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Home My WebLink About219-1271. 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: Install Cap String Development Exploratory 3. Address:Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 4,025 feet N/A feet true vertical 2,082 feet N/A feet Effective Depth measured 3,932 feet 950 feet true vertical 2,015 feet 896 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / L-80 4,016' MD 2,075' TVD 950 MD Packers and SSSV (type, measured and true vertical depth)Swell Pkr 896 TVD SSSV - 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: Scott Warner, Operations Engineer 324-594 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: WINJ WAG 946 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 scott.warner@hilcorp.com 907-564-4506 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 2 Size 120' 0 31664 0 500 44 measured TVD 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-127 50-133-20686-00-00 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: ADL0384372 / FEE CIRI Ninilchik Field / Beluga-Tyonek Gas Pool Ninilchik Unit Kalotsa 5 Plugs Junk measured Length Production Liner 4,016' Casing Structural 2,075'4,016' 120'Conductor Surface Intermediate 16" 7-5/8" 120' 1,196' 7,500psi 2,980psi 6,890psi 8,430psi 1,196'1,071' Burst Collapse 1,410psi 4,790psi p k ft t Fra O s 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 3:15 pm, Jan 06, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.01.06 14:45:12 - 09'00' Noel Nocas (4361) BJM 2/4/25 DSR-1/8/25SFD 3/25/2025 RBDMS JSB 011525 Perforate Page 1/1 Well Name: NINU Kalotsa 5 Report Printed: 1/6/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Jobs Actual Start Date:11/12/2024 End Date: Report Number 1 Report Start Date 11/12/2024 Report End Date 11/12/2024 Last 24hr Summary Move Capstring truck from Swanson to Susan Dione Report Number 2 Report Start Date 11/13/2024 Report End Date 11/13/2024 Last 24hr Summary Maint and run through cap string truck. Report Number 3 Report Start Date 12/2/2024 Report End Date 12/2/2024 Last 24hr Summary MIRU Capstring truck. Pull capstring from 2400' MD. RDMO. Report Number 4 Report Start Date 12/3/2024 Report End Date 12/4/2024 Last 24hr Summary PTW/PJSM w/ YJ E-line and Baker tractor crew. MIRU. MU tractor, GPT & JBGR. PT 250 low/2500 high. SITP - 202 psi. RIH to 1650' (80 deg. deviation), begin tractoring to 3100' and free fall to PBTD. Located fluid level at 3630' and tagged PBTD at 3885'. Perforated the BEL_49 (3852'-3857'), BEL_48 (3827'-3833'), BEL_48 (3808'-3814'). Secure well, rig back e-line and flow well. Report Number 5 Report Start Date 12/4/2024 Report End Date 12/5/2024 Last 24hr Summary PTW/PJSM. Perf the BEL 46 (3,679' - 3,689'), BEL 46 (3,662' - 3,672'), and BEL 45 (3,640' - 3,650') with well shut-in. Flow test in-between perf runs. SDFN. Turn well over to Prod Ops to flow overnight. Report Number 6 Report Start Date 12/5/2024 Report End Date 12/6/2024 Last 24hr Summary PTW/PJSM. Perf BEL 44 (3,620' - 3,628'), BEL 44 (3,601' - 3,611'), BEL 42 (3,569' - 3,575') with well shut-in. Flow test in-between perf runs. SDFN. Turn well over to Prod Ops. Report Number 7 Report Start Date 12/6/2024 Report End Date 12/7/2024 Last 24hr Summary PTW/PJSM. RDMO YJ E-line. Re-run cap string to 3,022'. Field: Ninilchik Sundry #: 324-594 State: Alaska Rig/Service:Permit to Drill (PTD) #:219-127Permit to Drill (PTD) #:219-127 Wellbore API/UWI:50-133-20686-00-00 y Perf BEL 44 (3,620' - 3,628'), BEL 44 (3,601' - 3,611'), BEL 42 (3,569' - 3,575') with well shut-in. gp ( g ), g Perforated the BEL_49 (3852'-3857'), BEL_48 (3827'-3833'),g BEL_48 (3808'-3814'). y Perf the BEL 46 (3,679' - 3,689'), BEL 46 (3,662' - 3,672'), and BEL 45 (3,640' - 3,650') Updated by DMA 12-18-24 SCHEMATIC Kalotsa #5 PTD: 219-127 API: 50-133-20686-00-00 PBTD = 3,932’ / TVD = 2,015’ TD = 4,025’ / TVD = 2,082’ RKB to GL = 18’ PERFORATIONS Sand TOP MD BTM MD TOP TVD BTM TVD FT Date Status Beluga 23 3,198’ 3,204’ 1,585’ 1,588’ 6’ 9/25/2021 Open Beluga 25 3,225’ 3,241’ 1,597’ 1,604’ 16’ 9/25/2021 Open Beluga 25 3,250’ 3,257’ 1,608’ 1,611’ 7’ 9/25/2021 Open Beluga 30 3,290’ 3,302’ 1,626’ 1,632’ 12’ 9/25/2021 Open Beluga 37 3,345’ 3,352’ 1,652’ 1,656’ 7’ 9/25/2021 Open Beluga 37 3,377’ 3,386’ 1,668’ 1,673’ 9’ 9/25/2021 Open Beluga 37 3,405’ 3,410’ 1,682’ 1,685’ 5’ 9/24/2021 Open Beluga 38 3,423’ 3,431’ 1,692’ 1,696’ 8’ 9/24/2021 Open Beluga 38 3,438’ 3,446’ 1,700’ 1,704’ 8’ 9/24/2021 Open Beluga 40 3,489’ 3,493’ 1,728’ 1,730’ 4’ 9/24/2021 Open Beluga 41 3,511’ 3,513’ 1,740’ 1,741’ 2’ 9/24/2021 Open Beluga 41 3,516’ 3,519’ 1,743’ 1,745’ 3’ 9/24/2021 Open Beluga 41 3,524’ 3,529’ 1,748’ 1,750’ 5’ 9/24/2021 Open Beluga 41L 3,541’ 3,549’ 1,757’ 1,762’ 8’ 9/24/2021 Open Beluga 42 3,569' 3,575' 1,774' 1,777' 6’ 12/5/2024 Open Beluga 44 3,601' 3,611' 1,793' 1,799' 10’ 12/5/2024 Open Beluga 44 3,620' 3,628' 1,805' 1,809' 8’ 12/5/2024 Open Beluga 45 3,640' 3,650' 1,817' 1,823' 10’ 12/4/2024 Open Beluga 46 3,662' 3,672' 1,831' 1,837' 10’ 12/4/2024 Open Beluga 46 3,679' 3,689' 1,841' 1,848' 10’ 12/4/2024 Open Beluga 47 3,705’ 3,725’ 1,858’ 1,871’ 20’ 10/17/20 Open Beluga 47 3,732’ 3,738’ 1,876’ 1,879’ 6’ 10/17/20 Open Beluga 47 3,760’ 3,776’ 1,894’ 1,905’ 16’ 10/17/20 Open Beluga 47 3,777’ 3,789’ 1,906’ 1,914’ 12’ 10/17/20 Open Beluga 48 3,808' 3,814' 1,927' 1,931' 6’ 12/3/2024 Open Beluga 48 3,827' 3,833' 1,940' 1,944' 6’ 12/3/2024 Open Beluga 49 3,841’ 3,846’ 1,950’ 1,953’ 5’ 10/16/20 Open Beluga 49 3,852 3,857' 1,957' 1,961' 5’ 12/3/2024 Open Beluga 49 3,857’ 3,863’ 1,961’ 1,965’ 6’ 10/16/20 Open Beluga 49 3,874’ 3,880’ 1,973’ 1,977’ 6’ 10/16/20 Open Beluga 50 3,926’ 3,930’ 2,010’ 2,013’ 4’ 10/15/20 Open OPEN HOLE / CEMENT DETAIL 7-5/8" 41 bbls 12ppg lead + 39 bbls 15.8ppg tail of cement in 9-7/8” hole. 38 bbls returned to surface 4-1/2” 84 bbls of Type 1 II lead cmt @ 12 ppg, and 17 bbls of premium G tail cmt @ 15.3 ppg in 6-3/4” hole. 5 bbls lost during cement job. No cement to surface. 27bbls of spacer returned to surface (of 40bbls pumped). Calculating top down, that says cement never made it above 495’ MD. Radial bond tool from 10/14/20 shows ToC at 950’ MD (10 days after CIP) CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 DWC/C 6.875” Surf 1,196’ 4-1/2" Prod Csg 12.6 L-80 DWC/C HT 3.958” Surf 4,016’ 1 16” 7-5/8” 4-1/2” No. Depth ID Item 1 950’ Swell Packer Well Notes: Goes >70° inclination at 1,470’ MD Capillary String (3/8”): Installed 12/6/24 Top Bottom MD 0 3,200’ TVD 0 1,586’ 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): 4,025 N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 7,500psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng scott.warner@hilcorp.com 907-564-4506 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 Scott Warner, 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 ADL0384372 / FEE-CIRI 219-127 50-133-20686-00-00 Hilcorp Alaska, LLC Proposed Pools: 12.6# / L-80 TVD Burst 4,016 8,430psi 1,071 Size 120 1,196 MD See Schematic 2,980psi 6,890psi 120120 1,196 October 25, 2024 4-1/2" 4,016 Perforation Depth MD (ft): 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Ninilchik Unit Kalotsa 5CO 701C Same 2,0754-1/2" ~683 psi 4,016 N/A Length Swell Pkr & N/A 950 (MD) 896 (TVD) & N/A 2,082 3,932 2,015 Ninilchik Beluga-Tyonek Gas 16" 7-5/8" See Schematic m n P s t N 66 Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 7:49 am, Oct 14, 2024 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.10.11 15:17:27 - 08'00' Noel Nocas (4361) 324-594 Perforate BJM 10/22/24 DSR-10/14/24SFD 10/19/2024 10-404 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.10.23 08:27:16 -08'00'10/23/24 RBDMS JSB 102924 Well: Kalotsa 5 Well Name: Kalotsa 5 API Number: 50-133-20686-00-00 Current Status: Gas Producer Permit to Drill Number: 219-127 Regulatory Contact: Donna Ambruz (907) 777-8305 (O) First Call Engineer: Scott Warner (907) 564-4506 (O) (907) 830-8863 (C) Second Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Maximum Expected BHP: 884 psi @ 2010’ TVD Based on 0.44 psi/ft Max. Potential Surface Pressure:683 psi Based on 0.1 psi/ft gas gradient to surface Applicable Frac Gradient: .70 psi/ft using 13.5 ppg EMW FIT at the surface casing shoe Shallowest Allowable Perf TVD: MPSP/(0.70-0.1) = 683 psi / 0.60 = 1138’ TVD (Will not perforate above top of pool or above surface casing shoe) Top of Applicable Gas Pool:2611’ MD/ 1405’ TVD Well Status: Online gas producer flowing at 950 mcfd, 20 bwpd, 42 psi FTP Brief Well Summary Kalotsa 5 was drilled and completed in October 2020, originally completed in the Beluga 47-50 sands. Rate IP’d at 4 mmscfd. In 2021 a cap string was run to help unload water but was pulled a few months after that to allow for perforations in the Beluga 23-41 sands. Rate increased again to ~4 mmscfd and declined to ~1.6 mmscfd by April 2023 and a cap string was run again to help consistently unload water. Rate has continued to decline and has now dropped to ~970 mscfd. The purpose of this work/sundry is to add perforations to the Beluga 23 through Beluga 50 sands to increase production. Notes Regarding Wellbore Condition x Inclination o Max inclination: 85° at 1719’ MD o Max DLS of 9.94°/100’ at 1282’ MD o > 70° inclination starting at 1470’ MD o Sail angle of 78°-85° from 1650’ to 2650’ MD, then rolls over <70° at 2956’ MD x Tags o N/A – last downhole operation outside of capstring work was done in September 2021 when e- coil perforations were completed. No tags were done Procedure: 1. MIRU Cap string truck 2. Pull 3/8” cap string from 2400’ MD 3. RD cap string truck 4. MIRU Eline and Tractor equipment 5. Pressure Test equipment to 250 psi low / 2500 psi high 6. Perforate and test the below sands from bottom up with a tractor due to deviation: (Will not perforate above top of pool or above surface casing shoe) Well: Kalotsa 5 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 Sand Top MD Btm MD Top TVD Btm TVD Interval BEL 23 ±3,205' ±3,218' ±1,588' ±1,594' ±13' BEL 30 ±3,305' ±3,315' ±1,633' ±1,638' ±10' BEL 30 ±3,319' ±3,331' ±1,640' ±1,645' ±12' BEL 37 ±3,384' ±3,394' ±1,672' ±1,677' ±10' BEL 38 ±3,445' ±3,457' ±1,704' ±1,710' ±12' BEL 40 ±3,464' ±3,474' ±1,714' ±1,720' ±10' BEL 41/42 ±3,554' ±3,577' ±1,765' ±1,778' ±23' BEL 43 ±3,582' ±3,593' ±1,781' ±1,788' ±11' BEL 44 ±3,597' ±3,631' ±1,790' ±1,811' ±34' BEL 45 ±3,639' ±3,653' ±1,816' ±1,825' ±14' BEL 46 ±3,658' ±3,675' ±1,828' ±1,839' ±17' BEL 46 ±3,677' ±3,691' ±1,840' ±1,849' ±14' BEL 48 ±3,805' ±3,818' ±1,925' ±1,934' ±13' BEL 48 ±3,823' ±3,835' ±1,937' ±1,946' ±12' BEL 49 ±3,848' ±3,860' ±1,955' ±1,963' ±12' BEL 49 ±3,879' ±3,892' ±1,976' ±1,986' ±13' BEL 50 ±3,898' ±3,908' ±1,990' ±1,997' ±10' BEL 50 ±3,917' ±3,928' ±2,004' ±2,012' ±11' a) Proposed perfs are also shown on the proposed schematic in red font b) Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation c) Use Gamma/CCL to correlate d) Record Tubing pressures before and after each perforating run at 5 min, 10 min, and 15 min intervals post perf shot (If using switched guns, wait 10 min between shots) e) Pending well production, all perf intervals may not be completed f) If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations g) If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations 4. RDMO a) If necessary, re- run cap string to aid with water production if encountered post perforating. Attachments: 1. Current Schematic 2. Proposed Schematic 3. Standard Well Procedure- N2 Operations Updated by DMA 04-25-23 SCHEMATIC Kalotsa #5 PTD: 219-127 API: 50-133-20686-00-00 PBTD = 3,932’ / TVD = 2,015’ TD = 4,025’ / TVD = 2,082’ RKB to GL = 18’ PERFORATIONS Sand TOP MD BTM MD TOP TVD BTM TVD FT Date Status Beluga 23 3,198’ 3,204’ 1,585’ 1,588’ 6’ 9/25/2021 Open Beluga 25 3,225’ 3,241’ 1,597’ 1,604’ 16’ 9/25/2021 Open Beluga 25 3,250’ 3,257’ 1,608’ 1,611’ 7’ 9/25/2021 Open Beluga 30 3,290’ 3,302’ 1,626’ 1,632’ 12’ 9/25/2021 Open Beluga 37 3,345’ 3,352’ 1,652’ 1,656’ 7’ 9/25/2021 Open Beluga 37 3,377’ 3,386’ 1,668’ 1,673’ 9’ 9/25/2021 Open Beluga 37 3,405’ 3,410’ 1,682’ 1,685’ 5’ 9/24/2021 Open Beluga 38 3,423’ 3,431’ 1,692’ 1,696’ 8’ 9/24/2021 Open Beluga 38 3,438’ 3,446’ 1,700’ 1,704’ 8’ 9/24/2021 Open Beluga 40 3,489’ 3,493’ 1,728’ 1,730’ 4’ 9/24/2021 Open Beluga 41 3,511’ 3,513’ 1,740’ 1,741’ 2’ 9/24/2021 Open Beluga 41 3,516’ 3,519’ 1,743’ 1,745’ 3’ 9/24/2021 Open Beluga 41 3,524’ 3,529’ 1,748’ 1,750’ 5’ 9/24/2021 Open Beluga 41L 3,541’ 3,549’ 1,757’ 1,762’ 8’ 9/24/2021 Open Beluga 47 3,705’ 3,725’ 1,858’ 1,871’ 20’ 10/17/20 Open Beluga 47 3,732’ 3,738’ 1,876’ 1,879’ 6’ 10/17/20 Open Beluga 47 3,760’ 3,776’ 1,894’ 1,905’ 16’ 10/17/20 Open Beluga 47 3,777’ 3,789’ 1,906’ 1,914’ 12’ 10/17/20 Open Beluga 49 3,841’ 3,846’ 1,950’ 1,953’ 5’ 10/16/20 Open Beluga 49 3,857’ 3,863’ 1,961’ 1,965’ 6’ 10/16/20 Open Beluga 49 3,874’ 3,880’ 1,973’ 1,977’ 6’ 10/16/20 Open Beluga 50 3,926’ 3,930’ 2,010’ 2,013’ 4’ 10/15/20 Open OPEN HOLE / CEMENT DETAIL 7-5/8" 41 bbls 12ppg lead + 39 bbls 15.8ppg tail of cement in 9-7/8” hole. 38 bbls returned to surface 4-1/2” 84 bbls of Type 1 II lead cmt @ 12 ppg, and 17 bbls of premium G tail cmt @ 15.3 ppg in 6-3/4” hole. 5 bbls lost during cement job. No cement to surface. 27bbls of spacer returned to surface (of 40bbls pumped). Calculating top down, that says cement never made it above 495’ MD. Radial bond tool from 10/14/20 shows ToC at 950’ MD (10 days after CIP) CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 DWC/C 6.875” Surf 1,196’ 4-1/2" Prod Csg 12.6 L-80 DWC/C HT 3.958” Surf 4,016’ 1 16” 7-5/8” 4-1/2” No. Depth ID Item 1 950’ Swell Packer Well Notes: Goes >70° inclination at 1,470’ MD Capillary String (3/8”): Installed 4/16/23 Top Bottom MD 0 2,400’ TVD 0 1,364’ Updated by SRW 10-11-24 PROPOSED Kalotsa #5 PTD: 219-127 API: 50-133-20686-00-00 PBTD = 3,932’ / TVD = 2,015’ TD = 4,025’ / TVD = 2,082’ RKB to GL = 18’ PERFORATIONS Sand TOP MD BTM MD TOP TVD BTM TVD FT Date Status Beluga 23 3,198’ 3,204’ 1,585’ 1,588’ 6’ 9/25/2021 Open Beluga 23 ±3,205' ±3,218' ±1,588' ±1,594' ±13' TBD Proposed Beluga 25 3,225’ 3,241’ 1,597’ 1,604’ 16’ 9/25/2021 Open Beluga 25 3,250’ 3,257’ 1,608’ 1,611’ 7’ 9/25/2021 Open Beluga 30 3,290’ 3,302’ 1,626’ 1,632’ 12’ 9/25/2021 Open Beluga 30 ±3,305' ±3,315' ±1,633' ±1,638' ±10' TBD Proposed Beluga 30 ±3,319' ±3,331' ±1,640' ±1,645' ±12' TBD Proposed Beluga 37 3,345’ 3,352’ 1,652’ 1,656’ 7’ 9/25/2021 Open Beluga 37 3,377’ 3,386’ 1,668’ 1,673’ 9’ 9/25/2021 Open Beluga 37 ±3,384' ±3,394' ±1,672' ±1,677' ±10' TBD Proposed Beluga 37 3,405’ 3,410’ 1,682’ 1,685’ 5’ 9/24/2021 Open Beluga 38 3,423’ 3,431’ 1,692’ 1,696’ 8’ 9/24/2021 Open Beluga 38 3,438’ 3,446’ 1,700’ 1,704’ 8’ 9/24/2021 Open Beluga 38 ±3,445' ±3,457' ±1,704' ±1,710' ±12' TBD Proposed Beluga 40 ±3,464' ±3,474' ±1,714' ±1,720' ±10' TBD Proposed Beluga 40 3,489’ 3,493’ 1,728’ 1,730’ 4’ 9/24/2021 Open Beluga 41 3,511’ 3,513’ 1,740’ 1,741’ 2’ 9/24/2021 Open Beluga 41 3,516’ 3,519’ 1,743’ 1,745’ 3’ 9/24/2021 Open Beluga 41 3,524’ 3,529’ 1,748’ 1,750’ 5’ 9/24/2021 Open Beluga 41L 3,541’ 3,549’ 1,757’ 1,762’ 8’ 9/24/2021 Open Beluga 41/42 ±3,554' ±3,577' ±1,765' ±1,778' ±23' TBD Proposed Beluga 43 ±3,582' ±3,593' ±1,781' ±1,788' ±11' TBD Proposed Beluga 44 ±3,597' ±3,631' ±1,790' ±1,811' ±34' TBD Proposed Beluga 45 ±3,639' ±3,653' ±1,816' ±1,825' ±14' TBD Proposed Beluga 46 ±3,658' ±3,675' ±1,828' ±1,839' ±17' TBD Proposed Beluga 46 ±3,677' ±3,691' ±1,840' ±1,849' ±14' TBD Proposed Beluga 47 3,705’ 3,725’ 1,858’ 1,871’ 20’ 10/17/20 Open Beluga 47 3,732’ 3,738’ 1,876’ 1,879’ 6’ 10/17/20 Open Beluga 47 3,760’ 3,776’ 1,894’ 1,905’ 16’ 10/17/20 Open Beluga 47 3,777’ 3,789’ 1,906’ 1,914’ 12’ 10/17/20 Open Beluga 48 ±3,805' ±3,818' ±1,925' ±1,934' ±13' TBD Proposed Beluga 48 ±3,823' ±3,835' ±1,937' ±1,946' ±12' TBD Proposed Beluga 49 3,841’ 3,846’ 1,950’ 1,953’ 5’ 10/16/20 Open Beluga 49 ±3,848' ±3,860' ±1,955' ±1,963' ±12' TBD Proposed Beluga 49 3,857’ 3,863’ 1,961’ 1,965’ 6’ 10/16/20 Open Beluga 49 ±3,879' ±3,892' ±1,976' ±1,986' ±13' TBD Proposed Beluga 49 3,874’ 3,880’ 1,973’ 1,977’ 6’ 10/16/20 Open Beluga 50 ±3,898' ±3,908' ±1,990' ±1,997' ±10' TBD Proposed Beluga 50 ±3,917' ±3,928' ±2,004' ±2,012' ±11' TBD Proposed Beluga 50 3,926’ 3,930’ 2,010’ 2,013’ 4’ 10/15/20 Open OPEN HOLE / CEMENT DETAIL 7-5/8" 41 bbls 12ppg lead + 39 bbls 15.8ppg tail of cement in 9-7/8” hole. 38 bbls returned to surface 4-1/2” 84 bbls of Type 1 II lead cmt @ 12 ppg, and 17 bbls of premium G tail cmt @ 15.3 ppg in 6-3/4” hole. 5 bbls lost during cement job. No cement to surface. 27bbls of spacer returned to surface (of 40bbls pumped). Calculating top down, that says cement never made it above 495’ MD. Radial bond tool from 10/14/20 shows ToC at 950’ MD (10 days after CIP) CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 DWC/C 6.875” Surf 1,196’ 4-1/2" Prod Csg 12.6 L-80 DWC/C HT 3.958” Surf 4,016’ 1 16” 7-5/8” 4-1/2” No. Depth ID Item 1 950’ Swell Packer Well Notes: Goes >70° inclination at 1,470’ MD Capillary String (3/8”): Installed 4/16/23 Top Bottom MD 0 2,400’ TVD 0 1 364’ 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. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:AOGCC Permitting (CED sponsored) To:Brooks, James S (OGC) Subject:FW: [EXTERNAL] Sundry_Kalotsa 5 322-384 - WITHDRAWAL/CANCEL Date:Friday, December 15, 2023 8:11:59 AM Attachments:Sundry_322-384_070822.pdf FYI: I have noted in 2022-403 Excel log. Grace From: Donna Ambruz <dambruz@hilcorp.com> Sent: Friday, December 15, 2023 8:01 AM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Jacob Flora <Jake.Flora@hilcorp.com> Subject: FW: [EXTERNAL] Sundry_Kalotsa 5 322-384 - WITHDRAWAL/CANCEL Please withdraw/cancel the above-referenced sundry. Thank you. Donna Ambruz Operations/Regulatory Tech KEN Asset Team Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 907.777.8305 - Direct dambruz@hilcorp.com From: Carlisle, Samantha J (OGC) <samantha.carlisle@alaska.gov> Sent: Friday, July 8, 2022 2:43 PM To: Abbie Barker <Abbie.Barker@hilcorp.com>; Carrie Janowski <Carrie.Janowski@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com>; Darci Horner - (C) <dhorner@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com>; Jerimiah Galloway <Jerimiah.Galloway@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Josh Allely - (C) <josh.allely@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com>; Tom Fouts <tfouts@hilcorp.com> Subject: [EXTERNAL] Sundry_Kalotsa 5 322-384 Samantha Carlisle AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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: Install Cap String Development Exploratory 3. Address: Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 4,025 feet N/A feet true vertical 2,082 feet N/A feet Effective Depth measured 3,932 feet 950 feet true vertical 2,015 feet 896 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / L-80 4,016' MD 2,075' TVD 950 MD Packers and SSSV (type, measured and true vertical depth)Swell Pkr 896 TVD SSSV - 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: 7,500psi 2,980psi 6,890psi 8,430psi 1,196' 1,071' Burst Collapse 1,410psi 4,790psi Production Liner 4,016' Casing Structural 2,075'4,016' 120'Conductor Surface Intermediate 16" 7-5/8" 120' 1,196' measured TVD 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-127 50-133-20686-00-00 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: ADL0384372 / FEE CIRI Ninilchik Field / Beluga-Tyonek Gas Pool Ninilchik Unit Kalotsa 5 Plugs Junk measured Length measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 1 Size 120' 1 31093 0 6018 64 Jake Flora, Operations Engineer 323-178 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 1211 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 jake.flora@hilcorp.com 907-777-8442 N/A p k ft t Fra O s 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 Kayla Junke at 1:44 pm, Apr 28, 2023 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361), ou=Users Date: 2023.04.28 13:08:48 -08'00' Noel Nocas (4361) Rig Start Date End Date 4/16/23 4/16/23 04/16/2023 - Sunday PTW, JSA . Move cap string truck from Kalotsa 8 and MIRU on Kalotsa 5. Spool off and cut 450' of 3/8" capillary tubing to remove kinks form spool. Kinks would not pass through injector head. Make up foot valve. Crack pressure 2450 psi. Stab on well. PT stack 250/1500 psi for 5 minutes. RIH to 2800' (target depth 3650') Started stacking weight. Picked up and kept loosing hole. Looks to be deviation and sand. Parked 2400 and lock down unit. Hook up to soap pump skid and start pumping soap at 40 gal/day down cap string. Free up weight 600 lbs. RIH weight 300 lbs. Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Kalotsa 5 50-133-20686-00-00 219-127 Updated by DMA 04-25-23 SCHEMATIC Kalotsa #5 PTD: 219-127 API: 50-133-20686-00-00 PBTD = 3,932 / TVD = 2,015 TD = 4,025 / TVD = 2,082 RKB to GL = 18 PERFORATIONS Sand TOP MD BTM MD TOP TVD BTM TVD FT Date Status Beluga 23 3,198 3,204 1,585 1,588 6 9/25/2021 Open Beluga 25 3,225 3,241 1,597 1,604 16 9/25/2021 Open Beluga 25 3,250 3,257 1,608 1,611 7 9/25/2021 Open Beluga 30 3,290 3,302 1,626 1,632 12 9/25/2021 Open Beluga 37 3,345 3,352 1,652 1,656 7 9/25/2021 Open Beluga 37 3,377 3,386 1,668 1,673 9 9/25/2021 Open Beluga 37 3,405 3,410 1,682 1,685 5 9/24/2021 Open Beluga 38 3,423 3,431 1,692 1,696 8 9/24/2021 Open Beluga 38 3,438 3,446 1,700 1,704 8 9/24/2021 Open Beluga 40 3,489 3,493 1,728 1,730 4 9/24/2021 Open Beluga 41 3,511 3,513 1,740 1,741 2 9/24/2021 Open Beluga 41 3,516 3,519 1,743 1,745 3 9/24/2021 Open Beluga 41 3,524 3,529 1,748 1,750 5 9/24/2021 Open Beluga 41L 3,541 3,549 1,757 1,762 8 9/24/2021 Open Beluga 47 3,705 3,725 1,858 1,871 20 10/17/20 Open Beluga 47 3,732 3,738 1,876 1,879 6 10/17/20 Open Beluga 47 3,760 3,776 1,894 1,905 16 10/17/20 Open Beluga 47 3,777 3,789 1,906 1,914 12 10/17/20 Open Beluga 49 3,841 3,846 1,950 1,953 5 10/16/20 Open Beluga 49 3,857 3,863 1,961 1,965 6 10/16/20 Open Beluga 49 3,874 3,880 1,973 1,977 6 10/16/20 Open Beluga 50 3,926 3,930 2,010 2,013 4 10/15/20 Open OPEN HOLE / CEMENT DETAIL 7-5/8" 41 bbls 12ppg lead + 39 bbls 15.8ppg tail of cement in 9-7/8 hole. 38 bbls returned to surface 4-1/2 84 bbls of Type 1 II lead cmt @ 12 ppg, and 17 bbls of premium G tail cmt @ 15.3 ppg in 6-3/4 hole. 5 bbls lost during cement job. No cement to surface. 27bbls of spacer returned to surface (of 40bbls pumped). Calculating top down, that says cement never made it above 495 MD. Radial bond tool from 10/14/20 shows ToC at 950 MD (10 days after CIP) CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16 Conductor Driven to Set Depth 84 X-56 Weld 15.01 Surf 120' 7-5/8" Surf Csg 29.7 L-80 DWC/C 6.875 Surf 1,196 4-1/2" Prod Csg 12.6 L-80 DWC/C HT 3.958 Surf 4,016 1 16 7-5/8 4-1/2 No. Depth ID Item 1 950 Swell Packer Well Notes: Goes >70° inclination at 1,470 MD Capillary String (3/8): Installed 4/16/23 Top Bottom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ϯ͕ϳϯϴ͛ ϭ͕ϴϳϲ͛ ϭ͕ϴϳϵ͛ ϲ͛ ϭϬͬϭϳͬϮϬ KƉĞŶ ĞůƵŐĂϰϳ ϯ͕ϳϲϬ͛ ϯ͕ϳϳϲ͛ ϭ͕ϴϵϰ͛ ϭ͕ϵϬϱ͛ ϭϲ͛ ϭϬͬϭϳͬϮϬ KƉĞŶ ĞůƵŐĂϰϳ ϯ͕ϳϳϳ͛ ϯ͕ϳϴϵ͛ ϭ͕ϵϬϲ͛ ϭ͕ϵϭϰ͛ ϭϮ͛ ϭϬͬϭϳͬϮϬ KƉĞŶ ĞůƵŐĂϰϵ ϯ͕ϴϰϭ͛ ϯ͕ϴϰϲ͛ ϭ͕ϵϱϬ͛ ϭ͕ϵϱϯ͛ ϱ͛ ϭϬͬϭϲͬϮϬ KƉĞŶ ĞůƵŐĂϰϵ ϯ͕ϴϱϳ͛ ϯ͕ϴϲϯ͛ ϭ͕ϵϲϭ͛ ϭ͕ϵϲϱ͛ ϲ͛ ϭϬͬϭϲͬϮϬ KƉĞŶ ĞůƵŐĂϰϵ ϯ͕ϴϳϰ͛ ϯ͕ϴϴϬ͛ ϭ͕ϵϳϯ͛ ϭ͕ϵϳϳ͛ ϲ͛ ϭϬͬϭϲͬϮϬ KƉĞŶ ĞůƵŐĂϱϬ ϯ͕ϵϮϲ͛ ϯ͕ϵϯϬ͛ Ϯ͕ϬϭϬ͛ Ϯ͕Ϭϭϯ͛ ϰ͛ ϭϬͬϭϱͬϮϬ KƉĞŶ KWE,K>ͬDEdd/> ϳͲϱͬϴΗ ϰϭďďůƐϭϮƉƉŐůĞĂĚнϯϵďďůƐϭϱ͘ϴƉƉŐƚĂŝůŽĨĐĞŵĞŶƚŝŶϵͲϳͬϴ͟ŚŽůĞ͘ϯϴďďůƐƌĞƚƵƌŶĞĚƚŽƐƵƌĨĂĐĞ ϰͲϭͬϮ͟ ϴϰďďůƐŽĨdǇƉĞϭ//ůĞĂĚĐŵƚΛϭϮƉƉŐ͕ĂŶĚϭϳďďůƐŽĨƉƌĞŵŝƵŵ'ƚĂŝůĐŵƚΛϭϱ͘ϯƉƉŐŝŶϲͲϯͬϰ͟ ŚŽůĞ͘ϱďďůƐůŽƐƚĚƵƌŝŶŐĐĞŵĞŶƚũŽď͘EŽĐĞŵĞŶƚƚŽƐƵƌĨĂĐĞ͘ϮϳďďůƐŽĨƐƉĂĐĞƌƌĞƚƵƌŶĞĚƚŽƐƵƌĨĂĐĞ;ŽĨ ϰϬďďůƐƉƵŵƉĞĚͿ͘ĂůĐƵůĂƚŝŶŐƚŽƉĚŽǁŶ͕ƚŚĂƚƐĂǇƐĐĞŵĞŶƚŶĞǀĞƌŵĂĚĞŝƚĂďŽǀĞϰϵϱ͛D͘ZĂĚŝĂů ďŽŶĚƚŽŽůĨƌŽŵϭϬͬϭϰͬϮϬƐŚŽǁƐdŽĂƚϵϱϬ͛D;ϭϬĚĂǇƐĂĨƚĞƌ/WͿ ^/E'd/> ^ŝǌĞ dǇƉĞ tƚ 'ƌĂĚĞ ŽŶŶ͘ / dŽƉ ƚŵ ϭϲ͟ŽŶĚƵĐƚŽƌʹƌŝǀĞŶ ƚŽ^ĞƚĞƉƚŚ ϴϰ yͲϱϲ tĞůĚ ϭϱ͘Ϭϭ͟ ^ƵƌĨ ϭϮϬΖ ϳͲϱͬϴΗ ^ƵƌĨƐŐ Ϯϵ͘ϳ >ͲϴϬ tͬ ϲ͘ϴϳϱ͟ ^ƵƌĨ ϭ͕ϭϵϲ͛ ϰͲϭͬϮΗ WƌŽĚƐŐ ϭϮ͘ϲ >ͲϴϬ tͬ,d ϯ͘ϵϱϴ͟ ^ƵƌĨ ϰ͕Ϭϭϲ͛ ϭ ϭϲ͟ ϳͲϱͬϴ͟ ϰͲϭͬϮ͟ EŽ͘ ĞƉƚŚ / /ƚĞŵ ϭϵϱϬ͛ ^ǁĞůůWĂĐŬĞƌ tĞůůEŽƚĞƐ͗ 'ŽĞƐхϳϬΣŝŶĐůŝŶĂƚŝŽŶĂƚϭ͕ϰϳϬ͛D hƉĚĂƚĞĚďǇ:>>ϬϲͬϮϵͬϮϮ WZKWK^ <ĂůŽƚƐĂηϱ Wd͗ϮϭϵͲϭϮϳ W/͗ϱϬͲϭϯϯͲϮϬϲϴϲͲϬϬͲϬϬ Wdсϯ͕ϵϯϮ͛ͬdsсϮ͕Ϭϭϱ͛ dсϰ͕ϬϮϱ͛ͬdsсϮ͕ϬϴϮ͛ Z<ƚŽ'>сϭϴ͛ WZ&KZd/KE^ ^ĂŶĚ dKWD dDD dKWds dDds &d ĂƚĞ ^ƚĂƚƵƐ ĞůƵŐĂϵͲϮϬ цϮ͕ϲϰϵ цϯ͕ϭϳϯ цϭ͕ϰϭϯ цϭ͕ϱϳϱ цϱϮϰ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ ĞůƵŐĂϮϯ ϯ͕ϭϵϴ͛ ϯ͕ϮϬϰ͛ ϭ͕ϱϴϱ͛ ϭ͕ϱϴϴ͛ ϲ͛ ϵͬϮϱͬϮϬϮϭ KƉĞŶ ĞůƵŐĂϮϱ ϯ͕ϮϮϱ͛ ϯ͕Ϯϰϭ͛ ϭ͕ϱϵϳ͛ ϭ͕ϲϬϰ͛ ϭϲ͛ ϵͬϮϱͬϮϬϮϭ KƉĞŶ ĞůƵŐĂϮϱ ϯ͕ϮϱϬ͛ ϯ͕Ϯϱϳ͛ ϭ͕ϲϬϴ͛ ϭ͕ϲϭϭ͛ ϳ͛ ϵͬϮϱͬϮϬϮϭ KƉĞŶ ĞůƵŐĂϯϬ ϯ͕ϮϵϬ͛ ϯ͕ϯϬϮ͛ ϭ͕ϲϮϲ͛ ϭ͕ϲϯϮ͛ ϭϮ͛ ϵͬϮϱͬϮϬϮϭ KƉĞŶ ĞůƵŐĂϯϳ ϯ͕ϯϰϱ͛ ϯ͕ϯϱϮ͛ ϭ͕ϲϱϮ͛ ϭ͕ϲϱϲ͛ ϳ͛ ϵͬϮϱͬϮϬϮϭ KƉĞŶ ĞůƵŐĂϯϳ ϯ͕ϯϳϳ͛ ϯ͕ϯϴϲ͛ ϭ͕ϲϲϴ͛ ϭ͕ϲϳϯ͛ ϵ͛ ϵͬϮϱͬϮϬϮϭ KƉĞŶ ĞůƵŐĂϯϳ ϯ͕ϰϬϱ͛ ϯ͕ϰϭϬ͛ ϭ͕ϲϴϮ͛ ϭ͕ϲϴϱ͛ ϱ͛ ϵͬϮϰͬϮϬϮϭ KƉĞŶ ĞůƵŐĂϯϴ ϯ͕ϰϮϯ͛ ϯ͕ϰϯϭ͛ ϭ͕ϲϵϮ͛ ϭ͕ϲϵϲ͛ ϴ͛ ϵͬϮϰͬϮϬϮϭ KƉĞŶ ĞůƵŐĂϯϴ ϯ͕ϰϯϴ͛ ϯ͕ϰϰϲ͛ ϭ͕ϳϬϬ͛ ϭ͕ϳϬϰ͛ ϴ͛ ϵͬϮϰͬϮϬϮϭ KƉĞŶ ĞůƵŐĂϰϬ ϯ͕ϰϴϵ͛ ϯ͕ϰϵϯ͛ ϭ͕ϳϮϴ͛ ϭ͕ϳϯϬ͛ ϰ͛ ϵͬϮϰͬϮϬϮϭ KƉĞŶ ĞůƵŐĂϰϭ ϯ͕ϱϭϭ͛ ϯ͕ϱϭϯ͛ ϭ͕ϳϰϬ͛ ϭ͕ϳϰϭ͛ Ϯ͛ ϵͬϮϰͬϮϬϮϭ KƉĞŶ ĞůƵŐĂϰϭ ϯ͕ϱϭϲ͛ ϯ͕ϱϭϵ͛ ϭ͕ϳϰϯ͛ ϭ͕ϳϰϱ͛ ϯ͛ ϵͬϮϰͬϮϬϮϭ KƉĞŶ ĞůƵŐĂϰϭ ϯ͕ϱϮϰ͛ ϯ͕ϱϮϵ͛ ϭ͕ϳϰϴ͛ ϭ͕ϳϱϬ͛ ϱ͛ ϵͬϮϰͬϮϬϮϭ KƉĞŶ ĞůƵŐĂϰϭ> ϯ͕ϱϰϭ͛ ϯ͕ϱϰϵ͛ 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KŶĐĞǇŽƵŚĂǀĞĐŽŶĨŝƌŵĞĚůŝŶĞƐĂƌĞďůĞĚĚŽǁŶ͕ŶŽƚƌĂƉƉĞĚƉƌĞƐƐƵƌĞĞǆŝƐƚƐ͕ĂŶĚŶŽŶŝƚƌŽŐĞŶŚĂƐ ĂĐĐƵŵƵůĂƚĞĚďĞŐŝŶƌŝŐĚŽǁŶŽĨůŝŶĞƐĨƌŽŵƚŚĞEŝƚƌŽŐĞŶWƵŵƉŝŶŐhŶŝƚ͘ ϭϳ͘Ϳ &ŝŶĂůŝǌĞũŽďůŽŐĂŶĚĚŝƐĐƵƐƐŽƉĞƌĂƚŝŽŶƐǁŝƚŚtĞůůƐŝƚĞDĂŶĂŐĞƌ͘ŽĐƵŵĞŶƚĂŶǇůĞƐƐŽŶƐůĞĂƌŶĞĚ ĂŶĚĐŽŶĨŝƌŵĨŝŶĂůƌĂƚĞƐͬƉƌĞƐƐƵƌĞͬǀŽůƵŵĞƐŽĨƚŚĞũŽďĂŶĚƌĞŵĂŝŶŝŶŐŶŝƚƌŽŐĞŶŝŶƚŚĞƚƌĂŶƐƉŽƌƚ͘ ϭϴ͘Ϳ ZDKEŝƚƌŽŐĞŶWƵŵƉŝŶŐhŶŝƚĂŶĚ>ŝƋƵŝĚEŝƚƌŽŐĞŶdƌĂŶƐƉŽƌƚ͘ 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 KALTOSA 5 (PTD 219-127) GPT/Perf 09/24/2021 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 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 4,025 feet N/A feet true vertical 2,082 feet N/A feet Effective Depth measured 3,932 feet 950 feet true vertical 2,015 feet 896 feet Perforation depth Measured depth 3,198 - 3,930 feet True Vertical depth 1,585 - 2,013 feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / L-80 950 (MD) 896 (TVD) 950 (MD) Packers and SSSV (type, measured and true vertical depth)Swell Pkr 896 (TVD) SSSV - N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Contact Name: Contact Email: Authorized Title:Contact Phone: 321-448 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: Authorized Name and Digital Signature with Date: WINJ WAG 962 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 0 162 Ryan Rupert ryan.rupert@hilcorp.com (907) 777-8503Dan Marlowe - Operations Manager measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 083,745 0 68 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 120' 1,196' N/A 7 Structural TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-127 50-133-20686-00-00 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: CO61505 / ADL0384372 Ninilchik Field / Beluga/Tyonek Gas Pool 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Kalotsa 5 Hilcorp Alaska, LLC Other: Patch/N2/CapString measuredPlugs Junk measured N/A Length 120' 1,196' Size Conductor Surface Intermediate 16" 7-5/8" Production Liner 4,016' Casing 120' 1,071' 2,075'4,016'4-1/2"7,500psi 2,980psi 6,890psi 8,430psi Burst Collapse 1,410psi 4,790psi L G Form 10-404 Revised 10/2021 Submit Within 30 days of Operations By Samantha Carlisle at 2:49 pm, Oct 22, 2021 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.10.22 14:34:39 -08'00' Dan Marlowe (1267) RBDMS HEW 10/22/2021 DSR-10/25/21BJM 10/28/21 SFD 10/25/2021 Rig Start Date End Date CTU 9/23/21 Future Daily Operations: Hilcorp Alaska, LLC Weekly Operations Summary API Number Well Permit NumberWell Name Kalotsa 5 50-133-20686-00-00 219-127 09/22/2021 - Wednesday Cap string removed. Full recovery. 09/26/2021 - Sunday Crews arrive on location. PTM, JSA. Check oils and warm up engines. MU and RIH w/1 11/16" GG, 1 11/16" SS and 9' and 7' of 2 7/8" 6spf, 60 degree phasing Razor charges. Log correlation pass and confirm with town team. Perforate BEL_37u from 3377' - 3386' and BEL_34 from 3345' - 3352'. POOH. MU and RIH w/1 11/16" GG, 1 11/16" SS and 12' and 7' of 2 7/8" 6spf, 60 degree phasing Razor charges. Log correlation pass and confirm with town team. Perforate BEL_30 from 3290' - 3302' and BEL_25L from 3250' - 3257'. POOH,MU and RIH w/1 11/16" GG, 1 11/16" SS and 16' and 6' of 2 7/8" 6spf, 60 degree phasing Razor charges. Log correlation pass and confirm with town team. Perforate BEL_25U from 3225' - 3241' and BEL_23 from 3198' - 3204' POOH. RDMO. 09/28/2021 - Tuesday No activity to report. No activity to report. 09/27/2021 - Monday No activity to report. 09/23/2021 - Thursday MIRU CTU 131 - Petrospec e-coil. NU BOPE and complete weekly test. AOGCC witness waived on 9/22/21 by Jim Regg via email. Spot Yellow Jacket wireline unit on location. SDFN with winds gusting to 44 mph. 09/24/2021- Friday Crews arrive on location. PTW and JSA. Continue rigging up. MU and RIH w/8' 2 7/8" 6 spf 60 degree phasing gun. Log, correlate and perforate BEL_41L from 3541' - 3549'. POOH. MU and RIH w/4', 2', 3', 5' 2 7/8" 6 spf 60 degree phasing gun. Log, correlate and perforate BEL_40, BEL_41u, BEL_41mu, BEL_41mL from 3489' - 3493', 3511' - 3513', 3516' - 3519', 3524' - 3529' respectively. POOH,MU and RIH w/5', 8', 8' 2 7/8" 6 spf 60 degree phasing gun. Log, correlate and perforate BEL_37L, BEL_38u, BEL_38L from 3405' - 3410', 3423' - 3431', 3438' - 3446' respectively. POOH. 09/25/2021 - Saturday perforate BEL_41L from 3541' - 3549'. perforate BEL_40, BEL_41u, BEL_41mu, BEL_41mL from 3489' - 3493', 3511' - 3513', 3516' - 3519', 3524' - 3529' r Perforate BEL_37u from 3377' - 3386' and BEL_34 from 3345' - 3352'. perforate BEL_37L, BEL_38u, BEL_38L from 3405' - 3410', 3423' - 3431', 3438' - 3446' r Perforate BEL_25U from 3225' - 3241' and BEL_23 from 3198' - 3204' Perforate BEL_30 from 3290' - 3302' and BEL_25L from 3250' - 3257'. Updated by CRR 10-22-21 SCHEMATIC Kalotsa #5 PTD: 219-127 API: 50-133-20686-00-00 PBTD = 3,932’ / TVD = 2,015’ TD = 4,025’ / TVD = 2,082’ RKB to GL = 18’ PERFORATIONS Sand TOP MD BTM MD TOP TVD BTM TVD FT Date Status Beluga 23 3,198’ 3,204’ 1,585’ 1,588’ 6’ 9/25/2021 Open Beluga 25 3,225’ 3,241’ 1,597’ 1,604’ 16’ 9/25/2021 Open Beluga 25 3,250’ 3,257’ 1,608’ 1,611’ 7’ 9/25/2021 Open Beluga 30 3,290’ 3,302’ 1,626’ 1,632’ 12’ 9/25/2021 Open Beluga 37 3,345’ 3,352’ 1,652’ 1,656’ 7’ 9/25/2021 Open Beluga 37 3,377’ 3,386’ 1,668’ 1,673’ 9’ 9/25/2021 Open Beluga 37 3,405’ 3,410’ 1,682’ 1,685’ 5’ 9/24/2021 Open Beluga 38 3,423’ 3,431’ 1,692’ 1,696’ 8’ 9/24/2021 Open Beluga 38 3,438’ 3,446’ 1,700’ 1,704’ 8’ 9/24/2021 Open Beluga 40 3,489’ 3,493’ 1,728’ 1,730’ 4’ 9/24/2021 Open Beluga 41 3,511’ 3,513’ 1,740’ 1,741’ 2’ 9/24/2021 Open Beluga 41 3,516’ 3,519’ 1,743’ 1,745’ 3’ 9/24/2021 Open Beluga 41 3,524’ 3,529’ 1,748’ 1,750’ 5’ 9/24/2021 Open Beluga 41L 3,541’ 3,549’ 1,757’ 1,762’ 8’ 9/24/2021 Open Beluga 47 3,705’ 3,725’ 1,858’ 1,871’ 20’ 10/17/20 Open Beluga 47 3,732’ 3,738’ 1,876’ 1,879’ 6’ 10/17/20 Open Beluga 47 3,760’ 3,776’ 1,894’ 1,905’ 16’ 10/17/20 Open Beluga 47 3,777’ 3,789’ 1,906’ 1,914’ 12’ 10/17/20 Open Beluga 49 3,841’ 3,846’ 1,950’ 1,953’ 5’ 10/16/20 Open Beluga 49 3,857’ 3,863’ 1,961’ 1,965’ 6’ 10/16/20 Open Beluga 49 3,874’ 3,880’ 1,973’ 1,977’ 6’ 10/16/20 Open Beluga 50 3,926’ 3,930’ 2,010’ 2,013’ 4’ 10/15/20 Open OPEN HOLE / CEMENT DETAIL 7-5/8" 41 bbls 12ppg lead + 39 bbls 15.8ppg tail of cement in 9-7/8” hole. 38 bbls returned to surface 4-1/2” 84 bbls of Type 1 II lead cmt @ 12 ppg, and 17 bbls of premium G tail cmt @ 15.3 ppg in 6-3/4” hole. 5 bbls lost during cement job. No cement to surface. 