down through tight spot.;F/8996'-719045' until able to slide through freely 2562 units of gas on bottoms up.;Cont. TIH F/9045'-10,164', washed through tight spot F/9045' -T/9106, had 25K set down @ 9263', work through same. P/1.1 -160K SIO -80K ROT -105K. Calculated pipe displacement=30.2, Measured=27.5, Difference=2.7 bbls Lost.;Filled pipe, washed down F/10,164'to TD @ 10,210, tagged fill @ 10,183'.;Pumped 20 bbl Hi - Vis sweep w/ walnut, staged up GPM/ROT to 270 GPM, SPP -2800-2425 psi, ROT -80 TQ-12/13.SK TQ -11/13.5K, had 150% increase in cuttings on sweep at surface. Added two drum of NXS lube to system for running casing.;Got SPR's, Flow checked (ok), TOOH F/10,210' -T/8740', worked through tight spot on elevators @ 9010'30K over.;Held PTSM, crew change, cont. TOOH F/8740' -T/5943', washed through tight spot F/6183' -T/6132', had a 40K overpull @ 6176', GPM -247 RPM40 SPP -1780 psi, pulled into shoe w1 no issues, pumped 2 ppg over MW dry job, blow down TD.;Cont. TOOH F/5943' -T/1545', P/U-30K S/0 - 28K. 2.6 bbls over calculated pipe displacement.; Hauled 56 bbls solids to KGF G&I Cumulative Solids 1491 bbis Hauled 56 bbls Fluid to KGF G&I Cumulative Fluid 2547 bbls Daily Losses down Hole 0 bbls Cumulative Lasses Down Hole 371 bbls Daily Metal 0lbs Cumulative Metal 2 lbs 7/18/2019 Continue POOH f/ 1545't/ 730'.;Stand Back HWDP, Jars Stand and collars unload sources, download MWD, UD BHA Break Bit 1 -1 -CT -G -X -IN -WT -TD, Break down remaining BHA components and UD.;Clean and Clear Rig Floor, Pull wear ring.;Set Test Plug and R/U U test GOP's, Flood stack and Lines, bleed air from lines shell test U 2500 psi.;Test BOP's as per state regulations, State Inspector Jim Regg waived witness of test, All test t/ 250/4000 psi w/ 4.5" Test Jt, Annular tested V 250/2500 psi, Total Safety Tested all gas alarms, preformed BOP test & had 2 Fail/Pass. Test #8 -Low test -test pump regulator was backed down causing;it to drop in pressure, bled down & re-tested(Pass). Test #10- Electric choke -leak on test manifold, tightened fitting on transducer (Pass).;Pulled test plug, set wear ring, RID testing equip, blew back choke manifold & lines, closed casing valve, filled stack.;R/U SLB wireline while monitoring hole, static loss rate=l BPH, started RIH wl SLB wireline tool Sonic Scanner XPT (98.3'), T/5009.;Held PTSM, crew change, cont. RIH w/ SLB wireline Sonic Scanner XPT tool, tagged up @ 7835', 7923', & 8270', work through all three, RIH to bottom, tagged at 10,205' WLM, logged up hole 300', RIH to bottom, made re -run to ensure data was correlating, logging up F/70,205'-T/5958',;currently RIH to collect pressure sample F/9745' -T/6069' (32 total). Static losses slowed to 114 BPH. Changed out oil in floor motor, Gen #1, & Gen #3, installed new float valve in de -gasser vessel & functioned (ok), cant. cleaning & housekeeping around rig, prepping for up coming rig move.;Hauled 25 bbls solids to KGF G&I Cumulative Solids 1516 bbls Hauled 65 bbis Fluid to KGF G&I Cumulative Fluid 2612 bbls Daily Losses down Hole 0 bbls Cumulative Losses Down Hole 371 bbls Daily Metal 3 lbs Cumulative Metal 5 lbs 7/19/2019 Take Pressure Samples @ 9745' 9677' 9559' 9508' 9454' Tools started sticking took 6k over pull to break free work string multiple times, Pull up the hole V 8720 and attempted to take pressure tools sticking, Pulled up hole to 7363' attempt to take pressures, tools sticking work tool string to get;free, over pull 6k tools came free, decision made to POOH, POOH f/ 7363' V surface, RID ELine , Release Eline Unit,:WU Clean Out BHA, bit, bit sub, and Stab, RIH w/ collars, HWDP, and Jars T/ 6213', cont. RIH out derrick to shoe, filling pipe every 2500'.;CBU at the shoe, GPM -275 SPP -1250, max gas at BU was 487 units, hung blocks and slip & cut drill line (cut 70' of drill line), preformed weekly PM on brakes, unhung blocks & calibrated hook Ioad.;Cont. TIH F16213' -T/8260', filled pipe & CBU, staged pump out to 270 -GPM SPP -1325-1600 psi ROT -80 TQ -9-10K P/U-120K S/0-80 ROT -95, max gas was 2882 un@s.;Cont. TIH F/8260' - T/10,126, had 30K set down @ 8313', washed & reamed through, and one @ 9750', worked through on elevators.;Filled pipe, staged pump up to 276 -GPM ROT -70 SPP -1685 psi, washed & reamed F/10,126' -T/10,210', P/U E -Kelley to tag fill @ 10,194' (16' of fill), P/U-135K S/0 -80K ROT -105K. Calculated pipe displacement=74.9 bbis Measured=69.3 bbls Difference=5.6 bbls Iost.;Held PTSM, crew change, pumped 20 bbl Hi -Vis sweep, hole unloaded wl coal & sand @ BU, had a 30% increase in cuttings at STS, and sweep came back 16 bbls late. Had a max gas of 2972 units.;pumped an additional BU to ensure hole was good & clean for running casing. Flow check, 114 bbl per/hr loss rate.;Started TOOH racking back in derrick F/10,210'-9192', started pumping OOH @ 250 GPM due to swabbing F/9192' -T/8642', well quit swabbing, started POOH on elevators racking back in derrick F/8642' to current depth of 7404'.;Hauled 5 bbls solids to KGF G&I Cumulative Solids 1521 bbls Hauled 50 bbls Fluid to KGF G&I Cumulative Fluid 2662 bbls Daily Losses down Hole 0 bbls Cumulative Losses Down Hole 371 bbls Ir--d-th— Daily Metal 3lbs Metal 5 Has 7/20/2019 Continue POOH 117404' 115903' standing back stands in derrick, Pump Dry Job.;POOH f/ 5903' V Surface UD DP and BHA Release Directional Drillers.;Service Rig and Top Drive.;RIH w/ remaining DP V Derrick V 5033' Pump Dry Job.;POOH UD DP f/ 5033' V Surface, vacuuming footballs through pipe prior to UD. Pipe displacement for trip, Calculated=37.3bbls Measured=39.3 bbls Difference=2.0 bbls lost.; Held PTSM, crew change, cleaned & cleared rig floor, drained stack, pulled wear ring, Dummy run 4.5" casing hanger, hanger set length=18.45', UD hanger, cleared catwalk, staged long bails, put centralizers on rig floor, R/U Weatherford power tongs, loaded shoe frac & 15 jts of 4.5" casing on rack.;Held PJSM w/ Weatherford & rig crew on running 4.5" casing, P/U & M/U shoe trac, filled shoe trac & checked floats (ok), cont. RIH w/ 4.5" TXP BTU 12.6 ppf casing, torqueing each connection to 6170K. Getting calculated pipe displacement, current depth of 2656'.;Hauled 0 bbls solids to KGF G&I Cumulative Solids 1521 bbls Hauled 0 bbls Fluid to KGF G&I Cumulative Fluid 2662 bbls Daily Losses down Hole 0 bbls Cumulative Losses Down Hole 371 bbls Daily Metal 3 lbs Cumulative Metal 5 lbs 7/21/2019 Continue RIH w/ 4/5" L-80 12.6# DWC Casing f/ 2656' U 5930' Hole taking correct displacement.;Circulate and condition mud stage pumps U 5 bpm 470 psi 12 ppg out 11.6 ppg in, circulate till balanced 11.6ppg in/out.;Continue RIH w/ 4.5" Casing 115930' tt 8603' Hole taking correct displacement no issues observed.;Circulate and condition mud stage pumps U 5 bpm 620 psi 70k PUW 58k SOW until 11.6 ppg in and out 900 units of gas.;RIH f/ 8603'118898' set down 20k.;Work String establish circulation 5 bpm 950 psi, max over pull observed 20k, taking weight work string U 8903', Continue working string setting 40- 50k down no over pull, attempt U wash down increase in pump pressure while setting down pump pressure washing off no footage made continue working;string setting 40-601k down weight, Pump lube pill around, full returns acting like setting on a ledge, prep to pull casing, build dryjob, unload casing racks, while driller continued to work string, broke through, work string through tight spot no issues. Load casing racks remove casing swedge.;Continue RIH f/ 8903' U 10205' WU hanger land on hanger, R/U circulating equipment. PIU -85K S/0 -55K, Calculated pipe displacement --45.6 Measured=44.7 Difference=.9 bbls lost during trip.;Circulate and condition mud stage pumps U 5 bpm 720 psi, spot in Halliburton Cementers, max gas 337 units, RID casing equip & rig bails, R/U long bails & elevators, R/U cement equip., shut down MP, loaded plugs & installed cement head on landing jt, R!U hard line & hoses to cement head & manifold;Started circ. through cement head, staged up to 5 bpm, held PJSM w/ Halliburton cementer, Peak, & rig crew, shut down & bled off rig pump.;Pumped 5 bbls of water to Fluid pack & gush lines. pressure tested lines, 500 psi Low & 4000 psi High (ok).;Pumped 23 bbls of 12.5 ppg spacer @ 4 bpm, dropped bottom plug, pumped 150 bbls of 12.5 ppg lead cement @ 4 bpm, followed by 35.4 bbls of 15.3 ppg tail @ 4 bpm, displaced w/ 143 bbls of 8.5 / ppg 3% KCL brine @ 5 bpm, slowed to 2 bpm @ 10 bbis away from bumping, bumped plug @ 153 bbls,;calculated displacement was 153.8 bbls, held 3000 -N PP J' psi for 3 mins, bled back 1.5 bbis to truck (Boats held). Lost 4.6 bbls during the job. CIP @ 01:40.;R/D cement lines & head, pulled landing jt, P/U pack off running tool, set primary pack off & back pressure valve, started emptying mud from pits & N/D GOP's @ current time.;Hauled 5 bbls solids to KGF G&I Cumulative Solids 1526 bbis �1I,v Hauled 235 bbls Fluid to KGF G&I Cumulative Fluid 2897 bbls Daily Losses down Hole 0 bbis Cumulative Losses Down Hole 371 bbis Daily Metal 0lbs Cumulative Metal 5lbs 7/22/2019 N/D BOP stack, N/U Dry Hole tree and test void seals t/ 5000 psi, Pull BPV and test Casing t/ 3500 psi Good test. set BPV, Secure tree.;Continue cleaning pits, break down and clean pumps, start breaking down back yard, remove top drive prep to scope derrick.;Unhook mods, prep to move rig finish removing and installing in cradle, scope derrick down, continue prep to move rig.;Hung off blocks, unspooled drill line, hung & tied off Kelley hose, service loop, & drill line in mast, prepped to lay over mast, disconnected mast cylinders, unpinned mast from sub & laid down mast.;RID & disconnected HYD lines and power cords to derrick, RID brake linkage & gas buster, prepped to scope dog house, and cont. to work on cleaning mud pits, laid out felt, liner, & set rig mats at CLU #14 for rig move @ 07:OO.;Finished cleaning pits, lowered degasser, laid down pit hand rails, folded up pit walkways, disconnected equalizer lines between pits, laid over gas buster, emptied rig water tank, lower dog house in water tank, RID & moved out service shacks. Rig released @ 0600 hrs 7/23/2019.;Hauled 7 bbls solids to KGF G&I Cumulative Solids 1533 bbls Hauled 269 bbls Fluid to KGF G&I Cumulative Fluid 3166 bbls Daily Losses down Hole 0 bbls Cumulative Losses Down Hole 371 bbls Daily Metal 0lbs Cumulative Metal 5 Ib .7 Activity Date Ops Summary Hilcorp Energy Company Composite Report Well Name: KEU KU 24-05B and tag at 10,056'. POOH had no problems.,RIR w/CBL tool and tie into OHL, Tagged at 10,068'. Ran CBL and found top of cement at 5025'. FL 46. Good Field: Kenai Gas Field 8/2/2019 County/State: Kenai, Alaska Rig up coil BOP's on well. Test BOP'S 250 psi low and 3000 psi high with tri-plex (no failures). Stab pipe into injector head. Finish rigging up hard lines. Will (LAT/LONG): start blow down in the morning. Secure well. 8/3/2019 avation (RKB): tubing and up coil. WHP 1200 psi at 500 SCF and getting back approx. 3/4 to 1 bpm fluid. Went on down hole reversing out and tag at 10,070' CTM. Pick up API #: 50-133-20683-00-00 Spud Date: p Job Name: 1912715C KU 24-05B Completion Contractor thru,spool to tank and it was not plugged. We bled 4.5" tubing down to 120 psi as we came out of hole., Rig down coil tubing. Will get spooler from West side to C i AFE #: transferring from tanker. SLB will be calling Air Liquid to come get tanker. Should be approx, 47 bbls left in hole after getting back 107 bbls. (3100' left in hole) AFE $: PTW. JSA with SLB and Cruz Crane operator.,MIRU SLB CTU 1. with 1.75" CT.,PT BOPE 250/3000 psi. 24 hr BOPE test witness notification sent 8/8/19 .7 Activity Date Ops Summary 7/30/2019 Sign in. Mobs to location. PTW, JSA and SIMOPS with welders. Rig up lubricator PT to 250 psi low and 3000 psi high. TP - 0 psi,RIH w/CCL, 3.75" GR/JB and tag at 10,056'. POOH had no problems.,RIR w/CBL tool and tie into OHL, Tagged at 10,068'. Ran CBL and found top of cement at 5025'. FL 46. Good cement where we are coinq to perf. Send field log to town. POOH,Rig down off well. Load up lub and tools. Clean up work area 8/2/2019 Sign in. Mobe to location. PTW and JSA. Finish up welding grate. AOGCC Jim Regg waived witness for BOP test,Spot coil equipment, tank and N2 tanker. Rig up coil BOP's on well. Test BOP'S 250 psi low and 3000 psi high with tri-plex (no failures). Stab pipe into injector head. Finish rigging up hard lines. Will start blow down in the morning. Secure well. 8/3/2019 Sign in. SLB coil mobe to location. PTW and JSA. Pick up injector PT 250 psi low and 3000 psi high.,RIH w/1.75" coil tubing to 3000' and start N2 down 4.5" tubing and up coil. WHP 1200 psi at 500 SCF and getting back approx. 3/4 to 1 bpm fluid. Went on down hole reversing out and tag at 10,070' CTM. Pick up to 10,060',well head pressure climbed to 2500 psi at 500 scf and getting about 3/4 of bbl. After SLB got 107 bbls of fluid back we last returns. Shut pump off and picked up to 9970' and found 2 pin holes and 9995',1 more pin hole in coil tubing. Shut job down and had a tailgate meeting on our options. Spool is self contained and also there was a liner under coil unit. Field foreman, lead op and myself call town and discussed options. Posted a person at each end of pad and when a truck needed to go by unit we shut down until truck was off pad. Got coil spooled back up to swab. Rigged up to see if coil was plugged. Pumped N2 thru,spool to tank and it was not plugged. We bled 4.5" tubing down to 120 psi as we came out of hole., Rig down coil tubing. Will get spooler from West side to spool another 1.75" coil tubing on reel. Secure welLSLB Pumped 2225 gals of N2 total. SLB will have a total of 2100 gal of N2 on their pump truck after transferring from tanker. SLB will be calling Air Liquid to come get tanker. Should be approx, 47 bbls left in hole after getting back 107 bbls. (3100' left in hole) 8/9/2019 PTW. JSA with SLB and Cruz Crane operator.,MIRU SLB CTU 1. with 1.75" CT.,PT BOPE 250/3000 psi. 24 hr BOPE test witness notification sent 8/8/19 15:09. Witness waived by Jim Reqq on 8/8/19 15:53 . BOPE test com late. N2 pump and transport will be delivered 0800. A/1 0/2019 PTW, JSA with SLB and Cruz.,Pick injector head. Make up 10' lubricator. Make up 1.90 coil connector. 46" x 1.75" straight joint and ball drop 1.75" Nozzle. .✓ Stab on well. PT stack 250/3000 psi.,RIH. Pervious N2 lift prior to pipe pin hole there was 107 out of 156 bbls returned. Fluid level calculated to be at 6760'. 6500' online N2 at 1000 scf/min. Reversing out. Pumping N2 down tubina and taking returns up 1.75" coil. Unload 47.6 bbls of fluid. Pumped 330,000 scf.,POOH to surface bleeding down WHP. Tagged up close swab 650 psi SITP of N2.,Rig down CTU 1. 8/11/2019 Sign in. Mobs to location. PTW and JSA. Spot and rig up AKE-Line equipment. Arm gun. Well head flange was leaking when attempting pressure test. Field gets wrenches and tightened up flange. PT to 250 psi low and 3000 psi high. TP - 680 psi,RIH w/2 -7/8"x17' HC Razor, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Get ok to pert from 9737'to 9754with 680 psi on tubing. Spotted and fired gun. After 5 min - 681 psi, 10 min - 680.9 psi and 15 min - 680.6 psi. POOH. Fired gun at 1210 his. All shots fired and gun was dry. D4D sand„RIH w/2 -7/8"x26' HC Razor, 6 spf, 60 deg phase and tie into Y/ OHL. Run correlation log and send to town. Get ok to pert from 9660' to 9686 with 676.8 psi on tubing. Spotted and fired gun. After 5 min - 677 psi, 10 min - P 676.2 psi and 15 min - 675.3 psi. POOH. Fired gun at 1450 his. All shots fired and gun was dry. D48 sand.,RIH w/2 -7/8"x24' HC Razor, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Was told to add 4' to our correlation log. Added 4 to log. Spotted gun from 9492' to 9516' and fired gun with 588.6 psi on tubing at 1730 hrs. After 5 min - 582.0 psi, 10 min - 576.7 psi and 15 min - 567.7 psi. POOH. All shots fired and gun was dry. D3B sand.,RIH w/2 -7/8"x17' HC Razor, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Get ok to pert from 9446'to 9463' with 436.5 psi on tubing. Spotted and fired gun. After 5 min - 431.3 psi, 10 min - 428.2 psi and 15 min - 425 psi. POOH. Fired gun at 1937 hrs. All shots fired and gun was dry. D3A sand., Rig down lubricator and secure well. Turn well back over to field. Rig down rest of equipment. Clean up work area. 8/16/2019 Sign in. Mabe to location. PTW and JSA. Spot and rig up equipment. PT lubricator to 250 psi low and 3500 psi high. TP - 520 psi.,RIH w/GPT tool and tie into land CBL log. Ran correlation log and found fluid at 9518'. Send log to town. POOH.,RIH w/2 -7/8"x25' Razor HC, 6 spf, 60 deg phase perf gun and tie into CBL log. Run correlation log and send to town. at ok to orf from 9165' to 9190' with 506 p, on tub g. Spotted and fired gun. After 5 min - 503 psi, 10 min - 502 psi 15 min - 500 psi.. POOH. All shots fired and gun was dry.,Rlq down lubricator and turn well over to field. Hilcorp Alaska, LLC Kenai Gas Field KGF 41-7 Pad KU 24-05B 501332068300 Sperry Drilling Definitive Survey Report 23 July, 2019 HALLIBURTON Sperry Drilling Halliburton Definitive Survey Report Companv: Hilcorp Alaska, LLC Local Coordinate Reference: Well KU 24-05B Project: Kenai Gas Field TVD Reference: Plan @ 84.10usft (HEC 169) Site: KGF 41-7 Pad MD Reference: Plan @ 84.10usft (HEC 169) Well: KU 24-05B North Reference: True Wellbore: KU 24-0513 Survev Calculation Method: Minimum Curvature Design: KU 24-05B Database: NORTH US+CANADA Protect Kenai Gas Field Map System: US State Plane 1927 (Exact solution) Svstem Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Well KU 24-05B, 519' FNL & 771' FEL Audit Notes: Well Position +N/S 0.00 usft Northing: 2,361,491.39 usft Latitude: 60° 27'29.166 N ACTUAL +El -W 0.00 usft Eastinq: 275,130.28 usft Longitude: 151" 14'44.555 W Position Uncertainty 0.50 usft Wellhead Elevation: usft Ground Level: 66.10 usft Wellbore KU 24-05B Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) P) (nn BGGM2018 513/2019 15.38 73.41 55,187.07651008 Design KU 24-056 Date 7/23/2019 Audit Notes: To Map Map Version: 1.0 Phase: ACTUAL Tie On Depth: 18.00 Vertical Section: Depth From (TVD) +NIS +El -W Direction 386.89 (usft) (usft) (usft) (°) 1,629.29 18.00 0.00 0.00 68.36 6,031.47 10,175.19 MWD+IFRI+MS+Saq(3)(KU 24-05B) 2_MWD+IFRI+MS+Sag Survey Program Date 7/23/2019 From To Map Map (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 201.83 325.62 MWD -Intern Azi+Sag (KU 24-05B) 2_MWD_Interp Azl+Sag H003Mb: Interpolated azimuth +sag correction 06/13/2019 386.89 1,543.89 MWD+IFRI+MS+Sag(1)(KU 24-058) 2_MWD+IFRI+MS+Sag A010Mb: IFR dec&multi-station analysis +sag 07/02/2019 1,629.29 5,945.26 MWD+IFRI+MS+Saq(2)(KU 24-05B) 2_MWD+IFRI+MS+Sag A010Mb: IFR dec & multi -station analysis +sag 07/0812019 6,031.47 10,175.19 MWD+IFRI+MS+Saq(3)(KU 24-05B) 2_MWD+IFRI+MS+Sag A010Mb: IFR dec&multi-station analysis+sag 07/14/2019 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +FJ -W Northing Essting DLS Section (usft) (1) (') (usft) (usft) (usft) (usft) (ft1 lft1 ('/1001 Ift) Survey Tool Name 18.00 0.00 0.00 18.00 -66.10 0.00 0.00 2,361,491.39 275,130.28 0.00 0.00 UNDEFINED 201.83 0.12 132.76 201.83 117.73 -0.13 0.14 2,361,491.25 275,130.41 0.07 0.08 2_ MWD_ Interp Azi+Sag(1) 230.89 0.15 98.65 230.89 146.79 -0.16 0.20 2,361,491.23 275,130.47 0.29 0.13 2_MWD Interp Azi+Sag(1) 264.85 0.28 141.40 264.85 180.75 -0.23 0.30 2,361,491.15 275,130.57 0.58 0.19 2 MWD_Interp Azi+Sag(1) 325.62 1.22 81.64 325.61 241.51 -0.25 1.03 2,361,491.12 275,131.30 1.82 0.86 2_ MWD_ Interp Azi+Sag(1) 386.89 3.83 83.87 386.82 302.72 0.06 3.71 2,361,491.38 275,133.99 4.26 3.47 2_MWD+IFR1+MS+Sag(2) 448.55 5.21 85.91 448.29 364.19 0.48 8.55 2,361,491.71 275,138.83 2.25 8.13 2_MWD+IFRI+MS+Sag(2) 50934 6.29 87.07 508.77 424.67 0.85 14.63 2,361,491.96 275,144.92 1.79 13.91 2_MWD+IFRI+MS+Sag(2) 571.84 7.27 88.20 570.83 486.73 1.15 22.00 2,361,492.12 275,152.29 1.58 20.87 2_MWD+IFRI+MS+Sag(2) 631.82 7.88 85.44 630.29 546.19 1.59 29.89 2,361,492.42 275,160.19 1.18 28.37 2_MWD+IFRI+MS+Sag(2) 694.99 9.18 86.52 692.76 608.66 2.24 39.24 2,361,492.89 275,169.55 2.07 37.30 2_MWD+IFRI+MS+Sag(2) 7/232019 7:09:OOPM Pape 2 COMPASS 5000.15 Build 91 Company: Project: Site: Well: Wellbore: Design: Survey Hilcorp Alaska, LLC Kenai Gas Field KGF 41-7 Pad KU 24-058 KU 24058 KU 24-05B MD Inc (usft) V) 755.64 9.92 817.07 10.38 878.25 10.67 940.78 11.03 1,001.12 11.36 1,064.30 1268 1,125.01 13.57 1,187.38 14.51 1,249.67 15.50 1,313.06 15.96 1,375.16 17.49 1,437.62 18.15 1,500.12 18.56 1,543.89 19.03 1,629.29 18.80 1,690.29 19.24 1,752.69 19.11 1,816.59 18.38 1,878.95 18.48 1,941.53 18.58 2,003.61 18.34 2,065.81 18.43 2,127.16 18.37 2,189.38 18.58 2,251.38 18.19 2,313.53 18.53 2,376.44 18.04 2,436.85 18.23 2,499.89 18.61 2,561.72 18.74 2,623.49 18.43 2,68522 18.64 2,747.07 19.04 2,809.32 17.82 2,871.25 17.95 2,932.92 18.24 2,995.66 18.65 3,058.96 17.44 3.120.82 17.77 3,183.53 17.99 Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survev Calculation Method: Database: Well KU 24-058 Plan @ 84.10usft (HEC 169) Plan @ 84.10usft (HEC 169) True Minimum Curvature NORTH US + CANADA 7/23/2019 7:09:OOPM Page 3 COMPASS 5000.15 Build 91 Map Map Vertical Azi TVD TVDSS +NIS +E/ -W Northing Easting DIS Section (°) (usft) (usft) (usft) (usft) Ifti Bill r/100.) ftli Survey Tool Name 82.25 752.57 668.47 3.24 49.25 2,361,493.70 275,179.57 1.69 46.97 2_MWD+IFR1+MS+Sag(2) 77.92 813.04 728.94 5.11 59.90 2,361,495.37 275,190.26 1.45 57.56 2_MWD+IFR1+MS+Sag(2) 75.58 873.19 789.09 7.68 70.78 2,361,497.73 275,201.18 0.84 68.62 2_MWD+IFR1+MS+Sag(2) 69.01 934.60 850.50 11.26 81.97 2,361,501.10 275,212.44 2.06 80.34 2_MWD+IFRI+MS+Sag(2) 67.62 993.79 909.69 15.59 92.85 2,361,505.22 275,223.40 0.71 92.06 2_MWD+IFRI+MS+Sag(2) 62.88 1,055.59 971A9 21.12 104.78 2,361,510.52 275,235.43 2.61 105.18 2_MWD+IFR1+MS+Sag(2) 62.63 1,114.71 1,030.61 27.44 117.03 2,361,516.60 275,247.80 1.47 118.90 2 MWD+IFRI+MS+Sag(2) 60.41 1,175.22 1,091.12 34.66 130.33 2,361,523.57 275,261.23 1.74 133.92 2_MWD+IFR1+MS+Sag(2) 60.02 1.235.38 1,151.28 42.67 144.32 2,361,531.32 275,275.37 1.60 149.89 2_MWD+IFR1+MS+Sag(2) 59.49 1,296.40 1,212.30 51.33 159.17 2,361,539.69 275,290.38 0.76 166.88 2_MWD+IFRI+MS+Sag (2) 61.51 1,355.87 1,271.77 60.11 174.73 2,361,548.18 275,306.10 2.64 184.58 2_MWD+IFR1+MS+Sag(2) 60.25 1,415.34 1,331.24 69.42 191.42 2,361,557.17 275,322.97 1.22 203.53 2_MWD+IFR1+MS+Sag(2) 58.77 1,474.66 1,390.56 79.41 208.38 2,361,566.83 275,340.11 0.99 222.97 2_MWD+IFR1+MS+Sag(2) 58.35 1,516.09 1,431.99 86.76 220.41 2,361,573.96 275,352.28 1.12 236.67 2_MWD+IFRI+MS+Sag(2) 58.71 1,596.88 1,51278 101.22 244.02 2,361,587.96 275,376.16 0.30 264.15 2_MWD+IFRI+MS+Sag(3) 57.98 1,654.55 1,570.45 111.65 260.94 2,361,598.08 275,393.27 0.82 283.72 2_MWD+IFRI+MS+Sag(3) 56.76 1,713.49 1,629.39 122.70 278.20 2,361,608.80 275,410.74 0.68 303.84 2_MWD+IFR1+M8+Sag(3) 59.91 1,774.00 1,689.90 133.48 295.67 2,361,619.25 275,428.40 1.95 324.05 2_MWD+IFRI+MS+Sag(3) 60.81 1,833.16 1,749.06 143.23 312.80 2,361,628.67 275,445.72 0.48 343.58 2_MWD+IFR1+MS+Sag(3) 59.32 1,892.50 1,808.40 153.16 330.04 2,361,638.27 275,463.14 0.77 363.26 2_MWD+IFRI+MS+Sag(3) 62.70 1,951.39 1,867.29 162.68 347.22 2,361,647.47 275,480.50 1.77 382.74 2_MWD+IFR1+MS+Sag (3) 62.96 2,010.41 1,926.31 171.64 364.67 2,361,656.09 275,498.12 0.20 402.27 2_MWD+IFR1+MS+Sag(3) 61.55 2,068.62 1,984.52 180.66 381.81 2,361,664.78 275,515.42 0.73 421.52 2_MW0+IFR1+MS+Sag(3) 61.14 2,127.64 2,043.54 190.11 399.11 2,361,673.91 275,532.90 0.40 441.09 2MWD+IFRI+MS+Sag(3) 60.66 2,186.47 2,102.37 199.62 416.20 2,361,683.09 275,550.16 0.67 460.48 2_MWD+IFR1+MS+Sag(3) 59.51 2,245.46 2,161.36 209.39 433.17 2,361,692.53 275,567.31 0.80 479.85 2_MWD+IFRI+MS+Sag(3) 61.74 2,305.19 2,221.09 219.07 450.36 2,361,701.89 275,584.68 1.36 499.41 2_MWD+IFR1+MS+Sag(3) 61.47 2,362.60 2,278.50 228.01 466.90 2,361,710.52 275,601.39 0.34 518.08 2 MWD+IFRI+MS+Sag(3) 60.82 2,422.41 2,338.31 237.63 484.35 2,361,719.80 275,619.01 0.69 537.84 2_MWD+IFR1+MS+Sag(3) 60.84 2,480.99 2,396.89 247.27 501.63 2,361,729.12 275,636.48 0.21 557.47 2_MWD+IFR1+MS+Sag(3) 62.62 2,539.54 2,455.44 256.60 518.97 2,361,738.11 275,653.98 1.05 577.02 2_MWD+IFR1+MS+Sag(3) 63.14 2,598.06 2,513.96 265.54 53644 2,361,746.73 275,671.62 0.43 596.55 2_MWD+IFRI+MS+Sag(3) 61.53 2,656.60 2,572.50 274.82 554.12 2,361,755.67 275,689.47 1.06 616.41 2_MWD+IFR1+MS+Sag (3) 62.54 2,715.66 2,631.56 284.05 571.50 2,361,764.57 275,707.02 2.03 635.97 2_MWD+IFRI+MS+Sag(3) 62.26 2,774.59 2,690.49 292.86 58838 2,361,773.06 275,724.04 0.25 654.89 2_MWD+IFR1+MS+Sag(3) 60.78 2,833.22 2,749.12 302.00 605.19 2,361,781.87 275,741.04 0.88 673.90 2_MWD+IFRI+MS+Sag (3) 60.38 2,892.73 2,808.63 311.75 622.48 2,361,791.29 275,758.51 0.68 693.57 2_MWD+IFR1+MS+Sag(3) 62.10 2,952.92 2,86882 321.19 639.66 2,361,800.41 275,775.87 2.09 713.03 2_MWD+IFR1+MS+Sag(3) 61.20 3,011.88 2,927.78 330.08 656.13 2,361,808.98 275,792.50 0.69 731.61 2_MWD+IFR1+MS+Sag(3) 60.65 3,071.56 2,987.46 339.43 672.95 2,361,818.02 275,809.50 0.44 750.70 2_MWD+IFRI+MS+Sag(3) 7/23/2019 7:09:OOPM Page 3 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well KU 24-05B Project: Kenai Gas Field TVD Reference: Plan Q 64.10usft (HEC 169) Site: KGF 41-7 Pad MD Reference: Plan @ 84.10usft (HEC 169) Well: KU 24-058 North Reference: True Wellbore: KU 24-05B Survev Calculation Method: Minimum Curvature Design: KU 24-05B Database: NORTH US+CANADA Survey Map Map vertical MD Inc Azl TVD TVDSS +N/ -S +E1 -W Northing Easting DLS Section (usft) V) (1) (usft) (usft) (usft) (usft) Ift1 rel r/100') !ftt Survey Tool Name 3,245.58 18.19 60.80 3,130.54 3,04644 348.86 689.76 2,361,827.12 275,826.48 0.33 769.79 2_MWD+IFRI+MS+Sag(3) 3,307.16 18.54 59.92 3,188.99 3,104.89 358.45 706.62 2,361,836.39 275,843.52 0.73 789.01 2_MWD+IFRI+MS+Sag(3) 3,369.89 17.65 63.53 3,248.62 3,164.52 367.69 723.77 2,361,845.31 275,860.84 2.28 808.35 2_MWD+IFR1+M8+Sa9(3) 3,432.11 17.53 63.84 3,307.93 3,223.83 376.03 74062 2,361,853.32 275,877.84 0.24 827.09 2_MWD+IFRI+MS+Sag(3) 3,495.46 17.97 62.92 3,368.26 3,284.16 384.68 757.89 2,361,861.65 275,895.27 0.82 846.33 2_MWD+IFR1+MS+Sag(3) 3,556.35 18.33 62.06 3,426.12 3,342.02 393.44 774.71 2,361,870.09 275,912.25 0.74 865.20 2_MWD+IFRI+MS+Sag(3) 3,617.08 18.58 60.83 3,483.73 3,399.63 402.63 791.59 2,361,878.96 275,929.31 0.76 884.28 2_MWD+IFR1+MS+Sag(3) 3,680.42 18.01 63.30 3,543.87 3,459.7 411.95 809.15 2,361,887.94 275,947.04 1.52 904.04 2_MWD+IFRI+MS+Sag(3) 3,743.76 18.19 63.22 3,604.07 3,519.97 420.81 826.72 2,361,896.46 275,964.78 0.29 923.64 2_MWD+IFR1+MS+Sag(3) 3,805.64 18.54 62.39 3,662.80 3,578.70 429.72 844.06 2,361,905.04 275,982.28 0.71 943.04 2_MWD+IFR1+MS+Sag(3) 3,867.03 18.76 62.83 3,720.97 3,636.87 438.75 861.50 2,361,913.74 275,999.88 0.43 962.58 2_MWD+IFRI+MS+Sag(3) 3,928.52 19.22 62.82 3,779.11 3,695.01 447.89 879.30 2,361,922.54 276,017.85 0.75 982.49 2_MWD+IFR1+MS+Sag(31 3,991.22 18.83 62.56 3,838.39 3,754.29 457.26 897.46 2,361,931.57 276,036.18 0.64 1,002.83 2_MWD+IFR1+MS+Sag(3) 4,053.32 17.48 61.26 3,897.39 3,813.29 466.37 914.53 2,361,940.35 276,053.42 2.27 1,022.06 2_MWD+IFR1+MS+Sag(3) 4,114.68 17.61 60.09 3,955.90 3,871.80 475.43 930.66 2,361,949.10 276,069.72 0.61 1,040.39 2_MWD+IFRI+MS+Sag(3) 4,176.29 18.38 59.61 4,014.50 3,93040 484.99 947.11 2,361,958.35 276,086.35 1.27 1,059.21 2_MWD+IFRI+MS+Sag(3) 4,238.14 18.76 59.64 4,073.13 3,989.03 494.95 964.11 2,361,967.99 276,103.53 0.61 1,078.68 2_MWD+IFR1+MS+Sag(3) 4,299.91 18.18 61.36 4,131.71 4,047.61 504.59 981.13 2,361,977.30 276,120.74 1.29 1,098.06 2_MWD+IFR1+MS+Sag(3) 4,361.80 16.76 62.71 4,190.75 4,106.65 513.30 997.54 2,361,985.71 276,137.30 2.39 1,116.52 2_MWD+IFRI+MS+Sag(3) 4,423.09 16.77 63.37 4,249.43 4,165.33 521.32 1,013.30 2,361,99343 276,153.21 0.31 1,134.13 2_MWD+IFR1+MS+Sag(3) 4,485.42 17.45 62.85 4,309.00 4,224.90 529.62 1,029.65 2,362,001.41 276,169.72 1.12 1,152.39 2_MW0+IFR1+MS+Sag(3) 4,647.46 17.90 62.21 4,368.12 4,284.02 538.30 1,046.36 2,362,009.78 276,186.59 0.79 1,171.13 2_MWD+IFRI+MS+Sag(3) 4,608.37 18.45 62.76 4,425.99 4,341.89 547.08 1,063.21 2,362,018.24 276,203.60 0.95 1,190.03 2_MWD+IFR1+MS+Sag(3) 4,671.10 19.08 62.49 4,485.38 4,401.28 556.36 1,081.13 2,362,027.17 276,221.69 1.01 1,210.10 2 MWD+IFRI+MS+Sag(3) 4,734.11 19.55 62.71 4,544.85 4,460.75 565.95 1,099.64 2,362,036.41 276,240.37 0.75 1,230.84 2_MWD+IFR1+MS+Sag(3) 4,795.49 18.33 61.86 4,602.90 4,518.80 575.21 1,117.27 2,362,045.34 276,258.18 2.04 1,250.65 2_MWD+IFR1+MS+Sag(3) 4,858.29 18.60 62.04 4,662.47 4,578.37 584.56 1,134.83 2,362,054.36 276,275.91 0.44 1,270.42 2_MWD+IFR1+MS+Sag(3) 4,920.32 17.41 59.72 4,721.46 4,637.36 593.88 1,151.58 2,362,063.36 276,292.83 2.24 1,289.42 2_MWD+IFR1+MS+Sag (3) 4,982.08 17.78 59.20 4,780.33 4,696.23 603.37 1,167.66 2,362,072.54 276,309.09 0.65 1,307.87 2_MWD+1FRI+MS+Sag (3) 5,044.57 18.53 59.17 4,839.71 4,755.61 613.34 1,184.38 2,362,082.19 276,326.00 1.20 1,327.09 2_MWD+IFR1+MS+Sag (3) 5,106.39 17.75 60.84 4,898.46 4,814.36 622.97 1,201.05 2,362,091.50 276,342.84 1.52 1,346.13 2_MWD+IFR1+MS+Sag(3) 5,168.12 16.23 62.84 4,957.49 4,873.39 631.49 1,216.94 2,362,099.72 276,358.89 2.64 1,364.05 2_MWD+IFRI+MS+Sag(3) 5,230.72 14.31 68.35 5,017.88 4,933.78 638.34 1,231.92 2,362,106.29 276,373.99 3.84 1,380.49 2_MWD+IFRI+MS+Sag(3) 5,292.95 13.16 74.25 5,078.33 4,994.23 643.10 1,245.88 2,362,110.78 276,388.05 2.91 1,395.23 2_MWD+IFR1+MS+Sag(3) 5,356.10 11.72 80.06 5,140.00 5,055.90 646.16 1,259.12 2,362,113.59 276,401.34 3.02 1,408.66 2_MWD+IFRI+MS+Sag(3) 5,418.13 11.63 80.80 5,200.75 5,116.65 648.25 1,271.50 2,362,115.44 276,413.75 0.28 1,420.94 2_MWD+IFRI+MS+Sag(3) 5,479.67 11.82 74.96 5,261.01 5,176.91 650.88 1,283.71 2,362,117.84 276,426.01 1.95 1,433.26 2_MWD+IFRI+MS+Sag(3) 5,541.69 12.14 72.95 5,321.68 5,237.58 654.44 1,296.08 2,362,121.16 276,438.45 0.85 1,446.07 2_MWD+IFRI+MS+Seg(3) 5.603.25 12.67 71.83 5,381.80 5,297.70 658.44 1,308.68 2,362,124.93 276,451.12 0.95 1,459.26 2_MWD+IFRI+MS+Sag(3) 5,665.61 11.50 77.37 5,442.78 5,358.68 661.93 1,321.25 2,362,128.18 276,463.75 2.64 1,472.23 2 MWD+IFRI+MS+Sag(3) 723/2019 7:09..00PM Paoe 4 COMPASS 5000.15 Build 91 Compamv: Hilcorp Alaska, LLC Project: Kenai Gas Field Site: KGF 41-7 Pad Well: KU 24-05B Wellbore: KU 24-05B Design: KU 24-05B Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well KU 24-058 Plan @ 84.10usft (HEC 169) Plan @ 84.10usft (HEC 169) True Minimum Curvature NORTH US + CANADA 7/23/2019 7:09:00PM Pace 5 COMPASS 5000.15 Build 91 Map Map vertical MD Inc Azi TVD TVDSS +NlS +E/ -W Northing Easting DLS Section (usft) (1) V) (usft) (usft) (usft) (usft) B7 fftl (-1100-) iffl Survey Tool Name 5,725.56 11.74 76.63 5,501.50 5,417.40 664.65 1,333.01 2,362,130.68 276,475.56 0.47 1,484.16 2_MWD+IFRI+MS+Sag(3) 5,788.49 12.20 76.58 5,563.06 5,478.96 667.67 1,345.71 2,362,133.46 276,488.31 0.73 1,497.08 2_MWD+IFR1+MS+Sag(3) 5,850.64 10.88 78.17 5,623.95 5,539.85 670.40 1,357.84 2,362,435.96 276,500.49 2.18 1,509.36 2_MWD+IFR1+MS+Sag(3) 5,911.96 10.91 78.03 5,684.17 5,600.07 672.79 1,369.18 2,362,138.13 276,511.88 0.07 1,520.78 2_MWD+IFR1+MS+Sag(3) 5,945.26 11.01 77.57 5,716.86 5,632.76 674.13 1,375.37 2,362,139.35 276,518.09 0.40 1,527.03 2_MWD+IFR1+1JS+Sag(3) 6,03147 10.91 79.79 5,801.50 5,717.40 6T7.35 1,391.43 2,362,142.26 276,534.21 0.50 1,543.15 2_MWD+IFRI+MS+Sag(4) 6.093.65 11.27 79.89 5,862.52 5,778.42 679.46 1,403.21 2,362,144.15 276,546.02 0.50 1,5%.87 2_MWD+IFR1+MS+Sag(4) 6,156.63 11.26 80.01 5,924.28 5,840.18 681.60 1,415.32 2,362,146.07 276,558.18 0.04 1,566.92 2_MWD+IFR1+MS+Sag(4) 6,216.64 11.36 80.43 5,983.13 5,89983 683.60 1,426.92 2,362,147.85 276,569.81 0.22 1,578.44 2_MWD+IFR1+MS+Sag(4) 6,278.55 10.79 74.48 6,043.89 5,95979 686.17 1,438.52 2,362,150.19 276,581.45 2.06 1,590.17 2_MWD+IFRI+MS+Sag(4) 6,341.55 11.02 71.60 6.105.75 6,021.65 68964 1,449.91 2,362,153.45 276,592.91 0.94 1,602.04 2_MWD+IFR1+MS+Sag(4) 6,403.50 10.72 70.55 6,166.59 6,08249 693.43 1,460.96 2,362,157.03 276,604.03 0.58 1,613.71 2_MWD+IFR1+MS+Sag(4) 6,466.01 10.54 69.65 6,228.03 6,143.93 697.36 1,471.80 2,362,160.75 276,614.94 0.39 1,625.24 2_MWD+IFRI+MS+Sag(4) 6,528.35 11.40 73.73 6,289.23 6,205.13 701.06 1,483.06 2,362,164.24 276,626.27 1.86 1,637.07 2_MWD+IFRI+MS+Sag(4) 6,591+49 11.63 74.30 6,351.10 6,267.00 704.53 1,495.18 2,362,167.49 276,638.45 0.41 1,649.61 2_MWD+IFRI+MS+Sag(4) 6,652.31 11.66 74.45 6,410.66 6,326.56 707.84 1,507.00 2,362,170.57 276,650.34 0.07 1,661.82 2_MWD+IFRI+MS+Sag(4) 6,715.39 11.63 75.59 6,472.45 6,388.35 711.13 1,519.30 2,362,173+63 276,662.69 0.37 1,674.47 2_MWD+IFRI+MS+Sag(4) 6,778.21 11.88 75.01 6,533.95 6,449.85 714.38 1,531.68 2,362,176.64 276,675.13 0.44 1,687.17 2_MWD+IFRI+MS+Sag(4) 6,840.17 11.22 75.53 6,594.65 6,510.55 717.54 1,543.68 2,362,179.57 276,687.19 1.08 1,699.49 2_MWD+IFR1+MS+Sag(4) 6,901.91 10.29 79.29 6,655.31 6,571.21 720.06 1,554.91 2,362,18188 276,698.47 1.89 1,710.86 2_MWD+IFRI+MS+Sag(4) 6,963.40 10.16 80.42 6,715.82 6,631.72 721.99 1,565.66 2,362,183.60 276,709.24 0.39 1,721.56 2_MWD+IFR1+MS+Sag(4) 7,025.38 10.25 80.77 6,776.82 6,692.72 723.78 1,576.49 2,362,185.19 276,720.11 0.18 1,732.29 2MWD+IFR1+MS+Sag(4) 7,087.51 10.13 80.90 6,837.97 6,753.87 725.53 1,587.34 2,362,186.73 276,730.99 0.20 1,743.02 2_MWD+IFRI+MS+Sag(4) 7,149.55 10.09 80.23 6,899.05 6,814.95 727.32 1,598.09 2,362,188.31 276,741.T 0.20 1,753.67 2_MWD+IFRI+MS+Sag (4) 7,211.34 10.12 82.05 6,959.88 6,875.78 728.99 1,608.80 2,362,189.78 276.752.51 0.52 1,764.24 2_MWD+IFR1+MS+Sag(4) 7,271.86 10.65 78.53 7,019.41 6,935.31 730.83 1,619.54 2,362,191.42 276,763.28 1.37 1,774.91 2_MWD+1FR1+MS+Sag(4) 7,335.20 10.77 78.29 7,081.65 6,99755 733.20 1,631.07 2,362,193.57 276,774.86 0.20 1,786.50 2_MWD*IFRI+MS+Sag(4) 7,397.24 10.67 76.87 7,142.60 7,058.50 735.68 1,642.34 2,362,195.84 276,786.17 0.46 1,797.89 2_MWD+IFR1+MS+Sag(4) 7,458.93 10.50 76.74 7,203.24 7,119.14 738.27 1,653.38 2,362,198.22 276,797.25 0.28 1,809.10 2_MWD+IFR1+MS+Sag(4) 7,520.55 11.32 79.17 7,263.75 7,179.65 740.69 1,60.78 2,362,200.42 276,808.70 1.53 1,820.59 2 MWD+IFRI+MS+Sag(4) 7,582.30 11.34 80.84 7,324.30 7,240.20 742.82 1,676.72 2,362,202.32 276,820.68 0.47 1,832.48 2_MWDNFRI+MS+Sag(4) 7,644.33 11.22 81.58 7,385.13 7,301.03 744.69 1,688.71 2,362,203.97 276,832.70 0.35 1,844.31 2_MWD+IFRI+MS+Sag(4) 7,706.41 11.19 82.54 7,446.02 7,361.92 746.36 1,700.66 2,362,205.41 276,844.68 0.30 1,856.03 