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Home My WebLink About219-114Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 09/12/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250912 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 223-34T 50283202060000 225059 8/28/2025 AK E-LINE Perf BRU 224-34T 50283202050000 225044 8/19/2025 AK E-LINE CIBP BRU 224-34T 50283202050000 225044 8/17/2025 AK E-LINE Perf BRU 224-34T 50283202050000 225044 8/22/2025 AK E-LINE Perf BRU 224-34T 50283202050000 225044 8/27/2025 AK E-LINE Perf BRU 241-23 50283201910000 223061 8/20/2025 AK E-LINE Plug/Perf GP 11-13RD 50733200260100 191133 8/29/2025 AK E-LINE Perf KALOTSA 6 50133206850000 219114 8/14/2025 AK E-LINE PPROF MGS ST 17595 06 50733100730000 166003 8/19/2025 AK E-LINE Drift MGS ST 17595 06 50733100730000 166003 8/26/2025 AK E-LINE Drift MGS ST 17595 11 50733200130000 167017 8/17/2025 AK E-LINE CBL MGS ST 17595 20 50733203770000 185135 8/21/2025 AK E-LINE CBL MPI 1-61 50029225200000 194142 8/19/2025 AK E-LINE Patch NCIU A-21A 50883201990100 225075 8/23/2025 AK E-LINE Perf END 1-23 50029225100000 194128 7/14/2025 HALLIBURTON MFC40 END 2-74 50029237850000 224024 7/12/2025 HALLIBURTON MFC40 END 3-07A 50029219110100 198147 7/13/2005 HALLIBURTON COILFLAG END 3-15 50029217510000 187094 7/15/2025 HALLIBURTON MFC24 NS-20 50029231180000 202188 9/2/2025 HALLIBURTON COILFLAG PBU 01-13A 50029202700100 225052 8/18/2025 HALLIBURTON RBT-COILFLAG PBU 07-24A 50029209450100 225045 8/3/2025 HALLIBURTON RBT-COILFLAG PBU C-34C 50029217850300 225068 8/25/2025 HALLIBURTON RBT SD-07 50133205940000 211050 8/14/2025 HALLIBURTON TMD3D ODSK-14 50703206100000 209155 9/8/2025 READ CaliperSurvey Please include current contact information if different from above. T40874 T40875 T40875 T40875 T40875 T40876 T40877 T40878 T40879 T40879 T40880 T40881 T40882 T40883 T40884 T40885 T40886 T40887 T40888 T40889 T40890 T40891 T40892 T40893 KALOTSA 6 50133206850000 219114 8/14/2025 AK E-LINE PPROF Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.09.12 14:33:03 -08'00' 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: 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): 5,745'N/A Casing Collapse Structural Conductor 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 Swell Pkr & N/A 1,466 (MD) 1,209 (TVD) & N/A 3,643'5,710'3,614' Ninilchik Beluga-Tyonek Gas 16" 7-5/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 NINILCHIK UNIT KALOTSA 6CO 701C Same 3,6354-1/2" 1,021 psi 5,735 N/A Length July 29, 2025 Cap String 3/8" 5,735 Perforation Depth MD (ft): See Attached Schematic 6,890psi 120120 1,654 Size 120 1,654 MD Hilcorp Alaska, LLC Proposed Pools: TVD Burst 1,923 8,430psi 1,257 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 219-114 50-133-20685-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Scott Warner, Operations Engineer AOGCC USE ONLY Tubing Grade: 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: m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 8:19 am, Jul 15, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.07.14 16:38:35 - 08'00' Noel Nocas (4361) 325-420 DSR-7/16/25SFD 7/22/2025 10-404 Request and obtain AOGCC approval before setting any plugs. BJM 7/22/25JLC 7/23/2025 Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.07.23 14:39:12 -08'00' 07/23/25 RBDMS JSB 072425 Well Prognosis Well Name: Kalotsa 6 API Number: 50-133-20685-00-00 Current Status: Producing Gas Well Permit to Drill Number: 219-114 Regulatory Contact: Donna Ambruz (907) 777-8305 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: 1321 psi @ 3002’ TVD Based on 0.44 psi/ft at deepest proposed perf. Existing perforations are depleted and not at original pressure Max. Potential Surface Pressure:1021 psi Based on 0.1 psi/ft gas gradient to surface Applicable Frac Gradient: 0.82 psi/ft using 15.7 ppg EMW Average FIT at the surface casing shoes across the Kalotsa structure Shallowest Allowable Perf TVD: MPSP/(0.82-0.1) = 1021 psi / 0.72 = 1418‘ TVD Top of Applicable Gas Pool:2508’ MD/ 1412’ TVD Well Status: Online Gas Producer flowing at 726 mcfd, 3 bwpd, 53 psi FTP Recent SITP: 641 psi post perforations on 3/4/24 Brief Well Summary Kalotsa 6 was drilled and completed in October 2019, targeting the Beluga 134 sands. Additional lower Beluga sands were perforated in 2020 and 2022, providing steady production until 2023, when a capillary string was installed to assist with water unloading. In 2024, the Beluga 120-74 interval was perforated, followed by the reinstallation of the capillary string to maintain well performance. This sundry request proposes adding new Upper Beluga perforations to enhance production. Notes Regarding Wellbore Condition x Inclination o Max deviation of 81° @ 2311’ MD x Min ID o 3.958” – 4-1/2” monobore x Recent Tags o 3/20/24 Cap string ran to 1923’ MD. Worked cap string to 2050’ but was unable to get deeper o 3/2/24 EL w/tractor tagged @ 5655’ MD, sticky when picking off bottom. Tractor required from 1700’ – 3200’ before being able to free fall. Perforated sands with the well shut in from BEL 120 -BEL 74 (5551’- 4566’) w/ 2-3/8” guns on switch Pre-Sundry Steps: 1. MIRU Cap string truck 2. Pull 3/8” cap string from 1923’ MD 3. RD cap string truck Procedure: 1. MIRU E-line w/ tractor and pressure control equipment 2. PT lubricator to 250 psi low / 2,000 psi high 3. RIH and perforate Beluga 5 – BEL 93 sands from bottom up: 0.82 psi/ft using 15.7 ppg EMW Average FIT at the surface casing shoes across the Kalotsa structure See attached emails. SFD Well Prognosis 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 Zone Top MD Btm MD Top TVD Btm TVD Footage BEL 5 ±2,544' ±2,550' ±1,420' ±1,421' ±6' BEL 5 ±2,567' ±2,573' ±1,424' ±1,426' ±6' BEL 10 ±2,633' ±2,683' ±1,438' ±1,449' ±50' BEL 10 ±2,697' ±2,727' ±1,453' ±1,460' ±30' BEL 12 ±2,766' ±2,773' ±1,470' ±1,472' ±7' BEL 13 ±2,802' ±2,827' ±1,479' ±1,487' ±25' BEL 13 ±2,837' ±2,844' ±1,490' ±1,492' ±7' BEL 15 ±2,857' ±2,863' ±1,496' ±1,498' ±6' BEL 16 ±2,873' ±2,879' ±1,501' ±1,503' ±6' BEL 16 ±2,896' ±2,945' ±1,509' ±1,527' ±49' BEL 16 ±2,956' ±2,966' ±1,532' ±1,535' ±10' BEL 20 ±3,046' ±3,056' ±1,569' ±1,573' ±10' BEL 23 ±3,062' ±3,069' ±1,576' ±1,579' ±7' BEL 23 ±3,075' ±3,089' ±1,581' ±1,588' ±14' BEL 23 ±3,089' ±3,127' ±1,588' ±1,605' ±38' BEL 30 ±3,160' ±3,170' ±1,620' ±1,625' ±10' BEL 30 ±3,170' ±3,189' ±1,625' ±1,634' ±19' BEL 30 ±3,209' ±3,215' ±1,644' ±1,647' ±6' BEL 34 ±3,231' ±3,237' ±1,654' ±1,657' ±6' BEL 37 ±3,260' ±3,270' ±1,669' ±1,674' ±10' BEL 38 ±3,285' ±3,291' ±1,682' ±1,685' ±6' BEL 38 ±3,295' ±3,312' ±1,687' ±1,696' ±17' BEL 38 ±3,319' ±3,325' ±1,700' ±1,703' ±6' BEL 40 ±3,336' ±3,352' ±1,709' ±1,717' ±16' BEL 40 ±3,362' ±3,382' ±1,723' ±1,734' ±20' BEL 41 ±3,401' ±3,408' ±1,745' ±1,748' ±7' BEL 41 ±3,429' ±3,437' ±1,760' ±1,765' ±8' BEL 43 ±3,455' ±3,468' ±1,775' ±1,783' ±13' BEL 44 ±3,490' ±3,510' ±1,796' ±1,808' ±20' BEL 44 ±3,510' ±3,524' ±1,808' ±1,816' ±14' BEL 45 ±3,526' ±3,532' ±1,818' ±1,821' ±6' BEL 45 ±3,542' ±3,548' ±1,827' ±1,831' ±6' BEL 46 ±3,556' ±3,571' ±1,836' ±1,845' ±15' BEL 46 ±3,580' ±3,590' ±1,850' ±1,857' ±10' BEL 47 ±3,605' ±3,611' ±1,866' ±1,870' ±6' BEL 47 ±3,615' ±3,621' ±1,872' ±1,876' ±6' BEL 47 ±3,627' ±3,641' ±1,880' ±1,889' ±14' Well Prognosis BEL 48 ±3,651' ±3,657' ±1,895' ±1,899' ±6' BEL 48 ±3,673' ±3,685' ±1,909' ±1,917' ±12' BEL 48 ±3,689' ±3,695' ±1,920' ±1,924' ±6' BEL 49 ±3,752' ±3,762' ±1,963' ±1,970' ±10' BEL 49 ±3,764' ±3,770' ±1,971' ±1,975' ±6' BEL 49 ±3,778' ±3,788' ±1,981' ±1,988' ±10' BEL 49 ±3,789' ±3,797' ±1,989' ±1,994' ±8' BEL 50 ±3,825' ±3,853' ±2,014' ±2,035' ±28' BEL 51 ±3,876' ±3,895' ±2,052' ±2,066' ±19' BEL 52 ±3,918' ±3,924' ±2,084' ±2,088' ±6' BEL 52 ±3,930' ±3,940' ±2,093' ±2,101' ±10' BEL 54 ±3,981' ±4,083' ±2,133' ±2,215' ±102' BEL 55 ±4,094' ±4,110' ±2,224' ±2,237' ±16' BEL 56 ±4,114' ±4,144' ±2,240' ±2,265' ±30' BEL 56 ±4,154' ±4,174' ±2,273' ±2,290' ±20' BEL 58 ±4,184' ±4,190' ±2,298' ±2,303' ±6' BEL 58 ±4,213' ±4,219' ±2,323' ±2,328' ±6' BEL 58A ±4,236' ±4,241' ±2,342' ±2,346' ±5' BEL 58A ±4,243' ±4,248' ±2,348' ±2,352' ±5' BEL 58A ±4,250' ±4,256' ±2,354' ±2,359' ±6' BEL 59 ±4,317' ±4,323' ±2,410' ±2,415' ±6' BEL 60 ±4,362' ±4,365' ±2,448' ±2,451' ±3' BEL 65 ±4,410' ±4,422' ±2,490' ±2,500' ±12' BEL 65 ±4,436' ±4,442' ±2,512' ±2,517' ±6' BEL 72 ±4,484' ±4,490' ±2,554' ±2,559' ±6' BEL 73 ±4,510' ±4,516' ±2,577' ±2,582' ±6' BEL 73 ±4,520' ±4,525' ±2,585' ±2,590' ±5' BEL 74 ±4,531' ±4,537' ±2,595' ±2,600' ±6' BEL 74 ±4,558' ±4,564' ±2,618' ±2,623' ±6' BEL 81 ±4,662' ±4,667' ±2,709' ±2,713' ±5' BEL 81 ±4,670' ±4,676' ±2,716' ±2,721' ±6' BEL 82 ±4,691' ±4,701' ±2,734' ±2,742' ±10' BEL 83 ±4,720' ±4,727' ±2,759' ±2,765' ±7' BEL 90 ±4,767' ±4,777' ±2,800' ±2,808' ±10' BEL 90 ±4,797' ±4,803' ±2,826' ±2,831' ±6' BEL 90 ±4,809' ±4,814' ±2,836' ±2,840' ±5' BEL 90 ±4,815' ±4,821' ±2,841' ±2,847' ±6' BEL 90 ±4,826' ±4,831' ±2,851' ±2,855' ±5' BEL 91 ±4,852' ±4,858' ±2,874' ±2,879' ±6' BEL 92 ±4,938' ±4,943' ±2,948' ±2,952' ±5' BEL 92 ±4,958' ±4,966' ±2,965' ±2,972' ±8' BEL 92 ±4,973' ±4,983' ±2,978' ±2,987' ±10' BEL 93 ±5,001' ±5,009' ±3,002' ±3,009' ±8' Well Prognosis 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. i. Patch will most likely be used to avoid shutting off current production. g. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations 4. RDMO 5. 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 SRW 04-9-24 SCHEMATIC Ninilchik Unit Kalotsa #6 PTD: 219-114 API: 50-133-20685-00-00 PBTD = 5,710’ MD / 3,614’ = TVD TD = 5,745’ MD / 3,643’ = TVD RKB to GL = 18’ RA Tags Joint Tops: 1728, 2224, 2720, 3216, 3713, 4209, 4701, 5198’(all MD) OPEN HOLE / CEMENT DETAIL 7-5/8"9-7/8” Hole: 77.5 bbls of 12ppg Class A lead cement and 32.5 bbls 15.8ppg Class A tail cement pumped with 100% returns and 30bbls cement back to surface. 4-1/2” 6-3/4” Hole: 126 bbls of 12ppg class A lead cement and 18 bbls of 15.3ppg class A tail cement pumped with 7bbl losses throughout job and 17bbl spacer back to surface. 10/10/19 CBL shows good cement up to 1150’ MD except for patchy cement from 3700’ - 4110’ MD. 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 1,654’ 4-1/2"Prod Csg 12.6 L-80 DWC/C HT 3.958”Surf 5,735’ 1 16” 7-5/8” 9-7/8” hole 4-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 1,466’3.958”6.875”Swell Packer 6-3/4” hole BEL 134 PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Amt Date Status BEL 74 4,566'4,573'2,625'2,631'7'3/4/2024 Open BEL 80 4,646'4,655'2,696'2,703'9'3/4/2024 Open BEL 90 4,779'4,784'2,810'2,814'5'3/4/2024 Open BEL 91 4,861'4,867'2,881'2,886'6'3/4/2024 Open BEL 91 4,871'4,876'2,890'2,894'5'3/4/2024 Open BEL 92 4,921'4,927'2,833'2,839'6'3/4/2024 Open BEL 93 5,013'5,018'3,013'3,016'5'3/3/2024 Open BEL 94 5,045'5,049'3,040'3,045'4'3/3/2024 Open BEL 95 5,092'5,096'3,082'3,084'4'3/3/2024 Open BEL 95 5,106'5,111'3,094'3,098'5'3/3/2024 Open BEL 96 5,136'5,142'3,120'3,126'6'3/3/2024 Open BEL 97 5,168'5,173'3,148'3,153'5'3/3/2024 Open BEL 97 5,177'5,181'3,156'3,159'4'3/3/2024 Open BEL 98 5,191'5,201'3,168'3,176'10'3/3/2024 Open BEL 99 5,226'5,230'3,198'3,202'4'3/3/2024 Open BEL 99 5,236'5,240'3,207'3,210'4'3/3/2024 Open BEL 99A 5,253'5,258'3,222'3,226'5'3/3/2024 Open BEL 99B 5,268'5,272'3,235'3,238'4'3/2/2024 Open BEL 99B 5,275'5,279'3,240'3,245'4'3/2/2024 Open BEL 100 5,290'5,307'3,254'3,268'17'3/2/2024 Open BEL 100 5,325'5,329'3,284'3,288'4'3/2/2024 Open BEL 100 5,340'5,353'3,297'3,308'13'3/2/2024 Open BEL 110 5,388'5,402'3,338'3,351'14'3/2/2024 Open BEL 115 5,427’5,440’3,372’3,383’13’7/15/2022 Open BEL 120 5,463'5,468'3,405'3,408'5'3/2/2024 Open BEL 120 5,491'5,501'3,427'3,436'10'3/2/2024 Open BEL 120 5,537'5,541'3,467'3,471'4'3/2/2024 Open BEL 120 5,543'5,551'±3,472'±3,479'±8'3/2/2024 Open BEL 131 5,557’5,567’3,484’3,494’10’7/24/2020 Open BEL 132 5,575’5,594’3,499’3,516’19’7/23/2020 Open BEL 134 5,624’5,682’3,541’3,590’58’10/17/2019 Open BEL 131 BEL 132 BEL 115 BEL 74 – BEL 110 BEL 120 Capillary String (3/8”): Installed 03/19/2024 Top Bottom MD 0 1,923’ TVD 0 1,310’ Updated by SRW 07-02-25 PROPOSED Ninilchik Unit Kalotsa #6 PTD: 219-114 API: 50-133-20685-00-00 PBTD = 5,710’ MD / 3,614’ = TVD TD = 5,745’ MD / 3,643’ = TVD RKB to GL = 18’ RA TAGS Joint Tops: 1728, 2224, 2720, 3216, 3713, 4209, 4701, 5198’ (all MD) OPEN HOLE / CEMENT DETAIL 7-5/8"9-7/8” Hole: 77.5 bbls of 12ppg Class A lead cement and 32.5 bbls 15.8ppg Class A tail cement pumped with 100% returns and 30bbls cement back to surface. 4-1/2” 6-3/4” Hole: 126 bbls of 12ppg class A lead cement and 18 bbls of 15.3ppg class A tail cement pumped with 7bbl losses throughout job and 17bbl spacer back to surface. 10/10/19 CBL shows good cement up to 1150’ MD except for patchy cement from 3700’ - 4110’ MD. 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 1,654’ 4-1/2"Prod Csg 12.6 L-80 DWC/C HT 3.958”Surf 5,735’ 1 16” 7-5/8” 9-7/8” hole 4-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 1,466’3.958”6.875”Swell Packer 6-3/4” hole BEL 134 PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Amt Date Status BEL 5 ±2,544'±2,550'±1,420'±1,421'±6'TBD Proposed BEL 5 ±2,567'±2,573'±1,424'±1,426'±6'TBD Proposed BEL 10 ±2,633'±2,683'±1,438'±1,449'±50'TBD Proposed BEL 10 ±2,697'±2,727'±1,453'±1,460'±30'TBD Proposed BEL 12 ±2,766'±2,773'±1,470'±1,472'±7'TBD Proposed BEL 13 ±2,802'±2,827'±1,479'±1,487'±25'TBD Proposed BEL 13 ±2,837'±2,844'±1,490'±1,492'±7'TBD Proposed BEL 15 ±2,857'±2,863'±1,496'±1,498'±6'TBD Proposed BEL 16 ±2,873'±2,879'±1,501'±1,503'±6'TBD Proposed BEL 16 ±2,896'±2,945'±1,509'±1,527'±49'TBD Proposed BEL 16 ±2,956'±2,966'±1,532'±1,535'±10'TBD Proposed BEL 20 ±3,046'±3,056'±1,569'±1,573'±10'TBD Proposed BEL 23 ±3,062'±3,069'±1,576'±1,579'±7'TBD Proposed BEL 23 ±3,075'±3,089'±1,581'±1,588'±14'TBD Proposed BEL 23 ±3,089'±3,127'±1,588'±1,605'±38'TBD Proposed BEL 30 ±3,160'±3,170'±1,620'±1,625'±10'TBD Proposed BEL 30 ±3,170'±3,189'±1,625'±1,634'±19'TBD Proposed BEL 30 ±3,209'±3,215'±1,644'±1,647'±6'TBD Proposed BEL 34 ±3,231'±3,237'±1,654'±1,657'±6'TBD Proposed BEL 37 ±3,260'±3,270'±1,669'±1,674'±10'TBD Proposed BEL 38 ±3,285'±3,291'±1,682'±1,685'±6'TBD Proposed BEL 38 ±3,295'±3,312'±1,687'±1,696'±17'TBD Proposed BEL 38 ±3,319'±3,325'±1,700'±1,703'±6'TBD Proposed BEL 40 ±3,336'±3,352'±1,709'±1,717'±16'TBD Proposed BEL 40 ±3,362'±3,382'±1,723'±1,734'±20'TBD Proposed BEL 41 ±3,401'±3,408'±1,745'±1,748'±7'TBD Proposed BEL 41 ±3,429'±3,437'±1,760'±1,765'±8'TBD Proposed BEL 43 ±3,455'±3,468'±1,775'±1,783'±13'TBD Proposed BEL 44 ±3,490'±3,510'±1,796'±1,808'±20'TBD Proposed BEL 44 ±3,510'±3,524'±1,808'±1,816'±14'TBD Proposed BEL 45 ±3,526'±3,532'±1,818'±1,821'±6'TBD Proposed BEL 45 ±3,542'±3,548'±1,827'±1,831'±6'TBD Proposed BEL 46 ±3,556'±3,571'±1,836'±1,845'±15'TBD Proposed BEL 46 ±3,580'±3,590'±1,850'±1,857'±10'TBD Proposed BEL 47 ±3,605'±3,611'±1,866'±1,870'±6'TBD Proposed BEL 47 ±3,615'±3,621'±1,872'±1,876'±6'TBD Proposed BEL 47 ±3,627'±3,641'±1,880'±1,889'±14'TBD Proposed BEL 48 ±3,651'±3,657'±1,895'±1,899'±6'TBD Proposed PERFORATION DETAIL - Continued on following page BEL 131 BEL 132 BEL 115 BEL 74 – BEL 110 BEL 120 PROPOSED Ninilchik Unit Kalotsa #6 PTD: 219-114 API: 50-133-20685-00-00 PERFORATION DETAIL Continued from previous page Sand Top MD Btm MD Top TVD Btm TVD Amt Date Status BEL 48 ±3,673' ±3,685' ±1,909' ±1,917' ±12' TBD Proposed BEL 48 ±3,689' ±3,695' ±1,920' ±1,924' ±6' TBD Proposed BEL 49 ±3,752' ±3,762' ±1,963' ±1,970' ±10' TBD Proposed BEL 49 ±3,764' ±3,770' ±1,971' ±1,975' ±6' TBD Proposed BEL 49 ±3,778' ±3,788' ±1,981' ±1,988' ±10' TBD Proposed BEL 49 ±3,789' ±3,797' ±1,989' ±1,994' ±8' TBD Proposed BEL 50 ±3,825' ±3,853' ±2,014' ±2,035' ±28' TBD Proposed BEL 51 ±3,876' ±3,895' ±2,052' ±2,066' ±19' TBD Proposed BEL 52 ±3,918' ±3,924' ±2,084' ±2,088' ±6' TBD Proposed BEL 52 ±3,930' ±3,940' ±2,093' ±2,101' ±10' TBD Proposed BEL 54 ±3,981' ±4,083' ±2,133' ±2,215' ±102' TBD Proposed BEL 55 ±4,094' ±4,110' ±2,224' ±2,237' ±16' TBD Proposed BEL 56 ±4,114' ±4,144' ±2,240' ±2,265' ±30' TBD Proposed BEL 56 ±4,154' ±4,174' ±2,273' ±2,290' ±20' TBD Proposed BEL 58 ±4,184' ±4,190' ±2,298' ±2,303' ±6' TBD Proposed BEL 58 ±4,213' ±4,219' ±2,323' ±2,328' ±6' TBD Proposed BEL 58A ±4,236' ±4,241' ±2,342' ±2,346' ±5' TBD Proposed BEL 58A ±4,243' ±4,248' ±2,348' ±2,352' ±5' TBD Proposed BEL 58A ±4,250' ±4,256' ±2,354' ±2,359' ±6' TBD Proposed BEL 59 ±4,317' ±4,323' ±2,410' ±2,415' ±6' TBD Proposed BEL 60 ±4,362' ±4,365' ±2,448' ±2,451' ±3' TBD Proposed BEL 65 ±4,410' ±4,422' ±2,490' ±2,500' ±12' TBD Proposed BEL 65 ±4,436' ±4,442' ±2,512' ±2,517' ±6' TBD Proposed BEL 72 ±4,484' ±4,490' ±2,554' ±2,559' ±6' TBD Proposed BEL 73 ±4,510' ±4,516' ±2,577' ±2,582' ±6' TBD Proposed BEL 73 ±4,520' ±4,525' ±2,585' ±2,590' ±5' TBD Proposed BEL 74 ±4,531' ±4,537' ±2,595' ±2,600' ±6' TBD Proposed BEL 74 ±4,558' ±4,564' ±2,618' ±2,623' ±6' TBD Proposed BEL 74 4,566' 4,573' 2,625' 2,631' 7' 3/4/2024 Open BEL 80 4,646' 4,655' 2,696' 2,703' 9' 3/4/2024 Open BEL 81 ±4,662' ±4,667' ±2,709' ±2,713' ±5' TBD Proposed BEL 81 ±4,670' ±4,676' ±2,716' ±2,721' ±6' TBD Proposed BEL 82 ±4,691' ±4,701' ±2,734' ±2,742' ±10' TBD Proposed BEL 83 ±4,720' ±4,727' ±2,759' ±2,765' ±7' TBD Proposed BEL 90 4,779' 4,784' 2,810' 2,814' 5' 3/4/2024 Open BEL 90 ±4,767' ±4,777' ±2,800' ±2,808' ±10' TBD Proposed BEL 90 ±4,797' ±4,803' ±2,826' ±2,831' ±6' TBD Proposed BEL 90 ±4,809' ±4,814' ±2,836' ±2,840' ±5' TBD Proposed BEL 90 ±4,815' ±4,821' ±2,841' ±2,847' ±6' TBD Proposed BEL 90 ±4,826' ±4,831' ±2,851' ±2,855' ±5' TBD Proposed BEL 91 4,861' 4,867' 2,881' 2,886' 6' 3/4/2024 