27bbls of spacer returned to surface (of 40bbls pumped). Calculating top down, that says cement never made it above 495’ MD. Radial bond tool from 10/14/20 shows ToC at 950’ MD (10 days after CIP) CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 DWC/C 6.875” Surf 1,196’ 4-1/2" Prod Csg 12.6 L-80 DWC/C HT 3.958” Surf 4,016’ 1 16” 7-5/8” 4-1/2” No. Depth ID Item 1 950’ Swell Packer Well Notes: Goes >70° inclination at 1,470’ MD Beluga 41 3,511’ 3,513’ 1,740’ 1,741’ 2’ 9/24/2021 Open Beluga 23 3,198’ 3,204’ 1,585’ 1,588’ 6’ 9/25/2021 Open Beluga 25 3,225’ 3,241’ 1,597’ 1,604’ 16’ 9/25/2021 Open Beluga 25 3,250’ 3,257’ 1,608’ 1,611’ 7’ 9/25/2021 Open Beluga 30 3,290’ 3,302’ 1,626’ 1,632’ 12’ 9/25/2021 Open Beluga 37 3,345’ 3,352’ 1,652’ 1,656’ 7’ 9/25/2021 Open Beluga 37 3,377’ 3,386’ 1,668’ 1,673’ 9’ 9/25/2021 Open Beluga 37 3,405’ 3,410’ 1,682’ 1,685’ 5’ 9/24/2021 Open Beluga 38 3,423’ 3,431’ 1,692’ 1,696’ 8’ 9/24/2021 Open Beluga 38 3,438’ 3,446’ 1,700’ 1,704’ 8’ 9/24/2021 Open Beluga 40 3,489’ 3,493’ 1,728’ 1,730’ 4’ 9/24/2021 Open Beluga 41 3,516’ 3,519’ 1,743’ 1,745’ 3’ 9/24/2021 Open Beluga 41 3,524’ 3,529’ 1,748’ 1,750’ 5’ 9/24/2021 Open Beluga 41L 3,541’ 3,549’ 1,757’ 1,762’ 8’ 9/24/2021 Open 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: _Patch/N2/Cap String_ 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 4,025'none Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 7,500psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: 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 2,082'3,932'2,015'~610 psi none Swell Packer; n/a 950' MD / 896' 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 CO61505 / ADL384372 219-127 50-133-20686-00-00 Kalotsa-05 Ninilchik Field; Beluga/Tyonek Gas Pool Length Size CO 701C Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY 12.6# L-80 TVD Burst 950' 8,430psi MD 2,980psi 6,890psi 120' 1,071' 120' 1,196' 2,075'4-1/2" 16" 7-5/8" 120' 1,196' 4,016' Perforation Depth MD (ft): See Attached Schematic 4,016' Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: September 20, 2021 4-1/2" Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 8:09 am, Sep 07, 2021 321-448 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.09.03 13:48:42 -08'00' Taylor Wellman (2143) * SFD 9/7/2021 DSR-9/7/21 *Perforations shallower than the Beluga/Tyonek Gas Pool will require a spacing exception.SFD 9/7/2021 * BOP test to 2500 psi. 10-404 CT X BJM 9/9/21 dts 9/9/2021 JLC 9/10/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.09.10 14:34:46 -08'00' RBDMS HEW 9/13/2021 Well Prognosis Well: Kalotsa-05 Date: 9/3/2021 Well Name:Kalotsa-05 API Number:50-133-20686-00-00 Current Status:Gas Producer Leg:N/A Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:219-127 First Call Engineer:Ryan Rupert (907) 777-8503 (O)(907) 301-1736 (C) Second Call Engineer:Jake Flora (907) 777-8442 (O)(720) 988-5375 (C) Maximum Expected BHP:~ 783 psi @ 1,732’ TVD 0.452 psi/ft gradient to BEL-40. Max. Potential Surface Pressure:~ 610 psi Using Max BHP minus 0.1 psi/ft. gas gradient to surface). BEL-40 pressure defines highest P, as other deeper sands have lower reservoir pressures observed in RFT’s Well Summary Kalotsa-05 is a2020 drill well that came on at >4000mcfd. It has slowly declined to it’s current production of just under 1000mcfd. Given the uphole potential in this well, the below perfs are proposed to increase rate from the well. The perfs will require e-coil operations since the well goes >70 degrees below 1450’ MD. Given how favorably the well responded when the cap string was installed in June-2021, the sundry below includes a provision to reinstall it after perf adds are complete. The purpose of this work is to add perfs to increase production from Kalotsa-05 Notes Regarding Wellbore Condition x Min ID = 3.833” (drift ID of 4-1/2” tubing/liner) x Deviation: o Max = 86 degrees at 1719’ MD o >70 deg from 1450 – 3000’ MD x 6/22/21: 3/8” cap string installed to 3650’ MD with no issues. Production smoothed out afterwards x October-2020 e-coil perf / initial completion o Tagged PBTD at 3931’ CTMD with a 2-7/8” x 4’ perf gun o Longest gun was 20’ and made it down to 3725’ MD Risks x Nitrogen o Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. o Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job) o Ensure all crews are aware of stop work authority Well Prognosis Well: Kalotsa-05 Date: 9/3/2021 Cap String Procedure 1. RU Cap String Truck. 2. Pull 3/8” capillary line from 3650’ MD 3. RD Cap String Truck and turn well over to production. e-Coil Procedure 1. MIRU Petrospec e-coil 2. Perform BOP test to 250psi low / 2500 high (notify AOGCC 24hrs in advance) 3. RU E-Line Data Acquisition Unit 4. MU GPT 5. RIH and log flowing GPT looking for FL. 6. Obtain a light tag of PBTD regardless of FL depth 7. Obtain an upward 30fpm flowing pass from 6750’ – 6350’ (across all perfs). POOH 8. RU perf guns. Likely 2-7/8” – 3-3/8” guns with 4-6 spf 9. RIH and perforate the below intervals per Geo/RE: a. Consult with OE for what WHP’s to use. May be shot while flowing b. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. c.Use Gamma/CCL to correlate. d.Record initial and 5/10/15 minute tubing pressures after firing (rates as well if shooting flowing) e. Consult with RE/Geo between each perf interval: i. Matt Petrowsky (Geo): 814-421-6753 ii. Anthony McConkey (RE): 529-6199 10. Once sufficient production has been added per RE/Geo, RD E-Line Unit and Coiled Tubing Unit and turn well over to production. Well Prognosis Well: Kalotsa-05 Date: 9/3/2021 Sand MD Top MD Bottom TVD Top TVD Bottom Total Footage (MD) BEL_C ±1,154'±1,170'±1,043'±1,054'16' BEL_D ±1,225'±1,241'±1,089'±1,098'16' BEL_1 ±1,310'±1,334'±1,136'±1,148'24' BEL_1A ±1,350'±1,369'±1,156'±1,164'19' BEL_1B ±1,374'±1,383'±1,166'±1,170'9' BEL_2 ±1,404'±1,426'±1,179'±1,188'22' BEL_2 ±1,433'±1,441'±1,190'±1,193'9' BEL_2A ±1,462'±1,521'±1,201'±1,219'59' BEL_5A ±2,013'±2,033'±1,292'±1,295'20' BEL_5A ±2,097'±2,118'±1,307'±1,311'22' BEL_6A ±2,251'±2,327'±1,335'±1,349'76' BEL_7 ±2,413'±2,433'±1,366'±1,370'20' BEL_8 ±2,458'±2,492'±1,375'±1,382'35' BEL_9 ±2,549'±2,565'±1,394'±1,397'16' BEL_9B ±2,642'±2,685'±1,412'±1,421'44' BEL_10 ±2,752'±2,878'±1,437'±1,471'126' BEL_13 ±2,884'±2,937'±1,473'±1,489'54' BEL_15 ±2,957'±2,968'±1,495'±1,499'11' BEL_16 ±3,002'±3,060'±1,511'±1,531'58' BEL_19 ±3,100'±3,128'±1,546'±1,557'29' BEL_20 ±3,154'±3,173'±1,567'±1,575'19' BEL_23 ±3,196'±3,207'±1,584'±1,589'11' BEL_25 ±3,223'±3,242'±1,596'±1,604'19' BEL_25 ±3,249'±3,258'±1,607'±1,611'9' BEL_30 ±3,289'±3,303'±1,626'±1,632'14' BEL_34 ±3,344'±3,353'±1,652'±1,656'9' BEL_37 ±3,374'±3,387'±1,667'±1,673'13' BEL_37 ±3,405'±3,411'±1,682'±1,686'7' BEL_38 ±3,422'±3,432'±1,691'±1,696'10' BEL_38 ±3,438'±3,453'±1,700'±1,708'16' BEL_40 ±3,486'±3,496'±1,726'±1,732'10' BEL_41 ±3,508'±3,529'±1,738'±1,750'22' BEL_41 ±3,541'±3,552'±1,757'±1,764'11' BEL_44 ±3,602'±3,612'±1,794'±1,800'10' BEL_44 ±3,621'±3,628'±1,805'±1,809'7' BEL_45 ±3,641'±3,650'±1,817'±1,823'10' BEL_46 ±3,662'±3,672'±1,830'±1,837'11' BEL_46 ±3,680'±3,689'±1,842'±1,847'9' BEL_48 ±3,808'±3,816'±1,927'±1,932'8' BEL_48 ±3,826'±3,832'±1,939'±1,943'6' Proposed perforations for Beluga C through Beluga 8 have been removed per Ryan Rupert's email dated 9/7/2021. SFD 9/7/2021 Beluga/Tyonek Gas Pool | | V ^ | | Undefined Gas Pool __________ SFD 9/7/2021 Well Prognosis Well: Kalotsa-05 Date: 9/3/2021 Cap String Procedure: 1. RU Cap String Truck. 2. Stab 3/8” capillary line into wellhead pack-off assembly. Make up BHA components. Install pack-off and pressure test against swab valve 250 psi low/3,000 psi high. 3. RIH with 3/8” capillary string to ±25’ MD above top open perf. 4. Install slips and connect tubing to chemical injection pump. 5. Set spool of remaining line near well 6. RD cap string Unit, and turn well over to production. Contingency Ecoil Plug or Patch 1. MIRU Petrospec e-coil 2. Perform BOP test to 250psi low / 3500 high (notify AOGCC 24hrs in advance) 3. RU E-Line Data Acquisition Unit 4. RIH W/ GPT tool and find fluid level 5. 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 6. Once fluid level is below interval to isolate, MU 4-1/2” patch or plug 7. RIH and set plug or patch per OE. 8. RD E-Line Unit and Coiled Tubing Unit and turn well over to production. Attachments: 1. Current schematic 2. Proposed Schematic 3. Standard Well procedure – N2 Operations Updated by CRR 09-03-21 SCHEMATIC Kalotsa #5 PTD: 219-127 API: 50-133-20686-00-00 PBTD = 3,932’ / TVD = 2,015’ TD = 4,025’ / TVD = 2,082’ RKB to GL = 18’ Sand TOP MD BTM MD TOP TVD BTM TVD FT Date Status Beluga 47 3,705’3,725’1,858’1,871’20’10/17/20 Open Beluga 47 3,732’3,738’1,876’1,879’6’10/17/20 Open Beluga 47 3,760’3,776’1,894’1,905’16’10/17/20 Open Beluga 47 3,777’3,789’1,906’1,914’12’10/17/20 Open Beluga 49 3,841’3,846’1,950’1,953’5’10/16/20 Open Beluga 49 3,857’3,863’1,961’1,965’6’10/16/20 Open Beluga 49 3,874’3,880’1,973’1,977’6’10/16/20 Open Beluga 50 3,926’3,930’2,010’2,013’4’10/15/20 Open CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 120' 7-5/8"Surf Csg 29.7 L-80 DWC/C 6.875”Surf 1,196’ 4-1/2"Prod Csg 12.6 L-80 DWC/C HT 3.958”Surf 4,016’ 1 16” 7-5/8” 4-1/2” No.Depth ID Item 1 950’Swell Packer OPEN HOLE / CEMENT DETAIL 7-5/8"41 bbls 12ppg lead + 39 bbls 15.8ppg tail of cement in 9-7/8” hole. 38 bbls returned to surface 4-1/2” 84 bbls of Type 1 II lead cmt @ 12 ppg, and 17 bbls of premium G tail cmt @ 15.3 ppg in 6-3/4” hole.5 bbls lost during cement job. No cement to surface.27bbls of spacer returned to surface (of 40bbls pumped). Calculating top down, that says cement never made it above 495’ MD. Radial bond tool from 10/14/20 shows ToC at 950’ MD (10 days after CIP) Well Notes: Goes >70° inclination at 1,470’ MD Capillary String (3/8”):06-22-21 Top Bottom MD 0 3,650’ TVD 0 1,824’ Updated by CRR 09-03-21 PROPOSED SCHEMATIC Kalotsa #5 PTD: 219-127 API: 50-133-20686-00-00 PBTD = 3,932’ / TVD = 2,015’ TD = 4,025’ / TVD = 2,082’ RKB to GL = 18’ Sand TOP MD BTM MD TOP TVD BTM TVD FT Date Status Perf add per sundry Beluga 47 3,705’3,725’1,858’1,871’20’10/17/20 Open Beluga 47 3,732’3,738’1,876’1,879’6’10/17/20 Open Beluga 47 3,760’3,776’1,894’1,905’16’10/17/20 Open Beluga 47 3,777’3,789’1,906’1,914’12’10/17/20 Open Beluga 49 3,841’3,846’1,950’1,953’5’10/16/20 Open Beluga 49 3,857’3,863’1,961’1,965’6’10/16/20 Open Beluga 49 3,874’3,880’1,973’1,977’6’10/16/20 Open Beluga 50 3,926’3,930’2,010’2,013’4’10/15/20 Open CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 120' 7-5/8"Surf Csg 29.7 L-80 DWC/C 6.875”Surf 1,196’ 4-1/2"Prod Csg 12.6 L-80 DWC/C HT 3.958”Surf 4,016’ 1 16” 7-5/8” 4-1/2” No.Depth ID Item 1 950’Swell Packer OPEN HOLE / CEMENT DETAIL 7-5/8"41 bbls 12ppg lead + 39 bbls 15.8ppg tail of cement in 9-7/8” hole. 38 bbls returned to surface 4-1/2” 84 bbls of Type 1 II lead cmt @ 12 ppg, and 17 bbls of premium G tail cmt @ 15.3 ppg in 6-3/4” hole.5 bbls lost during cement job. No cement to surface.27bbls of spacer returned to surface (of 40bbls pumped). Calculating top down, that says cement never made it above 495’ MD. Radial bond tool from 10/14/20 shows ToC at 950’ MD (10 days after CIP) Well Notes: Goes >70° inclination at 1,470’ MD Capillary String (3/8”):To be re-run Top Bottom MD 0 ±25’ above deepest perf TVD 0 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 Carlisle, Samantha J (CED) From:Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent:Tuesday, September 7, 2021 4:36 PM To:Davies, Stephen F (CED) Cc:McLellan, Bryan J (CED); Donna Ambruz; Taylor Wellman; Matthew Petrowsky; Anthony McConkey; Ryan Rupert Subject:RE: [EXTERNAL] Kalotsa 5 (PTD 219-127, Sundry 321-448) - Questions GoodcatchSteve.HilcorpproposesthatwestrikeoutallsandsfromthesundrystartingwiththeBELͲ8and above.LeaveBELͲ9inscope,andremoveBELͲ8andabove.TheBELͲ9andbelowproposedperfsinthesundryallfall withintheexistingBeluga/TyonekGasPool.Thanks, Ryan Rupert Kenai Ops Engineer (13146) 907-301-1736 (Cell) 907-777-8503 (Office) From:Davies,StephenF(CED)<steve.davies@alaska.gov> Sent:Tuesday,September7,202112:24PM To:RyanRupert<Ryan.Rupert@hilcorp.com> Cc:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov> Subject:[EXTERNAL]Kalotsa5(PTD219Ͳ127,Sundry321Ͳ448)ͲQuestions HiRyan, ConservationOrderNo.701CdefinesthetopoftheNinilchikBeluga/TyonekGasPoolasbeingequivalentto1555’MD (aboutͲ1284’TVDSS)intheKalotsaNo.3well.Statewidespacingregulationswillgovernanyperforationsshallower thantheBeluga/TyonekGasPool. MyquickwelllogcorrelationsforKalotsa3andKalotsa5suggestthetopoftheBeluga/TyonekGasPoolinKalotsa5lies atabout2610’MD(Ͳ1261’TVDSS).WillallperforationsproposedinHilcorp’sSundryApplication321Ͳ448liewithinthe Beluga/TyonekGasPool?Ifnot,areanyotherwellsperforatedabovetheBeluga/TyonekGasPoolwithinthesame governmentalsectionas,orwithin3,000feetof,Kalotsa5?Ifso,anyperforationsinKalotsa5thatlieabovethe Beluga/TyonekGasPoolwillrequireaspacingexception. Thanksandstaysafe, SteveDavies AlaskaOilandGasConservationCommission(AOGCC) CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGasConservationCommission (AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontainconfidentialand/orprivilegedinformation.Theunauthorizedreview,use ordisclosureofsuchinformationmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutfirstsavingorforwarding it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov. From:Davies, Stephen F (CED) To:AOGCC Records (CED sponsored) Subject:FW: [EXTERNAL] Kalotsa 5 (PTD 219-127, Sundry 321-448) - Questions Date:Tuesday, September 7, 2021 4:43:45 PM From: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Tuesday, September 7, 2021 4:36 PM To: Davies, Stephen F (CED) <steve.davies@alaska.gov> Cc: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov>; Donna Ambruz <dambruz@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com>; Matthew Petrowsky <mpetrowsky@hilcorp.com>; Anthony McConkey <amcconkey@hilcorp.com>; Ryan Rupert <Ryan.Rupert@hilcorp.com> Subject: RE: [EXTERNAL] Kalotsa 5 (PTD 219-127, Sundry 321-448) - Questions Good catch Steve. Hilcorp proposes that we strike out all sands from the sundry starting with the BEL-8 and above. Leave BEL-9 in scope, and remove BEL-8 and above. The BEL-9 and below proposed perfs in the sundry all fall within the existing Beluga/Tyonek Gas Pool. Thanks, Ryan Rupert Kenai Ops Engineer (13146) 907-301-1736 (Cell) 907-777-8503 (Office) From: Davies, Stephen F (CED) <steve.davies@alaska.gov> Sent: Tuesday, September 7, 2021 12:24 PM To: Ryan Rupert <Ryan.Rupert@hilcorp.com> Cc: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Subject: [EXTERNAL] Kalotsa 5 (PTD 219-127, Sundry 321-448) - Questions Hi Ryan, Conservation Order No. 701C defines the top of the Ninilchik Beluga/Tyonek Gas Pool as being equivalent to 1555’ MD (about -1284’ TVDSS) in the Kalotsa No. 3 well. Statewide spacing regulations will govern any perforations shallower than the Beluga/Tyonek Gas Pool. My quick well log correlations for Kalotsa 3 and Kalotsa 5 suggest the top of the Beluga/Tyonek Gas Pool in Kalotsa 5 lies at about 2610’ MD (-1261’ TVDSS). Will all perforations proposed in Hilcorp’s Sundry Application 321-448 lie within the Beluga/Tyonek Gas Pool? If not, are any other wells perforated above the Beluga/Tyonek Gas Pool within the same governmental section as, or within 3,000 feet of, Kalotsa 5? If so, any perforations in Kalotsa 5 that lie above the Beluga/Tyonek Gas Pool will require a spacing exception. Thanks and stay safe, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Install Cap String Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 4,025 feet N/A feet true vertical 2,082 feet N/A feet Effective Depth measured 3,932 feet 950 feet true vertical 2,015 feet 896 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / L-80 950' MD 896' TVD Packers and SSSV (type, measured and true vertical depth)Swell Pkr; N/A 950' MD 896' 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 ryan.rupert@hilcorp.com Senior Engineer:Senior Res. Engineer: Burst 2,980psi 8,430psi 120' 1,071'6,890psi Collapse 1,410psi 4,790psi 7,500psi Casing Structural 16" 7-5/8" Length 120' 1,196' 4,016' Conductor Surface Intermediate Production Authorized Signature with date: Authorized Name: 10 Casing Pressure Liner 1,313 0 Representative Daily Average Production or Injection Data 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-266 100 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 10 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-127 50-133-20686-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 1000 Kalotsa 05 N/A CO61505 / ADL384372 Plugs Junk measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Ninilchik Field - Beluga/Tyonek Gas PoolN/A measured TVD Tubing PressureOil-Bbl measured true vertical Packer 4-1/2"4,016'2,075' WINJ WAG 1,110 Water-Bbl MD 120' 1,196' 0 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 9:31 am, Jul 15, 2021 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.07.14 16:59:36 -08'00' Taylor Wellman (2143) DSR-7/15/21 SFD 7/16/2021RBDMS HEW 7/20/2021 BJM 10/12/21 Rig Start Date End Date Cap String 6/22/21 Future 06/22/2021 - Tuesday Install cap string to 3,650' MD. No issues. Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Kalotsa 5 50-133-20686-00-00 219-127 Updated by DMA 06-30-21 SCHEMATIC Ninilchik Unit Kalotsa #5 PTD: 219-127 API: 50-133-20686-00-00 PBTD = 3,932’ / TVD = 2,015’ TD = 4,025’ / TVD = 2,082’ RKB to GL = 18’ Sand TOP MD BTM MD TOP TVD BTM TVD FT Date Status Beluga 47 3,705’ 3,725’ 1,858’ 1,871’ 20’ 10/17/20 Open Beluga 47 3,732’ 3,738’ 1,876’ 1,879’ 6’ 10/17/20 Open Beluga 47 3,760’ 3,776’ 1,894’ 1,905’ 16’ 10/17/20 Open Beluga 47 3,777’ 3,789’ 1,906’ 1,914’ 12’ 10/17/20 Open Beluga 49 3,841’ 3,846’ 1,950’ 1,953’ 5’ 10/16/20 Open Beluga 49 3,857’ 3,863’ 1,961’ 1,965’ 6’ 10/16/20 Open Beluga 49 3,874’ 3,880’ 1,973’ 1,977’ 6’ 10/16/20 Open Beluga 50 3,926’ 3,930’ 2,010’ 2,013’ 4’ 10/15/20 Open CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 DWC/C 6.875” Surf 1,196’ 4-1/2" Prod Csg 12.6 L-80 DWC/C HT 3.958” Surf 4,016’ 1 16” 7-5/8” 4-1/2” No. Depth ID Item 1 950’ Swell Packer OPEN HOLE / CEMENT DETAIL 7-5/8" 41 bbls 12ppg lead + 39 bbls 15.8ppg tail of cement in 9-7/8” hole. 38 bbls returned to surface 4-1/2” 84 bbls of Type 1 II lead cmt @ 12 ppg, and 17 bbls of premium G tail cmt @ 15.3 ppg in 6-3/4” hole. 5 bbls lost during cement job. No cement to surface. 27bbls of spacer returned to surface (of 40bbls pumped). Calculating top down, that says cement never made it above 495’ MD. Radial bond tool from 10/14/20 shows ToC at 950’ MD (10 days after CIP) Well Notes: Goes >70° inclination at 1,470’ MD Capillary String (3/8”): 06-22-21 Top Bottom MD 0 3,650’ TVD 0 1,824’ 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: ____Cap string______ 2. Operator Name:4. Current Well Class:5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6.API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 4,025'none Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 7,500psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: 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 2,082'3,932'2,015'~705 psi none Swell Packer; n/a 950' MD / 896' 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 CO61505 / ADL384372 219-127 50-133-20686-00-00 Kalotsa-05 Ninilchik Field; Beluga/Tyonek Gas Pool Length Size CO 701C Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY 12.6# L-80 TVD Burst 950' 8,430psi MD 2,980psi 6,890psi 120' 1,071' 120' 1,196' 2,075'4-1/2" 16" 7-5/8" 120' 1,196' 4,016' Perforation Depth MD (ft): See Attached Schematic 4,016' 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: June 10, 2021 4-1/2" 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 8:00 am, Jun 01, 2021 321-266 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.05.28 14:06:03 -08'00' Taylor Wellman (2143) 10-404X DLB 06/01/2021 DSR-6/1/21BJM 6/11/21 dts 6/14/2021 JLC 6/14/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.06.14 11:07:27 -08'00' RBDMS HEW 6/16/2021 Cap String Well: Kalotsa-05 Date: 5/26/2021 Well Name:Kalotsa-05 API Number:50-133-20686-00-00 Current Status:Producing Gas Well Permit to Drill Number:219-127 Regulatory Contact:Donna Ambruz (907) 777-8305 (O) First Call Engineer:Ryan Rupert (907) 777-8503 (O)(907) 301-1736 (M) Second Call Engineer:Ted Kramer (907) 777-8420 (O)(985) 867-0665 (M) Maximum Expected BHP:~ 906 psi @ 2013’ TVD (Based on a 0.45 psi/ft. gradient) Max. Potential Surface Pressure:~ 705 psi (Using Max BHP minus 0.1 psi/ft. gas gradient to surface). Brief Well Summary Kalotsa-05 was D&C in October-2020. It came on at 4MMcfd+ and has steadily declined since then. The well is now at ~1.2MMcfd, and is requiring multiple soap sticks each day. The purpose of this work/sundry is to install a Capillary String in the well to allow for soap to be injected to help unload water. Notes Regarding Wellbore Condition x Inclination o Well goes > 70deg inclination at ~1470’ MD o Gets up to 85 degrees at 1719’ MD, and then sails at 80 degrees until 2650’ MD and then rolls over to and approaches 43 degrees at PBTD x Drifts o E-coil made it to 3725’ MD with a 20’ x 2-7/8” perf gun and logging sub o No wireline drifts in the well’s short history Procedure: 1. RU Cap String Truck. 2. Stab 3/8” capillary line into wellhead pack-off assembly. Make up BHA components. Install pack-off and pressure test against swab valve 250 psi low/3,000 psi high. 3. RIH with 3/8” capillary string to ±3650’ MD. a. Deviation will very likely stop us shallow of target depth b. Set cap string as deep as practical 4. Install slips and connect tubing to chemical injection pump. 5. Set spool of remaining line near well 6. RD cap string Unit, and turn well over to production. Attachments: 1. Proposed Schematic Updated by CRR 5-26-21 PROPOSED SCHEMATIC Ninilchik Unit Kalotsa #5 PTD:219-127 API: 50-133-20686-00-00 PBTD = 3,932’ / TVD = 2,015’ TD = 4,025’ / TVD = 2,082’ RKB to GL = 18’ Sand TOP MD BTM MD TOP TVD BTM TVD FT Date Status Beluga 47 3,705’3,725’1,858’1,871’20’10/17/20 Open Beluga 47 3,732’3,738’1,876’1,879’6’10/17/20 Open Beluga 47 3,760’3,776’1,894’1,905’16’10/17/20 Open Beluga 47 3,777’3,789’1,906’1,914’12’10/17/20 Open Beluga 49 3,841’3,846’1,950’1,953’5’10/16/20 Open Beluga 49 3,857’3,863’1,961’1,965’6’10/16/20 Open Beluga 49 3,874’3,880’1,973’1,977’6’10/16/20 Open Beluga 50 3,926’3,930’2,010’2,013’4’10/15/20 Open CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 120' 7-5/8"Surf Csg 29.7 L-80 DWC/C 6.875”Surf 1,196’ 4-1/2"Prod Csg 12.6 L-80 DWC/C HT 3.958”Surf 4,016’ 1 16” 7-5/8” 4-1/2” No.Depth ID Item 1 950’Swell Packer OPEN HOLE / CEMENT DETAIL 7-5/8"41 bbls 12ppg lead + 39 bbls 15.8ppg tail of cement in 9-7/8” hole. 38 bbls returned to surface 4-1/2” 84 bbls of Type 1 II lead cmt @ 12 ppg, and 17 bbls of premium G tail cmt @ 15.3 ppg in 6-3/4” hole.5 bbls lost during cement job. No cement to surface.27bbls of spacer returned to surface (of 40bbls pumped). Calculating top down, that says cement never made it above 495’ MD. 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ressure1-IPR PressureVLP Pressure, IPR Pressure (psig)690680670660650640630620610600590580570560550540530520510500490480470460450440430420410400390380370360350340330320310300290280270260250240230220210200190180170160150140130120110100908070605040302010Gas Rate (MMscf/day)543210 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20686-00-00Well Name/No. NINILCHIK UNIT KALOTSA 5Completion Status1-GASCompletion Date10/18/2020Permit to Drill2191270Operator Hilcorp Alaska, LLCMD4025TVD2082Current Status1-GAS12/16/2020UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:Geotap, Mudlog, MWD/LWD Logs, CBL 10-14-20NoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF10/12/202011 4075 Electronic Data Set, Filename: Kalotsa 5 LAS.las34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 AM Reports.pdf34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 Final Well Report.pdf34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 Drilling Dynamics Log MD 2in.pdf34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 Drilling Dynamics Log MD 5in.pdf34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 Drilling Dynamics Log TVD 2in.pdf34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 Drilling Dynamics Log TVD 5in.pdf34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 Formation Log MD 2in.pdf34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 Formation Log MD 5in.pdf34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 Formation Log TVD 2in.pdf34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 Formation Log TVD 5in.pdf34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 Gas Ratio Log MD 2in.pdf34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 Gas Ratio Log MD 5in.pdf34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 Gas Ratio Log TVD 2in.pdf34071EDDigital DataWednesday, December 16, 2020AOGCCPage 1 of 5Supplied byOpSupplied byOpKalotsa 5 LAS.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20686-00-00Well Name/No. NINILCHIK UNIT KALOTSA 5Completion Status1-GASCompletion Date10/18/2020Permit to Drill2191270Operator Hilcorp Alaska, LLCMD4025TVD2082Current Status1-GAS12/16/2020UICNoDF10/12/2020 Electronic File: Kalotsa 5 Gas Ratio Log TVD 5in.pdf34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 LWD Combo Log MD 2in.pdf34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 LWD Combo Log MD 5in.pdf34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 LWD Combo Log TVD 2in.pdf34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 LWD Combo Log TVD 5in.pdf34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 Drilling Dynamics Log MD 2in.tif34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 Drilling Dynamics Log MD 5in.tif34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 Drilling Dynamics Log TVD 2in.tif34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 Drilling Dynamics Log TVD 5in.tif34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 Formation Log MD 2in.tif34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 Formation Log MD 5in.tif34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 Formation Log TVD 2in.tif34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 Formation Log TVD 5in.tif34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 Gas Ratio Log MD 2in.tif34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 Gas Ratio Log MD 5in.tif34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 Gas Ratio Log TVD 2in.tif34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 Gas Ratio Log TVD 5in.tif34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 LWD Combo Log MD 2in.tif34071EDDigital DataWednesday, December 16, 2020AOGCCPage 2 of 5 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20686-00-00Well Name/No. NINILCHIK UNIT KALOTSA 5Completion Status1-GASCompletion Date10/18/2020Permit to Drill2191270Operator Hilcorp Alaska, LLCMD4025TVD2082Current Status1-GAS12/16/2020UICNoDF10/12/2020 Electronic File: Kalotsa 5 LWD Combo Log MD 5in.tif34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 LWD Combo Log TVD 2in.tif34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 LWD Combo Log TVD 5in.tif34071EDDigital DataDF10/12/2020 Electronic File: DbRaw.dbf34071EDDigital DataDF10/12/2020 Electronic File: DbRaw.mdx34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa5.dbf34071EDDigital DataDF10/12/2020 Electronic File: kalotsa5.hdr34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa5.mdx34071EDDigital DataDF10/12/2020 Electronic File: kalotsa5r.dbf34071EDDigital DataDF10/12/2020 Electronic File: kalotsa5r.mdx34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa5_SCL.DBF34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa5_SCL.MDX34071EDDigital DataDF10/12/2020 Electronic File: KALOTSA5_tvd.dbf34071EDDigital DataDF10/12/2020 Electronic File: KALOTSA5_tvd.mdx34071EDDigital DataDF10/12/2020 Electronic File: Kalotsa 5 Gas Show Reports.pdf34071EDDigital Data0 0 2191270 NINILCHIK UNIT KALOTSA 5 LOG HEADERS34071LogLog Header ScansDF10/30/202074 4025 Electronic Data Set, Filename: Kalotsa 5 LWD Final.las34145EDDigital DataDF10/30/2020 Electronic File: Kalotsa 5 Geo-Tap Pressure Tests.cgm34145EDDigital DataDF10/30/2020 Electronic File: Kalotsa 5 LWD Final MD.cgm34145EDDigital DataDF10/30/2020 Electronic File: Kalotsa 5 LWD Final TVD.cgm34145EDDigital DataDF10/30/2020 Electronic File: Kalotsa 5_Definitive Survey Report.pdf34145EDDigital DataDF10/30/2020 Electronic File: Kalotsa 5_Definitive Surveys.xlsx34145EDDigital DataDF10/30/2020 Electronic File: Kalotsa 5_DSR.txt34145EDDigital DataDF10/30/2020 Electronic File: Kalotsa 5_GIS.txt34145EDDigital DataDF10/30/2020 Electronic File: Kalotsa 5_Plan.pdf34145EDDigital DataWednesday, December 16, 2020AOGCCPage 3 of 5Kalotsa 5 LWD Final.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20686-00-00Well Name/No. NINILCHIK UNIT KALOTSA 5Completion Status1-GASCompletion Date10/18/2020Permit to Drill2191270Operator Hilcorp Alaska, LLCMD4025TVD2082Current Status1-GAS12/16/2020UICNoDF10/30/2020 Electronic File: Kalotsa 5_VSec.pdf34145EDDigital DataDF10/30/2020 Electronic File: Kalotsa 5 Geo-Tap Pressure Tests.emf34145EDDigital DataDF10/30/2020 Electronic File: Kalotsa 5 LWD Final MD.emf34145EDDigital DataDF10/30/2020 Electronic File: Kalotsa 5 LWD Final TVD.emf34145EDDigital DataDF10/30/2020 Electronic File: Kalotsa 5 Geo-Tap Pressure Tests.pdf34145EDDigital DataDF10/30/2020 Electronic File: Kalotsa 5 GeoTap Report - Final - All Pretests.pdf34145EDDigital DataDF10/30/2020 Electronic File: Kalotsa 5 LWD Final MD.pdf34145EDDigital DataDF10/30/2020 Electronic File: Kalotsa 5 LWD Final TVD.pdf34145EDDigital DataDF10/30/2020 Electronic File: Kalotsa 5 Geo-Tap Pressure Tests.tif34145EDDigital DataDF10/30/2020 Electronic File: Kalotsa 5 LWD Final MD.tif34145EDDigital DataDF10/30/2020 Electronic File: Kalotsa 5 LWD Final TVD.tif34145EDDigital Data0 0 2191270 NINILCHIK UNIT KALOTSA 5 LOG HEADERS34145LogLog Header ScansDF11/16/20203938 695 Electronic Data Set, Filename: KALOTSA-5_RBT_14OCT20_FieldData.las34265EDDigital DataDF11/16/2020695 3938 Electronic Data Set, Filename: KALOTSA-5_RBT_14OCT20_ProcessedLog-V1.las34265EDDigital DataDF11/16/2020 Electronic File: KALOTSA-5_RBT_14OCT20.pdf34265EDDigital DataDF11/16/2020 Electronic File: KALOTSA-5_RBT_14OCT20_FieldData.dlis34265EDDigital DataDF11/16/2020 Electronic File: KALOTSA-5_RBT_14OCT20_img.tiff34265EDDigital DataDF11/16/2020 Electronic File: KALOTSA-5_RBT_14OCT20_ProcessedLog-V1.dlis34265EDDigital DataDF11/16/2020 Electronic File: KALOTSA-5_RBT_14OCT20_ProcessedLog-V1.pdf34265EDDigital DataDF11/16/2020 Electronic File: KALOTSA-5_RBT_14OCT20_ProcessedLog-V1.tif34265EDDigital Data0 0 2191270 NINILCHIK UNIT KALOTSA 5 LOG HEADERS34265LogLog Header ScansWednesday, December 16, 2020AOGCCPage 4 of 5 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20686-00-00Well Name/No. NINILCHIK UNIT KALOTSA 5Completion Status1-GASCompletion Date10/18/2020Permit to Drill2191270Operator Hilcorp Alaska, LLCMD4025TVD2082Current Status1-GAS12/16/2020UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Compliance Reviewed By:Date:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:10/18/2020Release Date:9/26/201910/26/20201200 402521766CuttingsWednesday, December 16, 2020AOGCCPage 5 of 5M. Guhl12/16/2020 David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-5256 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: Date: 11/16/2020 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL KALOTSA 5 (PTD 219-127) Radial Bond Tool 10/14/2020 Please include current contact information if different from above. Received by the AOGCC 11/16/2020 PTD: 2191270 E-Set: 34265 Abby Bell 11/16/2020 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): GL: 126.5' BF:126.5' Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 (ft MSL) 22. Logs Obtained: 23. BOTTOM 16" X-56 120' 7-5/8" L-80 1,070' 4-1/2" L-80 2,077' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, TUBING RECORD N/AN/A SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): L - 205 sx / T - 75 sx Conductor Surface 1,196' L - 100 sx / T - 210 sx Driven STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 10/18/2020 2120' FSL, 407' FWL, Sec 7, T1S, R13W, SM, AK 2174' FNL, 2411' FEL, Sec 12, T1S, R14W, SM, AK 219-127 / 320-425 Ninilchik Field / Beluga/Tyonek Gas Pool 144.5' 3,932' MD / 2,015' TVD HOLE SIZE AMOUNT PULLED 50-133-20686-00-00 Kalotsa 5 209803 2233395 2332' FNL, 2244' FEL, Sec 12, T1S, R14W, SM, AK CEMENTING RECORD 2234201 SETTING DEPTH TVD 2234363 BOTTOM TOP 6-3/4" 38 bbls Surface 9-7/8"Surface CASING WT. PER FT.GRADE 207174 207010 TOP SETTING DEPTH MD Surface Per 20 AAC 25.283 (i)(2) attach electronic information 12.6# Surface DEPTH SET (MD) 950' MD / 899' TVD PACKER SET (MD/TVD) 84# 29.7# 120' Surface 4,016' Gas-Oil Ratio:Choke Size:Water-Bbl: PRODUCTION TEST 10/17/2020 Date of Test: 0 10/22/2020 24 Flow Tubing 0 4131 Oil-Bbl: 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 N/A4131 Flowing *** Please see attached schematic for perforation detail *** Casing run on 10/2/20 0 Geotap, Mudlog, MWD/LWD Logs, CBL 10-14-20 Sr Res EngSr Pet GeoSr Pet Eng N/A N/A Oil-Bbl: Water-Bbl: 00N/A September 29, 2020 September 24, 2020 C061505 / ADL384372 N/A N/A N/AN/A N/A 4,025' MD / 2,082' TVD WINJ SPLUG Other Abandoned Suspended Stratigraphic Test No No (attached) No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment By Samantha Carlisle at 4:11 pm, Nov 04, 2020 RBDMS HEW 11/5/2020 Completion Date 10/18/2020 HEW 187 37 G DSR-11/5/2020 4131 SFD 11/5/2020 Note : all completion operations done using Petrospec E-coil. gs cement packer completion gls 12/15/20 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD N/A N/A Top of Productive Interval Beluga 47 3,705' 1,858' 517' 507' 742' 719' 1020' 948' 1143' 1036' 3,690' 1849' 3,835' 1946' 3,896' 1989' Beluga 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Cody Dinger Contact Email:cdinger@hilcorp.com Authorized Contact Phone: 777-8389 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: FORMATION TESTS Permafrost - Top St 1 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. 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. If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. Authorized Name: Monty Myers Authorized Title: Drilling Manager Beluga 49 Beluga 50 Permafrost - Base 29. GEOLOGIC MARKERS (List all formations and markers encountered): Yes No Well tested? Yes No 28. CORE DATA If yes, list intervals and formations tested, briefly summarizing test results. Attach separate pages to this form, if needed, and submit detailed test information, including reports, per 20 AAC 25.071. NAME Beluga 47 ST 4 Beluga A Formation at total depth: Beluga C Wellbore Schemaitc, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt reports. Signature w/Date: 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. INSTRUCTIONS Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. TPI (Top of Producing Interval). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment, whichever occurs first. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). No NoSidewall Cores: Yes No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2020.11.04 15:39:05 -09'00' Monty M Myers :LQVWRQ+XJK(&(' &ƌŽŵ͗ŽĚǇŝŶŐĞƌфĐĚŝŶŐĞƌΛŚŝůĐŽƌƉ͘ĐŽŵх ^ĞŶƚ͗dŚƵƌƐĚĂǇ͕EŽǀĞŵďĞƌϱ͕ϮϬϮϬϭϬ͗ϯϲD dŽ͗tŝŶƐƚŽŶ͕,ƵŐŚ;ͿфŚƵŐŚ͘ǁŝŶƐƚŽŶΛĂůĂƐŬĂ͘ŐŽǀх ^ƵďũĞĐƚ͗Z͗΀ydZE>΁<ĂůŽƐƚĂϱ͕ϭϬͲϰϬϳ &ŽƌƚŚĂƚƉĂƌƚŝĐƵůĂƌƚĞƐƚŝƚƐŚŽǁĞĚϬdďŐͬƐŐƉƌĞƐƐƵƌĞƐ͘ ,ŽǁĞǀĞƌ͕ŝƚĚŽĞƐĂƉƉĞĂƌƚŽďĞƐŚŽǁŝŶŐƐŽŵĞĐƵƌƌĞŶƚůǇʹǁĞĐĂŶƐŚŽǁĂƚďŐƉƌĞƐƐƵƌĞŽĨϭϴϳƉƐŝĂŶĚĂĐƐŐƉƌĞƐƐƵƌĞŽĨϯϳ ƉƐŝ͘dŚĂƚŝƐĂŵŽƌĞĂĐĐƵƌĂƚĞƉŽƌƚƌĂǇĂůŽĨĨƵƚƵƌĞƉƌĞƐƐƵƌĞƐ͘ dŚĂŶŬƐ͊ ŽĚǇ &ƌŽŵ͗tŝŶƐƚŽŶ͕,ƵŐŚ;Ϳ΀ŵĂŝůƚŽ͗ŚƵŐŚ͘ǁŝŶƐƚŽŶΛĂůĂƐŬĂ͘ŐŽǀ΁ ^ĞŶƚ͗dŚƵƌƐĚĂǇ͕EŽǀĞŵďĞƌϱ͕ϮϬϮϬϭϬ͗ϮϳD dŽ͗ŽĚǇŝŶŐĞƌфĐĚŝŶŐĞƌΛŚŝůĐŽƌƉ͘ĐŽŵх ^ƵďũĞĐƚ͗΀ydZE>΁<ĂůŽƐƚĂϱ͕ϭϬͲϰϬϳ ,ŝŽĚǇ͕ /͛ŵƉƌŽĐĞƐƐŝŶŐĂŶŽƚŚĞƌϭϬͲϰϬϳ;<ĂůŽƐƚĂηϱWdϮϭϵͲϭϮϳͿĂŶĚǁĂŶƚĞĚƚŽĚŽƵďůĞĐŚĞĐŬĂƉŝĞĐĞŽĨŝŶĨŽƌŵĂƚŝŽŶ͘/ŶďŽǆϮϳ ƚŚĞƚƵďŝŶŐƉƌĞƐƐƵƌĞŝƐEͬĂŶĚƚŚĞĐĂƐŝŶŐƉƌĞƐƐƵƌĞŝƐϬ͘^ŚŽƵůĚŽŶĞŽĨƚŚŽƐĞƉƌĞƐƐƵƌĞƐďĞƉŽƐŝƚŝǀĞƐŝŶĐĞƚŚĞƌĞǁĂƐ ƉƌŽĚƵĐƚŝŽŶĚƵƌŝŶŐƚŚĞƚĞƐƚ͍dŚĂŶŬƐ ,ƵĞǇtŝŶƐƚŽŶ ^ƚĂƚŝƐƚŝĐĂůdĞĐŚŶŝĐŝĂŶ ůĂƐŬĂKŝůĂŶĚ'ĂƐŽŶƐĞƌǀĂƚŝŽŶŽŵŵŝƐƐŝŽŶ ŚƵŐŚ͘ǁŝŶƐƚŽŶΛĂůĂƐŬĂ͘ŐŽǀ ϵϬϳͲϳϵϯͲϭϮϰϭ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ʹǁĞĐĂŶƐŚŽǁĂƚďŐƉƌĞƐƐƵƌĞŽĨϭϴϳƉƐŝĂŶĚĂĐƐŐƉƌĞƐƐƵƌĞŽĨϯϳ ƉƐŝ͘dŚĂƚŝƐĂŵŽƌĞĂĐĐƵƌĂƚĞƉŽƌƚƌĂǇĂůŽĨĨƵƚƵƌĞƉƌĞƐƐƵƌĞƐ͘ Updated by CJD 10-28-20 SCHEMATIC Ninilchik Unit Kalotsa #5 PTD: 219-127 API: 50-133-20686-00-00 PBTD = 3,932’ / TVD = 2,015’ TD = 4,025’ / TVD = 2,082’ RKB to GL = 18’ PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD FT Size Date Status Beluga 47 3,705’ 3,725’ 1,858’ 1,871’ 20’ 2-7/8” 4-6 SPF 10/17/20 Open Beluga 47 3,732’ 3,738’ 1,876’ 1,879’ 6’ 2-7/8” 4-6 SPF 10/17/20 Open Beluga 47 3,760’ 3,776’ 1,894’ 1,905’ 16’ 2-7/8” 4-6 SPF 10/17/20 Open Beluga 47 3,777’ 3,789’ 1,906’ 1,914’ 12’ 2-7/8” 4-6 SPF 10/17/20 Open Beluga 49 3,841’ 3,846’ 1,950’ 1,953’ 5’ 2-7/8” 4-6 SPF 10/16/20 Open Beluga 49 3,857’ 3,863’ 1,961’ 1,965’ 6’ 2-7/8” 4-6 SPF 10/16/20 Open Beluga 49 3,874’ 3,880’ 1,973’ 1,977’ 6’ 2-7/8” 4-6 SPF 10/16/20 Open Beluga 50 3,926’ 3,930’ 2,010’ 2,013’ 4’ 2-7/8” 4-6 SPF 10/15/20 Open CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 DWC/C 6.875” Surf 1,196’ 4-1/2" Prod Csg 12.6 L-80 DWC/C HT 3.958” Surf 4,016’ 1 16” 7-5/8” 4-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 950’ 6” Swell Packer OPEN HOLE / CEMENT DETAIL 7-5/8" 41 bbls 12ppg lead + 39 bbls 15.8ppg tail of cement in 9-7/8” hole. 38 bbls returned to surface 4-1/2” 84 bbls of Type 1 II lead cmt @ 12 ppg, and 17 bbls of premium G tail cmt @ 15.3 ppg in 6-3/4” hole. 5 bbls lost during cement job. No cement to surface. MIT-IA to 2000 psi 10/12/20 CBL indicates TOC at 900 ft md Activity Date Ops Summary 9/23/2020 Flooded conductor with water, found leak at 1/2" test port/plug which had been broken off. Drained stack, removed broken nipple. Flooded mudline from pumps to topdrive, attempted to pressure test same, had leak at hardline union, bled off and replaced seal in union. Pressure tested mudline to;3500 psi, good test. Quadco on location at 09:30 RU gas sensors. Welder on location to fab bracket for hopper discharge line and repair shaker screen shelving in connex. Filled boiler with water. Spotted peak crane and set centrifuge, re-located crane and set clamshell windwall.;Brought in dry mud product, staged on mud docks, brought in spud mud from G&I, removed shipping blocks and plumbed in centrifuge, installed canvas roof top over centrifuge, test ran centrifuge, PU racked back HWDP and jars. Put water in pits 9-10. Accepted rig at 18:00 hours on 9-23-20.;Adjusted omni wrap on Kelly hose, offload mud to pits, dress shakers with new screens, house keeping around rig and location, call out truck to get another pipe tub on location, load strap and tally remaining DP on racks, warm up boiler slowly brining up to temperature;P/U and stand back remaining 38 jts of DP.;Service rig and top drive grease crown, inspect breaks on draworks.;House keeping around rig and location, Continue staging up boiler temp, clean and organize pump room and get parts inventory. 9/24/2020 Cont staging up boiler pressure, cont cleaning around yard and drilling connex. Staged BHA #1 on catwalk. Received, offloaded, drifted and strapped 29 jnts 7 5/8" casing. Received and staged surface bit on rig floor.;Kept mechanic at rig, all other crews traveled to Susan Dione Pad and held pre-spud meeting with Area Ops Manager, Geologist, Reservoir Engineer, Drilling Manager, Drilling Engineer, Production Reps, HSE Reps and Service Reps.;Returned to rig, held PJSM with Sperry Reps and rig crew, start MU directional BHA #1. Kymera bit jetted w/6 x 15's, mud motor w/1.5° bend, bit to bend = 7', DM, DGR, PWD, ADR and TM HOC collars. RFO = 104.8°. Plugged in and uploaded MWD. MU 1st NM flex DC and stand HWDP. Shallow pulse tested.;Spudded well at 119', rotating first stand down. 5K wob, 400 gpm-803 psi, 30 rpm-2339 ft/lbs on bott torque, checking wellhead and cellar area for broaching. Made connection and started slide drilling from 171' to 296', 6K wob, 426 gpm-1003 psi, 165 psi diff, 380 to 560 ft/hr ROP, MW 8.7/vis 220.;Obtained survey, pulled up hole to NM flex DC. PU 2nd NM flex DC, XO and RIH 2 stands HWDP then jars.;Resumed directional drilling 9 7/8" hole from 296' to 700', sliding wob 5K, 525 gpm-1405 psi, 171 psi diff, 400 to 700 ft/hr ROP, getting 8°/100' build rates. Top drive lost power.;Service rig while trouble shooting top drive.;Trouble shoot top drive power loss, found burned fuse generator tripped out when top drive shut down, fired back up gen, mechanic and electrician working to fix top drive, found that service loop was to tight when close to floor pulling on 37 pin connector causing connection to separate and short.;Drilling Ahead f/ 700' t/ 946' 550 gpm 1675 psi, 90 rpm 4.7k tq on 3.4k tq off, PUW 38k SOW 36k ROT 37k, 8.9 ppg MW 9.05 ppg ECD, Distance to plan 32.24' 32.16' high 7.89' right.;Hauled 76 bbls Solids to G&I Total Solids Hauled = 76 Hauled 119 bbls Trash Fluid to G&I Total Trash Fluid Hauled = 119 Hauled 0 bbls Cement to G&I Total Cement Hauled = 0 Daily Losses to Hole = 0 Total Losses to Hole = 0 n (LAT/LONG): evation (RKB): API #: Well Name: Field: County/State: NINU Kalotsa 5 Ninilchik Hilcorp Energy Company Composite Report , Alaska Contractor AFE #: AFE $: Job Name:2013110D Kalotsa 5 Drilling Spud Date: ;Spudded well at 119', 9/25/2020 Cont directional drilling 9 7/8" surface hole from 946' to TD at 1206'md/1077'tvd. Sliding wob 1-2K, 562 gpm-1865 psi, 90 to 160 psi diff, 126 to 250 ft/hr ROP. Rot wob 2K, 554 gpm-1930 psi, 88 rpm-5588 ft/lbs on bott torque, 120 ft/hr ROP, MW 8.9/vis 123, ECD's at 9.5 ppg, BGG 44 units.;had a max of 576 units at 1172'. TD'd in 60% clay, 40% sand. Had no issues with topdrive.;CBU at 550 gpm-1776 psi followed with a 20 bbl hi-vis nutplug sweep. Sweep back on time and with a 50% increase in cuttings.;LD single, flow check = static, pulled up hole on elevators from 1206' to 298', up wt 42K with no issue.;TIH on elevators from 298' to 700' and had to shut down for bad hydraulic hose on iron roughneck.;Replace hydraulic hose on iron roughneck. Sent notice to AOGCC of upcoming initial BOP test on 9-26-20.;Cont TIH from 700' to 1206' with no issue. MU topdrive and filled pipe.;Pumped a 20 bbl hi-vis nutplug sweep around at 522 gpm- 1608 psi, 84 rpm-4741 ft/lbs off bott torque. Sweep back on time with another 50% increase in cuttings. Obtained SPR's, flow check = static, LD single.;POOH from 1206' to 85' with no issue. Plugged in and downloaded MWD data. Wen to resume LD BHA and had no topdrive robotics.;Troubleshot topdrive issue. Swapped out service loop cable and installed protective wrap. Function tested same.;Cont POOH LD BHA #1. Bit graded a 0-1 and in gauge.;Cleaned and cleared rig floor. Cleared catwalk/piperacks of BHA. PU test joint and retrieved wear ring, LD same. PU and dummy ran hanger/landing joint, LD same.;RU Weatherford casing equipment, fill up line, staged centralizers on rig floor, staged casing on pipe racks.;Held PJSM with rig crew and Weatherford. MU shoe track, checked floats. Cont PU single in hole with 7 5/8" L-80 29.7# surface casing to 1171', MU landing joint and hanger, S/O and land on hanger @ 1196' PUW 42k SOW 36K.;R/U circulating equipment, break circulation stage pumps t/ 6 bpm 143 psi, Spot in Halliburton cementers and R/U hard lines and manifold to rig floor and pits and cuttings box, P/U cement head and load plugs, M/U cement head and break circulation through head.;MU plug launcher and hardline, Halliburton loaded lines with 5 bbls water and checked for leaks. Halliburton pressure tested lines at 510 low 3560 high, good tests. Halliburton pumped 39 bbls 10.5 ppg Tuned Spacer at 4 bpm-110 psi, dropped top plug and pumped 41 bbls (100 sx) 12 ppg Type III.;lead cement at 4 bpm-94 psi, followed by 39 bbls (210 sx) 15.8 ppg Class G tail cement at 4 bpm-120 psi. Halliburton dropped top plug, then displaced with 9.0 ppg Spud Mud at 4 bpm psi. Slowed pump to 2 bpm with 10 bbl to go. Did bump the plug at 49.5 bbls into displacement (calculated 51.3 bbls).;Held 1214 psi (FCP of 450 psi) for 3 minutes, bled off and floats held. Bled back .75 bbls to truck. Had 39 bbls of Spacer returns to surface and 38 bbls lead cement to surface. Added LCM to both lead and tail cement at 2.4 ppb. Mix water temp 62 deg. Pumped 50% excess on both lead and tail.;Lost 0 bbls throughout the job. Did reciprocate. CIP at 03:18, 9/26/20. RD and released Halliburton.;M/U and set Pack off, RILDS, test seals t/ 250/3000 psi f/ 15 min, N/D flow line and hole fill lines.;Hauled 0 bbls Solids to G&I Total Solids Hauled = 76 Hauled 0 bbls Trash Fluid to G&I Total Trash Fluid Hauled = 119 Hauled 0 bbls Cement to G&I Total Cement Hauled = 0 Daily Losses to Hole = 0 Total Losses to Hole = 0 9/26/2020 B/O landing jnt after setting packoff and L/D same. Wellhead Rep tested hanger at 250 low f/5 min and 3000 high f/15 min, good tests.;Unbolted 20” conductor riser from DSA, raised clear of DSA, removed DSA from wellhead. Due to length of riser and height of hanger neck we could not get riser out of cellar. Ended up cutting it in half with cutting wheels and removed in two pieces (planned on cutting and flanging riser anyway).;Staged “B” section at cellar entrance with crane, RU, set same and NU on wellhead.;Wellhead Rep tested packoff void and neck seal at 250 low f/5 min and 3000 high f/15 min, good tests. Staged wear ring, run tool/test plug on catwalk with 4 1/2" test joint. Spotted crane, picked BOP stack off float, layed back beaver slide and transferred stack to cellar bridge cranes.;Set spacer spool on wellhead, trolley in stack and set same. NU stack, choke and kill lines, installed koomey lines, installed drip pan and riser, R/U t/ test BOP's, set test plug and fill stack and lines w/ water.;Test BOP's w/ 4.5'' Test jt t/ 250/3500 psi with state inspector Jeff Jones witnessing, Test all equipment to state standards 2 FP on rig floor H2S gas detector. Perform Draw down test on accumulator passed, accumulator not maintaining a constant 1500 psi manifold pressure, State inspector wanted;it fixed before moving onto other well operations.;Trouble shoot accumulator, replace regulator on annular pressure side, no change annular pressure and manifold pressure still dropping, bleed off system pressure disconnect annular open and close lines hook together, pressure the system back up annular pressure stable manifold pressure bleeding off;but slower, continue trouble shooting accumulator system, hook up lines function annular multiple times, 4 way annular valve dripping and not stopping change out 4 way valve on accumulator. Pressure up system and function valve pressure stable on all gauges.;R/U and L/D excess HWDP and Jars in derrick, L/D Collar stand, Prep t/ P/U BHA.;Hauled 38 bbls Solids to G&I Total Solids Hauled = 259 Hauled 302 bbls Trash Fluid to G&I Total Trash Fluid Hauled = 781 Hauled 38 bbls Cement to G&I Total Cement Hauled = 38 Daily Losses to Hole = 0 Total Losses to Hole = 0 9/27/2020 Set wear ring, RU Sperry GeoSpan in cellar, CO 4 way valve on koomey unit to annular, LD NM flex DC's, jars and excess HWDP from derrick.;RU test equipment to test surface casing. Purged air, pumped up chart sensor, flooded choke manifold, functioned rams numerous times, finally got pressure to hold. Tested 7 5/8" surface casing to 3500 psi for 30 min on chart, pumped 28.75 gals, bled back 28.75 gals, RD test equipment.;Staged BHA #2, PU and MU 6 3/4" HDBS MM55D PDC jetted with 5 x 11's, mud motor set at 1.5°, bit to bend = 6', DM, GM, ADR, ALD, CTN, GeoTap and TM collars, RFO = 322.5°. Tools were hot loaded (uploaded) in yard prior to PU. MU topdrive and attempt shallow pulse test.;Test failed, pulled up hole, plugged in, downloaded and re-uploaded, can read tools. Attempted to shallow pulse test again, pulser not working. CO TM collar, plugged in and re-uploaded tools.;Floorhand pinched finger between rig tongs and iron roughneck while placing tongs on tool string, lacurated finger. Reported to Tool Push and Co Rep, who in turn reported it to HSE Rep, Drilling Engineer and Drilling Manager. Night Push drove floorhand to Soldotna Hospital for first aid.;Shallow pulse tested tools at 270 gpm, good test. Held PJSM and loaded nuke sources.;Held Safety Stand down with rig team on hand and finger placement.;Cont MU stab and NM flex DC's, XO, HWDP, jars and HWDP to 391'.;RIH f/ 391' t/ 997' set down 10 k unable to work through.;Drill cement t/ float collar plugs @ 1114' Drill plugs and FC Drill hard cement t/ FS @ 1194' Drill rat hole t/ 1206' Drill 20' of new hole t/ 1226'.;Circulate bottoms up Displace well t/ 6% KCL Polymer mud.;R/U and Perform FIT t/ 13.5 ppg EMW 260 psi w/ 8.9 ppg MW 1071' TVD.;Drill Ahead f/ 1226' t/ 1383' 305 gpm 1160 psi 40 rpm 3k tq on 2.2k tq off having detection issues w/ MWD, having to mad pass every slide interval 200 fph, sliding right out of the shoe, Distance to plan 7.12' 1.19' Low 7.02 Right.;Hauled 33 bbls Solids to G&I Total Solids Hauled = 292 Hauled 157 bbls Trash Fluid to G&I Total Trash Fluid Hauled = 938 Hauled 0 bbls Cement to G&I Total Cement Hauled = 38 Daily Losses to Hole = 0 Total Losses to Hole = 0 y pp ;Test BOP's w/ 4.5'' Test jt t/ 250/3500 psi with state inspector Jeff Jones witnessing, pg r mud.;R/U and Perform FIT t/ 13.5 ppg EMW 26 Cont directional drilling 9 7/8" surface hole from 946' to TD at 1206'md/1077'tvd. truck. Had 39 bbls of Spacer returns to surface and 38 bbls lead cement to surface. pg g pg r leaks. Halliburton pressure tested lines at 510 low 3560 high, good tests. Halliburton pumped 39 bbls pggpp 10.5 ppg Tuned Spacer at 4 bpm-110 psi, dropped top plug and pumped 41 bbls (100 sx) 12 ppg Type III.;lead cement at 4 bpm-94 psi, followed by 39 bbls (210 ppg p p p pp p p g p p ( ) ppg yp pp y ( sx) 15.8 ppg Class G tail cement at 4 bpm-120 psi. Halliburton dropped top plug, then displaced with 9.0 ppg Spud Mud at 4 bpm psi. Slowed pump to 2 bpm) ppg p p pp p p g p ppg with 10 bbl to go. Did bump the plug at 49.5 bbls into displacement (calculated 51.3 bbls).;Held 1214 psi (FCPppg p ( ) p MIT casing FIT 13.5 ppg qp g g p p p yg p Tested 7 5/8" surface casing to 3500 psi for 30 min on chart, pumped 28.75 gals, bled back 28.75 gals, RD test equipment.;Staged BHA #2, PU and MU 6 3/4"gp pp HDBS MM55D PDC jetted with 5 x 11's, mud motor set at 1.5°, bit to bend = 9/28/2020 During connection, saver sub broke at quill. With pump at idle, removed clamp and inspected dies (OK), shut down pump and re-torqued saver sub to quill, started pump and re-installed clamp. Resumed connection.;Cont drilling 6 3/4" hole from 1383' to 1632'. Sliding wob 3-4K, 308 gpm-1310 psi, 89 psi diff, 120 ft/hr ROP, MW 8.9/vis 54, ECD's at 9.7 ppg, BGG 21 units, max gas 560 units at 1492'. Mad passed slide intervals at 305 gpm-1252 psi, 60 rpm-3274 ft/lbs off bott torque at 200 ft/hr.;Cont drilling 6 3/4" hole from 1632' to 2246' md/1335' tvd. Sliding wob 3-4K, 308 gpm-1413 psi, 105 psi diff, 120 ft/hr ROP. Rot wob 1-3K, 308 gpm-1486 psi, 65 rpm-4000 ft/lbs on bott torque, 124 ft/hr ROP, MW 9.1/vis 53, ECD's at 9.8 to 10.8 ppg, BGG 46 units, max gas 851 units at 2123'.;CBU at 307 gpm-1406 psi, 60 rpm-3820 ft/lbs off bott torque. Obtained SPR's and flow check.;Pulled up hole on elevators from 2246' to 1192', up wt 32K. Took rotational check shots @ 1430' and 1340'.;Service rig and top drive, check draworks and grease crown, lost transformer on Geolog unit electrician working to fix issue and get back running.;RIH f/ 1192' t/ 2246' no hole issues.;Continue Drilling Ahead f/ 2246' t/ 2864' 308 GPM 1450 psi 60 RPM 4.5k tq on 3.8k tq off, 39k PUW 22k SOW 27k ROT, Pumped Hi Vis sweep when back on bottom 20 % increase in cuttings back on time. Distance to Plan 14.16' .25' Low 14.16' Left.;Hauled 50 bbls Solids to G&I Total Solids Hauled = 342 Hauled 225 bbls Trash Fluid to G&I Total Trash Fluid Hauled = 1163 Hauled 0 bbls Cement to G&I Total Cement Hauled = 38 Daily Losses to Hole = 0 Total Losses to Hole = 0 9/29/2020 Cont drilling 6 3/4" hole from 2864' to 3236'. Sliding wob 3-7K, 277 gpm-1384 psi, 128 psi diff, 90-120 ft/hr ROP. Rot wob 1-2K, 277 gpm-1386 psi, 60 rpm-4700 ft/lbs on bott torque, 120 ft/hr ROP, MW 9.2/vis 53, ECD's at 10.6 ppg, BGG 20 units, max gas 580 units at 3236'.;Added 1 drum NXS lube to suction pit for sliding. Received 156 jnts 4 1/2" casing and one swell packer. Started rack, tally and drift those.;Obtained survey, CBU twice at 291 gpm-1411 psi, 60 rpm-3600 ft/lbs off bott torque. Obtained SPR's and flow check = slight seepage.;Attempted to break out topdrive from tool joint for wiper trip, could not break out. Had to remove saver sub clamp, break out of saver sub, break saver sub with iron roughneck, MU new saver sub, MU topdrive and CBU one more time prior to wiper trip. Broke off topdrive with no issue.;Pulled up hole on elevators from 3236' to 2160' with no issue, up wt 48K. Calc hole fill = 7.1 bbls, actual hole fill = 8 bbls. At 2160' adjusted and reset topdrive max torque to 20,700 ft/lbs.;TIH on elevators from 2160' to 3207', MU topdrive and filled pipe. Washed/reamed to bottom and started a 20 bbl hi-vis nutplug condet sweep around at 270 gpm-1194 psi, 60 rpm-5619 ft/lbs off bott torque, sweep back on time with a 25% increase in cuttings.;Resumed drilling from 3236' to 3424', sliding wob 4 to 7K, 305 gpm-1573 psi, 120 psi diff, 120 ft/hr ROP. Rot wob 1-2K, 306 gpm-1528 psi, MW 9.2/vis 51, ECD's at 10.6 ppg, BGG 124 units, max gas 731 units at +/- 3307'. Cont rack and tally 4 1/2" casing.;Cont drilling 6 3/4" hole F/3424'-T/3798'. P/U-54K S/O- 26K ROT-37K GPM-308 SPP-1620 psi TQ-5K WOB-3-5K RPM-60 BGG 250 units, max gas 579 units at +/- 3680'.;Held PTSM, crew change. Cont drilling 6 3/4" hole F/3798' to TD @ 4025' as per Geologist. P/U-59K S/O-29K ROT-40K GPM-275 SPP-1547 psi TQ-6.8K Diff-75 WOB-2K RPM-57 BGG 300 units, max gas 353 units at +/- 4025'.;CBU X2 in till shakers cleaned up, shot survey, got SPR's.;POOH on elevators for wiper trip back to shoe F/4025' to current depth 2881'. P/U-42K S/O-22K Distance to well plan: 8.8' .63' low 8.77' left.;Hauled 54 bbls Solids to G&I Total Solids Hauled = 392 Hauled 216 bbls Trash Fluid to G&I Total Trash Fluid Hauled = 1379 Hauled 0 bbls Cement to G&I Total Cement Hauled = 38 Daily Losses to Hole = 0 Total Losses to Hole = 0 9/30/2020 Cont pulling wiper trip from 2881’ to 1206’ with no issue, SO and parked at 1267’. Released sample catchers.;CBU one time with little increase in cuttings to surface. Serviced rig and topdrive. During rig service, hole on trip tank, loss rate at 1.5 bph.;TIH on elevators to 3988’ with no issue, down wt 28K, MU last stand and topdrive, filled pipe and washed down to 4025’. Received rig loader but found parking brake housing to be cracked, parked loader. Received BOP cradle.;Started 20 bbl hi-vis nutplug sweep around at 275 gpm-1324 psi, had a max of 717 units gas at bottoms up that dropped off quickly, sweep back on time with a 25% increase in cuttings.;Held PJSM with Sperry Reps, LD single joint then started mad pass and GeoTap as per Sperry from 4016' to 3550', working up hole on odd breaks. Received centralizers, shoe track, landing joint and hanger.;Cont mad passing and Geo Tapping F/3550'-T/3027', completed a total of 18 station out of 35. While working on housekeeping , cleaning around rig and loaded out misc. mud products onto trailers.;Held PTSM, crew change. Cont. mad passing and Geo Tapping F/3027'-T/2892', completed a total of 23 station out of 35. Cont. with house keeping/cleaning around rig.;Hauled 39 bbls Solids to G&I Total Solids Hauled = 431 Hauled 386 bbls Trash Fluid to G&I Total Trash Fluid Hauled = 1765 Hauled 0 bbls Cement to G&I Total Cement Hauled = 38 Daily Losses to Hole = 30 Total Losses to Hole = 30 10/1/2020 Cont to mad pass and GeoTap from 2892’ up to 1521’ bit depth. Performed a total of 48 tests overall. Pumped at 286 gpm-1290 psi. Changed fuel filter, trans and oil filters on floor motor while parked and testing.;IH on elevators from 1521’ to 3953’ with no issue, MU last stand and topdrive, filled pipe and washed to bottom at 4025’. Down wt 28 to 22K. Gave AOGCC notice of upcoming casing run and cementing.;CBU one time, followed with a 20 bbl hi-vis nutplug sweep at 302 gpm-1595 psi, 60 rpm-4831 ft/lbs off bott torque. Had a max of 45 units gas at bottoms up. Sweep back on time with maybe 10% increase in fine silt/clay. Flow check = very slight seepage, obtained SPR's and pumped dry job.;Pulled up hole 10 stands with no issues racking back, from 4025' to 3428'. Swapped elevators around and began LD 4 1/2" DP from 3428' to 391'. Peak vac'ing wiper balls on pipe racks, clean and dope threads and installing thread protectors. Flow check (ok). Started L/D BHA #2.;Held PTSM, crew change. During rig crew change had 23 gal drilling mud spill to rig apron/ground by end of catwalk from Peak vac truck hose. Spill was reported to proper personal and cleaned up.;Resumed to L/D BHA #2, L/D HWDP, jars, & Flex collars. Held PJSM on removing sources, removed sources, down loaded MWD tool. L/D remainder of MWD tools , motor, & bit. Bit was in gauge. Bit graded 1-1-WT-A-X-I-NO-TD.;R/D Geo- span, cleaned & cleared rig floor. M/U mule shoe to std in derrick, currently RIH w/ first batch of DP to L/D out of derrick.;Hauled 0 bbls Solids to G&I Total Solids Hauled = 431 Hauled 75 bbls Trash Fluid to G&I Total Trash Fluid Hauled = 1840 Hauled 0 bbls Cement to G&I Total Cement Hauled = 38 Daily Losses to Hole = 2 Total Losses to Hole = 32 p 3/4" hole F/3798' to TD @ 4025' as per Geologist. P/U-5 Cont drilling 6 3/4" hole from 2864' to 3236'. Slid TD well at 4025 ft md 10/2/2020 MU 3' mule shoe on jnt of 4 1/2" DP, TIH with 20 stands from derrick to 1232'.;CBU twice with centrifuge running, to cut back surface volume MW and dry job from hole at 296 gpm-57 psi.;POOH LD 4 1/2" DP, Peak vac'ing wiper balls on pipe racks, cleaning and doping threads and installing thread protectors.;MU mule shoe on stand DP, RIH last of DP in derrick to 1138'.;CBU twice to cont cutting MW back with centrifuge, 305 gpm-64 psi.;POOH LD 4 1/2" DP from 1138' , LD mule shoe.;Drained stack, PU 2 7/8" test joint and run tool, retrieved wear ring. MU test plug and set same. Flooded stack, tested annular, upper rams and lower rams at 250/3500 for 5 min each, RD test equipment, pulled test plug, LD test joint. Weatherford on location at 14:00 hrs.;PU 4 1/2" landing joint with hanger, landed hanger and marked RKB on landing joint, LD same. RU Weatherford casing equipment, fill up line, staged centralizers, staged shoe track and casing, MU XO to TIW. Held PJSM with rig team and Weatherford crew.;PU and MU shoe track, filled pipe and checked float equipment (OK). Cont PU single in hole with 4.5" 12.6# L-80 DWC/C-HT casing to 1154', torqued connections to 6150 ft/lbs. Top filled on the fly, topped off every 10 jnts. P/U-24K S/O-23K.;MU circ swedge and topdrive, circulated bottoms up staging up to 215 gpm-0 psi, no gas.;Cont PU single in hole from 1154', exiting surface shoe at 1196', down to 2589' with no issue. MU circ swedge and topdrive. P/U-29K S/O-21K.;Broke circ. and circulated bottoms up staging up to 211 gpm-90 psi, max gas 46 units.;Cont PU single in hole w/ 4.5" casing F/2589'-T/3990'. P/U & M/U landing jt./hanger & drive sub, eased down and landed hanger on seat @ 4016', pulled off seat 1'. P/U-40K S/O-25K Cal Disp.= 18.2 bbls Act.=19.2 bbls Diff= 1 bbls.;Broke circulation, staged pumps up to 5 bpm while reciprocate pipe every so often. R/D casing handling equip. R/U bale extensions, staged & R/U HES cmts. GPM-218 SPP-131 psi Flow 18%.;Held PTSM, crew change. Cont. circ. & conditioning mud for cmt job while R/U HES cmts. P/U-40K S/O-22K GPM-218 SPP-131 psi.;Shut down pump, broke out TD & drive sub from stump, loaded plugs in cmt head, M/U cmt head to stump, broke circ. through cmt head, Held PJSM w/ rig crew, HES cmts, Peak, Baroid, & DSM.;Pumped water through cmt hard lines & manifold to cuttings box, lined up and circ. 4 bbls of water down hole, pressure tested lines 969 psi Low & 4870 psi High (ok). HES cmts pumped 40 bbls of 10.5 ppg Tune spacer at 4 bpm, shut down dropped bottom plug, pumped 84 bbls of Type 1 II lead cmt 12 ppg;at 4.5 bpm, followed by 17 bbls of premium G tail cmt 15.3 ppg at 3 bpm, dropped top plug, HES displaced w/ 9.2 ppg 6% KCL PHPA mud at 5 bpm, slowed pump to 2 bpm w/ 10 bbls to go, bumped plug at 58 bbls (calculated 59.8 bbls), held 1198 psi (FCP 490 psi) for 3 min, bled off & floats held.;Bled back .5 bbls to truck, Had 27 bbls of spacer return to surface and 0 bbls of cmt. Added 4.5 ppb of Bridge Maker to lead cmt only, pumped 20% excess on both lead & tail, lost 5 bbls during cmt job, were able to reciprocated pipe till displacing w/ mud due to pipe getting sticky, CIP @ 03:25.;Flushed & blew down cmt lines, R/D cmt head & lines, drained & flushed stack, backed out landing jt. M/U pack off to setting tool/landing jt. Set pack off, currently RILD's.;Hauled 0 bbls Solids to G&I Total Solids Hauled = 431 Hauled 130 bbls Trash Fluid to G&I Total Trash Fluid Hauled = 1970 Hauled 0 bbls Cement to G&I Total Cement Hauled = 38 Daily Losses to Hole = 0 Total Losses to Hole = 32 10/3/2020 Tested packoff at 500 low/5000 high for 5 min each, good tests. Cleared rig floor and catwalk, brought in and offloaded 2 7/8” PH-6 workstring, cont haul off excess mud, pulled water off upright tank and offloaded into pits for brine build. Racked and tallied 2 7/8”, fueled up Weatherford power unit;MU XO’s on TIW, built brine and spacer, installed slip type elevators on topdrive, dressed tongs and airslips for 2 7/8”, serviced rig and topdrive.;Held PJSM with Weatherford and rig crew, PU 1st jnt PH-6, MU bit sub, scraper and 3.75” roller cone. Made numerous attempts to get scraper to pass through hanger into casing, double checked OD (OK), possible the spring loaded dies not compressing enough to allow scraper to pass into 4.5" casing, or;scraper dies simply too thick, chose not to MU XO and push with topdrive, LD scraper, MU bit on bit sub, PU singled in hole with 2 7/8" PH-6 to 3929' and tagged up. MU XO and topdrive. Shipped out both landing joints, cont clenaing pits.;Start circ surface to surface with mud at 112 gpm-746 to 793 psi, rotated at 15 rpm-1669 to 1723 ft/lbs off bott torque. Lined up on spacer, pumped that followed with 6% KCL brine, staging up to 212 gpm-2324 psi.;POOH L/D 2-7/8" PH-6 work string F/3929'-T/154', while rinsing ID's of pipe w/ water and vacuuming them dry w/ vac truck on the racks. P/U-34K S/O-19K @ 3900'. Cont. working on cleaning pits & hauling off mud to G&I. Called out NOS well head Rep James.;Held PTSM, crew change. Cont. POOH 2-7/8" PH-6 work string F/154' to surface, L/D BHA #3. Cal Disp.=11.14 bbls Act=10.6 bbls Diff=.54 bbls.;R/D WOTC casing equip, R/U testing equip, flooded lines & purged out air.;Performed 4.5" casing test on chart for 30 min (ok), Pumped in 33 gals, bled back 33 gals.;R/D testing equip. Vacuumed out stack, set BPV, Jonny whacked stack. Flushed TD, mud lines, MP's , kill & choke lines, & choke manifold, and blew down same.;Cleaned & cleared rig floor, R/D tongs, ODS weight indicator, bleeder line, flow line, riser, & flow nipple. Bleed down koomey, opened ram cavities, currently performed monthly inspection on rams and cont. w/ cleaning of pits & hauling off mud.;Hauled 0 bbls Solids to G&I Total Solids Hauled = 431 Hauled 431 bbls Trash Fluid to G&I Total Trash Fluid Hauled = 2770 Hauled 0 bbls Cement to G&I Total Cement Hauled = 38 Daily Losses to Hole = 0 Total Losses to Hole = 32 10/4/2020 Removed GeoSpan from cellar, RD gen #3, opened and inspected BOP ram cavities (monthly PM), cont cleaning pits, closed up BOP's, ND stack and hoisted with bridge cranes, removed spacer spool, staged dry hole tree in cellar.;Hung dry hole tree and verified orientation with Production Rep, set tree and bolted up same, dressed pump #2 back to 5 1/2" for next well.;Pulled BPV and set 2 way check, flooded tree, tested hanger neck seals at 500/5000 psi 5 min each, tested void at 500 psi f/5 min low and 5000 psi f/15 min high, tested tree at 5000 f/5 min, good tests, RD released wellhead Reps.;Boiler shut in, blew down steam lines, cooling boiler for rig move. finished cleaning in pits, removed canvas roof top and frame over centrifuge, installed shipping blocks in centrifuge, racked shaker screens on new shelves in connex,;prepped iron roughneck for removal from floor, RD poorboy degasser, Peak crane on location at 15:00 hrs, spotted crane, removed windwalls from pits, picked hurricane vac, RD and LD topdrive from floor, picked clamshell;windwall behind iron roughneck, picked centrifuge from stand. (Lost all comms at 14:00 hrs).;Layed back beaver slide, transferred BOP stack from bridge cranes to Peak crane, set stack on cradle and laid over. R/D derrick board & prep for move. Tied off Kelley hose, service loop, & misc. lines in derrick. Installed shipping beams & secured bridge cranes in sub.;Scoped derrick and L/D lower section of TQ tube onto catwalk. Unspooled & cut 53' of drill line. Removed brake linkage & drive shaft for brake handle. Disconnected and coiled up air lines to dog house. R/D Pason & camera cables, prepped mast to lay over. R/D vacuum degasser & lowered into pit #4.;Disconnected hopper house jumpers, and pit equalizer lines. Loaded up mud product & misc. items around rig onto trailers.;Held PJSM on laying over mast. Laid over derrick, tied up remaining lines in derrick for transport.;Crew change, held PTSM & weekly safety meeting w/ rig crew. Cont. R/D electrical lines around rig and disconnecting utility lines between modules. Vac'd out water in rig boiler and secured boiler for move. R/D MP suction & discharge lines, and gas detection system. R/D choke house, and laid down;poor boy gas buster. R/D catwalk electrical & HYD lines, & accumulator hoses from sub to koomey. Finished R/D pit top and securing equip. Lowered roofs on mud pits, laid over V-door. Power washed cellar box. Cont. R/D & prepping to move. Final report for Kalotsa #5, released rig to Paxton 10 AFE. pggp gp p g g g MU circ swedge and topdrive. P/U-29K S/O-21K.;Broke circ. and circulated bottoms up staging up to 211 gpm-90 psi, max gas 46 gp pggpgppg units.;Cont PU single in hole w/ 4.5" casing F/2589'-T/3990'. P/U & M/U landing jt./hanger & drive sub, eased down and landed hanger on seat @ 4016', pulled cement 4.5" casing g HES cmts pumped 40 gp p p pg( ) p bbls of 10.5 ppg Tune spacer at 4 bpm, shut down dropped bottom plug, pumped 84 bbls of Type 1 II lead cmt 12 ppg;at 4.5 bpm, followed by 17 bbls of ppg p p pp p g p p yp ppg p y premium G tail cmt 15.3 ppg at 3 bpm, dropped top plug, HES displaced w/ 9.2 ppg 6% KCL PHPA mud at 5 bpm, slowed pump to 2 bpm w/ 10 bbls to go, p ppg p pp p p g p ppg p p p p g bumped plug at 58 bbls (calculated 59.8 bbls), held 1198 psi (FCP 490 psi) for 3 min, bled off & floats held.;Bled back .5 bbls to truck, Had 27 bbls of spacer ppg ( return to surface and 0 bbls of cmt. Ad Activity Date Ops Summary 10/13/2020 MIRU with Unit 131 on Kolotsa #5. NU BOP.,Test BOP. BOP configuration: Blind / Shear rams top, 1-3/4" fixed pipe / slip rams below. 24-hr notice given 10/12/2020 at 1330 hrs. Test witness waived by Jim Regg.,Secure well, leave location. 10/14/2020 Prep coil connector, inspect data collection connections for compatibility with Halliburton tools. Send Coil personnel to Yellow Jacket to retrieve crossover.,Service Coil Unit while waiting on Halliburton.,RU Halliburton data cables to Unit collector. MU CBL Memory logging BHA. Tag bottom at 3941' MD. Pick up, move down and re-tag. Log from Shoe to surface moving at 50 fpm. Verify data at surface. RD, Secure well for overnight. Depart location. 