2_MWD+1FR1+MS+Ssg(4) 7,769.46 11.09 82.43 7,507.89 7,423.79 747.95 1,712.74 2,362,206.78 276,856.78 0.16 1,867.85 2_MWD+IFRI+MS+Sag(4) 7,830.92 11.07 81.45 7,568.20 7,484.10 749.61 1,724.43 2,362,208.21 276,868.50 0.31 1,879.33 2_MWD+IFR1+MS+Sag(4) 7,892.85 10.91 81.75 7,629.00 7,544.90 751.33 1,736.11 2,362,209.71 276,880.21 0.27 1,890.82 2_MWD+IFR1+MS+Sag(4) 7,956.42 10.94 80.87 7,691.41 7,607.31 753.15 1,748.02 2,362,211.31 276,892.15 0.27 1,902.56 2_MWD+IFRI+MS+Sag(4) 8,018.83 10.53 82.38 7,752.73 7,668.63 754.85 1,759.52 2,362,212.79 276,903.68 0.80 1,913.87 2_MWD+IFR1+MS+Sag(4) 8,080.35 11.95 79.99 7,813.07 7,728.97 756.70 1,771.36 2,362,214.42 276,915.56 2.43 1,925.57 2_MWD+IFR1+MS+Sag(4) 8.143.30 12.35 78.96 7,874.61 7,790.51 759.12 1,784.39 2,362,216.59 276,928.63 0.72 1,938.57 2_MWD+IFRI+MS+Sag(4) 7/23/2019 7:09:00PM Pace 5 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Coordinate Reference: Well KU 24-058 Project: Kenai Gas Field TVD Reference: Plan @ 84.10us8 (HEC 169) Site: KGF 41-7 Pad MD Reference: Plan @ 84.10usft (HEC 169) Well: KU 24058 North Reference: True Wellbore: KU 24-056 Survey Calculation Method: Minimum Curvature Dasign: KU 24-05B Database: NORTH US+CANADA Survey 7/23/2019 7:09:OOPM Pane 6 COMPASS 5000.15 Build 91 Map Map vertical MD Inc Azi TVD TVDSS +N/ -S +EI -W Northing Easting DLS Section (usft) (') (1) (usft) (usft) (usft) (usft) !frl 1ftl (olil ) ft Survey Tool Name 8,204.80 12.08 80.02 7,93412 7,850.62 761.50 1,797.18 2,362,218.72 276,941.46 0.57 1,951.34 2_MWD+IFRI+MS+Sag(4) 8,266.64 12.52 79.50 7,995.14 7,911.04 763.84 1,810.15 2,362,220.82 276,954.47 0.73 1,964.25 2_MWD+IFR1+MS+Sag(4) 8,329.21 12.95 78.82 8,056.17 7,972.07 766.44 1,823.69 2,362,223.16 276,968.06 0.73 1,977.80 2_MWD+IFR1+MS+Sag(4) 8,390.99 12.60 79.55 8,116.42 8,03232 769.00 1,837.11 2,362,225.47 276,981.52 0.62 1,991.22 2_MWD+IFRI+MS+Sag(4) 8,453.81 11.44 75.77 8,177.86 8,093.76 771.77 1,849.89 2,362,228.00 276,994.35 2.23 2,004.12 2_MWD+IFR1+MS+Sag(4) 8,51387 11.75 73.10 8,236.70 8,15260 7]5.02 1,861.51 2,362,231.02 277,006.04 1.03 2,016.12 2_MWD+IFRI+MS+Sag(4) 8,575.88 11.99 73.30 8,297.38 8,213.28 778.70 1,873.72 2,362,234.48 277,018.31 0.39 2,028.83 2_MWD+IFR1+MS+Sag(4) 8,640.28 12.07 73.08 8,360.37 8,276.27 782.58 1,886.57 2,362,236.11 277,031.23 0.14 2,042.20 2_MWD+IFR1+MS+Sag(4) 8,702.29 9.88 81.05 8,421.24 8,337.14 785.30 1,898.03 2,362,240.61 277,042.74 4.29 2,053.85 2_MWD+IFRI+MS+Sag(4) 8,764.33 9.21 84.42 8,482.42 8,39832 786.61 1,908.23 2,362,241.73 277,052.96 1.41 2,063.82 2_MWD+IFRI+MS+Sag(4) 8,826.32 9.22 84.43 8,543.61 8,459.51 787.57 1,918.11 2,362,242.51 277,062.86 0.02 2,073.36 2_MWD+IFRI+MS+Sag(4) 8,887.82 9.22 85.49 8,604.32 8,520.22 788.44 1,927.93 2,362,243.19 277,072.69 0.28 2,082.80 2_MWD+IFRI+MS+Sag(4) 8,950.49 9.12 80.39 8,666.19 8,582.09 789.66 1,937.83 2,362,244.22 277,082.61 1.31 2,092.46 2_MWD+IFRI+MS+Sag(4) 9,01216 9.00 79.32 8,72].68 8,643.58 791.39 1,947.48 2,362,245.77 277,092.29 0.33 2,102.06 2_MWD+IFRI+MS+Sag(4) 9,073.99 8.77 80.68 8,788.18 8,704.08 793.03 1,956.79 2,362.247.23 277,101.64 0.51 2,111.33 2_MWD+IFRI+MS+Sag(4) 9,135.82 8.71 80.58 8,849.29 8,765.19 794.56 1,966.06 2,362,248.59 277,110.93 0.10 2,120.51 2_MWD+IFR1+MS+Sag(4) 9,196.87 8.42 81.08 8,909.66 8,825.56 796.01 1,975.04 2,362,249.87 277,119.93 0.49 2,129.39 2_MWD+IFRI+MS+Sag(4) 9,259.25 8.56 82.54 8,971.35 8,887.25 797.32 1,984.15 2,362,251.01 277,129.07 0.41 2,138.34 2_MWD+IFRI+MS+Sag(4) 9,319.90 8.17 85.02 9,031.36 8,947.26 798.28 1,992.92 2,362,251.60 277,137.86 0.88 2,146.85 2 MWD+IFRI+MS+Sag(4) 9,383.89 7.74 8957 9,094.73 9,010.63 798.71 2,001.76 2,362,252.06 277,146.70 1.19 2,155.22 2_MWD+IFRI+MS+Sag(4) 9,444.29 7.39 82.94 9,154.61 9,070.51 799.22 2,009.68 2,362,252.42 277,154.63 1.56 2,162.77 2_MWD+IFR1+MS+Sag(4) 9,506.20 7.34 73.93 9,216.01 9,131.91 800.80 2,017.44 2,362,253.85 277,162.41 1.87 2,170.56 2_MWD+IFR1+MS+Sag(4) 9,568.55 7.61 71.85 9,277.83 9,193.73 803.19 2,025.19 2,362,256.10 277,170.21 0.61 2,178.64 2_MWD+IFRI+MS+Sag(4) 9,631.49 7.72 74.36 9,340.21 9,256.11 805.63 2,033.22 2,362,258.38 277,178.28 0.56 2,187.01 2_MWD+IFRI+MS+Sag(4) 9,693.93 7.45 75.42 9,402.10 9,318.00 807.78 2,041.17 2.362,260 38 277,186.28 0.49 2,195.20 2_MWD+IFR1+MS+Sag(4) 9,755.90 7.42 76.64 9,463.55 9,379.45 809.72 2,048.95 2,362,262.17 277,194.09 0.26 2,203.14 2_MWD+IFRI+MS+Sag(4) 9,81].66 7.14 78.10 9,524.81 9,44011 811.43 2,056.59 2,362,263.74 277,201.76 0.54 2,210.87 2_MWD+IFRI+MS+Sag(4) 9,879.94 7.14 79.56 9,586.61 9,502.51 812.93 2,064.18 2,362,265.09 277,209.38 0.29 2,218.48 2_MWD+IFR1+MS+Sag(4) 9,941.10 7.06 80.03 9,647.30 9,563.20 814.27 2,071.62 2,362,266.29 277,216.84 0.16 2,225.89 2_MWD+IFR1+MS+Sag(4) 10,004.34 6.90 80.38 9,710.07 9,625.97 815.58 2,079.20 2,362,267.45 277,224.44 0.26 2,233.42 2_MWD+IFR1+MS+Sag(4) 10,065.77 6.55 84.76 9,771A8 9,686.98 816.51 2,086.32 2,362,268.26 277,231.58 1.01 2,240.39 2_MWD+IFRI+MS+Sag(4) 10,128.09 6.23 89.27 9,833.01 9,748.91 816.88 2,093.24 2,362,268.49 277,238.51 0.95 2,246.95 2_MWD+IFR1+MS+Sag(4) 10,175.19 5.97 91.27 9,879.85 9,795.75 816.86 2,09B.25 2,362,268.38 277,243.51 0.71 2,251.60 2_MWD+IFR1+MS+Sag(4) 10,210.00 5.97 91.27 9,914.47 9,830.37 816.78 2,101.87 2,362,268.23 277,247.13 0.00 2,254.93 PROJECTEDOTD Checked By: Mitch Laird Mg ' Approved By: Benjamin Hand Date: 7/23/2019 7/23/2019 7:09:OOPM Pane 6 COMPASS 5000.15 Build 91 Hilcorp Energy Company CASING & CEMENTING REPORT Lease 8 Well No. KEU KU 24-05B County Kenai State Alaska CASING RECORD Surface � TD 1.585.40 Shoe Deoth: 1.580.43 Date Run 2 -Jul -19 Supv. S Hauck/J Riley PBTD: (S Csg Wt. On Hook: 54,000 Type Float Collar: Casing (Or Liner) Detail 6 Setting Depths its. Component Size Wt. Grade THD Make Length Bottom Top Float Shoe 113/4 Liner hanger Info (Make/Model): X No TXP BTC Innovex 1.60 1,580.43 1,578.83 2 10 3/4" Baker Lock it 103/4 45.5 L-80 TXP BTC 81.80 1,578.83 1,497.03 Float Collar 113/4 TXP BTC Innovex 1.26 1,497.03 1,495.77 36 10 3/4" TXP Casing 103/4 45.5 L-80 TXP BTC 1,470.97 1,495.77 24.80 10 3/4" TXP Pup R 103/4 45.5 L-80 TXP BTC 2.45 24.80 22.35 Hanger 135/8 TXP BTC 0.85 1 22.35 21.50 Csg Wt. On Hook: 54,000 Type Float Collar: Innovex No. Hrs to Run: 6 Csg Wt. On Slips: Type of Shoe: Innovex Float Shoe Casing Crew: Weatherford Rotate Csg Yes X No Recip Csg X Yes _ No Ft. Min. 9 PPG Fluid Description: Spud Mud Cement Bump Plug? X Yes No Bump press Liner hanger Info (Make/Model): X No Liner top Packer?: _Yes X No Liner hanger test pressure: _Yes X Yes Floats Held X Yes No Centralizer Placement: 18 Total bow spring centralizers, 10' from each end on slop collars on It 1, middle ofjoint 2 with stop collars, 1 every CEMENTING REPORT Shoe @ 1580.43 FC @ 1,495.77 Top of Liner lush (Spacer) Slurry Class A Density (ppg) 10.5 Volume pumped (BBLs) 50 12 Volume pumped (BBLs) 140 Sacks: 325 Yield: 2.41 Mixing / Pumping Rate (bpm): 4.5 Slurry ,. Class A Sacks: 370 Yield: 1.18 sity (ppg) 15.8 Volume pumped (BBLs) 79.5 Mixing / Pumping Rate (bpm): Flush (Spacer) www.wellez.net WellEz Information Management LLC ver_04818br I Density (ppg) Rate (bpm): Volume: _ lacement: Spud Mud Density (ppg) 9 Rate (bpm): 5 Volume (actual / calculated): 1 (psi): 472 Pump used for disp: Cement Bump Plug? X Yes No Bump press ig Rotated? X No Reciprocated? X Yes —No % Returns during job ant returns to surface? _Yes X Yes No Spacer returns? X Yes _ No Vol to Surf: 70 mt In Place At: 0:30 Dale: 7/3/2019 Estimated TOC: 0 od Used To Determine TOC: Visual www.wellez.net WellEz Information Management LLC ver_04818br I Lease & Well No. County Kenai Hilcorp Energy Company CASING & CEMENTING REPORT KIEL KU 24-05B State Alaska Supv. CASING RECORD Intermediate � Tr) S 9Nn nn Rhnp r)pnth- 5 973 47 PBTD* Date Run 10 -Jul -19 R Pederson /J Rilev Csg Wt. On Hook: 142 Type Float Collar: Antelope No. Hrs to Run: Csg Wt. On Slips: Type of Shoe: Antelope Bullnose Casing Crew: Weatherford Rotate Csg Yes X No Recip Csg _ Yes X No Ft. Min. 9.2 PPG Fluid Description: 6% KCL Liner hanger Info (Make/Model): Liner top Packer?: _Yes X No Liner hanger test pressure: Floats Held X Yes No Centralizer Placement: Ran 75 hollow vane centralizers. Two on shoe joint, one per joint next 53 joints, one every other joint for four joints, one every third joint for sixteen joints. _ Shoe @ 5973.47 Casing (Or Liner) Detail Preflush (Spacer) Setting Depths As. Component Size Wt. Grade THD Make Length Bottom Top Float Shoe 85/8 Type: Class A Q H yd 563 Antelope 1.45 5,973.47 5,972.02 2 7 5/8 Casing jt 75/8 29.7 L-80 Hyd 563 77.88 5,972.02 5,894.14 Float Collar 85/8 Hyd 563 Antelope 1.30 5,894.14 5,892.84 145 7 5/8 Casing Jts 75/8 29.7 L-80 Hyd 563 5,830.18 5,892.84 23.11 7 5/8 Hyd Pup 75/8 29.7 L-80 hyd 563 2.50 23.11 20.61 Hanger 103/4 29.7 L-80 Hyd563 0.85 20.61 19.76 Csg Wt. On Hook: 142 Type Float Collar: Antelope No. Hrs to Run: Csg Wt. On Slips: Type of Shoe: Antelope Bullnose Casing Crew: Weatherford Rotate Csg Yes X No Recip Csg _ Yes X No Ft. Min. 9.2 PPG Fluid Description: 6% KCL Liner hanger Info (Make/Model): Liner top Packer?: _Yes X No Liner hanger test pressure: Floats Held X Yes No Centralizer Placement: Ran 75 hollow vane centralizers. Two on shoe joint, one per joint next 53 joints, one every other joint for four joints, one every third joint for sixteen joints. _ CEMENTING REPORT FC @ 5,892.84 Density (ppg) Top of Liner 10.5 Volume pumped (BBLs) 40 Sacks: 430 Yield: 2.39 Volume pumped (BBLs) 174 Mixing / Pumping Rate (bpm): 5 Sacks: 140 Yield: 1.24 Volume pumped (BBLs) 31 Mixing / Pumping Rate (bpm): 4 Density (ppg) Rate (bpm): Volume: : 6% KCL WBM Density(ppg) 9.2 Rate (bpm): 4.5 Volume (actual / calculated): (psi): 980 Pump used for disp: Halliburton Bump Plug? X Yes No ig Rotated? _Yes X No Reciprocated? _Yes X No % Returns during job ant returns to surface? _Yes X No Spacer returns? X Yes —No Vol to Surf: ant In Place At: 11:45 Date: 7/10/2019 Estimated TOC: od Used To D�er�nine TOC: CBL I Po/L ? ., . tee__. _ L i +moo— 3 Sc , (, " Q 0 r� Calculated Cmt Vol @ 0% excess: 20 Total Volume cmt Pumped: _ Cmt returned to surface: 0 Calculated cement left in wellbore: 205 OH volume Calculated: OH volume actual: Actual % Washout: www.wellez.net WellEz Information Management LLC ver 270/270.7 Bump press 15! 100 0 1,550 3S-Zb— 5 ro 205 Shoe @ 5973.47 Preflush (Spacer) Type: Lead Slurry Type: Class A Density (ppg) 12 Tail Slurry W Type: Class A Q Density (ppg) 15.3 Post Flush (Spacer) R r Type: CEMENTING REPORT FC @ 5,892.84 Density (ppg) Top of Liner 10.5 Volume pumped (BBLs) 40 Sacks: 430 Yield: 2.39 Volume pumped (BBLs) 174 Mixing / Pumping Rate (bpm): 5 Sacks: 140 Yield: 1.24 Volume pumped (BBLs) 31 Mixing / Pumping Rate (bpm): 4 Density (ppg) Rate (bpm): Volume: : 6% KCL WBM Density(ppg) 9.2 Rate (bpm): 4.5 Volume (actual / calculated): (psi): 980 Pump used for disp: Halliburton Bump Plug? X Yes No ig Rotated? _Yes X No Reciprocated? _Yes X No % Returns during job ant returns to surface? _Yes X No Spacer returns? X Yes —No Vol to Surf: ant In Place At: 11:45 Date: 7/10/2019 Estimated TOC: od Used To D�er�nine TOC: CBL I Po/L ? ., . tee__. _ L i +moo— 3 Sc , (, " Q 0 r� Calculated Cmt Vol @ 0% excess: 20 Total Volume cmt Pumped: _ Cmt returned to surface: 0 Calculated cement left in wellbore: 205 OH volume Calculated: OH volume actual: Actual % Washout: www.wellez.net WellEz Information Management LLC ver 270/270.7 Bump press 15! 100 0 1,550 3S-Zb— 5 ro 205 Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No. KEU KU 24-05B County Kenai State Alaska Date Run 21 -Jul -19 Supv. J Riley /J Richardson CASING RECORD Pro u ion m 1n 91n no Ahnn nnnfh 1n 9n5 n0 PRTD: Post Job Calculations: Calculated Cmt Vol @ 0% excess: 30 Total Volume cmt Pumped: 185 Cmt returned to surface: 0 Calculated cement left in wellbore: 185 OH volume Calculated: 188 OH volume actual: 207 Actual % Washout: 10 Make Seaboard Size 11 Test head to Remarks: Type SMB -22 Serial No. W.P. 5000 PSIG MIN OK www.wellez.net WellEz Information Management LLC ver_04818br Csg Wt. On Hook: 85,000 Type Float Collar: Casing (Or Liner) Detail Setting Depths its. Component Size Wt. Grade THD Make Length Bottom Top Bullnose shoe 5 Liner hanger Info(Make/Model): TXP BTC Antelope 1.41 10,205.55 10,204.14 2 4.5" Casing it 41/2 12.6 L-80 TXP BTC 82.91 10,204.14 10,121.23 Float collar 5 CEMENTING REPORT TXP BTC Antelope 1.30 10,121.23 10,119.93 127 4.5" Casingjt 41/2 12.6 L-80 TXP BTC 5,189.16 10,119.93 4,930.77 23 Pup 41/2 12.6 L-80 TXP BTC 2.33 4,930.77 4,928.44 2.07 Swell packer 7 150 Mixing / Pumping Rate (bpm): 4 TXP BTC Tail Slurry 11.66 4,928.44 4,916.78 Pup 41/2 12.6 L-80 TXP BTC Density (ppg) 15.3 Volume pumped (BBLs) 5.90 4,916.78 4,910.88 119 4.5" Casing jt 41/2 12.6 L-80 TXP BTC Density (ppg) 4,888.79 4,910.88 22.09 Displacement: Pup 41/2 12.6 L-80 TXP BTC 8.5 Rate (bpm): 2.58 22.09 19.51 FCP (psi): 2381 Pump used for lisp: Hanger 103/4 press 3000 1 No Reciprocated? _Yes 1.01 1 19.51 18.50 Post Job Calculations: Calculated Cmt Vol @ 0% excess: 30 Total Volume cmt Pumped: 185 Cmt returned to surface: 0 Calculated cement left in wellbore: 185 OH volume Calculated: 188 OH volume actual: 207 Actual % Washout: 10 Make Seaboard Size 11 Test head to Remarks: Type SMB -22 Serial No. W.P. 5000 PSIG MIN OK www.wellez.net WellEz Information Management LLC ver_04818br Csg Wt. On Hook: 85,000 Type Float Collar: Antelope No. Hrs to Run: Csg Wt. On Slips: Type of Shoe: Antelop Bull nose Casing Crew: Rotate Csg Yes X No Recip Csg _ Yes X No Ft. Min. 8.5 PPG Fluid Description: 3% KCL Brine Liner hanger Info(Make/Model): Liner top Packer?: _Yes _No Liner hanger test pressure: Floats Held X Yes No Centralizer Placement: Installed 75 centralizers total CEMENTING REPORT Shoe @ 10205.55 FC @ 10,121.23 Top of Liner PreBush(Spacer) Type: Density (ppg) 12.5 Volume pumped (BBLs) 23 Lead Slurry Type: Class A Sacks: 390 Yield: 2.07 Density (ppg) 12.5 Volume pumped (BBLs) 150 Mixing / Pumping Rate (bpm): 4 Tail Slurry Type: Class A Sacks: 158 Yield: 1.24 w Density (ppg) 15.3 Volume pumped (BBLs) 35 Mixing / Pumping Rate (bpm): 4 h Post Flush (Spacer) z Type: Density (ppg) Rate (bpm): Volume: LL Displacement: Type: 3% KCL Brine Density (ppg) 8.5 Rate (bpm): 5 Volume (actual / calculated): 153/153.8 FCP (psi): 2381 Pump used for lisp: Halliburton Bump Plug? X Yes _ No Bump press 3000 Casing Rotated? _Yes X No Reciprocated? _Yes X No % Returns during job 100 Cement returns to surface? X No Spacer returns? X No Vol to Surf: 0 _Yes Cement In Place At: 1:40 Date: 7/22/2019 _Yes Estimated TOC: 1Al Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0% excess: 30 Total Volume cmt Pumped: 185 Cmt returned to surface: 0 Calculated cement left in wellbore: 185 OH volume Calculated: 188 OH volume actual: 207 Actual % Washout: 10 Make Seaboard Size 11 Test head to Remarks: Type SMB -22 Serial No. W.P. 5000 PSIG MIN OK www.wellez.net WellEz Information Management LLC ver_04818br ;219- b -7Z Dora Oudean Hilcorp Alaska, LLC 177-1 GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 nil,, "p ua'L, L1 J E-mail: doudean@hilcorp.com DATE 09/12/2019 RECEIVED To: Alaska Oil & Gas Conservation Commission Pr_ - 1acm Eric l� 1*5121*+ SEP 12 2019 333 W 7th Ave Ste 100 Anchorage, AK 99501 AOGCC WELL SAMPLE INTERVAL KU 24-05B 1560'-3000' KU 24-05B 3000'-0500' KU 24-05B 4500'-5970' KU 24-05B 5970'-7440' KU 24-05B 7440'-8700' KU 24-05B 8700'-10210' 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 Date: gl13 DATE 09/12/14 21 90 %2 DeL Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 3 12 1 1 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 E tog data CD 1 : SS CALIPER BOREHOLE PROFILE LOG SONIC SCANNER MSIP-PPC-XPT-EDTC EXPRESS PRESSURE TOOL MSIP-PPC-XPT-EDTC CD 2: CBL 7-11-19 CBL/GR/CCL CD 3: CBL 7-30-19 CBL/GR/CCL CD 4: HALLIBURTON FINAL DATA DGR EWR-Phase 4 ALD Azimuthal Lithodensity CTN compensated Thermal Neutron Please include current contact information if different from above. R,ECE1 VES SEP 112019 ACGCC Please acknowledge receipt byesigning pRd returning one copy of this transmittal or FAX to 907 777.8337 BY. /\ I I_ '/ I R I Date: DATE 09/12/14 21 90 72 DeL Oudean Hilcorp Alaska, LLC t GeoTech 3800 Centerpoint Drive, Suite 1400 3 12 10 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 E log data CD 1 : SS CALIPER BOREHOLE PROFILE LOG SONIC SCANNER MSIP-PPC-XPT-EDTC EXPRESS PRESSURE TOOL MSIP-PPC-XPT-EDTC CD 2: CBL 7-11-19 CBL/GR/CCL CD 3: CBL 7-30-19 CBL/GR/CCL CD 4: HALLIBURTON FINAL DATA DGR EWR-Phase 4 ALD Azimuthal Lithodensity CTN compensated Thermal Neutron Please include current contact information if different from above. RECS,o'_ SEP 12 2019 A°Gcc Please acknowledge receipt boning pRd returning one copy of this transmittal or FAX to 907 777.8337 Received By: / \I I ._ V X X I Date: DATE 09/12/14 DeL 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 E log data CD 1 : SS CALIPER BOREHOLE PROFILE LOG SONIC SCANNER MSIP-PPC-XPT-EDTC EXPRESS PRESSURE TOOL MSIP-PPC-XPT-EDTC CD 2: CBL 7-11-19 CBL/GR/CCL CD 3: CBL 7-30-19 CBL/GR/CCL CD 4: HALLIBURTON FINAL DATA DGR EWR-Phase 4 ALD Azimuthal Lithodensity CTN compensated Thermal Neutron Please include current contact information if different from above. RECEI Vrn SEP 2 2o1g A®GCC 21 90'12 3 120 9 Please acknowledge receipt by s fining d returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: DATE 09/12/14 2190x2 Deb Duclean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 3 1 2 0 0 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 E log data CD 1 : SS CALIPER BOREHOLE PROFILE LOG SONIC SCANNER MSIP-PPC-XPT-EDTC EXPRESS PRESSURE TOOL MSIP-PPC-XPT-EDTC CD 2: CBL 7-11-19 CBL/GR/CCL CD 3: CBL 7-30-19 CBL/GR/CCL CD 4: HALLIBURTON FINAL DATA DGR EWR-Phase 4 ALD Azimuthal Lithodensity CTN compensated Thermal Neutron Please include current contact information if different from above. REcEjVED SEP 12 2019 AOGcc Please acknowledge receipt by signing 0 returning one copy of this transmittal or FAX to 907 777.8337 -•'nv' . WEU MEN THE STATE 01ALASKA GOVERNOR MIKE DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC. 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Kenai Gas Field, Tyonek Gas Pool 1, KU 24-05B Permit to Drill Number: 219-072 Sundry Number: 319-349 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 www.00gccaloska.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, 2,ic1. Cbmielowski Commissioner DATED this � i day of July, 2019. ABDMS, V JUL 2 6 2019 SCANNED JUL 2 9 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 2n AAI: 5'r 280 HE ENE JUL 2 4 ptg Crl-S '7 AQQ Q 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: Iniital Completion ❑� 2. Operator Name: 4. Current Well Class: , 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development Q Straligraphic ❑ Service ❑ 219-072 3. Address: 3800 Centerpoint Dr, Suite 1400 P 6. API Number: Anchorage Alaska 99503 50-133-20683-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? 510A Will planned perforations require a spacing exception? Yes ❑ No ❑� ' Kenai Unit (KU) 24-056 9. Property Designation (Lease Number): 10. Field/Pool(s): FEE A028142 Kenai Gas Field / Tyonek Gas Pool 1 it. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): 1 Plugs (MD): Junk (MD): 10,210' 9,914' 10,120' 9,825' i N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 120' 16" 120' 120' Surface 1,580' 10-3/4" 1,580' 1,550' 5,210psi 2,470psi Intermediate 5,973' 7-5/8" 5,973'5,744' 6,890psi 4,790psi Production 10,206' 4-1/2" 10,206' 9,908' 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 4,917'MD/4,718TVD; N/A 12. Attachments: Proposal Summary ✓ Wellbore schematic � 13. Well Class after proposed work: / Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development p Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: August 7, 2019 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑Q • 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: So York 777-8345 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramerGdhilcom.com I"'Vas ifsr�/� •'/ Contact Phone: 777-8420 01 Authorized Signature: {,,. /de es Date: / -f COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: (_'11 t Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test E] Location Clearance Other: RBDMSI�/jUL Z 61019 Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No 2/ Subsequent Form Required: 10-1401 - APPROVED BY ��All by: COMMISSIONER THE COMMISSION Date: Approved Submit Form and Form 1 403 Revised 4/2017 Approved application is va rd for monthsNomhe of approval. Attachments in Duplicate 10rwi.1 .H Hill" Alaska, LL Well Prognosis Well: KU 24-05B Date: 7/24/2019 Well Name: KU 24-05B API Number: 50-133-20683-00-00 Current Status: New Drill Leg: Estimated Start Date: August 7, 2019 Rig: CTU / E -line Reg. Approval Req'd? 10-403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 219-072 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: Estimated Bottom Hole Pressure: —3,000 psi @ 9,173 TVD (From pressure data) Max. Anticipated Surface Pressure: —2,083 psi (0.10 psi/ft gas grad. to surface) Brief Well Summary KU 24-05B is a newly drilled well that was TD'd on 7/17/19. The purpose of this Sundry is to blow dry and perforate several sands and place on production. Sundry Pre -work 1. RU Slickline Unit. PT lubricator to 250 psi low/3,000 psi high 2. Run a Gauge Ring in the well to PBTD.(GR may be a spent 2-7/8" perf gun 3. RD Slickline. 4. RU E -line Unit. PT lubricator to 250 psi low/3,000 psi high 5. RIH with CBL tool and log from PBTD to cement top. 6. POOH. RD E -line. Coil Tubing Procedure 7. MIRU CTU. Pressure test BOPS to 3,000 psi high 250 psi low. 8. RIH to PBTD jetting casing dry W/ nitrogen. Leave 1,600 psi on well. 9. RDMO Coil Tubing. E -Line Procedure _ l ote Fluid level. 10. MIRU a -line and PT lubricator to 250 psi low/3,000 psi high. 11. PU RIH W/pert guns. Perforate and test the following pert intervals according to instructions from the Reservoir Engineer: .H IGkonn Alesku, LU Well Prognosis Well: KU 24-05B Date: 7/24/2019 Proposed Perforated Intervals Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt D2 ±9,169 ±9,234' ±8,882' ±8,947' 65' MA ±91446' ±9,463' ±9,156' ±9,173' 17' D3B ±9,492' ±9,516' ±9,202' ±9,226' 24' D4B ±9,660 ±9,686 ±9,368 ±9,399 26' D4D ±9737 ±9754 ±9446 ±9462 17' a. Proposed perfs also shown on the proposed schematic in red font. b. Use GammalCCL to correlate. c. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. d. Conservation Order 510A governs perforating and flowing of the Sterling, Beluga and Tyonek sands in this field. e. Nitrogen may be used to pressure up the well or to push water away in the event a wet interval is encountered. A plug or a patch may also be set to eliminate the infiltration of water from a wet zone. f. Intervals may be tested individually or in conjunction with another interval. g. Intervals will be perforated and placed in the current well system for testing. 12. POOH. RD E -line. 13. Turn well over to production. Attachments: 1. Actual Schematic 2. Proposed Well Schematic 3. Proposed Wellhead Schematic 4. Coil BOP 5. Coil forward Jetting 6. Standard Well Procedure—N2 Operations con. nlasko, f.t.r. RKB: MSL =18.6 7-5/s TD=10,210'(MD) / 9,914'(TVD) PBTD=10,12d(MD) / 9,825'(TVD) SCHEMATIC CASING DETAIL Kenai Gas Field Well: KU 24-05B PTD: 219-072 API: 50-133-20683-00-00 Size Type Wt/Grade/Conn ID 4,917' 4-1/2" Swell Packer Conductor 109/X-56/Weld 16" 120' 30-3/4" Surface 45.5/L-80/TXP BTC 9.950"1,580' dTopBtm16" 7-5/8" Intermediate 29.7/L -80/W563 6.875"5,973' 4-1/2" Production 12.6/L-80/TXP BTC 3.958"10,206' JEWELRY DETAIL No Depth Item 1 4,917' 4-1/2" Swell Packer OPEN HOLE / CEMENT DETAIL 10-3/4" 220 BBL's of cement in 13.5" Hole. Returns to Surface (50% excess) 7-5/8" 205 BBL's of cement in 9-7/8" Hole. Est TOC @ 1,550' MD (0% excess) 4-1/2" 185 BBUs of cement in 6-3/4" Hole. Est TOC @ 2,934' (10% excess) Updated by DMA 07-24-19 B cars Ala.k.. LLC RKB: MSL =18.6' PROrOSED SCHEMATIC TD=10,210(MD) / 9,914'(TVD) PBTD=10,120(MD) / 9,825'(TVD) CASING DETAIL Kenai Gas Field Well: KU 24-05B PTD: 219-072 API: 50-133-20683-00-00 Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 109 / X-56 / Weld 16" Surf 120' 10-3/4" Surface 45.5 /L-80 / TXP BTC 9.950" Surf 1,580' 7-5/8" Intermediate 29.7/L -80/W563 6.875" Surf 5,973' 4-1/2" Production 12.6 / L-80 / TXP BTC 3.958" Surf 10,206' JEWELRY DETAIL No Depth Item 1 4,917' 4-1/2" Swell Packer PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status D2 ±9,169' ±9,234' ±8,882' ±8,947' 65 Proposed TBD D3A ±9,446' ±9,463' ±9,156' ±9,173' 17 Proposed TBD D3B ±9,492' ±9,516' ±9,202' ±9,226' 24 Proposed TBD D48 ±9,660' ±9,686' ±9,368' ±9,399' 26 Proposed TBD D413 ±9,737' ±9,754' ±9,446' ±9,462' 17 Proposed TBD OPEN HOLE/ CEMENT DETAIL 30-3/4" 220 BBL's of cement in 13.5" Hole. Returns to Surface (50% excess) 7-5/8" 205 BBL's of cement in 9-7/8" Hole. Est TOC @ 1,550' MD (0% excess) 4-1/2" 185 BBL's of cement in 6-3/4" Hole. Est TOC @ 2,934' (10% excess) Updated by DMA 07-24-19 Kenai Gas Field KU 24-0Proposed 07/18/201919 Ililrory �laka, I.IA: Kenai Gas Field KU 24-05B 16 X 10 % X 7 5/8 X 4 1/2 BHTA, Otis, 4 1/16 5M FE X 6.5" Otis Quick Union Valve, Swab, CIW-FLS, 4 1/16 5M FE, H WO, DD trim Valve, Upper Master CIW-FLS, 41/16 SM FE, H WO, DD trim Valve, Master, CIW-FLS, 41/165M FE, HWO, DD trim Multibowl Wellhead, 115M X 16 % 3M, W/ 4- 2 1/16 5M SSO Starting head, 16 % 3M X 16" SOW, w/ 2- 2 1/16 5M EFO Tubing hanger, ported, 11 X 4 1/2" DWC susp X 5.250-4 stub acme left hand lift, 4" H BPV, 3.998" min bore, 7" extended neck noc �`t\&� O oOc �\t\6�h' �960 v\ JaNS�Fe• �arJe��l got 3�1a �1185� oQefD Rotating flange, 4 1/16 5M x 4 1/16 5M Beluga River Unit KU 24-058 7/18/2019 COW Txtlng HH580 Injector Head. Weight =12,850106 ?,'! YRPvu SKW62LWdvMor z+�.6+ne+ce ve,niw �° SK W62n4-iH6"10K. IxnWl 4-111VKCor1Ai ,0.e mmMww IMnWI �� i xf snw. Sew,a6e�xov&io 4-1116" 10K flow Cross T. x'rscerz-m5-+oeazry. w xv+e: mx. z vm:+o� w,M. 4 - WOMead a6 WeMaga _� HSTANDARD WELL PROCEDURE Hama AWku. IAti NITROGEN OPERATIONS 1.1 MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.1 Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre -lob Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDSI. 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. S.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.1 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.) Welisite 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. f 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential 46 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 (SCFMI 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 ALASKA GOVERNOR MIKE DUNLEAVY Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Kenai Gas Field, Tyonek Gas Pool 1, KU 24-05B Permit to Drill Number: 219-072 Sundry Number: 319-260 Dear Mr. Myers: Alaska Oil and Gas Conservation Commission 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 w ww, a o g c c. a l o s k a. g o v 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 rel DATED this 2.3day of May, 2019. aBDMSd MAY 7 4 7019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS RECEIVED MAY 2 1 2019 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑✓ Plug for Reddll ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: n/dr-r 4- Wvv✓ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development ❑✓ • Stratigraphic ❑ Service ❑ 219-072 3. Address: 6. API Number: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-133-20683-00-00 ' 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? N/A Will planned perforations require a spacing exception? Yes ❑ No ❑✓ KU 24-056 9. Property Designation (Lease Number): 10. Field/Pool(s): FEE A028142 • Kenai Gas Field / Tyonek Gas Pool 1 I 11. PRESENT WELL CONDITION SUMMARY (Proposed) Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 10,385' 10,084' N/A N/A 3563 N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 120' 16" 120' 120' N/A N/A Surface 1,530' 10-3/4" 1,530' 1,500' 5210 2480 Intermediate 5,962' 7-5/8" 5,962' 5,730' 6890 4790 Production 10,385' 4-1/2" 10,385' 10,084' 8430 7500 Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): TBD TBD N/A N/A N/A Packers and SSSV Type: N/A Packers and SSSV MD (ft) and TVD (ft): N/A 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: CommencingOperations: 5/30/2019 pe 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: Monty Myers Contact Name: David Gorm Authorized Title: Drilling Manager Contact Email: g Drm a hilcor .COM FOK. ev%or- " r m y60-$ Contact Phone: 777-8333 I Authorized Signature: Date: S -2I _ ICY COMMISSION USE ONLY Conditions of approva : Notify Comrnission so that a representative may witness Sundry Number: /) I ry — ^ u o (Jl� L Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ /•//,1)% //❑ Other: ��J[. rtGY I.t.%0.t..rJ 2K. Z A4 -c— Z 5 r (53-5 � f'L/` Zl 3BDMS.r4-6�MAY 2 4 2019 Post Initial Injection MIT Req'd? Yes ❑ No ❑�-y/ / Spacing Exception Required? Yes No Subsequent Form Required: —cJ 7- ❑ I �I / U 6 APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: S(Su and e Z Form 403 Revised 4Y2017 ZA P oved application is vOfVumIMA approval. �Attachments in Duplicate H Hilcorp E-Weapffy 5/21/2019 David Gorm Drilling Engineer Commissioner Alaska Oil & Gas Conservation Commission 333 W. 71h Avenue Anchorage, Alaska 99501 Re: KU 24-05B Dear Commissioner, / Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 Tel 907 777 8333 Email dgorm@hilcorp.com Attached is the updated page and 10-403 for the variance request to drill the surface hole without a diverter on KU 24-05B due lack of equipment availability and recent offset wells drilling surface hole to similar depths with no issues. - If you have any questions, please don't hesitate to contact myself at 777-8333 or Monty Myers at 777- 8431. f S cerely, n C� David Gorm Drilling Engineer Hilcorp Alaska, LLC Page 1 of 1 H Hilcorp E��W> KU 24-05B 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 KU 24-05B. Ensure to provide AOGCC 24 hrs notice prior to testing BOPS. • The initial test of BOP equipment will be to 250/4000 psi & subsequent tests of the BOP equipment will be to 250/4000 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 BDP 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: • 20 AAC 25.005.4 (A) Requesting alternative calculation of maximum potential surface pressure. We will be planning worst case in the drilling mode will be 2/3 evacuation of wellbore gas with the reaming 1/3 volume in wellbore remains drilling fluid density. The high pressure at TD is a pressurized water zone with any influx being water. • 20 AAC 25.035 (c) - Diverter waiver request requested due to the recent drilling of KU 11-07X , KBU 32-06 and KBU 43-07Y on a nearby pad. No issues were experienced on either well drilling the surface hole. Surface casing will be set at the same depth on KU 24-05B. Page 8 Revision 1 May 2019 Project Kenai Gas Fi, Site KGF 41-07 Pad Well Plan KU 24-05B Wellbore KU 24-05B Design KU 24-05B wp08 4 1rT CASING UEIAN PID MD Namc ,`wv 12000 12000 16" 16 149969 153000 10 Y4' 10-3W 5277 25 550000 7 5.8" 7.5:8 10084101038459 J000 417' 41/2 KU 24-05B WPO8 T9t1 C N KU 24-056 wp08 CP1 � m 4 1/2" Ksu 43-07Y 7 518"_ 10314'4---- i T M Amneats W True NOM Magnetc NOM 1540' MaT511tc Frcltl SL Dip A 55190 41- 04 Angle 7341' Dale 4/104019 MOBN BGGM201a .egp0 .5100 4800 -A2003800 J000 -2400 11800 -1200 -600 0 6011 1200 1600 2400 3000 West( -)/East(+) (1500 usftfin) PTD -�19-/:7l Loepp, Victoria T (CED) From: Lehman, Nick R <Nick.R.Lehman@conocophillips.com> Sent: Monday, May 20, 2019 7:54 AM To: Loepp, Victoria T (CED) Subject: Re: [EXTERNAL]KRU 2M-39(PTD 218-171) Intermediate 1 Cement Follow Up Flag: Follow up Flag Status: Flagged Ok thanks. Nick On May 20, 2019, at 7:43 AM, Loepp, Victoria T (CED) <victoria.loepp@alaska.eov> wrote: Nick, Approval is granted to proceed as planned. Thanx, Victoria Sent from my iPhone On May 20, 2019, at 5:46 AM, Lehman, Nick R <Nick.R.Lehman@conocophillips.com> wrote: Yes we will - that is our plan. On May 20, 2019, at 5:19 AM, Loepp, Victoria T (CED) <victoria.loepp@alaska.gov> wrote: Will you be able to run the Sonic across the Intl cement including TOC? Sent from my iPhone On May 19, 2019, at 8:02 PM, Lehman, Nick R <Nick. R. Lehman @conocophillips.com> wrote: Good evening Victoria, We finished pumping our INTRMI cement job on 2M-39 (PTD 218-171) this afternoon. Below are the operational details for the job: - Schlumberger cementers pumped 66.1 bbls of 13.Oppg Mudpush followed by 167.2 bbls of 15.8ppg Class G, and 10.1 bbls of water. - Swapped to the rig and displaced with 1142 bbls of 10.3ppg LSND. Initial rate of 8 bpm, 422 ��.