Open BEL 91 4,871' 4,876' 2,890' 2,894' 5' 3/4/2024 Open BEL 92 4,921' 4,927' 2,833' 2,839' 6' 3/4/2024 Open BEL 92 ±4,938' ±4,943' ±2,948' ±2,952' ±5' TBD Proposed BEL 92 ±4,958' ±4,966' ±2,965' ±2,972' ±8' TBD Proposed BEL 92 ±4,973' ±4,983' ±2,978' ±2,987' ±10' TBD Proposed BEL 93 ±5,001' ±5,009' ±3,002' ±3,009' ±8' TBD Proposed BEL 93 5,013' 5,018' 3,013' 3,016' 5' 3/3/2024 Open BEL 94 5,045' 5,049' 3,040' 3,045' 4' 3/3/2024 Open BEL 95 5,092' 5,096' 3,082' 3,084' 4' 3/3/2024 Open BEL 95 5,106' 5,111' 3,094' 3,098' 5' 3/3/2024 Open BEL 96 5,136' 5,142' 3,120' 3,126' 6' 3/3/2024 Open BEL 97 5,168' 5,173' 3,148' 3,153' 5' 3/3/2024 Open BEL 97 5,177' 5,181' 3,156' 3,159' 4' 3/3/2024 Open BEL 98 5,191' 5,201' 3,168' 3,176' 10' 3/3/2024 Open BEL 99 5,226' 5,230' 3,198' 3,202' 4' 3/3/2024 Open BEL 99 5,236' 5,240' 3,207' 3,210' 4' 3/3/2024 Open BEL 99A 5,253' 5,258' 3,222' 3,226' 5' 3/3/2024 Open BEL 99B 5,268' 5,272' 3,235' 3,238' 4' 3/2/2024 Open BEL 99B 5,275' 5,279' 3,240' 3,245' 4' 3/2/2024 Open BEL 100 5,290' 5,307' 3,254' 3,268' 17' 3/2/2024 Open BEL 100 5,325' 5,329' 3,284' 3,288' 4' 3/2/2024 Open BEL 100 5,340' 5,353' 3,297' 3,308' 13' 3/2/2024 Open BEL 110 5,388' 5,402' 3,338' 3,351' 14' 3/2/2024 Open BEL 115 5,427’ 5,440’ 3,372’ 3,383’ 13’ 7/15/2022 Open BEL 120 5,463' 5,468' 3,405' 3,408' 5' 3/2/2024 Open BEL 120 5,491' 5,501' 3,427' 3,436' 10' 3/2/2024 Open BEL 120 5,537' 5,541' 3,467' 3,471' 4' 3/2/2024 Open BEL 120 5,543' 5,551' ±3,472' ±3,479' ±8' 3/2/2024 Open BEL 131 5,557’ 5,567’ 3,484’ 3,494’ 10’ 7/24/2020 Open BEL 132 5,575’ 5,594’ 3,499’ 3,516’ 19’ 7/23/2020 Open BEL 134 5,624’ 5,682’ 3,541’ 3,590’ 58’ 10/17/2019 Open 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: External sender. DO NOT open links or attachments from UNKNOWN senders. From:McLellan, Bryan J (OGC) To:Scott Warner Subject:RE: [EXTERNAL] RE: Kalotsa 2 AOGCC 10-403 325-278 PTD 216-155 Approved 05-13-25 Date:Thursday, May 29, 2025 9:21:02 AM Attachments:image002.png image003.png Scott, I agree with your formation fracture gradient analysis. I think that 15.7 ppg is a conservative estimate of frac pressure at the shoe and the deeper zones appear to be depleted to some extent. Hilcorp has approval to perforate the additional intervals listed in your May 27 email below. Thanks for providing the supporting data. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Scott Warner <scott.warner@hilcorp.com> Sent: Wednesday, May 28, 2025 3:28 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] RE: Kalotsa 2 AOGCC 10-403 325-278 PTD 216-155 Approved 05-13-25 Bryan, We tagged 4,516’ KB with slickline on Friday, the 23rd. A GPT run on E-line on Sunday, the 25th, still indicated cooling below 4,400’. To avoid tagging the gamma/pressure/temp tool at the bottom after slickline had already tagged at 4,516’, we decided to only log down to 4,400’. As I mentioned in my response to your email sent on May 7, I’m hesitant to place cement on the fill, as the pressure/temperature log suggests there is still contribution from the sand below. The shallowest allowable perforation calculations have been based on the FIT’s conducted on each individual sundried well. As the Kalotsa structure has been developed, deeper and higher-angle wells have been drilled, necessitating higher FIT’s to ensure well integrity, design appropriate casing depths, verify kick tolerance, confirm the formation can withstand higher mud weights, etc. The initial Kalotsa wells did not require such stringent tests, hence a lower FIT was performed. Over time, the structure has demonstrated its ability to withstand stronger FITs and one LOT. Well FIT LOT TVD Kalotsa 1 14.3 N/A 1360 Kalotsa 2 14.2 N/A 1379 Kalotsa 3 14.3 N/A 1316 Kalotsa 4 13.5 N/A 1410 Kalotsa 5 13.5 N/A 1071 Kalotsa 6 12.5 N/A 1258 Kalotsa 7 19.9 21.78 1415 Kalotsa 8 16.6 N/A 1666 Kalotsa 9 18.7 N/A 1369 Kalotsa 10 20.3 N/A 1408 Given this data, the FIT test used for Kalotsa 2 is very conservative. The average FIT test across the structure is 15.7 ppg EMW, indicating that the shallowest allowable perforation would be at 2472’ TVD. Considering the increasing FIT pressures due to more complex wells and the LOT showing a fracture pressure of 21.78 ppg EMW, using 15.7 ppg EMW remains conservative and would permit all perforations to be added. Thanks, Scott Warner CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Kenai – Operations Engineer Office: (907) 564-4506 Cell: (907) 830-8863 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, May 27, 2025 3:45 PM To: Scott Warner <scott.warner@hilcorp.com> Subject: [EXTERNAL] RE: Kalotsa 2 AOGCC 10-403 325-278 PTD 216-155 Approved 05-13-25 You can dump bail 25’ of cement on top of the plug at 4880’ and that will shift up the depth from which to base the new shallowest perf calcs enough to add all the additional perfs in the table below. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Scott Warner <scott.warner@hilcorp.com> Sent: Tuesday, May 27, 2025 1:41 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: Kalotsa 2 AOGCC 10-403 325-278 PTD 216-155 Approved 05-13-25 Bryan, Over the weekend, we perforated up to the approved interval at 2,800’ TVD. We would like to continue perforating, as there was no gain or loss in rate during the operation. The maximum SITP observed while perforating was 240 psi. This is similar to the lower BHP pressure seen on Kalotsa 10, which was recently approved, and suggests that intervals below the proposed perforation depths are no longer at original reservoir pressure. Using a gas gradient of 0.1 psi/ft, the SITP of 240 psi corresponds to an estimated BHP of approximately 764 psi at the T-17 depth—the deepest currently open TVD interval. This is significantly lower than the 0.44 psi/ft gradient currently being used to calculate the shallowest allowable perforation, which is limiting our ability to perforate additional depths. We would like to proceed with the following perforations, which were included in the original sundry: Thanks, Scott Warner Kenai – Operations Engineer Office: (907) 564-4506 Cell: (907) 830-8863 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, May 12, 2025 5:00 PM To: Scott Warner <scott.warner@hilcorp.com> Subject: RE: [EXTERNAL] Kalotsa 2 (PTD 216-155) perf sundry Scott, For now I’ll limit the shallowest perf depth on the existing sundry application. You can apply for shallower perfs after installing a cement plug. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Scott Warner <scott.warner@hilcorp.com> Sent: Friday, May 9, 2025 1:53 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] Kalotsa 2 (PTD 216-155) perf sundry Bryan, On 2/13/25 when we were perforating the well was shut in and built up/stabilized at 215 psi which is our actual maximum expected surface pressure from open perfs below. With that said we can use the newest proposed perfs as the maximum expected pressure which is the BEL 120 at 3449’ TVD. Maximum Expected BHP: 1517 psi @ 3449’ TVD Based on 0.44 psi/ft (Lowest proposed perforations- BEL 120) Max. Potential Surface Pressure: 1482 psi Based on 0.01 psi/ft gas gradient to surface Applicable Frac Gradient: 0.74 psi/ft using 14.2 ppg EMW FIT at the 7-5/8” surface casing shoe Shallowest Allowable Perf TVD: MPSP/(0.74-0.1) = 1482 psi / 0.64 = 2315‘ TVD I am hesitant to dump cement on top of the fill as I believe we still have some gas contributing from below the fill at ~4553’. We ran a GPT on 2/13 and saw cooling below 4350’ MD that didn’t warm back up until stopped logging right before the tag depth. Thanks, Scott Warner Kenai – Operations Engineer Office: (907) 564-4506 Cell: (907) 830-8863 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Sent: Wednesday, May 7, 2025 11:02 AM To: Scott Warner <scott.warner@hilcorp.com> Subject: [EXTERNAL] Kalotsa 2 (PTD 216-155) perf sundry Scott, When I do the calcs for shallowest allowable perf based on the T-17 being open (uncemented), then I calculate 2800’ TVD, which wouldn’t allow all of your proposed perfs. Where would you suggest setting a cement plug in this well? You could potentially set cement on top of the fill in the well, then you’d be able to perf everything you’re asking for. But we would prefer to see a plug between Tyonek and Beluga, so you could also set one there if there’s no more contribution from the Tyonek. I don’t want you to shut in any production by setting a plug. Let me know where you’d prefer to set cement, or alternatively we could just hold off on the shallwer perfs above 2800’ TVD for now. Thanks Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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:Scott Warner To:Davies, Stephen F (OGC) Cc:Dewhurst, Andrew D (OGC); McLellan, Bryan J (OGC) Subject:RE: [EXTERNAL] RE: NINILCHIK UNIT KALOTSA 6 (PTD 219-114, Sundry 325-420) - Information Request Date:Tuesday, July 22, 2025 11:43:15 AM Attachments:image001.png RE EXTERNAL RE Kalotsa 2 AOGCC 10-403 325-278 PTD 216-155 Approved 05-13-25.msg Steve, Apologies for just getting to this- I was OOO yesterday. Attached is the correspondence I’ve had with Bryan on this topic and below is a snippet of the FIT/LOT data from that email string. Well FIT LOT TVD Kalotsa 1 14.3 N/A 1360 Kalotsa 2 14.2 N/A 1379 Kalotsa 3 14.3 N/A 1316 Kalotsa 4 13.5 N/A 1410 Kalotsa 5 13.5 N/A 1071 Kalotsa 6 12.5 N/A 1258 Kalotsa 7 19.9 21.78 1415 Kalotsa 8 16.6 N/A 1666 Kalotsa 9 18.7 N/A 1369 Kalotsa 10 20.3 N/A 1408 Let me know if you have any questions. Thanks, Scott Warner Kenai – Operations Engineer Office: (907) 564-4506 Cell: (907) 830-8863 From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Tuesday, July 22, 2025 10:51 AM To: Scott Warner <scott.warner@hilcorp.