10/15/2020 RU Nitrogen unit to Coil Unit. PT lines. RIH with coil to TD of 3938'. Displace well with nitrogen, 60 bbls back to tank.,Swap out reels on coil unit to E-Coil reel,RU tools for Alaska E-Line. Test E-wire, good test. Perf guns to be run: 2-7/8" Razor, varied 4-6 shots per foot.,RIH with perf gun 1 on E-Coil and Alaska E- Line logging tools. Tag bottom at 3931' MD coil measurement. Log GR / CCL correlation pass, place guns on depth and fire interval 3926'-3930' MD. 4 shots per foot. POH 10/16/2020 Conduct pre-job discussion, focus on lifting techniques when making up lubricator and hand safety while handling guns. Conduct electrical checks on tools, open to well, 55 psi on well.,MU perf gun assembly #2, 6' of shots. Stab on to well, RIH. Log correlation pass, -21' correction. Set gun on depth, firing interval 3874'- 3880' MD. Good indication of firing. POH. Pressures monitored on SCADA for 5-10-15 minute interval. All shots fired.,MU perf gun assembly #3, 6' of shots. Stab on to well, RIH. Log correlation pass, -1' correction. Set gun on depth, firing interval 3857'-3863' MD. Good indication of firing. POH. Pressures monitored on SCADA for 5-10-15 minute interval. All shots fired.,MU perf gun assembly #4, 5' of shots. Stab on to well, RIH. Log correlation pass, 0' correction. Set gun on depth, firing interval 3841'-3846' MD. Good indication of firing. POH. Pressures monitored on SCADA for 5-10-15 minute in terval. All shots fired.,MU perf gun assembly #5, 12' of shots. Stab on to well, RIH. Log correlation pass, 0' correction. Set gun on depth, firing interval 3777'-3789' MD. Did not receive indication of firing from current indicator and no pressure differential from well. POH, break off lubricator and inspect equipment. Gun has not fired. RD, secure well for evening while AK E-Line investigates firing issue. 10/17/2020 Conduct safety meeting with crew regarding rig up of lubricator, perf runs. MU first perf BHA, stab on with lubricator.,RIH with perf BHA #5. Tag bottom, log across proposed perforation zone with 0' correction. Place guns on depth, fire at zone 3777'-3789'. POH. Swap out BHA.,RIH with perf BHA #6. Tag bottom, log across proposed perforation zone with -1' correction. Place guns on depth, fire at zone 3760'-3776'. POH with high pressure build rate. Swap out BHA. Initial estimates are gas production is rising.,RIH with perf BHA #7. Tag bottom, log across proposed perforation zone with 0' correction. Place guns on depth, fire at zone 3732'-3738'. POH. Indications of good pressure and flow increase. Swap out BHA.,RIH with perf BHA #8. Tag bottom, log across proposed perforation zone with -1' correction. Place guns on depth, fire at zone 3705'-3725'. POH. Good pressure increase and corresponding flow increase. LD BHA, secure well for the evening. 10/18/2020 PJSM on rigging down, emphasis on lifting operations. RD Alaska E-Line and Petrospec units. Clean site. Turn well over to Operations. n (LAT/LONG): evation (RKB): API #: Well Name: Field: County/State: NINU Kalotsa 5 Ninilchik Hilcorp Energy Company Composite Report , Alaska Contractor AFE #: AFE $: Job Name:2013110C Kalotsa 5 Completion Spud Date: RU Nitrogen unit to Coil Unit. PT lines. RIH with coil to TD of 3938'. Displace well with nitrogen, 60 bbls back to tank.,S perf runs p MU CBL Memory logging BHA. T completion sundry 320-425 02 October, 2020 Ninilchik Unit Kalotsa Kalotsa 5 501332068600 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Ninilchik Unit Kalotsa Halliburton Definitive Survey Report Well: Wellbore: Kalotsa 5 Kalotsa 5 Survey Calculation Method:Minimum Curvature As-Built @ 144.50usft (HEC 169) Design:Kalotsa 5 Database:NORTH US + CANADA MD Reference:As-Built @ 144.50usft (HEC 169) North Reference: Well Kalotsa 5 True Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Ninilchik Unit Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: Kalotsa 5 usft usft 0.00 0.00 2,233,395.651 209,803.593 126.50Wellhead Elevation:usft0.50 60° 6' 14.081 N 151° 35' 25.264 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) Kalotsa 5 Model NameMagnetics IFR 9/21/2020 14.32 72.95 55,052.20000000 Phase:Version: Audit Notes: Design Kalotsa 5 1.0 ACTUAL Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:18.00 304.170.000.0018.00 From (usft) Survey Program DescriptionTool NameSurvey (Wellbore) To (usft) Date 9/30/2020 Survey Date 3_MWD+IFR1+MS+Sag A010Mb: IFR dec & multi-station analysis + sag200.10 1,159.30 MWD+IFR1+MS+Sag (1) (Kalotsa 5)09/04/2020 3_MWD+IFR1+MS+Sag A010Mb: IFR dec & multi-station analysis + sag1,222.41 3,987.89 MWD+IFR1+MS+Sag (2) (Kalotsa 5)09/28/2020 MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 18.00 0.00 0.00 18.00 0.00 0.00-126.50 2,233,395.65 209,803.59 0.00 0.00 UNDEFINED 200.10 3.01 293.46 200.02 1.90 -4.3955.52 2,233,397.66 209,799.25 1.65 4.70 3_MWD+IFR1+MS+Sag (1) 261.93 8.08 297.28 261.54 4.54 -9.74117.04 2,233,400.43 209,793.96 8.22 10.61 3_MWD+IFR1+MS+Sag (1) 358.96 16.13 294.33 356.33 13.24 -28.11211.83 2,233,409.56 209,775.81 8.32 30.69 3_MWD+IFR1+MS+Sag (1) 419.71 18.34 290.14 414.35 20.00 -44.78269.85 2,233,416.73 209,759.31 4.17 48.28 3_MWD+IFR1+MS+Sag (1) 480.68 17.68 281.73 472.35 25.19 -62.85327.85 2,233,422.35 209,741.36 4.40 66.15 3_MWD+IFR1+MS+Sag (1) 542.21 16.91 275.07 531.10 27.88 -80.92386.60 2,233,425.47 209,723.37 3.45 82.61 3_MWD+IFR1+MS+Sag (1) 603.22 16.48 272.23 589.54 29.00 -98.40445.04 2,233,427.01 209,705.92 1.51 97.70 3_MWD+IFR1+MS+Sag (1) 661.93 19.56 276.38 645.36 30.42 -116.50500.86 2,233,428.86 209,687.86 5.68 113.47 3_MWD+IFR1+MS+Sag (1) 726.26 23.78 280.34 705.14 33.95 -139.97560.64 2,233,432.95 209,664.48 6.94 134.87 3_MWD+IFR1+MS+Sag (1) 787.75 28.69 282.76 760.28 39.43 -166.58615.78 2,233,439.08 209,638.01 8.17 159.97 3_MWD+IFR1+MS+Sag (1) 849.88 32.25 283.06 813.82 46.48 -197.28669.32 2,233,446.86 209,607.49 5.74 189.33 3_MWD+IFR1+MS+Sag (1) 910.92 36.34 283.08 864.24 54.25 -230.78719.74 2,233,455.44 209,574.19 6.70 221.41 3_MWD+IFR1+MS+Sag (1) 10/2/2020 4:47:18PM COMPASS 5000.15 Build 91E Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Ninilchik Unit Kalotsa Halliburton Definitive Survey Report Well: Wellbore: Kalotsa 5 Kalotsa 5 Survey Calculation Method:Minimum Curvature As-Built @ 144.50usft (HEC 169) Design:Kalotsa 5 Database:NORTH US + CANADA MD Reference:As-Built @ 144.50usft (HEC 169) North Reference: Well Kalotsa 5 True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 973.07 40.20 283.80 913.02 63.21 -268.20768.52 2,233,465.29 209,536.99 6.25 257.41 3_MWD+IFR1+MS+Sag (1) 1,034.82 42.13 282.95 959.51 72.60 -307.75815.01 2,233,475.64 209,497.68 3.25 295.40 3_MWD+IFR1+MS+Sag (1) 1,096.83 44.93 282.13 1,004.46 81.87 -349.43859.96 2,233,485.90 209,456.23 4.61 335.09 3_MWD+IFR1+MS+Sag (1) 1,159.30 48.49 281.54 1,047.29 91.19 -393.93902.79 2,233,496.29 209,411.97 5.74 377.14 3_MWD+IFR1+MS+Sag (1) 1,222.41 51.57 281.86 1,087.82 101.00 -441.29943.32 2,233,507.24 209,364.87 4.90 421.83 3_MWD+IFR1+MS+Sag (2) 1,282.36 57.52 282.20 1,122.58 111.17 -489.02978.08 2,233,518.56 209,317.39 9.94 467.05 3_MWD+IFR1+MS+Sag (2) 1,345.68 62.40 281.50 1,154.27 122.42 -542.661,009.77 2,233,531.09 209,264.04 7.77 517.74 3_MWD+IFR1+MS+Sag (2) 1,408.89 66.51 280.37 1,181.52 133.22 -598.641,037.02 2,233,543.24 209,208.33 6.70 570.13 3_MWD+IFR1+MS+Sag (2) 1,470.44 70.63 279.01 1,204.01 142.86 -655.111,059.51 2,233,554.23 209,152.12 7.00 622.25 3_MWD+IFR1+MS+Sag (2) 1,532.55 74.18 278.78 1,222.78 152.01 -713.591,078.28 2,233,564.79 209,093.87 5.73 675.78 3_MWD+IFR1+MS+Sag (2) 1,595.32 78.70 278.99 1,237.49 161.43 -773.861,092.99 2,233,575.66 209,033.84 7.21 730.94 3_MWD+IFR1+MS+Sag (2) 1,657.26 83.26 277.62 1,247.20 170.26 -834.381,102.70 2,233,585.94 208,973.56 7.68 785.97 3_MWD+IFR1+MS+Sag (2) 1,719.02 85.18 277.06 1,253.42 178.11 -895.321,108.92 2,233,595.25 208,912.83 3.24 840.80 3_MWD+IFR1+MS+Sag (2) 1,782.25 83.69 278.63 1,259.55 186.70 -957.661,115.05 2,233,605.34 208,850.71 3.41 897.20 3_MWD+IFR1+MS+Sag (2) 1,844.41 84.00 278.49 1,266.22 195.90 -1,018.771,121.72 2,233,616.01 208,789.84 0.55 952.93 3_MWD+IFR1+MS+Sag (2) 1,906.09 81.57 279.79 1,273.97 205.61 -1,079.181,129.47 2,233,627.17 208,729.68 4.46 1,008.37 3_MWD+IFR1+MS+Sag (2) 1,968.18 79.82 282.40 1,284.01 217.40 -1,139.301,139.51 2,233,640.40 208,669.86 5.02 1,064.73 3_MWD+IFR1+MS+Sag (2) 2,030.34 79.76 282.36 1,295.02 230.52 -1,199.051,150.52 2,233,654.95 208,610.44 0.12 1,121.53 3_MWD+IFR1+MS+Sag (2) 2,091.83 79.69 282.21 1,305.99 243.39 -1,258.171,161.49 2,233,669.25 208,551.65 0.27 1,177.68 3_MWD+IFR1+MS+Sag (2) 2,154.03 79.51 281.85 1,317.22 256.14 -1,318.001,172.72 2,233,683.43 208,492.14 0.64 1,234.35 3_MWD+IFR1+MS+Sag (2) 2,213.99 79.82 281.06 1,327.98 267.86 -1,375.821,183.48 2,233,696.53 208,434.63 1.40 1,288.76 3_MWD+IFR1+MS+Sag (2) 2,275.39 79.19 283.64 1,339.16 280.77 -1,434.791,194.66 2,233,710.86 208,375.98 4.26 1,344.80 3_MWD+IFR1+MS+Sag (2) 2,336.95 78.69 284.15 1,350.97 295.27 -1,493.431,206.47 2,233,726.77 208,317.70 1.15 1,401.47 3_MWD+IFR1+MS+Sag (2) 2,400.04 78.24 283.98 1,363.59 310.30 -1,553.401,219.09 2,233,743.24 208,258.12 0.76 1,459.52 3_MWD+IFR1+MS+Sag (2) 2,461.88 78.12 283.47 1,376.26 324.66 -1,612.201,231.76 2,233,759.01 208,199.68 0.83 1,516.24 3_MWD+IFR1+MS+Sag (2) 2,523.32 78.50 283.12 1,388.71 338.49 -1,670.751,244.21 2,233,774.25 208,141.48 0.83 1,572.45 3_MWD+IFR1+MS+Sag (2) 2,584.85 78.88 282.85 1,400.77 352.05 -1,729.541,256.27 2,233,789.22 208,083.03 0.75 1,628.71 3_MWD+IFR1+MS+Sag (2) 2,647.02 78.37 283.31 1,413.03 365.84 -1,788.911,268.53 2,233,804.43 208,024.01 1.10 1,685.57 3_MWD+IFR1+MS+Sag (2) 2,709.11 76.47 284.77 1,426.56 380.54 -1,847.691,282.06 2,233,820.54 207,965.60 3.82 1,742.47 3_MWD+IFR1+MS+Sag (2) 2,771.19 75.71 285.73 1,441.48 396.39 -1,905.831,296.98 2,233,837.78 207,907.86 1.94 1,799.47 3_MWD+IFR1+MS+Sag (2) 2,832.79 73.67 286.46 1,457.75 412.86 -1,962.911,313.25 2,233,855.62 207,851.19 3.50 1,855.95 3_MWD+IFR1+MS+Sag (2) 2,895.05 72.44 287.60 1,475.89 430.30 -2,019.861,331.39 2,233,874.43 207,794.68 2.64 1,912.86 3_MWD+IFR1+MS+Sag (2) 2,956.40 70.75 288.39 1,495.26 448.28 -2,075.221,350.76 2,233,893.74 207,739.77 3.01 1,968.76 3_MWD+IFR1+MS+Sag (2) 3,019.51 69.30 290.04 1,516.82 467.80 -2,131.231,372.32 2,233,914.59 207,684.25 3.36 2,026.06 3_MWD+IFR1+MS+Sag (2) 3,080.61 68.44 291.17 1,538.85 487.85 -2,184.571,394.35 2,233,935.93 207,631.40 2.23 2,081.46 3_MWD+IFR1+MS+Sag (2) 3,142.31 66.77 292.76 1,562.36 509.18 -2,237.471,417.86 2,233,958.52 207,579.03 3.61 2,137.21 3_MWD+IFR1+MS+Sag (2) 3,204.82 64.80 294.43 1,587.99 531.99 -2,289.721,443.49 2,233,982.59 207,527.35 3.98 2,193.25 3_MWD+IFR1+MS+Sag (2) 3,265.64 63.01 296.29 1,614.75 555.38 -2,339.071,470.25 2,234,007.15 207,478.57 4.03 2,247.22 3_MWD+IFR1+MS+Sag (2) 3,328.73 61.26 297.40 1,644.24 580.56 -2,388.831,499.74 2,234,033.52 207,429.43 3.18 2,302.53 3_MWD+IFR1+MS+Sag (2) 3,390.07 59.35 298.01 1,674.62 605.33 -2,436.011,530.12 2,234,059.42 207,382.87 3.23 2,355.47 3_MWD+IFR1+MS+Sag (2) 10/2/2020 4:47:18PM COMPASS 5000.15 Build 91E Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Ninilchik Unit Kalotsa Halliburton Definitive Survey Report Well: Wellbore: Kalotsa 5 Kalotsa 5 Survey Calculation Method:Minimum Curvature As-Built @ 144.50usft (HEC 169) Design:Kalotsa 5 Database:NORTH US + CANADA MD Reference:As-Built @ 144.50usft (HEC 169) North Reference: Well Kalotsa 5 True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 3,452.28 57.11 299.90 1,707.37 630.92 -2,482.281,562.87 2,234,086.12 207,337.22 4.43 2,408.14 3_MWD+IFR1+MS+Sag (2) 3,514.48 55.26 302.00 1,741.99 657.49 -2,526.601,597.49 2,234,113.74 207,293.55 4.09 2,459.73 3_MWD+IFR1+MS+Sag (2) 3,576.67 53.58 303.44 1,778.18 684.82 -2,569.161,633.68 2,234,142.09 207,251.67 3.29 2,510.29 3_MWD+IFR1+MS+Sag (2) 3,638.35 51.45 306.06 1,815.71 712.70 -2,609.371,671.21 2,234,170.93 207,212.14 4.83 2,559.22 3_MWD+IFR1+MS+Sag (2) 3,701.08 49.95 308.17 1,855.45 741.98 -2,648.081,710.95 2,234,201.13 207,174.14 3.53 2,607.69 3_MWD+IFR1+MS+Sag (2) 3,763.84 47.80 309.54 1,896.72 771.63 -2,684.901,752.22 2,234,231.66 207,138.05 3.80 2,654.80 3_MWD+IFR1+MS+Sag (2) 3,824.86 46.13 311.96 1,938.37 800.73 -2,718.691,793.87 2,234,261.56 207,104.97 3.99 2,699.10 3_MWD+IFR1+MS+Sag (2) 3,887.70 44.50 314.17 1,982.56 831.22 -2,751.341,838.06 2,234,292.83 207,073.07 3.60 2,743.24 3_MWD+IFR1+MS+Sag (2) 3,949.77 43.17 317.19 2,027.34 861.96 -2,781.371,882.84 2,234,324.28 207,043.78 3.99 2,785.36 3_MWD+IFR1+MS+Sag (2) 3,987.89 42.94 318.59 2,055.19 881.26 -2,798.821,910.69 2,234,344.00 207,026.80 2.58 2,810.64 3_MWD+IFR1+MS+Sag (2) 4,025.00 42.94 318.59 2,082.36 900.22 -2,815.541,937.86 2,234,363.36 207,010.54 0.00 2,835.12 PROJECTED to TD Approved By:Checked By:Date: 10/2/2020 4:47:18PM COMPASS 5000.15 Build 91E Page 4 Chelsea Wright Digitally signed by Chelsea Wright Date: 2020.10.02 14:01:54 -08'00'Benjamin Hand Digitally signed by Benjamin Hand Date: 2020.10.05 11:59:54 -08'00' TD Shoe Depth: PBTD: Jts. 2 27 Yes X No X Yes No Fluid Description: Liner hanger Info (Make/Model):Liner top Packer?: Yes X No Liner hanger test pressure:X Yes No Centralizer Placement: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp: X Yes No Casing Rotated? Yes X No Reciprocated?X Yes No % Returns during job Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: Cmt returned to surface: Calculated cement left in wellbore: OH volume Calculated: OH volume actual: Actual % Washout: Casing (Or Liner) Detail Float Shoe 8 5/8 Rotate Csg Recip Csg Ft. Min. PPG9 Shoe @ 1196 FC @ Top of Liner1,116.00 Floats Held 80 38 42 Spud Mud CASING RECORD County State Alaska Supv.Pederson / Riley Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.NINU Kalotsa 5 Date Run 25-Sep-20 Setting Depths Component Size Wt. Grade THD Make Length Bottom Top BTC Innovex 1.50 1,196.06 1,194.56 Csg Wt. On Hook:42,000 Type Float Collar:Innovex No. Hrs to Run:2 94 100 450FIRST STAGE10.5Tuned Prime 39 49.5/51.3 1214 38 Halliburton 15.8 39 Bump press Visual Bump Plug? 3:18 9/26/2020 22 1,196.061,206.00 CEMENTING REPORT Csg Wt. On Slips: Spud Mud 12 41 Type of Shoe:Innovex Casing Crew:Weatherford www.wellez.net WellEz Information Management LLC ver_04818br 4 7 5/8'' Casing jts 7 5/8 29.7 L-80 BTC 76.92 1,194.56 1,117.64 Float Collar 8 5/8 BTC Innovex 1.32 1,117.64 1,116.32 7 5/8'' Casing jts 7 5/8 29.7 L-80 USS-CDC USS-CDC 1,091.57 1,116.32 24.75 7 5/8'' Casing Pup Jt 7 5/8 29.7 L-80 USS-CDC 2.43 24.75 22.32 Hanger 13 5/8 0.92 22.32 21.40 Type III 100 2.4 Class G 210 1.04 4 TD Shoe Depth: PBTD: Jts. 2 72 22 Yes X No X Yes No 50 Fluid Description: Liner hanger Info (Make/Model): Liner top Packer?: Yes No Liner hanger test pressure:X Yes No Centralizer Placement: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp: X Yes No Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface? Yes X No Spacer returns?X Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: Cmt returned to surface: Calculated cement left in wellbore: OH volume Calculated: OH volume actual: Actual % Washout: Type 1 II 205 2.41 Premium G 75 1.24 4.5 19.98 Hanger 10 3/4 DWC/C 0.69 19.98 19.29 934.55 22.55 Pup Jt. 4 1/2 12.6 L-80 DWC/C Vam 2.57 22.55 15.05 949.60 934.55 Casing 4 1/2 12.6 L-80 DWC/C HT Vam 912.00 Pup Jt. 4 1/2 12.6 L-80 DWC/C Vam 955.57 Swell Packer 6 L-80 DWC/C 5.97 955.57 949.60 3,932.09 964.28 Pup Jt. 4 1/2 12.6 L-80 DWC/C Vam 8.71 964.28 1.30 3,933.39 3,932.09 Casing 4 1/2 12.6 L-80 DWC/C HT Vam 2,967.81 Float collar 5 DWC/C Innovex 72 centralizers Casing 4 1/2 12.6 L-80 DWC/C HT Vam 81.67 4,015.06 3,933.39 www.wellez.net WellEz Information Management LLC ver_04818br 3 Type of Shoe:Innovex Casing Crew:WOTC 12 84 4,016.424,025.00 3,932.09 CEMENTING REPORT Csg Wt. On Slips:25,000 6% KCL PHPA 3:25 10/3/2020 945 15.3 17 Bump press CBL Bump Plug? 58/59.8 1198HalliburtonFIRST STAGE10.5Tune spacer 40 9.2 58 99 490 Csg Wt. On Hook:40,000 Type Float Collar:Innovex No. Hrs to Run:7.5 DWC/C Innovex 1.36 4,016.42 4,015.06 Setting Depths Component Size Wt. Grade THD Make Length Bottom Top Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.NINU Kalotsa 5 Date Run 2-Oct-20 CASING RECORD County State Alaska Supv.Pederson / Richardson 3,932.09 Floats Held 80.8 101 0101 6% KCL PHPA Rotate Csg Recip Csg Ft. Min. PPG9.2 Shoe @ 4016.42 FC @ Top of Liner 70 77 10 Casing (Or Liner) Detail Float collar 5 27 of 40 bbls spacer to surface gls - TOC indicated at 900 ft md. Swell Packer 6 L-80 DWC/C 5.97 955.57 949.6 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: 10/30/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL Kalotsa 5 (PTD 219-127) FINAL LWD 09/24/2020 to 10/01/2020 Final Definitive Directional Survey MD/TVD •DGR Dual Gamma Ray •GM Gamma Module •DR Azimuthal Deep Resistivity •ALD Azimuthal Lithodensity •CTN Compensated Thermal Neutron Time Log •GEOTAP Formation Pressures Data Folders: PTD: 2191270 E-Set: 34145 Received by the AOGCC 10/30/2020 Abby Bell 10/30/2020 Z,)l9- 12, David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 CenterPoint Drive, Suite 1400 co Anchorage, AK 99503 Tele: (907) 777-8337 Nillnirp E-mail: david.douglas@hilcorp.com DATE:10/26/2020 To: Alaska Oil & Gas Conservation Commission RECEIVED 333 W 7th Ave Ste 100 i! I "T 2 6 2020 Anchorage, AK 99501 DATA TRANSMITTAL KALOTSA 5 (PTD 219-127) WELL BOX SAMPLE INTERVAL (FEET / MD) KALOTSA 5 BOX 1 OF 2 1200'- 2640' MD KALOTSA 5 BOX 2 OF 2 2640' - 4025' MD (TD) Please include current contact information if different from above. AOGCC Please acknowledge receipt by signing and returning one copy of this transmittal via Email or FAX to: (907) 777-8510 Received8` ;�� Date: 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___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): 4,026'none Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 7,500psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: 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 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: October 13, 2020 4-1/2" 4,017' Perforation Depth MD (ft): none 4,017'2,075'4-1/2" 16" 7-5/8" 120' 1,196' 2,980psi 6,890psi 120' 1,071' 120' 1,196' 12.6# L-80 TVD Burst 950' 8,430psi MDLengthSize CO 701A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 CO61505 / ADL384372 219-127 50-133-20686-00-00 Kalotsa-05 Ninilchik Field; Beluga/Tyonek Gas Pool COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): none ryan.rupert@hilcorp.com 2,082'3,931'2,014'~710 psi none Swell Packer; n/a 950' MD / 896' TVD; n/a Perforation Depth TVD (ft):Tubing Size: m n P 66 t _ Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 8:50 am, Oct 08, 2020 320-425 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.10.07 21:20:39 -08'00' Taylor Wellman X X CTU * 4000 psi BOPE test (CTU ) Perforate Plug Perforations _N2 & patch_______ GAS 10-407 gls 10/8/20 DLB 10/08/2020 (final well report) DSR-10/12/2020Comm. 10/12/2020 dts 10/12/2020 JLC 10/12/2020 Well Prognosis Well: Kalotsa-05 Date: 10/6/2020 Well Name:Kalotsa-05 API Number:50-133-20686-00-00 Current Status:New drill Gas Producer Leg:N/A Estimated Start Date:10/13/20 Rig:e-coil Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:219-127 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) Maximum Expected BHP:~ 913 psi @ 2,025’ TVD (Based on a 0.45 psi/ft gradient) Max. Potential Surface Pressure:~ 710 psi Using Max BHP minus 0.1 psi/ft. gas gradient to surface). Well Summary Kalotsa-05 is a new drill well TD’d 9/29/20. Theobjective of this below intervention is toobtain the requiredCBL and MIT-IA (covered under approved PTD 219-127), and initially complete the well. Notes Regarding Wellbore Condition x Min ID = 3.833” (drift ID of 4-1/2” tubing/liner) x Deviation: o Max = 86 degrees at 1719’ MD o >70 deg from 1450 – 3000’ MD x Well will be filled with 6% KCL x MIT-T to 3500 psi passed on 10/3/20 on rig Safety Concerns - Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. - Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job) - Ensure all crews are aware of stop work authority Pre-perf work:(Covered under approved PTD 219-127) 1. MIT-IA to at least 2000psi. 2. MIRU Coiled Tubing Unit 3. PT BOP equipment to 250 psi Low / 4,500 psi High. (Notify AOGCC 24 hrs. in advance on BOP test.) 4. Makeup memory CBL 5. RIH and log CBL per vendor recommendation from PBTD to surface. a. Obtain a light tag of PBTD, as it’s critical to log all the way to the shoe track 6. Confirm good data, and RD CBL vendor Sundry completion work (e-Coil): (forward CBL log to AOGCC by email prior to perforating) (need CT to run CBL /perf) (chart 30 min .. forward chart to AOGCC) Well Prognosis Well: Kalotsa-05 Date: 10/6/2020 7. MU nozzle, and RIH. 8. RU N2 pumping unit. 9. Blow well dry with N2 taking returns to tanks (~60 bbl WBV) 10. Once well is dry, leave N2 pressure on well per OE for the first perforation interval. 11. POOH w/ coil. LD BHA. 12. RU E-Line Data Acquisition Unit. 13. RU perf guns. Likely 2-3/4” – 3-3/8” guns with 4-6 spf 14. RIH and perforate the below intervals per Geo/RE: Sand MD Top MD Bottom TVD Top TVD Bottom Total Footage (MD) BEL_9 ±2,548'±2,565'±1,394'±1,397'17' BEL_9 ±2,641'±2,685'±1,412'±1,421'44' BEL_10 ±2,751'±2,878'±1,437'±1,471'127' BEL_13 ±2,883'±2,937'±1,472'±1,489'54' BEL_16 ±2,957'±2,968'±1,495'±1,499'11' BEL_16 ±3,002'±3,060'±1,511'±1,531'58' BEL_19 ±3,099'±3,128'±1,546'±1,557'29' BEL_20 ±3,156'±3,173'±1,568'±1,575'17' BEL_23 ±3,197'±3,206'±1,585'±1,589'9' BEL_25 ±3,222'±3,241'±1,596'±1,604'19' BEL_25 ±3,249'±3,257'±1,607'±1,611'8' BEL_30 ±3,289'±3,303'±1,626'±1,632'14' BEL_34 ±3,344'±3,353'±1,652'±1,656'9' BEL_37 ±3,376'±3,392'±1,668'±1,676'16' BEL_38 ±3,423'±3,431'±1,692'±1,696'8' BEL_38 ±3,439'±3,448'±1,700'±1,705'9' BEL_40 ±3,488'±3,494'±1,727'±1,731'6' BEL_40 ±3,509'±3,530'±1,739'±1,751'21' BEL_41 ±3,540'±3,552'±1,757'±1,764'12' BEL_44 ±3,602'±3,612'±1,794'±1,800'10' BEL_44 ±3,621'±3,628'±1,805'±1,809'7' BEL_45 ±3,642'±3,650'±1,818'±1,823'8' BEL_45 ±3,665'±3,672'±1,833'±1,837'7' BEL_45 ±3,681'±3,690'±1,843'±1,848'9' BEL_47 ±3,705'±3,741'±1,858'±1,882'36' BEL_47 ±3,759'±3,790'±1,894'±1,915'31' BEL_47 ±3,808'±3,814'±1,927'±1,931'6' BEL_47 ±3,827'±3,832'±1,940'±1,943'5' BEL_49 ±3,840'±3,848'±1,949'±1,955'8' BEL_49 ±3,853'±3,865'±1,958'±1,967'12' BEL_49 ±3,872'±3,889'±1,972'±1,984'17' BEL_50 ±3,923'±3,947'±2,008'±2,025'24' (review Nitrogen SOP with all personnel on location) (petrospec CTU) Well Prognosis Well: Kalotsa-05 Date: 10/6/2020 a. Consult with OE for what WHP to use for each perf set. Some may be shot while the well is flowing, also. b. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. c.Use Gamma/CCL to correlate. d. CO 701A covers all sands in this well up to and including the B-9. Any perfs above that would require a change to the CO and are NOT allowed to be shot at this time. e. Record initial and 5/10/15 minute tubing pressures after firing f. Consult with RE/Geo between each perf interval: i. Anthony McConkey: RE - 529-6199 ii. Matthew Petrowsky: Geo – 814-421-6753 15. Once sufficient production has been added per RE/Geo, RD E-Line Unit and Coiled Tubing Unit and turn well over to production. 16. CONTINGENT: If a zone is shown to make undesirable sand/water, set plug or patch for shut-off a. MIRU coil tubing unit b. PT BOP equipment to 250 psi Low / 4,500 psi High. (Notify AOGCC 24 hrs. in advance on BOP test.) c. If necessary, displace well with N2 taking returns into open formation d. RU E-Line Data Acquisition Unit. e. MU 4-1/2” patch and/or plug per vendor recommendation f. RIH and set over identified perf interval g. RDMO e-coil Attachments: 1. Proposed Schematic 2. Standard Well procedure – N2 Operations would require a change to the CO and are NOT allowed to be shot at this time. CO 701A covers all sands in this well up to and including the B-9. Any perfs above that Updated by CRR 10-6-20 PROPOSED SCHEMATIC Ninilchik Unit Kalotsa #5 PTD:219-127 API: 50-133-20686-00-00 PBTD = 3,931’ / TVD = 2,014’ TD = 4,026’ / TVD = 2,082’ RKB to GL = 18’ PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD FT Date Status TBD Perfs. See sundry CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 120' 7-5/8"Surf Csg 29.7 L-80 DWC/C 6.875”Surf 1,196’ 4-1/2"Prod Csg 12.6 L-80 DWC/C HT 3.958”Surf 4,017’ 1 16” 7-5/8” 4-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 950’Swell Packer OPEN HOLE / CEMENT DETAIL 7-5/8"41 bbls 12ppg lead + 39 bbls 15.8ppg tail of cement in 9-7/8” hole. 38 bbls returned to surface 4-1/2”84 bbls of Type 1 II lead cmt @ 12 ppg, and 17 bbls of premium G tail cmt @ 15.3 ppg in 6-3/4” hole. 5 bbls lost during cement job. No cement to surface. cement packer MIT-IA to 2000psi Note: High deviation well... >70 deg CBL required, Forward to AOGCC STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. STATE OF ALASKA Reviewed By:— &p' OIL AND GAS CONSERVATION COMMISSION P.1. Supry 1 0 I 7c7G ROPE Test Report for: NINILCHIK UNIT KALOTSA 5 - Comm Contractor/Rig No.: Hilcorp 169 PTD#: 2191270DATE: 9/26/2020 - Inspector Jeff Jones - Insp Source Operator: Hilcorp Alaska, LLC Operator Rep: Peterson / Riley Rig Rep: Davis / DeShotel Inspector Type Operation: DRILL Type Test: INIT Sundry No: Test Pressures: Rams: Annular: Valves: 250/3500' 250/3500 • 250/3500 MASP: 1212' Inspection No: bopJ1200928114639 Related [asp No: TEST DATA MISC. INSPECTIONS: MUD SYSTEM: ACCUMULATOR SYSTEM: P/F Visual Alarm Time/Pressure P/F Location Gen.: _ _ P Trip Tank P P - System Pressure 3040 - P - Housekeeping: P Pit Level Indicators P - P Pressure After Closure 1600 - P " PTD On Location P Flow Indicator P P 200 PSI Attained 25 P Standing Order Posted P Meth Gas Detector P P _ Full Pressure Attained 93 P Well Sign P H2S Gas Detector FP FP Blind Switch Covers: All P Drl. Rig P MS Misc NA NA Nitgn. Bottles (avg): 4 (o) 2400 P ' Hazard Sec. P ACC Misc 1 FP Misc NA FLOOR SAFTY VALVES: BOP STACK: CHOKE MANIFOLD: Quantity P/F Quantity Size P/F Quantity P/F Upper Kelly 1 P Stripper 0 NA No. Valves 15 P Lower Kelly 1 P ' Annular Preventer 1 11 P - Manual Chokes 1 P Ball Type 1 P #1 Rams I 2 7/8x5 P Hydraulic Chokes 1 P Inside BOP 1 P . #2 Rams I " Blind P CH Misc 0 NA FSV Misc 0 NA #3 Rams 1 2 7/8x5 P #4 Rams 0 NA_ #5 Rams 0 NA INSIDE REEL VALVES: #6 Rams 0 NA (Valid for Coil Rigs Only) Choke Ln. Valves 1 31/8 P Quantity P/F HCR Valves 2 ' 3 1/8-2 1/16 ' _ P Inside Reel Valves 0 _ _ NA Kill Line Valves 2 -21/16 P ' Check Valve 0 _ _ _ NA BOP Misc 0 NA Number of Failures: 3 ' Test Results Test Time 6 ✓ Remarks: Parker Drilling personnel performed the tests on Hilcorp's rig #169 today in a safe and proficient manner with 3 failures obseryed. The H2S gas alarm on the dg Floor failed to operate properly and was repaired and passed a retest. The Koomey BOPE control unit failed to automatically maintain manifold pressure. The annular oressure re for and 4-wav valve were replaced and this item passed a retest. The pit volume totalizer and gas detection alarm systems were successfully tested and the rig and surrounding location appeared clean and orderly. David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-5256 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE 10/12/2020 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL KALOTSA 5 (PTD 219-127) FINAL CD – EOW DRILL REPORTS-LWD LOGS-MUDLOGS 09/30/2020 Please include current contact information if different from above. PTD: 2191270 E-Set: 34071 Received by the AOGCC 10/12/2020 Abby Bell 10/12/2020 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): 4,026'none Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 7,500psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: 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 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: October 13, 2020 4-1/2" 4,017' Perforation Depth MD (ft): none 4,017'2,075'4-1/2" 16" 7-5/8" 120' 1,196' 2,980psi 6,890psi 120' 1,071' 120' 1,196' 12.6# L-80 TVD Burst 950' 8,430psi MDLengthSize CO 701A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 CO61505 / ADL384372 219-127 50-133-20686-00-00 Kalotsa-05 Ninilchik Field; Beluga/Tyonek Gas Pool COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): none ryan.rupert@hilcorp.com 2,082'3,931'2,014'~710 psi none Swell Packer; n/a 950' MD / 896' TVD; n/a Perforation Depth TVD (ft):Tubing Size: m n P 66 t _ Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 8:50 am, Oct 08, 2020 320-425 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.10.07 21:20:39 -08'00' Taylor Wellman X X CTU * 4000 psi BOPE test (CTU ) Perforate Plug Perforations _N2 & patch_______ GAS 10-407 gls 10/8/20 DLB 10/08/2020 (final well report) DSR-10/12/2020Comm. 10/12/2020 dts 10/12/2020 JLC 10/12/2020 RBDMS HEW 11/3/2020 Well Prognosis Well: Kalotsa-05 Date: 10/6/2020 Well Name:Kalotsa-05 API Number:50-133-20686-00-00 Current Status:New drill Gas Producer Leg:N/A Estimated Start Date:10/13/20 Rig:e-coil Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:219-127 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) Maximum Expected BHP:~ 913 psi @ 2,025’ TVD (Based on a 0.45 psi/ft gradient) Max. Potential Surface Pressure:~ 710 psi Using Max BHP minus 0.1 psi/ft. gas gradient to surface). Well Summary Kalotsa-05 is a new drill well TD’d 9/29/20. Theobjective of this below intervention is toobtain the requiredCBL and MIT-IA (covered under approved PTD 219-127), and initially complete the well. Notes Regarding Wellbore Condition x Min ID = 3.833” (drift ID of 4-1/2” tubing/liner) x Deviation: o Max = 86 degrees at 1719’ MD o >70 deg from 1450 – 3000’ MD x Well will be filled with 6% KCL x MIT-T to 3500 psi passed on 10/3/20 on rig Safety Concerns - Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. - Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job) - Ensure all crews are aware of stop work authority Pre-perf work:(Covered under approved PTD 219-127) 1. MIT-IA to at least 2000psi. 2. MIRU Coiled Tubing Unit 3. PT BOP equipment to 250 psi Low / 4,500 psi High. (Notify AOGCC 24 hrs. in advance on BOP test.) 4. Makeup memory CBL 5. RIH and log CBL per vendor recommendation from PBTD to surface. a. Obtain a light tag of PBTD, as it’s critical to log all the way to the shoe track 6. Confirm good data, and RD CBL vendor Sundry completion work (e-Coil): (forward CBL log to AOGCC by email prior to perforating) (need CT to run CBL /perf) (chart 30 min .. forward chart to AOGCC) Well Prognosis Well: Kalotsa-05 Date: 10/6/2020 7. MU nozzle, and RIH. 8. RU N2 pumping unit. 9. Blow well dry with N2 taking returns to tanks (~60 bbl WBV) 10. Once well is dry, leave N2 pressure on well per OE for the first perforation interval. 11. POOH w/ coil. LD BHA. 12. RU E-Line Data Acquisition Unit. 13. RU perf guns. Likely 2-3/4” – 3-3/8” guns with 4-6 spf 14. RIH and perforate the below intervals per Geo/RE: Sand MD Top MD Bottom TVD Top TVD Bottom Total Footage (MD) BEL_9 ±2,548'±2,565'±1,394'±1,397'17' BEL_9 ±2,641'±2,685'±1,412'±1,421'44' BEL_10 ±2,751'±2,878'±1,437'±1,471'127' BEL_13 ±2,883'±2,937'±1,472'±1,489'54' BEL_16 ±2,957'±2,968'±1,495'±1,499'11' BEL_16 ±3,002'±3,060'±1,511'±1,531'58' BEL_19 ±3,099'±3,128'±1,546'±1,557'29' BEL_20 ±3,156'±3,173'±1,568'±1,575'17' BEL_23 ±3,197'±3,206'±1,585'±1,589'9' BEL_25 ±3,222'±3,241'±1,596'±1,604'19' BEL_25 ±3,249'±3,257'±1,607'±1,611'8' BEL_30 ±3,289'±3,303'±1,626'±1,632'14' BEL_34 ±3,344'±3,353'±1,652'±1,656'9' BEL_37 ±3,376'±3,392'±1,668'±1,676'16' BEL_38 ±3,423'±3,431'±1,692'±1,696'8' BEL_38 ±3,439'±3,448'±1,700'±1,705'9' BEL_40 ±3,488'±3,494'±1,727'±1,731'6' BEL_40 ±3,509'±3,530'±1,739'±1,751'21' BEL_41 ±3,540'±3,552'±1,757'±1,764'12' BEL_44 ±3,602'±3,612'±1,794'±1,800'10' BEL_44 ±3,621'±3,628'±1,805'±1,809'7' BEL_45 ±3,642'±3,650'±1,818'±1,823'8' BEL_45 ±3,665'±3,672'±1,833'±1,837'7' BEL_45 ±3,681'±3,690'±1,843'±1,848'9' BEL_47 ±3,705'±3,741'±1,858'±1,882'36' BEL_47 ±3,759'±3,790'±1,894'±1,915'31' BEL_47 ±3,808'±3,814'±1,927'±1,931'6' BEL_47 ±3,827'±3,832'±1,940'±1,943'5' BEL_49 ±3,840'±3,848'±1,949'±1,955'8' BEL_49 ±3,853'±3,865'±1,958'±1,967'12' BEL_49 ±3,872'±3,889'±1,972'±1,984'17' BEL_50 ±3,923'±3,947'±2,008'±2,025'24' (review Nitrogen SOP with all personnel on location) (petrospec CTU) Well Prognosis Well: Kalotsa-05 Date: 10/6/2020 a. Consult with OE for what WHP to use for each perf set. Some may be shot while the well is flowing, also. b. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. c.Use Gamma/CCL to correlate. d. CO 701A covers all sands in this well up to and including the B-9. Any perfs above that would require a change to the CO and are NOT allowed to be shot at this time. e. Record initial and 5/10/15 minute tubing pressures after firing f. Consult with RE/Geo between each perf interval: i. Anthony McConkey: RE - 529-6199 ii. Matthew Petrowsky: Geo – 814-421-6753 15. Once sufficient production has been added per RE/Geo, RD E-Line Unit and Coiled Tubing Unit and turn well over to production. 