�,,ry, psi increasing to 1092 psi, and then decreased ° , ' t A rate to 3 bpm after 1100 bbls pumped witn a final circulating pressure of 750 psi. Overall, we saw good lift pressure; 500+psi of lift pressure once cement turned the corner We did not bump the top plug. We checked the floats and confirmed floats were not holding. The well is currently shut in and we are waiting on cement to set up before moving forward. As previously mentioned, there are no hydrocarbon zones open in this interval. Please see attached pdf for further details. Once cement has setup, we will move forward as per original plan. We will be running the SonicVision 675 with INTRM2 drilling BHA for logging cement in recorded mode and will retrieve the data once we finish drilling the INTRM2 section. Please let me know if you have any questions or concerns with our plan forward. At this point, I anticipate we'll be picking up the INTRM2 BHA sometime tomorrow morning. Regards, Nick Lehman Drilling Engineer I ConocoPhillips Alaska Office (907)263-4951 1 Cell (832)499-6739 Nick.R.Lehman@ConocoPhillips.com From: Loepp, Victoria T (CED) <victoria.loepp@a Iaska.eov> Sent: Sunday, May 19, 2019 8:01 AM To: Lehman, Nick R <Nick R Lehman@conocophillips.com> Subject: Re: [EXTERNAL]KRU 2M-39(PTD 218-171) Intermediate 1 Cement Very good, thanx for the update. Send cement job summary when available. Victoria Sent from my iPhone On May 19, 2019, at 7:44 AM, Lehman, Nick R <Nick R Lehman @conocophiIIips.com> wrote: Good morning Victoria, On 2M-39 Kuparuk Injector (PTD 218- 171) with Doyon 19, we drilled the 12- 1/4" INTRMI hole to land ^B' TVD into the HRZ shale, reaching TD of 15798' MD / 5801' TVD on 5/12/19 18:00 hrs. Since then, we have come out of hole, laid down drilling BHA, re -tested BOPE, and run in hole with our 9-5/8" 47# Intermediate 1 casing string. Currently, we have reached bottom and are unable to circulate fluid to surface. We have tried to regain circulation with no success and are moving forward with our Intermediate 1 cement job. We will be pumping enough cement to bring TOC to 500' TVD above the shoe (13,663' MD / 5301' TVD) at 35% excess equating to 165 bbls of 15.8ppg Class G cement. We will also be pumping CemNet LCM material in the cement as an extra precaution. We believe the thief zone is located at 8000' MD / 4030' TVD based on observations drilling, backreaming, and running casing. With the thief zone being 5663' MD / 1271' TVD above our planned TOC, we believe we will be able to lift cement as planned. After drilling and logging the section, we have confirmed our initial assessment that there are no hydrocarbon -bearing zones exposed in this hole section. As soon as we finish the cement job and have the final reports, I will put together a summary, outline observed lift pressure, and send to you for your review. Thanks for your time and help, Nick Lehman Drilling Engineer I ConocoPhillips Alaska Office (907)263-4951 1 Cell (832)499- 6739 Nick. R. Lehman@ConocoPhillips. com From: Loepp, Victoria T (DOA) <victoria.loepp@a Iaska.Qov> Sent: Tuesday, March 12, 2019 8:53 AM To: Lehman, Nick R <Nick.R. Lehman@conocophillips.com> Subject: [EXTERNAL]KRU 2M-39(PTD 218-171) Intermediate 1 Cement Nick, The following changes are approved for KRU 2M-39(PTD 218-171): :1 O V N gI M N M s 7 ' r � I 1 9 i.. i � ?j GJ CJ Y C O Y Lr C O 'Em O C r 'D pl N O Y V 0 O" Lei N C N O L a C O 7 O ++ L C_bl, w O 0 m C E C N � 0 n O - O c x oY v Ow o u a_ $ v 2 NS y ,o .c N � DD O Y d CO L 4, N f E 2 C Q C Y C p O yd O u o Y o -O 'a o f l0 m v ~ Z 4- N y 3 n Y to C y L L d y, a u m N N L (0 O O Y ` v C n :o3 E v a C c.l v y V) N }� M. y o i O E O X O U y o o a n nv v CL o YO m *' v o C Q 0 0 in n v v .� c o u o 3 '6 cLn �° t L 'O o cu •E Y 41 C •C �^ 9 Y O ate.+ i '6 A (6 m -C _3 (n c Y 1� lO C O pop Y 7 w - =3 S N •� O N CC YO L G/ Ql L �„c Y Ln N L L L C ° 3Nz °�°0Q v� ° �_�cm"z�0d� > m V O {— U Q Schwartz, Guy L (DOA) From: David Gorm <dgorm@hilcorp.com> Sent: Thursday, May 16, 2019 9:42 AM To: Schwartz, Guy L (CED) Subject: RE: [EXTERNAL] RE: KU 24-05B - Radius Map Guy, We will be requesting an exception to the MASP rule. We will be planning worst case in the drilling mode will be 2/3 evacuation of wellbore gas with the reaming 1/3 volume in wellbore remains drilling fluid density. The high pressure at TD is a pressurized water zone with any influx being water. We will adjust our procedure to conduct an FIT to 14 ppg at the 7-5/8" Intermediate shoe proposed set at 5,700' TVD. We anticipate final MW of 12-12.2. Thanks, David Gorm Drilling Engineer Hilcorp Alaska Cell: 505-215-2819 From: Schwartz, Guy L (DOA) [mailto:guy.schwartz@alaska.gov] Sent: Wednesday, May 15, 2019 4:05 PM To: David Gorm <dgorm@hilcorp.com> Subject: [EXTERNAL] RE: KU 24-05B - Radius Map Thanks ... As we discussed plan on TOC for the 7 5/8" at 4500 ft. also. 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 low. 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 (Guv schwartz@alaska.aov). From: David Gorm <deorm@hilcorp.com> Sent: Wednesday, May 15, 2019 11:21 AM To: Schwartz, Guy L (DOA) <Ruy.schwartz@alaska.Qov> Subject: KU 24-05B - Radius Map Guy, Per our conversation for KU24-05B please find attached a current Map with a 1000' radius circle indicating there are no current housing dwelling near the planned well that would require a SSSV installed for the proposed completion of the well. Let me know if you need any more detail. Thanks, David Gorm Drilling Engineer Hilcorp Alaska 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. .� h?. �-1 • • • a .rt`.4,� tN'h' ~� • ,p. �, • . • A 0 3 _ • s • Y j • • `:.. r F 7n �amm� Q�i.�in, ,una• �_ ' • . - I • : �swai. ` •. ® �. i((ff r E � � • • � ,� °� �_ � V 1 li• • • � M <,< < e A $ § J�§ k \/�\o \ }QLD \� (*!{Ul ol (I|� §�k\ «§(k }/\\ +�|« (033 ]on ( <,< < e $ J�§ \/�\o \� ///CR ! !:! {! 22] - «\ �- } 3 ( ( ) z !E > § \ } \ \ \ }\\ } .a3 { ƒ } � - � ( K \ \ j ) \ THE STATE OfALASKA 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: Kenai Gas Field, Tyonek Gas Pool, KU 24-05B Hilcorp Alaska, LLC. Permit to Drill Number: 219-072 Surface Location: 519' FNL, 771' FEL, SEC. 7, T4N, Rl IW, SM, AK Bottomhole Location: 418' FSL, 1262' FWL, SEC. 5, T4N, RI l W, SM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced development well. 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, Daniel T. Seamount, Jr. Commissioner DATED this �L3- of May, 2019. I STATE OF ALASKA I ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL IIIIIIIIIIIIIIIIIFlLTS�Lh' �rcL�� MAY 11 0 2013 1 a. Type of Work: 11b. Proposed Well Class: Exploratory -Gas ❑ Service - WAG M Service -Disp ❑ 1c. Speci{��cq{f y-�y or: Drill ❑v 'Lateral ElStratigraphic Test El Development -Oil LlService- Winj El Single Zone ❑v Coalbed Gas lel s y ates ❑ Redrill ❑ Reentry ❑ Exploratory - Oil ❑ Development - Gas I Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket Q Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 KU 24-05B 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 10,385' TVD: 10,084' Kenai Gas Field r Tyonek Gas Pool 1 , 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: 519' FNL, 771' FEL, Sec 7, T4N, R11 W, SM, AK FMA028142 Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 412' FSL, 1233' FWL, Sec 5, T4N, R11 W, SM, AK N/A 5/30/2019 9. Acres in Property: 14. Distance to Nearest Property: Total Depth: 418' FSL, 1262' FWL, Sec 5, T4N, R11 W, SM, AK 2494 8573' to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 84.1 15. Distance to Nearest Well Open Surface: x-275130 y- 2361491 Zone -4 GL / BF Elevation above MSL (ft): 66.1 to Same Pool: 1260' to KDU 02 16. Deviated wells: Kickoff depth: 318 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 18.3 degrees Downhole: 6353 ' Surface: 3563 • lift CJ, - 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Cond 16" 109# X-56 Weld 120' Surface Surface 120' 120' Driven 13-1/2" 10-3/4" 45.5# L-80 TXP BTC 1,530' Surface Surface 1,530' 1,500' L-567.5 ft3/T-321.5 ft3 9-7/8" 7-5/8" 29.7# L-80 W563 5,962' Surface Surface 5,962' 5,730' L - 997.6 ft3 / T - 168 ft3 6-3/4" 4-1/2" 12.6# L-80 TXP BTC 10,385' Surface Surface 10,385' 10,084' T- 1317 ft3 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) u' c'"T Ak,i 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/Structuml Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Hydraulic Fracture planned? Yes El No 2 20. Attachments: Property Plat O BOP Sketch Drilling Program Time v. Depth Plot 4 Shallow Hazard Analysis e Diverter Sketch e Seabed Report B Drilling Fluid Program e 20 AAC 25.050 requirements 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: d orM hiloor .COM Authorized Title: Drilling Manager Contact Phone: 777-8333 Authorized Signature: — Date: Commission Use Only Permit to Drill API Number: Permit Approval r 11 E5 /f e7 I /]I LU Vl See cover letter for other requirements. Number: a 50- (3 -206'83- OQ^ Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: [� Other: Y, yoco `Gs,f- Samples req'd: Yes ❑ No e Mud log req'd: Yes ❑ NOR' P5. HzS measures: Yes ❑ No R' Directional svy req'd: Yes [Rr No ❑ ,,1r n q l #&)PSQ c cl, p PI) J/�.1� Spacing exception req'd: Yes ❑ NoQ Inclination -only svy req'd: Yes ❑ No ' �D057- J 1,r! ,�/ � �'t' Zd FV?C- ZS. (e -X 4M) Post initial injection MIT req'd: Yes[] No❑ A4(- APPROVED BY Date: Approved by: COMMISSIONER THE COMMISSION U J�� suomrc Dorm ane Fo 1 07 ggvigetl��/017 z if r t valid for 24 f d tA4 oval per 20 AAC 25 005(g) Attachments in Duplicate Jl i� ;;,I-, ort(' 1:,"5/4 /19 H Hilcorp 5/10/2019 David Gorm Drilling Engineer Commissioner Alaska Oil & Gas Conservation Commission 333 W. 7'h Avenue Anchorage, Alaska 99501 Re: KU 24-05B Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 Tel 907 777 8333 Email dgorm@hilcorp.com Dear Commissioner, KU 24-05B is a grass roots development well from the 41-07 pad in the Kenai Gas Field targeting the Deep Tyonek Unit, targeting the D2, D3, and D4 sands. The base plan is an "S" turn wellbore, kicking off at 300' MD and building to 18 deg, then dropping back to vertical starting at 9,835' MD, then drilling a vertical tangent to TO at 10,384' MD. Drilling operations are expected to commence approximately May 301h, 2019. The Hilcorp Rig # 169 will be used to drill and partially complete the wellbore. A workover rig will follow behind to perforate the well. {.,,-6j, ? 5C Sw If you have any questions, please don't hesitate to contact myself at 777-8333 or Monty Myers at 777- 8431. Sincerely, T Il4 V,^14 David Gorm Drilling Engineer Hilcorp Alaska, LLC Page 1 of 1 -Un Hilcorp Alaska, LLC KU 24-05B Drilling Program Kenai Gas Field w Approved by: David W Gorm Revision 0 April 2019 KU 24-05B Procedure Drilling Procedure Hilcorp 9-®CamVml Contents 1.0 Well Summary.................................................................................................................................2 2.0 Management of Change Information............................................................................................3 3.0 Tubular Program: ........................................................................................................................... 4 4.0 Drill Pipe Information: ................................................................................................................... 4 5.0 Internal Reporting Requirements..................................................................................................5 6.0 Planned Wellbore Schematic..........................................................................................................6 7.0 Drilling / Completion Summary.....................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications.....................................................................8 9.0 RX and Preparatory Work..........................................................................................................10 10.0 NX 21-1/4112M 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 NIU and Test.........................................................................................................................24 15.0 Drill 9-7/8" Hole Section...............................................................................................................25 16.0 Run 7-5/8" Intermediate Casing..................................................................................................29 17.0 Cement 7-5/8" Cement Procedure ...............................................................................................32 18.0 Drill 6-3/4" Hole Section...............................................................................................................35 19.0 Run 4-1/2" Production Long String.............................................................................................40 20.0 Cement 4-1/2" Production Long String.......................................................................................43 21.0 Completions...................................................................................................................................44 22.0 BOP Schematic..............................................................................................................................45 23.0 Wellhead Schematic......................................................................................................................46 24.0 Days Vs Depth................................................................................................................................47 25.0 Formation Tops.............................................................................................................................48 26.0 Anticipated Drilling Hazards.......................................................................................................50 27.0 Rig Layout......................................................................................................................................53 28.0 FIT Procedure................................................................................................................................54 29.0 Choke Manifold Schematic...........................................................................................................55 30.0 Casing Design Information...........................................................................................................56 31.0 9-7/8" Hole Section MASP............................................................................................................57 32.0 6-3/4" Hole Section MASP............................................................................................................59 33.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................61 34.0 Surface Plat (As Built) (NAD 27).................................................................................................62 35.0 Offset MW vs TVD Chart .............................................................................................................63 36.0 Drill Pipe Information...................................................................................................................64 37.0 Directional Program(WP02)........................................................................................................66 n Hilcorp Energy,27 1.0 Well Summary KU 24-05B Drilling Procedure Well KU 24-05B Pad & Old Well Designation KU 24-05B is a grass roots well on the KGF 41-07 Pad Planned Completion Type Perforated, TBG less Target Reservoir(s) Beluga & T onek formations Planned Well TD, MD / TVD 10,411' MD / 9,880' TVD PBTD, MD / TVD 10,331' MD / 9,800' TVD Surface Location (Governmental) 771' FEL, 519' FNL, Sec 7, T4N, RI IW, SM, AK Surface Location (NAD 27) X=275130.276, Y=2361491.387 Surface Location (NAD 83) X=1415158.021, Y=2361246.842 Top of Productive Horizon (Governmental) 412' FSL, 1233' FWL, Sec 5, T4N, RI l W, SM, AK TPH Location AD 27) X = 277191, Y = 2362269 BHL (Governmental) 418' FSL, 1262' FWL, Sec 5, T4N, RI IW, SM, AK BHL AD 27 X = 277220, Y = 2362275 AFE Number 1912715 AFE Drilling Days 25 AFE Completion Days AFE Drilling Amount $4,500,000 AFE Completion Amount Maximum Anticipated Pressure (Surface) 3563 psi Maximum Anticipated Pressure (Downhole/Reservoir) 6353 psi Work String 4-1/2" 16.6# S-135 CDS-40 KB Elevation above MSL: 84 ft GL Elevation above MSL: 66 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 April 2019 2.0 Management of Change Information Hilcorp Alaska, LLC Changes to Approved Permit to Drill KU 24-05B Drilling Procedure Date: 4-29-2019 Subject: Changes to Approved Permit to Drill for KU 24.05B File #: KU 24 -OSB Drilling and Completion Program Any modifications to KU 24-05B Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be communicated to the BLM and AOGCC. H Hilcorp L^ C—Wy Sec Page Date Procedure Change Approved Approved B B Approval: Prepared: Drilling Manager Drilling Engineer Date Date Page 3 Revision 0 April 2019 3.0 Tubular Program: Hole OD (in) ID Drift Conn Section (in) (in) OD Weld - -- - 45.5 L-80 UT BTC Cond 16" 15" - - 13-1/2" 10-3/4" 9.95" 9.875" 11.75" 9-7/8" 7-5/8" 6.875" 6.75" 8.5" 6-3/4" 4-1/2" 3.958" 3.833" 5" 4.0 Drill Pipe Information: KU 24-05B Drilling Procedure Wt Grade Conn Bu Collapse Tension ectiogit.�,? (#/ft) _. 109 X-56 Weld - -- - 45.5 L-80 UT BTC 5210 2480 1040 29.7 L-80 W563 6890 4790 683 12.6 L-80 TXPBTC 8430 7500 288 pole OD(in) & m('. JID TJ OD Wt Grade Conn Burst Collapse Tension ectiogit.�,? (#/ft) 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 0 April 2019 5.0 Internal Reporting Requirements KU 24-05B 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 deonn a hilcorp.com, mmyersna hilcorp.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! I ! ! 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 dgorm@hilcorp.com, mmversghilcorp.com and cdineer@hilcorp.com 5.6 Casing and Curl report • Send casing and cement report for each string of casing to dgonn@hilcom.com, mmyers@hilcoW.com and cdinger@hilcorp.com Page 5 Revision 0 April 2019 Procedure Drilling Procedure Hileorp E.a Campy 6.0 Planned Wellbore Schematic Kenai Gas Field PROPOSED SCHEMATIC Well: Ku 24-05B PTD: TBD ______________________________________________ _______________ CASING DETAIL W&NEL.=188' o>e Tenn W[I Gradel fano ID I TOO I MM ' ' �` JEWELRY DETAIL +r < re No Dept Kem nuc --- ------------------ -;,----------------- a'A :. :•y OPEN HOLE/CEMENT DETAIL r �", r'✓,�,�CV � 1tr 6" 156 BaL's afmmens in 135'IWIe. Reeurns [a Surfare SD9: exmsl Fes. ]-5/e" 1939aL's of mmenx in9-]/d'Itale. Lrt'f%OV 029'IR%excess L,b� �• � M1J2" 1989aL'zdxmert[inb3je'Ible. Est T';; C �3,5W I]O.iexcess PAZ -10A r � 4A - OL z5bn rs� many�'in,D}/14�'MDI R3fD=SQ3f1D'I� /14DDDi><'DF Updated b4 MG 4-332D19 Page 6 Revision 0 April 2019 H Hilcorp a.w C.W, KU 24-05B Drilling Procedure 7.0 Drilling / Completion Summary KU 24-05B is a grass roots development well from the 41-07 pad in the Kenai Gas Field targeting the Deep Tyonek Unit, targeting the D2, D3, and D4 sands. The base plan is an "S" turn wellbore, kicking off at 300' MD and building to 18 deg, then dropping back to vertical starting at 9,835' MD, then drilling a vertical tangent to TD at 10,000' MD. Drilling operations are expected to commence approximately May 30th, 2019. The Hilcorp Rig # 169 will be used to drill and partially complete the wellbore. A workover rig will follow behind to perforate the well. Surface casing will be run to 1,529' 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 1,529' MD. Run and curt 10-3/4" surface casing. 4. N/D diverter, N/U & test 11"x 5M T3 -Energy BOP. 5. Drill 9-7/8" hole section to 5,962' MD. Run and cmt 7-5/8" intermediate casing. 6. Drill 6-3/4" production hole section to well TD. Run and cmt 4-1/2" prod casing. Reservoir Evaluation Plan: 1. Surface hole: No LWD, & no open hole logs planned. Mud loggers will generate a mud log. 2. Intermediate hole: LWD: GR + Res No Open Hole wireline logging. Mud loggers will generate a mud log. 3. Production hole: LWD: GR + Res + Den/Neu (Triple Combo). No Open Hole wireline logging. Mud loggers will generate a mud log. Page 7 Revision 0 April 2019 KU 24-05B 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 KU 24-05B. Ensure to provide AOGCC 24 hrs notice prior to testing BOPS. • The initial test of BOP equipment will be to 250/4000 psi & sub$equent tests of the BOP equipment will be to 250/4000 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 rs ime. Page 8 Revision 0 April 2019 U Hilcorp E..W Company Summary of BOP Equipment and Test Requirements KU 24-05B Drilling Procedure Hole Section Equipment Test Pressure(psi) 13-1/2" • 21-1/4" x 2M Hydril MSP diverter Function Test Only • l l" x 5M T3 -Energy (Model 7082) Annular BOP • I I" x 5M T3 -Energy Double Ram Initial Test: 250/4000 o Blind ram in btm cavity (Annular 2500 psi) • Mud cross 9-7/8" & 6-3/4" 11" x 5M T-3 Energy Single Ram • 3-1/8" 5M Choke Line Subsequent Tests: • 2-1/16' x 5M Kill line 250/4000 • 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). • 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.reggna alaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartzkalaska.gov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / Email: melvin.rixse@alaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: victoria.loeppalaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: hqp://doa.alaska.izov/oizc/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 April 2019 9.0 R/U and Preparatory Work KU 24-05B Drilling Procedure 9.1 Set 16" conductor at 112' below ground level (130' 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 0 April 2019 H Hilcorp E..W C.� 10.0 N/U 21-1/4" 2M Diverter KU 24-05B 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. N/U 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 11 Revision 0 April 2019 10.5 Rig and Diverter Line Orientation on KU 24-05B Pad: KU 24 -OSB Drilling Procedure I ®KDU 9 ❑ I J@(U 13- I *BU 41-7 1` �q KU 43-6RD WBU 41 7X KENAI GAS � ®KD l 4 j FIELD PAD ®KU 43-6A , 41-7 V` Page 12 Revision 0 April 2019 Annular Preventer Diverter Tee, 21!/." x 2M w116" ANSI 150 16-%- 3M x 21-'/." 2M 16-3/V 3M Casing head Assy KU 24-05B Drilling Procedure Page 13 Revision 0 April 2019 N Hilcorp EZ T- 11.0 Drill 13-1/2" Hole Section KU 24-058 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" 16.0 S-135 CDS40 11.2 Hydraulics Summary: Page 14 Revision 0 April 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 0-1529 13-1/2" 550 1800 85 9.0 9.3 0.739 HWDP Page 14 Revision 0 April 2019 KO Drilling Procedure 1 rp Camp* 11.3 Primary bit will be the 13-1/2" Hughes Christensen Kymera Hybrid Bit KM633. Hughes Christensen PRODUCTDVERv1EW Kymera` m Hybrid Bits Best of Both Worlds Designeed to take adsatin ge of the best attributes of bot14 K,vmere combines roller mow and fixed cutter demeaHs, Ln lvow4 Ilirau.,aI Owrtd Relative to p(x' bits, Kytnera genal g lower nsrrall lontim and minim imd lonple Rnnuatims to improv$lm face control and reduce vibrations.. Lour edbmton The rmique design of Kymera bits provides an slable&iRing plmCamlthmmhigmcs vibration presem in mikrc •� PDC envuonments. Bcllir lenlf,we cnrilml Srglarior dir"joonal bit for molm"unary Applications with beter tool(axe control and steentiniry Iban a P Faster and More Dumblc When drilling mterbakkd and harder fmmm(ao, minthe to PDC bits. this unique design provides ince sed durability in transition zorles and smoother, faster drilling in hard rock. Bil Speci rimbu rs Numher ofalades, Cones 3.3 Pmnary Curter Sin 0.75 in (19-1 mm) Cutter Q"Wtity (Total. Facel (35,23) Cutting SWclure(Inrar. HmL Gauge)Dachl�Dachbv bide Number of Nozzles 6SP Fixed TFA 04in(0 sq.mm) Bearing i Seal Package Journal w law i S6 Single Energim MFS 'ago b.re Cianee i Makeup Le1W01 5.75 in ( IJ6.1 Moir + 17.24.5 in (4.IR mml Bit &cakcr P Connection 6•98 Rag Pin 712'I1,1SA, 171.40akn-0b1511 i. htakap 1 orqum55.4110m1 :1-4--1 Waa Hit Je 7. 45 npryIb 1579. S6 63.61Nm1 Apprax,ShipP®l W6ght3a6Ills (156.9 kg) Per. Pan Number SII"O ONnnling Reccmmwndations' IhJrmllie 11me rJ4 a5Dl35opvn 1A75U51UPIpl1i. Ro .1bm ease 1Fur RaWry anJ AIUAV .Applieaian5. Aon. Weiele tffi Hir 6a klbR6ln a kdaV) Page 15 Revision 0 April 2019 11.4 13-1/2" directional assy: KU 24-05B Drilling Procedure COMPONENTDATA Item .r ID Gauge Weight Top Bottom Length Cumulative Description 1 Tricone 6.750 3.438 13.500 173.30 P 6-518" REG 0.96 0.96 2 8" SpenyDrill Labe 415 - 8.000 5.000 121.08 B 6-518" REG B 6-518" REG 32.06 33.04 5.3 st Bim Sleeve Stabilizer 13.250 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 8.000 1.920 142.70 B 6-518" REG P 6-518" REG 4.55 46.59 5 8" EWR-P4 Collar 8.000 2000. 151.00 B 6-518" REG P 6-518" REG 12.19 58.78 6 8" HCIM Collar 8.000 1.920 1 1 149.90 B 6518' REGIP 6-5/8" REG 4.97 63.75 7 8" TM Collar 7.830 3250 151.20 B 6518" REG P 6-518" REG 9.07 72.82 8 8- Flex Collar 7.750 2.875 138.64 B 6-0" REG P 6518" REG 30.00 102.82 9 S' Flex Collar 7.500 2.875 128.44 B 6518" REG P 6518" REG 2922 13204 10 8" Bottle Neck XO 7.875 3.063 140.89 B 4-112" IF P 6518" REG 3.52 135.56 11 6 314' Flex Collar 6.813 2.875 102.10 B 4-112" IF P 4-12" IF 30.00 165.56 12 6,V4" Flex Collar 6.688 2.875 97.58 B 4-12" IF P 4-112" IF 30.38 195.94 13 4 12"IF x CDS-40 X- 6.150 2.687 81.91 B 4.5' CDS P 4112" If 2.51 798.45 Over Sub 14 2 Jnts�DP S-40 4.500 2.813 33.02 61.36 259.81 15 CDS-40 x 4 12"IF X- 6.200 2.687 83.56 B 4-112" IF P 4.5" CDS 2.50 262.31 Over Sub 40 16 6114" Jars 6250 2250 91.01 B 4-12" IF P 4-112" IF 31.79 294.10 17 4112' IF x CDS 40 X- 6.470 2.687 9272 B4.5"CDS P¢112"IF 2.65 296.75 Over Sub 40 18 15 Jnts 4.5" COS40 4.500 2.813 36.86 459.91 756.66 HWDP 756.66 Bit Number Nozzles :3xi6,ix14 Bit Size (in) : 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 No LWD tools will be run on the 13-1/2" hole section. 11.7 Begin drilling out from 16" conductor at reduced flow rates to avoid broaching the conductor. 11.8 Drill 13-1/2" hole section to 1529' MD / 1500' TVD. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. Page 16 Revision 0 April 2019 KU 24 -OSB Drilling Procedure • 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. • 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 1500'— 1700' MD. • Take MWD surveys every stand drilled (60' intervals). 11.9 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: MD I Mud Viscosity PV YP API FL LGS 15 - 20 ppb Weight 0.1 ppb (8.5 — 9.0 pH) BARAZAN D+ as needed BAROID 41 as required for 8.8 — 9.5 ppg 120'— 1,529' 8.8-9.5 250-85 40-20 55-25 1 <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 11.10 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16" conductor shoe. 11.11 TOH with the drilling assy, handle BHA as appropriate. Page 17 Revision 0 April 2019 H HilwEng 12.0 Run 10-3/4" Surface Casing 12.1 R/U and pull 15.375" wearbushing. KU 24-05B 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 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 Triangle Base 10-3/4" 22,630 ft -lbs Page 18 Revision 0 April 2019 KU 24-05B Procedure Drilling Procedure Hilcorp Energy Cmnpmy TXPCR? BTG a 1 rrzDln Outside Diamohv 10750,1- Min. Wag 07.5% cw0i::6w ID DAM N. kl*> pLms 4191 n. 7,mdsvf, 5 (') 6rad9 LDO RMLAR Typo 1 Wall Telckne+ss 0,100 W. EonMrclior. OD RLGULAR n L -.-r•; c. I:ri n'. Option 1940999 P IT,V COUP(m PIPE BODY Iln dwt Red Is'. 3ard Red Lr4d. LID Type 1' Dill API Standard WBi d'. em" 2n.1 S�b im 2nd sand:. Brown TSpe Lasing 3!d Rand'.. 3(d &I. td - 401- Banc PIPF 9OD"Y DATA GEOMETRY Na^.ilcbDD 10.750ih Vtminalwai;rA Na -rel ID 0.950 n. 'Blah 7bk4nem DD TiMranpr API 45.5lbs'll Drill 7.791 in 0.40e1n Plar, Eru"S!Vt 44201W PERFORMANCE ecdy Null 1610.101La IPlammyldd 5210rti BYYg amen Pi G:JUrr 2470 rd, CONNECTION DATA GEOMETRY Cana:licv OD 11.750 i'1- C"piN Lw yh 10.125 Y+ cw0i::6w ID DAM N. kl*> pLms 4191 n. 7,mdsvf, 5 Corecoo,0j cptax RMLAR PERFORMANCE n L -.-r•; c. I:ri n'. 1-1 1940999 P IT,V H sl Pn,e -e tbP" 5210.909 P9 Iln Oo, Opn ssen Effan--y 710 :. cattw: am SP0,41h 1040000.171:0 KIa.. Afow1 &. 4.0 34'i1N0 im Exle"i -rmwr Qro:rl 2470.M Pn MAKE-UP TORQUES Kinmu-! 29170 tabs il,"m.m 22070 d-L�e Ktamum 24199 M1bS OPERATION LIMB TORO/E3 IPe'aln0`a-3.; a7700t+bs r,Pk lue 4500-kn Page 19 Revision 0 April 2019 KU 24-05B 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) fl 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 April 2019 KU 24 -OSB Procedure Drilling Procedure Hilcorp Ene Company 13.0 Cement 10-3/4" Surface Casing 13.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. • How to handle curt 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: Calculation: Vol Vol (ft3) (BBLS) LEAD: 120' x .106 bpf = 12.8 71.6 16" Conductor x 10-3/4" casing annulus: LEAD: (1029' —120') x .065 bpf x 1.5 = 88.3 495.9 13-1/2" OH x 10-3/4" Casing annulus: Total LEAD: 101.1 567.5 1 3 4 Sr TAIL: (1529'-1029') x .065 bpf x 1.5 = 48.6 272.8 13-1/2" OH x 10-3/4" Casing annulus: TAIL: 90 x .096 bpf = 8.7 48.7 10-3/4" Shoe track: Total TAIL: 57.3 321.5 aS z? s c Page 21 Revision 0 April 2019 U Hilcrp Evcigy,,2,T Cement Slurry Design: KU 24-056 Drilling Procedure 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% KCUEZ 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: 1439' x .0962 bpf= 138 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 overdisplace by more than 'h 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 April 2019 Lead Slurry (1200' MD to surface) Tail Slurry (1700' to 1200' 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% KCUEZ 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: 1439' x .0962 bpf= 138 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 overdisplace by more than 'h 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 April 2019 H Hilcorp KU 24-05B 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 tanning 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 successor problems during the cement job Send final "As -Run " casing tally & casing and cement resort to dgorm@hilcorp com This will be included with the EOW documentation that goes to the AOGCC. Page 23 Revision 0 April 2019 H Hilcorp Enm Company 14.0 BOP N/U and Test 14.1 N/D the diverter. KU 24-05B 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 601 Ii 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 250/4000 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 9.5 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 April 2019 15.0 Drill 9-7/8" Hole Section KU 24-05B Drilling Procedure 15.1 Prior to P/U 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: COMPONENTDATA Item� .. ID Gauge Weight Top Bottom Length Cumulative -suiption Serial Number [i n) (in) (in) ObA Connectitin Connectim (ft) Length (ft) 1 9 7B' PDC 7.600 1 3.000 1 9.673 13051 P 6-518' REG 0.90 0.90 2 2'18 " 7'E.O 7-000 4.952 93.13 B 4-117 IF B 6518" REG 27.30 2820 std Btm Sleeve Stebier 9.625 3 6 314' DM Collar 6.740 3.125 103.40 B 4-117 IF P 4-117 IF 920 37.40 4 6 3W CHOR Collar 6760 1.920 97.80 B 4-112'IF P 4-12' IF 6.42 43.82 5 6 314' EWR-P4 Cnlar 6.730 2.000 104.30 B 4-1/2'IF P4 -MF IF 12.10 55.92 6 1 Inline Stabilizer (ILS) 6730 1.92(1 9.500 111-37 B 4-112' IF P 4-12' IF 1.95 57.87 7 6 314' PWD 1 6.730 1905 96.30 B 4-112^ IF P 4-12' IF 6A3 64.30 B 6 3r4' HCIM Cofer 6750 1.920 101.70 B 4-112' IF P4 -171F 6.59 70.89 9 6 314" ALO Collar 6750 1.920 8.062 104.30 B 4-117 IF P 4-112' IF 18.42 89.31 Stabliier B.062 10 6 314' CTN Ca0ar 6.720 1.905 10230 B 4-11,71F P 4-12' IF 11.84 101.15 11 6 3W TM Collar 6.850 3.250 99.70 B 4-117 IF P 4-12' IF 10.02 111.17 12 6 3W Flex Caller 6813 2.875 10210 B 4-112' IF P 4-12' IF 30.00 141.17 13 634' Flex Caller 6.688 2.875 97.58 B 4-117 IF P 4-12' IF 30.38 171.55 14 4 12' IF x CDS-40 X- 6-150 2.687 8191 B 4.5' CDS P 4-12' IF 2.51 174.06 Over Sub 40 15 2Jnts4.55' PDS -40 4-500 2.813 33.02 61.36 235.42 HWD16 6200 2.687 83.56 B4-117IF40 2.50 237.92 Over Sub 17 6 114' Jars 6250 2250 91.01 B 4-117 IF P 4-12' IF 31.79 269.71 18 4 1MF x CDS-40 X- 6.470 2.687 92.72 8 4-5' CDS P 412 IF 2.65 272.36 O� Sub 40 19 1 4.500 2.813 36.86 459-91 73227 HWDF 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 April 2019 U Hilerp Energy C2, 15.6 Primary bit will be the Baker Hughes 9-7/8" Kymera. Hughes Christensen Kymera",' Hybrid Bits 9.N75 in. (250.8 mm) KMX524 Ll -,t of WNL W.0d+ Desig cd W take advantage of the been attributes of both. Kymea combines rW;cr oatc arid fined cutter eianent. Imps, d Direcai,nul Control R«rirx in POC bis, Ky. gerwtea lorw overall torque and mni nixed wrquc fluctuations to iramwilaiMl lacesmntrol and reduce nlra mass. ).o.er vilsal;on The tnique "gn of Kromer, him protides an stable drilling platf9nn that mlliltuaes wlnalion present in matte c PDC enviran.b. Ludt,, roolf.,vr ,4 Superior directional bit for inter or rotary applications wish beater fonlfnce v rmnA and than a P 6 Faster and Mare Durable Whcrl drilling iraerbedded and harder fomutirrn, rebtise m POC' Firs, Ibis unique desigal rarnhie. irwenscd durability in mans tion aelww and tnoodtr, faster drilling in lard rock. kit Spe:iricuior. Nunber ufOkrles-Cnnux 4.2 Primary Gear Sin 0.625 in (15.9 roro) comf Q Murk) lTaal. Face) M 221 Cutting Sauiurc if.. l Ieel. Gin.ge)CsrlioCcnivCarbide Nunba of NOT)ks Fixed TFA Rating f Seal Pwkage 4 CSP. 1A 03DI sy.in (193 c5 eq.tmn) 3mamnl w+Inset i $ogle Faa>gi)v 3dP$ KU 24-05B Drilling Procedure PRODUCT pbTF.RVIFW Gauge / Makeup 1-en61h 6 an I I 52 mro) 7 15.347 in (389.5 total kit Breaker F Connection 6418 Reg Pin )a_'tir Sub "1-4affitah 4y> 3. Makeup Torque s'4 bn1ea I l raid all n.^r.su Vsn.me3Lo. 5y aJ eWm1 Ar%.. Mirping Wcig1t216 lb. (911 kg) Ket: I" Nutnber %25211 Opc,lio, Roux.... laion,' Ila.lr WIL auc uo-9uo u,rNUIM)J.(n1a4:J)(l4.1.AAL,;..nGmi furtrM nod Ilravrt.ApplmWInnr.%I, We1Na[)n lilt 49 kaf 1211.. S N) Page 26 Revision 0 April 2019 H Hilcorp 15.7 9-7/8" hole section mud program summary: KU 24-05B 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 — 9.5 ppg 6% KCl/EZ MUD/BDF-976 fresh water based drilling fluid. Properties: 15.8 15.9 Product Mud Water Plastic KCI 22 ppb (29 K chlorides) Caustic MD Weight Viscosity Viscos1,529'- field Point pH HPHT DEXTRID LT 9.0-9.5 40-53 15-25 15-25 8.5-9.5 <11.0 5,962' 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 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 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. 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 ppg EMW. Page 27 Revision 0 April 2019 n Hilcorp Evngy Compmq KU 24-058 Drilling Procedure 15.13 Drill 9-7/8" hole section to 5,962' MD / 5,700' 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. 15.14 Casing point selection: TD the 9-7/8" hole section around 5,950' MD (5,700' TVD) in the middle of MB 5. 15.15 At TD; pump sweeps, CBU, and pull a wiper trip back to the 10-3/4" shoe. 15.16 TOH with the drilling assy, stand back BHA if possible. Page 28 Revision 0 April 2019 H Hilcorp E—VC-VZY KU 24-05B 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 250/4000 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 - 0 £• (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 4000' MD. • Install centralizers over couplings on every 4' joint above 4000' MD to 10-3/4" shoe at 1529' 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 April 2019 Drilling Procedure Procedure Hilcorp Eae� Compavy Wedge 5630 ....,.,.. 