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: [EXTERNAL] RE: NINILCHIK UNIT KALOTSA 6 (PTD 219-114, Sundry 325-420) - Information Request CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Hello Scott, I’m checking to ensure you received my email, below. I’ll be leaving for vacation on Thursday, and I’d like to keep this application moving through AOGCC’s review process. Thanks and Be Well, Steve Davies Senior Petroleum Geologist 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 From: Davies, Stephen F (OGC) Sent: Monday, July 21, 2025 1:35 PM To: Scott Warner <scott.warner@hilcorp.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: NINILCHIK UNIT KALOTSA 6 (PTD 219-114, Sundry 325-420) - Information Request Scott, I'm reviewing Hilcorp Alaska, LLC's Sundry Application for Kalotsa 6 and I have a request. The application states: Could Hilcorp please provide a copy of the LOT/FIT data that were to derive this Average FIT value? Thanks and Be Well, Steve Davies Senior Petroleum Geologist 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 responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. 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 5,745 feet N/A feet true vertical 3,643 feet N/A feet Effective Depth measured 5,710 feet 1,466 feet true vertical 3,614 feet 1,209 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)Cap String 3/8" 1,923' MD 1,310' TVD Packers and SSSV (type, measured and true vertical depth)Swell Pkr; N/A 1,466' MD 1,209' TVD N/A, N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date:Contact Name: Contact Email: Authorized Title:Contact Phone: Scott Warner, Operations Engineer 324-060 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: WINJ WAG 848 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 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 0 Size 120' 0 01768 0 620 66 4-1/2" Intermediate 16" 7-5/8" 120' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-114 50-133-20685-00-00 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: C061505 / ADL384372 Ninilchik / Beluga-Tyonek Gas Pool Ninilchik Unit Kalotsa 6 true vertical Production Liner 5,735' Casing Structural 3,635'5,735' 120'Conductor Surface 1,654' TVDMD measured Packer Plugs Junk measured Length scott.warner@hilcorp.com 907-564-4506 7,500psi 6,890psi 8,430psi 1,654'1,257' Burst Collapse 4,790psi measured 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 Samantha Coldiron at 9:17 am, Apr 15, 2024 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.04.12 17:51:59 - 08'00' Noel Nocas (4361) DSR-4/23/24 RBDMS JSB 041824 Page 1/2 Well Name: NINU Kalotsa 6 Report Printed: 3/27/2024www.peloton.com Well Operations Summary Jobs Actual Start Date:2/28/2024 End Date:2/29/2024 Report Number 1 Report Start Date 2/18/2024 Report End Date 2/19/2024 Operation Arrive on location. PM check cap string truck. MIRU HAK capillary string truck. Perform spool swaps. Load 3/8" cap string from Kalotsa 6 into craddle. Stab tubing into injector head chains. Stab on well. Remove Cap string hanger. Back off lock down screws. Pull 1600 lbs. 150 lbs over set weight. Spool string OOH to surface for 5348'. Close swab. Bleed down and pop off. All cap tubing and foot valve recovered. Install productions night cap. RIg down Cap string truck and move to Paxton pad. Report Number 2 Report Start Date 2/28/2024 Report End Date 2/29/2024 Operation PTW, PJSM, MIRU YJ E-line and Altus tractor equipment. M/U 2.50" tractor, GR/CCL and 2-3/8" x three perf guns. Op check tractor and gamma ray, arm guns and pull into lubricator (70'). PU but wind gusts prevented ability to stab on well. LD lubricator and stand down monitoring wind. Report Number 3 Report Start Date 3/2/2024 Report End Date 3/3/2024 Operation YJ E-line and Altus Tractor Intervention arrives obtains PTW, holds PJSM. M/U 2.50" tractor, GR/CCL,Op check tools and M/U Gun Run #1 (2-3/8"OD - 5 spf) with 3 switch guns. Tally CCL to T.S. (8.5', 16' and 29'). PU tools, lubricator and PT 250 psi / 2000 psi. Pass. FTP 104psi / 800 mcf. Open swab, RIH to 1600' (76 deg. dev.),go on line with tractor to 3200'. SI well flow, able to free fall, RIH and tag PBTD at 5655'(sticky). PU and run correlation pass and confirm on depth. Log into position and shoot the BEL_120 sands (5537'-5541' and 5543'-5551'). Start: 224 psi 10 min: 225 psi. PU and shoot BEL_120 sand (5491'-5501') Start: 224 psi 10 min: 236 psi. PU and shoot BEL_120 sand (5463'-5468') Start: 236 psi 10 min: 245 psi. POOH. OOH. All shots fired, guns dry. Op check tractor and GR/CCL, M/U Gun Run #2 (2 x switch guns). Tally CCL -T.S. (9' & 24.5'). Open swab (260 psi SITP), RIH to 1700', tractor on line to 3200', tractor offline. RIH, correlate, confirm on depth, position and shoot BEL_110 sand (5388'-5402') Start: 265 psi 10 min: 275 psi PU, position and shoot BEL_100 sand (5340'-5353') Start: 275 psi 10 min: 287 psi. POOH. OOH. All shots fired, guns dry. Op check tractor and GR/CCL, M/U Gun Run #3 (3 x switch guns). Tally CCL -T.S. (9',17' & 38.5'). Open swab (302 psi SITP), RIH to 1600', tractor on line to 3200', tractor offline. RIH, correlate, confirm on depth, position and shoot the BEL100 sand (5325'-5329'). Start: 306 psi 10 min: 321 psi. PU, position and shoot the BEL_100 sand (5290' - 5307'). Start: 321 psi 10 min: 421 psi PU, position and shoot the BEL_99B sand (5275'-5279'). Start: 421 psi 10min: 463 psi. POOH. OOH. All shots fired, guns dry. Drop 2 soap sticks, secure well, SDFN and turn well over to production to flow well overnight. Report Number 4 Report Start Date 3/3/2024 Report End Date 3/4/2024 Operation YJ E-line and Altus Tractor Intervention arrives obtains PTW, holds PJSM. M/U 2.50" tractor, GR/CCL,Op check tools and M/U Gun Run #4 (2-3/8" - 5spf) with 4 switch guns. Tally CCL to T.S. (9', 17',24.5' & 32'). PU tools, lubricator and move to well head. FTP 71psi / 1.92mmcfd. SI well at 0800 hrs to build pressure. Open swab, RIH to 1600' (76 deg. dev.),go on line with tractor to 3200' (tractor offline) free fall and RIH, run correlation pass and confirm on depth. Log into position and shoot the BEL_99B sand (5268'-5272'). Start: 685 psi 10 min: 674 psi. PU and shoot BEL_99A sand (5253'-5258') Start: 674 psi 10 min: 668 psi. PU and shoot BEL_99 sand (5236'-5240') Start: 668 psi 10 min: 665 psi. PU and shoot the BEL_99 sand (5226'-5230') Start: 665 psi 10 min: 667 psi. POOH. OOH. All shots fired, guns dry. Op check tractor and GR/CCL, M/U Gun Run #5 (4 x switch guns). Tally CCL -T.S. (9',16.5',24',31.5'). Open swab (658 psi SITP), RIH to 1600', tractor on line to 3200', tractor offline. RIH, correlate, confirm on depth, position and shoot BEL_98 sand (5191'-5201') Start: 657 psi 10 min: 655 psi. PU, position and shoot BEL_97 sand (5177'-5181') Start: 655 psi 10 min: 659 psi. PU, position and shoot BEL_97 sand (5168'-5173') Start: 659 psi 10 min: 660 psi. PU, position and shoot the BEL_96 sand (5136'-5142'). Start: 660 psi 10 min: 662 psi. POOH. OOH. All shots fired, guns dry. Op check tractor and GR/CCL, M/U Gun Run #6 (4 x switch guns). Tally CCL -T.S. (9',16.5', 24 & 32'). Open swab (658 psi SITP), RIH to 1600', tractor on line to 3200', tractor offline. RIH, correlate, confirm on depth, position and shoot the BEL_95 sand (5106'-5111'). Start: 657 psi 10 min: 656 psi. PU, position and shoot the BEL_95 sand (5092' - 5096'). Start: 656 psi 10 min: 658 psi PU, position and shoot the BEL_94 sand (5045'-5049'). Start: 658 psi 10min: 659 psi. PU, position and shoot the BEL_93 sand (5013'-5018') Start: 659 psi 10 min: 664 psi. POOH. OOH. All shots fired, guns dry. Secure well, SDFN and turn well over to production to flow well overnight. Report Number 5 Report Start Date 3/4/2024 Report End Date 3/5/2024 Operation YJ E-line and Altus Tractor Intervention arrives obtains PTW, holds PJSM. M/U 