16. CONTINGENT: If a zone is shown to make undesirable sand/water, set plug or patch for shut-off a. MIRU coil tubing unit b. PT BOP equipment to 250 psi Low / 4,500 psi High. (Notify AOGCC 24 hrs. in advance on BOP test.) c. If necessary, displace well with N2 taking returns into open formation d. RU E-Line Data Acquisition Unit. e. MU 4-1/2” patch and/or plug per vendor recommendation f. RIH and set over identified perf interval g. RDMO e-coil Attachments: 1. Proposed Schematic 2. Standard Well procedure – N2 Operations would require a change to the CO and are NOT allowed to be shot at this time. CO 701A covers all sands in this well up to and including the B-9. Any perfs above that Updated by CRR 10-6-20 PROPOSED SCHEMATIC Ninilchik Unit Kalotsa #5 PTD:219-127 API: 50-133-20686-00-00 PBTD = 3,931’ / TVD = 2,014’ TD = 4,026’ / TVD = 2,082’ RKB to GL = 18’ PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD FT Date Status TBD Perfs. See sundry CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 120' 7-5/8"Surf Csg 29.7 L-80 DWC/C 6.875”Surf 1,196’ 4-1/2"Prod Csg 12.6 L-80 DWC/C HT 3.958”Surf 4,017’ 1 16” 7-5/8” 4-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 950’Swell Packer OPEN HOLE / CEMENT DETAIL 7-5/8"41 bbls 12ppg lead + 39 bbls 15.8ppg tail of cement in 9-7/8” hole. 38 bbls returned to surface 4-1/2”84 bbls of Type 1 II lead cmt @ 12 ppg, and 17 bbls of premium G tail cmt @ 15.3 ppg in 6-3/4” hole. 5 bbls lost during cement job. No cement to surface. cement packer MIT-IA to 2000psi Note: High deviation well... >70 deg CBL required, Forward to AOGCC 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. Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Ninilchik Field, Beluga/Tyonek Gas Pool, Kalotsa 5 Hilcorp Alaska, LLC Permit to Drill Number: 219-127 (revised) Surface Location: 2618' FSL, 1514' FEL, Sec 12, T1S, R14W, SM, AK Bottomhole Location: 973' FNL, 2588' FWL, Sec 12, T1S, R14W, 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, Jeremy M. Price Chair DATED this ___ day of September, 2020. y J M P i 1 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 6,249' TVD: 3,914' 4a. Location of Well (Governmental Section):7. Property Designation: Surface: Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date: Total Depth:9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 144.5' 15. Distance to Nearest Well Open Surface: x-209803 y- 2233395 Zone-4 126.5' to Same Pool: 989' to Paxton 9 16. Deviated wells:Kickoff depth: 200 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 80 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Cond 16" 84# X-56 Weld 120' Surface Surface 120' 120' 9-7/8" 7-5/8" 29.7# L-80 DWC/C 1,010' Surface Surface 1,010' 937' 6-3/4" 4-1/2" 12.6# L-80 DWC/C HT 6,249' Surface Surface 6,249' 3,914' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned?Yes No 20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number:50- Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Sr Pet Eng Sr Pet Geo Sr Res Eng Surface Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): 8/18/2020 See cover letter for other requirements. Perforation Depth MD (ft): 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Commission Use Only Effect. Depth MD (ft): Authorized Signature: Production Liner Casing Intermediate L - 234 ft3 / T - 181 ft3 Effect. Depth TVD (ft): Conductor/Structural Length 1559 Total Depth MD (ft):Total Depth TVD (ft): Cement Quantity, c.f. or sacks Cement Volume MDSize Plugs (measured): (including stage data) Driven STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL REVISED 20 AAC 25.005 L - 859 ft3 T - 90 ft3 1212 2618' FSL, 1514' FEL, Sec 12, T1S, R14W, SM, AK 973' FNL, 2588' FWL, Sec 12, T1S, R14W, SM, AK N/A 4762 Kalotsa 5 Ninilchik Field Beluga/Tyonek Gas Pool 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp Alaska, LLC 2120' FSL, 407' FWL, Sec 7, T1S, R13W, SM, AK C061505 / ADL384372 022035244 5009' to nearest unit boundary 9/18/2020 Authorized Name: Monty Myers Authorized Title: Drilling Manager Frank Roach frank.roach@hilcorp.com 777-8413 18. Casing Program:Top - Setting Depth - BottomSpecifications es N os N es No s N o D s s s D o : es No s No es No s ype of W L l R L 1b S Class: 44 well is p G S S 20 S S S S G E S Form 10-401 Revised 3/2020 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) By Samantha Carlisle at 10:56 am, Aug 18, 2020 219-127 revised 133-20686-00-00 9/26/2019 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2020.08.18 10:36:08 -08'00' Monty M Myers X X X gls 8/3120 *3500 psi BOPE test CBL and MIT required post rig. *Sundry approval is required to perforate well' *Diverter waived per 20 AAC25.035 (H)(2) X * X X DSR-8/18/2020 X DLB 08/18/2020ls8888888888//3120 waived per 20 AAC 9/1/2020 Kalotsa #5 Drilling Program Ninilchik Unit Rev 0 August 17th, 2020 Kalotsa #5 Drilling Procedure Contents 1.0 Well Summary ........................................................................................................................... 2 2.0 Management of Change Information ........................................................................................ 3 3.0 Tubular Program:...................................................................................................................... 4 4.0 Drill Pipe Information: .............................................................................................................. 4 5.0 Internal Reporting Requirements ............................................................................................. 5 6.0 Planned Wellbore Schematic ..................................................................................................... 6 7.0 Drilling / Completion Summary ................................................................................................ 7 8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8 9.0 R/U and Preparatory Work ..................................................................................................... 10 10.0 N/U 16” Conductor Riser ........................................................................................................ 10 11.0 Drill 9-7/8” Hole Section .......................................................................................................... 12 12.0 Run 7-5/8” Surface Casing ...................................................................................................... 14 13.0 Cement 7-5/8” Surface Casing ................................................................................................. 17 14.0 BOP N/U and Test.................................................................................................................... 21 15.0 Drill 6-3/4” Hole Section .......................................................................................................... 22 16.0 Run 4-1/2” Production Casing ................................................................................................. 25 17.0 Cement 4-1/2” Production Casing ........................................................................................... 28 18.0 RDMO ...................................................................................................................................... 30 19.0 BOP Schematic ........................................................................................................................ 31 20.0 Wellhead Schematic ................................................................................................................. 32 21.0 Days Vs Depth .......................................................................................................................... 33 22.0 Geo-Prog .................................................................................................................................. 34 23.0 Anticipated Drilling Hazards .................................................................................................. 35 24.0 Saxon Rig 169 Layout .............................................................................................................. 37 25.0 FIT Procedure .......................................................................................................................... 38 26.0 Choke Manifold Schematic ...................................................................................................... 39 27.0 Casing Design Information ...................................................................................................... 40 28.0 6-3/4” Hole Section MASP ....................................................................................................... 41 29.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 42 30.0 Surface Plat (NAD 27) ............................................................................................................. 43 31.0 Directional Plan (wp06) ........................................................................................................... 44 Page 2 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 1.0 Well Summary Well Kalotsa #5 Pad & Old Well Designation Kalotsa #5 is a grass roots well on Kalotsa Pad Planned Completion Type 4-1/2” Production tubing Target Reservoir(s) Beluga Planned Well TD, MD / TVD 6,100 MD / 3,744’ TVD PBTD, MD / TVD 6,020’ MD / 3,674’ TVD Surface Location (Governmental) 2120' FSL, 407' FWL, Sec 7, T1S, R13W, SM, AK Surface Location (NAD 27) X=209803.59, Y=2233395.65 Top of Productive Horizon (Governmental) 2618' FSL, 1514' FEL, Sec 12, T1S, R14W, SM, AK TPH Location (NAD 27) X=207895.32, Y=2233853.89 BHL (Governmental) 973' FNL, 2588' FWL, Sec 12, T1S, R14W, SM, AK BHL (NAD 27) X=206758.51, Y=2235571.40 AFE Number 2013110 AFE Drilling Days 4 MOB, 18 DRLG AFE Completion Days 10 AFE Drilling Amount $3,146,230 AFE Completion Amount $930,000 Maximum Anticipated Pressure (Surface) 1212 psi Maximum Anticipated Pressure (Downhole/Reservoir) 1559 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB – GL 144.5’(126.5 + 18) Ground Elevation 126.5’ BOP Equipment 11” 5M T3-Energy Annular BOP 11” 5M T3-Energy Double Ram 11” 5M T3-Energy Single Ram SFD 8/19/20206,249 MD / 3,914' TVD Page 3 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 2.0 Management of Change Information SFD 8/19/2020 approved in advance by Page 4 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 3.0 Tubular Program: Hole Section OD (in) ID (in) Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 16” 15.01” 14.822 17” 84 J-55 Weld 2980 1410 - 9-7/8” 7-5/8” 6.875” 6.75” 8.5” 29.7 L-80 DWC/C 6890 4790 683 6-3/4” 4-1/2” 3.958” 3.833” 5.0” 12.6 L-80 DWC/C HT 8430 7500 288 4.0 Drill Pipe Information: Hole Section OD (in) ID (in) TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 4-1/2” 3.826 2.6875” 5.25” 16.6 S-135 CDS40 17,693 16,769 468k All casing will be new Page 5 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellez. x Report covers operations from 6am to 6am x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry tab. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. 5.2 Afternoon Updates x Submit a short operations update each work day to Frank.Roach@hilcorp.com, mmyers@hilcorp.com and cdinger@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. Each rig will be assigned a username to login with. 5.4 EHS Incident Reporting x Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don’t wait until an emergency to have to call around and figure it out!!!! a. John Coston: O: (907) 777-6726 C: (907) 227-3189 b. Matt Hogge: O: (907) 777-8418 C: (907) 227-9829 2. Spills: Keegan Fleming: O:907-777-8477 C:907-350-9439 x Notify Drlg Manager 1. Monty M Myers: O: 907-777-8431 C: 907-538-1168 x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to Frank.Roach@hilcorp.com and cdinger@hilcorp.com 5.6 Casing and Cmt report x Send casing and cement report for each string of casing to Frank.Roach@hilcorp.com and cdinger@hilcorp.com Page 6 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 6.0 Planned Wellbore Schematic MIT-IA 2000 psi post rig CBL required Page 7 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 7.0 Drilling / Completion Summary Kalotsa #5 is a S-shaped directional grassroots development well to be drilled off of the Kalotsa pad. Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the Beluga sands. The base plan is a directional wellbore with a kick off point at 300’ MD. Maximum hole angle will be 80° and TD of the well will be 6,249’ MD/ 3,914’ TVD, ending with 33° inclination left in the hole. Vertical section will be 3,743 ft. Drilling operations are expected to commence approximately September 18th, 2020. The Hilcorp Rig # 169 will be used to drill the wellbore then run casing and cement. Surface casing will be run to 1,010’ MD / 936’ TVD and cemented to surface to ensure protection of any shallow freshwater resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed, a Temp log will be run between 6 – 18 hrs after CIP to determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All waste & mud generated during drilling and completion operations will be hauled to the 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 conductor riser. (No diverter, diverter waiver requested) 3. Drill 9-7/8” hole to 1,010’ MD. Run and cmt 7-5/8” surface casing. 4. ND conductor riser, N/U & test 11” x 5M Townsend BOP. 5. Drill 6-3/4” hole section to 6,249’ MD. Perform Wiper trip. 6. Make cleanout run 7. POOH laying down drill pipe. 8. Run and cmt 4-1/2” production casing. 9. N/D BOP, N/U temp abandonment cap, RDMO. Reservoir Evaluation Plan: 1. Surface hole: GR + Res (LWD) 2. Production Hole: GR + Res + Den/Neu (LWD). 3. Mud loggers from surface casing point to TD. Page 8 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling of Kalotsa #5. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/2500 psi & subsequent tests of the BOP equipment will be to 250/2500 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. x If the BOP is used to shut in on the well in a well control situation, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements” x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. Regulation Variance Requests: x Diverter waiver requested due to the recent drilling of Kalotsa #1, Kalotsa #2, Kalotsa #3 and Kalotsa #4 nearby (~50’ away). No issues were experienced while drilling the surface hole. Surface casing for these wells were set at 1500’ TVD. Surface casing is requested to be set at 1,250’ TVD on Kalotsa #5. No shallow hydrocarbon zones will be penetrated. Page 9 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 9-7/8” x No diverter utilized n/a 6-3/4” x 11” x 5M Annular BOP x 11” x 5M Double Ram o Blind ram in btm cavity x Mud cross x 11” x 5M Single Ram x 3-1/8” 5M Choke Line x 2-1/16” x 5M Kill line x 3-1/8” x 2-1/16” 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/2500 (Annular 2500 psi) Subsequent Tests: 250/2500 (Annular 2500 psi) x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Additional requirements may be stipulated on APD and Sundry. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov Guy Schwartz / Petroleum Engineer / (O): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / Email: melvin.rixse@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email: victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 10 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 9.0 R/U and Preparatory Work 9.1 Set 16” conductor at +/-120’ below ground level. 9.2 Dig out and set impermeable cellar. 9.3 Install 16-3/4” 3M “A” section. Ensure to orient wellhead so that tree will line up with flowline later. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of rig. 9.6 R/U Hilcorp Rig # 169, spot service company shacks, spot & R/U company man & toolpusher offices. 9.7 RU Mud loggers on surface hole section for gas detection only. No samples required 9.8 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.9 Mix mud for 9-7/8” hole section. 9.10 Install 5-1/2” liners in mud pumps. x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes with 5-1/2” liners 10.0 N/U 16” Conductor Riser 10.1 N/U 16” Conductor Riser x Ensure line does not direct flow from trip tank straight down the flowline. Fill up line and flowline should be oriented 90 degrees to each other at approx. the same height. x Ensure flowline outlet installed so that enough slope exists to carry cuttings to the shakers. x Consider adding additional drainage points at the bottom of the conductor riser if deemed necessary. x R/U fill up line to conductor riser. 10.2 Set wear bushing in wellhead. Page 11 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 10.3 Rig Orientation on Kalotsa pad: Page 12 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 11.0 Drill 9-7/8” Hole Section 11.1 P/U 9-7/8” directional drilling assy: x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Workstring will be 4.5” 16.6# S-135 CDS40 11.2 9-7/8” BHA (GR and Res are included in BHA): 11.3 PU 9-7/8” bit, 4-1/2” HWDP, Jars, & Workstring 11.4 Begin drilling out from 16” conductor at reduced flow rates to avoid broaching the conductor. 11.5 Drill 9-7/8” hole section to 1,010’ MD/ 936’ TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate. x Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team. x Keep swab and surge pressures low when tripping. x Make wiper trips every 500’ or every couple days unless hole conditions dictate otherwise. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. x TD the hole section in a good shale between 1000’ MD and 1200’ MD. x Take MWD surveys every stand drilled (60’ intervals). 11.6 9-7/8” hole mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. System Type: 8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Page 13 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 120-1900’ 8.8 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0 System Formulation: Aquagel + FW spud mud Product Concentration FRESH WATER SODA ASH AQUAGEL CAUSTIC SODA BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT ALDACIDE G X-TEND II 0.905 bbl 0.5 ppb 12-15 ppb 0.1 ppb (9 pH) as needed as required for weight if required for <12 FL 0.1 ppb 0.02 ppb 11.7 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16” conductor shoe. 11.8 TOH with the drilling assy, handle BHA as appropriate. Page 14 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 12.0 Run 7-5/8” Surface Casing 12.1 R/U and pull wear-bushing. 12.2 R/U Weatherford 7-5/8” casing running equipment. x Ensure 7-5/8” DWC x CDS 40 XO on rig floor and M/U to FOSV. x R/U fill-up line to fill casing while running. x Ensure all casing has been drifted on the location prior to running. x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ float shoe bucked on (thread locked). x (1) Joint with coupling thread locked. x (1) Joint with float collar bucked on pin end & thread locked. x Install (2) centralizers on shoe joint over a stop collar. 10’ from each end. x Install (1) centralizer, mid tube on thread locked joint and on FC joint. x Ensure proper operation of float equipment. 12.5 Continue running 7-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x M/U connections to the base of the triangle stamped on the pin end. Note M/U torque values required to achieve this position. x After making up several connections, use the torque required to M/U to base of triangle as the M/U torque and continue running string. x Install (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the event a top out job is needed. x Utilize a collar clamp until weight is sufficient to keep slips set properly. 7-5/8” DWC Estimated M/U Torque Casing OD Minimum Maximum Yield Torque 7-5/8” 21,700 ft-lbs 25,100 ft-lbs 28,500 ft-lbs Page 15 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 Page 16 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.7 Slow in and out of slips. 12.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 12.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 12.11 After circulating, lower string and land hanger in wellhead again. Page 17 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 13.0 Cement 7-5/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Cementers equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface. x Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. 13.2 Document efficiency of all possible displacement pumps prior to cement job 13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.4 Pump 5 bbls 10 ppg spacer. Test surface cmt lines. 13.5 Pump remaining 30 bbls of 10 ppg spacer. 13.6 Drop bottom plug. Mix and pump cmt per below recipe. 13.7 Cement volume based on annular volume + 50% open hole excess. Job will consist of lead & tail, TOC brought to surface. Page 18 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 SURFACE CEMENT CALCULATIONS CSG BTM (ft) 1,848 CSG Size 7 5/8 Section: Calculation: Vol (BBLS) Vol (ft3) LEAD: 120’ x .162 bpf = 19.45 109.2 16” Conductor x 7-5/8” Casing annulus: LEAD: (510’ – 120’) x .038 bpf x 1.5 = 22.23 124.8 9-7/8” OH x 7-5/8” Casing annulus: Total LEAD: 41.68 234.0 TAIL: (1,010’-510’) x .038 bpf x 1.5 = 28.50 160.0 9-7/8” OH x 7-5/8” Casing annulus: TAIL: 80 x .046 bpf = 3.67 20.6 7-5/8” Shoe track: Total TAIL: 32.17 180.6 Total Cement: 73.85 414.6 Cement Slurry Design: Lead Slurry (510’ MD to surface) Tail Slurry (1010’ to 510’ MD) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.46 ft3/sk 1.22 ft3/sk Mixed Water 14.349 gal/sk 5.507 gal/sk Mixed Fluid 14.469 gal/sk 5.507 gal/sk Additives Code Description Concentration Code Description Concentration G Cement 94#/sk A Cement 94#/sk D110 Retarder 0.15 gal/sk BWOC D046 Anti Foam 0.2 % BWOC D046 Anti Foam 0.2 % BWOC D065 Dispersant 0.4 % BWOC D079 Extender 2.0 % BWOC S002 CaCl2 0.35 % BWOC D020 Extender 3.0 % BWOC D177 CaCl2 0.1 % BWOC Page 19 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat and continue with the cement job. 13.9 After pumping cement, drop top plug and displace cement with spud mud. 13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.11 Displacement calculation: 1010’- 80’ = 930’ x .046 bpf = 43 bbls 13.12 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.13 Do not over-displace by more than ½ shoe track volume. Total volume in shoe track is 3.7 bbls. x Be prepared for cement returns to surface. If cmt returns are not observed to surface, be prepared to run a temp log between 12 – 18 hours after CIP. x Be prepared with small OD top out tubing in the event a top out job is required. The AOGCC will require us to run steel pipe through the hanger flutes. The ID of the flutes is 1.5”. 13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 13.15 R/D cement equipment. Flush out wellhead with FW. 13.16 Back out and L/D landing joint. Flush out wellhead with FW. 13.17 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. Page 20 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 13.18 Lay down landing joint and pack-off running tool. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com, Frank.Roach@hilcorp.com, and mmyers@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 21 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 14.0 BOP N/U and Test 14.1 N/U wellhead assy. Install 7-5/8” packoff P-seals. Test to 3000 psi. 14.2 N/U 11” x 5M T3-Energy BOP as follows: x BOP configuration from Top down: 11” x 5M T3-Energy annular BOP/11” x 5M T3-Energy Model 6011i double ram /11” x 5M mud cross/11” x 5M T3-Energy Model 6011i single ram x Double ram should be dressed with 2-7/8 x 5” VBRs in top cavity, blind ram in btm cavity. x Single ram should be dressed with 2-7/8 x 5” VBRs. x N/U bell nipple, install flowline. x Install (1) manual valves & (1) HCR valve on kill side of mud cross. x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 14.3 Run 4-1/2” BOP test assy, land out test plug (if not installed previously). x Test BOP to 250/2500 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. x Ensure to leave “B” section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.4 R/D BOP test assy. 14.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.6 Mix 9.0 ppg 6% KCL PHPA mud system. 14.7 R/U mud loggers for production hole section. 14.8 Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section. Page 22 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 15.0 Drill 6-3/4” Hole Section 15.1 Pull test plug, run and set wear bushing 15.2 Ensure BHA components have been inspected previously. 15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 15.4 TIH, Conduct shallow hole test of MWD and confirm Gamma Ray and Resistivity LWD functioning properly. 15.5 Ensure TF offset is measured accurately and entered correctly into the MWD software. 15.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. 15.7 Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 15.8 6-3/4” BHA: 15.9 6-3/4” hole section mud program summary: Weighting material to be used for the hole section will be salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. System Type: 9.0 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 1,010’- 6,249’ 9.0 – 9.5 40-53 15-25 15-25 8.5-9.5 11.0 Note: EMW needed at 3914' TVD at T.D. is 7.7 ppg. DLB 08/18/2020 Page 23 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 System Formulation: 6% KCL EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for a 9.0 – 10.0 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 15.10 TIH w/ 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. 15.11 R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst. 7-5/8” burst is 6890 psi / 2 = 3445 psi. 15.12 Drill out shoe track and 20’ of new formation. 15.13 CBU and condition mud for FIT. 15.14 Conduct FIT to 13.5 ppg EMW. Note: Offset field test data predicts frac gradient at the 7-5/8” shoe to be between 11 - 13 ppg EMW. A 13.5 ppg FIT results in a 4 ppg kick margin while drilling with the planned MW of 9.5 ppg. Kick tolerance = (13.5-9.5)X(936/3914) = 0.95 15.15 Drill 6-3/4” hole section to 6,249’ MD / 3,914’ TVD x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 225 - 300 gpm. Ensure shaker screens are set up to handle this flowrate. x Keep swab and surge pressures low when tripping. x Make wiper trips every 500’ unless hole conditions d ictate otherwise. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed necessary. 15.16 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8” shoe. Page 24 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 15.17 POOH LDDP and BHA 15.18 4-1/2” pipe rams previously installed in BOP stack and tested. Page 25 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 16.0 Run 4-1/2” Production Casing 16.1. R/U Weatherford 4-1/2” casing running equipment. x Ensure 4-1/2” DWC/C HT x CDS 40 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill casing while running. x Ensure all casing has been drifted prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.2. P/U shoe joint, visually verify no debris inside joint. 16.3. Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). x (1) joint casing, threadlocked (coupling also thread locked) x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x Solid body centralizers will be pre-installed on shoe joint an FC joint. x Leave centralizers free floating so that they can slide up and down the joint. x Ensure proper operation of float shoe and float collar. x Utilize a collar clamp until weight is sufficient to keep slips set properly 16.4. Continue running 4-1/2” production casing x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install solid body centralizers on every joint to 1,600’ MD. x Install solid body centralizers on every other joint from 1,600’ MD to 7-5/8” shoe. Leave the centralizers free floating. x Pick up swell packer and place in string at approximately 760’ MD. 16.5. Continue running 4-1/2” production casing 4-1/2” DWC/C HT M/U torques Casing OD Minimum Maximum Yield Torque 4-1/2” 5,800 ft-lbs 6,500 ft-lbs 8,400 ft-lbs Page 26 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 Page 27 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 16.6. Run in hole w/ 4-1/2” casing to the 7-5/8” casing shoe. 16.7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole dictates. 16.8. Obtain slack off weight, PU weight, rotating weight and torque of the casing. 16.9. Circulate 2X bottoms up at shoe, ease casing thru shoe. 16.10. Continue to RIH w/ casing no faster than 1 jt./minute. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.11. Set casing slowly in and out of slips. 16.12. PU swell packer to be placed at approximately 760’. Swell packer should have 10’ handling pups installed on both ends with bow spring centralizers on pups. 16.13. Swedge up and wash last 2 joints to bottom. P/U 5’ off bottom. Note slack-off and pick-up weights. 16.14. Stage pump rates up slowly to circulating rate. Circ and condition mud with casing on bottom. Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the shakers are clean. Reduce the low end rheology of the drilling fluid by adding water and thinners. 16.15. Reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 28 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 17.0 Cement 4-1/2” Production Casing 17.1. Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Cementers equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. x Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. x Document efficiency of all possible displacement pumps prior to cement job. 17.2. Attempt to reciprocate the casing during cmt operations until hole gets sticky 17.3. Pump 5 bbls of 10.5 ppg Mud Push spacer. 17.4. Test surface cmt lines to 4500 psi. 17.5. Pump remaining 30 bbls 10.5 ppg Mud Push spacer. 17.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed weight. Job is designed to pump 20% OH excess. Page 29 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 Production CEMENT CALCULATIONS CSG BTM (ft) 6,249 CSG Size 4 1/2 Section: Calculation: Vol (BBLS) Vol (ft3) LEAD: (1,010'-510') x .026 bpf = 13.12 73.7 7-5/8" x 4-1/2" Casing annulus: LEAD: (5,749’ – 1,010’) x .025 bpf x 1.20 = 139.84 785.1 6-3/4" OH x 4-1/2" Casing annulus: Total LEAD: 152.96 858.8 TAIL: (6,249’-5,749’) x .025 bpf x 1.20 = 14.75 82.8 6-3/4" OH x 4-1/2" Casing annulus: TAIL: 80 x .015 bpf = 1.22 6.8 4-1/2” Shoe track: Total TAIL: 15.97 89.7 Total Cement: 168.93 948.5 17.7. Drop wiper plug and displace with 6% KCl 17.8. If hole conditions allow – continue reciprocating casing throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 17.9. If elevated displacement pressures are encountered, position casing at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 17.10. Bump the plug and pressure up to 500 psi over final lift pressure. Hold pressure for 3 minutes. 17.11. Do not over-displace by more than ½ shoe track. Shoe track volume is 1.2 bbls. 17.12. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 17.13. RD cementers and flush equipment. Page 30 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 17.14. WOC minimum of 12 hours, test casing to 3500 psi and chart for 30 minutes. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to Frank.Roach@hilcorp.com and mmyers@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 18.0 RDMO 18.1. Install BPV in wellhead 18.2. N/D BOPE 18.3. N/U temp abandonment cap 18.4. RDMO Hilcorp Rig #169 gls NOTE: CBL and MIT -IA to 2000 psi required post rig. May not perforate well until sundry approval and AOGCC has reviewed CBL Page 31 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 19.0 BOP Schematic Page 32 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 20.0 Wellhead Schematic Page 33 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 21.0 Days Vs Depth Page 34 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 22.0 Geo-Prog Page 35 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 23.0 Anticipated Drilling Hazards 9-7/8” Hole Section: Lost Circulation: Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Maintain YP between 25 – 45 to optimize hole cleaning and control ECD. Wellbore stability: Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity. Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP of ~50 - ~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200’ of drilling to reduce the likelihood of washing out the conductor shoe. To help insure good cement to surface after running the casing, condition the mud to a YP of 25 –30 prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be achieved. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. Page 36 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 6-3/4” Hole Section: Lost Circulation: Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP between 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. H2S: H2S is not present in this hole section. No abnormal temperatures are present in this hole section. DLB 08/18/2020 Page 37 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 24.0 Hilcorp Rig 169 Layout Page 38 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 25.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 39 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 26.0 Choke Manifold Schematic Page 40 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 27.0 Casing Design Information Page 41 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 28.0 6-3/4” Hole Section MASP Page 42 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 29.0 Spider Plot (NAD 27) (Governmental Sections) Page 43 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 30.0 Surface Plat (NAD 27) Page 44 Version 0 August, 2020 Kalotsa #5 Drilling Procedure Rev 0 31.0 Directional Plan (wp07) !"