10118/2018 outaWO Dbmater 1.636 n. Min. Wall 87.5Y Thlckness (•I Gnlae L80 Goa r I Wall Thickness 0,3760i pnnestlpn OO REGULAR TyV6 Option CWPl1MG PIPE pODY Gratle L00 Typo 1GnRB.ay R"Isi Hann Rea AP161An0aR1 ISI B.M B. 2na S. 2,a Baro.. Brown TOPS Casing 3rd pa - 3rd Band' - nm B.M: - PIPE BODY DATA GEOMETRY PERFORMANCE ----� BaayY 1d5 en0m 683x1000lb. Intemel wia 6600011 SLAYS 600M pal Collapse 4700p0 CONNECTION DATA I GEOMETRY Cannxann OD 8.600 n CnuMng l.an0ib 936 Cnmarvn lD 6.BT6 h. LMMe Lon& e.6W n. Tntmle peen 3'19 COme.Ia OD Oplion REG"R PERFORMANCE --TInim..'n [a.ra.1. Mit G75 n. Nominal lD CPS.. Wal Thicklmea 0.376.x. Rain Ertl WaaM 00.06 Duo OOTGenlrce AN Da ExWnA Pressure Capality AT90.000 p9i Caiptn0 race LO 45500011s PERFORMANCE ----� BaayY 1d5 en0m 683x1000lb. Intemel wia 6600011 SLAYS 600M pal Collapse 4700p0 CONNECTION DATA I GEOMETRY Cannxann OD 8.600 n CnuMng l.an0ib 936 Cnmarvn lD 6.BT6 h. LMMe Lon& e.6W n. Tntmle peen 3'19 COme.Ia OD Oplion REG"R PERFORMANCE tendon EOclw 100.01'. Jmol YRtl WmgN 603.000x1000 Imernll R66sure Cepx01 6000.000 ps1 F.. Canrnnpon EFKknry 100.045 Compreasian Slecrt0lh 603,000x1000 Ltar Allmvatlnepntlitt5 As°11000 Da ExWnA Pressure Capality AT90.000 p9i Caiptn0 race LO 45500011s MAKE-UP TORQUES Mnimum 8600 MM Optimum 10300 0-0a Mind.. 16100 nJbs OPERATION LIMB TORQUES Opnr "Ty In Moll ftT Yield Tcnne 46p00plbs BUCK -ON 56nlmpm IM966aT 13arimum a/s66 ban 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 April 2019 H Hilcorp Eom� Company KU 24 -OSB 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 RAJ 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 31 Revision 0 April 2019 n HilmF.� �� j 17.0 Cement 7-5/8" Cement Procedure KU 24-05B 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 10.0 ppg spacer. Close low torque on plug dropping head, test surface cmt lines to 4000 psi. 17.4 Pump remaining 35 bbls 10.0 ppg spacer. l d "fes 17.5 Mix and pump slurry per below design: Section: Calculation: Vol (BBLS) Vol (ft3) LEAD: (5,400-1,529') x .038 bpf x 1.2 = 177.7 997.6 ft3 9-7/8" OH x 7-5/8" csg: Total Lead: 177.7 bbls 997.6 1t3 TAIL: (5,962' — 5,400') x .038 bpf x 1.2 = 25.8 144.8 ft3 9-7/8" OH x 7-5/8" csg: TAIL: 90' x .046 bpf = 4.1 23.2 ft3 7-5/8" Shoe Track: Total Tail: 29.9 bbls 168 0 Page 32 Revision 0 April 2019 yis �>< r35- 5--A H Hilcorp en� czjx KU 24-05B Drilling Procedure 17.7 After pumping cement, drop top plug and displace cement with mud. Use the cement unit to displace with as volumes can be tracked much more accurately. Displacement talcs: • 5,872' x .0459 bpf = 269 bbls. • Displace with 9.5 ppg 6% KCl/EZ MUD/BDF-976 drilling fluid out of mud pits. 17.8 Monitor returns closely while displacing cement. Adjust pump rate if necessary. 17.9 Do not overdisplace by more than % shoe track volume. Total volume in shoe track is 4.1 bbls. 17.10 There should be no curt returns to surface. TOC is planned to be at 1,000' 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 33 Revision 0 April 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 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 Type1 Cement 94 lb/sk Type1 Cement 94 lb/sk Additives WellLife 1094 Monofilament fiber 0.21% BWOC WellLife 1094 Monofilament fiber 0.20% BWOC 17.7 After pumping cement, drop top plug and displace cement with mud. Use the cement unit to displace with as volumes can be tracked much more accurately. Displacement talcs: • 5,872' x .0459 bpf = 269 bbls. • Displace with 9.5 ppg 6% KCl/EZ MUD/BDF-976 drilling fluid out of mud pits. 17.8 Monitor returns closely while displacing cement. Adjust pump rate if necessary. 17.9 Do not overdisplace by more than % shoe track volume. Total volume in shoe track is 4.1 bbls. 17.10 There should be no curt returns to surface. TOC is planned to be at 1,000' 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 33 Revision 0 April 2019 Drilling Procedure Procedure Hilcorp en� czT 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 dzormghilcorp com. This will be included with the EOW documentation that goes to the AOGCC. 17.1 R/D cement equipment. Flush out wellhead with FW. 17.2 Back out and L/D landing joint, flush out wellhead with FW. 17.3 M/LJ 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. 17.4 Lay down landing joint and pack -off running tool. Page 34 Revision 0 April 2019 n Hilcorp E=W Cmpv y 18.0 Drill 6-3/4" Hole Section KU 24-05B 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): Annular/VBR/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. 18.5 Ensure BHA Components have been inspected previously. Ensure to have enough 4-1/2" DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 18.6 Drift & caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 18.7 Ensure TF offset is measured accurately and entered correctly into the MWD software. 18.8 Confirm that the bit is dressed with a TFA of 0.46 sqin. Have DD run hydraulics models to ensure optimum TFA. We want to pump at 270 gpm. 18.9 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 35 Revision 0 April 2019 H Hi1CO2p Ev C %T 18.10 PfU below 6-3/4" directional drilling assy: KU 24-05B Drilling Procedure COMPONENTDATA Item.D 1 Description 6 314" PDC (in) 4.680 r Gauge (in) (in) 1.500 1 6.750 Weight (thpiri 1 52-60 Top Connection IP 3-112" REG Bottom Connection Length (it) 0.70 1 Cumulative Length (ft) 0.70 2 4 314" SperryDrill Lobe 516- 8.3 s1 4-750 2.794 44.57 B 3-112" IF B 3-112" REG 29.70 30.40 3 4 314' DM Collar 4710 2.610 4820 B 3-112" IF P 3-112" IF 921 39.61 4 4 314" EWR 1 DGR 4.740 1.250 4820 B 3-112" IF P 3-112" IF 24.40 64-01 5 4 314" ALD Collar 4.720 1250 5.625 45.50 B 3-112" IF P 3-112" IF 14.35 78.36 Stabilizer 5.625 6 4 314' CTN Collar 1 4.760 1250 50.50 B 3-112" IF I P 3-112" IF 11-14 89.50 7 4 314" PWD Collar 4-730 1250 47.90 B 3112" IF P 3-112" IF 923 98.73 a 4 314" TM Collar 4-680 2.812 46.10 B 3112" IF P 3112" IF 11.13 109.86 9 4 314' NM Flex Collar 4.625 2.313 42-94 B 3-112" IF P 3-112" IF 31.05 140.91 10 4 W4' NM Flex Collar 4-750 2.313 46.08 B 3112" IF P 3112" IF 31.05 171.96 11 X70 f3 112" IF P x 4 112" CDS 40 840 5210 2.750 52-41 B 4. " CDS P 3-112" IF 1.35 17331 12 4 jts x 4 112' HW DP 4.500 2-687 36.86 122.93 29624 13 4 112" Jar 4.625 2.500 40.53 B 4.5" CDS 40 P 4.5" CDS 40 31.71 327.95 14 1 7 jts x 4 UT HWDP 4.500 2.687 1 36.86 214.33 54228 Total_ _ s• Page 36 Revision 0 April 2019 U Hileorp Evc,gy Compavy KU 24-05B Drilling Procedure 18.11 Primary bit will 6-3/4" Baker Hughes Kymera KM323. Hughes Christensen KymeraTll" FSR Hybrid Bits Best of Both Worlds Designed to take advantage of the best attributes of both, Kyrnm combines rolls cone and fixed cutter elements. Better toolface control Superior directional bit for motor or rotary applications with better toolface control and steerability than a PI Improved torque control Kymem bits offer unrivaled torque in the toughest formations; even in transition zones torque is with amooth and fast drilling. Higher overall ROP Maintains PDC -equivalent ROP in soft fannatittim while increasing ROP in harder formations typically drilled by roller cone bits. High efficiency in Carbonates Improved cutting structure optimizes drilling in carbonates for high efficiency. Bit Srti ilicafiom Number of Blades, Cones 3,2 Primary Cutter Size 0.44 in (11.2 mm) PRODUCT OVERVIEW Gauge / Makeup Length 3.5 in (88.9 mm) / 9.801 in (2489 mm) Bit Breaker N CutlerQuantity (Toa, Face) (20.15) Connection Cutting Structure (Inner, Heel, Gauge)Conic1WedSciDX PDC Number ofNozzks Fixed TFA Bearing i Seal Package 2 SP, I PORT 0.11 sq.in (70.97 sq.mm) Journal w/Insert / Single Energizer MFS Makeup Torque 3-112 Reg Pin 41 ell" Bit Sub 5.2.5.7kft-Ib(7.0-7.7kNm) 4114"Bit Sub 6.3-6.9k8-Ib(8.6-9.4kNm) 4112"Bit Sub 7.6.8.4kft-16(103-11.4kNm) Approxi Shipping Nreight53 lbs (24 kg) Ref. Part Number X22715 Opemting Recommendations* Hydraulic Ilou rate: 250.550 Spot 4950-2100 turn). Rotation Saeed: For Rotary and Motor Applications Max. weight the Bic 33 kit, (I4 at or LAW) Page 37 Revision 0 April 2019 H Hilcorp KU 24-05B Drilling Procedure 18.12 TIH to TOC. Shallow test MWD on trip in. Note depth TOC tagged at on AM report. 18.13 Conduct casing test to 3500 psi / 30 min. S� " A4 I 18.14 Drill out shoe track and additional 20' new formation. CBU and prep for FIT. 1'f.0 18.15 Conduct FIT topg EMW. �� w FIT— -r P4TA 18.16 Drill 6-3/4" hole to 10,385' MD / 9,964' TVD using above motor assembly. -iza A 66 C c • 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. 18.17 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 38 Revision 0 April 2019 n Hilcorp mer car KU 24-05B Drilling Procedure System Type: 9.5 — 12.5 ppg 6% KCl/EZ MUD/BDF-976 fresh water based drilling fluid. Properties: ,r F.� o',L P MD E—I Viscosity Plastic Viscosi field Point pH HPHT 5,962'- + 7DEXTRIDLT 40-53 15-25 15-25 8.5-9.5 0.75 ppb 10,385' 1-2 ppb I ppb BARACARB 5125150 15 - 20 ppb (5 ppb of each) — 18.18 Hilcorp Geologists will follow LWD log closely to determine exact TD. 18.19 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8" shoe. 18.20 TOH with drilling assy, handle BHA as appropriate. 18.21 No open hole logs are planned for the production hole section. Page 39 Revision 0 April 2019 Concentration 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) + 7DEXTRIDLT 1.25 ppb (as required 18 YP]rate) 2 - 4 ppb 0.75 ppb 1-2 ppb I ppb BARACARB 5125150 15 - 20 ppb (5 ppb of each) BAROID 41 as required for a 9.5 —12.2 p ALDACIDE G 0.1 ppb BARACOR 700 1 ppb BARASCAV D 0.5 b (maintain per dilutio 18.18 Hilcorp Geologists will follow LWD log closely to determine exact TD. 18.19 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8" shoe. 18.20 TOH with drilling assy, handle BHA as appropriate. 18.21 No open hole logs are planned for the production hole section. Page 39 Revision 0 April 2019 H Hilcorp KU 24-05B Drilling Procedure 19.0 Run 4-1/2" Production Long String 19.1 Install and test 4-1/2" casing ram in top ram cavity. Test to 250/4000 psi. 19.2 Dummy run casing hanger and mark landing joint. 19.3 R/U Weatherford 4-1/2" casing running equipment. • Ensure 4-1/2" 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. 19.4 PIU shoe joint, visually verify no debris inside joint. 19.5 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. 19.6 Continue running 4-1/2" prod casing. • 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 5,900' MD. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 4-1/2" TXP BTC torques Casing OD Minimum Maximum Yield Torque 4-1/2 5,550 ft -lbs 6,170 ft -lbs 8,800 ft -lbs Page 40 Revision 0 April 2019 KU 24-05B Procedure Drilling Procedure Hilcorp r>naW TXM BTC 0510312017 D.tsede D,.mr 1500 In. 6b1. Wall 37.5. CO,MOW DJD option REGYLAR PERFORMANCE Thit,IrI nGrade L30 low iensm Etrcmng CGmprpill,n EmnOrrcy Enamal il'aaarp CaPicnl 1M % 108!: 7590.000 pu bM yie. S:mn"'. CumPmaswn siJc qln 3MD00 xl OfR le. 266.000x10W le: Type d M30.000 PL sl vt0ort Wall ThieAnese 0.271 n. Cpnneeop W REGULAR R4nlmum 55506.1tc Option 6178 It Ix CDDPMHG qPE 30DY Grade L3DType1' Drift API Standard 9id1 Red 1stWr.d. Red 6790 n![c Y"wtl rccpua e508 It 1s1 Gand: rl. 2rd Mnd. ?nd Dad Sreen Type Casing 3ad Q.w 3rd EUnd. Slh SaM: PIPE BODY DATA GEOMETRY Npmna. DD 4"0n 11[rnrval •/lctlnl 126 QI IXdl 3A331n. N.. ID 3.956 vi Wall Tnlcircu 0211 m Plam End W,Ignt 1225.".. Do T.W. AN PERFORMANCE 3W1 MIaN Se ,iI 2661IM0 las iwxnal Y.4 640 P. SRNs 66000 camps, 7900 pa. CONNECTION DATA GEOMETRY C.L, nn DD 5.000 m Cwy1n6 iengN 9.0]51rt C[menbn ID }9661n. Mina-ua Les. 1A161n TNaad: Ryrin 5 CO,MOW DJD option REGYLAR PERFORMANCE iensm Etrcmng CGmprpill,n EmnOrrcy Enamal il'aaarp CaPicnl 1M % 108!: 7590.000 pu bM yie. S:mn"'. CumPmaswn siJc qln 3MD00 xl OfR le. 266.000x10W le: IntaIDal PNdsma Capauty 1'I M. aw.aMcesManp M30.000 PL sl vt0ort MAKE-UP TOROMS R4nlmum 55506.1tc D'ulimum 6178 It Ix Manimem 671H,16M OPERATK)N LIMB TORgUES DpcaaLoa TVQoc 6790 n![c Y"wtl rccpua e508 It Page 41 Revision 0 April 2019 H Hilcorp KU 24-05B Drilling Procedure 19.7 M/U casing hanger joint 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. 19.8 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 19.9 R/IJ 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. 19.10 After circulating, lower string and land hanger in wellhead again. Page 42 Revision 0 April 2019 U Ililcorp env C—Prq 20.0 Cement 4-1/2" Production Long String KU 24-05B Drilling Procedure 20.1 Hold a pre job safety meeting over the upcoming cmt operations. Ensure the below is covered during the meeting: • How to handle curt 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 long string during cmt operations. 20.3 Pump 5 bbls 12.5 ppg MUDPUSH II spacer. 20.4 Test surface cmt lines to 4500 psi. `%�� LOD, s 20.5 Pump remaining 20 bbls 12.5 ppg MUDPUSH II spacer. 20.6 Mix and pump slurries per below recipe. Ensure cmt is pumped at designed weight. Job is designed to pump 30% OH excess.r �� c' r r 1. Section: Calculation: W5`" Vol BLS Vol (ft3) 7-5/8" x 4-1/2" Overlap (Tail): (5,962') 0.0262 = 3$ 51,0'I" 6-3/4" OH x 4-1/2" Casing (Tail): (10,385 — 5,9 .0246 x1.3 = 142- 799 Shoe Track (Tail): 90'x 0.015 = 1.4 7.9 Total Volume (Tail): Typel 234.3 1317 Slurry Information: M Page 43 Revision 0 April 2019 %Fe 3 Tail Slurry (10,385'to 2,500' MD) System EXPANDACEM (TM) SYSTEM Density 15.3 Ib/gal Yield 1.241 ft3/sk Mixed Water 5.55 gal/sk Additives Code Description Concentration Typel Cement 94 lb/sk WellLife 1094 Monofilament fiber 0 .20% BWOC Page 43 Revision 0 April 2019 %Fe 3 H �IICcOIP 20.7 Drop top plug and displace with 3% KCl. 10,285 ft x .01522 = 157 bbls. KU 24-05B Drilling Procedure 20.8 Do not overdisplace by more than %2 shoe track. Shoe track volume is 1.4 bbls. 20.9 Bleed pressure to zero to check float equipment. 20.10 Pressure up again to 3500 psi and hold for 30 min to test production bore. 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 successor problems during the cement job Send final "As -Run " casing tally & casing and cement report to dorm hilcoT com This will be included with the EOW documentation that goes to the AOGCC 21.0 Completions 23.1 A separate Sundry will be submitted to the AOGCC that will cover the completion operations for KU 24-05B `i' x 7 Page 44 Revision 0 April 2019 U Hilco E ycomT 22.0 BOP Schematic KU 24-05B Drilling Procedure Page 45 Revision 0 April 2019 H HilCO2�7 m Eap Company 23.0 Wellhead Schematic Kenal Gas Field 16 X 10 X X 75/8 X 41/2 111 aA, Obs, 41/165M FEX 6.5- Otis OW ck Unlon Valve, Swab, CIW-FLS, 41/16 5M FE, "WO, EE trim Valve, Upper Master CIW-FLS, 41/16 5M FF, MWO, EE trim Valve, Master, CIW-FLS, 41/16 SM FE, MWO, EE VIrn Mulbbowl Wellhead, WM 22, 11 5M X 16 X 3M, W/ 4- 2 1/16 SM SSO Starting head. 5 -22 -ET 16 X 3M X 16` SOW, w/ 2- 2 1/16 SM EM K'2 4 - '5B 24-O5B Drilling Procedure 6ena1 Gas Field VG 0. 0�o FF- � ce�ot oQe Page 46 Revision 0 April 2019 Drilling Procedure Procedure HilwEvmgy Company 24.0 Days Vs Depth G 2000 4000 5r L d N v 6000 J N � K- 8000 8000 10000 12000 0 Days Vs Depth 5 10 15 20 25 30 Days Page 47 Revision 0 April 2019 35 H Hilmai E.c Company 25.0 Formation Tops KU 24-05B Drilling Procedure Page 48 Revision 0 April 2019 TOP MIME t1THOLOGY __- P3 Al Sands J Coals Gawwater 3,459 3,3270 123 275994 1459.3510.45 MAS Sands / Coals Gas/Water 3,507 3,373.0 129 276008 148D.05 P3 .A6 Sands l Coals GasMlater 3,603 3464.0 742 278036 1521.00 P3 A7 Sandal Coals GasNVeter 3,745 3,599.0 767 W2362173 278078 1581.75 P3 As Sands ICoals Gar.Water 3,775 3,827.0 184 276086 1594.35 P3 A9 SandslCoals GasWater 3,821 3,871.0 170 278100 1814.15 PJ Ail Sands l Coals Gawwater 3,841 6w690.0 173 278106 162270 PJ A11 Sands I Coals GasfWater 3,905 3.750.0 -3866 2382181 276124 1649.70 0.45 P9 91 Sands l Coals GawWater 3,978 3,819.0 .1735 2362191 278146 1580.75 0.45 P4 62 Sands l Coals Gawwater 4,059 3,896.0 3812 23lMD1 278169 1715.40 0.45 Pc 93 Sands l Coals Gas/Water 4,113W2362396 0 3864 2382209 276185 1738.80 0.45 P5 93a Sands/Gaels Gas 4,1870 3933 2362218 276207 1769.85 0.45 Ps B4 Sands l Coals Gas 4,2090 -3954 2362221 276213 1779.30 0.45 PS BS P6 Cl STORAGE Sands l Coals Gas 4,3830 -4120 2362244 276264 1854.00 0.45 Sands Gas 4,686 -4407 2362283 276352 1983.13 0.45 P6 C2 STORAGE Sands Gas 4,863 4574 2362306 276404 2058.30 8.43 L_IiFLCt.1.4 ilts I Sands I Coal Gas 4,9310 4838 2352315 276424 2087.10 0.45uIiets / Sands I Coal Gas 4,91170 -0891 2382323 276440 2110.95 0.45 un 2 ills I Sands 1 Ca Gas 5,0430 -4745 2362330 276457 2135.25 0.45 UB 3 Sts 1 Sends 1 Coal Gas 5,091 4.874.0 4790 2362336 1 276471 1 2155.50 0.45 UB 3A (Sends/Coal Gas 5,135 4,9180 41132 2382342 276484 2174.40 0.45 U94 1Sands l Coal Gas 5,171 4.950.0 4868Up 2382347 278494 2189.70 0.45 4A I Sands I Co Gas 5,197 4.974.0 4890 2382350 278501 2200.50 0.45 u9 4B 1 Sands / Co Gas 5,222 4,898.0 4914 2382353 276509 2217.30 0.45 112 5 its Is /cc Gas 5,248 5,023.0 4939 2382357 278516 222255 0.45. Up SA !Sends! Co Gas 5.277 5,050.0 4968 2382367 278525 2234.70 0.45 u9 58 / Sands i CID21Gas 5,312 5,0830 4999 2382366 278535 2249.55 0.45 Up 6 / Sends i Ca Gas 5,354 1230 5039 2382377 278547 2287.55 0.45 UB 7 !Sends / Co Gas 5,387 5.154.0 -5070 2302375 276557 2281.50 0.45 UB 7A its l Sem l Co Gas 5,409 5,178.0 5092 2382378 276564 2291.40 0.45. UB a ISands /Co Gas 5,487 5,230.D 5148 1 2382385 276580 2315.70 0. UB 9 / Sandal Ca GasMlater 5,522 5,28a0 5199 2382393 276597 2339.55 0. M BELt1GA /Sends!Co GasNVeterT 51594 5,351.0 -5267 1 2362402 278618 2370.15 0.45 1,12 t Dts l Sends 1 Co GasJwater 5,845 5.399.0 5315 2362409 276632 2391.75 0.45 1,18 2 its / Sanda l Cod Gas/Water 5,680 54320 -5348 2382413 278642 2405.60 0.45 h123 1Sands I Co Gasrwater 5,741 5,490.0 5408 2382427 278660 243270 0.45 M9,4 !Sands 1 Co Gas1water 5,813 5,558.0 5474 2352431 276682 2463.30 0.45 1,12 5 /Sands I Co Gasnater 5,918 51658.0 5574 2382444 278772 2508.30 0.4 1,12 6 / Sends! Co Gas 6,009 5.744.0 5860 2362456 276739 2547.00 0.45 1,12 7 / Sends l Co Gas 6,148 5.676.0 -5792 2382474 276779 2608.40 0.45 h12 x !Sends / Coal Gas 6,215 939.0 -5855 2382483 276799 1 2634.75 0.45 M99 its/Sands l Coal Gas 6,268 5,989.0 590.5 2382490 278814 286725 0.45 L BELLY -i.9 15andsi Co Wet 6,373 8.489.0 -6005 2382504 278845 2702.25 0.45 La I /Sandal Coal Wet 6,400 0,115.0 -8037 2382507 276853 2713.85 0.45 1.9 IA its / Sends I CosW Wet 60432 6,145.0 -6061LB- 2382511 278862 2727.05 0.45 1C ISand&I Gas 6,472 6-1820 -8098 2382517 278874 2744.10 0.45 La La I ills!Sands /Co at 6,504 8,213.0 -6129 2362521 276883 2758.05 0.45 1811 D s1Sends/Co Gas 6,559 13,265.05787 2362528 278899 2781.45 0.45 LB IE its!Sands ! Wet 6.618 8,320.0 -6236 2362536 276916 2805.20 0.45 LB IF I Sands 1 Co Wet 8,854 1 6.355.0 {8171 2382540 276927 2821.95 0.45 18 2 ! Sands / Co Wet 1 6,702 8,400.0 -6316 2362547 276941 2842.20 0.45 Page 48 Revision 0 April 2019 KU 24-058 Drilling Procedure LS 2A / Sands / Coal Wet 6.7598.484.0 -6370 2362354 276938 2886.50 0.45 LB 28 itts / Sands / Coal Wet 6,794 6,4680 -6404 2362359 270568 2881.80 0.43 LB 2C INS / Santls I Coal Wet 6,823 6,515.0 -6431 2382363 276977 2693.93 0.45 L8 2D Itts / Saws / Coal Gas 6 888 6.576.0 -6492 23625]1 276993 2921.40 0.45 LB 2E ills / Sands I Coal Wet 6.927 6,614.0 -6530 2362576 277007 2938.30 045 LB 3 ]iRs pts / Sands I Coal Wet 61989 6.6720 -6588 2362384 277023 4 0 296 6 045 LB 3.4 las / Sande I Coal Wet 7,025 8,707.0 -6623 2362389 2]7036 2980.35 0.45 LB 3B las / Sands / Coal Wet 7,058 6,737.0 -6653 2362593 2]]045 2993.83 0,45 LB 3C Itts / Sands / Coal Wet 7,102 6.179.0 -6693 2362599 277058 3012.73 0.45 LB 4 in / Sands / Coal Wet 7,136 6,830.0 -6746 2362606 2]]074 3035.70 0.45 LB 4.4 Itts / Sands / Coal Wel 7.192 6.865.0 -6781 2382611 277084 3051.45 0.45 LB 413 Itts / Sands / Coal Wel 7227 6.690-0 -8814 2362615 277094 3066.30 0.43 1.6 4C In / Sands / Coal Gas 7,264 6,933.0 -6849 2362620 277105 3082.05 0.43 LB 4D Itts / Sands / Coal Wet 7,334 6,999.0 -6913 2362629 277126 3111.75 045 LB 5 Itts / Santls / Coal Wet 7,356 7,022.0 -6938 2362632 277133 3122.10 OAS LS SA Itts I Sands / Coal Wel 7,368 7.032.0 -6948 2362634 277136 3126.60 0.43 LB 5B Itts / Sands I Coal Wet 7,439 7.098.0 -7014 2362643 277136 3156.30 0.43 L8 5C Itts I Sawa / Coal Wet 7,489 7.146.0 -7062 2362649 277171 31]].90 0.45 LB Itts l Santls/Coal Wel 7,521 7,176.0 -7092 2362634 277180 3191.40 045 LB 6A Itts / Sands / Coal Wel 7,532 7,186.0 -7102 2362655 277183 3195.90 OAS LB 68 In I Sands I Coal Wet 7.575 7227.0 -7143 2362661 2771% 321435 0.43 TYONEK Silts / Sands / COME Wet 7,591 7,242.0 -7158 2362663 277201 3221.10 0.45 TY 72 6 Santls/Coals Gas 7,635 7.2114.0 -7200 2362669 277214 3240.00 0.45 TY 73 1 Saws Coals Gas 7,665 7,312.0 -7228 2362672 277222 3252.60 0.43 TY 73 2 Sands / Coals Wel 7.703 7 349.0 -7265 2362677 2]]233 3269.25 OAS LR IA Sands Coals Wet 7,726 7,371.0 -7287 2362681 277240 3279.15 0.45 OE IB Sands Coals Wet 7.766 7.427.0 -7343 2362688 277238 3304.35 0.45 tlT IC Sands Coals Wel 7.871 7.508.0 -7424 2362899 277283 3340.80 0.43 UE ID Sands /Coals Gas 7,888 7,524.0 -7440 2SS 702 277267 3348.00 0.45 TV 758 Sands/Coals Gas 7941 7574.0 -7490 2362709 2]]303 3370.50 0.45 UT 2A Santls / Coals Wet 7,995 7,625.0 -7341 2362716 277319 339345 0.93 L'T 2B Sands / Coals I Wet 8,023 7,652.0 -7368 2362719 277327 3403.60 OAS TY 76 7 Sands/Coals Wet 8037 1 7,665.0 -7581 2362721 277331 3411.43 0.45 In 3A Sands / Coals Wet 8,105 7.730.0 -7616 2362730 277351 3440.70 0.45 OF 3B Sands/Coals Wet 8.138 7,761.0 -7677 2362734 277360 3434.63 045 TY 79 2 Sands l Coals Wel 8227 7.845.0 -7761 2362746 277386 3492.43 0.45 DF 4A Santls/Coals Wel 8,263 2679.0 -7793 2362751 277397 3307.73 OAS UT 4B Sands/Coals Gas 8,307 7.921.0 -7837 2382756 277410 3526.65 0.45 IA 4C Sands /Coals Wet 6.338 2950.0 -7866 2362760 2]]419 3339.70 043 M 4 Sands/Coals Wet 8,476 8,081.0 -7997 2362778 277459 3398.83 0.43 OF 4E Sands/Coals Wet 8,602 8,200.0 -8116 2362795 277496 3632.20 OAS OF 4F Sands /Coals Wet 8.699 8.293.0 -8209 2362808 277524 3694.03 0.43 T'"6A Sands/Coals I Wet 8,722 8314.0 -8230 2362811 277531 3703.30 0.45 TY 84 6B Sands /Coals Wel 8.804 f 8.392.0 -8308 2362821 277533 3738.80 045 TY " tiC Sands / Coals Gas 8,868 6,432.0 -6368 2362830 277374 3765.60 OAS TY B6 2 Santls / Coals Wet 5.911 8.493.0 -6409 2362835 277586 3784.05 0.45 T' 36 2.A Sands / Coals Wel 8.938 8,519.0 -8435 2362639 277394 379575 0.45 TY 86 2B Sands/Coals Gas 9,027 8.603.0 -8519 2362850 271r820 3833.55 OAS TY DI Santls Gas 9,154 8,723.0 -8639 2382867 277637 3ali 0.45 TY D2 Sands Gas 9,331 8,891.0 -8807 2362889 277707 3963.13 0.45 T' D3 A Sands Wet 9,440 8,998.0 -8914 2362900 277731 4011.90 043 TY D'- B Sands Wet 9,522 9,078.0 -8994 2362907 277/46 4047.30 0.45 TY DS Shale We hl 9,594 9,149.0 -9065 2362911 277736 4079.25 OAS TY D3 A Santls Gas 9,637 8,191.0 -9107 2382914 277/61 4011 18 0.45 T' D3 B Saws Gas 9,863 1 9.2120 -9133 2362915 277764 4109.85 0.43 TY D3 C Santls Wet 9.726 9,280.0 -9196 2362917 277769 4138.20 0.43 TY D3 D Sands Wel 9,757 9.311.0 -9227 2362918 277771 4152.15 0.45 TY D4 A Saws Gas 9.815 9.369.0 -9265 2362919 277 3 4178.25 0.45 TY Dt 8 Saws Gas 9.840 9.394.0 -9310 2362919 277773 4189.50 0.45 TY D4 C Sands Wet 9.872 9426.0 -9342 2362919 27]7]3 4203,90 0.45 TY D4 D Saws Gas 9,913 9,4670 -9353 2362919 277713 4222.35 0.43 TY D5 Santls Wet 9,952 9,506.0 -9422 2362919 277773 4239.90 043 TY D6 saws Gas 9,998 91552.0 -wee 2362919 2]7]73 4260.60 0.43 TY D6A Sands Wet 10.049 9.603.0 -9519 2362919 271773 4283.55 0.45 TY D68 Santls Wet 10.091 9,645.0 -9561 2362919 2]]7/3 430245 0.45 TY D7 Santls Wet 10.266 9.823.0 1 -9739 2362919 27=3 4382.55 OAS TY DB Saws Wet 10,366 9,920.0 1 -9836 2362919 1 2]]773 4426.20 0.43 Page 49 Revision 0 April 2019 5� N H�ilc 26.0 Anticipated Drilling Hazards 13-1/2" Hole Section: KU 24-05B 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 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: 1-12S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. Page 50 Revision 0 April 2019 n Hilcorp W-11 9-7/8" Hole Section: Lost Circulation: KU 24-05B 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. yNo abnormal pressures or temperatures are present in this hole section. Page 51 Revision 0 April 2019 U Hilcorp E -W ,:.., 6-3/4" Hole Section: KU 24-05B Drilling Procedure Lost Circulation: 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 1 — 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: H2S is not present in this hole section. No abnormal temperatures are present in this hole section. Abnormal pressure: • All formations above 8,500' TVD are at original pressure. Formations below this depth are over- pressured to 11.5 — 11.8 ppg EMW. This pressure regime exists from 8500' to TD of the well. Maintain MW at a minimum of 11.8 ppg with additions of barite from 8000' to section TD. The transition to • abnormal pressure occurs from 8500' to 10,000' TVD. Pore pressure increases from normal (8.5 — 9 ppg) to 11.5 — 11.7 ppg through this area. It is imperative that the MW be kept above 11.8 ppg to avoid influx into the wellbore. Page 52 Revision 0 April 2019 H Hilcorp E.ew C.WY 27.0 Rig Layout KU 24-05B Drilling Procedure Page 53 Revision 0 April 2019 KU 24-05B Procedure Drilling Procedure Hilcorp Enc ,2,T 28.0 FIT Procedure Formation InteErity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1 -minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre -determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre -determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 54 Revision 0 April 2019 Drilling Procedure Procedure Hileorp � czjx 29.0 Choke Manifold Schematic �. umrc rm a crv.Ea Page 55 Revision 0 April 2019 H Hilcorp E.m compmy KU 24-05B Drilling Procedure 30.0 Casing Design Information Calculation & Casing Design Factors Kenai Gas Unit DATE: 5-2-2019 WELL: KU 24-05B FIELD: Kenai Gas Unit DESIGN BY: David W Gorm in Criteria: Hole Size 9-7/8" Mud Density: 9.5 ppg Hole Size 6-3/4" Mud Density: 12.2 ppg Drilling Mode MASP (sec 1): 1948 psi (See attached MASP determination & calculation) MASP (sec 2): 3563 psi (See attached MASP determination & calculation) Production Mode MASP: 4400 psi (See attached MASP determination & calculation) Collapse Calculation: Section Calculation 1, 2 Normal gradient external stress (0.44 psi/ft) and the casing evacuated for the internal stress 3 Oserpressured external stress (0.63 psi/ft) and the casing evacuated Casinq Section Calculation/Specification 1 2 3 Casing OD 10-3/4" 7-5/8" 4-1/2" Top (MD) 0 0 0 Top (TVD) 0 j 0 0 Bottom (MD) 1,529 i 5,962 10,385 Bottom (ND) _ 1,500 1 5,730 10,084 Length 1,529 5,962 10,385 Weight (ppf) 45.5 29.7 12.6 Grade L-80 L-80 L-80 Connection TV BTC HYD563 TV BTC Weight w/o Bouyancy Factor (lbs) 69,570 177,071 130,851 Tension at Top of Section (lbs) 69,570 177,071 130,851 Min strength Tension (1000 Ids) 1040 683 288 Worst Case Safety Factor (Tension) 14.95 3.86 2.20 Collapse Pressure at bottom (Psi) 650 2,964 6,217 Collapse Resistance w/o tension (Psi) 2,470 4,790 7,500 Worst Case Safety Factor (Collapse) 3.80 1.62 1.21 MASP (psi) 650 1,948 3,563 Minimum Yield (psi)5,210 6,890 8,430 I Worst case safety factor (Burst) 8.02 •. 3.54 2.37 j Page 56 Revision 0 April 2019 n Hilcorp Energy Company KU 24-05B Drilling Procedure 31.0 9-7/8" Hole Section MASP Maximum Anticipated Surface Pressure Calculation xi9-7/8' Hole Section `_ KU 24,058 Kenai, Alaska MD TVD Planned Top: 1529 1500 Planned TD: 5962 5730 AntidoeMd Formations and Pressures: Fonnation TVD Est Pressure Oil/Gas/Wet PPG Grad P3 A4 3327 1459 Gas/Water &4 0.44 P3 AS 3373 148D Gas/Water 84 0.44 P3 A6 3,464 1521 Gas/Water &4 0.44 P3 A7 3599 1582 Gas/Water 815 0.44 P3 AS 3827 1594 Gas/Water 8.5 0.44 P3 A9 3,671 1614 Gas/Water &5 0.44 P3 AIO 3690 1623 Gas/water 18.5 0.44 P3 -AU 3750 1650 Gas/Water &5 0.44 P4 Bi 3819 1681 Gas/Water 8.5 0.44 P4 B2 3896 1715 Gas/Water &5 0.44 PS B3 3,948 1739 Gas/Water &5 0.44 PS B4X 4017 1770 Gas 11.5 0.44 PS B4 4,038 1779 Gas &5 Q44 PS BS 8704 1&54 Gas &5 0.41 P6 CISTORAGE 4491 1983 Gat &S 0.44 P6 C2STORAGE 4658 7058 Gas &S 0.44 U BELUGA 1 4,722 2067 Gas &5 0.44 UB_1 4775 2111 Gas &S 0.44 UB -2 4,829 2t35 Gas 11.5 0.44 LIB -3 4874 21% Gas &5 0.44 UB 304, 4916 2174 Gas &5 0.44 UB 4 4950 2190 Gas &S 0.44 US 4A 4974 2201 Gas &5 0.44 UB 4B 4998 2211 Gas &5 0.44 UB_5 5,023 2223 Gas &5 0.44 UB_5A 5050 2235 Gas &5 0.44 UB_SB 5,083 2250 Gas &5 0.44 UBL-6 5123 2268 Gas &5 0.44 1.18_7 5154 2282 Gas &5 0.44 UB 7A 4176 2291 Gas &5 0.44 UB_8 5730 2316 Gas &5 0.44 UB_9 5,283 2340 Gas/Water &5 0.44 M_BELUGA 5,351 2370 Gas/Water &5 OA4 MB_3 5,399 2392 Gas/Water &5 0.44 MB 2 5432 2407 Gas/water &5 0.44 MOL3 5,490 2433 Gas/Water 131.5 0.44 MB 4 5558 2463 Gas/Water &5 0.41 MB 5 5658 2508 Gas/Water &5 0.44 TD 5,730 2533 Gas/Water &5 0.44 Page 57 Revision 0 April 2019 H Hilcorp Enngy C.,Z, KU 24-05B Drilling Procedure Offset Well Mud Densities Well MW range Top (TVD) Bottom (TVD) Date KBU 42-06Y 9.0-9.7ppg 1,575 5,821 2014 KBU 23-05 9.0- 9.4 ppg 1,410 5,688 2014 KBU 11-08Z 9.0-9.4ppg 1,603 5,581 2014 Assumptions: 1. Maximum planned mud density forthe 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 1500'1VD=14.4 ppg EMW Fracture Pressure at 10-3/4" shoe considering a full column of gas from shoe to surface: 1500(ft)x0.75(psi/ft)= 1125 psi 1125(psi)-[0.1(psi/ft)*1500(ft)]= 975 psi MASP from pore pressure; entire wellbore evacuated to gas from TD 5730 (ft) x 0.44(psi/ft)= 2521 si 2521(psi)-[0.1(psi/ft)*5730(ft)]= 1948 psi 1938(psi)-[(2/3)*0.1(psi/ft)*5700(ft)]+[(1/3)*0.44(psi/ft)*5700(ft)]= 722 psi Alternate Drilling MASP Summary: 1. MASP while drilling 9-7/8" production hole is governed by SIBHP minus 2/3wellbore evacuated to gas from TD. Page 58 Revision 0 April 2019 U Hilcorp Enn Came y KU 24-05B Drilling Procedure 32.0 6-3/4" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 11 6-3/4" Hole Section H� 202 KU 24058 Kenai, Alaska MD TVD Planned Top: 5962 5730 Planned TD: 10385 10084 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad MB_7 5,876 2606 Gas &5 0.44 MB -8 5,939 2635 Gas &5 0.44 MB -9 5,989 2657 Gas &5 0.44 L_BELUGA 6,089 2702 Wet 8.5 0.44 LB 1B 6,182 2744 Gas 8.5 0.44 LB ID 6,265 2781 Gas &5 0.44 LB 4C 6,933 3082 Gas 8.5 0.44 TY_72_8 7,284 3240 Gas 8.6 0.44 TY_73_1 7,312 3253 Gas 8.6 0.44 UT -1D 7,524 3348 Gas &6 0.44 TY -75-8 7,574 3371 Gas &6 0.45 UT 4B 7,921 3527 Gas &6 0.45 TY -84 -GC 8,452 3766 Gas 8.6 1 0.45 TY_86_28 8,603 3834 Gas &6 0.45 TY Dl 8,723 3888 Gas 8.6 0.45 TY D2 8,891 3963 Gas 8.6 0.45 TY D3 A 9,191 4098 Gas &6 0.45 TY_D313 9,217 4110 Gas 116 0.45 T(_D3_C 9,280 4138 Wet 8.6 0.45 TY_D3_D 9,311 4152 Wet &6 0.45 TY D4 A 9,369 4178 Gas &6 0.45 TY D4 B 9,394 4190 Gas &6 0.45 TY D4 C 9,426 4204 Wet &6 0.45 TY_D4_D 9,467 4222 Gas &6 0.45 TY D5 9,506 4240 Wet &6 0.45 TY_D6 9,552 4261 Gas &6 M5 TD 10,084 6321 Wet 121 0.63 Page 59 Revision 0 April 2019 9 H Hilcorp Em, c"mnNr KU 24-05B Drilling Procedure Offset Well Mud Densities Well MW range Top (TVD) Bottom (TVD) Date KBU 42-06Y 9.7 - 12 ppg 5,821 10,029 2014 KBU 23-05 9.4- 12.1 ppg 5,688 9,884 2014 KBU 11-08Z 9.4-12.2 ppg 5,581 9,508 2014 Assumptions: 1. Maximum planned mud density for the 6-3/4" hole section is 12.2 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 5,730' TVD =14.0 ppg EMW Fracture Pressure at 7-5/8" shoe considering a full column of gas from shoe to surface: 5730 (ft) x 0.72(psi/ft)= 4126 psi / 4126 (psi) - [0.1(psi/ft)*5730(ft)]= 3553 psi y/ MASP from pore pressure; entire wellbore evacuated to gas from TD 10084(ft) x 0.63(psi/ft)= 6353 psi 6353(psi) - [0.1(psi/ft)*10084 (ft)]- 5345 psi 6353(psi) - [(2/3)*0.1(psi/ft)*10084(ft)]+[(1/3)*0.63(psi/ft)*10084(ft)]= 3563 psi Alternate Drilling MASP Summary: 1. MASP while drilling 6-3/4" production hole is governed by SIBHP minus 2/3 wellbore evacuated to gas from TD. Page 60 Revision 0 April 2019 KU 24 -OSB Drilling Procedure 33.0 Spider Plot (NAD 27) (Governmental Sections) ``KU 32 46It &l 1®U st.aex Bll t 1 1 •I@U M2 VIi lu=M BNL 1 ! / I K8U 3xAe / 1 I / 1 1 u29XOb81i 1 f ' 1 I 1 / `♦`l i MBu 9J03 BML ,Y9d[Bw 1 1♦♦ I � /l Ii�♦ 1 I 1 ; \ ; KN 21ddM BNL \ 1\ 11 `�♦ r ( I I ♦ 11 4 1 1 / 14J 2� BML` 1MU 01811 1 ! /�� '• � \111//L ( e1i 1 T� � xellumel I XBU 4z.aex 1 1 I �1alu sz48 B vtsoe 811E Ir I 1 NBU 12415 BML 1 i i 8 00II1u213) I� KU 24-05B TPH � �L 4x= 11-0B%11 BML \ IIBI tt qTX BML �y�pq' AL"_4-05B SHL 1 ♦♦ • `t�gy I.ax, I1aBNL %-IYOiUi91-0JR6 BHLINU ATXPNL ; ` ``�\. `,may 1W+KU IILB BML \ \ 1 ♦ 1 1♦ i 1 KN Y!-0TM BML KBU Ot-0T / I I • �` 11 11.11..tI uW 1u CTU 02iIT BML 1 1 Legend 1 I I • KU24-05B—SHL • OMer Sw f. Hole L..t, 1 \♦ I � X KU24-05B_TPH • OMer Bottom Hole Low�ic0 i �I@t12241TBK \ INJ 4}I + KU24-058_BHL _-- Well Paths \\ •1®1f4]A]X BIR Oil end Gas Und Bountlary Me 43AIN BHq _; Page 61 Kenai Unit KU 24-05B Well wp_08 Revision 0 0 500 1.10 1.500 2.ODO Feet Kaska Stale Plane Zane 4. NAD27 Map Dale: N10,2019 April 2019 H Hilcorp 13� yam KU 24 -OSB Drilling Procedure 34.0 Surface Plat (As Built) (NAD 27) ( mb ®KDU 9 p KENAI GAS FIELD PAD 41-7 tl KBU 42-6X® GRAPHIC SCALE C sr ',Y ':Y :CO 1 inch 100 ft C Cr4wAtbv I. FIF MKU 13-5 *BU 41-7 n ®KU 43-6RD m �*BU 41-7% n ®KDU 4 Y ®KU 43-6A KDU-20 ®KU 24-5RD Fm fiit-8 101 ®KU 43-- 7 o � O N Y mco 1 ® � Y O 1 m O 1 I KU 24-058 ' AS—BUILT THIS SURVEY Y i HILCORP ALASKA, LLC KU 24-058 AS -BUILT SURFACE LOCATION DIAGRAM KENAI GAS FIELD PAD 41.7 AluKka, LLC , SECTION 6 & 7, T4N, R11 W, S.M. ALASKA Page 62 Revision 0 April 2019 1-4 r m ®KU 34-6 - NORTH n � e x � - I + a n a x x m �mmcc y I ® ® M7 ®KBU 12-5 S6IS KBU 33-6® S7 PE r x � � ®KBU 42-06Y N N 19KTU 32-7H Y x I ®KDU 9 p KENAI GAS FIELD PAD 41-7 tl KBU 42-6X® GRAPHIC SCALE C sr ',Y ':Y :CO 1 inch 100 ft C Cr4wAtbv I. FIF MKU 13-5 *BU 41-7 n ®KU 43-6RD m �*BU 41-7% n ®KDU 4 Y ®KU 43-6A KDU-20 ®KU 24-5RD Fm fiit-8 101 ®KU 43-- 7 o � O N Y mco 1 ® � Y O 1 m O 1 I KU 24-058 ' AS—BUILT THIS SURVEY Y i HILCORP ALASKA, LLC KU 24-058 AS -BUILT SURFACE LOCATION DIAGRAM KENAI GAS FIELD PAD 41.7 AluKka, LLC , SECTION 6 & 7, T4N, R11 W, S.M. ALASKA Page 62 Revision 0 April 2019 1-4 U Hilcorp E� c.�r 35.0 Offset MW vs TVD Chart MW Vs TVD I 2000 4000 0 6000 H 10000 KU 24-05B Drilling Procedure 12000 8 8.5 9 9.5 10 10.5 MW (ppb) 11 11.5 12 12.5 Page 63 Revision 0 April 2019 Drilling Procedure Procedure Hilcorp Energy Compmy 36.0 Drill Pipe Information "--- SIZE 41/211 LE COMMRND WEIGHT: 16.6 LBS/FT ERIRRV SERVICES GRADE; S•135 RANGE 11(31.5') DRILL PIPE SPECS CONNECTION: CDS40 71,16E NEW PREMIUM IN MM W MM OD 4.500 1143 4,365 1 10.9 WALLTHICKNESS 0.337 8.6 0.270 6.8 ID 3.826 97.2 3.826 972 FYi.BS N -M FT -LBS N+M TORSIONAL STRENGTH 55.453 75.200 43.451 58.900 80% TORSIONAL STRENGTH 44.352 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 INS MMS IN, MMS CROSS SECTIONAL AREA BODY 4.407 2844 3.469 2238 CROSS SECTIONAL AREA OD 15.904 10261 14.966 9655'. CROSS SECTIONAL AREA ID 11.497 741 7 1 1•497 7417' INS MMs INS MM. SECTION MODULUS 4.271 69995 3.347 54845 POLAR SECTION MODULUS 8.543 139989 6.694 109690 TOOL JOINT EW PREMIUM PSI KPA PSI KPA YIELD STRENGTH 130,000 896,318 130.000 896,316 IN MM IN MM OD 5-2500 133.4 5.1198 130.0 ID 2.6875 68.3 2.6875 68-3 PIN LENGTH 1 1 .0 279.4 1 1 .O 279-4 BOX LENGTH 14.0 355.6 14.0 355.6 FTa.BS N -M FTiBS 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 -QP TORQUE 21,200 28.800 20,800 28200 MIN MAKEi1PTOROUE 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 Fr M APPROXIMATE LENGTH 31.50 9.60 GAL/FT MS/M FLUID DISPLACEMENT 0.273 0,003394 FLUIDCAPACITr 0.577 0.007169 IN MM DRIFT SIZE11 2.5625 65 Page 64 Revision 0 April 2019 KU 24-05B Drilling Procedure COMBINED LOAD CURVE FOR 4 1/2" 5-135 16.6 LBS/FT DRILL PIPE WITH CDS40 CONNECTIONS 9W,000 - _... - ... 