2.50" tractor, GR/CCL,Op check tools and M/U Gun Run #7 (2-3/8" x 5 spf) 4 gun intervals: 6',5',6'&5', tally CCL - T.S. 9',16.5',24' & 32'). Well flowing at 1.3 mmcfd but irratically dropping rate. SI well and drop 4 soapsticks, open flow monitoring rate and pressure. RU metahnol pump and drop 20 gallons down tubing & flow line. Establish tubing and lines are ice-free. SI well, PU lubricator and tools and move to wellhead. Open swab, RIH, fall to 1600', activate tractor and walk tools to 3200', off with tractor and free fall. Run correlaion pass from 5000'-4300', confirm on depth, position gun and perforate BEL_92 (4921'-4927') Start: 626 psi 10 min: 621 psi. PU and shoot BEL_91 (4871'-4876') Start: 621 psi 10 min: 626 psi. PU and shoot BEL_91 (4861'-4867'). Start: 626 psi 10 min: 637 psi. PU and shoot BEL_90 (4779'-4784') Start: 637 psi 10 min: 646 psi. POOH. OOH. All shots fired, guns dry. Op check tractor and GR/CCL, M/U Gun Run #8 (9' & 7', Tally CCL-TS: 9' & 21'). Move to well head, RIH, correlate, confirm on depth, position and shoot BEL_80 (4646'-4655'). Start: 630 psi 10 min: 632 psi. PU, position and shoot BEL_74 (4566'-4573'). Start: 632 psi 10 min: 639 psi. POOH. All shots fired, guns dry. Drop 3 soap sticks, secure well and RDMO E-line and tractor services.Turn well over to production. Job complete. API: 50-133-20685-00-00 Field: Ninilchik Sundry #: 324-060 State: Alaska Rig/Service:Permit to Drill (PTD) #:219-114 Page 2/2 Well Name: NINU Kalotsa 6 Report Printed: 3/27/2024www.peloton.com Well Operations Summary Report Number 6 Report Start Date 3/16/2024 Report End Date 3/17/2024 Operation MIRU Hilcorp capillary string truck. Load wooden drum and 3/8" cap tubing into spooler. Stab thorught counter and Injector head. Make up packoff assembly. Install 3/4" OD foot valve. Set pressure 2300 psi. Stab on well. PT pack off assembly 250/3500 psi. Open well 23.5 turns. RIH WHP 44 psi. @ 1503' RIH weight stacked from 400 lbs to -300 lbs. Weight not coming back. Over pull from 400 lbs to 1200 lbs and broke free. Attempt to work string down. Max depth 1704' stacking weight. Not able to pass depth. Pick up to 1650' and lock down pack off assembly and Injector head. Rig up SS soap skid line to spooler. Lift well form depth overnight to attempt to clean up debris/sand. Report Number 7 Report Start Date 3/18/2024 Report End Date 3/19/2024 Operation Cap string was temporarily locked down at 1650'. Attempted to lift well with foamer. Pick up 500 lbs over string weight. Work string for 4 hours while onine with foamer down cap string. Closed in well and pumped 2 x 55 gallon drums of diesel down tubing. Cap string achieved 1874' (+224'). Lock down cap string and secure location. Plan forward: Continue to pump foamer and unload well. Attempt to run 3/8" SS cap string to 5400'. Report Number 8 Report Start Date 3/19/2024 Report End Date 3/20/2024 Operation Continue Cap string deployment after lifting well overnight with foamer from 1868'. Clean pick up weight at depth was 500 lbs. First pick up 1300 lbs 800 lbs over. Picked up to 1500' and run back down. Worked cap string to 2050' then stacked 600 lbs. Not able to get deeper by working string. Parked and locked down pack off assemblies and reel brake @ 1923'. Plan forward: Continue pumping foamer at depth. Attempt another run for 4500' after flowing well at current depth. API: 50-133-20685-00-00 Field: Ninilchik Sundry #: 324-060 State: Alaska Rig/Service: Updated by SRW 04-9-24 SCHEMATIC Ninilchik Unit Kalotsa #6 PTD: 219-114 API: 50-133-20685-00-00 PBTD = 5,710’ MD / 3,614’ = TVD TD = 5,745’ MD / 3,643’ = TVD RKB to GL = 18’ RA Tags Joint Tops: 1728, 2224, 2720, 3216, 3713, 4209, 4701, 5198’(all MD) OPEN HOLE / CEMENT DETAIL 7-5/8"9-7/8” Hole: 77.5 bbls of 12ppg Class A lead cement and 32.5 bbls 15.8ppg Class A tail cement pumped with 100% returns and 30bbls cement back to surface. 4-1/2” 6-3/4” Hole: 126 bbls of 12ppg class A lead cement and 18 bbls of 15.3ppg class A tail cement pumped with 7bbl losses throughout job and 17bbl spacer back to surface. 10/10/19 CBL shows good cement up to 1150’ MD except for patchy cement from 3700’ - 4110’ MD. 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 1,654’ 4-1/2"Prod Csg 12.6 L-80 DWC/C HT 3.958”Surf 5,735’ 1 16” 7-5/8” 9-7/8” hole 4-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 1,466’3.958”6.875”Swell Packer 6-3/4” hole BEL 134 PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Amt Date Status BEL 74 4,566'4,573'2,625'2,631'7'3/4/2024 Open BEL 80 4,646'4,655'2,696'2,703'9'3/4/2024 Open BEL 90 4,779'4,784'2,810'2,814'5'3/4/2024 Open BEL 91 4,861'4,867'2,881'2,886'6'3/4/2024 Open BEL 91 4,871'4,876'2,890'2,894'5'3/4/2024 Open BEL 92 4,921'4,927'2,833'2,839'6'3/4/2024 Open BEL 93 5,013'5,018'3,013'3,016'5'3/3/2024 Open BEL 94 5,045'5,049'3,040'3,045'4'3/3/2024 Open BEL 95 5,092'5,096'3,082'3,084'4'3/3/2024 Open BEL 95 5,106'5,111'3,094'3,098'5'3/3/2024 Open BEL 96 5,136'5,142'3,120'3,126'6'3/3/2024 Open BEL 97 5,168'5,173'3,148'3,153'5'3/3/2024 Open BEL 97 5,177'5,181'3,156'3,159'4'3/3/2024 Open BEL 98 5,191'5,201'3,168'3,176'10'3/3/2024 Open BEL 99 5,226'5,230'3,198'3,202'4'3/3/2024 Open BEL 99 5,236'5,240'3,207'3,210'4'3/3/2024 Open BEL 99A 5,253'5,258'3,222'3,226'5'3/3/2024 Open BEL 99B 5,268'5,272'3,235'3,238'4'3/2/2024 Open BEL 99B 5,275'5,279'3,240'3,245'4'3/2/2024 Open BEL 100 5,290'5,307'3,254'3,268'17'3/2/2024 Open BEL 100 5,325'5,329'3,284'3,288'4'3/2/2024 Open BEL 100 5,340'5,353'3,297'3,308'13'3/2/2024 Open BEL 110 5,388'5,402'3,338'3,351'14'3/2/2024 Open BEL 115 5,427’5,440’3,372’3,383’13’7/15/2022 Open BEL 120 5,463'5,468'3,405'3,408'5'3/2/2024 Open BEL 120 5,491'5,501'3,427'3,436'10'3/2/2024 Open BEL 120 5,537'5,541'3,467'3,471'4'3/2/2024 Open BEL 120 5,543'5,551'±3,472'±3,479'±8'3/2/2024 Open BEL 131 5,557’5,567’3,484’3,494’10’7/24/2020 Open BEL 132 5,575’5,594’3,499’3,516’19’7/23/2020 Open BEL 134 5,624’5,682’3,541’3,590’58’10/17/2019 Open BEL 131 BEL 132 BEL 115 BEL 74 – BEL 110 BEL 120 Capillary String (3/8”): Installed 03/19/2024 Top Bottom MD 0 1,923’ TVD 0 1,310’ Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 4/4/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240404 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 19RD 50133205790100 219188 2/23/2024 YELLOW JACKET GPT-PERF BRU 241-23 50283201910000 223061 11/25/2023 AK E-LINE Perf HV B-13 50231200320000 207151 3/11/2024 YELLOW JACKET GPT KALOTSA 6 50133206850000 219114 3/2/2024 YELLOW JACKET PERF KU 13-06A 50133207160000 223112 3/13/2024 YELLOW JACKET GPT-PERF KU 21-06RD 50133100900100 201097 3/19/2024 YELLOW JACKET GPT-PERF END MPI 2-62 50029216480000 186158 2/14/2024 YELLOW JACKET PERF MPU G-18 50029231940000 204020 3/21/2024 READ Caliper Survey MPU G-18 50029231940000 204020 3/9/2024 AK E-LINE HoistCutter MPU I-24 50029237780000 224001 3/11/2024 AK E-LINE CBL NCIU A-18 50883201890000 223033 12/20/2023 AK E-LINE Perf NCIU A-18 50883201890000 223033 12/18/2024 AK E-LINE GPT/Plug/Perf PAXTON 3 50133205880000 209168 3/6/2024 YELLOW JACKET GPT PAXTON 3 50133205880000 209168 3/8/2024 YELLOW JACKET PERF PAXTON 3 50133205880000 209168 3/12/2024 AK E-LINE PPROF PAXTON 7 50133206430000 214130 2/26/2024 YELLOW JACKET PERF PBU 09-52 50029236180000 218168 3/24/2024 HALLIBURTON PPROF SD-06 50133205820000 208160 2/20/2024 YELLOW JACKET PERF SRU 222-33 50133207150000 223100 12/19/2023 AK E-LINE Perf Please include current contact information if different from above T38683 T38684 T38685 T38686 T38689 T38687 T38690 T38691 T38691T38692 T38963 T38963 T38694 T38694 T38694 T38695 T38696 T38697 T38698 KALOTSA 6 50133206850000 219114 3/2/2024 YELLOW JACKET PERF Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.04.09 13:48:29 -08'00' 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Pull Cap String, N2 2.Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 5,745'N/A Casing Collapse Structural Conductor 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 219-114 50-133-20685-00-00 Hilcorp Alaska, LLC Proposed Pools: N/A TVD Burst N/A 8,430psi 1,257 Size 120 1,654 MD See Attached Schematic 6,890psi 120120 1,654 February 14, 2024 N/A 5,735 Perforation Depth MD (ft): 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 NINILCHIK UNIT KALOTSA 6CO 701C Same 3,6354-1/2" 1,220psi 5,735 N/A Length Swell Pkr & N/A 1,466 (MD) 1,209 (TVD) & N/A 3,643'5,710'3,614' Ninilchik Beluga-Tyonek Gas 16" 7-5/8" See Attached Schematic m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Samantha Coldiron at 2:41 pm, Feb 07, 2024 324-060 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.02.06 19:07:08 - 09'00' Noel Nocas (4361) 10-404 DSR-2/13/24 Beluga-Tyonek Gas Perforate SFD 2/8/2024BJM 2/14/24*&:JLC 2/14/2024 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.02.14 16:20:31 -06'00' RBDMS JSB 021424 Well: Kalotsa-06 Well Name: Kalotsa 6 API Number: 50-133-20685-00-00 Current Status: Gas Producer Permit to Drill Number: 219-114 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: 1580 psi @ 3590’ TVD Based on 0.44 psi/ft Max. Potential Surface Pressure: 1220 psi Based on 0.1 psi/ft gas gradient to surface Well Status: Online gas producer @ 855 mcfd, 10 bwpd @ 61 psi FTP Brief Well Summary Kalotsa 6 was drilled and completed in October 2019, targeting the Beluga 134 sands. The well IP’d at 3.0 MMCFD and declined off to less than 1.0 MMCFD by March 2020. In July 2020 the Beluga 132 and 131 sands were added, increasing production by 1.8 MMCFD. By December 2020, the rate was less than 1.0 MMCFD Operations reduced flowing tubing pressure to about 25 psi, resulting in an increase of 1.0 MMCFD and unloading of 80 bwpd. In July, 2022 e-coil was used to perforate the Beluga 115 sand, with mechanical issues preventing additional Beluga perforations at this time. In April 2023, a capillary string was installed allowing soap/foamer to be injected and help unload water. The purpose of this work/sundry is to add perforations to the Beluga 74 through Beluga 120 sands to increase production. Wellbore Condition & History ** Max Deviation of 81°@ 2311’MD 07/24/20 Used e-coil to perforate Beluga 131 sand at 5,557’ MD 07/15/22 E-coil add perfs: Beluga 115 (5,427-5,440’ MD) 4/3/23 Capillary string installed @ 5,375’ MD Pre-Sundry Steps 1. Pull cap string Procedure: 1. MIRU Eline and Tractor equipment 2. Pressure Test equipment to 2000 psi High\ 250 psi Low 3. Perforate and test the below sands from bottom up: Sand Top MD Btm MD Top TVD Btm TVD Interval BEL_74 ±4,566' ±4,573' ±2,625' ±2,631' ±7' BEL_80 ±4,646' ±4,655' ±2,696' ±2,703' ±9' BEL_90 ±4,779' ±4,784' ±2,810' ±2,814' ±5' BEL_91 ±4,861' ±4,867' ±2,881' ±2,886' ±6' BEL_91 ±4,871' ±4,876' ±2,890' ±2,894' ±5' BEL_92 ±4,921' ±4,927' ±2,833' ±2,839' ±6' BEL_93 ±5,013' ±5,018' ±3,013' ±3,016' ±5' BEL_94 ±5,045' ±5,049' ±3,040' ±3,045' ±4' BEL_95 ±5,092' ±5,096' ±3,082' ±3,084' ±4' BEL_95 ±5,106' ±5,111' ±3,094' ±3,098' ±5' Well: Kalotsa-06 BEL_96 ±5,135' ±5,142' ±3,119' ±3,126' ±7' BEL_97 ±5,168' ±5,173' ±3,148' ±3,153' ±5' BEL_97 ±5,177' ±5,181' ±3,156' ±3,159' ±4' BEL_98 ±5,191' ±5,201' ±3,168' ±3,176' ±10' BEL_99 ±5,226' ±5,230' ±3,198' ±3,202' ±4' BEL_99 ±5,236' ±5,240' ±3,207' ±3,210' ±4' BEL_99A ±5,253' ±5,258' ±3,222' ±3,226' ±5' BEL_99B ±5,268' ±5,272' ±3,235' ±3,238' ±4' BEL_99B ±5,275' ±5,279' ±3,240' ±3,245' ±4' BEL_100 ±5,290' ±5,307' ±3,254' ±3,268' ±17' BEL_100 ±5,325' ±5,329' ±3,284' ±3,288' ±4' BEL_100 ±5,340' ±5,353' ±3,297' ±3,308' ±13' BEL_110 ±5,388' ±5,403' ±3,338' ±3,352' ±15' BEL_120 ±5,463' ±5,468' ±3,405' ±3,408' ±5' BEL_120 ±5,491' ±5,501' ±3,427' ±3,436' ±10' BEL_120 ±5,537' ±5,541' ±3,467' ±3,471' ±4' BEL_120 ±5,543' ±5,551' ±3,472' ±3,479' ±8' 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 h) Frac Calcs: using 12.5 ppg EMW FIT at the surface casing shoe (0.65 psi/ft) frac gradient i) Shallowest Allowable Perf TVD = MPSP/ (0.65-0.1) = 1173 psi / 0.55 = 2,132’ TVD 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 Only perfs from 4566'-5551' MD permitted under this sundry without further approval. -bjm Frac Calcs: using 12.5 ppg EMW FIT at the surface casing shoe (0.65 psi/ft) frac gradient Shallowest Allowable Perf TVD = MPSP/ (0.65-0.1) = 1173 psi / 0.55 = 2,132’ TVD Updated SRW 01-30-24 SCHEMATIC Ninilchik Unit Kalotsa #6 PTD: 219-114 API: 50-133-20685-00-00 PBTD = 5,710’ MD / 3,614’ = TVD TD = 5,745’ MD / 3,643’ = TVD RKB to GL = 18’ RA Tags Joint Tops: 1728, 2224, 2720, 3216, 3713, 4209, 4701, 5198’(all MD) OPEN HOLE / CEMENT DETAIL 7-5/8"9-7/8” Hole: 77.5 bbls of 12ppg Class A lead cement and 32.5 bbls 15.8ppg Class A tail cement pumped with 100% returns and 30bbls cement back to surface. 4-1/2” 6-3/4” Hole: 126 bbls of 12ppg class A lead cement and 18 bbls of 15.3ppg class A tail cement pumped with 7bbl losses throughout job and 17bbl spacer back to surface. 10/10/19 CBL shows good cement up to 1150’ MD except for patchy cement from 3700’ - 4110’ MD. 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 1,654’ 4-1/2"Prod Csg 12.6 L-80 DWC/C HT 3.958”Surf 5,735’ 1 16” 7-5/8” 9-7/8” hole 4-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 1,466’3.958”6.875”Swell Packer 6-3/4” hole B-134 PERFORATION DETAIL Zone Sand Top (MD) Btm (MD) Top (TVD) Btm (TVD)Amt Date Status Beluga BEL_115 5,427’5,440’3,372’3,383’13’07/15/22 Open Beluga BEL_131 5,557’5,567’3,484’3,494’10’07/24/20 Open Beluga BEL_132 5,575’5,594’3,499’3,516’19’07/23/20 Open Beluga 134 5,624’5,682’3,541’3,590’58’10/17/19 Open BEL_131 BEL_132 BEL_115 Capillary String (3/8”): Installed 4/6/2023 Top Bottom MD 0 5,375’ TVD 0 3,328’ Updated by SRW 01-30-24 Proposed SCHEMATIC Ninilchik Unit Kalotsa #6 PTD: 219-114 API: 50-133-20685-00-00 PBTD = 5,710’ MD / 3,614’ = TVD TD = 5,745’ MD / 3,643’ = TVD RKB to GL = 18’ RA Tags Joint Tops: 1728, 2224, 2720, 3216, 3713, 4209, 4701, 5198’(all MD) OPEN HOLE / CEMENT DETAIL 7-5/8"9-7/8” Hole: 77.5 bbls of 12ppg Class A lead cement and 32.5 bbls 15.8ppg Class A tail cement pumped with 100% returns and 30bbls cement back to surface. 4-1/2” 6-3/4” Hole: 126 bbls of 12ppg class A lead cement and 18 bbls of 15.3ppg class A tail cement pumped with 7bbl losses throughout job and 17bbl spacer back to surface. 10/10/19 CBL shows good cement up to 1150’ MD except for patchy cement from 3700’ - 4110’ MD. 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 1,654’ 4-1/2"Prod Csg 12.6 L-80 DWC/C HT 3.958”Surf 5,735’ 1 16” 7-5/8” 9-7/8” hole 4-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 1,466’3.958”6.875”Swell Packer 6-3/4” hole B-134 PERFORATION DETAIL Zone Sand Top (MD) Btm (MD) Top (TVD) Btm (TVD)Amt Date Status Beluga BEL_74 ±4,566'±4,573'±2,625'±2,631'±7'Proposed TBD Beluga BEL_80 ±4,646'±4,655'±2,696'±2,703'±9'Proposed TBD Beluga BEL_90 ±4,779'±4,784'±2,810'±2,814'±5'Proposed TBD Beluga BEL_91 ±4,861'±4,867'±2,881'±2,886'±6'Proposed TBD Beluga BEL_91 ±4,871'±4,876'±2,890'±2,894'±5'Proposed TBD Beluga BEL_92 ±4,921'±4,927'±2,833'±2,839'±6'Proposed TBD Beluga BEL_93 ±5,013'±5,018'±3,013'±3,016'±5'Proposed TBD Beluga BEL_94 ±5,045'±5,049'±3,040'±3,045'±4'Proposed TBD Beluga BEL_95 ±5,092'±5,096'±3,082'±3,084'±4'Proposed TBD Beluga BEL_95 ±5,106'±5,111'±3,094'±3,098'±5'Proposed TBD Beluga BEL_96 ±5,135'±5,142'±3,119'±3,126'±7'Proposed TBD Beluga BEL_97 ±5,168'±5,173'±3,148'±3,153'±5'Proposed TBD Beluga BEL_97 ±5,177'±5,181'±3,156'±3,159'±4'Proposed TBD Beluga BEL_98 ±5,191'±5,201'±3,168'±3,176'±10'Proposed TBD Beluga BEL_99 ±5,226'±5,230'±3,198'±3,202'±4'Proposed TBD Beluga BEL_99 ±5,236'±5,240'±3,207'±3,210'±4'Proposed TBD Beluga BEL_99A ±5,253'±5,258'±3,222'±3,226'±5'Proposed TBD Beluga BEL_99B ±5,268'±5,272'±3,235'±3,238'±4'Proposed TBD Beluga BEL_99B ±5,275'±5,279'±3,240'±3,245'±4'Proposed TBD Beluga BEL_100 ±5,290'±5,307'±3,254'±3,268'±17'Proposed TBD Beluga BEL_100 ±5,325'±5,329'±3,284'±3,288'±4'Proposed TBD Beluga BEL_100 ±5,340'±5,353'±3,297'±3,308'±13'Proposed TBD Beluga BEL_110 ±5,388'±5,403'±3,338'±3,352'±15'Proposed TBD Beluga BEL_115 5,427’5,440’3,372’3,383’13’07/15/22 Open Beluga BEL_120 ±5,463'±5,468'±3,405'±3,408'±5'Proposed TBD Beluga BEL_120 ±5,491'±5,501'±3,427'±3,436'±10'Proposed TBD Beluga BEL_120 ±5,537'±5,541'±3,467'±3,471'±4'Proposed TBD Beluga BEL_120 ±5,543'±5,551'±3,472'±3,479'±8'Proposed TBD Beluga BEL_131 5,557’5,567’3,484’3,494’10’07/24/20 Open Beluga BEL_132 5,575’5,594’3,499’3,516’19’07/23/20 Open Beluga 134 5,624’5,682’3,541’3,590’58’10/17/19 Open BEL_131 BEL_132 BEL_115 BEL_74 – BEL_110 BEL_120 STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: 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 5,745 feet N/A feet true vertical 3,643 feet N/A feet Effective Depth measured 5,710 feet 1,466 feet true vertical 3,614 feet 1,209 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth) N/A N/A N/A N/A Packers and SSSV (type, measured and true vertical depth) Swell Pkr; N/A 1,466' MD 1,209' TVD N/A, N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Contact Phone: Jake Flora, Operations Engineer 323-179 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 1252 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 Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 0 Size 120' 1 31093 0 6218 64 4-1/2" Intermediate 16" 7-5/8" 120' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-114 50-133-20685-00-00 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: C061505 / ADL384372 Ninilchik - Beluga/Tyonek Gas Pool Ninilchik Unit Kalotsa 6 measured true vertical Production Liner 5,735' Casing Structural 3,635'5,735' 120'Conductor Surface 1,654' TVD 7,500psi 6,890psi 8,430psi 1,654' 1,257' Burst Collapse 4,790psi measured Packer Plugs Junk measured Length 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 1:48 pm, Apr 28, 2023 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361), ou=Users Date: 2023.04.28 13:07:24 -08'00' Noel Nocas (4361) Rig Start Date End Date 4/5/23 4/6/23 04/06/2023 - Thursday Continue working cap string from 2400' but could not get to fall. Shut in well and began pumping diesel with triplex while working cap string. Pooh to 2300' and then began to fall again. RIH to 5400' and got a PU weight of 1450 lbs. Set cap string at 5375' MD. RDMO. 04/05/2023 - Wednesday Conduct TGSM and JSA. MIRU and PT pack-off assembly to 250 psi low/1500psi high. RIH with foot valve (2000 psi opening psi) and 3/8" cap string. Set down at 2288'MD. Worked Cap string and fell to 2300' at very slow pace. Pumped 1.5 Bbls of diesel and cap string began to fall much better. Stopped RIH to rebuild injection swivel for pumping methanol down cap string with triplex on the cap string unit and then cap string would not fall on it's own afterward. Stopped and secured for the night and will resume working in hole in the morning. Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Kalotsa 6 50-13-20685-00-00 219-114 Updated by DMA 04-25-23 SCHEMATIC Ninilchik Unit Kalotsa #6 PTD: 219-114 API: 50-133-20685-00-00 PBTD = 5,710 MD / 3,614 = TVD TD = 5,745 MD / 3,643 = TVD RKB to GL = 18 RA Tags Joint Tops: 1728, 2224, 2720, 3216, 3713, 4209, 4701, 5198(all MD) OPEN HOLE / CEMENT DETAIL 7-5/8"9-7/8 Hole: 77.5 bbls of 12ppg ClassA lead cement and 32.5 bbls 15.8ppg Class A tail cement pumped with 100% returns and 30bbls cement back to surface. 4-1/2 6-3/4 Hole: 126 bbls of 12ppg class A lead cement and 18 bbls of 15.3ppg class A tail cement pumped with 7bbl losses throughout job and 17bbl spacer back to surface. 10/10/19 CBL shows good cement up to 1150 MD except for patchy cement from 3700 - 4110 MD. CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01Surf 120' 7-5/8"Surf Csg 29.7 L-80 DWC/C 6.875Surf 1,654 4-1/2"Prod Csg 12.6 L-80 DWC/C HT 3.958Surf 5,735 1 16 7-5/8 9-7/8 hole 4-1/2 JEWELRY DETAIL No. Depth ID OD Item 1 1,4663.9586.875Swell Packer 6-3/4 hole B-134 PERFORATION DETAIL Zone Sand Top (MD) Btm (MD) Top (TVD) Btm (TVD)Amt Date Status Beluga BEL_115 5,4275,4403,3723,3831307/15/22 Open Beluga BEL_131 5,5575,5673,3433,3511007/24/20 Open Beluga BEL_132 5,5755,5943,3583,3741907/23/20 Open Beluga 134 5,6245,6823,3993,4485810/17/19 Open BEL_131 BEL_132 BEL_115 Capillary String (3/8): Installed 4/6/2023 Top Bottom MD 0 5,375 TVD 0 3,328 RBDMS JSB 040423 David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 09/28/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20220928 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 07A 501332028401 214060 7/12/2022 AK E-Line CIBP GPT BCU 18RD 501332058401 222033 7/13/2022 AK E-Line Perf BCU 18RD 501332058401 222033 7/16/2022 AK E-Line GPT Perf BCU 18RD 501332058401 222033 7/23/2022 AK E-Line GPT CIBP Perf BRU 212-24 502832003700 172015 6/27/2022 AK E-Line CBL BRU 212-24 502832003700 172015 7/5/2022 AK E-Line CIBP CBL TBG END 1-45 500292199100 189124 7/23/2022 AK E-Line Perf END 4-02 500292178900 188022 7/21/2022 AK E-Line Perf HVB B-16 502312004000 212133 6/23/2022 AK E-Line Drift, Plug, Cement IRU 241-01 502832018400 221076 8/5/2022 AK E-Line CBL IRU 241-01 502832018400 221076 8/9/2022 AK E-Line Perf Kalotsa 6 501332068500 219114 7/16/2022 AK E-Line Perf KTU 24-06H 501332049000 199073 7/15/2022 AK E-Line GPT Perf MPU S-34 500292317100 203130 7/5/2022 AK E-Line Drift PBU F-26C 500292198703 213045 8/4/2022 AK E-Line Patch/LDL SRU 213-15 501332065200 215100 8/3/2022 AK E-Line GPT Perf Please include current contact information if different from above. T37068 T37069 T37069 T37069 T37070 T37070 T37071 T37072 T37073 T37081 T37081 T37074 T37075 T37076 T37077 T37078 Kalotsa 6 501332068500 219114 7/16/2022 AK E-Line Perf Kayla Junke Digitally signed by Kayla Junke Date: 2022.09.30 12:44:16 -08'00' 5HJJ-DPHV%2*& )URP%URRNV3KRHEH/2*& 6HQW7KXUVGD\$XJXVW30 7R5\DQ7KRPSVRQ &F5HJJ-DPHV%2*& 6XEMHFW5(%23(7HVW5HSRUW.DORWVD $WWDFKPHQWV)R[[OV[[OV[ ZǇĂŶ͕ ƚƚĂĐŚĞĚŝƐĂƌĞǀŝƐĞĚƌĞƉŽƌƚĐŚĂŶŐŝŶŐƚŚĞWdηĨŽƌŵĂƚƚŽƌĞĨůĞĐƚϮϭϵϭϭϰϬ͘WůĞĂƐĞƵƉĚĂƚĞǇŽƵƌĐŽƉǇ͘ /͛ǀĞĂůƐŽĂƚƚĂĐŚĞĚƚŚĞůĂƚĞƐƚKWƌĞƉŽƌƚƚĞŵƉůĂƚĞĨŽƌĨƵƚƵƌĞƵƐĞ͘ dŚĂŶŬǇŽƵ͕ WŚŽĞďĞ WŚŽĞďĞƌŽŽŬƐ ZĞƐĞĂƌĐŚŶĂůǇƐƚ ůĂƐŬĂKŝůĂŶĚ'ĂƐŽŶƐĞƌǀĂƚŝŽŶŽŵŵŝƐƐŝŽŶ WŚŽŶĞ͗ϵϬϳͲϳϵϯͲϭϮϰϮ 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 Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. &ƌŽŵ͗ZǇĂŶdŚŽŵƉƐŽŶфZǇĂŶ͘dŚŽŵƉƐŽŶΛŚŝůĐŽƌƉ͘ĐŽŵх ^ĞŶƚ͗&ƌŝĚĂǇ͕ƵŐƵƐƚϭϮ͕ϮϬϮϮϭ͗ϰϲWD dŽ͗ZĞŐŐ͕:ĂŵĞƐ;K'Ϳфũŝŵ͘ƌĞŐŐΛĂůĂƐŬĂ͘ŐŽǀх͖KK'WƌƵĚŚŽĞĂǇфĚŽĂ͘ĂŽŐĐĐ͘ƉƌƵĚŚŽĞ͘ďĂǇΛĂůĂƐŬĂ͘ŐŽǀх͖ ƌŽŽŬƐ͕WŚŽĞďĞ>;K'ͿфƉŚŽĞďĞ͘ďƌŽŽŬƐΛĂůĂƐŬĂ͘ŐŽǀх Đ͗ŽŶŶĂŵďƌƵǌфĚĂŵďƌƵǌΛŚŝůĐŽƌƉ͘ĐŽŵх ^ƵďũĞĐƚ͗KWdĞƐƚZĞƉŽƌƚ<ĂůŽƚƐĂϲ͕ϴͬϭϬͬϮϮ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ll BOPE reports are due to the agency within 5 days of testing* SSu b m i t t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:8 DATE: 8/10/22 Rig Rep.: Rig Phone: (907)887-1766 Operator: Op. Phone:(907)632-4113 Rep.: E-Mail Well Name: PTD #2191140 Sundry #322-264 Operation: Drilling: Workover: x Explor.: Test: Initial: x Weekly: Bi-Weekly: Other: Rams:250/3000 Annular:NA Valves:250/3000 MASP:1196 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 0NA Housekeeping P Rig P Lower Kelly 0NA PTD On Location P Hazard Sec.P Ball Type 0NA Standing Order Posted NA Misc.NA Inside BOP 0NA FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 1 1.75"P Trip Tank NA NA Annular Preventer 0 N/A NA Pit Level Indicators NA NA #1 Rams 1 1.75" BS P Flow Indicator NA NA #2 Rams 1 1.75" PS P Meth Gas Detector NA NA #3 Rams 0 N/A NA H2S Gas Detector NA NA #4 Rams 0 N/A NA MS Misc 0NA #5 Rams 0 N/A NA #6 Rams 0 N/A NA Quantity Test Result Choke Ln. Valves 2 2"P Inside Reel valves 1P HCR Valves 0 N/A NA Kill Line Valves 2 2"P Check Valve 0 N/A NA ACCUMULATOR SYSTEM: BOP Misc 0 N/A NA Time/Pressure Test Result System Pressure (psi)3000 P CHOKE MANIFOLD:Pressure After Closure (psi)2500 P Quantity Test Result 200 psi Attained (sec)4 P No. Valves 5P Full Pressure Attained (sec)14 P Manual Chokes 2P Blind Switch Covers: All stations Yes Hydraulic Chokes 0NA Nitgn. Bottles # & psi (Avg.):NA CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:0 Test Time:2.5 Hours Repair or replacement of equipment will be made within N/A days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 8/9/22 16:35 Waived By Test Start Date/Time:8/10/2022 13:30 (date) (time)Witness Test Finish Date/Time:8/10/2022 16:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Fox Accumulator precharge pressure 1400 psi, pressure testing fluid: water Terence Rais Hilcorp Alaska Ryan Thompson Ninilchik Unit Kalotsa 6 Test Pressure (psi): ryan.thompson@hilcorp.com Form 10-424 (Revised 02/2022) 2022-0810_BOP_Fox8_Ninilchik_Kalotsta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ll BOPE reports are due to the agency within 5 days of testing* SSu b m i t t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:8 DATE: 7/13/22 Rig Rep.: Rig Phone: 208-553-6699 Operator: Op. Phone:907-777-8300 Rep.: E-Mail Well Name: PTD #22191140 Sundry #322-264 Operation: Drilling: Workover: X Explor.: Test: Initial: X Weekly: Bi-Weekly: Other: Rams:250/3000 Annular:NA Valves:250/3000 MASP:1196 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 0NA Housekeeping P Rig NA Lower Kelly 0NA PTD On Location P Hazard Sec.NA Ball Type 0NA Standing Order Posted NA Misc.NA Inside BOP 0NA FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 1 1.75"P Trip Tank NA NA Annular Preventer 0 NA NA Pit Level Indicators NA NA #1 Rams 1 1.75 B/S P Flow Indicator NA NA #2 Rams 1 1.75 P/S P Meth Gas Detector NA NA #3 Rams 0 NA NA H2S Gas Detector NA NA #4 Rams 0 NA NA MS Misc 0NA #5 Rams 0 NA NA #6 Rams 0 NA NA Quantity Test Result Choke Ln. Valves 2 2"P Inside Reel valves 1P HCR Valves 0 NA NA Kill Line Valves 2 2"P Check Valve 0 NA NA ACCUMULATOR SYSTEM: BOP Misc 0 NA NA Time/Pressure Test Result System Pressure (psi)3000 P CHOKE MANIFOLD:Pressure After Closure (psi)2450 P Quantity Test Result 200 psi Attained (sec)5 P No. Valves 5P Full Pressure Attained (sec)13 P Manual Chokes 2P Blind Switch Covers: All stations Yes Hydraulic Chokes 0NA Nitgn. Bottles # & psi (Avg.): NA NA CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:0 Test Time:3.0 Hours Repair or replacement of equipment will be made within NA days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 7/12/22 16:28 Waived By Test Start Date/Time:7/13/2022 15:00 (date) (time)Witness Test Finish Date/Time:7/13/2022 18:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Fox Accumulator precharge pressure 1400 psi Landry Lynn Hilcorp Cole Bartlewski Ninilchik Unit Kalotsa 6 Test Pressure (psi): cbartlewski@hilcorp.com Form 10-424 (Revised 02/2022) 2022-0713_BOP_Fox8_Ninilchik_Kalotsa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y Samantha Carlisle at 9:34 am, May 03, 2022 'LJLWDOO\VLJQHGE\'DQ0DUORZH '1FQ 'DQ0DUORZH RX 8VHUV 'DWH 'DQ0DUORZH '65 ; 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Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: N2 Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 5,745 feet N/A feet true vertical 3,643 feet N/A feet Effective Depth measured 5,710 feet 1,466 feet true vertical 3,614 feet 1,209 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)N/A N/A MD TVD Packers and SSSV (type, measured and true vertical depth)Swell Pkr; N/A 1,466' MD 1,209' 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 120' 1,257' 8,430psi 6,890psi Collapse 4,790psi 7,500psi Casing Structural 16" 7-5/8" 4-1/2" Length 120' 1,654' 5,735' Conductor Surface Intermediate Production Authorized Signature with date: Authorized Name: 32 Casing Pressure Liner 2,650 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. 