# -275 0 275 550 825 1100 1375 1650 1925 2200 2475 2750 3025 3300 3575 3850 4125True Vertical Depth (550 usft/in)0 275 550 825 1100 1375 1650 1925 2200 2475 2750 3025 3300 3575 3850 Vertical Section at 304.17° (550 usft/in) Kalotsa 5 wp09 Beluga 135 Kalotsa 5 wp07 Beluga 10 7 5/8" x 9-7/8" 4 1/2" x 6-3/4" 5 0 0 10001500200025003000350040004 5 0 0 5 00 0 5 5 0 0 6 0 0 0 6 2 4 9 Kalotsa 5 Wp10 Start Dir 4º/100' : 200' MD, 200'TVD Start Dir 6º/100' : 400' MD, 399.35'TVD End Dir : 1000' MD, 929.8' TVD Start Dir 6º/100' : 1040' MD, 958.57'TVD End Dir : 1640' MD, 1235.65' TVD Start Dir 3.5º/100' : 2640' MD, 1409.29'TVD End Dir : 4661.08' MD, 2584.19' T Total Depth : 6249.25' MD, 3914.15' TVD Beluga 1 Beluga 10 Beluga 45 Beluga 47A Beluga 52 Beluga 53A Beluga 58A Beluga 52 Beluga 59 Beluga 70 Beluga 72 Beluga 82 Beluga 134 Beluga 134A Beluga 135 Beluga 136 Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: Kalotsa 5 126.50 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2233395.65 209803.59 60° 6' 14.081 N 151° 35' 25.264 W SURVEY PROGRAM Date: 2019-08-13T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.00 1010.00 Kalotsa 5 Wp10 (Kalotsa 5) 3_MWD+IFR1+MS+Sag 1010.00 6249.25 Kalotsa 5 Wp10 (Kalotsa 5) 3_MWD+IFR1+MS+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 1141.50 997.00 1346.70 Beluga 1 1419.50 1275.00 2694.47 Beluga 10 1799.50 1655.00 3611.37 Beluga 45 1850.50 1706.00 3693.55 Beluga 47A 2066.50 1922.00 4009.16 Beluga 52 2066.50 1922.00 4009.16 Beluga 52 2138.50 1994.00 4106.21 Beluga 53A 2327.50 2183.00 4348.81 Beluga 58A 2383.50 2239.00 4418.20 Beluga 59 2494.50 2350.00 4553.44 Beluga 70 2530.50 2386.00 4596.79 Beluga 72 2711.50 2567.00 4813.11 Beluga 82 3520.50 3376.00 5779.17 Beluga 134 3555.50 3411.00 5820.97 Beluga 134A 3584.50 3440.00 5855.60 Beluga 135 3650.50 3506.00 5934.41 Beluga 136 REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Kalotsa 5, True North Vertical (TVD) Reference:As-Built @ 144.50usft (HEC 169) Measured Depth Reference:As-Built @ 144.50usft (HEC 169) Calculation Method:Minimum Curvature Project:Ninilchik Unit Site:Kalotsa Well:Kalotsa 5 Wellbore:Kalotsa 5 Design:Kalotsa 5 Wp10 Ninilchik Unit Kalotsa Kalotsa 5 Kalotsa 5 Kalotsa 5 Wp10 6.049 CASING DETAILS TVD TVDSS MD Size Name 936.99 792.49 1010.00 7-5/8 7 5/8" x 9-7/8" 3914.15 3769.65 6249.25 4-1/2 4 1/2" x 6-3/4" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 18.00 0.00 0.00 18.00 0.00 0.00 0.00 0.00 0.00 2 200.00 0.00 0.00 200.00 0.00 0.00 0.00 0.00 0.00 Start Dir 4º/100' : 200' MD, 200'TVD 3 400.00 8.00 282.00 399.35 2.90 -13.64 4.00 282.00 12.91 Start Dir 6º/100' : 400' MD, 399.35'TVD 4 1000.00 44.00 282.00 929.80 56.69 -266.70 6.00 0.00 252.50 End Dir : 1000' MD, 929.8' TVD 5 1040.00 44.00 282.00 958.57 62.47 -293.88 0.00 0.00 278.24 Start Dir 6º/100' : 1040' MD, 958.57'TVD 6 1640.00 80.00 282.00 1235.65 170.81 -803.59 6.00 0.00 760.82 End Dir : 1640' MD, 1235.65' TVD 7 2640.00 80.00 282.00 1409.29 375.56 -1766.88 0.00 0.00 1672.83 Start Dir 3.5º/100' : 2640' MD, 1409.29'TVD 8 4661.08 33.13 351.96 2584.19 1242.36 -2975.11 3.50 147.05 3159.34 End Dir : 4661.08' MD, 2584.19' TVD 9 5830.52 33.13 351.96 3563.50 1875.25 -3064.55 0.00 0.00 3588.77 Kalotsa 5 wp09 Beluga 135 10 6249.25 33.13 351.96 3914.15 2101.86 -3096.57 0.00 0.00 3742.53 Total Depth : 6249.25' MD, 3914.15' TVD 023346770093311671400163318672100South(-)/North(+) (350 usft/in)-3267 -3033 -2800 -2567 -2333 -2100 -1867 -1633 -1400 -1167 -933 -700 -467 -233 0West(-)/East(+) (350 usft/in)Kalotsa 5 wp09 Beluga 1357 5/8" x 9-7/8"4 1/2" x 6-3/4"2505007501000125015001750200022502500275030003250350037503914Kalotsa 5 Wp10Start Dir 4º/100' : 200' MD, 200'TVDStart Dir 6º/100' : 400' MD, 399.35'TVDEnd Dir : 1000' MD, 929.8' TVDStart Dir 6º/100' : 1040' MD, 958.57'TVDEnd Dir : 1640' MD, 1235.65' TVDStart Dir 3.5º/100' : 2640' MD, 1409.29'TVDEnd Dir : 4661.08' MD, 2584.19' TVDTotal Depth : 6249.25' MD, 3914.15' TVDProject: Ninilchik UnitSite: KalotsaWell: Kalotsa 5Wellbore: Kalotsa 5Plan: Kalotsa 5 Wp10WELL DETAILS: Kalotsa 5126.50+N/-S +E/-W NorthingEastingLatittude Longitude0.000.002233395.65209803.5960° 6' 14.081 N 151° 35' 25.264 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Kalotsa 5, True NorthVertical (TVD) Reference:As-Built @ 144.50usft (HEC 169)Measured Depth Reference:As-Built @ 144.50usft (HEC 169)Calculation Method:Minimum CurvatureCASING DETAILSTVD TVDSS MD Size Name936.99 792.49 1010.00 7-5/8 7 5/8" x 9-7/8"3914.15 3769.65 6249.25 4-1/2 4 1/2" x 6-3/4" 03006009001200150018002100240027003000South(-)/North(+) (450 usft/in)-3300 -3000 -2700 -2400 -2100 -1800 -1500 -1200 -900 -600 -300 0 300 600West(-)/East(+) (450 usft/in)500100015002000250030003 5 0 0 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 5 0 0 7 0 0 0 7 5 0 0 7958Kalotsa 4250030003480Paxton #95001000150020002500300035004000450050005500600065007 0 0 075007857 Kalotsa 2500100015002000250030003500400045005000550060006500700075007773Kalotsa 1500100015002000250030003500400045005000Kalotsa 3500100015002000250030003500Kalotsa 65 0 0 100015002000250030003500Kalotsa 7 wp065001000150020002500300035003914Kalotsa 5 Wp10Azimuths to True NorthMagnetic North: 14.42°Magnetic FieldStrength: 54914.7nTDip Angle: 72.94°Date: 9/20/2020Model: BGGM2020TMProject: Ninilchik UnitSite: KalotsaWell: Kalotsa 5Wellbore: Kalotsa 5Plan: Kalotsa 5 Wp10-127 -63 0 63 127West(-)/East(+) (95 usft/in)063127South(-)/North(+) (95 usft/in)Kalotsa 450015002000Kalotsa 2500Kalotsa 1Kalotsa 3500Kalotsa 65 0 0 Kalotsa 7 wp06500Kalotsa 5 Wp10 $ % & ' ( )*+ ( , , -& ." !"#$$%&'()#*+, + -#& +,./0 1 .+ ( !"#$$%&'()#*+, ! 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" ( - / . + " 5(7 9 567 :%" 567 324' 5(7 . ! 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eparation Factor0 350 700 1050 1400 1750 2100 2450 2800 3150 3500 3850 4200 4550 4900 5250 5600 5950 6300Measured DepthNo-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:Kalotsa 5 NAD 1927 (NADCON CONUS)Alaska Zone 04126.50+N/-S +E/-W Northing Easting Latittude Longitude0.000.00 2233395.65 209803.59 60° 6' 14.081 N 151° 35' 25.264 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Kalotsa 5, True NorthVertical (TVD) Reference:As-Built @ 144.50usft (HEC 169)Measured Depth Reference:As-Built @ 144.50usft (HEC 169)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2019-08-13T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool18.00 1010.00 Kalotsa 5 Wp10 (Kalotsa 5) 3_MWD+IFR1+MS+Sag1010.00 6249.25 Kalotsa 5 Wp10 (Kalotsa 5) 3_MWD+IFR1+MS+Sag0.0035.0070.00105.00140.00175.00Centre to Centre Separation (60.00 usft/in)0 350 700 1050 1400 1750 2100 2450 2800 3150 3500 3850 4200 4550 4900 5250 5600 5950 6300Measured DepthKalotsa 4Kalotsa 2Kalotsa 1Kalotsa 3Kalotsa 6Kalotsa 7 wp06GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference18.00 To 6249.25Project: Ninilchik UnitSite: KalotsaWell: Kalotsa 5Wellbore: Kalotsa 5Plan: Kalotsa 5 Wp10Ladder / S.F. PlotsCASING DETAILSTVD TVDSS MD Size Name936.99 792.49 1010.00 7-5/8 7 5/8" x 9-7/8"3914.15 3769.65 6249.25 4-1/2 4 1/2" x 6-3/4" 1 Carlisle, Samantha J (CED) From:Frank Roach <Frank.Roach@hilcorp.com> Sent:Monday, August 31, 2020 1:56 PM To:Schwartz, Guy L (CED) Cc:Monty Myers; Cody Dinger Subject:Proposed change to (PTD 219-127) Kalotsa #5 Guy, Thankyouforthephonecallearliertoday.Aswediscussed,youarecorrectinthattheresubmittalofthepermitwas duetoanXYchangeof>500feet.Belowisaplanviewthatillustratesthedifferencebetweenthe2019permitted wellpath(red)andtherevised,2020proposedwellpath(blue): Pleaseletmeknowifyouneedanyadditionalinformation. Regards, FrankVRoach DrillingEngineer 907.854.2321(c) 907.777.8413(o) The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 2 Revised 2/2015 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: ____________________________ POOL: ______________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit No. _____________, API No. 50-_______________________. Production should continue to be reported as a function of the original API number stated above. Pilot Hole 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 name (_______________________PH) and API number (50-_____________________) from records, data and logs acquired for well (name on permit). Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. (_____________________________) as Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for well ( ) until after ( ) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (________________________) must contact the AOGCC to obtain advance approval of such water well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (_______________________________) in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Kalotsa 5 219-127 REVISED X Ninilchik Beluga/Tyonek Gas X X WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:NINILCHIK UNIT KALOTSA 5Initial Class/TypeDEV / 1-GASGeoArea820Unit51432On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2191270NINILCHIK, BELUGA-TYONEK GAS - 562503NA1 Permit fee attachedYes Surface Location lies within Fee_CIRI; Top Prod Int & TD lie within ADL0384372.2 Lease number appropriateYes NINILCHIK, BELUGA-TYONEK GAS – 562503, governed by CO 701C3 Unique well name and numberYes Rule 3 (Well Spacing) There shall be no gas well spacing restrictions within the Affected Area, except:4 Well located in a defined poolYes A) No gas well shall be drilled or completed less than 1,500 feet from the exterior boundary of the5 Well located proper distance from drilling unit boundaryYes Affected Area unless the owner and landowner is the same on both sides of the line.6 Well located proper distance from other wellsYes B) No gas well shall be drilled or completed less than 1,500 feet from an uncommitted tract within the7 Sufficient acreage available in drilling unitYes Ninilchik Unit unless the well and the uncommitted tract both lie within the same Participating Area.8 If deviated, is wellbore plat includedYes As planned, this well conforms to CO 701C, Rule 3 (Well Spacing).9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For servNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 16" conductor set at 120 ft.18 Conductor string providedYes Surface casing set at 1250 ft TVD19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes 4.5" longstring will be cemented back to Surf casing … also using swell packer at 1600 ft.21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes BTC calcs supplied.23 Casing designs adequate for C, T, B & permafrostYes Rig 169 has steel pits . All waste to approved disposal well.24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes No issues26 Adequate wellbore separation proposedYes Diverter Waived per 20 AAC 25.035(h)(2) . Nearest well 750 ft away27 If diverter required, does it meet regulationsYes Max formation pressure = 1707 psi ( 8.7 ppg EMW) Drill with 9.0-9.5 ppg mud28 Drilling fluid program schematic & equip list adequateYes 169 has 5000 psi WP BOPE29 BOPEs, do they meet regulationYes MASP = 1328 psi Will test BOPE to 2500 psi30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes Separate sundry to perforate well.32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S is not anticipated based on nearby wells.35 Permit can be issued w/o hydrogen sulfide measuresYes Maximum expected reservoir pressure is 8.7 ppg EMW; however, most sands encountered are expected36 Data presented on potential overpressure zonesNA to be depleted to severely depleted. Production interval will be drilled using 9.0 to 9.5 ppg mud.37 Seismic analysis of shallow gas zonesNA Additional materials will be onsite to build mud to 1 ppg more than the greatest anticipated mud weight.38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprDLBDate8/31/2020ApprGLSDate9/1/2020ApprDLBDate8/31/2020AdministrationEngineeringGeologyGeologic Commissioner:DTSDate:Engineering Commissioner:JLCDatePublic CommissionerDateCement packer well… need CBL to verify TOC . MIT-IA required post rig. Gls . Revised PTD due to moving BHL by more than 500 ft. glsJLC 9/1/2020Daniel T. Seamount, Jr.Digitally signed by Daniel T. Seamount, Jr. Date: 2020.09.01 13:50:26 -08'00'JMP9/1/2020 THE STATE 9 1 1 A - Falls] W441 k 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 www.aogcc.alaska.gov Re: Ninilchik Field, Beluga/Tyonek Gas Pool, Kalotsa 5 Hilcorp Alaska, LLC Permit to Drill Number: 219-127 Surface Location: 2120' FSL, 407' FWL, SEC. 7, TIS, RI 3W, SM, AK Bottomhole Location: 1768' FSL, 1574' FWL, SEC. 12, TIS, RI 4W, 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, )0 Daniel T. Seamount, Jr. Commissioner DATED thisZ (' day of September, 2019. ri- q,:rra b ^n 7 {qrr' (e V J STATE OF ALASKA ' ALAorCA OIL AND GAS CONSERVATION COMMIb_.ON SEP 16 3019 PERMIT TO DRILL 20 AAC 25.005 1 a. Type of Work: Drill 0 ' Lateral ❑ Redrill ❑ Reentry ❑ 1b. Proposed Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service - Disp ❑ Stratigraphic Test ❑ Development - Oil ❑ Service - Winj ❑ Single Zone 0 Exploratory - Oil ❑ Development - Gas Q Service -Supply ❑ Multiple Zone ❑ 1 c. Specify if well is prppgsed for: Coalbed Gas ❑ Gas Hydrates ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: Hilcorp Alaska, LLC 5. Bond: Blanket Q • Single Well ❑ Bond No. 022035244 11. Well Name and Number: Kalotsa 5 ' 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 6. Proposed Depth: MD: 6,100' TVD: 3,744' 12. Field/Pool(s): Ninilchik Field Beluga/Tyonek Gas Pool 4a. Location of Well (Governmental Section): Surface: 2120' FSL, 407' FWL, Sec 7, T1 S, R13W, SM, AK Top of Productive Horizon: 2186' FSL, 151' FEL, Sec 12, T1 S, R1 4W, SM, AK Total Depth: 1768' FSL, 1574' FWL, Sec 12, T1 S, R14W, SM, AK 7. Property Designation: C061505 / ADL384372 - 8. DNR Approval Number: N/A 13. Approximate Spud Date: 10/20/2019 9. Acres in Property: 4762 14. Distance to Nearest Property: 3724' to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): Surface: x-209803 y- 2233395 Zone -4 10. KB Elevation above MSL (ft): 144.5' ' GL / BF Elevation above MSL (ft): 126.5' 15. Distance to Nearest Well Open to Same Pool: 1566' to Paxton 7 16. Deviated wells: Kickoff depth: 200 feet Maximum Hole Angle: 80 degrees 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Downhole: 1707 ' Surface: 1328 ' 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling I Length MD TVD MD TVD (including stage data) Cond 16" 84# X-56 Weld 120' Surface Surface 120' 120' Driven 9-7/8" 7-5/8" 29.7# L-80 DWC/C 1,848' Surface Surface 1,848' 1,250' L - 505 ft3 / T - 182 ft3 6-3/4" 4-1/2" 12.6# L-80 DWC/C HT 6,100' Surface Surface 6,100' 3,744' L - 695 ft3 T - 90 ft3 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Hydraulic Fracture planned? Yes ❑ No ❑Q 20. Attachments: Property Plat ❑ BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch e Seabed Report ❑ Drilling Fluid Program ❑✓ 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: d1orm hilcor .Com Authorized Title: Drilling Manger Contact Phone: 777-8333 Authorized Signature: Date: 4. 11' 17 Commission Use Only Permit to Drill G Number: � I �' API Number: 50- I33"` Permit Approva Date: ?j� ` See cover letter for other requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Er Other:SSU 'QST ��' P �• ? Samples req'd: Yes E] No [R" Mud log req'd: Yes ❑ No EK _ A rG H2S measures: Yes ❑ No[� Directional svy req'd: Yes No El '0k- C_ 8_ ` I _ l ' Spacing exception req'd: Yes ❑ No[ r Inclination -only svy req'd: Yes ❑ No ,_t r- 0 / Z V_ f �' w Z/ n Post initial injection MIT req'd: Yes ElNo El /46 PP �r APPROVED BY C� I r� Approved by: COMMISSIONER THE COMMISSION Date: 1 Submit Form and Form to-4ot Reaise / 17�/D'^ /This permit is valid o 2 o t r e f ap val per AAC 25.00 ttachments in Dunlicate Hilcorp Alaska, LLC Kalotsa #5 Drilling Program Ninilchik Unit Rev 0 August 28th, 2019 Hilcorp Energy company Contents Kalotsa #5 Drilling Procedure 1.0 Well Summary.................................................................................................................................2 2.0 Management of Change Information............................................................................................3 3.0 Tubular Program: ........................................................................................................................... 4 4.0 Drill Pipe Information: ................................................................................................................... 4 5.0 Internal Reporting Requirements..................................................................................................5 6.0 Planned Wellbore Schematic..........................................................................................................6 7.0 Drilling / Completion Summary.....................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications.....................................................................8 9.0 R/U and Preparatory Work..........................................................................................................10 10.0 N/U 16" Conductor Riser..............................................................................................................10 11.0 Drill 9-7/8" Hole Section...............................................................................................................12 12.0 Run 7-5/8" Surface Casing...........................................................................................................15 13.0 Cement 7-5/8" Surface Casing.....................................................................................................18 14.0 BOP N/U and Test.........................................................................................................................22 15.0 Drill 6-3/4" Hole Section...............................................................................................................23 16.0 Run 4-1/2" Production Casing.....................................................................................................26 17.0 Cement 4-1/2" Production Casing...............................................................................................29 18.0 RDMO............................................................................................................................................31 19.0 BOP Schematic..............................................................................................................................32 20.0 Wellhead Schematic......................................................................................................................33 21.0 Days Vs Depth................................................................................................................................34 22.0 Geo-Prog.........................................................................................................................................35 23.0 Anticipated Drilling Hazards.......................................................................................................36 24.0 Saxon Rig 169 Layout...................................................................................................................38 25.0 FIT Procedure................................................................................................................................39 26.0 Choke Manifold Schematic...........................................................................................................40 27.0 Casing Design Information...........................................................................................................41 28.0 6-3/4" Hole Section MASP............................................................................................................42 29.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................43 30.0 Surface Plat (NAD 27)...................................................................................................................44 31.0 Directional Plan (wp06)................................................................................................................45 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp Energy Company 1.0 Well Summary Well Kalotsa 45 ' Pad & Old Well Designation Kalotsa #5 is a grass roots well on Kalotsa Pad Planned Completion Type 4-1/2" Production tubing Target Reservoir(s) Beluga ' Planned Well TD, MD / TVD 6,100 MD / 3,744' TVD PBTD, MD / TVD 6,020' MD / 3,674' TVD Surface Location (Governmental) 2120' FSL, 407' FWL, Sec 7, TIS, R13W, SM, AK Surface Location (NAD 27) X=209803.59, Y=2233395.65 Surface Location (NAD 83) X=1349822.91, Y=2233154.88 Top of Productive Horizon (Governmental) 2186' FSL, 151' FEL, Sec 12, TIS, R14W, SM, AK TPH Location (NAD 27) X=209247.62, Y=2233389.62 TPH Location (NAD 83) X=1349266.94, Y=2233148.81 BHL (Governmental) 1768' FSL, 1574' FWL, Sec 12, TIS, R14W, SM, AK BHL (NAD 27) X=205684.17, Y=2233057.05 ' BHL (NAD 83) X=1345703.51, Y=2232815.98 AFE Number AFE Drilling Days 4.MOB, 18 DRLG AFE Completion Days AFE Drilling Amount $3,143,072 AFE Completion Amount $400,000 Maximum Anticipated Pressure (Surface) 1328 psi ' Maximum Anticipated Pressure (Downhole/Reservoir) , 1707 psi Work String 4-1/2" 16.64 S-135 CDS-40 RKB — GL 144.5'(126.5 + 18) . Ground Elevation 126.5' ' BOP Equipment 11" 5M T3 -Energy Annular BOP 11" 5M T3 -Energy Double Ram 11" 5M T3 -Energy Single Ram Page 2 Version 0 August, 2019 j Kalotsa #5 Drilling Procedure Rev 0 Hilcorp Energy Company 2.0 Management of Change Information 11 Hilcorp Alaska, LLC Hilcorp Changes to Approved Permit to Drill Date: August 8t', 2019 Subject: Changes to Approved Permit to Drill for Kalotsa #5 File #: Kalotsa #5 Drilling and Completion Program Any modifications to Kalotsa #5 Drilling & Completion Pro ram will be documented and approved below. Changes to an approved AFD will be co cate BLM and AOGCC. Sec Page Date Procedure Change Approved Approved By By Approval: Drilling Manager Date Prepared: David Gorm Drilling Engineer Date Page 3 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp Energy Company 3.0 Tubular Program: Hole Section OD (in) ID (in) Drift (j4L_ Conn , OD (in) Wt (#/ft(psi) Grade Conn Burst I Collapse Tension (k -lbs) Cond 16" 15.01" 14.822 17" 84 J-55 Weld 2980 1410 - 9-7/8" 7-5/8" 6.875" 6.75" 8.5" 29.7 L-80 DwaC 6890 4790 683 6-3/4" 4-1/2" 3.958" 3.833" 5.0" 12.6 L-80 DwC/C HT 8430 7500 288 4.0 Drill Pipe Information: Hole OD (in) Section ID (in) TJ ID in TJ OD in Wt #/ft Grade Conn Burst si)(psi) Collapse Tension k -lbs) All 4-1/2" 3.826 2.6875" 5.25" 16.6 5-135 CDS40 17,693 16,769 468k All casing will be new Page 4 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp Energy Company 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellez. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry tab. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. 5.2 Afternoon Updates • Submit a short operations update each work day to daormghilcow.com, mm.yers(i�hilcorp.com and cdinger@hilcoM.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. Each rig will be assigned a username to login with. 5.4 EHS Incident Reporting • Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don't wait until an emergency to have to call around and figure it out!!!! a. John Coston: O: (907) 777-6726 C: (907) 227-3189 b. Matt Hogge: O: (907) 777-8418 C: (907) 227-9829 2. Spills: Keegan Fleming: 0:907-777-8477 C:907-350-9439 Notify Drlg Manager 1. Monty M Myers: O: 907-777-8431 C: 907-538-1168 Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally • Send final "As -Run" Casing tally to dgornighilcorp.com and cdin eg_r(a,hilcorp.com 5.6 Casing and Cmt report • Send casing and cement report for each string of casing to dizortn@hilcoM.com and cdingerghilcorp.com Page 5 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp Energy Company 6.0 Planned Wellbore Schematic N€nilrhik Unit PROPOSED SCHEMATIC Kal°tsa#5 PTD: 1 BD API_ TBD RKStoGL=18' CASING DETAIL 16' G3; _ PHTD = 6,020` / TVD = 3,725' TD = 6,100' / TV D = 3,794' size Type Wt Grade Conn_ ID Top MM 16„ Carxlu3or-Oriven to Set Depth 84 k-56 Weld ISM, Surf 120' 7-5/8' Surf 29.7 L -W MWC 6.875" Surf 1.w 4-1 ' Prod 126 L-80 DWCJC w 3958" Surf 6,1w I JEWELRY DETAIL r Na. DE ID OD Item 1 �lo q't 1 1648 3.958" 6.675" Swell Packer SWru Plvf. OPEN HOLE jCEMENTDETAIL 122 Mrs uttm-n-•ntin9-7/rhale- Returns tosurface UE;e�essl 4,112' 1 139 BBL's d cement in 6-3 4" hale- E-st TDC @D 1348 2096 exm-m LL7� ^ Page 6 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp Energy Company 7.0 Drilling / Completion Summary Kalotsa #5 is a S-shaped directional grassroots development well to be drilled off of the Kalotsa pad. Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the Beluga sands. The base plan is a directional wellbore with a kick off point at 300' MD. Maximum hole angle will be 80° and TD of the well will be 6,100' MD/ 3,743' TVD, ending with 30° inclination left in the hole. Vertical section will be 4,087 ft. Drilling operations are expected to commence approximately October 20th, 2019. The Hilcorp Rig # 169 will be used to drill the wellbore then run casing and cement. Surface casing will be run to 1,848' MD / 1,250' TVD and cemented to surface to ensure protection of any shallow freshwater resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface ✓ are not observed, a Temp log will be run between 6 —18 hrs after CIP to determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All waste & mud generated during drilling and completion operations will be hauled to the 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 conductor riser. (No diverter, diverter waiver requested) 3. Drill 9-7/8" hole to 1,848' MD. Run and curt 7-5/8" surface casing. 4. ND conductor riser, N/U & test 11" x 5M Townsend BOP. 3 Dr' 5. Drill 6-3/4" hole section to 5,814' MD. Perform Wiper trip. 6. Make cleanout run 7. POOH laying down drill pipe. 8. Run and cmt 4-1/2" production casing. 9. N/D BOP, N/U temp abandonment cap, RDMO. Reservoir Evaluation Plan: 1. Surface hole: GR + Res + Den/Neu (L)VD) 2. Production Hole: GR + Res + Den/Neu (LWD). 3. Mud loggers from surface casing point to TD. Page 7 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp Energy Company 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 of Kalotsa #5. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. �. J/ry • The initial test of BOP equipment will be to 2501.'�-W psi & subsequent tests of the BOP equipment will be to 250/2, si for 5/10 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • 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. Regulation Variance Requests: Diverter waiver requested due to the recent drilling of Kalotsa #1, Kalotsa #2, Kalotsa #3 and Kalotsa #4 nearby (-50' away). No issues were experienced while drilling the surface hole. Surface casing for these wells were set at 1500' TVD. Surface casing is requested to be set at 1,250' TVD on Kalotsa #5. No shallow hydrocarbon zones will be penetrated. ,rte � �-� �.c,`,.•n.1 Page 8 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp Energy Company Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) 9-7/8" • No diverter utilized n/a • 11" x 5M Townsend Annular BOP 3 50-0 • 11" x 5M Townsend Double Ram Initial Test: 250/6501 o Blind ram in btm cavity (Annular 2500 psi) • Mud cross 6-3/4" • 11" x 5M Townsend Single Ram • 3-1/8" 5M Choke Line Subsequent Tests: 250/x.599 3 )wt' • 2-1/16" x 5M Kill line 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. a Any other notifications required in APD. Additional requirements may be stipulated on APD and Sundry. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: jim.regg@alaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz@alaska.gov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / Email: melvin.rixse@alaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotifhtml Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp Energy Company 9.0 R/U and Preparatory Work 9.1 Set 16" conductor at +/-120' below ground level. 9.2 Dig out and set impermeable cellar. 9.3 Install 16-3/4" 3M "A" section. Ensure to orient wellhead so that tree will line up with flowline later. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of rig. 9.6 R/U Hilcorp Rig # 169, spot service company shacks, spot & R/U company man & toolpusher offices. 9.7 RU Mud loggers on surface hole section for gas detection only. No samples required 9.8 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.9 Mix mud for 9-7/8" hole section. 9.10 Install 5-1/2" liners in mud pumps. • HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes with 5-1/2" liners 10.0 N/U 16" Conductor Riser 10.1 NIU 16" Conductor Riser • Ensure line does not direct flow from trip tank straight down the flowline. Fill up line and flowline should be oriented 90 degrees to each other at approx. the same height. • Ensure flowline outlet installed so that enough slope exists to carry cuttings to the shakers. • Consider adding additional drainage points at the bottom of the conductor riser if deemed necessary. • R/U fill up line to conductor riser. 10.2 Set wear bushing in wellhead. Page 10 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hi1COIp Energy Company 10.3 Rig Orientation on Kalotsa pad: Page 11 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp Energy Company 11.0 Drill 9-7/8" Hole Section 11.1 P/U 9-7/8" 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. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Workstring will be 4.5" 16.64 S-135 CDS40 11.2 9-7/8" BHA (GR and Res are included in below BHA): ` COMPONENT Ran # 1 DATA Description Serial 9-7'8' PDC Number .D (in) 6.020 10 (in) 2.250 Gauge Weight (in) tlbp* 9.875 83.45 Top Clorkr=tfon P 4-1+2" REG Length (it) 0.89 Length: (ft) 0.89 2 7" SperryDrill Lobe 718 - 7.5 stg 7.000 4.952 95.69 B 4-112" IF 30.00 30.89 Stabilizer 9.625 3 6-314" Integral Blade 9 114" 6.760 2.500 9.750 105.59 B 4-112" IF 6.99 37.88 4 6-34" Float Sub 6.800 2.375 108.67 B 4-112" IF 3.00 40.88 5 614" DM Collar (Directional) 6.720 3.125 103.40 B 4-112" IF 9.20 50.08 6 6 314" DGR Collar (Gamma) 6.710 1.920 97.80 B 44.2" IF 6.50 56.58 7 6 14" EWR-P4 Collar (Resistivity) 6.710 2.000 104.30 B 4-112" IF 12.00 68.58 8 6 14" PWD Collar (Pressure) 6.720 1.905 96.30 B 4-1!2" IF 4.44 73.02 9 6 3.4" HCIM Collar (Processor) 6.750 1.920 101.70 B 4-1I2" IF 6.50 79.52 10 6 14"TM Collar (Telemetry) 6.550 3250 103.60 B 4-112" IF 9.90 89.42 11 6.75" NM Flex Collar 6.450 2.875 8923 B 4-1!2" IF 30.00 119.42 12 X -Over Sub 4-112 IF x CDS 40 6.450 2.625 92.91 B 4.40CDS 3.00 122.42 13 3 jts 4-112" HWDP 4.500 2.813 36.86 93.00 215.42 14 X -Over Sub CDS 40 x 4-112 IF 6.300 2.625 87.79 B 4-1l2" IF 3.00 218.42 15 6414" Weatherford Jar 6.270 2250 91.68 B 442" IF 30.00 248.42 16 X -Over Sub 4-V2 IF x CDS 40 6230 2.625 1 85.44 113 4.5" CDS40 3.00 251.42 17 5 jts 4-1I2" HWDP 4.500 2.813 1 36.86 1 1 155.00 406.42 - 406.42 Page 12 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp Energy Company 11.3 PU 9-7/8" bit, 4-1/2" HWDP, Jars, & Workstring 11.4 Begin drilling out from 16" conductor at reduced flow rates to avoid broaching the conductor. 11.5 Drill 9-7/8" hole section to 1,848' MD/ 1,250' TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Pump at 500 - 550 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. • 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. • TD the hole section in a good shale between 1700' MD and 1900' MD. • Take MWD surveys every stand drilled (60' intervals). v 11.6 9-7/8" hole mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg. - Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. System Type: 8.8 — 9.5 ppg Pre -Hydrated Aquagel/freshwater spud mud Properties: De the Density Viscosity Plastic Viscosity Yield Point I API FI. H 120-1900' 1 8.8-9.5-1 85-150 1 20-40 25-45 1 510 18.5-9.0 Page 13 Version 0 August, 2019 Hilcorp Energy Company 11.7 11.8 Kalotsa #5 Drilling Procedure Rev 0 System Formulation: Aquagel + FW spud mud Product Concentration FRESH WATER 0.905 bbl SODA ASH 0.5 ppb AQUAGEL 12-15 ppb CAUSTIC SODA 0.1 ppb (9 pH) BARAZAN D+ as needed BAROID 41 as required for weight PAC -L /DEXTRID LT if required for <12 FL ALDACIDE G 0.1 ppb X -TEND Il 0.02 ppb At TD; pump sweeps, CBU, and pull a wiper trip back to the 16" conductor shoe. TOH with the drilling assy, handle BHA as appropriate. Page 14 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp Energy Company 12.0 Run 7-5/8" Surface Casing 12.1 R/U and pull wear -bushing. 12.2 R/U Weatherford 7-5/8" casing running equipment. • Ensure 7-5/8" DWC 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 7-5/8" 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. • 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. 