800,000 - ]00,000 600,000 c 500.000 . C 400,000 %. 200 OCC mb 0 10,000 20.000 30,000 401000 50,000 60.000 POW TagllwJWW) NEWTUBE COMBINED LOAD .... PREMIUM TUBE COMBINED LOAD —MAKEUPTOROUE —SHOULDERSEPE"TION —PIN YIELD —BOX YIELD Page 65 Revision 0 April 2019 H HilcOrp Energy CompmY 37.0 Directional Program (WP02) KU 24-05B Drilling Procedure Page 66 Revision 0 April 2019 Hilcorp Alaska, LLC Kenai Gas Field KGF 41-7 Pad Plan: KU 24-05B KU 24-05B Plan: KU 24-05B wp08 Standard Proposal Report 09 May, 2019 HALLIBURTON Sperry Drilling Services Hilcorp Alaska, LLC KErEKtINUL INrUNMAIIUN HALLIBURTON t,, ordinate(NIE) Reference: Well Pian: KU 24-05B, True North Calculation Method: Minimum Curvature Vertical (D) Reference: Plan C$ 84.10usft (HEC 169) aperey Grilling Error System: ISCWSA lan @ 84.10usR (HEC 169) Seen Method: Closest Approach 30 Measured Depth Reference: P Error Surtace: Pedal Curve Calculation Method: Minimum Curvature Warning Method: Error Ratio Project: Kenai Gas Field s cTION DETAILS Site: KGF 41-7 Pad Sec MD Inc Ad ND +NIS +EI -W DIe9 TFace VSect Target Annota4on Well: Plan: KU 24-058 t 18.00 ODD 0.00 18.00 Doo 0.00 0.00 0.00 0+00 2 318.00 0.00 000 31800 0.00 000 000 0.00 000 Shut Dir2°1100':31SMD, 318' 1) Wellbore: KU 24058 76800 9.00 80.00 766.15 Son 35.27 2.00 90.00 32.78 Stan 01r25°It0T: 768' MD. 766AV5 4 1219.80 18.30 6094 1205.17 34.67 132.67 2.50 5136 136.29 End Dir: i 2198' MD. 12031TND Design: KU 24-05B wp08 5 5111,45 18.30 60.84 4900.00 630,00 1200.00 0.00 0.00 1347.75 IN 24058 ep08 CPI Ssm Dlr r110P : 5111.45' MD, 4900WI) fi 5388.711 11.19 70.39 511BID 6511117 1264.49 3.00 166.13 b17.53 End Dir t 53867' MD, 51689T NO 7 9461,44 11.18 78.39 9163.31 81573 203902 0.00 0.00 2196.13 Sam Dir 3°1100': 9451.44'MD, 91633tTVD 8 9834.59 0,00 66.12 9534.10 823,04 2074.62 3.00 180.00 2231,91 End Dir : 9834.59' MD. 9534.1' ND 9 10234.59 0 00 66.12 99N.10 823.04 2074.62 0.00 800 2231.91 KU 24-05B 4p08 Tul 10 10304.59 000 66A2 1084,10 823.03 2074.62 0.00 111 2231,91 Total Depth: 1038459' MD, 10084.1'ND Kenai Gas Field 5.291 KGF 41-7 Pad Plan: KU 244158 KU 24-058 KU 24.458 08 WELL DETAILS: Plan: KU 24-0513 -750- 66.10 +N/ -S +El -W Northing Easting LatlBude Longitude 0.00 0,00 2361491.39 275130.28 60° 27' 29.1664 N 151° 14' 44.5552 16" X 24" SUBJEY PROGRAM 0 Start Dir 2°/100' : 318' MD, 318'TVD Dale: 2019-05-03T00:0001) Valiaaaa: Yes Version: - - " - Depth From Depth To SunreylPlan Tool 500 Start Dir 2.5°/100': 768' MD, 766.15'TVD 18.00 1530.00 KU24-0511w 13 (KU24a5B) 2_Mwoarikl+MS+S, 1530.00 5962.00 KU 24-0511""03 IQJ 24-058) 2_MWD+IFRI+MS+Sag 596200 1038459 KU 24-0513 "08 (KU 24-0513) 2MWD+IFRI+MS+Sag 750 1p00 End Dir : 1219.8' MD, 1205.17'TVD FORMATION TOP DETAILS \ 10 3/4" X 13 1/2" NDPath NOSSPath MDPath Formation 1500 d 1,6-09 - - - 3326.10 3242.00 3453]1 P3 A4 3819.10 3735.00 3972.98 P4_131 3948.10 3864.00 4108,85 FE B3 2000 4489.10 4405.00 4678.67 P6 Cl STORAGE 4656.10 4572.00 4854.56 P6 C2 STORAGE 22504719.10 4635.00 4920.92 U_BELUGA 2.600 5347.10 5263.00 557130 M BELUGA 6085AD 6001.00 6323.52 L_BELUGA 6177.10 6093.00 6417.30 LB 1B 6260.10 6176.00 6501.91 LBID 160p0 6570.10 6486.00 68117.93 LB_20 3000 6929.10 6845.00 7183.88 LB 4C 727610 7192.00 7537.62 TY 72 8 _.3500 7302.10 7218.00 7564.12 W 73_1 P3 A4 7516.10 7432.00 7782.27 UT ID 7566.10 7462.00 7833.24 TY_75_8 3750 - 4_1PI_B1 __ ...... _ _.-4000 7913.10 7829.00 8186.97 UT 48 y _ - 8437.10 8353.00 8721.14 TY_84 6C PS B3 8581.10 8497.00 8867.93 TY_86 213 p - 8703.10 8619.00 8992.30 TY 01 C' PB C1 STORAGE 4500 8872.10 8788.00 9164.57 TY 02 '- _ --- 9172.10 9088.00 9470.39 TY D3 A 4500 PfiC2 STORAGE _ Start Dir 3a/100' : 5111.45' MD, 4900'ND 9359.10 9275.00 9859.35 TY_Di_A _ L - - - - - - 5000 - - - " 9381.10 9297.00 9681.43 TY_D4 B a U_BELUGA - " - - 9454.10 9370.00 9754.57 T1 D4_0 N ch _ - 9511.10 9457.00 9841.59 TY D6 Z5250- KU 24-05B wpO8 CPI 5500- - - - - - -End Dir :5388.7 MD, 5168.07 ND D. _ .. ....... _ __ .- ...- M BELUGA CASING DETAILS 6006 - - - - - - 7 5/8" z 9 7/8" NO NOSS MD Size Name H6000 120.00 35.90 120.00 16 16" x 24" L_BELUGA-- _ _.- _.. -., 1499.68 1415.58 1530.00 10-3/4 10314'x13112" LS IB, - - - 6500 5730.46 5646.36 5962.00 7-518 75/8'.97)8" LB_1D 10084.10 10000.00 10384.59 4-112 4104 63W 6750 LB -2D 7000 B- W-72-8_727z_e_7500 7500 TY -73-1 UT_4B N 84 6C SSW TY_86 213 " �g00 TY_DT; 9000 Start Dir 3o/100': 9461.44' MD, 9163.31'ND TY D3 A L5UUTY 041, TY D4 g - ___ _ _End Dir :9834.59'MD, 9534.1' ND 'JTY_Dd D _ 00 9750- TY -D6 _Total Depth :10384.59' MD, 10084.1' ND KU 24-056 wp08 Tgtl - - - - - - 4 1/2" x 6 3/4" 10500 KU 24-05B wp08 Tiii T 0 750 1500 2250 3000 3750 4500 5250 6000 Vertical Section at 68.36° (1500 usMin) NAW OM MCIN �i iUE/L�gvrm Ib" x 24" End Dv :1219.8'MD, 1205.17- WD 0 Start Dir 2.5-11W: : ]68' MD, 766.19WD Sean Dir 2"/IW' : 318' MD, 3187VD �Nrtiul (rv9f xWnn+' Pbn @�M 1da36�L twlxoiu Mrm uMg6.edrenu liMm®iev G10Mu6�XFLiWI nn IMM: Projec....enai Gas Fieltl Site: KGF 4t-7 Pad Will Plan: KU 24 -OSB Wellbore: KU 24058 Plan: KU 24-058 wp08 End Dv :1219.8'MD, 1205.17- WD 0 Start Dir 2.5-11W: : ]68' MD, 766.19WD Sean Dir 2"/IW' : 318' MD, 3187VD �Nrtiul (rv9f xWnn+' Pbn @�M 1da36�L twlxoiu Mrm uMg6.edrenu liMm®iev G10Mu6�XFLiWI nn IMM: 7 98" x 9 7/8" 110.385 KV 24059 uy08 C I o N o if KU 24-058 wp08 o $ c $ > o o$ Slert Diro3"/100':941.4 MD,9163.31'TVD EM Dir : 9834.59' MD, 9534.1' TVD' J � ?r oo Tore) Depth : 10384.59' �, 10084.1' TVD 'o Fnd Dir :5368]'hm, 51660TTVD Sr D1r 3"/100': 5111.45' MD, 49009 0 167 333 SW 667 8]] IOW 116] Wmt(-)/F tq+) (2501ss0/1n) T Stt UO See Name QD 0 35.90 120.00 16 .. IJ99fig 1415.50 I. 1530W 1039 10314-x 13W 57W 46564636 M 20 M ]-SIB 1..x.]2' 10084.10 1000 0.00 1(3843. 41R 41?x631V KV 24-05. uy08 T 1 4 M. x 6 3/4" 7 98" x 9 7/8" 110.385 KV 24059 uy08 C I o N o if KU 24-058 wp08 o $ c $ > o o$ Slert Diro3"/100':941.4 MD,9163.31'TVD EM Dir : 9834.59' MD, 9534.1' TVD' J � ?r oo Tore) Depth : 10384.59' �, 10084.1' TVD 'o Fnd Dir :5368]'hm, 51660TTVD Sr D1r 3"/100': 5111.45' MD, 49009 0 167 333 SW 667 8]] IOW 116] Wmt(-)/F tq+) (2501ss0/1n) i Project: Kenai Gas Field Site: KGF 41-7 Pad Well: Plan: KU 24-05B Wellbore: KU 24-05B Plan: KU 24-05B wp08 KBU 31-06X KN 4]-bXRD KT 43-6X 8000 5000 KT31431XRD2 ]000 6000 4000 5000 HALLISURTON %04 6w.ry o.In1.q t..va� 2000 4 12" x 6 3/4" 7 SB" x 9 7B" 3200 0000 $ F 4000 KU 4 4gg1 133 1000 02 KU I I KDU 2 (21-8) "� o KBU 4^---7RD D c KBU 42-7 0 fu4 g 1000 11 I-oliz I I -267 -133 0 133 267 West( -)/East(+) (20011sft/in) KU 14-05 2a5 000 West( -)/East(+) (600 m8/in) %04 2000 4 12" x 6 3/4" 7 SB" x 9 7B" 0000 $ KU 24-050 w 08 2000 KBU 1185 2000 o N� Q 'b K3U41-7x _ 4" 13 In $ K)UJg2 (2I-8) KBU 11-eY KDU 10 KDU 2 (21-8) No hb$ 2 �O Q KU 11-8 tr� KN 32-7H h g 00 KBU 11-08Z o _ v� N KBU 42 -]RD -I(DU-O4RD 3000 T M Azimulha b True Nodh Magnetic Nodh: 15.38° Magnetic Field Strength: 55187.1nT Dip Angle: 73.41° Dale: 511 Model: BGGM2018 -1200 -800 400. 0 400 800 1200 1600 2000 2400 2800 West( -)/East(+) (600 m8/in) HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Kenai Gas Field Site: KGF 41-7 Pad Well: Plan: KU 24-05B Wellbore: KU 24-05B Design: KU 24-058 wp08 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: KU 24-058 TVD Reference: Plan @ 84.10usft (HEC 169) MD Reference: Plan @ 84.10usft (HEC 169) North Reference: True Survey Calculation Method: Minimum Curvature 'roject Kenai Gas Field lap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level leo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point lap Zone: Alaska Zone 04 Using geodetic scale factor Site KGF 41-7 Pad Site Position: Northing: 2,361,462.42 Left Latitude: 60° 27'28 8295 N From: Lat/Long Easting: 274,852.80usft Longitude: 151° 14'50.0763 W Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid Convergence: -1.09 ' Well Plan: KU 24-05B, 519' FNL 8 771' FEL Well Position +N/S 0.00 usft Northing: 2,361,491.39 usft Latitude: 60' 27'29.1664 N +El -W 0.00 usft Easting: 275,130.28 usft Longitude: 151° 14'44.5552W Position Uncertainty 0.50 usft Wellhead Elevation: usft Ground Level: 66.10 usft Wellbore KU 24-058 Magnetics Model Name Sample Date Declination Dip Angle Field Strength U) P) (nT) BGG102018 5/3/2019 15.38 7341 55,187.07651008 Design KU 24-058 wp08 Audit Notes: Version: Phase: PLAN Tie On Depth: 18.00 Vertical Section: Depth From (TVD) -N/.S +El -W Direction (usft) (usft) (usft) (°) 18.00 0.00 0.00 68.36 Pian Sections Measured Vertical TVD Dogleg Build Tum Depth Inclination Azimuth Depth System +N/ -S +Et -W Rate Rate Rate Tool Face (usft) (') (') (usft) usft (usft) (usft) (°/100usft) ("/100usft) (°/100usft) (°) I 18.00 0.00 0.00 18.00 -66.10 0.00 0.00 0.00 0.00 0.00 0.00 318.00 0.00 0.00 318.00 233.90 0.00 0.00 0.00 0.00 0.00 0.00 768.00 9.00 90.00 766.15 682.05 0.00 35.27 2.00 2.00 0.00 90.00 1,219.80 18.30 60.84 1,205.17 1,121.07 34.67 132.87 2.50 2.06 -6.45 -51.36 5,111.45 18.30 60.84 4,900.00 4,815.90 630.00 1,200.00 0.00 0.00 0.00 0.00 5,388.70 11.19 78.39 5,168.07 5,083.97 656.67 1,264.49 3.00 -2.56 6.33 156.13 9,461.44 11.19 78.39 9,163.31 9.07921 815.73 2,039.02 0.00 0.00 0.00 0.00 9,834.59 0.00 66.12 9,534.10 9,450.00 823.04 2,074.62 3.00 -3.00 0.00 180.00 10,234.59 0.00 66.12 9,934.10 9,850.00 823.04 2,074.62 0.00 0.00 0.00 0.00 10,384.59 0.00 66.12 10,084.10 10,000.00 823.04 2,074.62 0.00 0.00 0.00 66.12 51912019 6:24:06PM Page 2 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Kenai Gas Field Site: KGF 41-7 Pad Well: Plan: KU 24 -OSB Wellbore: KU 24-05B Design: KU 24-05B wp08 Planned Survey Measured Vertical Depth Inclination Azimuth Depth (usft) (1) (1) (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" Easting DLS Vert Section 200.00 0.00 0.00 200.00 300.00 0.00 0.00 300.00 318.00 0.00 0.00 318.00 Start Dir 2-/100': 318' Will 318'TVD 275,130.28 400.00 1.64 90.00 399.99 500.00 3.64 90.00 499.88 600.00 5.64 90.00 599.54 700.00 7.64 90.00 698.87 768.00 9.00 90.00 766.15 Start Dir 2.5•1100': 768' MD, 766.15'TVD 800.00 9.52 86.22 797.73 900.00 11.35 76.80 896.08 1,000.00 13.40 70.09 993.76 1,100.00 15.58 65.18 1,090.57 1,200.00 17.85 61.47 1,186.35 1,219.80 18.30 60.84 1,205.17 End Dir : 1219.8' MD, 1205.17' TVD 2.00 1,300.00 18.30 60.84 1,281.31 1,400.00 18.30 60.84 1,376.25 1,500.00 18.30 60.84 1,471.20 1,530.00 18.30 60.84 1,499.68 10 3/4" x 13 112" 0.00 25.43 1,600.00 18.30 60.84 1,566.14 1,700.00 18.30 60.84 1,661.08 1,800.00 18.30 60.84 1,756.02 1,900.00 18.30 60.84 1,850.97 2,000.00 18.30 60.84 1,945.91 2,100.00 18.30 60.84 2,040.85 2,200.00 18.30 60.84 2,135.79 2,300.00 18.30 60.84 2,230.74 2,400.00 18.30 60.84 2,325.68 2,500.00 18.30 60.84 2,420.62 2,600.00 18.30 60.84 2,515.56 2,700.00 18.30 60.84 2,610.51 2,800.00 18.30 60.84 2,705.45 2,900.00 18.30 60.84 2,800.39 3,000.00 18.30 60.84 2,895.33 3,100.00 18.30 60.84 2,990.28 3,200.00 18.30 60.84 3,085.22 3,300.00 18.30 60.84 3,180.16 3,400.00 18.30 60.84 3,275.10 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: KU 24-058 TVD Reference: Plan @ 84.10usft (HEC 169) MD Reference: Plan @ 84.10usft (HEC 169) North Reference: True Survey Calculation Method: Minimum Curvature SWO19 6:24:06PM Page 3 COMPASS 5000.15 Build 91 Map Map TVDss +NIS +E/ -W Northing Easting DLS Vert Section usft (usft) (usft) (usft) (usft) 66.10 66.10 0.00 0.00 2,361,491.39 275,130.28 0.00 0.00 -15.90 0.00 0.00 2,361,491.39 275,130.28 0.00 0.00 -35.90 0.00 0.00 2,361,491.39 275,130.28 0.00 0.00 -115.90 0.00 0.00 2,361,491.39 275,130.28 0.00 0.00 .215.90 0.00 0.00 2,361,491.39 275,130.28 0.00 0.00 -233.90 0.00 0.00 2,361,491.39 275,130.28 0.00 0.00 -315.89 0.00 1.17 2,361,491.36 275,131.45 2.00 1.09 -415.78 0.00 5.78 2,361,491.28 275,136.05 2.00 5.37 .515.44 0.00 13.87 2,361,491.12 275,144.14 2.00 12.89 .614.77 0.00 25.43 2,361,490.91 275,155.70 2.00 23.64 -682.05 0.00 35.27 2,361,490.72 275,165.54 2.00 32.78 -713.63 0.17 40.41 2,361,490.80 275,170.68 2.50 37.63 -811.98 2.97 58.25 2,361,493.25 275,188.57 2.50 55.24 -909.66 9.16 78.74 2,361,499.06 275,209.17 2.50 76.57 -1,006.47 18.75 101.83 2,361,508.21 275,232.44 2.50 101.57 -1,102.25 31.71 127.49 2,361,520.67 275,258.34 2.50 130.20 -1,121.07 34.67 132.87 2,361,523.54 275,263.77 2.50 136.29 .1,197.21 46.94 154.86 2,361,535.39 275,285.99 0.00 161.26 -1,292.15 62.24 182.28 2,361,550.16 275,313.69 0.00 192.39 -1,387.10 77.53 209.70 2,361,564.94 275,341.40 0.00 223.52 -1,415.58 82.12 217.93 2,361,569.37 275,349.71 0.00 232.85 -1,482.04 92.83 237.12 2,361,579.71 275,369.10 0.00 254.65 -1,576.98 108.13 264.55 2,361,594.49 275,396.81 0.00 285.77 -1,671.92 123.43 291.97 2,361,609.26 275,424.51 0.00 316.90 -1,766.87 138.72 319.39 2,361,624.04 275,452.22 0.00 348.03 -1,861.81 154.02 346.81 2,361,638.81 275,479.92 0.00 379.16 -1,956.75 169.32 374.23 2,351,653.59 275,507.63 0.00 410.29 -2,051.69 184.62 401.65 2,361,668.37 275,535.33 0.00 441.42 -2,146.64 199.91 429.07 2,361,683.14 275,563.03 0.00 472.55 -2,241.58 215.21 456.49 2,361,697.92 275,590.74 0.00 503.68 -2,336.52 230.51 483.91 2,361,712.69 275,618.44 0.00 534.81 -2,431.46 245.81 511.34 2,361,727.47 275,646.15 0.00 565.94 -2,526.41 261.10 538.76 2,361,742.24 275,673.85 0.00 597.07 -2,621.35 276.40 566.18 2,361,757.02 275,701.56 0.00 628.20 -2,716.29 291.70 593.60 2,361,771.79 275,729.26 0.00 659.33 -2,811.23 307.00 621.02 2,361,786.57 275,756.96 0.00 690.46 -2,906.18 322.30 648.44 2,361,801.35 275,784.67 0.00 721.59 -3,001.12 337.59 675.86 2,361,816.12 275,812.37 0.00 752.72 -3,096.06 352.89 703.28 2,361,830.90 275,840.08 0.00 783.85 -3,191.00 368.19 730.70 2,361,845.67 275,867.78 0.00 814.98 SWO19 6:24:06PM Page 3 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Kenai Gas Field Site: KGF 41-7 Pad Well: Plan: KU 24-05B Wellbore: KU 24-05B Design: KU 24-058 wp08 Planned Survey Map Map Measured +N/ -S +FJ.W Vertical Fasting Depth Inclination Vert Section Azimuth Depth TVDss (usft) (°) x,242.00 (°) (usft) usft 3,453.71 18.30 60.84 3,326.10 -3,242.00 P3 -A4 2,361,860.45 275,895.49 0.00 846.11 3,500.00 18.30 60.84 3,370.05 -3,285.95 3,600.00 18.30 60.84 3,464.99 -3,380.89 3,700.00 18.30 60.84 3,559.93 -3,475.83 3,800.00 18.30 60.84 3,654.87 -3,570.77 3,900.00 18.30 60.84 3,749.82 -3,665.72 3,972.98 18.30 60.84 3,819.10 -3,735.00 P4 -B1 895.23 2,361,934.33 276,034.01 0.00 4,000.00 18.30 60.84 3,844.76 -3,760.66 4,100.00 18.30 60.84 3,939.70 -3,855.60 4,108.85 18.30 60.84 3,948.10 -3,864.00 PS -83 276,089.42 0.00 1,064.02 505.87 4,200.00 18.30 60.84 4,034.64 -3,950.54 4,300.00 18.30 60.84 4,129.59 -4,045.49 4,400.00 18.30 60.84 4,224.53 -4,140.43 4,500.00 18.30 60.84 4,319.47 -4,235.37 4,600.00 18.30 60.84 4,414.41 -4,330.31 4,678.67 18.30 60.84 4,489.10 -4,405.00 Pit C1 STORAGE 2,362,037.76 276,227.94 0.00 4,700.00 18.30 60.84 4,509.35 -4,425.25 4,800.00 18.30 60.84 4,604.30 -4,520.20 4,854.56 18.30 60.84 4,656.10 -4,572.00 P6 C2 STORAGE 276,283.35 0.00 1,281.93 4,900.00 18.30 60.84 4,699.24 -4,615.14 4,920.92 18.30 60.84 4,719.10 -4,635.00 U_BELUGA 1,313.06 628.25 1,196.86 2,362,096.86 5,000.00 18.30 60.84 4,794.18 -4,710.08 5,100.00 18.30 60.84 4,889.12 -4,805.02 5,111.45 18.30 60.84 4,900.00 -4,815.90 Start Dir 3-/100': 5111.45' MD, 4900'TVD 2,362,119.24 276,388.73 5,200.00 15.91 64.77 4,984.63 -4,900.53 5,300.00 13.32 70.81 5,081.39 .4,997.29 5,388.70 11.19 78.39 5,168.07 -5,083.97 End Dir : 5388.7' MD, 5168.07' TVD 276,428.15 0.00 5,400.00 11.19 78.39 5,179.15 -5,095.05 5,500.00 11.19 78.39 5,277.25 -5,193.15 5,571.20 11.19 78.39 5,347.10 -5,263.00 M_BELUGA 276,466.33 0.00 1,477.04 672.73 5,600.00 11.19 78.39 5,375.35 -5,291.25 5,700.00 11.19 78.39 5,473.44 -5,389.34 5,800.00 11.19 78.39 5,571.54 -5,487.44 5,900.00 11.19 78.39 5,669.64 -5,585.54 5,962.00 11.19 78.39 5,730.46 -5,646.36 7518"z 9718" Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan: KU 24-058 Plan @ 84.10usft (HEC 169) Plan @ 84.10usft (HEC 169) True Minimum Curvature 5/92019 6:24:06PM Page 4 COMPASS 5000.15 Build 91 Map Map +N/ -S +FJ.W Northing Fasting DLS Vert Section (usft) (usft) (usft) (usft) x,242.00 376.40 745.43 2,361,853.61 275,882.66 0.00 831.70 383.49 758.12 2,361,860.45 275,895.49 0.00 846.11 398.78 785.55 2,361,875.22 275,923.19 0.00 877.24 414.08 812.97 2,361,890.00 275,950.90 0.00 908.37 429.38 840.39 2,361,904.78 275,978.60 0.00 939.50 444.68 867.81 2,361,919.55 276,006.30 0.00 970.63 455.84 887.82 2,361,930.33 276,026.52 0.00 993.35 459.97 895.23 2,361,934.33 276,034.01 0.00 1,001.76 475.27 922.65 2,361,949.10 276,061.71 0.00 1,032.89 476.62 925.08 2,361,950.41 276,064.16 0.00 1,035.64 490.57 950.07 2,361,963.88 276,089.42 0.00 1,064.02 505.87 977.49 2,361,978.65 276,117.12 0.00 1,095.15 521.16 1,004.91 2,361,993.43 276,144.83 0.00 1,126.28 536.46 1,032.34 2,362,008.20 276,172.53 0.00 1,157.41 551.76 1,059.76 2,362,022.98 276,200.23 0.00 1,188.54 563.79 1,081.33 2,362,034.60 276,222.03 0.00 1,213.03 567.06 1,087.18 2,362,037.76 276,227.94 0.00 1,219.67 582.35 1,114.60 2,362,052.53 276,255.64 0.00 1,250.80 590.70 1,129.56 2,362,060.59 276,270.76 0.00 1,267.78 597.65 1,142.02 2,362,067.31 276,283.35 0.00 1,281.93 600.85 1,147.76 2,362,070.40 276,289.14 0.00 1,288.44 612.95 1,169.44 2,362,082.08 276,311.05 0.00 1,313.06 628.25 1,196.86 2,362,096.86 276,338.76 0.00 1,344.19 630.00 1,200.00 2,362,098.55 276,341.93 0.00 1,347.75 641.95 1,223.12 2,362,110.06 276,365.27 3.00 1,373.65 651.58 1,246.40 2,362,119.24 276,388.73 3.00 1,398.84 656.67 1,264.49 2,362,123.99 276,406.91 3.00 1,417.53 657.11 1,266.64 2,362,124.39 276,409.06 0.00 1,419.69 661.01 1,285.66 2,362,127.94 276,428.15 0.00 1,438.81 663.79 1,299.20 2,362,130.46 276,441.74 0.00 1,452.42 664.92 1,304.67 2,362,131.48 276,447.24 0.00 1,457.92 668.82 1,323.69 2,362,135.03 276,466.33 0.00 1,477.04 672.73 1,342.71 2,362,138.57 276,485.41 0.00 1,496.16 676+64 1,361.73 2,362,142.12 276,504.50 0.00 1,515.27 679.06 1,373.52 2,362,144.31 276,516.33 0.00 1,527.13 5/92019 6:24:06PM Page 4 COMPASS 5000.15 Build 91 Halliburton HALLI B U RTO N Standard Proposal Report Database: Company: Project: Site: Well: Wellbore: Design: NORTH US +CANADA Hilcorp Alaska, LLC Kenai Gas Field KGF 41-7 Pad Plan: KU 24-05B KU 24-05B KU 24-05B wp08 Local Co-ordinate Reference: Well Plan: KU 24-05B ND Reference: Plan @ 84.10usft (HEC MD Reference: Plan @ 84.10usft (HEC North Reference: True Survey Calculation Method: Minimum Curvature 169) 169) Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NIS +EI -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) -5,683.64 6,000.00 11.19 78.39 5,767.74 -5,683.64 680.54 1,380.74 2,362,145.66 276,523.59 0.00 1,534.39 6,100.00 11.19 78.39 5,865.83 5,781.73 684.45 1,399.76 2,362,149.21 276,542.67 0.00 1,553.51 6,200.00 11.19 78.39 5,963.93 -5,879.83 688.35 1,418.78 2,362,152.75 276,561.76 0.00 1,572.63 6,300.00 11.19 78.39 6,062.03 -5,977.93 692.26 1,437.80 2,362,156.30 276,580.85 0.00 1,591.74 6,323.52 11.19 78.39 6,085.10 -6,001.00 693.18 1,442.27 2,362,157.13 276,585.34 0.00 1,596.24 L_BELUGA 6,400.00 11.19 78.39 6,160.13 -6,076.03 696.16 1,456.81 2,362,159.84 276,599.94 0.00 1,610.86 6,417.30 11.19 78.39 6,177.10 -6,093.00 696.84 1,460.10 2,362,160.45 276,603.24 0.00 1,614.17 LB_1B 6,500.00 11.19 78.39 6,258.22 -6,174.12 700.07 1,475.83 2,362,163.39 276,619.02 0.00 1,629.98 6,501.91 11.19 78.39 6,260.10 -6,176.00 700.14 1,476.20 2,362,163.45 276,619.39 0.00 1,630.34 LB_1D 6,600.00 11.19 78.39 6,356.32 -6,272.22 703.97 1,494.85 2,362,166.93 276,638.11 0.00 1,649.10 6,700.00 11.19 78.39 6,454.42 -6,370.32 707.88 1,513.87 2,362,170.48 276,657.20 0.00 1,668.21 6,800.00 11.19 78.39 6,552.52 -6,468.42 711.78 1,532.88 2,362,174.02 276,676.28 0.00 1,687.33 6,817.93 11.19 78.39 6,570.10 -6,486.00 712.48 1,536.29 2,362,174.66 276,679.70 0.00 1,690.76 LB_2D 6,900.00 11.19 78.39 6,650.61 -6,566.51 715.69 1,551.90 2,362,177.56 276,695.37 0.00 1,706.45 7,000.00 11.19 78.39 6,748.71 -6,664.61 719.60 1,570.92 2,362,181.11 276,714.46 0.00 1,725.57 7,100.00 11.19 78.39 6,846.81 -6,762.71 723.50 1,589.94 2,362,184.65 276,733.54 0.00 1,744.68 7,183.89 11.19 78.39 6,929.10 -6,845.00 726.78 1,605.89 2,362,187.63 276,749.56 0.00 1,760.72 LB_4C 7,200.00 11.19 78.39 6,944.90 -6,860.80 727.41 1,608.95 2,362,188.20 276,752.63 0.00 1,763.80 7,300.00 11.19 78.39 7,043.00 -6,958.90 731.31 1,627.97 2,362,191.74 276,771.72 0.00 1,782.92 7,400.00 11.19 78.39 7,141.10 -7,057.00 735.22 1,646.99 2,362,195.29 276,790.81 0.00 1,802.03 7,500.00 11.19 78.39 7,239.20 -7,155.10 739.12 1,666.01 2,362,198.83 276,809.89 0.00 1,821.15 7,537.62 11.19 78.39 7,276.10 -7,192.00 740.59 1,673.16 2,362,200.17 276,817.07 0.00 1,828.34 TY -72-8 7,564.12 11.19 78.39 7,302.10 -7,218.00 741.63 1,678.20 2,362,201.11 276,822.13 0.00 1,833.41 TY -73-1 7,600.00 11.19 78.39 7,337.29 -7,253.19 743.03 1,685.02 2,362,202.38 276,828.98 0.00 1,840.27 7,700.00 11.19 78.39 7,435.39 -7,351.29 746.93 1,704.04 2,362,205.92 276,648.07 0.00 1,859.39 7,782.27 11.19 78.39 7,516.10 -7,432.00 750.15 1,719.69 2,362,208.64 276,863.77 0.00 1,875.12 UT_1D 7,800.00 11.19 78.39 7,533.49 -7,449.39 750.84 1,723.06 2,362,209.47 276,867.15 0.00 1,878.50 7,833.24 11.19 78.39 7,566.10 -7,482.00 752.14 1,729.38 2,362,210.65 276,873.50 0.00 1,884.86 TY -75-8 7,900.00 11.19 78.39 7,631.59 -7,547.49 754.74 1,742.08 2,362,213.01 276,886.24 0.00 1,897.62 8,000.00 11.19 78.39 7,729.68 -7,645.58 758.65 1,761.09 2,362,216.56 276,905.33 0.00 1,916.74 8,100.00 11.19 78.39 7,827.78 -7,743.68 762.56 1,780.11 2,362,220.10 276,924.42 0.00 1,935.86 8,186.97 11.19 78.39 7,913.10 -7,829.00 765.95 1,796.65 2,362,223.19 276,941.02 0.00 1,952.48 UT -4B 8,200.00 11.19 78.39 7,925.88 -7,841.78 766.46 1,799.13 2,362,223.65 276,943.50 0.00 1,954.97 8,300.00 11.19 78.39 8,023.98 -7,939.88 770.37 1,818.14 2,362,227.19 276,962.59 0.00 1,974.09 8,400.00 11.19 78.39 8,122.07 -8,037.97 774.27 1,837.16 2,362,230.74 276,981.68 0.00 1,993.21 51912019 6:24:06PM Page 5 COMPASS 5000.15 Build 91 Halliburton H ALL I B U R TO N Standard Proposal Report Database: NORTH US +CANADA Local Co-ordinate Reference: Well Plan: KU 24-05B Company: Hilcorp Alaska, LLC TVD Reference: Pian @ 84.10usft (HEC 169) Project: Kenai Gas Field MD Reference: Plan @ 84.10usft (HEC 169) Site: KGF 41-7 Pad North Reference: True Well: Plan: KU 24-05B Survey Calculation Method: Minimum Curvature Wellbore: KU 24-05B Design: KU 24 -OSB wp08 Azimuth Depth Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +PJ -W Northing Easting DLS Vert Section (usft) (1) (") (usft) usft (usft) (usft) (usft) (usft) -8,136.07 8,500.00 11.19 78.39 8,220.17 -8,136.07 778.18 1,856.18 2,362,234.28 277,000.76 0.00 2,012.33 8,600.00 11.19 78.39 8,318.27 -8,234.17 782.08 1,875.20 2,362,237.83 277,019.85 0.00 2,031.44 8,700.00 11.19 78.39 8,416.36 -8,332.26 785.99 1,894.21 2,362,241.37 277,038.94 0.00 2,050.56 8,721.14 11.19 78.39 8,437.10 -8,353.00 786.81 1,898.23 2,362,242.12 277,042.97 0.00 2,054.60 TY_84_BC 8,800.00 11.19 78.39 8,514.46 -8,430.36 789.89 1,913.23 2,362,244.92 277,058.02 0.00 2,069.68 8,867.93 11.19 78.39 8,581.10 -8,497.00 792.55 1,926.15 2,362,247.33 277,070.99 0.00 2,082.66 TY 86_2B 8,900.00 11.19 78.39 8,612.56 -8,528.46 793.80 1,932.25 2,362,248.46 277,077.11 0.00 2,088.79 8,992.30 11.19 78.39 8,703.10 -8,619.00 797.40 1,949.80 2,362,251.73 277,094.73 0.00 2,106.44 TY D1 9,000.00 11.19 78.39 8,710.66 -8,626.56 797.70 1,951.27 2,362,252.01 277,096.20 0.00 2,107.91 9,100.00 11.19 78.39 8,808.75 -8,724.65 801.61 1,970.28 2,362,255.55 277,115.29 0.00 2,127.03 9,164.57 11.19 78.39 8,872.10 -8,788.00 804.13 1,982.56 2,362,257.84 277,127.61 0.00 2,139.37 TY -D2 9,200.00 11.19 78.39 8,906.85 -8,822.75 805.52 1,989.30 2,362,259.10 277,134.37 0.00 2,146.15 9,300.00 11.19 78.39 9,004.95 -8,920.85 809.42 2,008.32 2,362,262.64 277,153.46 0.00 2,165.26 9,400.00 11.19 78.39 9,103.05 -9,018.95 813.33 2,027.34 2,362,266.19 277,172.55 0.00 2,184.38 9,461.44 11.19 78.39 9,163.31 -9,079.21 815.73 2,039.02 2,362,266.36 277,184.27 0.00 2,196.13 Start Dir 3°7100' : 9461.44' MD, 9163.31'TV13 9,470.39 10.93 78.39 9,172.10 -9,088.00 816.07 2,040.70 2,362,268.68 277,185.96 3.00 2,197.82 TY_O3 A 9,500.00 10.04 78.39 9,201.22 -9,117.12 817.15 2,045.98 2,362,269.66 277,191.26 3.00 2,203.12 9,600.00 7.04 78.39 9,300.10 -9,216.00 820.14 2,060.52 2,362,272.37 277,205.85 3.00 2,217.74 9,659.35 5.26 78.39 9,359.10 -9,275.00 821.42 2,066.75 2,362,273.53 277,212.10 3.00 2,224.00 TY_D4_A 9,681.43 4.59 78.39 9,381.10 -9,297.00 821.80 2,068.60 2,362,273.88 277,213.97 3.00 2,225.86 TY D4 8 9,700.00 4.04 78.39 9,399.62 -9,315.52 822.08 2,069.97 2,362,274.13 277,215.34 3.00 2,227.24 9,754.57 2.40 78.39 9,454.10 -9,370.00 822.70 2,072.97 2,362,274.69 277,218.35 3.00 2,230.26 TY D -O4 9,800.00 1.04 78.39 9,499.51 -9,415.41 822.97 2,074.31 2,362,274.94 277,219.69 3.00 2,231.60 9,834.59 0.00 66.12 9,534.10 -9,450.00 823.04 2,074.62 2,362,275.00 277,220.00 3.00 2,231.91 End Dir : 9834.59' MD, 9534.1' TVD 9,841.59 0.00 0.00 9,541.10 -9,457.00 823.04 2,074.62 2,362,275.00 277,220.00 0.00 2,231.91 TY D6 9,900.00 0.00 0.00 9,599.51 -9,515.41 823.04 2,074.62 2,362,275.00 277,220.00 0.00 2,231.91 10,000.00 0.00 0.00 9,699.51 -9,615.41 823.04 2,074.62 2,362,275.00 277,220.00 0.00 2,231.91 10,100.00 0.00 0.00 9,799.51 -9,715.41 823.04 2,074.62 2,362,275.00 277,220.00 0.00 2,231.91 10,200.00 0.00 0.00 9,899.51 -9,815.41 823.04 2,074.62 2,362,275.00 277,220.00 0.00 2,231.91 10,234.59 0.00 66.12 9,934.10 -9,850.00 823.04 2,074.62 2,362,275.00 277,220.00 0.00 2,231.91 10,300.00 0.00 0.00 9,999.51 -9,915.41 823.04 2,074.62 2,362,275.00 277,220.00 0.00 2,231.91 10,384.59 0.00 0.00 10,084.10 -10,000.00 823.04 2,074.62 2,362,275.00 277,220.00 0.00 2,231.91 Total Depth : 10384.59' MD, 10084.1' TVD - 41/2" x 6 3/4" SWO19 6:24:06PM Page 6 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Kenai Gas Field Site: KGF 41-7 Pad Well: Plan: KU 24-058 Wellbore: KU 24-05B Design: KU 24-05B wp08 Local Co-ordinate Reference: ND Reference: MD Reference: North Reference: Survey Calculation Method: Targets Target Name -hitimiss target Dip Angle Dip Dir. TVD -Shape (°) (°) (usft) KU 24-05B wp08 Tun 0.00 0.00 9,934.10 - plan hits target center - Paint KU 24-05B wp08 CP1 0.00 - plan hits target center - Paint Casing Points Measured Vertical P4 Bi Depth Depth P3 A4 (usft) (usft) TY_D4_A 1,530.00 1,499.68 10 3/4"x 13 1/2" 10,384.59 10,084.10 4 112" x 6 3/4" 5,962.00 5,730.46 7 5/8" x 9 7/8" 120.00 120.00 16" x 24• Halliburton Standard Proposal Report Well Plan: KU 24-056 Plan @ 84.10usft (HEC 169) Plan @ B4.10usft (NEC 169) True Minimum Curvature +N/ -S +EJ -W Northing Eastal (usft) (usft) (usft) (usft) 823.04 2,074.62 2,362,275.00 277,220.00 0.00 4,900.00 630.00 1,200.00 2,362,098.55 276,341.93 Casing Hole Diameter Diameter Name (11) () 10-314 13-1/2 4-1/2 6-3/4 7-5/8 9-7/8 16 24 Formations Measured Vertical Vertical Depth Depth Depth SS (usft) (usft) Name Dip Dip Direction Lithology (I (I 3,972,98 3,819.10 P4 Bi 3,453.71 3,326.10 P3 A4 9,659.35 9,359.10 TY_D4_A 8,721.14 8,437.10 TY_84_So 6,501.91 6,260.10 LB -1 9,841.59 9,541.10 TY—D6 7,833.24 7,566.10 TY_75_8 4,854.56 4,656.10 P6_C2 STORAGE 6,323.52 6,085.10 L_BELUGA 8,186.97 7,913.10 UT_4B 4,920.92 4,719.10 U_BELUGA 4,678.67 4,489.10 P6—CI STORAGE 9,164.57 8,872.10 TY -02 9,754.57 9,454.10 TY_D4_D 7,782.27 7,516.10 UT -1D 7,537.62 7,276.10 TY_72_8 4,108.85 3,948.10 P5133 9,681.43 9,681.43 9,381.10 TY_D4_B 5,571.20 5,347.10 M_BELUGA 6,817.93 6,570.10 LB_2D 8,867.93 8,581.10 TY—B6-2B 9,470.39 9,172.10 TV_D3_A 8,992.30 8,703.10 TY—DI 7,564.12 7,302.10 TY_73_1 6,417.30 6,177.10 LB_1B 7,183.89 6,929.10 LB_4C 5/912019 6:24:06PM Page 7 COMPASS 5000.15 Build 91 HQLLIBURTON Database: NORTH US+CANADA Company: Hiloorp Alaska, LLC Project: Kenai Gas Field Site: KGF 41-7 Pad Well: Plan: KU 24-05B Wellbore: KU 24-05B Design: KU 24-05B wp08 Plan Annotations Measured Vertical Depth Depth (usft) (usft) 318.00 318.00 768.00 766.15 1,219.80 1,205.17 5,111.45 4,900.00 5,388.70 5,168.07 9,461.44 9,163.31 9,834.59 9,534.10 10,384.59 10,084.10 Local Corordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Local Coordinates -NIS +E/ -W (usft) (usft) 0.00 0.00 0.00 35.27 34.67 132.87 630.00 1,200.00 656.67 1,264.49 815.73 2,039.02 823.04 2,074.62 823.04 2,074.62 Halliburton Standard Proposal Report Well Plan: KU 24-05B Plan @ 34.10usft (HEC 169) Plan @ 84.10usft (HEC 169) True Minimum Curvature Comment Start Dir 2-1100': 318' MD, 318'TVD Start Dir 2.5°/100' : 768' MD, 766.15'TVD End Dir : 1219.8' MD, 1205.17' TVD Start Dir 3°/100' : 5111.45' MD, 4900'TVD End Dir : 5388.7' MD, 5168.07' TVD Start Dir Wit 00': 9461.44' MD, 9163.317VD End Dir : 9834.59' MD, 9534.1' TVD Total Depth: 10384.59' MD, 10084.1' TVD 5/912019 6:24:06PM Page 8 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Kenai Gas Field KGF 41-7 Pad Plan: KU 24-05B KU 24-05B KU 24-05B wp08 Sperry Drilling Services Clearance Summary Anticollision Report 09 May, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (HigM1slde Reference) Reference Design: KGF 417 Pad - Plan: KU 2405H -KU 24 -05B -KU 2405B wp08 Well Coordinates: 2,361,491 ]9 N, 275,100.28 E (60. 2T 291 T' N,151.14' 4456" M Datum Height: Plan l@ 84.10ush(HEC 169) Scan Range: Dog to 10,384.59 usfl. Measured Depth. Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation @ 1,000.00 poll Gamete, Scale Factor Applied Version: 5000.15 StAK 91 Scan Type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 10011000 of references Soon Type: 25.00 HALLIBURTON Sperry Drilling Services Hilcorp Alaska, LLC HALLIBURTON Kenai Gas Field Anticollision Report for Plan: KU 24-05B - KU 24-05B wp08 Clo est Approach 30 Frexlmay Scan on Currant Survey Data (KIgholde Reference) Reference Design: KGF 416 Pad -Plan: KU 2445B -KU U45B-KU 2445B a;,08 Scan Range: 0.00 to 10,384.59 usn. Measured Depth. Scan Radius is Unlimited. Clearance Factor citing is Unlimited Max Ellipse Separation is 1,000.00 usR Measured Minimum @Meaeuretl Ellipse siMeasured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Companson Well Name- Wellborn Name- Design push) (usn) (..ft) (pan) usit Kenai Deep Unit 2 KDU 2-KDU 2(21-8)-KDU 2(21-8) 57641 227.73 57641 22690 561.69 31349 Centre Distance Pass - KDU 2-KDU 2(21-8)-KDU 2(21-8) 60000 227.85 600.0 220.78 581.01 32232 Ellgse Separation Pass - KDU2-KDU 2(21 a)-KDU 2(21-8) 1,400.00 256.71 1.400.00 240.71 1,31427 16.040 Clearance Factor Pass KGF 41-7 Pad KBU 11-08Z-KBU II -OU -KBU 11-08Z 392.55 64.97 392.55 61.53 39340 18.871 Denlre Distance Pass - MU 11-08Z - KSU 11-082-KBU 11-08Z 425.00 6540 425.00 61.43 425.80 17,742 Ellipse Separation Pass - KBU 11-002-KBU 11-O8Z-KBU 11-08Z 800.40 84.75 800.00 78.14 798.35 12.025 Clearance Factor Pass - KBU 118X-KBU II -BX -KBU 11-8X 7,061,13 134.80 7,061.13 71.06 7,067,70 2.142 Centre Distance Pass KBU if -8X- KBU 118X. KBU 11-8X 7,150.00 13507 7,150.00 71.40 7,158.36 2.121 Ellipse Separatum Pass- KBU1I-BX-KBU II -BX -KDU 118X 7,175.00 13529 7,17500 71.45 7,180.96 2.119 Clearance Factor Pass- KBU 11-SY-KRU 118Y-KRU 118Y 2,325.00 248.54 2,325.00 227.29 2,326,95 11,694 Clearance Factor Pace - KBU 11 -BY -KBU II-8Y-KBU it -8Y 2,335.52 248.51 2,335.52 227.27 2,336.66 11100 Ellipse Separetion Pass - KBU 31-06X-KBU 31-06X-KBU 31-06% 502.04 'PID8 502.04 27.58 50270 2.671 Centre Distance Pass- KBU 31-06X-KBU 31-06X. KBU 31-06X 52500 44.27 52500 2145 525.33 2.632 Clearer. Factor Pass- KBU 41 -7 -hall 41-7-KBU 41-7 1,416.60 289.26 1.41680 273.06 1.392.46 17.852 Cenlre Distance pass - KBU 41 -7 -Men 41-7. KBU 41-7 1,450.00 289.46 1.450.00 272.85 1,424.02 17.428 Ellipse Separation Paas- KBU41-7-KRU 41-7-KBU 41-7 1,925.0D 330.97 1825.00 309.93 1,87685 15.720 Clearance Factor Pass- KBU 41-7X-KBU 4I-0X-KBU 41-7X 1,447,76 179,16 1,447.76 16827 1,421.95 16.444 Centre Distance Pass - KBU 4I-0X-KRU 4IJX-KBU 414X 1,450.00 179.16 1.450.00 168.25 1.424.04 16421 Ellipse Separation pass - KBU417X-KBU 41-9X-KBU 41-7X 1,525.00 181.07 1,525.00 169.67 1,494.85 15.884 Clearance Factor Pace- KBU 42-7-KBU 42-7-KBU 42-7 1,99683 WAS 11996.83 332.81 2,055.95 23.700 Centre Distance Pass - KBU42-7-KBU 42-7-KBU 42-7 2,02500 347.61 2.025.00 332.71 2,08343 23.327 Ellipse5eparatmn Pass- KBU 42-7-KBU 42-0-KRU 42-7 2,550.00 411.75 21550.00 381.31 2,572.76 20,146 Clea2nce Factor Pass- KBU 42-7-KBU 42-7RD-KBU 42-0RD 1,996.83 WAS 1,996.83 33281 2.055.95 23.700 Cemre Distance Pass - KBU 42-9-KBU 42-7RD-KBU 42-7RD 2,025.00 347.61 2,02500 332.71 2,083.43 23.327 Ellipse SepmaUset Pass - KBU 42-7 - KBU 42-7RD-KBU42-7RD 2,550.00 411.75 2,550.00 391.31 2,572.76 20.146 Clearance Factor Pass - KDU-02 (21-8) - KDU 02(21-8)-KDU 02 (21,8) 1.428,70 114.80 1,42870 92.80 1,406A4 5.203 Centre Distance Pass- 09 May. 2019 - 18.25 Page 2 m6 COMPASS HALLIBURTON I � Hilcorp Alaska, LLC Kenai Gas Field Anticollision Report for Plan: KU 24-05B - KU 24-05B wp08 Closest Approach 3D Proximity sun on Consul Survey Data (HigM1sitle Reference) Reference Design: KGF 41.7 Pad -Plan: KU U458-KU 24-0513-KU 24458 wpOB Sun Range: 0.00 W 10,380.59 rift. Unsecured Depth. Sum Radius is Unlimited. Clearance Fscbr cutoff is Unlimited Max Ellipse Separation Is 1,000.00 can Site Nemo Measured Minimum @Musumd Ellipse ®Measuretl Clearance summary Sued on Com parison Well Name-Wellbore Name-Design Depth Distance Depth Separation Depth Factor Minimum se [ para ion Warning Warning (..ft) daft) fmft) (usft) rift 02(214)-KDU 02(21-8) KDU-02(21-8)-KOU 02(214)-KDU 02(21-8) 1,45000 115.07 1,450.00 92.80 1,426.21 5.167 Ellipse Sepaatlpn Pass- KOU-04-KDL -KDU-Oa 1,4)500 115.]8 1,4]500 93.33 1,449.29 5.157 Clearance Fedor Pass - KDU-04-KDU-04-KDU-04 889.25 22]33 689.25 21639 919.84 20.)]] Canoe Distance Pass- MU-04- KOU-0a NDU-04- 80000 22]3) 900'00 21029 929.51 20.51) Ellipse Separation Pess- 1,075.00 243.00 1,075.00 229.65 1,080.31 19.206 Cleeance Factor Pass- KDU-04-KDU04RD-KDU-04R0 KDU-04-KDU-04RD-KDU-04RD 889.25 227.33 88925 218.39 919.64 20= Centre Distance Pass - KOU-04-KDU-04RD-KDU-04RD 900.00 22).3] 900.00 216.29 929.51 20.517 Ellipse Separation Pass- KDU-IO -KDU Ili -KDU 10 1,0)5.01) 243.00 1,0]5.1%1 228'65 1,060.31 18206 Clamor. Factor PaSs- KDU-IO-KDU 10- KOU10 168.69 16580 168.69 16397 168.89 ]]616 Cadre Distance Pass- NDU-iD -(DU 10 -KDU 10 325.00 166.07 32590 162.91 325.12 52578 Ellipse Sepaatipn Pass- 950.00 234.62 950.00 222.10 944.41 31.221 Clearence Factor Pass - KID 32-0)H-KTU 32-7H-K7U 32-7H KTU32-0]H-KTU 32-7H-KTU 32-)H 1,633,06 367.34 1,633.06 355.46 1,594.05 30.928 Centre Distance Pass- KTU32-WH-KID 32-)H-KTD 32-)H 11650.00 36).38 1,607.00 355.43 11810.96 30.752 Ellipse Separation Pass- KrU 43-06X-KTU e-EX - KrU 434% 2,1]590 402.82 2,175.00 386.46 2,10878 28952 Gleaance Factor Pess- KTU43-O6X-KTU 434%-KTU 435% 300.00 285.fi9 300.00 281.20 316.90 63.696 Carlin Distance Pass- KID 43-06X-KTU 43- 435% 475.00 286.66 47590 26009 491.82 43.544 Ellipse Separation 1,375.00 347.21 1,3)5.00 330.25 1,322.)) 20.479 Ckaance Factor Pa.- KTU 4346%-KTU 43-6XRD-KTU 434XRD UU43-06X-KTU 436XR0-K71.1 43-6XRD 300.00 285.69 300.00 281.20 316.90 63,698 Centre Distance Pass- KTU43-06X-KTU 43-6XRD-KTU 436XRD 475.00 286.68 475.00 280.09 491.82 43.544 Ellipse separation Pass - KTU43-06X-KTU 435XRD2-OU 43.6XRD2 1,375.00 347.21 1,37500 33025 1,322.)) 20479 Clearance Factor Pass - M43-06X-KTU 436XRD2-K 43-6XRD2 300.00 285.69 301).00 281.20 316.90 63.698 Centra DisMnce Pass - KTU 43-06X-KTU 43-6XRD2-KTU 434iXRD2 475.00 286.68 475.00 290.09 49482 4].544 Ellipse SeparationPass- 1,3]5.00 36].21 1,3)5.00 330.25 1,322.)) 204]9 Clearence Factor Pass- KU 11-0-KU 114-KU 11-0 KU 14-05-KU 14-05-KU 1445 1.411.83 55.90 1'411'93 3825 1,3fi2.B5 3.168 Charente Factor Pass- KU 14-1)5-KU 14-05-KU 14-05 301.24 118.39 301.24 114.05 301.6fi 2).2)3 Centre Distance Pass- KU14-5-KU24-05-KU-5 32590 118.41 32500 11398 325:28 26.700 Ellipse Sepaation Pass- KU24-5-KU 24-5-KU 24-5 1,175.00 159.98 1,175.00 150.70 1,197.35 17.245 Clearance Factor Pass- KU 24-5-KU 24-5-KU 245 18.00 200.19 18na 198.13 12.90 43.296 Centre Distance Pass- KU 24-5 - KU 245 KU 245 325.00 202-85 325.00 19740 317.62 43.839 Ellipse Separeion Pass- 1,500.00 30917 1,500.90 291.77 1,381.47 17.211 Clearence Fador Pass - 09 Mag 2019 - 18:25 Pa9e3p/6 COMPASS I HALLIBURTON an) and Surtsey Tool 1800 11530.00 KU 24-058 wp08 � Hileorls Alaska, LLC 2_MWDHFRI*MSeSag 5,962.00 10,384.59 KU 24-058 woos ? MWDaIFR1+M5+Sag Ellipse "mor terms are correlated across survey tool lie -on points. CalculeVA ellipaea in a-Psaceauffaxe moors. Kenai Gas Field Anticollision Report for Plan: KU 24-05B - KU 24 -OSB wp08 Distance Bebmen commas; the straight line distance beNrean wellbore corms. Clearance Factor= Distance BeMreen Profiles / (Dlstano Between Profiles - Ellipse Sepmaton). Closest Approach 3D Proximity Scan on Current SOrvey Data (Nlgbaltle Reference) All stator coordinates were calculated using the Minimum Curvature method. Reference Design: KGF 41-7 Pad - Plan: KU 24 -1158 -KU 24.05B -KU 2d45B wpYB Son Range: 0.00 to 10,384.59 -sn. Measured Depth. Sean Radius Is Unlimited. Clearance Factor cutoff Is Unlimited Max Ellipse Separation Is 1.000.00 usn San Name Measured Minimum Sal easmost Ellipse Consumer! Clearance Summary Based an Depth Well Name - Wellbore Name Design Distance pePiM1 Separation Depth Factor Minimum Separation WarningComparison (..ft) (..ft) (.aft) (-aft) usft KU 245 -KU 24-5RD-KU 2451,0 18.00 KU24-5-KU 24 -SRO -KU 24-5RD 200.19 18.00 198.13 27.90 97.298 Centre Distance Pass- 325.00 KU 245 -KU 24.5RD-KU 24-5RD 202.05 325.00 19JA4 332.fi2 43839 EII'se M Separation Pass- 150gW KU43bA-KU 43- 6A -KU 43-6A 30977 1,50000 291.]] 1,396AJ 17.211 Clearance Factor Pass - 10.00 KU 43EA-KU 43-6A- KU 237.20 18.00 23535 25.55 117.244 Centre Distance Pass- 7500 KU43-6A-KU 43bA-KU 436q 23].53 ]5.00 235.16 8 1.11 10.038 Ellipse Saoaralion Pass- 1.300.00 386.05 1,300.00 368.78 1.161.68 22.359 Clearance Factor Pass- KU 43 -7 -KU 43 -7 -KU 43-7 695.65 KU43-]-KU 43.7 -KU 0-7 43.66 695.65 34.13 718.42 4.581 Centre Davems Pass- 700.00 KU 43 -0 -KU 43 -7 -KU 43-7 43.69 70D.W 34.09 722.52 4.552 Ellipse Separation Pasa- 72500 44.98 72500 35.00 746.03 4.505 Clearance Factor Pa. - Sumeyfoolprogram From To surveylPlan an) and Surtsey Tool 1800 11530.00 KU 24-058 wp08 1,53000 6962.00 KU 24-058 wpO8 2_MWDHFRI*MSeSag 5,962.00 10,384.59 KU 24-058 woos ? MWDaIFR1+M5+Sag Ellipse "mor terms are correlated across survey tool lie -on points. CalculeVA ellipaea in a-Psaceauffaxe moors. Separation is the actual distance between ellipands. Distance Bebmen commas; the straight line distance beNrean wellbore corms. Clearance Factor= Distance BeMreen Profiles / (Dlstano Between Profiles - Ellipse Sepmaton). All stator coordinates were calculated using the Minimum Curvature method. 09 May, 2019 - 18:25 Page 4 care COMPASS MALLLIBURTON aP.m oaen.e Project: Kenai Gas R, - Site: KGF 41-7 Ped Well: Plan: KU 24-058 Wellbore: KU 24-058 Plan: KU 24-058 wp08 Ladder/ S.F. Plots V✓c'w (lea BCNrems: eYn® 1cquZn MEc c[9lrveiu Muw 41opJon leum: Atiia ®�aavaNee EC 1931 0.¢: M19IlSL]TPo:OOU] WWakJ'.ee `h ss,: °epN eo °i9°z°o r' ma .,Is .w93.m mi zone � I'U z.a'sei sL imi:us s°y 9e1M 14'a9aa KU Z4Ms vo091gx 2au591 3J ..,FI rllr leo: KUxwsa NM 192'1 rNAC[0\re"AN ALssh Lica Ul bb.lo L H' v4u1411,9u3 Gv1in UliYuh InnYNh oao ow 9 nsue.z$ 66°zr±s lKiN Isr lrasssxw GLOBAL FILTER APPLIED: All v Psft un fa 200r+ loomo00 of Merenu TVD 7VTes MD Sim I20.00 35.90 Im00 16 O Measured Depth 4.50 —T I I 3.00 Colliston Risk Procedures Req, I I I Collision Avoidance Req. L50 NOGo Zone -Stop Dulling NOERRORS I DD 0 600 1200 1800 2400 30pp 3600 4200 4800 5400 6000 6600 7200 7f )0 8400 9000 9600 10200 10800 11400 Pepzn I From: David Gorm To: Boyer David L (DOA) Cc: Davies Stephen F (DOA) Subject: RE: [EXTERNAL] KU 24-05B Date: Tuesday, May 14, 2019 8:40:17 AM Dave, The only significance of the "B" in the well name was to differentiate the well from the existing well KU 24-05. The team is trying maintain the naming convention based on the bottom location as it corresponds to the proposed well KU 24-05B. Unfortunately the offset well KU 24-05 not in the same quarter section had already been applied the name that would correspond to the currently proposed BHL. Let me know if you any more questions. Thanks, David Gorm K Drilling Engineer (,s q V'uSS KV 0-f —S h 0+ Hilcorp Alaska cJ Cell: 505-215-2819 P, P V 1' I From: Boyer, David L (DOA) [mailto:david.boye2@alaska.gov] Sent: Monday, May 13, 2019 4:59 PM To: David Gorm <dgorm@hilcorp.com> Cc: Davies, Stephen F (DOA) <steve.davies@alaska.gov> Subject: [EXTERNAL] KU 24-05B Hi David, I just began the geologic review for the KU 24-05B grassroots well. We wanted to check in to see if there is any significance to the "B" in the well name? As you know, the "B" suffix is also frequently used for the 2nd sidetrack from a mother wellbore. Thank you, Dave Boyer Senior Geologist AOGCC 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 maybe 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. Transform Points Source coordinate system K r I CafrP State Plane 1927 -Alaska Zone Datum: K(A;Z+--05B NAD 1927- North America Datum of 1927 (Meant Target coordinate system Albers Equal Area (-1K) Datum: NAD 1927 - North America Datum of 1927 (Mean) - - -------- — -_ -- ---- -- -- ----- -- i ype values - into— the spreand or copy and paste columns of data from a spreadsheet using the keyboard shortcuts Ctd+C to ropy and Ctd+V to paste. Then click on the appropriate arrow button to transform the points to the desired coordinate system. e Back finish Cancel Help TRANSMITTAL LETTER CHECKLIST WELL NAME: _ (A , a �t -- 0 5' B / PTD: -;L,�� — Q :7-g L, evelopment Service _ Exploratory _ Stratigraphic Test Non -Conventional FIELD: VCP Vt a t (j a N( 14 POOL: Ty e.9 hp /,.k- G0.S (00 L .ice 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. (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. (Comnanv Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC 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 through 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 V/ (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements 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 da s after com letion, sus ension or abandonment of this well. Revised 2/2015 Annular Preventer Diverter Tee, 21!/." x 2M w116" ANSI 150 16-%- 3M x 21-'/." 2M 16-3/V 3M Casing head Assy KU 24-05B Drilling Procedure Page 13 Revision 0 April 2019 N Hilcorp EZ T- 11.0 Drill 13-1/2" Hole Section KU 24-058 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" 16.0 S-135 CDS40 11.2 Hydraulics Summary: Page 14 Revision 0 April 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 0-1529 13-1/2" 550 1800 85 9.0 9.3 0.739 HWDP Page 14 Revision 0 April 2019 KO Drilling Procedure 1 rp Camp* 11.3 Primary bit will be the 13-1/2" Hughes Christensen Kymera Hybrid Bit KM633. Hughes Christensen PRODUCTDVERv1EW Kymera` m Hybrid Bits Best of Both Worlds Designeed to take adsatin ge of the best attributes of bot14 K,vmere combines roller mow and fixed cutter demeaHs, Ln lvow4 Ilirau.,aI Owrtd Relative to p(x' bits, Kytnera genal g lower nsrrall lontim and minim imd lonple Rnnuatims to improv$lm face control and reduce vibrations.. Lour edbmton The rmique design of Kymera bits provides an slable&iRing plmCamlthmmhigmcs vibration presem in mikrc •� PDC envuonments. Bcllir lenlf,we cnrilml Srglarior dir"joonal bit for molm"unary Applications with beter tool(axe control and steentiniry Iban a P Faster and More Dumblc When drilling mterbakkd and harder fmmm(ao, minthe to PDC bits. this unique design provides ince sed durability in transition zorles and smoother, faster drilling in hard rock. Bil Speci rimbu rs Numher ofalades, Cones 3.3 Pmnary Curter Sin 0.75 in (19-1 mm) Cutter Q"Wtity (Total. Facel (35,23) Cutting SWclure(Inrar. HmL Gauge)Dachl�Dachbv bide Number of Nozzles 6SP Fixed TFA 04in(0 sq.mm) Bearing i Seal Package Journal w law i S6 Single Energim MFS 'ago b.re Cianee i Makeup Le1W01 5.75 in ( IJ6.1 Moir + 17.24.5 in (4.IR mml Bit &cakcr P Connection 6•98 Rag Pin 712'I1,1SA, 171.40akn-0b1511 i. htakap 1 orqum55.4110m1 :1-4--1 Waa Hit Je 7. 45 npryIb 1579. S6 63.61Nm1 Apprax,ShipP®l W6ght3a6Ills (156.9 kg) Per. Pan Number SII"O ONnnling Reccmmwndations' IhJrmllie 11me rJ4 a5Dl35opvn 1A75U51UPIpl1i. Ro .1bm ease 1Fur RaWry anJ AIUAV .Applieaian5. Aon. Weiele tffi Hir 6a klbR6ln a kdaV) Page 15 Revision 0 April 2019 11.4 13-1/2" directional assy: KU 24-05B Drilling Procedure COMPONENTDATA Item .r ID Gauge Weight Top Bottom Length Cumulative Description 1 Tricone 6.750 3.438 13.500 173.30 P 6-518" REG 0.96 0.96 2 8" SpenyDrill Labe 415 - 8.000 5.000 121.08 B 6-518" REG B 6-518" REG 32.06 33.04 5.3 st Bim Sleeve Stabilizer 13.250 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 8.000 1.920 142.70 B 6-518" REG P 6-518" REG 4.55 46.59 5 8" EWR-P4 Collar 8.000 2000. 151.00 B 6-518" REG P 6-518" REG 12.19 58.78 6 8" HCIM Collar 8.000 1.920 1 1 149.90 B 6518' REGIP 6-5/8" REG 4.97 63.75 7 8" TM Collar 7.830 3250 151.20 B 6518" REG P 6-518" REG 9.07 72.82 8 8- Flex Collar 7.750 2.875 138.64 B 6-0" REG P 6518" REG 30.00 102.82 9 S' Flex Collar 7.500 2.875 128.44 B 6518" REG P 6518" REG 2922 13204 10 8" Bottle Neck XO 7.875 3.063 140.89 B 4-112" IF P 6518" REG 3.52 135.56 11 6 314' Flex Collar 6.813 2.875 102.10 B 4-112" IF P 4-12" IF 30.00 165.56 12 6,V4" Flex Collar 6.688 2.875 97.58 B 4-12" IF P 4-112" IF 30.38 195.94 13 4 12"IF x CDS-40 X- 6.150 2.687 81.91 B 4.5' CDS P 4112" If 2.51 798.45 Over Sub 14 2 Jnts�DP S-40 4.500 2.813 33.02 61.36 259.81 15 CDS-40 x 4 12"IF X- 6.200 2.687 83.56 B 4-112" IF P 4.5" CDS 2.50 262.31 Over Sub 40 16 6114" Jars 6250 2250 91.01 B 4-12" IF P 4-112" IF 31.79 294.10 17 4112' IF x CDS 40 X- 6.470 2.687 9272 B4.5"CDS P¢112"IF 2.65 296.75 Over Sub 40 18 15 Jnts 4.5" COS40 4.500 2.813 36.86 459.91 756.66 HWDP 756.66 Bit Number Nozzles :3xi6,ix14 Bit Size (in) : 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 No LWD tools will be run on the 13-1/2" hole section. 11.7 Begin drilling out from 16" conductor at reduced flow rates to avoid broaching the conductor. 11.8 Drill 13-1/2" hole section to 1529' MD / 1500' TVD. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. Page 16 Revision 0 April 2019 KU 24 -OSB Drilling Procedure • 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. • 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 1500'— 1700' MD. • Take MWD surveys every stand drilled (60' intervals). 11.9 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: MD I Mud Viscosity PV YP API FL LGS 15 - 20 ppb Weight 0.1 ppb (8.5 — 9.0 pH) BARAZAN D+ as needed BAROID 41 as required for 8.8 — 9.5 ppg 120'— 1,529' 8.8-9.5 250-85 40-20 55-25 1 <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 11.10 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16" conductor shoe. 11.11 TOH with the drilling assy, handle BHA as appropriate. Page 17 Revision 0 April 2019 H HilwEng 12.0 Run 10-3/4" Surface Casing 12.1 R/U and pull 15.375" wearbushing. KU 24-05B 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 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 Triangle Base 10-3/4" 22,630 ft -lbs Page 18 Revision 0 April 2019 KU 24-05B Procedure Drilling Procedure Hilcorp Energy Cmnpmy TXPCR? BTG a 1 rrzDln Outside Diamohv 10750,1- Min. Wag 07.5% cw0i::6w ID DAM N. kl*> pLms 4191 n. 7,mdsvf, 5 (') 6rad9 LDO RMLAR Typo 1 Wall Telckne+ss 0,100 W. EonMrclior. OD RLGULAR n L -.-r•; c. I:ri n'. Option 1940999 P IT,V COUP(m PIPE BODY Iln dwt Red Is'. 3ard Red Lr4d. LID Type 1' Dill API Standard WBi d'. em" 2n.1 S�b im 2nd sand:. Brown TSpe Lasing 3!d Rand'.. 3(d &I. td - 401- Banc PIPF 9OD"Y DATA GEOMETRY Na^.ilcbDD 10.750ih Vtminalwai;rA Na -rel ID 0.950 n. 'Blah 7bk4nem DD TiMranpr API 45.5lbs'll Drill 7.791 in 0.40e1n Plar, Eru"S!Vt 44201W PERFORMANCE ecdy Null 1610.101La IPlammyldd 5210rti BYYg amen Pi G:JUrr 2470 rd, CONNECTION DATA GEOMETRY Cana:licv OD 11.750 i'1- C"piN Lw yh 10.125 Y+ cw0i::6w ID DAM N. kl*> pLms 4191 n. 7,mdsvf, 5 Corecoo,0j cptax RMLAR PERFORMANCE n L -.-r•; c. I:ri n'. 1-1 1940999 P IT,V H sl Pn,e -e tbP" 5210.909 P9 Iln Oo, Opn ssen Effan--y 710 :. cattw: am SP0,41h 1040000.171:0 KIa.. Afow1 &. 4.0 34'i1N0 im Exle"i -rmwr Qro:rl 2470.M Pn MAKE-UP TORQUES Kinmu-! 29170 tabs il,"m.m 22070 d-L�e Ktamum 24199 M1bS OPERATION LIMB TORO/E3 IPe'aln0`a-3.; a7700t+bs r,Pk lue 4500-kn Page 19 Revision 0 April 2019 KU 24-05B 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) fl 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 April 2019 KU 24 -OSB Procedure Drilling Procedure Hilcorp Ene Company 13.0 Cement 10-3/4" Surface Casing 13.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. • How to handle curt 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: Calculation: Vol Vol (ft3) (BBLS) LEAD: 120' x .106 bpf = 12.8 71.6 16" Conductor x 10-3/4" casing annulus: LEAD: (1029' —120') x .065 bpf x 1.5 = 88.3 495.9 13-1/2" OH x 10-3/4" Casing annulus: Total LEAD: 101.1 567.5 1 3 4 Sr TAIL: (1529'-1029') x .065 bpf x 1.5 = 48.6 272.8 13-1/2" OH x 10-3/4" Casing annulus: TAIL: 90 x .096 bpf = 8.7 48.7 10-3/4" Shoe track: Total TAIL: 57.3 321.5 aS z? s c Page 21 Revision 0 April 2019 U Hilcrp Evcigy,,2,T Cement Slurry Design: KU 24-056 Drilling Procedure 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% KCUEZ 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: 1439' x .0962 bpf= 138 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 overdisplace by more than 'h 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 April 2019 Lead Slurry (1200' MD to surface) Tail Slurry (1700' to 1200' 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% KCUEZ 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: 1439' x .0962 bpf= 138 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 overdisplace by more than 'h 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 April 2019 H Hilcorp KU 24-05B 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 tanning 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 successor problems during the cement job Send final "As -Run " casing tally & casing and cement resort to dgorm@hilcorp com This will be included with the EOW documentation that goes to the AOGCC. Page 23 Revision 0 April 2019 H Hilcorp Enm Company 14.0 BOP N/U and Test 14.1 N/D the diverter. KU 24-05B 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 601 Ii 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 250/4000 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 9.5 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 April 2019 15.0 Drill 9-7/8" Hole Section KU 24-05B Drilling Procedure 15.1 Prior to P/U 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: COMPONENTDATA Item� .. ID Gauge Weight Top Bottom Length Cumulative -suiption Serial Number [i n) (in) (in) ObA Connectitin Connectim (ft) Length (ft) 1 9 7B' PDC 7.600 1 3.000 1 9.673 13051 P 6-518' REG 0.90 0.90 2 2'18 " 7'E.O 7-000 4.952 93.13 B 4-117 IF B 6518" REG 27.30 2820 std Btm Sleeve Stebier 9.625 3 6 314' DM Collar 6.740 3.125 103.40 B 4-117 IF P 4-117 IF 920 37.40 4 6 3W CHOR Collar 6760 1.920 97.80 B 4-112'IF P 4-12' IF 6.42 43.82 5 6 314' EWR-P4 Cnlar 6.730 2.000 104.30 B 4-1/2'IF P4 -MF IF 12.10 55.92 6 1 Inline Stabilizer (ILS) 6730 1.92(1 9.500 111-37 B 4-112' IF P 4-12' IF 1.95 57.87 7 6 314' PWD 1 6.730 1905 96.30 B 4-112^ IF P 4-12' IF 6A3 64.30 B 6 3r4' HCIM Cofer 6750 1.920 101.70 B 4-112' IF P4 -171F 6.59 70.89 9 6 314" ALO Collar 6750 1.920 8.062 104.30 B 4-117 IF P 4-112' IF 18.42 89.31 Stabliier B.062 10 6 314' CTN Ca0ar 6.720 1.905 10230 B 4-11,71F P 4-12' IF 11.84 101.15 11 6 3W TM Collar 6.850 3.250 99.70 B 4-117 IF P 4-12' IF 10.02 111.17 12 6 3W Flex Caller 6813 2.875 10210 B 4-112' IF P 4-12' IF 30.00 141.17 13 634' Flex Caller 6.688 2.875 97.58 B 4-117 IF P 4-12' IF 30.38 171.55 14 4 12' IF x CDS-40 X- 6-150 2.687 8191 B 4.5' CDS P 4-12' IF 2.51 174.06 Over Sub 40 15 2Jnts4.55' PDS -40 4-500 2.813 33.02 61.36 235.42 HWD16 6200 2.687 83.56 B4-117IF40 2.50 237.92 Over Sub 17 6 114' Jars 6250 2250 91.01 B 4-117 IF P 4-12' IF 31.79 269.71 18 4 1MF x CDS-40 X- 6.470 2.687 92.72 8 4-5' CDS P 412 IF 2.65 272.36 O� Sub 40 19 1 4.500 2.813 36.86 459-91 73227 HWDF Totes- ftic�i 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 April 2019 U Hilerp Energy C2, 15.6 Primary bit will be the Baker Hughes 9-7/8" Kymera. Hughes Christensen Kymera",' Hybrid Bits 9.N75 in. (250.8 mm) KMX524 Ll -,t of WNL W.0d+ Desig cd W take advantage of the been attributes of both. Kymea combines rW;cr oatc arid fined cutter eianent. Imps, d Direcai,nul Control R«rirx in POC bis, Ky. gerwtea lorw overall torque and mni nixed wrquc fluctuations to iramwilaiMl lacesmntrol and reduce nlra mass. ).o.er vilsal;on The tnique "gn of Kromer, him protides an stable drilling platf9nn that mlliltuaes wlnalion present in matte c PDC enviran.b. Ludt,, roolf.,vr ,4 Superior directional bit for inter or rotary applications wish beater fonlfnce v rmnA and than a P 6 Faster and Mare Durable Whcrl drilling iraerbedded and harder fomutirrn, rebtise m POC' Firs, Ibis unique desigal rarnhie. irwenscd durability in mans tion aelww and tnoodtr, faster drilling in lard rock. kit Spe:iricuior. Nunber ufOkrles-Cnnux 4.2 Primary Gear Sin 0.625 in (15.9 roro) comf Q Murk) lTaal. Face) M 221 Cutting Sauiurc if.. l Ieel. Gin.ge)CsrlioCcnivCarbide Nunba of NOT)ks Fixed TFA Rating f Seal Pwkage 4 CSP. 1A 03DI sy.in (193 c5 eq.tmn) 3mamnl w+Inset i $ogle Faa>gi)v 3dP$ KU 24-05B Drilling Procedure PRODUCT pbTF.RVIFW Gauge / Makeup 1-en61h 6 an I I 52 mro) 7 15.347 in (389.5 total kit Breaker F Connection 6418 Reg Pin )a_'tir Sub "1-4affitah 4y> 3. Makeup Torque s'4 bn1ea I l raid all n.^r.su Vsn.me3Lo. 5y aJ eWm1 Ar%.. Mirping Wcig1t216 lb. (911 kg) Ket: I" Nutnber %25211 Opc,lio, Roux.... laion,' Ila.lr WIL auc uo-9uo u,rNUIM)J.(n1a4:J)(l4.1.AAL,;..nGmi furtrM nod Ilravrt.ApplmWInnr.%I, We1Na[)n lilt 49 kaf 1211.. S N) Page 26 Revision 0 April 2019 H Hilcorp 15.7 9-7/8" hole section mud program summary: KU 24-05B 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 — 9.5 ppg 6% KCl/EZ MUD/BDF-976 fresh water based drilling fluid. Properties: 15.8 15.9 Product Mud Water Plastic KCI 22 ppb (29 K chlorides) Caustic MD Weight Viscosity Viscos1,529'- field Point pH HPHT DEXTRID LT 9.0-9.5 40-53 15-25 15-25 8.5-9.5 <11.0 5,962' 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 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 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. 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 ppg EMW. Page 27 Revision 0 April 2019 n Hilcorp Evngy Compmq KU 24-058 Drilling Procedure 15.13 Drill 9-7/8" hole section to 5,962' MD / 5,700' 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. 15.14 Casing point selection: TD the 9-7/8" hole section around 5,950' MD (5,700' TVD) in the middle of MB 5. 15.15 At TD; pump sweeps, CBU, and pull a wiper trip back to the 10-3/4" shoe. 15.16 TOH with the drilling assy, stand back BHA if possible. Page 28 Revision 0 April 2019 H Hilcorp E—VC-VZY KU 24-05B 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 250/4000 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 - 0 £• (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 4000' MD. • Install centralizers over couplings on every 4' joint above 4000' MD to 10-3/4" shoe at 1529' 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 April 2019 Drilling Procedure Procedure Hilcorp Eae� Compavy Wedge 5630 ....,.,.. 10118/2018 outaWO Dbmater 1.636 n. Min. Wall 87.5Y Thlckness (•I Gnlae L80 Goa r I Wall Thickness 0,3760i pnnestlpn OO REGULAR TyV6 Option CWPl1MG PIPE pODY Gratle L00 Typo 1GnRB.ay R"Isi Hann Rea AP161An0aR1 ISI B.M B. 2na S. 2,a Baro.. Brown TOPS Casing 3rd pa - 3rd Band' - nm B.M: - PIPE BODY DATA GEOMETRY PERFORMANCE ----� BaayY 1d5 en0m 683x1000lb. Intemel wia 6600011 SLAYS 600M pal Collapse 4700p0 CONNECTION DATA I GEOMETRY Cannxann OD 8.600 n CnuMng l.an0ib 936 Cnmarvn lD 6.BT6 h. LMMe Lon& e.6W n. Tntmle peen 3'19 COme.Ia OD Oplion REG"R PERFORMANCE --TInim..'n [a.ra.1. Mit G75 n. Nominal lD CPS.. Wal Thicklmea 0.376.x. Rain Ertl WaaM 00.06 Duo OOTGenlrce AN Da ExWnA Pressure Capality AT90.000 p9i Caiptn0 race LO 45500011s PERFORMANCE ----� BaayY 1d5 en0m 683x1000lb. Intemel wia 6600011 SLAYS 600M pal Collapse 4700p0 CONNECTION DATA I GEOMETRY Cannxann OD 8.600 n CnuMng l.an0ib 936 Cnmarvn lD 6.BT6 h. LMMe Lon& e.6W n. Tntmle peen 3'19 COme.Ia OD Oplion REG"R PERFORMANCE tendon EOclw 100.01'. Jmol YRtl WmgN 603.000x1000 Imernll R66sure Cepx01 6000.000 ps1 F.. Canrnnpon EFKknry 100.045 Compreasian Slecrt0lh 603,000x1000 Ltar Allmvatlnepntlitt5 As°11000 Da ExWnA Pressure Capality AT90.000 p9i Caiptn0 race LO 45500011s MAKE-UP TORQUES Mnimum 8600 MM Optimum 10300 0-0a Mind.. 16100 nJbs OPERATION LIMB TORQUES Opnr "Ty In Moll ftT Yield Tcnne 46p00plbs BUCK -ON 56nlmpm IM966aT 13arimum a/s66 ban 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 April 2019 H Hilcorp Eom� Company KU 24 -OSB 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 RAJ 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 31 Revision 0 April 2019 n HilmF.� �� j 17.0 Cement 7-5/8" Cement Procedure KU 24-05B 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 10.0 ppg spacer. Close low torque on plug dropping head, test surface cmt lines to 4000 psi. 17.4 Pump remaining 35 bbls 10.0 ppg spacer. l d "fes 17.5 Mix and pump slurry per below design: Section: Calculation: Vol (BBLS) Vol (ft3) LEAD: (5,400-1,529') x .038 bpf x 1.2 = 177.7 997.6 ft3 9-7/8" OH x 7-5/8" csg: Total Lead: 177.7 bbls 997.6 1t3 TAIL: (5,962' — 5,400') x .038 bpf x 1.2 = 25.8 144.8 ft3 9-7/8" OH x 7-5/8" csg: TAIL: 90' x .046 bpf = 4.1 23.2 ft3 7-5/8" Shoe Track: Total Tail: 29.9 bbls 168 0 Page 32 Revision 0 April 2019 yis �>< r35- 5--A H Hilcorp en� czjx KU 24-05B Drilling Procedure 17.7 After pumping cement, drop top plug and displace cement with mud. Use the cement unit to displace with as volumes can be tracked much more accurately. Displacement talcs: • 5,872' x .0459 bpf = 269 bbls. • Displace with 9.5 ppg 6% KCl/EZ MUD/BDF-976 drilling fluid out of mud pits. 17.8 Monitor returns closely while displacing cement. Adjust pump rate if necessary. 17.9 Do not overdisplace by more than % shoe track volume. Total volume in shoe track is 4.1 bbls. 17.10 There should be no curt returns to surface. TOC is planned to be at 1,000' 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 33 Revision 0 April 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 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 Type1 Cement 94 lb/sk Type1 Cement 94 lb/sk Additives WellLife 1094 Monofilament fiber 0.21% BWOC WellLife 1094 Monofilament fiber 0.20% BWOC 17.7 After pumping cement, drop top plug and displace cement with mud. Use the cement unit to displace with as volumes can be tracked much more accurately. Displacement talcs: • 5,872' x .0459 bpf = 269 bbls. • Displace with 9.5 ppg 6% KCl/EZ MUD/BDF-976 drilling fluid out of mud pits. 17.8 Monitor returns closely while displacing cement. Adjust pump rate if necessary. 17.9 Do not overdisplace by more than % shoe track volume. Total volume in shoe track is 4.1 bbls. 17.10 There should be no curt returns to surface. TOC is planned to be at 1,000' 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 33 Revision 0 April 2019 Drilling Procedure Procedure Hilcorp en� czT 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 dzormghilcorp com. This will be included with the EOW documentation that goes to the AOGCC. 17.1 R/D cement equipment. Flush out wellhead with FW. 17.2 Back out and L/D landing joint, flush out wellhead with FW. 17.3 M/LJ 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. 17.4 Lay down landing joint and pack -off running tool. Page 34 Revision 0 April 2019 n Hilcorp E=W Cmpv y 18.0 Drill 6-3/4" Hole Section KU 24-05B 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): Annular/VBR/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. 18.5 Ensure BHA Components have been inspected previously. Ensure to have enough 4-1/2" DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 18.6 Drift & caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 18.7 Ensure TF offset is measured accurately and entered correctly into the MWD software. 18.8 Confirm that the bit is dressed with a TFA of 0.46 sqin. Have DD run hydraulics models to ensure optimum TFA. We want to pump at 270 gpm. 18.9 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 35 Revision 0 April 2019 H Hi1CO2p Ev C %T 18.10 PfU below 6-3/4" directional drilling assy: KU 24-05B Drilling Procedure COMPONENTDATA Item.D 1 Description 6 314" PDC (in) 4.680 r Gauge (in) (in) 1.500 1 6.750 Weight (thpiri 1 52-60 Top Connection IP 3-112" REG Bottom Connection Length (it) 0.70 1 Cumulative Length (ft) 0.70 2 4 314" SperryDrill Lobe 516- 8.3 s1 4-750 2.794 44.57 B 3-112" IF B 3-112" REG 29.70 30.40 3 4 314' DM Collar 4710 2.610 4820 B 3-112" IF P 3-112" IF 921 39.61 4 4 314" EWR 1 DGR 4.740 1.250 4820 B 3-112" IF P 3-112" IF 24.40 64-01 5 4 314" ALD Collar 4.720 1250 5.625 45.50 B 3-112" IF P 3-112" IF 14.35 78.36 Stabilizer 5.625 6 4 314' CTN Collar 1 4.760 1250 50.50 B 3-112" IF I P 3-112" IF 11-14 89.50 7 4 314" PWD Collar 4-730 1250 47.90 B 3112" IF P 3-112" IF 923 98.73 a 4 314" TM Collar 4-680 2.812 46.10 B 3112" IF P 3112" IF 11.13 109.86 9 4 314' NM Flex Collar 4.625 2.313 42-94 B 3-112" IF P 3-112" IF 31.05 140.91 10 4 W4' NM Flex Collar 4-750 2.313 46.08 B 3112" IF P 3112" IF 31.05 171.96 11 X70 f3 112" IF P x 4 112" CDS 40 840 5210 2.750 52-41 B 4. " CDS P 3-112" IF 1.35 17331 12 4 jts x 4 112' HW DP 4.500 2-687 36.86 122.93 29624 13 4 112" Jar 4.625 2.500 40.53 B 4.5" CDS 40 P 4.5" CDS 40 31.71 327.95 14 1 7 jts x 4 UT HWDP 4.500 2.687 1 36.86 214.33 54228 Total_ _ s• Page 36 Revision 0 April 2019 U Hileorp Evc,gy Compavy KU 24-05B Drilling Procedure 18.11 Primary bit will 6-3/4" Baker Hughes Kymera KM323. Hughes Christensen KymeraTll" FSR Hybrid Bits Best of Both Worlds Designed to take advantage of the best attributes of both, Kyrnm combines rolls cone and fixed cutter elements. Better toolface control Superior directional bit for motor or rotary applications with better toolface control and steerability than a PI Improved torque control Kymem bits offer unrivaled torque in the toughest formations; even in transition zones torque is with amooth and fast drilling. Higher overall ROP Maintains PDC -equivalent ROP in soft fannatittim while increasing ROP in harder formations typically drilled by roller cone bits. High efficiency in Carbonates Improved cutting structure optimizes drilling in carbonates for high efficiency. Bit Srti ilicafiom Number of Blades, Cones 3,2 Primary Cutter Size 0.44 in (11.2 mm) PRODUCT OVERVIEW Gauge / Makeup Length 3.5 in (88.9 mm) / 9.801 in (2489 mm) Bit Breaker N CutlerQuantity (Toa, Face) (20.15) Connection Cutting Structure (Inner, Heel, Gauge)Conic1WedSciDX PDC Number ofNozzks Fixed TFA Bearing i Seal Package 2 SP, I PORT 0.11 sq.in (70.97 sq.mm) Journal w/Insert / Single Energizer MFS Makeup Torque 3-112 Reg Pin 41 ell" Bit Sub 5.2.5.7kft-Ib(7.0-7.7kNm) 4114"Bit Sub 6.3-6.9k8-Ib(8.6-9.4kNm) 4112"Bit Sub 7.6.8.4kft-16(103-11.4kNm) Approxi Shipping Nreight53 lbs (24 kg) Ref. Part Number X22715 Opemting Recommendations* Hydraulic Ilou rate: 250.550 Spot 4950-2100 turn). Rotation Saeed: For Rotary and Motor Applications Max. weight the Bic 33 kit, (I4 at or LAW) Page 37 Revision 0 April 2019 H Hilcorp KU 24-05B Drilling Procedure 18.12 TIH to TOC. Shallow test MWD on trip in. Note depth TOC tagged at on AM report. 18.13 Conduct casing test to 3500 psi / 30 min. S� " A4 I 18.14 Drill out shoe track and additional 20' new formation. CBU and prep for FIT. 1'f.0 18.15 Conduct FIT topg EMW. �� w FIT— -r P4TA 18.16 Drill 6-3/4" hole to 10,385' MD / 9,964' TVD using above motor assembly. -iza A 66 C c • 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. 18.17 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 38 Revision 0 April 2019 n Hilcorp mer car KU 24-05B Drilling Procedure System Type: 9.5 — 12.5 ppg 6% KCl/EZ MUD/BDF-976 fresh water based drilling fluid. Properties: ,r F.� o',L P MD E—I Viscosity Plastic Viscosi field Point pH HPHT 5,962'- + 7DEXTRIDLT 40-53 15-25 15-25 8.5-9.5 0.75 ppb 10,385' 1-2 ppb I ppb BARACARB 5125150 15 - 20 ppb (5 ppb of each) — 18.18 Hilcorp Geologists will follow LWD log closely to determine exact TD. 18.19 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8" shoe. 18.20 TOH with drilling assy, handle BHA as appropriate. 18.21 No open hole logs are planned for the production hole section. Page 39 Revision 0 April 2019 Concentration 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) + 7DEXTRIDLT 1.25 ppb (as required 18 YP]rate) 2 - 4 ppb 0.75 ppb 1-2 ppb I ppb BARACARB 5125150 15 - 20 ppb (5 ppb of each) BAROID 41 as required for a 9.5 —12.2 p ALDACIDE G 0.1 ppb BARACOR 700 1 ppb BARASCAV D 0.5 b (maintain per dilutio 18.18 Hilcorp Geologists will follow LWD log closely to determine exact TD. 18.19 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8" shoe. 18.20 TOH with drilling assy, handle BHA as appropriate. 18.21 No open hole logs are planned for the production hole section. Page 39 Revision 0 April 2019 H Hilcorp KU 24-05B Drilling Procedure 19.0 Run 4-1/2" Production Long String 19.1 Install and test 4-1/2" casing ram in top ram cavity. Test to 250/4000 psi. 19.2 Dummy run casing hanger and mark landing joint. 19.3 R/U Weatherford 4-1/2" casing running equipment. • Ensure 4-1/2" 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. 19.4 PIU shoe joint, visually verify no debris inside joint. 19.5 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. 19.6 Continue running 4-1/2" prod casing. • 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 5,900' MD. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 4-1/2" TXP BTC torques Casing OD Minimum Maximum Yield Torque 4-1/2 5,550 ft -lbs 6,170 ft -lbs 8,800 ft -lbs Page 40 Revision 0 April 2019 KU 24-05B Procedure Drilling Procedure Hilcorp r>naW TXM BTC 0510312017 D.tsede D,.mr 1500 In. 6b1. Wall 37.5. CO,MOW DJD option REGYLAR PERFORMANCE Thit,IrI nGrade L30 low iensm Etrcmng CGmprpill,n EmnOrrcy Enamal il'aaarp CaPicnl 1M % 108!: 7590.000 pu bM yie. S:mn"'. CumPmaswn siJc qln 3MD00 xl OfR le. 266.000x10W le: Type d M30.000 PL sl vt0ort Wall ThieAnese 0.271 n. Cpnneeop W REGULAR R4nlmum 55506.1tc Option 6178 It Ix CDDPMHG qPE 30DY Grade L3DType1' Drift API Standard 9id1 Red 1stWr.d. Red 6790 n![c Y"wtl rccpua e508 It 1s1 Gand: rl. 2rd Mnd. ?nd Dad Sreen Type Casing 3ad Q.w 3rd EUnd. Slh SaM: PIPE BODY DATA GEOMETRY Npmna. DD 4"0n 11[rnrval •/lctlnl 126 QI IXdl 3A331n. N.. ID 3.956 vi Wall Tnlcircu 0211 m Plam End W,Ignt 1225.".. Do T.W. AN PERFORMANCE 3W1 MIaN Se ,iI 2661IM0 las iwxnal Y.4 640 P. SRNs 66000 camps, 7900 pa. CONNECTION DATA GEOMETRY C.L, nn DD 5.000 m Cwy1n6 iengN 9.0]51rt C[menbn ID }9661n. Mina-ua Les. 1A161n TNaad: Ryrin 5 CO,MOW DJD option REGYLAR PERFORMANCE iensm Etrcmng CGmprpill,n EmnOrrcy Enamal il'aaarp CaPicnl 1M % 108!: 7590.000 pu bM yie. S:mn"'. CumPmaswn siJc qln 3MD00 xl OfR le. 266.000x10W le: IntaIDal PNdsma Capauty 1'I M. aw.aMcesManp M30.000 PL sl vt0ort MAKE-UP TOROMS R4nlmum 55506.1tc D'ulimum 6178 It Ix Manimem 671H,16M OPERATK)N LIMB TORgUES DpcaaLoa TVQoc 6790 n![c Y"wtl rccpua e508 It Page 41 Revision 0 April 2019 H Hilcorp KU 24-05B Drilling Procedure 19.7 M/U casing hanger joint 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. 19.8 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 19.9 R/IJ 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. 19.10 After circulating, lower string and land hanger in wellhead again. Page 42 Revision 0 April 2019 U Ililcorp env C—Prq 20.0 Cement 4-1/2" Production Long String KU 24-05B Drilling Procedure 20.1 Hold a pre job safety meeting over the upcoming cmt operations. Ensure the below is covered during the meeting: • How to handle curt 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 long string during cmt operations. 20.3 Pump 5 bbls 12.5 ppg MUDPUSH II spacer. 20.4 Test surface cmt lines to 4500 psi. `%�� LOD, s 20.5 Pump remaining 20 bbls 12.5 ppg MUDPUSH II spacer. 