7-5/8" DWC Estimated M/U Torque Casing OD Minimum Maximum Yield Torque 7-5/8" 21,700 ft -lbs 25,100 ft -lbs 28,500 ft -lbs Page 15 Version 0 August, 2019 Hilcorp Energy Company Connection Type. DWC/C Casing STANDARD Technical Specifications Size(©.D.): Weight (Wall): 7-5/8 in 29.70 Ib/ft (0.375 in) Material L-80 Grade 80,000 Minimum Yield Strength (psi.) 95,000 Minimum Ultimate Strength (psi.) Connection Performance Properties 683,000 Pipe Dimensions 7.625 Nominal Pipe Body O.D. (in.) 6.875 Nominal Pipe Body I.D. (in.) 0.375 Nominal Wall Thickness (in.) 29.70 Nominal Weight (lbs./ft.) 29.06 Plain End Weight (lbs./ft.) 8.541 Nominal Pipe Body Area (sq. in.) Connection Performance Properties 683,000 Pipe Body Performance Properties 683;000 Minimum Pipe Body Yield Strength (lbs.) 4,790 Minimum Collapse Pressure (psi.) 6,890 Minimum Internal Yield Pressure (psi.) 6,300 Hydrostatic Test Pressure (psi.) Connection Performance Properties 683,000 Connection Dimensions 8.500 Connection O.D. (in.) 6.875 Connection I.D. (in.) 6.750 Connection Drift Diameter (in.) 4.69 Make-up Loss (in.) 8.541 Critical Area (sq. in.) 100.0 Joint Efficiency (%) Connection Performance Properties 683,000 Joint Strength (lbs.) 16,430 Reference String Length (ft) 1.4 Design Factor 721,000 API Joint Strength (lbs.) 342,000 Compression Rating (lbs.) 4,790 API Collapse Pressure Rating (psi.) 6,890 API Internal Pressure Resistance (psi.) 24.0 Maximum Uniaxial Bend Rating [degrees/100 ft] Approximated Field End Torque Values 21,700 Minimum Final Torque (ft. -lbs.) 25,100 Maximum Final Torque (ft.-Ibs.) 28,500 Connection Yield Torque (ft. -lbs.) Kalotsa #5 Drilling Procedure Rev 0 Grade: L-80 "Sam �!"U SA VAM USA 4424 W. Sam Houston Pkw, y. Suite 150 Houston, TX 77041 Phone: 713-479-3200 Fax: 713-479-3234 E-mail: VAMUSAsales(c-�vam-usa.com Page 16 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hi1COIp EneW Cmpmy 12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.7 Slow in and out of slips.` 12.8 P!U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 12.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 12.11 After circulating, lower string and land hanger in wellhead again. Page 17 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp Energy Company 13.0 Cement 7-5/8" Surface Casing 13.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. • Pump 20 bbls of freshwater through all of Cementers equipment, taking returns to cuttings bin, prior to pumping any fluid downhole • How to handle cmt returns at surface. • 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. 13.2 Document efficiency of all possible displacement pumps prior to cement job 13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.4 Pump 5 bbls 10 ppg spacer. Test surface cmt lines. SP/41-rtz- 13.5 Pump remaining 30 bbls of 10 ppg spacer. 13.6 Drop bottom plug. Mix and pump cmt per below recipe. 13.7 Cement volume based on annular volume + 50% open hole excess. Job will consist of lead & tail, TOC brought to surface. r, Page 18 Version 0 August, 2019 / Hi1Corp Energy Company Kalotsa #5 Drilling Procedure Rev 0 SURFACE CEMENT CALCULATIONS Extended CSG 75/8 CSG BTM (ft) 1,848 Size Section: Calculation: Vol Vol f 2.46 ft3/sk (BBLS) (ft3) LEAD: 14.349 gal/sk 16" Conductor x 7-5/8" 120' x .162 bpf = 19.45 109.2 Casing annulus: 5.507 gal/sk LEAD: Code Description Concentration Code (1,348'— 120') x.046 bpf x 1.5 Concentration 9-7/8" OH x 7-5/8" G 70.46 395.6 Casing annulus: Cement 94#/sk Total LEAD: D110 89.91 504.8 D046 TAIL: 0.2 % BWOC Additives D046 (1,848'-1,348') x.038 bpf x 1.5 0.2 % BWOC D065 9-7/8" OH x 7-5/8" 28.69 161.1 Casing annulus: Extender 2.0 % BWOC 5002 TAIL: 0.35 % BWOC D020 80 x .046 bpf = 3.67 20.6 7-5/8" Shoe track: 0.1 % BWOC Total TAIL: 32.36 181.7 Total Cement: I V 122.27,'1 686.5 1 "0Lf s¢ I`t F .5x Cement Slurry Design: Lead Slurry (1348' MD to surface) Tail Slurry (1348' to 1848' MD) System Extended Conventional Density 12 Ib/gal 15.4 Ib/gal Yield f 2.46 ft3/sk 1.22 ft3/sk Mixed Water 14.349 gal/sk 5.507 gal/sk Mixed Fluid 14.469 gal/sk 5.507 gal/sk Code Description Concentration Code Description Concentration G Cement 94#/sk A Cement 94#/sk D110 Retarder 0.15 gal/sk BWOC D046 Anti Foam 0.2 % BWOC Additives D046 Anti Foam 0.2 % BWOC D065 Dispersant 0.4 % BWOC D079 Extender 2.0 % BWOC 5002 CaC12 0.35 % BWOC D020 Extender 3.0 % BWOC D177 CaC12 0.1 % BWOC Page 19 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp EneW Company 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets "sticky", land the hanger on seat and continue with the cement job. 13.9 After pumping cement, drop top plug and displace cement with spud mud. 13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.11 Displacement calculation: I/ 1848'- 80' = 1768' x.046 bpf = 81 bbls 13.12 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.13 Do not over -displace by more than 1/2 shoe track volume. Total volume in shoe track is 3.7 bbls. Be prepared for cement returns to surface. If cmt returns are not observed to surface, be prepared to run a temp log between 12 — 18 hours after CIP. k) a c C.. -cam Be prepared with small OD top out tubing in the event a top out job is required. The AOGCC will require us to run steel pipe through the hanger flutes. The ID of the flutes is 1.5". 13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 13.15 R/D cement equipment. Flush out wellhead with FW. 13.16 Back out and L/D landing joint. Flush out wellhead with FW. 13.17 M/U pack -off running tool and pack -off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. Page 20 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp Energy Company 13.18 Lay down landing joint and pack -off running tool. Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface & volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the success or problems during the cement job Send final "As -Run "casing tally & casing and cement report to cdin eerrkhilcorp. com and mm ers ,hilcorp. com. This will be included with the EOW documentation that goes to the AOGCC. Page 21 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp Energy Company 14.0 BOP N/U and Test 14.1 N/U wellhead assy. Install 7-5/8" packoff P -seals. Test to 3000 psi. 14.2 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 601 li double ram /11" x 5M mud cross/11" x 5M T3 -Energy Model 601 li 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. 14.3 Run 4-1/2" BOP test assy, land out test plug (if not installed previously). p • Test BOP to 2501 for 5/10 min. Test annular to 250/2500 psi for 5/10 min. • Ensure to leave "B" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.4 R/D BOP test assy. 14.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.6 Mix 9.0 ppg 6% KCL PHPA mud system. 14.7 R/U mud loggers for production hole section. J 14.8 Rack back as much 4-1/2" DP in derrick as possible to be used while drilling the hole section. Page 22 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp EneW Company 15.0 Drill 6-3/4" Hole Section 15.1 Pull test plug, run and set wear bushing 15.2 Ensure BHA components have been inspected previously. 15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 15.4 TIH, Conduct shallow hole test of MWD and confirm Gamma Ray and Resistivity LWD functioning properly. 15.5 Ensure TF offset is measured accurately and entered correctly into the MWD software. 15.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. 15.7 Workstring will be 4.5" 16.6# S-135 CDS40. Ensure to have enough 4-1/2" DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 15.8 6-3/4" BHA: COMPONENTDATA 0 1 Description HDSS MMD64 .. (in) 4.750 (in) 1.500 Cwd 6.750 (Ibpf) 54.37 Connection P 3-u2- REG (110 0.80 Cumut Length j 0.80 2 4 3/4' SperryDr01 Lobe 516 - 8.3 stg 4.750 2.794 44.57 B 312" IF 26.70 27.50 Stabilizer &.375 3 4 3!4" NM integral Blade Stabikzer 4.750 2.313 6.500 46.07 8 31,"2" IF 5.60 33.10 4 4 314- DM Collar (Directional) 4.750 2.610 47.00 B 3-1,2" IF 9.18 4228 5 4 3'4' PWD 25KSI (Pressure) 4.750 1.250 47.90 B NC 38 923 51.51 6 Inline Stabilizer (ILS) 4350 1250 6.500 5621 B 3- 1 2' IF 3.00 54.51 7 4 314" SP4 (Resistivity/Gamma) • 4.750 1.250 48.20 B NC 38 22,50 77.02 8 Inline Stabilizer (ILS) 4.750 1.250 6.500 56.21 B 3-112" IF 3.00 80.02 9 4 3/4• ALD Collar (Density) 4.750 1250 6.375 45.50 B NC 38 14.35 94.37 Stabilizer 6.375 10 4 314' CTN Collar (Porosity) 4,750 1.250 50.50 B NC 38 11.14 105.51 11 4 3'4" TM Collar (Telemetry) 4.750 2.812 46.10 8 NC 38 10.86 11&.37 12 4-314" NM Flex 4.750 2.313 46.07 B 312" IF 30.00 146.37 13 4 314" NM Flex 4.750 2.313 46.07 B 3-112' IF 30.00 176.37 14 4 314" NM Flex 4.750 2.313 46.07 B 3.12" IF 30.00 206.37 15 4 34• Float Sub 4.750 2250 46.84 B 3- uZ IF 2.50 208.87 16 4 112' IF P to XT -39 B XO Sub 4.750 2.500 43.66 B 4- XT39 1.67 210.54 17 1 i14- HWDP XT -39 4.000 2.563 2524 31.50 242.04 18 4 V4' Hydraulic Jar 4.635 2.250 43.95 B 4" XT39 29.30 271.34 19 4 its 4- HW DP XT -39 4.000 2.563 25.24 126.00 397.34 20 4" DP XT -39 4.000 3.240 14.73 31.50 428.84 428.84 Page 23 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp Energy company 15.9 6-3/4" hole section mud program summary: Weighting material to be used for the hole section will be salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. System Type: 9.0 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: System Formulation: 6% KCL EZ Mud DP Product Mud Water Plastic KCl 22 ppb (29 K chlorides) Caustic NM BARAZAN D+ Viscosity EZ MUD DP Yield Point pH HPHT PAC -L Weight BARACARB 5/25/50 15 - 20 ppb (5 ppb of each) BAROID 41 as required for a 9.0 —10.0 ppg ALDACIDE G 1.848'- 5.814' 9.0-9.5 40-53 15-25 15-25 8.5-9.5 < 11.0 System Formulation: 6% KCL EZ Mud DP Product Concentration Water 0.905 bbl KCl 22 ppb (29 K chlorides) Caustic 0.2 ppb (9 pH) BARAZAN D+ 1.25 ppb (as required 18 YP) EZ MUD DP 0.75 ppb (initially 0.25 ppb) DEXTRID LT 1-2 ppb PAC -L 1 ppb BARACARB 5/25/50 15 - 20 ppb (5 ppb of each) BAROID 41 as required for a 9.0 —10.0 ppg ALDACIDE G 0.1 ppb BARACOR 700 1 ppb BARASCAV D 0.5 ppb (maintain per dilution rate 15.10 TIH w/ 6-3/4" directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. 15.11 R/U and test casing to,1506'psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst. 7-5/8" burst is 6890 psi / 2 = 3445 psi. 15.12 Drill out shoe track and 20' of new formation. 15.13 CBU and condition mud for FIT. Page 24 Version 0 August, 2019 ./ Hilcorp EneW Company Kalotsa #5 Drilling Procedure Rev 0 15.14 Conduct FIT to 12.5 ppg EMW. ✓ D U-1 - Kick tolerance = (12.5-9.5)X(1250/3794) = 0.98 <� 15.15 Drill 6-3/4" hole section to 6,100' MD / 3,794' TVD • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Pump at 225 - 300 gpm. Ensure shaker screens are set up to handle this flowrate. • Keep swab and surge pressures low when tripping. • Make wiper trips every 500' 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 HTHP fluid loss < 10. • Take MWD surveys every 100' drilled. Surveys can be taken more frequently if deemed necessary. 15.16 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8" shoe. 15.17 POOH LDDP and BHA 15.18 4-1/2" pipe rams previously installed in BOP stack and tested. Page 25 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp Energy Company 16.0 Run 4-1/2" Production Casing 16.1. R/U Weatherford 4-1/2" casing running equipment. • Ensure 4-1/2" DWC/C HT x CDS 40 crossover on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure all casing has been drifted prior to running. • Be sure to count the total # of joints 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. 16.2. P/U shoe joint, visually verify no debris inside joint. 16.3. Continue M/U & thread locking shoe track assy consisting of: • (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). • (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). • Solid body centralizers will be pre-installed on shoe joint an FC joint. Leave centralizers free floating so that they can slide up and down the joint. Ensure proper operation of float shoe and float collar. Utilize a collar clamp until weight is sufficient to keep slips set properly 16.4. Continue running 4-1/2" production 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 solid body centralizers on every joint to 5,300' MD. • Install solid body centralizers on every other joint to 7-5/8" shoe. Leave the centralizers free floating. Pick up swell packer and place in string at approximately 1,648' MD. 16.5. Continue running 4-1/2" production casing 4-1/2" DWC/C HT M/U torques Casing OD Minimum Maximum Yield Torque 4-1/2" 5,800 ft -lbs 6,500 ft -lbs 7,200 ft -lbs Page 26 Version 0 August, 2019 Hilcorp EncW Company Connection Type: DWC/C Tubing standard Kalotsa #5 Drilling Procedure Rev 0 Technical Specifications Size(O.D.): Weight (Wall): 41/2 in 12.60 lb/ft (0.271 in) Material L-80 Grade 80,000 Minimum Yield Strength (psi) 95,000 Minimum Ultimate Strength (psi) Appoximated Field End Torque Values 5,800 Minimum Final Torque (ft -lbs) 6,500 Maximum Final Torque (ft -lbs) 7,200 Connection Yield Torque (ft -lbs) Grade: L-80 AAM USA VAM USA 4424 W. Sam Houston Pkwy. Suite 1501 Houston. TX 770141 Phone: 713-479-3200 Fax: 713479-3234 E-majl: VAMUSAsales yam-usaxom Page 27 Version 0 August, 2019 Pipe Dimensions 4.500 Nominal Pipe Body O.D. (in) 3.958 Nominal Pipe Body I.D.(in) 0.271 Nominal Wall Thickness (in) 12.60 Nominal Weight (lbs/ft) 12.25 Plain End Weight (lbs/ft) 3.600 Nominal Pipe Body Area (sq in) Appoximated Field End Torque Values 5,800 Minimum Final Torque (ft -lbs) 6,500 Maximum Final Torque (ft -lbs) 7,200 Connection Yield Torque (ft -lbs) Grade: L-80 AAM USA VAM USA 4424 W. Sam Houston Pkwy. Suite 1501 Houston. TX 770141 Phone: 713-479-3200 Fax: 713479-3234 E-majl: VAMUSAsales yam-usaxom Page 27 Version 0 August, 2019 Pipe Body Performance Properties 288,000 Minimum Pipe Body Yield Strength (lbs) 7,500 Minimum Collapse Pressure (psi) 8,430 Minimum Internal Yield Pressure (psi) 7,700 Hydrostatic Test Pressure (psi) Appoximated Field End Torque Values 5,800 Minimum Final Torque (ft -lbs) 6,500 Maximum Final Torque (ft -lbs) 7,200 Connection Yield Torque (ft -lbs) Grade: L-80 AAM USA VAM USA 4424 W. Sam Houston Pkwy. Suite 1501 Houston. TX 770141 Phone: 713-479-3200 Fax: 713479-3234 E-majl: VAMUSAsales yam-usaxom Page 27 Version 0 August, 2019 Connection Dimensions 5.000 Connection O.D. (in) 3.958 Connection I.D. (in) 3.833 Connection Ddft Diameter (in) 3.94 Make-up Loss (in) 3.600 Critical Area (sq in) 100.0 Joint Efficiency (%) Appoximated Field End Torque Values 5,800 Minimum Final Torque (ft -lbs) 6,500 Maximum Final Torque (ft -lbs) 7,200 Connection Yield Torque (ft -lbs) Grade: L-80 AAM USA VAM USA 4424 W. Sam Houston Pkwy. Suite 1501 Houston. TX 770141 Phone: 713-479-3200 Fax: 713479-3234 E-majl: VAMUSAsales yam-usaxom Page 27 Version 0 August, 2019 Connection Performance Properties 288,000 Joint Strength (Ibs) 14,290 Reference String Length (ft) 1.6 Design Factor 314,000 API Joint Strength (lbs) 288,000 Compression Rating (lbs) 7,500 API Collapse Pressure Rating (psi) 8,430 API Internal Pressure Resistance (psi) 81.5 Maximum Uniaxial Bend Rating [degrees1100 ft] Appoximated Field End Torque Values 5,800 Minimum Final Torque (ft -lbs) 6,500 Maximum Final Torque (ft -lbs) 7,200 Connection Yield Torque (ft -lbs) Grade: L-80 AAM USA VAM USA 4424 W. Sam Houston Pkwy. Suite 1501 Houston. TX 770141 Phone: 713-479-3200 Fax: 713479-3234 E-majl: VAMUSAsales yam-usaxom Page 27 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp Energy Company 16.6. Run in hole w/ 4-1/2" casing to the 7-5/8" casing shoe. 16.7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole dictates. 16.8. Obtain slack off weight, PU weight, rotating weight and torque of the casing. 16.9. Circulate 2X bottoms up at shoe, ease casing thru shoe. 16.10. Continue to RIH w/ casing no faster than 1 jt./minute. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.11. Set casing slowly in and out of slips. 16.12. PU swell packer to be placed at approximately 1,648'. Swell packer should have 10' handling pups installed on both ends with bow spring centralizers on pups. 16.13. Swedge up and wash last 2 joints to bottom. P/U 5' off bottom. Note slack -off and pick-up weights. 16.14. Stage pump rates up slowly to circulating rate. Circ and condition mud with casing on bottom. Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the shakers are clean. Reduce the low end rheology of the drilling fluid by adding water and thinners. 16.15. Reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 28 Version 0 August, 2019 0 Hilcorp EneW Company 17.0 Cement 4-1/2" Production Casing Kalotsa #5 Drilling Procedure Rev 0 17.1. Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. • Pump 20 bbls of freshwater through all of Cementers equipment, taking returns to cuttings bin, prior to pumping any fluid downhole • 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. Attempt to reciprocate the casing during cmt operations until hole gets sticky 17.3. Pump 5 bbls of 10.5 ppg Mud Push spacer. 17.4. Test surface cmt lines to 4500 psi. 17.5. Pump remaining 30 bbls 10.5 ppg Mud Push spacer. 17.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed weight. Job is designed to pump 20% OH excess. Page 29 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Production CEMENT CALCULATIONS CSG 41/2 CSG BTM ft 6,100 Size Section: Calculation: Vol Vol (BBLS) (ft3) LEAD: 7-5/8" x 4-1/2" (1,848'-1,348') x.026 bpf = 13.12 73.7 Casing annulus: LEAD: (5,600' — 1,848') x.025 bpf x 6-3/4" OH x 4-1/2" 1.20 = 110.71 621.6 Casing annulus: Total LEAD: 123.83 695.3 TAIL: (6,100'-5,600') x .025 bpf x 1.20 6-3/4" OH x 4-1/2" 14.75 82.8 Casing annulus: TAIL: 80 x.015 bpf = 1.22 6.8 4-1/2" Shoe track: Total TAIL: 15.97 89.7 Total Cement: 139.81 785.0 17.7. Drop wiper plug and displace with 6% KCl ,;? fL 79 sr 17.8. If hole conditions allow — continue reciprocating casing throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 17.9. If elevated displacement pressures are encountered, position casing at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 17.10. Bump the plug and pressure up to 500 psi over final lift pressure. Hold pressure for 3 minutes. 17.11. Do not over -displace by more than 1/2 shoe track. Shoe track volume is 1.2 bbls. 17.12. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 17.13. RD cementers and flush equipment. Page 30 Version 0 August, 2019 Kalotsa #5 Drilling Procedure / k Rev 0 Hilcorp (\ Er,cW Company 17.14. WOC minimum of 12 hours, test casing to 3500 psi and chart for 30 minutes. 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 mmyers(a�hilcorp. com. This will be included with the EOW documentation that goes to the AOGCC. 18.0 RDMO 18.1. Install BPV in wellhead 18.2. N/D BOPE 18.3. N/U temp abandonment cap 18.4. RDMO Hilcorp Rig #169 T— �r -, x 7 re- /' 1 -A z,s-D 0 /as, /--? 'D ►—� Page 31 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp EneW cm Wy 19.0 BOP Schematic Page 32 Version 0 August. 2019 Hilcorp Etl W Company 20.0 Wellhead Schematic Tubing head. C HpS, 13 5/8 51V 2-21/16 Starting head, t 135/85Mx16 1/16 5h Kalotsa #5 Drilling Procedure Rev 0 Casing hanger, CW, 11 x 4 A DWC/C box btm x 6.125" RH stub acme box top. W/ 7 5/8 Ineck, 4" type H BPV profile, DO -NL material BHTA, Otis, 41/16 5M FE x 6.5 Otis quick union top Page 33 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 H11Corp Enew Company 21.0 Days Vs Depth 0 1000 200( 300( 4000 [. Q v 0 5000 C) v 6000 Days Vs Depth 10 15 20 Days Page 34 Version 0 August, 2019 25 30 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp Energy Company n .% n ►moi' + Y 5858-44 i r 3 ° KS 144:5 �I SYS 2��E IJt . �liii - 26- IBJO �' ISL , 126.5 PROPOSED. MA Drill a 6109 LAD (3794' TVD) grass rents wet at Nnichik Field (Pax. Dionne Stnxturel T---ty wasting slacked (.gaper Beluga pay sands updip cd c%is" peneee&alans. Pmqected to hit Belugp 30 Lhrnugh 52 sands updip of catnent wells. Upside r rues are L_awer Beluga stratigrafhic traps and u ppesmrmst Upper Beluga (1-16) sands cfeannq LAP at the t=p ry TQPM4fA= MUM rniru my ,5 JltcB'I.i illStlG cac•rntrs l�jSettf. - -- - ts'rt - --- ? 3uti' T r• .: • b,gas T.375 1.142 -997 2.233.460.16 20G. -23T.27 5r4 O. J Belnt90 flo 2.817 1.420 1275 2.233.678.50 207,610.30 639 0.45 D.41 w 13, 2.958 1.455 •1310 2.233.527.92 207,637 -Ca 4&D 0.3'3 E#zt'uga...id5 �• ae' 3.055 1,485 -1340 2.233.513.11 207576-57 4t6 0.26 -- •1399 2.233.506.73 207.029.89 693 a45. 13.w'trga 21Q _ �r• �e... 3.276 T: 544 i3m4T}n 3Kt .:;t.. 3.351 1.604 =1459 2.233.540.46 20-,204.W 727 0.45 Deiuya34 3.4T5 1„635 -14910 2:233.529,35 207270,99 736 0.45:'. 37 3.437 1.646 3.5DI 2.233.504.28 207..221-22 740 77145, Beftrge 40 shad:•': 3,525 1.693 -1548 2-233,546.71 207,154.74 752 0.45 paTucu 41 samGn :. r _• 3.5755 1.721 •1576 2.233.544.2& 207,179-29 654 0.38 £1eInya 44 sarrdstcnn _ 3,683' f.785 -7640 2233.562.00 207,02Y-78 714 CtdD 8whoga4d sandstone depleledans 3.707 1.,80E -1655 22.233.545.35 2777,01244 378 0.21:. D'4LVU 471: sarxtslav*e 3786 1.651 •17D6 2.233,559.60 2'0d.950.68 833 045 ,Ocf'L-tsv_5.0stmdsE ae• 3.98:• 7,PW -3941 2.233,599.10 204%817.68 6:95 0135 -- _r--_ 84 2233.573.aS 206.774.92 696 0. 34 l3elu� 51 r. 4:0138 3:1029 .19 Re toga 52 sandstone depleted gas 4.:088 2087 •1922 2-222.56V.03 206, 734.50 455 0.22 Beluga 53A sandstanc depleted pas 4, VW- 2,139 -3954 2.233.554.35 20+6..689-42 235 0.11 Beluga 5$A saradWA ne depir ad gas 4.407 2.32,8 •2183 2.233.578.48 244554.15 465 0.20 Devruva 59 sarndstc 4.471 2384 •2239 2.233.580.75 204527.85 715 0.30 ,£teHvy.*v L•it _ sztrrds3cr*c• 4.519 2.425 .2280 2.233.59590 204.478.:52 9194 0.47 Dertrg:� 6.5 sar:dstc:rx 4.56-1 2.453 -2378 2.233.584.3? 206,479.52 862 0.3'4 A*hva 70 sandstone depletedgas 4_6W 2.495 -2330 2.233.5a?0.12 206,461.07 424 0.17 BehWa 72 a depleledgas 4..641 2.531 ,2366 2.233.584.30 204449..43 380 0.15 SYct 82 .:t. c•• • 4.850 2.712 •2567 2.233.590.12 204.338.90 813 0.30 Beft'SO 92-2 5.091 2,921 -2776 2.233.601-31 206..216.21 935 0.32 .t3ettr¢n 1[t�Cc, _ .. _. =`.'�. 5.457 .3.238 -3093 2.233.622.54 204.444.50 907 0.28 Beftiqu 170 :°a _ 5.fY43 3.312 -3167 2.233.594.12 206,011.08 960 0.29 Deluya 115 .•x..,..•. 5..:98 3.3877 •3265 2.233.616.60 205.977.37 1008 0130- Dr4ugg1;%5 1_ 5.15-M 3.394 •3249 2.233.610.47 205964..31 9&'4 0.29; !3e(uyw 73T ear:tt;.'.:,rm• .5.723 a-faft ,3323 2233.6TD.41 205.904.99 7(140 CLSO 11'eltga1.84 sandstane, dephilad,gas 5784 ,3.521 -31376 2.233.640.07 Ad588275 915 0.26 Bcltga 1JAA sarmistane dgplefedgas 5.825 3558 .3471 2-233.642.71 205,789.43 924 0.28; .Beluga 1:85 saradsrone depleted gas 5.0758 $5115 -3000 2.233.643.52 205•.715.'`5+7 394' 0.11 i J$chaga 136 sandstone dep!eted gas jlllf 5.930 $.657 -3512B 2,233,643.9.9 20.5,.68&.30 329 0.09 Surface to TD, samples callected at 29 niervals- CuMna descriptions Provided at no greater than h 00'i Spemr L %VD triple a:arnbo surface ca-mog stxtatg; Sperry t_WV• Tr{ile Cometh productaun string None �- } Plane niche Page 35 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp Energy Company 23.0 Anticipated Drilling Hazards 9-7/8" Hole Section: Lost Circulation: Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Maintain YP between 25 — 45 to optimize hole cleaning and control ECD. Wellbore stability: Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger than normal can cause hole -cleaning problems. If encountered, be prepared to increase the viscosity. Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP of —50 - —60 lbs/l00ft2 to combat this issue. Maintain low flow rates for the initial 200' of drilling to reduce the likelihood of washing out the conductor shoe. To help insure good cement to surface after running the casing, condition the mud to a YP of 25 — 30 prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be achieved. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. Page 36 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp Energy Company 6-3/4" Hole Section: Lost Circulation: Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi -vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP between 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The . need for good planning and drilling practices is also emphasized as a key component for success. • 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 running coals. • Emphasize good hole cleaning through hydraulics, ROP and system rheology. H2S: 1-12S is not present in this hole section. No abnormal temperatures are present in this hole section. Page 37 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp EneW Company 24.0 Hilcorp Rig 169 Layout Page 3 8 Version 0 August, 2019 Ob Le9 A '' 6 Page 3 8 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp Energy Company 25.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1 -minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre -determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre -determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 39 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp Energy Campmy 26.0 Choke Manifold Schematic Page 40 Version 0 August, 2019 I :f�rMl' _,h1'' to �;��r�i,l��l •. =_�' �A llr'it r7C 'moi �� =■S c �V7 f 2 6 firr - rr`iir } �q �Y Page 40 Version 0 August, 2019 ff Hilcorp Energy COMPMy 27.0 Casing Design Information Kalotsa #5 Drilling Procedure I Rev 0 Calculation & Casing Design Factors DATE: 8-14-2019 WELL: Kalotsa 5 FIELD: Ninilchik DESIGN BY: David Gorm Design Criteria: Hole Size 9-7.;8 Mud Density: 9. ppg Hole Size 6 -3,,4 Mud Density: 9-5 ppg Drilling Mode MASP: 1328 Top (MD) ................................................................................................................ Production Mode ............................... ............................ 0 ............................... MASP: 1328 psi (See attached MASP determination & calculation) Collapse Calculation: Section Calculation 1 Normal gradient external stress (0.45 psiffl) and the casing evacuated forth e internal stress Calculation/Specification1 2 ........................................................................................................................ Casing OD ........................................................................................................................ ............................... ........................... 7 5M 4112 Top (MD) ................................................................................................................ ....... ............................... ............................ 0 ............................... 0 Top OVID) ........................... 0 0 ................... I .............. i�E ..64........................................................ Bottom ...............................6......................................................... ............................... ............................... ............................ 1,848 6,100 ............................ ottorn (TVD) ........................................................................................................................ ............................... 1,250 i ........................... 3,794 Length ........................................................................................................................ 1,848 6,100 Weight (ppf)12.6 ........................................................................................................................ . ............................... ............................ GradeL-80 L-80 ........................................................................................................................ Connection ............................... ........................... IDWC DWC HT ei w/o Bouyancy Factor (Ibs) .......... ........ .................................................................................. ... ............................... ............................. ............................ ..54,896 .......................... .. 76,860 Tension at Top of Section (lbs)54,896 1 76,860 Min strength Tension (1000 lbs) ........... . ................ ............... ............................ 6341 1 288 . ..... ............ ��iiw iili ...... ........... .... .......... ............................... . ...... Worst Case (Tension) 1i : S.Y97 Collapse Pressure at bottom (Psi) ............................... ............................ 563 1,707 .. lapse Resistance w/o tension (Psi) ... ............................... :: ............................ 4,790 7,500 Worst o flapse) ...... .......................... 8.52 7-1-4.39 - ............................. ................................................................. MASP (psi) ............................... ............................ 1328 1,328 ....................... .... ....................................................................................... Minimum Yield (psi) ............................................ . ........... i ........... .................. ............................ 6,890 ............... ........................ 8,430 .Worst case safety factor (Burst) ..................................................................................................................................................................................... 5.19 6.35 Section .............. f Page 41 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp Energy Company 28.0 6-3/4" Hole Section MASP Page 42 Maximum Anticipated Surface Pressure Calculation 6.314" Holt Section !!1llc Kalotsa 85 Kenai, Alaska MD TVD Planned Top: 0 0 Planned TD: 6100 3794 Anticinated Formations and Pressures - Formation TVD Est Pre -.pure Oi11G4s1Wet PPG Grad Beluga 1 1141.5 514 1 possible qa,, 8.7 0.45 Belu a 10 1419.5 639 po,,5ible qa,, 8.7 0.45 Beluga 13 1454.5 480 Qa§ 6.3 0.33 Bdu a 16 1484.5 416 qas 5.4 0.28 Beluga 20 1543.5 635 qQ5 8.7 0.45 Beluga 30 1603.5 722 qas 8.7 0.45 Bdu a 34 1634.5 736 QW 8.7 0.45 Bdu a 37 1645.5 740 as 8.7 0.45 Beluga 40 1692.5 762 as 8.7 0.45 Beluga 41 1720.5 654 as 7.3 0.38 Beluga 44 1784.5 714 qas 7.7 0.4 Beluga 45 1799.5 378 Q4§;1 4"0 0.21 Beluga 47A 1850.5 833 depleted qai 4 8.7 0.45 Bclu a 50 1985.5 695 as 6.7 0.35 Belu a 51 1 2028.5 690 qas 6.5 0.34 Bdu a 52 2066.5 455 as 4.2 0.22 13 -Juga 53A 2138.5 235 depleted qas 2.1 0.11 Bdu a 58A 2327.5 466 depleted q4c 3.8 0.2 Bdu a 59 2383.5 715 depleted qa5 5.8 0.3 Beluga 60 2424.5 994 gal 7.9 0.41 Bolucla 65 2462.5 862 qas 6.7 0.35 Beluga 70 2494.5 424 q.V 3.3 0.17 Belucia 72 2530.5 380 depleted qas 2.9 0.15 Bdu a 82 2711.5 813 dt leted qas 5.8 0.3 Beluga 92-2 2,321 935 as 6.2 0.32 Beluga 100 3,238 907 as 5.4 0.28 Beluga 110 3,312 960 qas 5.6 0.29 Beluga 115 3.360 100$ Clal 5.8 0.3 Belucia 120 3,334 384 qa5 5.6 0.29 Beluga 131 3,468 1040 qav 5.8 0.3 Belu a 134 3,521 915 as 5.0 0.26 Bclu a 134A 3,556 924 depleted qa,, 5.0 0.26 Beluga 135 1 3,585 394 de lettA qa, 2.1 0.11 Beluga 136 1 3,651 329 depleted qQs 1.7 - 0.09 Offset Well Mud Densities Kalotsa 1 9.0 - 9.2 Dpa 1.341 7,772 Kalotsa 2 9.0 - 9.4 1,347 7,857 Kalotsa 3 9.0 - 9.3 1,231 6,642 M201? Kalotsa 4 9.0 - 9.5 1,363 6.3:37 1. Maximum planned mud density for the 6-314 hole section is 9.5 ppq. 2. Calculations assume rtstryoiro contain 100% qas f worst casel. 3. Calculations assume worst case event is complete evacuation of wellbore to qas. 4. Anticipated fracture qradient at 1,25O'TVD = 13.5 ppq EMW Fracture Pressure at 7-518- shoe considering a Full column of gas From shoe to surface= 1,250 (ft) x 0.70 (psilft)= 875 1 875 (psi) - [0.1(psilft)'1,250 (ft)]= 1 750 psi MASP from pore pressure; entire wellbore evacuated to gas From TO 3,794 fftl x 0.45 fpsilftl= 1707 i 1307 fpcil - [0.1 fpsilftl'3,794 fftll= 1328 si Summatyt 4 1. MASP while drillinq 6-314" production hole is goyerned by frac pressure at 7-518" shoe with entire wellbore evacuated to qa-. Version 0 August, 2019 41 75C 10 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp Energy Company Ninilchik Unit F Kalotsa 5 a e n AlasY.a ^state PBare 2cc,e $. #1ACi2i Iliilmrp Ata-ka. LIX wp07 Map Date: &271201$ A Page 43 Version 0 August, 2019 HilCOIp Energy Company 30.0 Surface Plat (NAD 27) Kalotsa #5 Drilling Procedure Rev 0 GOVT LOT 2 GOVT LOT 3 ASP NAD83, ZONE 4 KAL4I'34 PAL N: 2,233,154.669 E: 1,348,822.918 ,��}�' a ASP NAD83, GEOGRAPHIC a LAT.: N 60'O6'11.5417- Fi KAL67rSk a10 LONG.: W 15135'33.2240" ,utr�7 sa r..Y NGVD29 ELEV.: 12£_5 PAC raLtr9 sq Dnp SP NAD27, ZONNE 4 N: 2,233,395.651 E: 209,603, 593 SP NAD27, GEOGRAPHIC T.: N 60'0614.060$" �ONG.:M1W 15135'25.2639' LOT 1 j KN 85-129 GOV'1 LOT i I 1 I i 1 i 2120' FSL (NTS) � 1 e i i 1 nPYMUM t* ! 1 us410 1i1Y j ___--------- ___-� - SECTION _07 _T_15 _R1_3W (NTS) ___----------- ----..__----.-_-- SECTION 18 T18-R136N 7N1'S-~-'----®-`-- NOTES 1. @A. -JS OF OC IC CONTROL. AM MADal POSITION {EFOCJ M031 IS AN OPUS ! SOLUTION FROM NGS CCaRDT: RTES STATIONS'f{ENS CORS ARF'.. 'T:EA CORS ARF', A,1O MAN1 MAE- I CORS ARP' TO ESTABLISH THE POSITION OF'DID 3Cft SUSAN DIONNE PAD. TFE raEDDETIC POSITION OF CIO 3 WAS CETERMI.MED TO HAVE A LATnUDE OF WD943-995?4 AND ALONGITUDE OF I51.1V35 172*W THE ALA-SKA STATE PLANE COORDINATES OSPI ZONE d ARE N=22363 37 93 5 E=135302.572 ELEV. 139.79' tNGVM+291, 2 BASIS CF VERTI AL. LCNTRCL 15 WOS SM VR2 FID TTWr,86 LOC'ATE'S' AT MIiEPOS; 127.E OF T3£ STERLING HIGIRVAY HAW,* AM ELEVATION OF 233.59 FEET NGV029 ACCOFL4MG TO NGS PUEUSHED DATA, 3. CC<3 O TE CONVERINCM IKAD33 TO NA132711%ERE DCBE USIMG CORF-. N SCFT"AF:c VT RS ION 6. G. 1. OF A �# _.2a♦._ 7.v: A. MCiBE. t � SCALE U :tin tL&I Page 44 Version 0 August, 2019 HILCORP ALASKA. LLC - KALOTSA#fi5 axwm"a ace NINILCHIK ALASKA=F-k AS -BUILT SURFACE LOCATION �. a s aco:,as:racalrxr wc. aaa ..as;. I:sar�swz� cu rlAnsasxaas •'-'-"':-.