20.6 Mix and pump slurries per below recipe. Ensure cmt is pumped at designed weight. Job is designed to pump 30% OH excess.r �� c' r r 1. Section: Calculation: W5`" Vol BLS Vol (ft3) 7-5/8" x 4-1/2" Overlap (Tail): (5,962') 0.0262 = 3$ 51,0'I" 6-3/4" OH x 4-1/2" Casing (Tail): (10,385 — 5,9 .0246 x1.3 = 142- 799 Shoe Track (Tail): 90'x 0.015 = 1.4 7.9 Total Volume (Tail): Typel 234.3 1317 Slurry Information: M Page 43 Revision 0 April 2019 %Fe 3 Tail Slurry (10,385'to 2,500' MD) System EXPANDACEM (TM) SYSTEM Density 15.3 Ib/gal Yield 1.241 ft3/sk Mixed Water 5.55 gal/sk Additives Code Description Concentration Typel Cement 94 lb/sk WellLife 1094 Monofilament fiber 0 .20% BWOC Page 43 Revision 0 April 2019 %Fe 3 H �IICcOIP 20.7 Drop top plug and displace with 3% KCl. 10,285 ft x .01522 = 157 bbls. KU 24-05B Drilling Procedure 20.8 Do not overdisplace by more than %2 shoe track. Shoe track volume is 1.4 bbls. 20.9 Bleed pressure to zero to check float equipment. 20.10 Pressure up again to 3500 psi and hold for 30 min to test production bore. 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 successor problems during the cement job Send final "As -Run " casing tally & casing and cement report to dorm hilcoT com This will be included with the EOW documentation that goes to the AOGCC 21.0 Completions 23.1 A separate Sundry will be submitted to the AOGCC that will cover the completion operations for KU 24-05B `i' x 7 Page 44 Revision 0 April 2019 U Hilco E ycomT 22.0 BOP Schematic KU 24-05B Drilling Procedure Page 45 Revision 0 April 2019 H HilCO2�7 m Eap Company 23.0 Wellhead Schematic Kenal Gas Field 16 X 10 X X 75/8 X 41/2 111 aA, Obs, 41/165M FEX 6.5- Otis OW ck Unlon Valve, Swab, CIW-FLS, 41/16 5M FE, "WO, EE trim Valve, Upper Master CIW-FLS, 41/16 5M FF, MWO, EE trim Valve, Master, CIW-FLS, 41/16 SM FE, MWO, EE VIrn Mulbbowl Wellhead, WM 22, 11 5M X 16 X 3M, W/ 4- 2 1/16 SM SSO Starting head. 5 -22 -ET 16 X 3M X 16` SOW, w/ 2- 2 1/16 SM EM K'2 4 - '5B 24-O5B Drilling Procedure 6ena1 Gas Field VG 0. 0�o FF- � ce�ot oQe Page 46 Revision 0 April 2019 Drilling Procedure Procedure HilwEvmgy Company 24.0 Days Vs Depth G 2000 4000 5r L d N v 6000 J N � K- 8000 8000 10000 12000 0 Days Vs Depth 5 10 15 20 25 30 Days Page 47 Revision 0 April 2019 35 H Hilmai E.c Company 25.0 Formation Tops KU 24-05B Drilling Procedure Page 48 Revision 0 April 2019 TOP MIME t1THOLOGY __- P3 Al Sands J Coals Gawwater 3,459 3,3270 123 275994 1459.3510.45 MAS Sands / Coals Gas/Water 3,507 3,373.0 129 276008 148D.05 P3 .A6 Sands l Coals GasMlater 3,603 3464.0 742 278036 1521.00 P3 A7 Sandal Coals GasNVeter 3,745 3,599.0 767 W2362173 278078 1581.75 P3 As Sands ICoals Gar.Water 3,775 3,827.0 184 276086 1594.35 P3 A9 SandslCoals GasWater 3,821 3,871.0 170 278100 1814.15 PJ Ail Sands l Coals Gawwater 3,841 6w690.0 173 278106 162270 PJ A11 Sands I Coals GasfWater 3,905 3.750.0 -3866 2382181 276124 1649.70 0.45 P9 91 Sands l Coals GawWater 3,978 3,819.0 .1735 2362191 278146 1580.75 0.45 P4 62 Sands l Coals Gawwater 4,059 3,896.0 3812 23lMD1 278169 1715.40 0.45 Pc 93 Sands l Coals Gas/Water 4,113W2362396 0 3864 2382209 276185 1738.80 0.45 P5 93a Sands/Gaels Gas 4,1870 3933 2362218 276207 1769.85 0.45 Ps B4 Sands l Coals Gas 4,2090 -3954 2362221 276213 1779.30 0.45 PS BS P6 Cl STORAGE Sands l Coals Gas 4,3830 -4120 2362244 276264 1854.00 0.45 Sands Gas 4,686 -4407 2362283 276352 1983.13 0.45 P6 C2 STORAGE Sands Gas 4,863 4574 2362306 276404 2058.30 8.43 L_IiFLCt.1.4 ilts I Sands I Coal Gas 4,9310 4838 2352315 276424 2087.10 0.45uIiets / Sands I Coal Gas 4,91170 -0891 2382323 276440 2110.95 0.45 un 2 ills I Sands 1 Ca Gas 5,0430 -4745 2362330 276457 2135.25 0.45 UB 3 Sts 1 Sends 1 Coal Gas 5,091 4.874.0 4790 2362336 1 276471 1 2155.50 0.45 UB 3A (Sends/Coal Gas 5,135 4,9180 41132 2382342 276484 2174.40 0.45 U94 1Sands l Coal Gas 5,171 4.950.0 4868Up 2382347 278494 2189.70 0.45 4A I Sands I Co Gas 5,197 4.974.0 4890 2382350 278501 2200.50 0.45 u9 4B 1 Sands / Co Gas 5,222 4,898.0 4914 2382353 276509 2217.30 0.45 112 5 its Is /cc Gas 5,248 5,023.0 4939 2382357 278516 222255 0.45. Up SA !Sends! Co Gas 5.277 5,050.0 4968 2382367 278525 2234.70 0.45 u9 58 / Sands i CID21Gas 5,312 5,0830 4999 2382366 278535 2249.55 0.45 Up 6 / Sends i Ca Gas 5,354 1230 5039 2382377 278547 2287.55 0.45 UB 7 !Sends / Co Gas 5,387 5.154.0 -5070 2302375 276557 2281.50 0.45 UB 7A its l Sem l Co Gas 5,409 5,178.0 5092 2382378 276564 2291.40 0.45. UB a ISands /Co Gas 5,487 5,230.D 5148 1 2382385 276580 2315.70 0. UB 9 / Sandal Ca GasMlater 5,522 5,28a0 5199 2382393 276597 2339.55 0. M BELt1GA /Sends!Co GasNVeterT 51594 5,351.0 -5267 1 2362402 278618 2370.15 0.45 1,12 t Dts l Sends 1 Co GasJwater 5,845 5.399.0 5315 2362409 276632 2391.75 0.45 1,18 2 its / Sanda l Cod Gas/Water 5,680 54320 -5348 2382413 278642 2405.60 0.45 h123 1Sands I Co Gasrwater 5,741 5,490.0 5408 2382427 278660 243270 0.45 M9,4 !Sands 1 Co Gas1water 5,813 5,558.0 5474 2352431 276682 2463.30 0.45 1,12 5 /Sands I Co Gasnater 5,918 51658.0 5574 2382444 278772 2508.30 0.4 1,12 6 / Sends! Co Gas 6,009 5.744.0 5860 2362456 276739 2547.00 0.45 1,12 7 / Sends l Co Gas 6,148 5.676.0 -5792 2382474 276779 2608.40 0.45 h12 x !Sends / Coal Gas 6,215 939.0 -5855 2382483 276799 1 2634.75 0.45 M99 its/Sands l Coal Gas 6,268 5,989.0 590.5 2382490 278814 286725 0.45 L BELLY -i.9 15andsi Co Wet 6,373 8.489.0 -6005 2382504 278845 2702.25 0.45 La I /Sandal Coal Wet 6,400 0,115.0 -8037 2382507 276853 2713.85 0.45 1.9 IA its / Sends I CosW Wet 60432 6,145.0 -6061LB- 2382511 278862 2727.05 0.45 1C ISand&I Gas 6,472 6-1820 -8098 2382517 278874 2744.10 0.45 La La I ills!Sands /Co at 6,504 8,213.0 -6129 2362521 276883 2758.05 0.45 1811 D s1Sends/Co Gas 6,559 13,265.05787 2362528 278899 2781.45 0.45 LB IE its!Sands ! Wet 6.618 8,320.0 -6236 2362536 276916 2805.20 0.45 LB IF I Sands 1 Co Wet 8,854 1 6.355.0 {8171 2382540 276927 2821.95 0.45 18 2 ! Sands / Co Wet 1 6,702 8,400.0 -6316 2362547 276941 2842.20 0.45 Page 48 Revision 0 April 2019 KU 24-058 Drilling Procedure LS 2A / Sands / Coal Wet 6.7598.484.0 -6370 2362354 276938 2886.50 0.45 LB 28 itts / Sands / Coal Wet 6,794 6,4680 -6404 2362359 270568 2881.80 0.43 LB 2C INS / Santls I Coal Wet 6,823 6,515.0 -6431 2382363 276977 2693.93 0.45 L8 2D Itts / Saws / Coal Gas 6 888 6.576.0 -6492 23625]1 276993 2921.40 0.45 LB 2E ills / Sands I Coal Wet 6.927 6,614.0 -6530 2362576 277007 2938.30 045 LB 3 ]iRs pts / Sands I Coal Wet 61989 6.6720 -6588 2362384 277023 4 0 296 6 045 LB 3.4 las / Sande I Coal Wet 7,025 8,707.0 -6623 2362389 2]7036 2980.35 0.45 LB 3B las / Sands / Coal Wet 7,058 6,737.0 -6653 2362593 2]]045 2993.83 0,45 LB 3C Itts / Sands / Coal Wet 7,102 6.179.0 -6693 2362599 277058 3012.73 0.45 LB 4 in / Sands / Coal Wet 7,136 6,830.0 -6746 2362606 2]]074 3035.70 0.45 LB 4.4 Itts / Sands / Coal Wel 7.192 6.865.0 -6781 2382611 277084 3051.45 0.45 LB 413 Itts / Sands / Coal Wel 7227 6.690-0 -8814 2362615 277094 3066.30 0.43 1.6 4C In / Sands / Coal Gas 7,264 6,933.0 -6849 2362620 277105 3082.05 0.43 LB 4D Itts / Sands / Coal Wet 7,334 6,999.0 -6913 2362629 277126 3111.75 045 LB 5 Itts / Santls / Coal Wet 7,356 7,022.0 -6938 2362632 277133 3122.10 OAS LS SA Itts I Sands / Coal Wel 7,368 7.032.0 -6948 2362634 277136 3126.60 0.43 LB 5B Itts / Sands I Coal Wet 7,439 7.098.0 -7014 2362643 277136 3156.30 0.43 L8 5C Itts I Sawa / Coal Wet 7,489 7.146.0 -7062 2362649 277171 31]].90 0.45 LB Itts l Santls/Coal Wel 7,521 7,176.0 -7092 2362634 277180 3191.40 045 LB 6A Itts / Sands / Coal Wel 7,532 7,186.0 -7102 2362655 277183 3195.90 OAS LB 68 In I Sands I Coal Wet 7.575 7227.0 -7143 2362661 2771% 321435 0.43 TYONEK Silts / Sands / COME Wet 7,591 7,242.0 -7158 2362663 277201 3221.10 0.45 TY 72 6 Santls/Coals Gas 7,635 7.2114.0 -7200 2362669 277214 3240.00 0.45 TY 73 1 Saws Coals Gas 7,665 7,312.0 -7228 2362672 277222 3252.60 0.43 TY 73 2 Sands / Coals Wel 7.703 7 349.0 -7265 2362677 2]]233 3269.25 OAS LR IA Sands Coals Wet 7,726 7,371.0 -7287 2362681 277240 3279.15 0.45 OE IB Sands Coals Wet 7.766 7.427.0 -7343 2362688 277238 3304.35 0.45 tlT IC Sands Coals Wel 7.871 7.508.0 -7424 2362899 277283 3340.80 0.43 UE ID Sands /Coals Gas 7,888 7,524.0 -7440 2SS 702 277267 3348.00 0.45 TV 758 Sands/Coals Gas 7941 7574.0 -7490 2362709 2]]303 3370.50 0.45 UT 2A Santls / Coals Wet 7,995 7,625.0 -7341 2362716 277319 339345 0.93 L'T 2B Sands / Coals I Wet 8,023 7,652.0 -7368 2362719 277327 3403.60 OAS TY 76 7 Sands/Coals Wet 8037 1 7,665.0 -7581 2362721 277331 3411.43 0.45 In 3A Sands / Coals Wet 8,105 7.730.0 -7616 2362730 277351 3440.70 0.45 OF 3B Sands/Coals Wet 8.138 7,761.0 -7677 2362734 277360 3434.63 045 TY 79 2 Sands l Coals Wel 8227 7.845.0 -7761 2362746 277386 3492.43 0.45 DF 4A Santls/Coals Wel 8,263 2679.0 -7793 2362751 277397 3307.73 OAS UT 4B Sands/Coals Gas 8,307 7.921.0 -7837 2382756 277410 3526.65 0.45 IA 4C Sands /Coals Wet 6.338 2950.0 -7866 2362760 2]]419 3339.70 043 M 4 Sands/Coals Wet 8,476 8,081.0 -7997 2362778 277459 3398.83 0.43 OF 4E Sands/Coals Wet 8,602 8,200.0 -8116 2362795 277496 3632.20 OAS OF 4F Sands /Coals Wet 8.699 8.293.0 -8209 2362808 277524 3694.03 0.43 T'"6A Sands/Coals I Wet 8,722 8314.0 -8230 2362811 277531 3703.30 0.45 TY 84 6B Sands /Coals Wel 8.804 f 8.392.0 -8308 2362821 277533 3738.80 045 TY " tiC Sands / Coals Gas 8,868 6,432.0 -6368 2362830 277374 3765.60 OAS TY B6 2 Santls / Coals Wet 5.911 8.493.0 -6409 2362835 277586 3784.05 0.45 T' 36 2.A Sands / Coals Wel 8.938 8,519.0 -8435 2362639 277394 379575 0.45 TY 86 2B Sands/Coals Gas 9,027 8.603.0 -8519 2362850 271r820 3833.55 OAS TY DI Santls Gas 9,154 8,723.0 -8639 2382867 277637 3ali 0.45 TY D2 Sands Gas 9,331 8,891.0 -8807 2362889 277707 3963.13 0.45 T' D3 A Sands Wet 9,440 8,998.0 -8914 2362900 277731 4011.90 043 TY D'- B Sands Wet 9,522 9,078.0 -8994 2362907 277/46 4047.30 0.45 TY DS Shale We hl 9,594 9,149.0 -9065 2362911 277736 4079.25 OAS TY D3 A Santls Gas 9,637 8,191.0 -9107 2382914 277/61 4011 18 0.45 T' D3 B Saws Gas 9,863 1 9.2120 -9133 2362915 277764 4109.85 0.43 TY D3 C Santls Wet 9.726 9,280.0 -9196 2362917 277769 4138.20 0.43 TY D3 D Sands Wel 9,757 9.311.0 -9227 2362918 277771 4152.15 0.45 TY D4 A Saws Gas 9.815 9.369.0 -9265 2362919 277 3 4178.25 0.45 TY Dt 8 Saws Gas 9.840 9.394.0 -9310 2362919 277773 4189.50 0.45 TY D4 C Sands Wet 9.872 9426.0 -9342 2362919 27]7]3 4203,90 0.45 TY D4 D Saws Gas 9,913 9,4670 -9353 2362919 277713 4222.35 0.43 TY D5 Santls Wet 9,952 9,506.0 -9422 2362919 277773 4239.90 043 TY D6 saws Gas 9,998 91552.0 -wee 2362919 2]7]73 4260.60 0.43 TY D6A Sands Wet 10.049 9.603.0 -9519 2362919 271773 4283.55 0.45 TY D68 Santls Wet 10.091 9,645.0 -9561 2362919 2]]7/3 430245 0.45 TY D7 Santls Wet 10.266 9.823.0 1 -9739 2362919 27=3 4382.55 OAS TY DB Saws Wet 10,366 9,920.0 1 -9836 2362919 1 2]]773 4426.20 0.43 Page 49 Revision 0 April 2019 5� N H�ilc 26.0 Anticipated Drilling Hazards 13-1/2" Hole Section: KU 24-05B 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 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: 1-12S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. Page 50 Revision 0 April 2019 n Hilcorp W-11 9-7/8" Hole Section: Lost Circulation: KU 24-05B 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. yNo abnormal pressures or temperatures are present in this hole section. Page 51 Revision 0 April 2019 U Hilcorp E -W ,:.., 6-3/4" Hole Section: KU 24-05B Drilling Procedure Lost Circulation: 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 1 — 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: H2S is not present in this hole section. No abnormal temperatures are present in this hole section. Abnormal pressure: • All formations above 8,500' TVD are at original pressure. Formations below this depth are over- pressured to 11.5 — 11.8 ppg EMW. This pressure regime exists from 8500' to TD of the well. Maintain MW at a minimum of 11.8 ppg with additions of barite from 8000' to section TD. The transition to • abnormal pressure occurs from 8500' to 10,000' TVD. Pore pressure increases from normal (8.5 — 9 ppg) to 11.5 — 11.7 ppg through this area. It is imperative that the MW be kept above 11.8 ppg to avoid influx into the wellbore. Page 52 Revision 0 April 2019 H Hilcorp E.ew C.WY 27.0 Rig Layout KU 24-05B Drilling Procedure Page 53 Revision 0 April 2019 KU 24-05B Procedure Drilling Procedure Hilcorp Enc ,2,T 28.0 FIT Procedure Formation InteErity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1 -minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre -determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre -determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 54 Revision 0 April 2019 Drilling Procedure Procedure Hileorp � czjx 29.0 Choke Manifold Schematic �. umrc rm a crv.Ea Page 55 Revision 0 April 2019 H Hilcorp E.m compmy KU 24-05B Drilling Procedure 30.0 Casing Design Information Calculation & Casing Design Factors Kenai Gas Unit DATE: 5-2-2019 WELL: KU 24-05B FIELD: Kenai Gas Unit DESIGN BY: David W Gorm in Criteria: Hole Size 9-7/8" Mud Density: 9.5 ppg Hole Size 6-3/4" Mud Density: 12.2 ppg Drilling Mode MASP (sec 1): 1948 psi (See attached MASP determination & calculation) MASP (sec 2): 3563 psi (See attached MASP determination & calculation) Production Mode MASP: 4400 psi (See attached MASP determination & calculation) Collapse Calculation: Section Calculation 1, 2 Normal gradient external stress (0.44 psi/ft) and the casing evacuated for the internal stress 3 Oserpressured external stress (0.63 psi/ft) and the casing evacuated Casinq Section Calculation/Specification 1 2 3 Casing OD 10-3/4" 7-5/8" 4-1/2" Top (MD) 0 0 0 Top (TVD) 0 j 0 0 Bottom (MD) 1,529 i 5,962 10,385 Bottom (ND) _ 1,500 1 5,730 10,084 Length 1,529 5,962 10,385 Weight (ppf) 45.5 29.7 12.6 Grade L-80 L-80 L-80 Connection TV BTC HYD563 TV BTC Weight w/o Bouyancy Factor (lbs) 69,570 177,071 130,851 Tension at Top of Section (lbs) 69,570 177,071 130,851 Min strength Tension (1000 Ids) 1040 683 288 Worst Case Safety Factor (Tension) 14.95 3.86 2.20 Collapse Pressure at bottom (Psi) 650 2,964 6,217 Collapse Resistance w/o tension (Psi) 2,470 4,790 7,500 Worst Case Safety Factor (Collapse) 3.80 1.62 1.21 MASP (psi) 650 1,948 3,563 Minimum Yield (psi)5,210 6,890 8,430 I Worst case safety factor (Burst) 8.02 •. 3.54 2.37 j Page 56 Revision 0 April 2019 n Hilcorp Energy Company KU 24-05B Drilling Procedure 31.0 9-7/8" Hole Section MASP Maximum Anticipated Surface Pressure Calculation xi9-7/8' Hole Section `_ KU 24,058 Kenai, Alaska MD TVD Planned Top: 1529 1500 Planned TD: 5962 5730 AntidoeMd Formations and Pressures: Fonnation TVD Est Pressure Oil/Gas/Wet PPG Grad P3 A4 3327 1459 Gas/Water &4 0.44 P3 AS 3373 148D Gas/Water 84 0.44 P3 A6 3,464 1521 Gas/Water &4 0.44 P3 A7 3599 1582 Gas/Water 815 0.44 P3 AS 3827 1594 Gas/Water 8.5 0.44 P3 A9 3,671 1614 Gas/Water &5 0.44 P3 AIO 3690 1623 Gas/water 18.5 0.44 P3 -AU 3750 1650 Gas/Water &5 0.44 P4 Bi 3819 1681 Gas/Water 8.5 0.44 P4 B2 3896 1715 Gas/Water &5 0.44 PS B3 3,948 1739 Gas/Water &5 0.44 PS B4X 4017 1770 Gas 11.5 0.44 PS B4 4,038 1779 Gas &5 Q44 PS BS 8704 1&54 Gas &5 0.41 P6 CISTORAGE 4491 1983 Gat &S 0.44 P6 C2STORAGE 4658 7058 Gas &S 0.44 U BELUGA 1 4,722 2067 Gas &5 0.44 UB_1 4775 2111 Gas &S 0.44 UB -2 4,829 2t35 Gas 11.5 0.44 LIB -3 4874 21% Gas &5 0.44 UB 304, 4916 2174 Gas &5 0.44 UB 4 4950 2190 Gas &S 0.44 US 4A 4974 2201 Gas &5 0.44 UB 4B 4998 2211 Gas &5 0.44 UB_5 5,023 2223 Gas &5 0.44 UB_5A 5050 2235 Gas &5 0.44 UB_SB 5,083 2250 Gas &5 0.44 UBL-6 5123 2268 Gas &5 0.44 1.18_7 5154 2282 Gas &5 0.44 UB 7A 4176 2291 Gas &5 0.44 UB_8 5730 2316 Gas &5 0.44 UB_9 5,283 2340 Gas/Water &5 0.44 M_BELUGA 5,351 2370 Gas/Water &5 OA4 MB_3 5,399 2392 Gas/Water &5 0.44 MB 2 5432 2407 Gas/water &5 0.44 MOL3 5,490 2433 Gas/Water 131.5 0.44 MB 4 5558 2463 Gas/Water &5 0.41 MB 5 5658 2508 Gas/Water &5 0.44 TD 5,730 2533 Gas/Water &5 0.44 Page 57 Revision 0 April 2019 H Hilcorp Enngy C.,Z, KU 24-05B Drilling Procedure Offset Well Mud Densities Well MW range Top (TVD) Bottom (TVD) Date KBU 42-06Y 9.0-9.7ppg 1,575 5,821 2014 KBU 23-05 9.0- 9.4 ppg 1,410 5,688 2014 KBU 11-08Z 9.0-9.4ppg 1,603 5,581 2014 Assumptions: 1. Maximum planned mud density forthe 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 1500'1VD=14.4 ppg EMW Fracture Pressure at 10-3/4" shoe considering a full column of gas from shoe to surface: 1500(ft)x0.75(psi/ft)= 1125 psi 1125(psi)-[0.1(psi/ft)*1500(ft)]= 975 psi MASP from pore pressure; entire wellbore evacuated to gas from TD 5730 (ft) x 0.44(psi/ft)= 2521 si 2521(psi)-[0.1(psi/ft)*5730(ft)]= 1948 psi 1938(psi)-[(2/3)*0.1(psi/ft)*5700(ft)]+[(1/3)*0.44(psi/ft)*5700(ft)]= 722 psi Alternate Drilling MASP Summary: 1. MASP while drilling 9-7/8" production hole is governed by SIBHP minus 2/3wellbore evacuated to gas from TD. Page 58 Revision 0 April 2019 U Hilcorp Enn Came y KU 24-05B Drilling Procedure 32.0 6-3/4" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 11 6-3/4" Hole Section H� 202 KU 24058 Kenai, Alaska MD TVD Planned Top: 5962 5730 Planned TD: 10385 10084 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad MB_7 5,876 2606 Gas &5 0.44 MB -8 5,939 2635 Gas &5 0.44 MB -9 5,989 2657 Gas &5 0.44 L_BELUGA 6,089 2702 Wet 8.5 0.44 LB 1B 6,182 2744 Gas 8.5 0.44 LB ID 6,265 2781 Gas &5 0.44 LB 4C 6,933 3082 Gas 8.5 0.44 TY_72_8 7,284 3240 Gas 8.6 0.44 TY_73_1 7,312 3253 Gas 8.6 0.44 UT -1D 7,524 3348 Gas &6 0.44 TY -75-8 7,574 3371 Gas &6 0.45 UT 4B 7,921 3527 Gas &6 0.45 TY -84 -GC 8,452 3766 Gas 8.6 1 0.45 TY_86_28 8,603 3834 Gas &6 0.45 TY Dl 8,723 3888 Gas 8.6 0.45 TY D2 8,891 3963 Gas 8.6 0.45 TY D3 A 9,191 4098 Gas &6 0.45 TY_D313 9,217 4110 Gas 116 0.45 T(_D3_C 9,280 4138 Wet 8.6 0.45 TY_D3_D 9,311 4152 Wet &6 0.45 TY D4 A 9,369 4178 Gas &6 0.45 TY D4 B 9,394 4190 Gas &6 0.45 TY D4 C 9,426 4204 Wet &6 0.45 TY_D4_D 9,467 4222 Gas &6 0.45 TY D5 9,506 4240 Wet &6 0.45 TY_D6 9,552 4261 Gas &6 M5 TD 10,084 6321 Wet 121 0.63 Page 59 Revision 0 April 2019 9 H Hilcorp Em, c"mnNr KU 24-05B Drilling Procedure Offset Well Mud Densities Well MW range Top (TVD) Bottom (TVD) Date KBU 42-06Y 9.7 - 12 ppg 5,821 10,029 2014 KBU 23-05 9.4- 12.1 ppg 5,688 9,884 2014 KBU 11-08Z 9.4-12.2 ppg 5,581 9,508 2014 Assumptions: 1. Maximum planned mud density for the 6-3/4" hole section is 12.2 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 5,730' TVD =14.0 ppg EMW Fracture Pressure at 7-5/8" shoe considering a full column of gas from shoe to surface: 5730 (ft) x 0.72(psi/ft)= 4126 psi / 4126 (psi) - [0.1(psi/ft)*5730(ft)]= 3553 psi y/ MASP from pore pressure; entire wellbore evacuated to gas from TD 10084(ft) x 0.63(psi/ft)= 6353 psi 6353(psi) - [0.1(psi/ft)*10084 (ft)]- 5345 psi 6353(psi) - [(2/3)*0.1(psi/ft)*10084(ft)]+[(1/3)*0.63(psi/ft)*10084(ft)]= 3563 psi Alternate Drilling MASP Summary: 1. MASP while drilling 6-3/4" production hole is governed by SIBHP minus 2/3 wellbore evacuated to gas from TD. Page 60 Revision 0 April 2019 KU 24 -OSB Drilling Procedure 33.0 Spider Plot (NAD 27) (Governmental Sections) ``KU 32 46It &l 1®U st.aex Bll t 1 1 •I@U M2 VIi lu=M BNL 1 ! / I K8U 3xAe / 1 I / 1 1 u29XOb81i 1 f ' 1 I 1 / `♦`l i MBu 9J03 BML ,Y9d[Bw 1 1♦♦ I � /l Ii�♦ 1 I 1 ; \ ; KN 21ddM BNL \ 1\ 11 `�♦ r ( I I ♦ 11 4 1 1 / 14J 2� BML` 1MU 01811 1 ! /�� '• � \111//L ( e1i 1 T� � xellumel I XBU 4z.aex 1 1 I �1alu sz48 B vtsoe 811E Ir I 1 NBU 12415 BML 1 i i 8 00II1u213) I� KU 24-05B TPH � �L 4x= 11-0B%11 BML \ IIBI tt qTX BML �y�pq' AL"_4-05B SHL 1 ♦♦ • `t�gy I.ax, I1aBNL %-IYOiUi91-0JR6 BHLINU ATXPNL ; ` ``�\. `,may 1W+KU IILB BML \ \ 1 ♦ 1 1♦ i 1 KN Y!-0TM BML KBU Ot-0T / I I • �` 11 11.11..tI uW 1u CTU 02iIT BML 1 1 Legend 1 I I • KU24-05B—SHL • OMer Sw f. Hole L..t, 1 \♦ I � X KU24-05B_TPH • OMer Bottom Hole Low�ic0 i �I@t12241TBK \ INJ 4}I + KU24-058_BHL _-- Well Paths \\ •1®1f4]A]X BIR Oil end Gas Und Bountlary Me 43AIN BHq _; Page 61 Kenai Unit KU 24-05B Well wp_08 Revision 0 0 500 1.10 1.500 2.ODO Feet Kaska Stale Plane Zane 4. NAD27 Map Dale: N10,2019 April 2019 H Hilcorp 13� yam KU 24 -OSB Drilling Procedure 34.0 Surface Plat (As Built) (NAD 27) ( mb ®KDU 9 p KENAI GAS FIELD PAD 41-7 tl KBU 42-6X® GRAPHIC SCALE C sr ',Y ':Y :CO 1 inch 100 ft C Cr4wAtbv I. FIF MKU 13-5 *BU 41-7 n ®KU 43-6RD m �*BU 41-7% n ®KDU 4 Y ®KU 43-6A KDU-20 ®KU 24-5RD Fm fiit-8 101 ®KU 43-- 7 o � O N Y mco 1 ® � Y O 1 m O 1 I KU 24-058 ' AS—BUILT THIS SURVEY Y i HILCORP ALASKA, LLC KU 24-058 AS -BUILT SURFACE LOCATION DIAGRAM KENAI GAS FIELD PAD 41.7 AluKka, LLC , SECTION 6 & 7, T4N, R11 W, S.M. ALASKA Page 62 Revision 0 April 2019 1-4 r m ®KU 34-6 - NORTH n � e x � - I + a n a x x m �mmcc y I ® ® M7 ®KBU 12-5 S6IS KBU 33-6® S7 PE r x � � ®KBU 42-06Y N N 19KTU 32-7H Y x I ®KDU 9 p KENAI GAS FIELD PAD 41-7 tl KBU 42-6X® GRAPHIC SCALE C sr ',Y ':Y :CO 1 inch 100 ft C Cr4wAtbv I. FIF MKU 13-5 *BU 41-7 n ®KU 43-6RD m �*BU 41-7% n ®KDU 4 Y ®KU 43-6A KDU-20 ®KU 24-5RD Fm fiit-8 101 ®KU 43-- 7 o � O N Y mco 1 ® � Y O 1 m O 1 I KU 24-058 ' AS—BUILT THIS SURVEY Y i HILCORP ALASKA, LLC KU 24-058 AS -BUILT SURFACE LOCATION DIAGRAM KENAI GAS FIELD PAD 41.7 AluKka, LLC , SECTION 6 & 7, T4N, R11 W, S.M. ALASKA Page 62 Revision 0 April 2019 1-4 U Hilcorp E� c.�r 35.0 Offset MW vs TVD Chart MW Vs TVD I 2000 4000 0 6000 H 10000 KU 24-05B Drilling Procedure 12000 8 8.5 9 9.5 10 10.5 MW (ppb) 11 11.5 12 12.5 Page 63 Revision 0 April 2019 Drilling Procedure Procedure Hilcorp Energy Compmy 36.0 Drill Pipe Information "--- SIZE 41/211 LE COMMRND WEIGHT: 16.6 LBS/FT ERIRRV SERVICES GRADE; S•135 RANGE 11(31.5') DRILL PIPE SPECS CONNECTION: CDS40 71,16E NEW PREMIUM IN MM W MM OD 4.500 1143 4,365 1 10.9 WALLTHICKNESS 0.337 8.6 0.270 6.8 ID 3.826 97.2 3.826 972 FYi.BS N -M FT -LBS N+M TORSIONAL STRENGTH 55.453 75.200 43.451 58.900 80% TORSIONAL STRENGTH 44.352 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 INS MMS IN, MMS CROSS SECTIONAL AREA BODY 4.407 2844 3.469 2238 CROSS SECTIONAL AREA OD 15.904 10261 14.966 9655'. CROSS SECTIONAL AREA ID 11.497 741 7 1 1•497 7417' INS MMs INS MM. SECTION MODULUS 4.271 69995 3.347 54845 POLAR SECTION MODULUS 8.543 139989 6.694 109690 TOOL JOINT EW PREMIUM PSI KPA PSI KPA YIELD STRENGTH 130,000 896,318 130.000 896,316 IN MM IN MM OD 5-2500 133.4 5.1198 130.0 ID 2.6875 68.3 2.6875 68-3 PIN LENGTH 1 1 .0 279.4 1 1 .O 279-4 BOX LENGTH 14.0 355.6 14.0 355.6 FTa.BS N -M FTiBS 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 -QP TORQUE 21,200 28.800 20,800 28200 MIN MAKEi1PTOROUE 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 Fr M APPROXIMATE LENGTH 31.50 9.60 GAL/FT MS/M FLUID DISPLACEMENT 0.273 0,003394 FLUIDCAPACITr 0.577 0.007169 IN MM DRIFT SIZE11 2.5625 65 Page 64 Revision 0 April 2019 KU 24-05B Drilling Procedure COMBINED LOAD CURVE FOR 4 1/2" 5-135 16.6 LBS/FT DRILL PIPE WITH CDS40 CONNECTIONS 9W,000 - _... - ... 800,000 - ]00,000 600,000 c 500.000 . C 400,000 %. 200 OCC mb 0 10,000 20.000 30,000 401000 50,000 60.000 POW TagllwJWW) NEWTUBE COMBINED LOAD .... PREMIUM TUBE COMBINED LOAD —MAKEUPTOROUE —SHOULDERSEPE"TION —PIN YIELD —BOX YIELD Page 65 Revision 0 April 2019 H HilcOrp Energy CompmY 37.0 Directional Program (WP02) KU 24-05B Drilling Procedure Page 66 Revision 0 April 2019 Hilcorp Alaska, LLC Kenai Gas Field KGF 41-7 Pad Plan: KU 24-05B KU 24-05B Plan: KU 24-05B wp08 Standard Proposal Report 09 May, 2019 HALLIBURTON Sperry Drilling Services Hilcorp Alaska, LLC KErEKtINUL INrUNMAIIUN HALLIBURTON t,, ordinate(NIE) Reference: Well Pian: KU 24-05B, True North Calculation Method: Minimum Curvature Vertical (D) Reference: Plan C$ 84.10usft (HEC 169) aperey Grilling Error System: ISCWSA lan @ 84.10usR (HEC 169) Seen Method: Closest Approach 30 Measured Depth Reference: P Error Surtace: Pedal Curve Calculation Method: Minimum Curvature Warning Method: Error Ratio Project: Kenai Gas Field s cTION DETAILS Site: KGF 41-7 Pad Sec MD Inc Ad ND +NIS +EI -W DIe9 TFace VSect Target Annota4on Well: Plan: KU 24-058 t 18.00 ODD 0.00 18.00 Doo 0.00 0.00 0.00 0+00 2 318.00 0.00 000 31800 0.00 000 000 0.00 000 Shut Dir2°1100':31SMD, 318' 1) Wellbore: KU 24058 76800 9.00 80.00 766.15 Son 35.27 2.00 90.00 32.78 Stan 01r25°It0T: 768' MD. 766AV5 4 1219.80 18.30 6094 1205.17 34.67 132.67 2.50 5136 136.29 End Dir: i 2198' MD. 12031TND Design: KU 24-05B wp08 5 5111,45 18.30 60.84 4900.00 630,00 1200.00 0.00 0.00 1347.75 IN 24058 ep08 CPI Ssm Dlr r110P : 5111.45' MD, 4900WI) fi 5388.711 11.19 70.39 511BID 6511117 1264.49 3.00 166.13 b17.53 End Dir t 53867' MD, 51689T NO 7 9461,44 11.18 78.39 9163.31 81573 203902 0.00 0.00 2196.13 Sam Dir 3°1100': 9451.44'MD, 91633tTVD 8 9834.59 0,00 66.12 9534.10 823,04 2074.62 3.00 180.00 2231,91 End Dir : 9834.59' MD. 9534.1' ND 9 10234.59 0 00 66.12 99N.10 823.04 2074.62 0.00 800 2231.91 KU 24-05B 4p08 Tul 10 10304.59 000 66A2 1084,10 823.03 2074.62 0.00 111 2231,91 Total Depth: 1038459' MD, 10084.1'ND Kenai Gas Field 5.291 KGF 41-7 Pad Plan: KU 244158 KU 24-058 KU 24.458 08 WELL DETAILS: Plan: KU 24-0513 -750- 66.10 +N/ -S +El -W Northing Easting LatlBude Longitude 0.00 0,00 2361491.39 275130.28 60° 27' 29.1664 N 151° 14' 44.5552 16" X 24" SUBJEY PROGRAM 0 Start Dir 2°/100' : 318' MD, 318'TVD Dale: 2019-05-03T00:0001) Valiaaaa: Yes Version: - - " - Depth From Depth To SunreylPlan Tool 500 Start Dir 2.5°/100': 768' MD, 766.15'TVD 18.00 1530.00 KU24-0511w 13 (KU24a5B) 2_Mwoarikl+MS+S, 1530.00 5962.00 KU 24-0511""03 IQJ 24-058) 2_MWD+IFRI+MS+Sag 596200 1038459 KU 24-0513 "08 (KU 24-0513) 2MWD+IFRI+MS+Sag 750 1p00 End Dir : 1219.8' MD, 1205.17'TVD FORMATION TOP DETAILS \ 10 3/4" X 13 1/2" NDPath NOSSPath MDPath Formation 1500 d 1,6-09 - - - 3326.10 3242.00 3453]1 P3 A4 3819.10 3735.00 3972.98 P4_131 3948.10 3864.00 4108,85 FE B3 2000 4489.10 4405.00 4678.67 P6 Cl STORAGE 4656.10 4572.00 4854.56 P6 C2 STORAGE 22504719.10 4635.00 4920.92 U_BELUGA 2.600 5347.10 5263.00 557130 M BELUGA 6085AD 6001.00 6323.52 L_BELUGA 6177.10 6093.00 6417.30 LB 1B 6260.10 6176.00 6501.91 LBID 160p0 6570.10 6486.00 68117.93 LB_20 3000 6929.10 6845.00 7183.88 LB 4C 727610 7192.00 7537.62 TY 72 8 _.3500 7302.10 7218.00 7564.12 W 73_1 P3 A4 7516.10 7432.00 7782.27 UT ID 7566.10 7462.00 7833.24 TY_75_8 3750 - 4_1PI_B1 __ ...... _ _.-4000 7913.10 7829.00 8186.97 UT 48 y _ - 8437.10 8353.00 8721.14 TY_84 6C PS B3 8581.10 8497.00 8867.93 TY_86 213 p - 8703.10 8619.00 8992.30 TY 01 C' PB C1 STORAGE 4500 8872.10 8788.00 9164.57 TY 02 '- _ --- 9172.10 9088.00 9470.39 TY D3 A 4500 PfiC2 STORAGE _ Start Dir 3a/100' : 5111.45' MD, 4900'ND 9359.10 9275.00 9859.35 TY_Di_A _ L - - - - - - 5000 - - - " 9381.10 9297.00 9681.43 TY_D4 B a U_BELUGA - " - - 9454.10 9370.00 9754.57 T1 D4_0 N ch _ - 9511.10 9457.00 9841.59 TY D6 Z5250- KU 24-05B wpO8 CPI 5500- - - - - - -End Dir :5388.7 MD, 5168.07 ND D. _ .. ....... _ __ .- ...- M BELUGA CASING DETAILS 6006 - - - - - - 7 5/8" z 9 7/8" NO NOSS MD Size Name H6000 120.00 35.90 120.00 16 16" x 24" L_BELUGA-- _ _.- _.. -., 1499.68 1415.58 1530.00 10-3/4 10314'x13112" LS IB, - - - 6500 5730.46 5646.36 5962.00 7-518 75/8'.97)8" LB_1D 10084.10 10000.00 10384.59 4-112 4104 63W 6750 LB -2D 7000 B- W-72-8_727z_e_7500 7500 TY -73-1 UT_4B N 84 6C SSW TY_86 213 " �g00 TY_DT; 9000 Start Dir 3o/100': 9461.44' MD, 9163.31'ND TY D3 A L5UUTY 041, TY D4 g - ___ _ _End Dir :9834.59'MD, 9534.1' ND 'JTY_Dd D _ 00 9750- TY -D6 _Total Depth :10384.59' MD, 10084.1' ND KU 24-056 wp08 Tgtl - - - - - - 4 1/2" x 6 3/4" 10500 KU 24-05B wp08 Tiii T 0 750 1500 2250 3000 3750 4500 5250 6000 Vertical Section at 68.36° (1500 usMin) NAW OM MCIN �i iUE/L�gvrm Ib" x 24" End Dv :1219.8'MD, 1205.17- WD 0 Start Dir 2.5-11W: : ]68' MD, 766.19WD Sean Dir 2"/IW' : 318' MD, 3187VD �Nrtiul (rv9f xWnn+' Pbn @�M 1da36�L twlxoiu Mrm uMg6.edrenu liMm®iev G10Mu6�XFLiWI nn IMM: Projec....enai Gas Fieltl Site: KGF 4t-7 Pad Will Plan: KU 24 -OSB Wellbore: KU 24058 Plan: KU 24-058 wp08 End Dv :1219.8'MD, 1205.17- WD 0 Start Dir 2.5-11W: : ]68' MD, 766.19WD Sean Dir 2"/IW' : 318' MD, 3187VD �Nrtiul (rv9f xWnn+' Pbn @�M 1da36�L twlxoiu Mrm uMg6.edrenu liMm®iev G10Mu6�XFLiWI nn IMM: 7 98" x 9 7/8" 110.385 KV 24059 uy08 C I o N o if KU 24-058 wp08 o $ c $ > o o$ Slert Diro3"/100':941.4 MD,9163.31'TVD EM Dir : 9834.59' MD, 9534.1' TVD' J � ?r oo Tore) Depth : 10384.59' �, 10084.1' TVD 'o Fnd Dir :5368]'hm, 51660TTVD Sr D1r 3"/100': 5111.45' MD, 49009 0 167 333 SW 667 8]] IOW 116] Wmt(-)/F tq+) (2501ss0/1n) T Stt UO See Name QD 0 35.90 120.00 16 .. IJ99fig 1415.50 I. 1530W 1039 10314-x 13W 57W 46564636 M 20 M ]-SIB 1..x.]2' 10084.10 1000 0.00 1(3843. 41R 41?x631V KV 24-05. uy08 T 1 4 M. x 6 3/4" 7 98" x 9 7/8" 110.385 KV 24059 uy08 C I o N o if KU 24-058 wp08 o $ c $ > o o$ Slert Diro3"/100':941.4 MD,9163.31'TVD EM Dir : 9834.59' MD, 9534.1' TVD' J � ?r oo Tore) Depth : 10384.59' �, 10084.1' TVD 'o Fnd Dir :5368]'hm, 51660TTVD Sr D1r 3"/100': 5111.45' MD, 49009 0 167 333 SW 667 8]] IOW 116] Wmt(-)/F tq+) (2501ss0/1n) i Project: Kenai Gas Field Site: KGF 41-7 Pad Well: Plan: KU 24-05B Wellbore: KU 24-05B Plan: KU 24-05B wp08 KBU 31-06X KN 4]-bXRD KT 43-6X 8000 5000 KT31431XRD2 ]000 6000 4000 5000 HALLISURTON %04 6w.ry o.In1.q t..va� 2000 4 12" x 6 3/4" 7 SB" x 9 7B" 3200 0000 $ F 4000 KU 4 4gg1 133 1000 02 KU I I KDU 2 (21-8) "� o KBU 4^---7RD D c KBU 42-7 0 fu4 g 1000 11 I-oliz I I -267 -133 0 133 267 West( -)/East(+) (20011sft/in) KU 14-05 2a5 000 West( -)/East(+) (600 m8/in) %04 2000 4 12" x 6 3/4" 7 SB" x 9 7B" 0000 $ KU 24-050 w 08 2000 KBU 1185 2000 o N� Q 'b K3U41-7x _ 4" 13 In $ K)UJg2 (2I-8) KBU 11-eY KDU 10 KDU 2 (21-8) No hb$ 2 �O Q KU 11-8 tr� KN 32-7H h g 00 KBU 11-08Z o _ v� N KBU 42 -]RD -I(DU-O4RD 3000 T M Azimulha b True Nodh Magnetic Nodh: 15.38° Magnetic Field Strength: 55187.1nT Dip Angle: 73.41° Dale: 511 Model: BGGM2018 -1200 -800 400. 0 400 800 1200 1600 2000 2400 2800 West( -)/East(+) (600 m8/in) HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Kenai Gas Field Site: KGF 41-7 Pad Well: Plan: KU 24-05B Wellbore: KU 24-05B Design: KU 24-058 wp08 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: KU 24-058 TVD Reference: Plan @ 84.10usft (HEC 169) MD Reference: Plan @ 84.10usft (HEC 169) North Reference: True Survey Calculation Method: Minimum Curvature 'roject Kenai Gas Field lap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level leo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point lap Zone: Alaska Zone 04 Using geodetic scale factor Site KGF 41-7 Pad Site Position: Northing: 2,361,462.42 Left Latitude: 60° 27'28 8295 N From: Lat/Long Easting: 274,852.80usft Longitude: 151° 14'50.0763 W Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid Convergence: -1.09 ' Well Plan: KU 24-05B, 519' FNL 8 771' FEL Well Position +N/S 0.00 usft Northing: 2,361,491.39 usft Latitude: 60' 27'29.1664 N +El -W 0.00 usft Easting: 275,130.28 usft Longitude: 151° 14'44.5552W Position Uncertainty 0.50 usft Wellhead Elevation: usft Ground Level: 66.10 usft Wellbore KU 24-058 Magnetics Model Name Sample Date Declination Dip Angle Field Strength U) P) (nT) BGG102018 5/3/2019 15.38 7341 55,187.07651008 Design KU 24-058 wp08 Audit Notes: Version: Phase: PLAN Tie On Depth: 18.00 Vertical Section: Depth From (TVD) -N/.S +El -W Direction (usft) (usft) (usft) (°) 18.00 0.00 0.00 68.36 Pian Sections Measured Vertical TVD Dogleg Build Tum Depth Inclination Azimuth Depth System +N/ -S +Et -W Rate Rate Rate Tool Face (usft) (') (') (usft) usft (usft) (usft) (°/100usft) ("/100usft) (°/100usft) (°) I 18.00 0.00 0.00 18.00 -66.10 0.00 0.00 0.00 0.00 0.00 0.00 318.00 0.00 0.00 318.00 233.90 0.00 0.00 0.00 0.00 0.00 0.00 768.00 9.00 90.00 766.15 682.05 0.00 35.27 2.00 2.00 0.00 90.00 1,219.80 18.30 60.84 1,205.17 1,121.07 34.67 132.87 2.50 2.06 -6.45 -51.36 5,111.45 18.30 60.84 4,900.00 4,815.90 630.00 1,200.00 0.00 0.00 0.00 0.00 5,388.70 11.19 78.39 5,168.07 5,083.97 656.67 1,264.49 3.00 -2.56 6.33 156.13 9,461.44 11.19 78.39 9,163.31 9.07921 815.73 2,039.02 0.00 0.00 0.00 0.00 9,834.59 0.00 66.12 9,534.10 9,450.00 823.04 2,074.62 3.00 -3.00 0.00 180.00 10,234.59 0.00 66.12 9,934.10 9,850.00 823.04 2,074.62 0.00 0.00 0.00 0.00 10,384.59 0.00 66.12 10,084.10 10,000.00 823.04 2,074.62 0.00 0.00 0.00 66.12 51912019 6:24:06PM Page 2 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Kenai Gas Field Site: KGF 41-7 Pad Well: Plan: KU 24 -OSB Wellbore: KU 24-05B Design: KU 24-05B wp08 Planned Survey Measured Vertical Depth Inclination Azimuth Depth (usft) (1) (1) (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" Easting DLS Vert Section 200.00 0.00 0.00 200.00 300.00 0.00 0.00 300.00 318.00 0.00 0.00 318.00 Start Dir 2-/100': 318' Will 318'TVD 275,130.28 400.00 1.64 90.00 399.99 500.00 3.64 90.00 499.88 600.00 5.64 90.00 599.54 700.00 7.64 90.00 698.87 768.00 9.00 90.00 766.15 Start Dir 2.5•1100': 768' MD, 766.15'TVD 800.00 9.52 86.22 797.73 900.00 11.35 76.80 896.08 1,000.00 13.40 70.09 993.76 1,100.00 15.58 65.18 1,090.57 1,200.00 17.85 61.47 1,186.35 1,219.80 18.30 60.84 1,205.17 End Dir : 1219.8' MD, 1205.17' TVD 2.00 1,300.00 18.30 60.84 1,281.31 1,400.00 18.30 60.84 1,376.25 1,500.00 18.30 60.84 1,471.20 1,530.00 18.30 60.84 1,499.68 10 3/4" x 13 112" 0.00 25.43 1,600.00 18.30 60.84 1,566.14 1,700.00 18.30 60.84 1,661.08 1,800.00 18.30 60.84 1,756.02 1,900.00 18.30 60.84 1,850.97 2,000.00 18.30 60.84 1,945.91 2,100.00 18.30 60.84 2,040.85 2,200.00 18.30 60.84 2,135.79 2,300.00 18.30 60.84 2,230.74 2,400.00 18.30 60.84 2,325.68 2,500.00 18.30 60.84 2,420.62 2,600.00 18.30 60.84 2,515.56 2,700.00 18.30 60.84 2,610.51 2,800.00 18.30 60.84 2,705.45 2,900.00 18.30 60.84 2,800.39 3,000.00 18.30 60.84 2,895.33 3,100.00 18.30 60.84 2,990.28 3,200.00 18.30 60.84 3,085.22 3,300.00 18.30 60.84 3,180.16 3,400.00 18.30 60.84 3,275.10 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: KU 24-058 TVD Reference: Plan @ 84.10usft (HEC 169) MD Reference: Plan @ 84.10usft (HEC 169) North Reference: True Survey Calculation Method: Minimum Curvature SWO19 6:24:06PM Page 3 COMPASS 5000.15 Build 91 Map Map TVDss +NIS +E/ -W Northing Easting DLS Vert Section usft (usft) (usft) (usft) (usft) 66.10 66.10 0.00 0.00 2,361,491.39 275,130.28 0.00 0.00 -15.90 0.00 0.00 2,361,491.39 275,130.28 0.00 0.00 -35.90 0.00 0.00 2,361,491.39 275,130.28 0.00 0.00 -115.90 0.00 0.00 2,361,491.39 275,130.28 0.00 0.00 .215.90 0.00 0.00 2,361,491.39 275,130.28 0.00 0.00 -233.90 0.00 0.00 2,361,491.39 275,130.28 0.00 0.00 -315.89 0.00 1.17 2,361,491.36 275,131.45 2.00 1.09 -415.78 0.00 5.78 2,361,491.28 275,136.05 2.00 5.37 .515.44 0.00 13.87 2,361,491.12 275,144.14 2.00 12.89 .614.77 0.00 25.43 2,361,490.91 275,155.70 2.00 23.64 -682.05 0.00 35.27 2,361,490.72 275,165.54 2.00 32.78 -713.63 0.17 40.41 2,361,490.80 275,170.68 2.50 37.63 -811.98 2.97 58.25 2,361,493.25 275,188.57 2.50 55.24 -909.66 9.16 78.74 2,361,499.06 275,209.17 2.50 76.57 -1,006.47 18.75 101.83 2,361,508.21 275,232.44 2.50 101.57 -1,102.25 31.71 127.49 2,361,520.67 275,258.34 2.50 130.20 -1,121.07 34.67 132.87 2,361,523.54 275,263.77 2.50 136.29 .1,197.21 46.94 154.86 2,361,535.39 275,285.99 0.00 161.26 -1,292.15 62.24 182.28 2,361,550.16 275,313.69 0.00 192.39 -1,387.10 77.53 209.70 2,361,564.94 275,341.40 0.00 223.52 -1,415.58 82.12 217.93 2,361,569.37 275,349.71 0.00 232.85 -1,482.04 92.83 237.12 2,361,579.71 275,369.10 0.00 254.65 -1,576.98 108.13 264.55 2,361,594.49 275,396.81 0.00 285.77 -1,671.92 123.43 291.97 2,361,609.26 275,424.51 0.00 316.90 -1,766.87 138.72 319.39 2,361,624.04 275,452.22 0.00 348.03 -1,861.81 154.02 346.81 2,361,638.81 275,479.92 0.00 379.16 -1,956.75 169.32 374.23 2,351,653.59 275,507.63 0.00 410.29 -2,051.69 184.62 401.65 2,361,668.37 275,535.33 0.00 441.42 -2,146.64 199.91 429.07 2,361,683.14 275,563.03 0.00 472.55 -2,241.58 215.21 456.49 2,361,697.92 275,590.74 0.00 503.68 -2,336.52 230.51 483.91 2,361,712.69 275,618.44 0.00 534.81 -2,431.46 245.81 511.34 2,361,727.47 275,646.15 0.00 565.94 -2,526.41 261.10 538.76 2,361,742.24 275,673.85 0.00 597.07 -2,621.35 276.40 566.18 2,361,757.02 275,701.56 0.00 628.20 -2,716.29 291.70 593.60 2,361,771.79 275,729.26 0.00 659.33 -2,811.23 307.00 621.02 2,361,786.57 275,756.96 0.00 690.46 -2,906.18 322.30 648.44 2,361,801.35 275,784.67 0.00 721.59 -3,001.12 337.59 675.86 2,361,816.12 275,812.37 0.00 752.72 -3,096.06 352.89 703.28 2,361,830.90 275,840.08 0.00 783.85 -3,191.00 368.19 730.70 2,361,845.67 275,867.78 0.00 814.98 SWO19 6:24:06PM Page 3 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Kenai Gas Field Site: KGF 41-7 Pad Well: Plan: KU 24-05B Wellbore: KU 24-05B Design: KU 24-058 wp08 Planned Survey Map Map Measured +N/ -S +FJ.W Vertical Fasting Depth Inclination Vert Section Azimuth Depth TVDss (usft) (°) x,242.00 (°) (usft) usft 3,453.71 18.30 60.84 3,326.10 -3,242.00 P3 -A4 2,361,860.45 275,895.49 0.00 846.11 3,500.00 18.30 60.84 3,370.05 -3,285.95 3,600.00 18.30 60.84 3,464.99 -3,380.89 3,700.00 18.30 60.84 3,559.93 -3,475.83 3,800.00 18.30 60.84 3,654.87 -3,570.77 3,900.00 18.30 60.84 3,749.82 -3,665.72 3,972.98 18.30 60.84 3,819.10 -3,735.00 P4 -B1 895.23 2,361,934.33 276,034.01 0.00 4,000.00 18.30 60.84 3,844.76 -3,760.66 4,100.00 18.30 60.84 3,939.70 -3,855.60 4,108.85 18.30 60.84 3,948.10 -3,864.00 PS -83 276,089.42 0.00 1,064.02 505.87 4,200.00 18.30 60.84 4,034.64 -3,950.54 4,300.00 18.30 60.84 4,129.59 -4,045.49 4,400.00 18.30 60.84 4,224.53 -4,140.43 4,500.00 18.30 60.84 4,319.47 -4,235.37 4,600.00 18.30 60.84 4,414.41 -4,330.31 4,678.67 18.30 60.84 4,489.10 -4,405.00 Pit C1 STORAGE 2,362,037.76 276,227.94 0.00 4,700.00 18.30 60.84 4,509.35 -4,425.25 4,800.00 18.30 60.84 4,604.30 -4,520.20 4,854.56 18.30 60.84 4,656.10 -4,572.00 P6 C2 STORAGE 276,283.35 0.00 1,281.93 4,900.00 18.30 60.84 4,699.24 -4,615.14 4,920.92 18.30 60.84 4,719.10 -4,635.00 U_BELUGA 1,313.06 628.25 1,196.86 2,362,096.86 5,000.00 18.30 60.84 4,794.18 -4,710.08 5,100.00 18.30 60.84 4,889.12 -4,805.02 5,111.45 18.30 60.84 4,900.00 -4,815.90 Start Dir 3-/100': 5111.45' MD, 4900'TVD 2,362,119.24 276,388.73 5,200.00 15.91 64.77 4,984.63 -4,900.53 5,300.00 13.32 70.81 5,081.39 .4,997.29 5,388.70 11.19 78.39 5,168.07 -5,083.97 End Dir : 5388.7' MD, 5168.07' TVD 276,428.15 0.00 5,400.00 11.19 78.39 5,179.15 -5,095.05 5,500.00 11.19 78.39 5,277.25 -5,193.15 5,571.20 11.19 78.39 5,347.10 -5,263.00 M_BELUGA 276,466.33 0.00 1,477.04 672.73 5,600.00 11.19 78.39 5,375.35 -5,291.25 5,700.00 11.19 78.39 5,473.44 -5,389.34 5,800.00 11.19 78.39 5,571.54 -5,487.44 5,900.00 11.19 78.39 5,669.64 -5,585.54 5,962.00 11.19 78.39 5,730.46 -5,646.36 7518"z 9718" Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan: KU 24-058 Plan @ 84.10usft (HEC 169) Plan @ 84.10usft (HEC 169) True Minimum Curvature 5/92019 6:24:06PM Page 4 COMPASS 5000.15 Build 91 Map Map +N/ -S +FJ.W Northing Fasting DLS Vert Section (usft) (usft) (usft) (usft) x,242.00 376.40 745.43 2,361,853.61 275,882.66 0.00 831.70 383.49 758.12 2,361,860.45 275,895.49 0.00 846.11 398.78 785.55 2,361,875.22 275,923.19 0.00 877.24 414.08 812.97 2,361,890.00 275,950.90 0.00 908.37 429.38 840.39 2,361,904.78 275,978.60 0.00 939.50 444.68 867.81 2,361,919.55 276,006.30 0.00 970.63 455.84 887.82 2,361,930.33 276,026.52 0.00 993.35 459.97 895.23 2,361,934.33 276,034.01 0.00 1,001.76 475.27 922.65 2,361,949.10 276,061.71 0.00 1,032.89 476.62 925.08 2,361,950.41 276,064.16 0.00 1,035.64 490.57 950.07 2,361,963.88 276,089.42 0.00 1,064.02 505.87 977.49 2,361,978.65 276,117.12 0.00 1,095.15 521.16 1,004.91 2,361,993.43 276,144.83 0.00 1,126.28 536.46 1,032.34 2,362,008.20 276,172.53 0.00 1,157.41 551.76 1,059.76 2,362,022.98 276,200.23 0.00 1,188.54 563.79 1,081.33 2,362,034.60 276,222.03 0.00 1,213.03 567.06 1,087.18 2,362,037.76 276,227.94 0.00 1,219.67 582.35 1,114.60 2,362,052.53 276,255.64 0.00 1,250.80 590.70 1,129.56 2,362,060.59 276,270.76 0.00 1,267.78 597.65 1,142.02 2,362,067.31 276,283.35 0.00 1,281.93 600.85 1,147.76 2,362,070.40 276,289.14 0.00 1,288.44 612.95 1,169.44 2,362,082.08 276,311.05 0.00 1,313.06 628.25 1,196.86 2,362,096.86 276,338.76 0.00 1,344.19 630.00 1,200.00 2,362,098.55 276,341.93 0.00 1,347.75 641.95 1,223.12 2,362,110.06 276,365.27 3.00 1,373.65 651.58 1,246.40 2,362,119.24 276,388.73 3.00 1,398.84 656.67 1,264.49 2,362,123.99 276,406.91 3.00 1,417.53 657.11 1,266.64 2,362,124.39 276,409.06 0.00 1,419.69 661.01 1,285.66 2,362,127.94 276,428.15 0.00 1,438.81 663.79 1,299.20 2,362,130.46 276,441.74 0.00 1,452.42 664.92 1,304.67 2,362,131.48 276,447.24 0.00 1,457.92 668.82 1,323.69 2,362,135.03 276,466.33 0.00 1,477.04 672.73 1,342.71 2,362,138.57 276,485.41 0.00 1,496.16 676+64 1,361.73 2,362,142.12 276,504.50 0.00 1,515.27 679.06 1,373.52 2,362,144.31 276,516.33 0.00 1,527.13 5/92019 6:24:06PM Page 4 COMPASS 5000.15 Build 91 Halliburton HALLI B U RTO N Standard Proposal Report Database: Company: Project: Site: Well: Wellbore: Design: NORTH US +CANADA Hilcorp Alaska, LLC Kenai Gas Field KGF 41-7 Pad Plan: KU 24-05B KU 24-05B KU 24-05B wp08 Local Co-ordinate Reference: Well Plan: KU 24-05B ND Reference: Plan @ 84.10usft (HEC MD Reference: Plan @ 84.10usft (HEC North Reference: True Survey Calculation Method: Minimum Curvature 169) 169) Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NIS +EI -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) -5,683.64 6,000.00 11.19 78.39 5,767.74 -5,683.64 680.54 1,380.74 2,362,145.66 276,523.59 0.00 1,534.39 6,100.00 11.19 78.39 5,865.83 5,781.73 684.45 1,399.76 2,362,149.21 276,542.67 0.00 1,553.51 6,200.00 11.19 78.39 5,963.93 -5,879.83 688.35 1,418.78 2,362,152.75 276,561.76 0.00 1,572.63 6,300.00 11.19 78.39 6,062.03 -5,977.93 692.26 1,437.80 2,362,156.30 276,580.85 0.00 1,591.74 6,323.52 11.19 78.39 6,085.10 -6,001.00 693.18 1,442.27 2,362,157.13 276,585.34 0.00 1,596.24 L_BELUGA 6,400.00 11.19 78.39 6,160.13 -6,076.03 696.16 1,456.81 2,362,159.84 276,599.94 0.00 1,610.86 6,417.30 11.19 78.39 6,177.10 -6,093.00 696.84 1,460.10 2,362,160.45 276,603.24 0.00 1,614.17 LB_1B 6,500.00 11.19 78.39 6,258.22 -6,174.12 700.07 1,475.83 2,362,163.39 276,619.02 0.00 1,629.98 6,501.91 11.19 78.39 6,260.10 -6,176.00 700.14 1,476.20 2,362,163.45 276,619.39 0.00 1,630.34 LB_1D 6,600.00 11.19 78.39 6,356.32 -6,272.22 703.97 1,494.85 2,362,166.93 276,638.11 0.00 1,649.10 6,700.00 11.19 78.39 6,454.42 -6,370.32 707.88 1,513.87 2,362,170.48 276,657.20 0.00 1,668.21 6,800.00 11.19 78.39 6,552.52 -6,468.42 711.78 1,532.88 2,362,174.02 276,676.28 0.00 1,687.33 6,817.93 11.19 78.39 6,570.10 -6,486.00 712.48 1,536.29 2,362,174.66 276,679.70 0.00 1,690.76 LB_2D 6,900.00 11.19 78.39 6,650.61 -6,566.51 715.69 1,551.90 2,362,177.56 276,695.37 0.00 1,706.45 7,000.00 11.19 78.39 6,748.71 -6,664.61 719.60 1,570.92 2,362,181.11 276,714.46 0.00 1,725.57 7,100.00 11.19 78.39 6,846.81 -6,762.71 723.50 1,589.94 2,362,184.65 276,733.54 0.00 1,744.68 7,183.89 11.19 78.39 6,929.10 -6,845.00 726.78 1,605.89 2,362,187.63 276,749.56 0.00 1,760.72 LB_4C 7,200.00 11.19 78.39 6,944.90 -6,860.80 727.41 1,608.95 2,362,188.20 276,752.63 0.00 1,763.80 7,300.00 11.19 78.39 7,043.00 -6,958.90 731.31 1,627.97 2,362,191.74 276,771.72 0.00 1,782.92 7,400.00 11.19 78.39 7,141.10 -7,057.00 735.22 1,646.99 2,362,195.29 276,790.81 0.00 1,802.03 7,500.00 11.19 78.39 7,239.20 -7,155.10 739.12 1,666.01 2,362,198.83 276,809.89 0.00 1,821.15 7,537.62 11.19 78.39 7,276.10 -7,192.00 740.59 1,673.16 2,362,200.17 276,817.07 0.00 1,828.34 TY -72-8 7,564.12 11.19 78.39 7,302.10 -7,218.00 741.63 1,678.20 2,362,201.11 276,822.13 0.00 1,833.41 TY -73-1 7,600.00 11.19 78.39 7,337.29 -7,253.19 743.03 1,685.02 2,362,202.38 276,828.98 0.00 1,840.27 7,700.00 11.19 78.39 7,435.39 -7,351.29 746.93 1,704.04 2,362,205.92 276,648.07 0.00 1,859.39 7,782.27 11.19 78.39 7,516.10 -7,432.00 750.15 1,719.69 2,362,208.64 276,863.77 0.00 1,875.12 UT_1D 7,800.00 11.19 78.39 7,533.49 -7,449.39 750.84 1,723.06 2,362,209.47 276,867.15 0.00 1,878.50 7,833.24 11.19 78.39 7,566.10 -7,482.00 752.14 1,729.38 2,362,210.65 276,873.50 0.00 1,884.86 TY -75-8 7,900.00 11.19 78.39 7,631.59 -7,547.49 754.74 1,742.08 2,362,213.01 276,886.24 0.00 1,897.62 8,000.00 11.19 78.39 7,729.68 -7,645.58 758.65 1,761.09 2,362,216.56 276,905.33 0.00 1,916.74 8,100.00 11.19 78.39 7,827.78 -7,743.68 762.56 1,780.11 2,362,220.10 276,924.42 0.00 1,935.86 8,186.97 11.19 78.39 7,913.10 -7,829.00 765.95 1,796.65 2,362,223.19 276,941.02 0.00 1,952.48 UT -4B 8,200.00 11.19 78.39 7,925.88 -7,841.78 766.46 1,799.13 2,362,223.65 276,943.50 0.00 1,954.97 8,300.00 11.19 78.39 8,023.98 -7,939.88 770.37 1,818.14 2,362,227.19 276,962.59 0.00 1,974.09 8,400.00 11.19 78.39 8,122.07 -8,037.97 774.27 1,837.16 2,362,230.74 276,981.68 0.00 1,993.21 51912019 6:24:06PM Page 5 COMPASS 5000.15 Build 91 Halliburton H ALL I B U R TO N Standard Proposal Report Database: NORTH US +CANADA Local Co-ordinate Reference: Well Plan: KU 24-05B Company: Hilcorp Alaska, LLC TVD Reference: Pian @ 84.10usft (HEC 169) Project: Kenai Gas Field MD Reference: Plan @ 84.10usft (HEC 169) Site: KGF 41-7 Pad North Reference: True Well: Plan: KU 24-05B Survey Calculation Method: Minimum Curvature Wellbore: KU 24-05B Design: KU 24 -OSB wp08 Azimuth Depth Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +PJ -W Northing Easting DLS Vert Section (usft) (1) (") (usft) usft (usft) (usft) (usft) (usft) -8,136.07 8,500.00 11.19 78.39 8,220.17 -8,136.07 778.18 1,856.18 2,362,234.28 277,000.76 0.00 2,012.33 8,600.00 11.19 78.39 8,318.27 -8,234.17 782.08 1,875.20 2,362,237.83 277,019.85 0.00 2,031.44 8,700.00 11.19 78.39 8,416.36 -8,332.26 785.99 1,894.21 2,362,241.37 277,038.94 0.00 2,050.56 8,721.14 11.19 78.39 8,437.10 -8,353.00 786.81 1,898.23 2,362,242.12 277,042.97 0.00 2,054.60 TY_84_BC 8,800.00 11.19 78.39 8,514.46 -8,430.36 789.89 1,913.23 2,362,244.92 277,058.02 0.00 2,069.68 8,867.93 11.19 78.39 8,581.10 -8,497.00 792.55 1,926.15 2,362,247.33 277,070.99 0.00 2,082.66 TY 86_2B 8,900.00 11.19 78.39 8,612.56 -8,528.46 793.80 1,932.25 2,362,248.46 277,077.11 0.00 2,088.79 8,992.30 11.19 78.39 8,703.10 -8,619.00 797.40 1,949.80 2,362,251.73 277,094.73 0.00 2,106.44 TY D1 9,000.00 11.19 78.39 8,710.66 -8,626.56 797.70 1,951.27 2,362,252.01 277,096.20 0.00 2,107.91 9,100.00 11.19 78.39 8,808.75 -8,724.65 801.61 1,970.28 2,362,255.55 277,115.29 0.00 2,127.03 9,164.57 11.19 78.39 8,872.10 -8,788.00 804.13 1,982.56 2,362,257.84 277,127.61 0.00 2,139.37 TY -D2 9,200.00 11.19 78.39 8,906.85 -8,822.75 805.52 1,989.30 2,362,259.10 277,134.37 0.00 2,146.15 9,300.00 11.19 78.39 9,004.95 -8,920.85 809.42 2,008.32 2,362,262.64 277,153.46 0.00 2,165.26 9,400.00 11.19 78.39 9,103.05 -9,018.95 813.33 2,027.34 2,362,266.19 277,172.55 0.00 2,184.38 9,461.44 11.19 78.39 9,163.31 -9,079.21 815.73 2,039.02 2,362,266.36 277,184.27 0.00 2,196.13 Start Dir 3°7100' : 9461.44' MD, 9163.31'TV13 9,470.39 10.93 78.39 9,172.10 -9,088.00 816.07 2,040.70 2,362,268.68 277,185.96 3.00 2,197.82 TY_O3 A 9,500.00 10.04 78.39 9,201.22 -9,117.12 817.15 2,045.98 2,362,269.66 277,191.26 3.00 2,203.12 9,600.00 7.04 78.39 9,300.10 -9,216.00 820.14 2,060.52 2,362,272.37 277,205.85 3.00 2,217.74 9,659.35 5.26 78.39 9,359.10 -9,275.00 821.42 2,066.75 2,362,273.53 277,212.10 3.00 2,224.00 TY_D4_A 9,681.43 4.59 78.39 9,381.10 -9,297.00 821.80 2,068.60 2,362,273.88 277,213.97 3.00 2,225.86 TY D4 8 9,700.00 4.04 78.39 9,399.62 -9,315.52 822.08 2,069.97 2,362,274.13 277,215.34 3.00 2,227.24 9,754.57 2.40 78.39 9,454.10 -9,370.00 822.70 2,072.97 2,362,274.69 277,218.35 3.00 2,230.26 TY D -O4 9,800.00 1.04 78.39 9,499.51 -9,415.41 822.97 2,074.31 2,362,274.94 277,219.69 3.00 2,231.60 9,834.59 0.00 66.12 9,534.10 -9,450.00 823.04 2,074.62 2,362,275.00 277,220.00 3.00 2,231.91 End Dir : 9834.59' MD, 9534.1' TVD 9,841.59 0.00 0.00 9,541.10 -9,457.00 823.04 2,074.62 2,362,275.00 277,220.00 0.00 2,231.91 TY D6 9,900.00 0.00 0.00 9,599.51 -9,515.41 823.04 2,074.62 2,362,275.00 277,220.00 0.00 2,231.91 10,000.00 0.00 0.00 9,699.51 -9,615.41 823.04 2,074.62 2,362,275.00 277,220.00 0.00 2,231.91 10,100.00 0.00 0.00 9,799.51 -9,715.41 823.04 2,074.62 2,362,275.00 277,220.00 0.00 2,231.91 10,200.00 0.00 0.00 9,899.51 -9,815.41 823.04 2,074.62 2,362,275.00 277,220.00 0.00 2,231.91 10,234.59 0.00 66.12 9,934.10 -9,850.00 823.04 2,074.62 2,362,275.00 277,220.00 0.00 2,231.91 10,300.00 0.00 0.00 9,999.51 -9,915.41 823.04 2,074.62 2,362,275.00 277,220.00 0.00 2,231.91 10,384.59 0.00 0.00 10,084.10 -10,000.00 823.04 2,074.62 2,362,275.00 277,220.00 0.00 2,231.91 Total Depth : 10384.59' MD, 10084.1' TVD - 41/2" x 6 3/4" SWO19 6:24:06PM Page 6 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Kenai Gas Field Site: KGF 41-7 Pad Well: Plan: KU 24-058 Wellbore: KU 24-05B Design: KU 24-05B wp08 Local Co-ordinate Reference: ND Reference: MD Reference: North Reference: Survey Calculation Method: Targets Target Name -hitimiss target Dip Angle Dip Dir. TVD -Shape (°) (°) (usft) KU 24-05B wp08 Tun 0.00 0.00 9,934.10 - plan hits target center - Paint KU 24-05B wp08 CP1 0.00 - plan hits target center - Paint Casing Points Measured Vertical P4 Bi Depth Depth P3 A4 (usft) (usft) TY_D4_A 1,530.00 1,499.68 10 3/4"x 13 1/2" 10,384.59 10,084.10 4 112" x 6 3/4" 5,962.00 5,730.46 7 5/8" x 9 7/8" 120.00 120.00 16" x 24• Halliburton Standard Proposal Report Well Plan: KU 24-056 Plan @ 84.10usft (HEC 169) Plan @ B4.10usft (NEC 169) True Minimum Curvature +N/ -S +EJ -W Northing Eastal (usft) (usft) (usft) (usft) 823.04 2,074.62 2,362,275.00 277,220.00 0.00 4,900.00 630.00 1,200.00 2,362,098.55 276,341.93 Casing Hole Diameter Diameter Name (11) () 10-314 13-1/2 4-1/2 6-3/4 7-5/8 9-7/8 16 24 Formations Measured Vertical Vertical Depth Depth Depth SS (usft) (usft) Name Dip Dip Direction Lithology (I (I 3,972,98 3,819.10 P4 Bi 3,453.71 3,326.10 P3 A4 9,659.35 9,359.10 TY_D4_A 8,721.14 8,437.10 TY_84_So 6,501.91 6,260.10 LB -1 9,841.59 9,541.10 TY—D6 7,833.24 7,566.10 TY_75_8 4,854.56 4,656.10 P6_C2 STORAGE 6,323.52 6,085.10 L_BELUGA 8,186.97 7,913.10 UT_4B 4,920.92 4,719.10 U_BELUGA 4,678.67 4,489.10 P6—CI STORAGE 9,164.57 8,872.10 TY -02 9,754.57 9,454.10 TY_D4_D 7,782.27 7,516.10 UT -1D 7,537.62 7,276.10 TY_72_8 4,108.85 3,948.10 P5133 9,681.43 9,681.43 9,381.10 TY_D4_B 5,571.20 5,347.10 M_BELUGA 6,817.93 6,570.10 LB_2D 8,867.93 8,581.10 TY—B6-2B 9,470.39 9,172.10 TV_D3_A 8,992.30 8,703.10 TY—DI 7,564.12 7,302.10 TY_73_1 6,417.30 6,177.10 LB_1B 7,183.89 6,929.10 LB_4C 5/912019 6:24:06PM Page 7 COMPASS 5000.15 Build 91 HQLLIBURTON Database: NORTH US+CANADA Company: Hiloorp Alaska, LLC Project: Kenai Gas Field Site: KGF 41-7 Pad Well: Plan: KU 24-05B Wellbore: KU 24-05B Design: KU 24-05B wp08 Plan Annotations Measured Vertical Depth Depth (usft) (usft) 318.00 318.00 768.00 766.15 1,219.80 1,205.17 5,111.45 4,900.00 5,388.70 5,168.07 9,461.44 9,163.31 9,834.59 9,534.10 10,384.59 10,084.10 Local Corordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Local Coordinates -NIS +E/ -W (usft) (usft) 0.00 0.00 0.00 35.27 34.67 132.87 630.00 1,200.00 656.67 1,264.49 815.73 2,039.02 823.04 2,074.62 823.04 2,074.62 Halliburton Standard Proposal Report Well Plan: KU 24-05B Plan @ 34.10usft (HEC 169) Plan @ 84.10usft (HEC 169) True Minimum Curvature Comment Start Dir 2-1100': 318' MD, 318'TVD Start Dir 2.5°/100' : 768' MD, 766.15'TVD End Dir : 1219.8' MD, 1205.17' TVD Start Dir 3°/100' : 5111.45' MD, 4900'TVD End Dir : 5388.7' MD, 5168.07' TVD Start Dir Wit 00': 9461.44' MD, 9163.317VD End Dir : 9834.59' MD, 9534.1' TVD Total Depth: 10384.59' MD, 10084.1' TVD 5/912019 6:24:06PM Page 8 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Kenai Gas Field KGF 41-7 Pad Plan: KU 24-05B KU 24-05B KU 24-05B wp08 Sperry Drilling Services Clearance Summary Anticollision Report 09 May, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (HigM1slde Reference) Reference Design: KGF 417 Pad - Plan: KU 2405H -KU 24 -05B -KU 2405B wp08 Well Coordinates: 2,361,491 ]9 N, 275,100.28 E (60. 2T 291 T' N,151.14' 4456" M Datum Height: Plan l@ 84.10ush(HEC 169) Scan Range: Dog to 10,384.59 usfl. Measured Depth. Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation @ 1,000.00 poll Gamete, Scale Factor Applied Version: 5000.15 StAK 91 Scan Type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 10011000 of references Soon Type: 25.00 HALLIBURTON Sperry Drilling Services Hilcorp Alaska, LLC HALLIBURTON Kenai Gas Field Anticollision Report for Plan: KU 24-05B - KU 24-05B wp08 Clo est Approach 30 Frexlmay Scan on Currant Survey Data (KIgholde Reference) Reference Design: KGF 416 Pad -Plan: KU 2445B -KU U45B-KU 2445B a;,08 Scan Range: 0.00 to 10,384.59 usn. Measured Depth. Scan Radius is Unlimited. Clearance Factor citing is Unlimited Max Ellipse Separation is 1,000.00 usR Measured Minimum @Meaeuretl Ellipse siMeasured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Companson Well Name- Wellborn Name- Design push) (usn) (..ft) (pan) usit Kenai Deep Unit 2 KDU 2-KDU 2(21-8)-KDU 2(21-8) 57641 227.73 57641 22690 561.69 31349 Centre Distance Pass - KDU 2-KDU 2(21-8)-KDU 2(21-8) 60000 227.85 600.0 220.78 581.01 32232 Ellgse Separation Pass - KDU2-KDU 2(21 a)-KDU 2(21-8) 1,400.00 256.71 1.400.00 240.71 1,31427 16.040 Clearance Factor Pass KGF 41-7 Pad KBU 11-08Z-KBU II -OU -KBU 11-08Z 392.55 64.97 392.55 61.53 39340 18.871 Denlre Distance Pass - MU 11-08Z - KSU 11-082-KBU 11-08Z 425.00 6540 425.00 61.43 425.80 17,742 Ellipse Separation Pass - KBU 11-002-KBU 11-O8Z-KBU 11-08Z 800.40 84.75 800.00 78.14 798.35 12.025 Clearance Factor Pass - KBU 118X-KBU II -BX -KBU 11-8X 7,061,13 134.80 7,061.13 71.06 7,067,70 2.142 Centre Distance Pass KBU if -8X- KBU 118X. KBU 11-8X 7,150.00 13507 7,150.00 71.40 7,158.36 2.121 Ellipse Separatum Pass- KBU1I-BX-KBU II -BX -KDU 118X 7,175.00 13529 7,17500 71.45 7,180.96 2.119 Clearance Factor Pass- KBU 11-SY-KRU 118Y-KRU 118Y 2,325.00 248.54 2,325.00 227.29 2,326,95 11,694 Clearance Factor Pace - KBU 11 -BY -KBU II-8Y-KBU it -8Y 2,335.52 248.51 2,335.52 227.27 2,336.66 11100 Ellipse Separetion Pass - KBU 31-06X-KBU 31-06X-KBU 31-06% 502.04 'PID8 502.04 27.58 50270 2.671 Centre Distance Pass- KBU 31-06X-KBU 31-06X. KBU 31-06X 52500 44.27 52500 2145 525.33 2.632 Clearer. Factor Pass- KBU 41 -7 -hall 41-7-KBU 41-7 1,416.60 289.26 1.41680 273.06 1.392.46 17.852 Cenlre Distance pass - KBU 41 -7 -Men 41-7. KBU 41-7 1,450.00 289.46 1.450.00 272.85 1,424.02 17.428 Ellipse Separation Paas- KBU41-7-KRU 41-7-KBU 41-7 1,925.0D 330.97 1825.00 309.93 1,87685 15.720 Clearance Factor Pass- KBU 41-7X-KBU 4I-0X-KBU 41-7X 1,447,76 179,16 1,447.76 16827 1,421.95 16.444 Centre Distance Pass - KBU 4I-0X-KRU 4IJX-KBU 414X 1,450.00 179.16 1.450.00 168.25 1.424.04 16421 Ellipse Separation pass - KBU417X-KBU 41-9X-KBU 41-7X 1,525.00 181.07 1,525.00 169.67 1,494.85 15.884 Clearance Factor Pace- KBU 42-7-KBU 42-7-KBU 42-7 1,99683 WAS 11996.83 332.81 2,055.95 23.700 Centre Distance Pass - KBU42-7-KBU 42-7-KBU 42-7 2,02500 347.61 2.025.00 332.71 2,08343 23.327 Ellipse5eparatmn Pass- KBU 42-7-KBU 42-0-KRU 42-7 2,550.00 411.75 21550.00 381.31 2,572.76 20,146 Clea2nce Factor Pass- KBU 42-7-KBU 42-7RD-KBU 42-0RD 1,996.83 WAS 1,996.83 33281 2.055.95 23.700 Cemre Distance Pass - KBU 42-9-KBU 42-7RD-KBU 42-7RD 2,025.00 347.61 2,02500 332.71 2,083.43 23.327 Ellipse SepmaUset Pass - KBU 42-7 - KBU 42-7RD-KBU42-7RD 2,550.00 411.75 2,550.00 391.31 2,572.76 20.146 Clearance Factor Pass - KDU-02 (21-8) - KDU 02(21-8)-KDU 02 (21,8) 1.428,70 114.80 1,42870 92.80 1,406A4 5.203 Centre Distance Pass- 09 May. 2019 - 18.25 Page 2 m6 COMPASS HALLIBURTON I � Hilcorp Alaska, LLC Kenai Gas Field Anticollision Report for Plan: KU 24-05B - KU 24-05B wp08 Closest Approach 3D Proximity sun on Consul Survey Data (HigM1sitle Reference) Reference Design: KGF 41.7 Pad -Plan: KU U458-KU 24-0513-KU 24458 wpOB Sun Range: 0.00 W 10,380.59 rift. Unsecured Depth. Sum Radius is Unlimited. Clearance Fscbr cutoff is Unlimited Max Ellipse Separation Is 1,000.00 can Site Nemo Measured Minimum @Musumd Ellipse ®Measuretl Clearance summary Sued on Com parison Well Name-Wellbore Name-Design Depth Distance Depth Separation Depth Factor Minimum se [ para ion Warning Warning (..ft) daft) fmft) (usft) rift 02(214)-KDU 02(21-8) KDU-02(21-8)-KOU 02(214)-KDU 02(21-8) 1,45000 115.07 1,450.00 92.80 1,426.21 5.167 Ellipse Sepaatlpn Pass- KOU-04-KDL -KDU-Oa 1,4)500 115.]8 1,4]500 93.33 1,449.29 5.157 Clearance Fedor Pass - KDU-04-KDU-04-KDU-04 889.25 22]33 689.25 21639 919.84 20.)]] Canoe Distance Pass- MU-04- KOU-0a NDU-04- 80000 22]3) 900'00 21029 929.51 20.51) Ellipse Separation Pess- 1,075.00 243.00 1,075.00 229.65 1,080.31 19.206 Cleeance Factor Pass- KDU-04-KDU04RD-KDU-04R0 KDU-04-KDU-04RD-KDU-04RD 889.25 227.33 88925 218.39 919.64 20= Centre Distance Pass - KOU-04-KDU-04RD-KDU-04RD 900.00 22).3] 900.00 216.29 929.51 20.517 Ellipse Separation Pass- KDU-IO -KDU Ili -KDU 10 1,0)5.01) 243.00 1,0]5.1%1 228'65 1,060.31 18206 Clamor. Factor PaSs- KDU-IO-KDU 10- KOU10 168.69 16580 168.69 16397 168.89 ]]616 Cadre Distance Pass- NDU-iD -(DU 10 -KDU 10 325.00 166.07 32590 162.91 325.12 52578 Ellipse Sepaatipn Pass- 950.00 234.62 950.00 222.10 944.41 31.221 Clearence Factor Pass - KID 32-0)H-KTU 32-7H-K7U 32-7H KTU32-0]H-KTU 32-7H-KTU 32-)H 1,633,06 367.34 1,633.06 355.46 1,594.05 30.928 Centre Distance Pass- KTU32-WH-KID 32-)H-KTD 32-)H 11650.00 36).38 1,607.00 355.43 11810.96 30.752 Ellipse Separation Pass- KrU 43-06X-KTU e-EX - KrU 434% 2,1]590 402.82 2,175.00 386.46 2,10878 28952 Gleaance Factor Pess- KTU43-O6X-KTU 434%-KTU 435% 300.00 285.fi9 300.00 281.20 316.90 63.696 Carlin Distance Pass- KID 43-06X-KTU 43- 435% 475.00 286.66 47590 26009 491.82 43.544 Ellipse Separation 1,375.00 347.21 1,3)5.00 330.25 1,322.)) 20.479 Ckaance Factor Pa.- KTU 4346%-KTU 43-6XRD-KTU 434XRD UU43-06X-KTU 436XR0-K71.1 43-6XRD 300.00 285.69 300.00 281.20 316.90 63,698 Centre Distance Pass- KTU43-06X-KTU 43-6XRD-KTU 436XRD 475.00 286.68 475.00 280.09 491.82 43.544 Ellipse separation Pass - KTU43-06X-KTU 435XRD2-OU 43.6XRD2 1,375.00 347.21 1,37500 33025 1,322.)) 20479 Clearance Factor Pass - M43-06X-KTU 436XRD2-K 43-6XRD2 300.00 285.69 301).00 281.20 316.90 63.698 Centra DisMnce Pass - KTU 43-06X-KTU 43-6XRD2-KTU 434iXRD2 475.00 286.68 475.00 290.09 49482 4].544 Ellipse SeparationPass- 1,3]5.00 36].21 1,3)5.00 330.25 1,322.)) 204]9 Clearence Factor Pass- KU 11-0-KU 114-KU 11-0 KU 14-05-KU 14-05-KU 1445 1.411.83 55.90 1'411'93 3825 1,3fi2.B5 3.168 Charente Factor Pass- KU 14-1)5-KU 14-05-KU 14-05 301.24 118.39 301.24 114.05 301.6fi 2).2)3 Centre Distance Pass- KU14-5-KU24-05-KU-5 32590 118.41 32500 11398 325:28 26.700 Ellipse Sepaation Pass- KU24-5-KU 24-5-KU 24-5 1,175.00 159.98 1,175.00 150.70 1,197.35 17.245 Clearance Factor Pass- KU 24-5-KU 24-5-KU 245 18.00 200.19 18na 198.13 12.90 43.296 Centre Distance Pass- KU 24-5 - KU 245 KU 245 325.00 202-85 325.00 19740 317.62 43.839 Ellipse Separeion Pass- 1,500.00 30917 1,500.90 291.77 1,381.47 17.211 Clearence Fador Pass - 09 Mag 2019 - 18:25 Pa9e3p/6 COMPASS I HALLIBURTON an) and Surtsey Tool 1800 11530.00 KU 24-058 wp08 � Hileorls Alaska, LLC 2_MWDHFRI*MSeSag 5,962.00 10,384.59 KU 24-058 woos ? MWDaIFR1+M5+Sag Ellipse "mor terms are correlated across survey tool lie -on points. CalculeVA ellipaea in a-Psaceauffaxe moors. Kenai Gas Field Anticollision Report for Plan: KU 24-05B - KU 24 -OSB wp08 Distance Bebmen commas; the straight line distance beNrean wellbore corms. Clearance Factor= Distance BeMreen Profiles / (Dlstano Between Profiles - Ellipse Sepmaton). Closest Approach 3D Proximity Scan on Current SOrvey Data (Nlgbaltle Reference) All stator coordinates were calculated using the Minimum Curvature method. Reference Design: KGF 41-7 Pad - Plan: KU 24 -1158 -KU 24.05B -KU 2d45B wpYB Son Range: 0.00 to 10,384.59 -sn. Measured Depth. Sean Radius Is Unlimited. Clearance Factor cutoff Is Unlimited Max Ellipse Separation Is 1.000.00 usn San Name Measured Minimum Sal easmost Ellipse Consumer! Clearance Summary Based an Depth Well Name - Wellbore Name Design Distance pePiM1 Separation Depth Factor Minimum Separation WarningComparison (..ft) (..ft) (.aft) (-aft) usft KU 245 -KU 24-5RD-KU 2451,0 18.00 KU24-5-KU 24 -SRO -KU 24-5RD 200.19 18.00 198.13 27.90 97.298 Centre Distance Pass- 325.00 KU 245 -KU 24.5RD-KU 24-5RD 202.05 325.00 19JA4 332.fi2 43839 EII'se M Separation Pass- 150gW KU43bA-KU 43- 6A -KU 43-6A 30977 1,50000 291.]] 1,396AJ 17.211 Clearance Factor Pass - 10.00 KU 43EA-KU 43-6A- KU 237.20 18.00 23535 25.55 117.244 Centre Distance Pass- 7500 KU43-6A-KU 43bA-KU 436q 23].53 ]5.00 235.16 8 1.11 10.038 Ellipse Saoaralion Pass- 1.300.00 386.05 1,300.00 368.78 1.161.68 22.359 Clearance Factor Pass- KU 43 -7 -KU 43 -7 -KU 43-7 695.65 KU43-]-KU 43.7 -KU 0-7 43.66 695.65 34.13 718.42 4.581 Centre Davems Pass- 700.00 KU 43 -0 -KU 43 -7 -KU 43-7 43.69 70D.W 34.09 722.52 4.552 Ellipse Separation Pasa- 72500 44.98 72500 35.00 746.03 4.505 Clearance Factor Pa. - Sumeyfoolprogram From To surveylPlan an) and Surtsey Tool 1800 11530.00 KU 24-058 wp08 1,53000 6962.00 KU 24-058 wpO8 2_MWDHFRI*MSeSag 5,962.00 10,384.59 KU 24-058 woos ? MWDaIFR1+M5+Sag Ellipse "mor terms are correlated across survey tool lie -on points. CalculeVA ellipaea in a-Psaceauffaxe moors. Separation is the actual distance between ellipands. Distance Bebmen commas; the straight line distance beNrean wellbore corms. Clearance Factor= Distance BeMreen Profiles / (Dlstano Between Profiles - Ellipse Sepmaton). All stator coordinates were calculated using the Minimum Curvature method. 09 May, 2019 - 18:25 Page 4 care COMPASS MALLLIBURTON aP.m oaen.e Project: Kenai Gas R, - Site: KGF 41-7 Ped Well: Plan: KU 24-058 Wellbore: KU 24-058 Plan: KU 24-058 wp08 Ladder/ S.F. Plots V✓c'w (lea BCNrems: eYn® 1cquZn MEc c[9lrveiu Muw 41opJon leum: Atiia ®�aavaNee EC 1931 0.¢: M19IlSL]TPo:OOU] WWakJ'.ee `h ss,: °epN eo °i9°z°o r' ma .,Is .w93.m mi zone � I'U z.a'sei sL imi:us s°y 9e1M 14'a9aa KU Z4Ms vo091gx 2au591 3J ..,FI rllr leo: KUxwsa NM 192'1 rNAC[0\re"AN ALssh Lica Ul bb.lo L H' v4u1411,9u3 Gv1in UliYuh InnYNh oao ow 9 nsue.z$ 66°zr±s lKiN Isr lrasssxw GLOBAL FILTER APPLIED: All v Psft un fa 200r+ loomo00 of Merenu TVD 7VTes MD Sim I20.00 35.90 Im00 16 O Measured Depth 4.50 —T I I 3.00 Colliston Risk Procedures Req, I I I Collision Avoidance Req. L50 NOGo Zone -Stop Dulling NOERRORS I DD 0 600 1200 1800 2400 30pp 3600 4200 4800 5400 6000 6600 7200 7f )0 8400 9000 9600 10200 10800 11400 Pepzn I From: David Gorm To: Boyer David L (DOA) Cc: Davies Stephen F (DOA) Subject: RE: [EXTERNAL] KU 24-05B Date: Tuesday, May 14, 2019 8:40:17 AM Dave, The only significance of the "B" in the well name was to differentiate the well from the existing well KU 24-05. The team is trying maintain the naming convention based on the bottom location as it corresponds to the proposed well KU 24-05B. Unfortunately the offset well KU 24-05 not in the same quarter section had already been applied the name that would correspond to the currently proposed BHL. Let me know if you any more questions. Thanks, David Gorm K Drilling Engineer (,s q V'uSS KV 0-f —S h 0+ Hilcorp Alaska cJ Cell: 505-215-2819 P, P V 1' I From: Boyer, David L (DOA) [mailto:david.boye2@alaska.gov] Sent: Monday, May 13, 2019 4:59 PM To: David Gorm <dgorm@hilcorp.com> Cc: Davies, Stephen F (DOA) <steve.davies@alaska.gov> Subject: [EXTERNAL] KU 24-05B Hi David, I just began the geologic review for the KU 24-05B grassroots well. We wanted to check in to see if there is any significance to the "B" in the well name? As you know, the "B" suffix is also frequently used for the 2nd sidetrack from a mother wellbore. Thank you, Dave Boyer Senior Geologist AOGCC 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 maybe 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. Transform Points Source coordinate system K r I CafrP State Plane 1927 -Alaska Zone Datum: K(A;Z+--05B NAD 1927- North America Datum of 1927 (Meant Target coordinate system Albers Equal Area (-1K) Datum: NAD 1927 - North America Datum of 1927 (Mean) - - -------- — -_ -- ---- -- -- ----- -- i ype values - into— the spreand or copy and paste columns of data from a spreadsheet using the keyboard shortcuts Ctd+C to ropy and Ctd+V to paste. Then click on the appropriate arrow button to transform the points to the desired coordinate system. e Back finish Cancel Help TRANSMITTAL LETTER CHECKLIST WELL NAME: _ (A , a �t -- 0 5' B / PTD: -;L,�� — Q :7-g L, evelopment Service _ Exploratory _ Stratigraphic Test Non -Conventional FIELD: VCP Vt a t (j a N( 14 POOL: Ty e.9 hp /,.k- G0.S (00 L .ice 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. (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. (Comnanv Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC 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 through 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 V/ (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements 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 da s after com letion, sus ension or abandonment of this well. Revised 2/2015 WELL PERMIT PTD#:2190720 Appr Date DLB 5/14/2019 1 2 13 4 5 6 7 10 11 15 16 17 Initial Well Name: KENA T ONEI( UNIT 24-058 Program _D_EV _ END GeoArea 820 Unit 51120 _ _ On/Off Shore On ............... .... .. Lease number appropriate. NA. Yes Unique well name and number - - _ _ - _ _ - - - Yes Well located in.a defined _pool _ Yes Well located proper distance_ from drilling unit. boundary. _ - . _ - _ Yes Well located proper distance from other wells Yes Sufficient acreage available in drilling unit.. - _ - - Yes If deviated, is wellbore plat included _ - _ Yes Operator only affected party..... _ _ Yes Operator has appropriate_ bond in force _ _ _ _ _ - Yes Permit can be issued without conservation order _ _ Yes Permit can be issued without administrative. approval _ Yes _ Can permit be approved before 15 -day wail.... _ - . _ - _ - _ Yes _ Well located within area and strata authorized by Injection Order # (put 10# in -Comments). (For" NA All wells. within 1(4 -mile area"of review identified (For servicewell only). _ _ _ NA Pre -produced injector duration.of pre -production less than 3 months. (Fpr service well only) " _ NA ---- _-. Nonronven. gas conforms to AS31,05.030(j.1.A),(J,2.A-D)- - - - - - - NA.. . Well bore seg [j Engineering 19 -Conductor string provided " -— - - - - - - Surface casing, protects all known USDWs es ---- — - - - - - - - - - - - - 16 conductor set at 120 ft - 20 . - - - - - - - - - CMT. vol adequate. to circulate"on cenductpr &surf csg _ _ .... _ Yes - _ _ 10 3/4" surface casing will be"set at I= It and fully cemented. - 21 _ .. CMT vol adequate to tie-in long stringzons csg Yes 22 CMT will coyer all known productive horirizons -Yes 7 5/8". intermediate casing will be cemented to the surfcasingshoe. 23 24 _ .. _ _ Casing designs adequate for C, T, B &-permafrost_ _ _ _ _ _Yes.... _ _ _ Yes _ _ - .BTC talcs provided.. Adequate tankage. reserve pit Yes 25 If a re -drill, has. a 10--403 for abandonment been approved . _ rig has steel pits -.Ali waste to be transported to KGF G_& 1- 26 - " Adequate wellbore separation -Yes _ NA_ - 27 27 If d)verter required, does it meet regulations - No issues with collision.. Appr Date 28 _ _ - - _ - Drilling fluid_ program schematic & equip list adequate. 9 P 9 _ _ Yes _ _ 169 n has 16' diverter bne. Layoutma 9-p provided " GLS 5/15/2019 29 - _ _ .. _ _ BOPEs, do they meet regulation Yes - - - Max form pressure =.6353 psi ( 12.0 ppg EMW) will drill prod section with _12.2 ppg mud 30 BOPE.press rating appropriate; test to.(put prig in comments). -Yes _ _ _ . _ . Rig has 11" 5000_ si_BOPE - - - 31 _ _ . _ _ Choke manifold complies w/API RP -53 (May 84), - Yes _ MASP = 3583 psi" ( using alt talc.,. 2/3 gas column.) Will. test ROPE to 4000 psi - - - 32 _ _ - Work will occur without operation shutdown " Yes Yes _ _ _ _ _ - - 33 Is presence of H2S gas probable _ - Sundry required to perforate well. CBL is also required with MIT of IA. - - _ Mechanical condition of wells within AOR verified (For service well only) ..-. _. - " No __. NA.... - - - - _ " _ H2S not expected. - - - - - - - - - - - - 35 Permit Can be issued w/o hydrogen sulfide measures Yes ---__ -Wells Geology 36 Data. presented on potential overpressure zones - " - _ H2S not anticipated based on offset - Appr Date 37 _ _ _ _ _ _ _ - _ _ Seismic analysis" of shallow gas. zones- _ - _ _Yes - - _ _ ..Planned mud weights a - - 9 PPear"adequate to Control the. operator's forecast of most likely pore pressures_ DLB 5/14/2019 38 - .. ........ ... - Seabed condition survey (if Off -shore) _. NA.---- 39 Contact name/ hone for weekly_progress reports [exploratory only].- - - - " - - - - - - - Geologic Commissioner: Engineering Public Date: Commissioner: Date Commissioner Date Using Cement packer for completion. CBL is required to find TOC and IA must be pressure tested and charted. GLS 'Q �l�/n