•• SEC. 07 T01 S R13W %'-c•T Iiilrorp Ala ika. I.I.0 SEWARD MERIDIAN, ALASKA Page 44 Version 0 August, 2019 Kalotsa #5 Drilling Procedure Rev 0 Hilcorp Energy Company 31.0 Directional Plan (wp07) Page 45 Version 0 August, 2019 Hilcorp Alaska, LLC Ninilchik Unit Kalotsa Kalotsa 5 Kalotsa 5 Plan: Kalotsa 5 Wp07 Standard Proposal Report 27 August, 2019 HALLIBURTON Sperry Drilling Services HALLIBURTON Sperry Drilling Project: Ninilchik Unit Site: Kalotsa Well: Kalotsa 5 Wellbore: Kalotsa 5 Design: Kalotsa 5 Wp07 Ninilchik Unit Kalotsa Kalotsa 5 Kalotsa 5 Kalotsa 5 Wp07 6.009 St314i Hilcorp Alaska, LLC TVDssPath REFERENCE INFORMATION Calculation Method: Minimum Curvature Error System: ISCWSA Scan Method: Closest Approach 3D TVD Co-ordinate (N/E) Reference: Well Kalotsa 5, True North Vertical (TVD) Reference: As -Built @ 144.50usft (HEC 169) Measured Depth Reference: As -Built @ 144.50usft (HEC 169) Error Surface: Pedal Curve Warning Method: Error Ratio Size Calculation Method: Minimum Curvature Sec MD Inc Azi TVD +N/ -S +E/ -W Dleg TFace VSect Target Annotation 1 18.00 0.00 0.00 18.00 0.00 0.00 0.00 0.00 0.00 2 200.00 0.00 0.00 200.00 0.00 0.00 0.00 0.00 0.00 Start Dir 4°/100' : 200' MD, 200'TVD 3 400.00 8.00 268.00 399.35 -0.49 -13.93 4.00 268.00 13.90 Start Dir 6°/100' : 400' MD, 399.35'TVD 4 1600.00 80.00 268.00 1206.87 -27.70 -793.27 6.00 0.00 791.75 End Dir : 1600' MD, 1206.87' TVD 5 2743.85 80.00 268.00 1405.50 -67.01 -1919.06 0.00 0.00 1915.37 Kalotsa 5 wp07 Beluga 10 Start Dir 3°/100' : 2743.85' MD, 1405.5" 6 4243.85 35.00 268.00 2190.89 -110.04 -3151.13 3.00 180.00 3145.07 7 4597.55 33.07 249.29 2484.81 -147.80 -3343.31 3.00 -108.15 3340.16 End Dir : 4597.53' MD, 2484.79' TVD B 5681.27 33.07 249.29 3393.02 -356.86 -3896.39 0.00 0.00 3912.27 Kalotsa 5 wp07 Beluga 135 9 6100.00 33.07 249.29 3743.94 -437.63 -4110.09 0.00 0.00 4133.33 Total Depth : 6100' MD, 3743.94' TVD 0 16" _ Start Dir 41/100' : 200' MD, 200'TVD 325 - - - - - Start Dir 6°/100' : 400' MD, 399.35'TVD Soo End Dir : 1600' MD, 1206.87' TVD 00 WELL DETAILS: Kalotsa 5 TVDssPath CASING DETAILS 126.50 TVD TVDSS MD Size Name 120.00 -24.50 120.00 16 16" 1250.00 1105.50 1848.36 7-5/8 7 5/8" x 9-7/8" 3743.94 3599.44 6100.00 4-1/2 41/2"x6-3/4" 0 16" _ Start Dir 41/100' : 200' MD, 200'TVD 325 - - - - - Start Dir 6°/100' : 400' MD, 399.35'TVD Soo End Dir : 1600' MD, 1206.87' TVD 00 WELL DETAILS: Kalotsa 5 TVDssPath MDPath 126.50 1141.50 N/ -S +E/ -W Northing Easting Latittude Longitude 0.00 0.00 2233395.6510 209803.5930 60" 6'14.0808 N 151°35'25.2639 W Beluga 10 1454.50 SURVEY PROGRAM 2958.28 Beluga 13 Date: 2019-08-13T00:00:00 Validated: Yes Version: 3682.28 Beluga 44 Depth From Depth To Survey/Plan Tool Beluga 45 18.00 1848.00 Kalotsa 5 Wp07 (Kalotsa 5) 3 MWD+IFRI+MS+Sa Beluga 47A 1848.00 6100.00 Kalotsa 5 Wp07 (Kalotsa 5) 3_MWD+IFRI+MS+Sa TVDPath TVDssPath MDPath Formation 1141.50 997.00 1373.30 Beluga 1 1419.50 1275.00 2816.63 Beluga 10 1454.50 1310.00 2958.28 Beluga 13 1784.50 1640.00 3682.28 Beluga 44 1799.50 1655.00 3706.37 Beluga 45 1850.50 1706.00 3785.61 Beluga 47A 2462.50 2318.00 4570.92 Beluga 65 2494.50 2350.00 4609.11 Beluga 70 2530.50 2386.00 4652.07 Beluga 72 2711.50 2567.00 4868.05 Beluga 82 3467.50 3323.00 5770.14 Beluga 131 3520.50 3376.00 5833.38 Beluga 134 3650.50 3506.00 5988.51 Beluga 136 975Start Dir 3°/100' : 2743.85' MD, 1405.5'TVD 0 o Beluga 1 o N 1300 CNI o0 rn Beluga 10 ` o O LO Beluga 13 ' 00 L 1625 7 5/8" x 9-7/8" Kalotsa 5 wp07 Beluga 10 a Beluga 44 d) Beluga 45 1950 Beluga 47A p000 4) 7 H 2275 A500 End Dir : 4597.53' MD, 2484.79' TVD - Beluga 65_ _ _ _ - - _ - - - .-. Beluga 70 -_ ... ..... ... -._ ..__._ ........ -.. ...._ -_. 2600 Beluga 72 - - - - - - - - - - -_ Beluga 82_ 2925 3250 Kalotsa 5 wp07 Beluga 135 _ Beluga 131 - - - - - - - - - - -- - - - - - - - - - - - 4 1/2" x 6-3/4„ 3575 Beluga 134 Opo ,' Beluga 136 Total Depth : 6100' MD, 3743.94' TVD 3900-1Kalotsa 5 Wp07 0 325 650 975 1300 1625 1950 2275 2600 2925 3250 3575 3900 4225 4550 Vertical Section at 263.920 (650 usft/in) HALLIBURTON sf»r•.�y o.eu..a . _.___ q End D6 : 4597.53' MD, 2484.79' TVD 250 v Toul Depth : 61 00'MD, 3743 94' TVD + 0 0 -250- -500 250 -500 � Kalotsa 5 tW 7 Beluga 135 _75n- Ka1W8a5 Wp07 -1500 1111110. Project: Ninilchik Unit WELL DETAUS: Kzlmsa 5 126.50 Site: Kalotsa Well: Kalotsa 5 N/ -S +E/ -W Nonlsing Eating Ia t de luvgitudc Wellbore: Kalotsa 5 0.00 0.00 2233395.6510 209803.5930 6W 6' 14.0808 N 151.35' 25.2639 W REFERENCE INFORMATION Plan: Kalotsa 5 Wp07 Co-ordinate IWE) Reference: Well Kalolse 5, True North 16 Venice) (IVO) Reference: M -Built @ 144.SOusf1(HEC 169) 1250.00 Measured Dapol Reference: M -Built® 144.SOusfl(HEC 169) Calculation Method: Minimum Curvature Stan Dv 4°/100' : 200' MD, 200TVD Sun on 6"/100' : 400' MD, 399.35TVD End Du : 1600' MD, 1206.87' TVD Start Dir 3'1]W; 2743.85' MD, 1405.5TVD Kalotsa 5 rvp07 Beluga 10 4500 -4250 -4000 -3750 -3500 -3250 -3000 -2750 -2500 -2250 -2000 -1750 -1500 -1250 -1000 -750 -500 -250 0 250 West( -)/East(+) (500 us@/in) CASING DETAILS TVD TVDSS MD Size N- 120-00-24.50 120.00 16 16" 1250.00 1105.50 1848.36 7-5/8 7 5/8" x 9-7/8" 3743.94 3599.44 6100.00 4-1/2 41/2"x6-3/4" Stan Dv 4°/100' : 200' MD, 200TVD Sun on 6"/100' : 400' MD, 399.35TVD End Du : 1600' MD, 1206.87' TVD Start Dir 3'1]W; 2743.85' MD, 1405.5TVD Kalotsa 5 rvp07 Beluga 10 4500 -4250 -4000 -3750 -3500 -3250 -3000 -2750 -2500 -2250 -2000 -1750 -1500 -1250 -1000 -750 -500 -250 0 250 West( -)/East(+) (500 us@/in) Hi Mw FA 6 -5200 -4800 -4400 -4000 -3600 -3200 -2800 2400 2000 -1600 -1200 -800 400 0 West( -)/Fast(+) (600 ttsft/in) 400 • Database: NORTH US + CANADA Comoanv: Hilcorp Alaska, LLC Proiect: Ninilchik Unit Site: Kalotsa Well: Kalotsa 5 Wellbore: Kalotsa 5 Design: Kalotsa 5 Wp07 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Kalotsa 5 TVD Reference: As -Built @ 144.50usft (HEC 169) MD Reference: As -Built @ 144.50usft (HEC 169) North Reference: True Survey Calculation Method: Minimum Curvature - Proiect Ninilchik Unit Map Svstem: US State Plane 1927 (Exact solution) Svstem Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Usinq Well Reference Point Map Zone: Alaska Zone 04 Usinq qeodetic scale factor Plan Sections Kalotsa Build Turn 'Site +E/ -W Measured Site Position: Rate Northing: 2,233,473.8990 usft Latitude: From: Map Eastinq: 209,844.1600 usft Longitude: Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid Convergence: Well Kalotsa 5 h (usft) Well Position +N/ -S 0.00 usft Northing: 2,233,395.6510 usft Latitude: 0.00 +E/ -W 0.00 usft Eastinq: 209,803.5930 usft Longitude: Position Uncertainty 0.00 0.50 usft Wellhead Elevation: usft Ground Level: 55.50 0.00 400.00 8.00 Wellbore Kalotsa 5 Magnetics Model Name Sample Date Declination Dip Angle (°) (°) 268.00 BGGM2018 9/13/2019 15.06 73.05 Design Kalotsa 5 Wp07 80.00 268.00 Audit Notes: 1,261.00 -67.01 4,243.85 Version: 268.00 Phase: PLAN Tie On Depth: 18.00 Vertical Section: 4,597.55 Depth From (TVD) +N/ -S +E/ -W Direction 2,484.81 2,340.31 (usft) (usft) (usft) (') 33.07 249.29 18.00 0.00 0.00 263.92 Plan Sections Dogleg Build Turn +E/ -W Measured Rate Rate Vertical TVD (°1100usft) Depth Inclinatio Azimut Depth System +N/ -S (usft) n h (usft) usft (usft) 18.00 0.00 0.00 18.00 -126.50 0.00 200.00 0.00 0.00 200.00 55.50 0.00 400.00 8.00 268.00 399.35 254.85 -0.49 1,600.00 80.00 268.00 1,206.87 1,062.37 -27.70 2,743.85 80.00 268.00 1,405.50 1,261.00 -67.01 4,243.85 35.00 268.00 2,190.89 2,046.39 -110.04 4,597.55 33.07 249.29 2,484.81 2,340.31 -147.80 5,681.27 33.07 249.29 3,393.02 3,248.52 -356.86 6,100.00 33.07 249.29 3,743.94 3,599.44 -437.63 600 6' 14.8608 N 151' 35'24.5010 W -1.38 60° 6' 14.0808 N I 151'35'25.2639W 126.50 usft , Field Strength (nT) 55,003.95373707 8/27/2019 12:21:45PM Paae 2 COMPASS 5000.15 Build 91 Dogleg Build Turn +E/ -W Rate Rate Rate Tool Face (usft) (°1100usft) (°/1o0usft (°/100usft 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 -13.93 4.00 4.00 0.00 268.00 1 -793.27 6.00 6.00 0.00 0.00 -1,919.06 0.00 0.00 0.00 0.00 -3,151.13 3.00 -3.00 0.00 180.00 -3,343.31 3.00 -0.55 -5.29 -108.15 -3,896.39 0.00 0.00 0.00 0.00 -4,110.09 0.00 0.00 0.00 0.00 8/27/2019 12:21:45PM Paae 2 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US + CANADA Companv: Hilcorp Alaska, LLC Proiect: Ninilchik Unit Site: Kalotsa Well: Kalotsa 5 Wellbore: Kalotsa 5 Desiqn: Kalotsa 5 Wp07 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: SurveV Calculation Method: Standard Well Kalotsa 5 As -Built @ 144.50usft (HEC 169) As -Built @ 144.50usft (HEC 169) True Minimum Curvature Halliburton Proposal Report Planned Survey j Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NIS +EI -W Northing Easting DLS Vert (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) -126.50 Section 18.00 0.00 0.00 18.00 -126.50 0.00 0.00 2,233,395.6510 209,803.5930 0.0000 0.00 100.00 0.00 0.00 100.00 -44.50 0.00 0.00 2,233,395.6510 209,803.5930 0.0000 0.00 120.00 0.00 0.00 120.00 -24.50 0.00 0.00 2,233,395.6510 209,803.5930 0.0000 0.00 16" 200.00 0.00 0.00 200.00 55.50 0.00 0.00 2,233,395.6510 209,803.5930 0.0000 0.00 Start Dir 4°/100' : 200' MD, 200'TVD 300.00 4.00 268.00 299.92 155.42 -0.12 -3.49 2,233,395.6132 209,800.1040 4.0000 3.48 400.00 8.00 268.00 399.35 254.85 -0.49 -13.93 2,233,395.4999 209,789.6539 4.0000 13.90 Start Dir 61/100' : 400' MD, 399.35'TVD 500.00 14.00 268.00 497.47 352.97 -1.15 -32.99 2,233,395.2931 209,770.5829 6.0000 32.93 600.00 20.00 268.00 593.06 448.56 -2.17 -62.20 2,233,394.9763 209,741.3610 6.0000 62.08 700.00 26.00 268.00 685.06 540.56 -3.54 -101.23 2,233,394.5529 209,702.3082 6.0000 101.03 800.00 32.00 268.00 772.49 627.99 -5.23 -149.66 2,233,394.0276 209,653.8524 6.0000 149.37 900.00 38.00 268.00 854.36 709.86 -7.23 -206.96 2,233,393.4061 209,596.5246 6.0000 206.56 1,000.00 44.00 268.00 929.80 785.30 -9.52 -272.49 2,233,392.6952 209,530.9528 6.0000 271.97 1,100.00 50.00 268.00 997.97 853.47 -12.07 -345.55 2,233,391.9027 209,457.8554 6.0000 344.88 1,200.00 56.00 268.00 1,058.12 913.62 -14.85 -425.33 2,233,391.0373 209,378.0334 6.0000 424.51 1,300.00 62.00 268.00 1,109.60 965.10 -17.84 -510.95 2,233,390.1085 209,292.3612 6.0000 509.97 1,373.30 66.40 268.00 1,141.50 997.00 -20.15 -576.89 2,233,389.3932 209,226.3861 6.0000 575.78 Beluga 1 1,400.00 68.00 268.00 1,151.85 1,007.35 -21.00 -601.49 2,233,389.1264 209,201.7775 6.0000 600.33 1,500.00 74.00 268.00 1,184.39 1,039.89 -24.30 -695.94 2,233,388.1019 209,107.2748 6.0000 694.60 1,600.00 80.00 268.00 1,206.87 1,062.37 -27.70 -793.27 2,233,387.0461 209,009.8884 6.0000 791.75 End Dir : 1600' MD, 1206.87' TVD 1,700.00 80.00 268.00 1,224.24 1,079.74 -31.14 -891.69 2,233,385.9784 208,911.4138 0.0000 889.98 1,800.00 80.00 268.00 1,241.60 1,097.10 -34.58 -990.11 2,233,384.9108 208,812.9393 0.0000 988.21 1,848.36 80.00 268.00 1,250.00 1,105.50 -36.24 -1,037.71 2,233,384.3945 208,765.3150 0.0000 1,035.71 7 5/8" x 9-7/8" 1,900.00 80.00 268.00 1,258.97 1,114.47 -38.01 -1,088.53 2,233,383.8432 208,714.4647 0.0000 1,086.44 2,000.00 80.00 268.00 1,276.33 1,131.83 -41.45 -1,186.95 2,233,382.7756 208,615.9901 0.0000 1,184.67 2,100.00 80.00 268.00 1,293.70 1,149.20 -44.89 -1,285.37 2,233,381.7080 208,517.5155 0.0000 1,282.90 2,200.00 80.00 268.00 1,311.06 1,166.56 -48.32 -1,383.80 2,233,380.6404 208,419.0410 0.0000 1,381.13 2,300.00 80.00 268.00 1,328.43 1,183.93 -51.76 -1,482.22 2,233,379.5728 208,320.5664 0.0000 1,479.37 2,400.00 80.00 268.00 1,345.79 1,201.29 -55.20 -1,580.64 2,233,378.5052 208,222.0918 0.0000 1,577.60 2,500.00 80.00 268.00 1,363.16 1,218.66 -58.63 -1,679.06 2,233,377.4375 208,123.6172 0.0000 1,675.83 2,600.00 80.00 268.00 1,380.52 1,236.02 -62.07 -1,777.48 2,233,376.3699 208,025.1426 0.0000 1,774.06 2,700.00 80.00 268.00 1,397.89 1,253.39 -65.51 -1,875.90 2,233,375.3023 207,926.6681 0.0000 1,872.29 2,743.85 80.00 268.00 1,405.50 1,261.00 -67.01 -1,919.06 2,233,374.8342 207,883.4862 0.0000 1,915.37 Start Dir 31/100': 2743.85' MD, 1405.5'TVD 2,743.86 80.00 268.00 1,405.50 1,261.00 -67.02 -1,919.06 2,233,374.8341 207,883.4802 0.0000 1,915.37 Kalotsa 5 wp07 Beluga 10 2,800.00 78.32 268.00 1,416.06 1,271.56 -68.94 -1,974.17 2,233,374.2364 207,828.3448 3.0003 1,970.37 2,816.63 77.82 268.00 1,419.50 1,275.00 -69.51 -1,990.43 2,233,374.0600 207,812.0770 3.0000 1,986.60 Beluga 10 2,900.00 75.32 268.00 1,438.87 1,294.37 -72.34 -2,071.46 2,233,373.1810 207,730.9979 3.0000 2,067.48 8/27/2019 12:21:45PM Paae 3 COMPASS 5000.15 Build 91 =7_\ "I =1N �loT►r Database: NORTH US + CANADA TVD Reference: Companv: Hilcorp Alaska, LLC @ 144.50usft (HEC 169) Project: Ninilchik Unit As -Built @ 144.50usft (HEC 169) Site: Kalotsa True Well: Kalotsa 5 Calculation Method: Minimum Curvature Wellbore: Kalotsa 5 Map Map Desiqn: Kalotsa 5 Wp07 +E/ -W Northing Planned Survey DLS Vert (usft) (usft) Measured (usft) 1,310.00 Vertical -74.30 Depth Inclination Azimuth Depth TVDss (usft) (1) (1) (usft) usft 2,958.28 73.57 268.00 1,454.50 1,310.00 Beluga 13 3.0000 2,257.46 -82.22 -2,354.34 3,000.00 72.32 268.00 1,466.74 1,322.24 3,100.00 69.32 268.00 1,499.59 1,355.09 3,200.00 66.32 268.00 1,537.35 1,392.85 3,300.00 63.32 268.00 1,579.90 1,435.40 3,400.00 60.32 268.00 1,627.12 1,482.62 3,500.00 57.32 268.00 1,678.90 1,534.40 3,600.00 54.32 268.00 1,735.08 1,590.58 3,682.28 51.85 268.00 1,784.50 1,640.00 Beluga 44 -2,785.58 2,233,365.4347 207,016.4947 3.0000 3,700.00 51.32 268.00 1,795.51 1,651.01 3,706.37 51.12 268.00 1,799.50 1,655.00 Beluga 45 3.0000 2,851.46 -102.31 -2,929.82 3,785.61 48.75 268.00 1,850.50 1,706.00 Beluga 47A 2,233,363.1196 206,802.9547 3.0000 2,993.23 3,800.00 48.32 268.00 1,860.03 1,715.53 3,900.00 45.32 268.00 1,928.45 1,783.95 4,000.00 42.32 268.00 2,000.60 1,856.10 4,100.00 39.32 268.00 2,076.28 1,931.78 4,200.00 36.32 268.00 2,155.27 2,010.77 4,243.85 35.00 268.00 2,190.89 2,046.39 4,300.00 34.51 265.17 2,237.03 2,092.53 4,400.00 33.80 259.98 2,319.80 2,175.30 4,500.00 33.31 254.62 2,403.16 2,258.66 4,570.92 33.11 250.76 2,462.50 2,318.00 Beluga 65 206,457.7110 3.0000 3,340.16 -148.28 4,597.53 33.07 249.30 2,484.79 2,340.29 End Dir : 4597.53' MD, 2484.79' ND 2,233,326.2540 206,451.7564 4,597.55 33.07 249.29 2,484.81 2,340.31 4,600.00 33.07 249.29 2,486.86 2,342.36 4,609.11 33.07 249.29 2,494.50 2,350.00 Beluga 70 2,233,291.7865 206,353.4787 0.0000 3,447.04 4,652.07 33.07 249.29 2,530.50 2,386.00 Beluga 72 -206.15 -3,497.67 2,233,273.7299 206,301.9940 4,700.00 33.07 249.29 2,570.67 2,426.17 4,800.00 33.07 249.29 2,654.47 2,509.97 4,868.05 33.07 249.29 2,711.50 2,567.00 Beluga 82 2,233,219.5604 206,147.5399 0.0000 3,658.21 4,900.00 33.07 249.29 2,738.28 2,593.78 5,000.00 33.07 249.29 2,822.08 2,677.58 5,100.00 33.07 249.29 2,905.89 2,761.39 5,200.00 33.07 249.29 2,989.69 2,845.19 5,300.00 33.07 249.29 3,073.50 2,929.00 5,400.00 33.07 249.29 3,157.30 3,012.80 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Kalotsa 5 TVD Reference: As -Built @ 144.50usft (HEC 169) MD Reference: As -Built @ 144.50usft (HEC 169) North Reference: True Survev Calculation Method: Minimum Curvature Map Map +N/ -S +E/ -W Northing Easting DLS Vert (usft) (usft) (usft) (usft) 1,310.00 Section -74.30 -2,127.57 2,233,372.5723 207,674.8567 3.0000 2,123.48 -75.69 -2,167.43 2,233,372.1400 207,634.9780 3.0000 2,163.26 -78.98 -2,261.81 2,233,371.1162 207,540.5482 3.0000 2,257.46 -82.22 -2,354.34 2,233,370.1125 207,447.9673 3.0000 2,349.81 -85.37 -2,444.77 2,233,369.1316 207,357.4891 3.0000 2,440.06 -88.45 -2,532.85 2,233,368.1761 207,269.3616 3.0000 2,527.97 -91.43 -2,618.34 2,233,367.2488 207,183.8263 3.0000 2,613.30 -94.32 -2,701.00 2,233,366.3521 207,101.1176 3.0000 2,695.80 -96.62 -2,766.74 2,233,365.6390 207,035.3414 3.0000 2,761.42 -97.10 -2,780.61 2,233,365.4885 207,021.4624 3.0000 2,775.26 -97.27 -2,785.58 2,233,365.4347 207,016.4947 3.0000 2,780.22 -99.39 -2,846.18 2,233,364.7773 206,955.8574 3.0000 2,840.71 -99.77 -2,856.95 2,233,364.6604 206,945.0788 3.0000 2,851.46 -102.31 -2,929.82 2,233,363.8701 206,872.1763 3.0000 2,924.18 -104.73 -2,999.00 2,233,363.1196 206,802.9547 3.0000 2,993.23 -107.01 -3,064.31 2,233,362.4111 206,737.6037 3.0000 3,058.42 -109.15 -3,125.58 2,233,361.7465 206,676.3025 3.0000 3,119.57 -110.04 -3,151.13 2,233,361.4694 206,650.7422 3.0000 3,145.07 -111.94 -3,183.07 2,233,360.3384 206,618.7621 3.0000 3,177.03 -119.16 -3,238.70 2,233,354.4553 206,562.9778 3.0000 3,233.11 -131.29 -3,292.58 2,233,343.6319 206,508.8238 3.0000 3,287.97 -142.84 -3,329.65 2,233,332.9771 206,471.4861 3.0000 3,326.06 -147.80 -3,343.30 2,233,328.3455 206,457.7197 3.0000 3,340.16 -147.80 -3,343.31 2,233,328.3424 206,457.7110 3.0000 3,340.16 -148.28 -3,344.56 2,233,327.8995 206,456.4480 0.0000 3,341.46 -150.03 -3,349.21 2,233,326.2540 206,451.7564 0.0000 3,346.27 -158.32 -3,371.13 2,233,318.4975 206,429.6402 0.0000 3,368.95 -167.57 -3,395.59 2,233,309.8430 206,404.9633 0.0000 3,394.25 -186.86 -3,446.63 2,233,291.7865 206,353.4787 0.0000 3,447.04 -199.98 -3,481.36 2,233,279.4995 206,318.4447 0.0000 3,482.96 -206.15 -3,497.67 2,233,273.7299 206,301.9940 0.0000 3,499.83 -225.44 -3,548.70 2,233,255.6734 206,250.5093 0.0000 3,552.62 -244.73 -3,599.74 2,233,237.6169 206,199.0246 0.0000 3,605.41 -264.02 -3,650.77 2,233,219.5604 206,147.5399 0.0000 3,658.21 -283.31 -3,701.81 2,233,201.5039 206,096.0553 0.0000 3,711.00 -302.60 -3,752.84 2,233,183.4474 206,044.5706 0.0000 3,763.79 812 7120 19 12:21:45PM Paw 4 COMPASS 5000.15 Build 91 HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Kalotsa 5 Companv: Hilcorp Alaska, LLC TVD Reference: As -Built @ 144.50usft (HEC 169) Proiect: Ninilchik Unit MD Reference: As -Built @ 144.50usft (HEC 169) Site: Kalotsa North Reference: True Well: Kalotsa 5 Survev Calculation Method: Minimum Curvature Wellbore: Kalotsa 5 Desiqn: Kalotsa 5 Wp07 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +El -W Northing Easting DLS Vert (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 3,096.61 Section 5,500.00 33.07 249.29 3,241.11 3,096.61 -321.89 -3,803.88 2,233,165.3909 205,993.0859 0.0000 3,816.58 5,600.00 33.07 249.29 3,324.91 3,180.41 -341.18 -3,854.91 2,233,147.3344 205,941.6012 0.0000 3,869.37 5,681.27 33.07 249.29 3,393.02 3,248.52 -356.86 -3,896.39 2,233,132.6600 205,899.7600 0.0000 3,912.27 Kalotsa 5 wp07 Beluga 135 5,700.00 33.07 249.29 3,408.72 3,264.22 -360.47 -3,905.95 2,233,129.2779 205,890.1165 0.0000 3,922.16 5,770.14 33.07 249.29 3,467.50 3,323.00 -374.00 -3,941.75 2,233,116.6126 205,854.0040 0.0000 3,959.19 Beluga 131 5,800.00 33.07 249.29 3,492.52 3,348.02 -379.76 -3,956.99 2,233,111.2214 205,838.6319 0.0000 3,974.95 5,833.38 33.07 249.29 3,520.50 3,376.00 -386.20 -3,974.02 2,233,105.1933 205,821.4440 0.0000 3,992.58 Beluga 134 5,900.00 33.07 249.29 3,576.33 3,431.83 -399.05 -4,008.02 2,233,093.1649 205,787.1472 0.0000 4,027.74 5,988.51 33.07 249.29 3,650.50 3,506.00 -416.12 -4,053.19 2,233,077.1837 205,741.5798 0.0000 4,074.47 Beluga 136 6,000.00 33.07 249.29 3,660.13 3,515.63 -418.34 -4,059.06 2,233,075.1084 205,735.6625 0.0000 4,080.53 6,100.00 - 33.07 249.29 3,743.94 • 3,599.44 -437.63 -4,110.09 2,233,057.0519 205,684.1778 0.0000 4,133.32 Total Depth : 6100' MD, 3743.94' TVD - 4 1/2" x 6-314" Tarqets Target Name hit/miss target Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing Easting Shape (°) (°) (usft) (usft) (usft) (usft) (usft) Kalotsa 5 wp07 Beluga 135 0.00 0.00 3,393.02 -356.86 -3,896.39 2,233,132.6600 205,899.7600 plan hits target center Circle (radius 100.00) Kalotsa 5 wp07 Beluga 10 0.00 0.00 1,405.50 -67.02 -1,919.06 2,233,374.8300 207,883.4800 plan hits target center Circle (radius 100.00) Casinq Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name 6,100.00 3,743.94 4 1/2" x 6-3/4" 4-1/2 6-3/4 120.00 120.00 16" 16 24 1,848.36 1,250.00 7 5/8" x 9-7/8" 7-5/8 9-7/8 8/27/2019 12:21:45PM Paae 5 COMPASS 5000.15 Build 91 HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Kalotsa 5 Company: Hilcorp Alaska, LLC TVD Reference: As -Built @ 144.50usft (HEC 169) Proiect: Ninilchik Unit MD Reference: As -Built @ 144.50usft (HEC 169) Site: Kalotsa North Reference: True Well: Kalotsa 5 Survey Calculation Method: Minimum Curvature Wellbore: Kalotsa 5 Desiqn: Kalotsa 5 Wp07 Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (usft) (usft) Name Lithology 4,652.07 2,530.50 Beluga 72 3,785.61 1,850.50 Beluga 47A 4,868.05 2,711.50 Beluga 82 2,816.63 1,419.50 Beluga 10 4,609.11 2,494.50 Beluga 70 3,682.28 1,784.50 Beluga 44 2,958.28 1,454.50 Beluga 13 5,833.38 3,520.50 Beluga 134 3,706.37 1,799.50 Beluga 45 1,373.30 1,141.50 Beluga 1 4,570.92 2,462.50 Beluga 65 5,770.14 3,467.50 Beluga 131 5,988.51 3,650.50 Beluga 136 Plan Annotations Measured Vertical Local Coordinates i Depth Depth +N/ -S +E/ -W (usft) (usft) (usft) (usft) Comment 200.00 200.00 0.00 0.00 Start Dir 4°/100' : 200' MD, 200'TVD 400.00 399.35 -0.49 -13.93 Start Dir 61/100' : 400' MD, 399.35'TVD 1,600.00 1,206.87 -27.70 -793.27 End Dir : 1600' MD, 1206.87' TVD 2,743.85 1,405.50 -67.01 -1,919.06 Start Dir 3°/100' : 2743.85' MD, 1405.5'TVD 4,597.53 2,484.79 -147.80 -3,343.30 End Dir : 4597.53' MD, 2484.79' TVD 6,100.00 3,743.94 -437.63 -4,110.09 Total Depth : 6100' MD, 3743.94' TVD 8/27/2019 12:21:45PM Paae 6 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Ninilchik Unit Kalotsa Kalotsa 5 Kalotsa 5 Kalotsa 5 Wp07 Sperry Drilling Services Clearance Summary Anticollision Report 27 August, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Reference Design: Kalotsa - Kalotsa 5 - Kalotsa 5 - Kalotsa 5 Wp07 Well Coordinates: 2,233,395.65 N, 209,803.59 E (6W 06' 14.08" N, 151° 35'25.26" W) Datum Height: As -Built @ 144.50usft (HEC 169) Scan Range:0.00 to 6,100.00 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usft Geodetic Scale Factor Applied Version: 5000.15 Build: 91 Scan Type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Scan Type: 25.00 HALLIBURTON Sperry Drilling Services Hilcorp Alaska, LLC H A LL I B U R TO N Ninilchik unit Anticollision Report for Kalotsa 5 - Kalotsa 5 Wp07 Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) 100.07 43.086 Ellipse Separation Reference Design: Kalotsa - Kalotsa 5 - Kalotsa 5 - Kalotsa 5 Wp07 86.09 201.20 46.465 Centre Distance Scan Range: 0.00 to 6,100.00 usft. Measured Depth. 120.30 538.94 28.754 Clearance Factor Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usft 65.339 Centre Distance Measure Minimum @Measure Site Name d Distance d Comparison Well Name - Wellbore Name - Design D..mh ri._cal Denrh Kalotsa Pass - 148.43 99.54 Kalotsa 1 - Kalotsa 1 - Kalotsa 1 100.00 88.11 100.00 Kalotsa 1 - Kalotsa 1 - Kalotsa 1 201.17 87.98 201.17 Kalotsa 1 - Kalotsa 1 - Kalotsa 1 550.00 124.63 550.00 Kalotsa 2 - Kalotsa 2 - Kalotsa 2 18.00 118.78 18.00 Kalotsa 2 - Kalotsa 2 - Kalotsa 2 100.00 118.84 100.00 Kalotsa 2 - Kalotsa 2 - Kalotsa 2 600.00 157.13 600.00 Kalotsa 3 - Kalotsa 3 - Kalotsa 3 18.00 150.35 18.00 Kalotsa 3 - Kalotsa 3 - Kalatsa 3 100.00 150.47 100.00 Kalotsa 3 - Kalotsa 3 - Kalotsa 3 675.00 232.02 675.00 Kalotsa 4 - Kalotsa 4 - Kalotsa 4 18.00 176.45 18.00 Kalotsa 4 - Kalotsa 4 - Kalotsa 4 100.00 176.45 100.00 Kalotsa 4 - Kalotsa 4 - Kalotsa 4 1,400.00 491.98 1,400.00 Kalotsa 6 - Kalotsa 6 - Kalotsa 6 Wp04 100.00 46.38 100.00 Kalotsa 6 - Kalotsa 6 - Kalotsa 6 Wp04 200.00 46.38 200.00 Kalotsa 6 - Kalotsa 6 - Kalatsa 6 Wp04 400.00 56.36 400.00 Paxton Pass - 506.91 3,938.51 Paxton #1 - Paxton #1 - Paxton #1 5,600.00 680.95 5,600.00 Paxton #1 - Paxton #1 - Paxton #1 5,725.00 668.72 5,725.00 Paxton #1 - Paxton #1 - Paxton #1 5,750.07 668.36 5,750.07 Paxton #7 - Paxton #7 - Paxton #7 4,200.00 463.08 4,200.00 Paxton #7 - Paxton #7 - Paxton #7 4,250.00 457.54 4,250.00 Paxton #7 - Paxton #7 - Paxton #7 4,271.30 457.01 4,271.30 Paxton #9 - Paxton #9 - Paxton #9 4,125.00 578.59 4,125.00 Paxton #9 - Paxton #9 - Paxton #9 4,200.00 568.01 4,200.00 Paxton #9 - Paxton #9 - Paxton #9 4,227.61 567.18 4,227.61 Ellipse @Measure Clearance Summary Based Separation d Factor on Minimum h.sftl 0-th Separation Warning 86.06 100.07 43.086 Ellipse Separation Pass - 86.09 201.20 46.465 Centre Distance Pass - 120.30 538.94 28.754 Clearance Factor Pass - 116.96 18.00 65.339 Centre Distance Pass - 116.80 99.82 58.126 Ellipse Separation Pass - 152.63 592.22 34.938 Clearance Factor Pass - 148.53 18.00 82.704 Centre Distance Pass - 148.43 99.54 73.615 Ellipse Separation Pass - 226.81 635.84 44.563 Clearance Factor Pass - 174.63 18.00 97.063 Centre Distance Pass - 174.41 100.00 86.294 Ellipse Separation Pass - 479.68 1,449.34 40.018 Clearance Factor Pass - 43.55 99.90 16.407 Ellipse Separation Pass - 44.00 199.90 19.544 Centre Distance Pass - 52.72 399.29 15.473 Clearance Factor Pass - 612.68 4,391.37 9.974 Clearance Factor Pass - 602.89 4,452.07 10.159 Ellipse Separation Pass - 603.07 4,464.29 10.237 Centre Distance Pass - 399.73 3,957.77 7.310 Clearance Factor Pass - 395.97 3,970.14 7.432 Ellipse Separation Pass - 396.40 3,975.17 7.540 Centre Distance Pass - 515.07 3,916.76 9.109 Clearance Factor Pass - 506.69 3,932.56 9.264 Ellipse Separation Pass - 506.91 3,938.51 9.412 Centre Distance Pass - 27 August, 2019 - 12:10 Page 2 of 5 COMPASS HALLIBURTON Anticollision Report for Kalotsa 5 - Kalotsa 5 Wp07 Survev tool program From To Survey/Plan Survey Tool rusfrl lusftl 18.00 1,848.00 Kalotsa 5 Wp07 3_MWD+IFRI+MS+Sag 1,848.00 6,100.00 Kalotsa 5 Wp07 3_MWD+IFRI+MS+Sag Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. Hilcorp Alaska, LLC Ninilchik Unit 27 August, 2019 - 12:10 Page 3 of 5 COMPASS r HALLIBURTON Project: Ninllchik Unit REFERENCE INFORMATION WELL DETAIIS1Calorsa 5 NAD 1927 (NADCON CONUS) Alaska Zane 04 Kalotsa well: Well: Kalotsa 5 Co -o ,i le (NE) Reference: Well Kalotsa 5, True (HE (D/D) Reference: 0.s -Built ®144.50usft (HEC 169) 126.50 ESpxrry Orllling Wellbore: Kalot a 5 Measured Dep(hRa(erence:As-auilt@144.50usft (HEC 169) +N/-$ .-1 +E/ -W Narlhing Fasting [ati[Nde Longi .& Plan: Kalotsa 5 Wp07 Calculation WN . Minimum Curvature 0.00 0.00 2233395.6510 209503.5930 60` 6' 14.0808 N 151° 35"_5.2639 W SURVEY PROGRAM GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Date: 2()IM8-t3T-W:00 Validated: Yes Version: 18.00 To 6100.00 Depth Fmm DepM To Surrey/Plan Tool CASING DETAILS 18.00 1848.00 Kelotsa5 Wp0](Kalootsa 5) 3_MWD+IFRI+MS+Sag adder/S.F. Plots 848.00 6100.00 Kalolsa5 Wp0](Kaloo 5) MS F-L sa 3_MWD.W141 9 TVD TVDSS MD Size Nanta 120.00 -24.50 120.00 16 16" 1250.00 1105.50 1848.36 7-5/8 7 5/8" x 9-7l8" Kalotsa 4 3743 94 3599.44 6100.00 4-1/2 4 1/2" x 6-3/4" 175.00 ...�.^• - - i Kalotsa 3 I -140.00 CD ----.._ Y 1.1 __ ! T j 0 C3 Kalotsa 2 I - ------- I 0105.o0 __ ,-.. .. _ _ __ __..._.__-_ _......._._...._._.... cc u) Kalotsa � 70.00- ._.............. ..........._..._.__. Kalotsa 6 U r/ o � 35.0o- 5.00 ,.00 0.00 i 0 350 700 1050 1400 1750 2100 2450 2800 3150 3500 3850 4200 4550 4900 5250 5600 5950 630 Measured Depth 4.50 -_.-_. _-_.._. ... - .... _._.._ I 3.00 ILL c Collision Risk Procedures Req i CX Collision Avoidance Req. I j 1.50 No -Go Zone - Stop Drilling I NOERRORS I 0.00 0 350 700 1050 1400 1750 21170 2450 2800 3150 3500 3850 4200 4550 4900 5250 5600 5950 Measured Depth TRANSMITTAL LETTER CHECKLIST WELL NAME: ��d��=� PTD: 22 -le?— /" % 2 Development Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: (C POOL:�� Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- - - - (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69 In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - - -� from records, data and logs acquired for well name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company 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 target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements 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. Revised 2/2015 WELL PERMIT CHECKLIST held a Pool NINILCHIK, BELUGA-TYONEK GAS -. 562503 Well Name: NINILCHIK UNIT KA_LOM$.A 5 Program DSV Well bore seg ❑ PTD#: 2191270 Company HilcQMAlaska�� _ . Initial Classrrype _.DEV / PENR_ GeoArea 820 Unit 51432 _ ONOff Shore On Annular Disposal ❑ Administration 1 Permit. fee attached... ... NA. 2 Lease number appropriate. _ _ _ Yes _ Surface Location lies within Fee_CIRI; Top Prod Int & TD lie within. ADL0384372. 3 Unique well name and number _ _ _ _ _ Yes ... NINILCHIK, BELUGA-TYONEK GAS —562503, governed. by C0 701G 4 Well located in a. defined pool _ _ .... _ _ _ _ Yes _ _ Rule 3 (Well. Spacing) There shall be no gas well spacing restrictions within the Affected Area, except: _ 5 Well located proper distance from drilling unit boundary _ .... _ Yes _ _ A). No gas well shall be drilled or completed less than 1.,500 feel from the exterior boundary of the 6 Well located proper distance from other wells _ _ _ Yes _ _ Affected Area unless. the owner and landowner is the same on both sides. of the line. 7 Sufficient acreage available in drilling unit _ _ _ _ _ _ _ _ _ .. _ .. Yes _ _ _ _ B).No gas well shall be drilled or completed less than 1,500 feet from an uncommitted tract within the 8 If deviated, is wellbore plat. included _ _ _ _ Yes ..... Ninilchik Unit unless the well and the uncommitted tract both lie within the same Participating Area....... 9 Operator only affected party_ _ _ _ _ _ _ . _ _ _ _ .. _ _ _ _ _ _ . Yes _ _ As planned, this well conforms to C0 701C, Rule 3 (Well Spacing) 10 Operator has. appropriate bond in forte _ _ _ _ ..... Yes 11 Permit can be issued without conservation order. _ _ Yes Appr Date '.12 Pemlit.can be issued without administrative. approval _ _ Yes SFD 9/16/2019 13 Can permit be approved before 15 -day wait_ _ _ _ ...... Yes _ _ _ 14 Well located within area and strata authorized by. Injection Order # (put. 10# in, comments)_ (For, NA. _ 15 All wells within 1/4. mile area of review identified (For service well only) . .. _ _ _ _ NA. 16 Pre -produced injector; duration of pre -production less than 3 months. (For service well only) NA... 17 18 Noncori gas conforms to AS31.05.0300.1.A),Q,2.A-D) .. _ _ _ _ _ _ _ _ _ _ _ _ Conductor string. provided _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .......... . . .. NA. Yes _ _ _ _ 16" conductor set at 120 ft. Engineering 19 Surface casing protects all known USDWs _ _ _ _ _ _ ... Yes .. _ _ Surface casing set at 1250 ft TVD 20 CMT vol adequate. to circulate on conductor & surf csg _ ....... . . .... . . .. . . Yes _ ....... 21 CMT vol adequate to tie-in long string to surf csg_ _ _ _ _ _ _ _ _ Yes _ _ 4.5" _longstring will be cemented back to Surf casing .... also using swell packer at 1600 ft. . 22 CMT will cover all known productive horizons........ _ _ _ _ _ _ _ Yes ...... 23 Casing designs adequate for C, T, B &,permafrost_ _ _ _ .. _ ..... Yes _ _ _ BTG calor supplied_ 24 Adequate tankage. or reserve pit .. _ Yes _ _ _ Rig 169 has steel pits , All waste to approved disposal well _ 25 If a re -drill, has. a 10-403 for abandonment been approved ... _ _ _ _ _ _ .. _ _ _ _ NA .......... . . . . . . . 26 Adequate wellbore separation proposed _ _ _ _ _ _ _ _ _ _ _ _ _ _ _Yes _ _ _ No issues 27 If diverter required, does it meet regulations_ _ _ _ .. _ _ _ _ _ _ Yes .. - Diverler Waived per 20 AAC ?5.035(h)(2). Nearest well 750 ft away Appr Date 28 Drilling fluid program schematic & equip list adequate _ ... _ _ Yes Max formation pressure =.1707 psi ( 8.7 ppg_EMW) Drill with 9.0-9,5_ ppg mud GLS 9/26/2019 29 BOPEs,.do they meet regulation _ _ ..... _ _ Yes ... _ 169 has 5000psi WP BOPS 30 ROPE press rating appropriate; test to (put psig in comments)... _ _ Yes _ _ _ _ _ MASP = 1328.psi Will testBOPE, t0 2500 psi .. . 31 Choke. manifold complies w/API. RP -53 (May 84) _ _ _ _ _ _ .. _ Yes 32 Work will occur without operation shutdown_ ...... _ _ _ _ _ Yes .. Separate sundry to perforate well....... _ 33 Is presence of H2S gas probable _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ No 34 Mechanical condition of wells within AOR verified (For service well only), _ _ _ _ _ _ ... NA ... 135 Permit. can be issued w/o hydrogen sulfide measures _ ...... _ _ _ _ Yes .... H2S is not anticipated based on nearby wells.. Geology 36 Data presented on potential overpressure zones _ _ _ .... . . . . . . ..... _ Yes _ .... _ Maximum expected reservoir. pressure is 8,7. ppg EMW; however, most sands encountered are expected . Appr Date 37 Seismic analysis of shallow gas zones _ .. ... ... _ _ _ _ _ _ _ _ _ _ NA ...... to be depleted to severely depleted. Production interval will be drilled using _9 0 to 9.5 ppg mud. SFD 9/16/2019 38 Seabed condition survey.(if off -shore) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ..... _ _ NA. _ .. _ _ _ Additional materials will be onsite to build mud to 1 ppg more than the greatest anticipated. mgdweight.. . 39 Contact name/phone for weekly_ progress reports. [exploratory only.] _ _ _ _ _ _ _ _ _ _ NA..... Geologic Engineering Date Public Date Cement packer well... need CBL to verify TOC . MIT -IA required post rig. GIs . Date: Commissioner: Commissioner: Commissioner