320-179 188 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 52 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-114 50-133-20685-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 2670 Ninilchik Unit Kalotsa 6 N/A C061505 / ADL384372 5,735' Plugs Junk measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Ninilchik - Beluga/Tyonek Gas PoolN/A measured TVD Tubing PressureOil-Bbl measured true vertical Packer 3,635' WINJ WAG 615 Water-Bbl MD 120' 1,654' 0 t Fra O 6. A G L PG , R 2 Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Jody Colombie at 11:34 am, Aug 14, 2020 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.08.14 10:43:28 -08'00' Taylor Wellman RBDMS HEW 8/14/2020 SFD 8/14/2020 N22 Perforate DSR-8/17/2020gls 10/20/20 Rig Start Date End Date E-Coil 5/6/20 7/24/20 07/22/2020 - Wednesday PTW, JSA. Load E coil spool into CTU unit. Rig up to well head. Install BOPE stack. Rig up choke skid, HAK hot oil truck. 24 Hr. BOPE test witness notification sent 7/21/2020 @ 15:19 PM. Witness waived by Jim Regg via emial notification. Start BOPE test. Test all rams and valves 250/3,500 psi. BOPE test complete. Rig Up AK E-line. Test connection to E-coil. Good to go. SDFN. 07/23/2020 - Thursday PTW, JSA. Fire equipment. Pick injector head. Stack up 30' of lubricator. Make up AK E-line to coil connector head. Confirm good communication. Pick gun and lower into cellar. Make up to Coil connector. Stab on well. PT stack 250/3,500 psi. Bleed off to tank. Equalize well. Open swab and RIH. 5,651' end of guns start Logging OOH at 50 feet per minute. Pulling pass for first gun run. Logged OOH to 5,100' Tied into Halliburton RCBL log 10 OCT 2019. Send log to town. Drop back down to 5,651'. Shift up 1' as per town. Log into depth. 4 attempts made. Coil operator couldn't catch depth. Always 1-2' off. CCl to top shot 9.4' . Parked coil at 5,565.6' CCL depth. Well is flowing 975 MCFD @ 210 psi. 2 7/8" guns loaded 6 SPF 60* phasing Razor charges. Shooting Beluga BEL_132 sands from 5,575'-5,594'. (19'). Confirmed fired at wellhead. POOH with coil. After 5 minutes 15 psi increase 245.7 psi 1.2 MMCFD flow rate. 15 minutes 40 psi increase 285.7 psi 1.49 MMCFD flow rate. When coil reached surface well seemed to be loosing rate but gaining pressure. Talked with pad op and found there has been an issue with flow line and the 80 psi of DP seen upstream of the surface check valve. Tagged up. Close swab valve. Bleed down stack and pop off well. Spent guns. Crews made up second gun. Stabbed on well. Started RIH. Decision was made to POOH to surface and rig back CTU unit and investigate flow line blockage. 450 psi on CTU gauge. 0 flow to HSU. Shut in well. Rig back coil. Perform lock out tag out with production operator. Confirmed 0 psi on flow line upstream and down stream of check valve. Broke two blind flanges. Attempted to use camera snake. Couldn't make out images. Found blockage right before flapper style check valve. Appears to be a in line witches hat filter. Break out check valve remove witches hat and re install normal ring gasket. Hammer up 2x blind flanges and check valve flanges. Pressure test flow line. Night operators will bring well online. 05/06/2020 - Wednesday PTW and JSA. Spot equipment and rig up lubricator. Well flowing 564 at 257 psi RIH w/ roller bogies and GPT tool. Tagged at 5699'. Ran correlation log and send to town. There was no fluid level. POOH. Town said correlation log was 2.5' deep. Well flowing 560K at 252 psi. Did not have to shut in well. RIH w/4 roller bogies , 2-7/8" x 20' (19' loaded) HC, 6 spf, 60 deg phase with well flowing and tool sat down at 1,750'. Tried different speeds and depths we started speeds at. Tried with the well flowing and with it shut in and nothing helped. Pumped 30 gals diesel and didn't help. POOH. Call town and discussed. RIH w/4 roller bogies , 2-7/8" x 10' HC, 6 spf, 60 deg phase with well flowing and tool sat down at 2,050'. Pumped 25 gals of diesel. Tried different speeds and depths we started speeds at. Tried with the well flowing and with it shut in and nothing help. We had took off 2 weight bars also before going in hole. POOH. RIH w/4 roller bogies, 2- 7/8"x10' HC, 6 spf, 60 deg phase, added 5' wt bar with well flowing and tool sat down at 1,950'. Tried different speeds and depths we started speeds at. Tried with the well flowing and with it shut in and nothing helped. POOH. Call town and was told to rig down and take equipment back to shop Rig down off tree and equipment. Turn well over to field. Return to base. Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Kalotsa 6 50-13-20685-00-00 219-114 Found blockage right before flapper style check valve. Rig Up AK E-line. Test Tied into Halliburton RCBL log 10 OCT 2019. S Test all rams and valves 250/3,500 psi. Shooting Beluga BEL_132 sands from 5,575'-5,594'. (19' Spot equipment and rig up lubricator. Well flowing 564 at 257 psi RIH w/ roller bogies and GPT tool. Tagged at 5699'. Ran correlation log and send to town. Eline attempt to perf Load E coil spool into CTU unit. Rig Start Date End Date E-Coil 5/6/20 7/24/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Kalotsa 6 50-13-20685-00-00 219-114 PTW, JSA. Fire equipment. Pick injector head and lubricator. Make 10' gun. Stab on well. PT stack 250/3,500 psi. RIH. Well flowing 1,637 MMCFD at 170 psi. Log correlation pass tied into halliburton CBL log from OCT 2019. Send Log to town. CCL to top shot 8.5' PU to 5,548.5' CCL depth. Shooting 2-7/8" x 10' gun loaded 6 spf with 60° phasing Razor charges in the Beluga BEL_131 zone from 5,557'-5,567'. Operations isn't changing choke setting. 11:23 hrs shoot guns. POOH with coil. 2,153 MMCFD after 15 minutes at 172 psi. OOH at surface. Close swab valve. Break down guns. All shots fired. Well flowing 2.7 @ 213 psi. Guns were wet. Rig down CTU and move to Paxton pad. 07/24/2020 - Friday Well flowing 1,637 MMCFD at 170 psi. charges in the Beluga BEL_131 zone from 5,557'-5,567' Updated by DMA 08-06-20 SCHEMATIC Ninilchik Unit Kalotsa #6 PTD: 219-114 API: 50-133-20685-00-00 PBTD = 5,710’ MD / 3,614’ = TVD TD = 5,745’ MD / 3,643’ = TVD’ RKB to GL = 18’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 DWC/C 6.875” Surf 1,654’ 4-1/2" Prod Csg 12.6 L-80 DWC/C HT 3.958” Surf 5,735’ 1 16” 7-5/8” 9-7/8” hole 4-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 1,466’ 3.958” 6.875” Swell Packer 6-3/4” hole B-134 PERFORATION DETAIL Zone Sand Top (MD) Btm (MD) Top (TVD) Btm (TVD) Amt SPF Date Status Beluga BEL_131 5,557’ 5,567’ 3,343’ 3,351’ 10’ 6 07/24/20 Open Beluga BEL_132 5,575’ 5,594’ 3,358’ 3,374’ 19’ 6 07/23/20 Open Beluga 134 5,624’ 5,682’ 3,399’ 3,448’ 58’ 6 10/17/19 Open BEL_131 BEL_132 Beluga BEL_131 5,557’5,567’3,343’3,351’10’6 07/24/20 Open Beluga BEL_132 5,575’5,594’3,358’3,374’19’6 07/23/20 Opengp//,,,,_ BEL_131 BEL_132 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? Will planned perforations require a spacing exception? Yes No 9. Property Designation (Lease Number): 10. Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 5,745'N/A Casing Collapse Structural Conductor Surface 4,790 psi Intermediate 7,500 psi Production 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: Christina Twogood Operations Manager Contact Email: Contact Phone: 777-8443 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng ctwogood@hilcorp.com 3,643' 5,710' 3,614' ~ 1,227 psi N/A Swell Pkr; N/A 1,466' MD / 1,209' TVD; N/A, 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 C061505 / ADL384372 219-114 50-133-20685-00-00 Kalotsa 6 Length Size CO 701A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY Ninilchik - Beluga/Tyonek Gas Pool N/A TVD Burst N/A MD 8,430 psi 6,890 psi1,257' 3,635' 120' 1,654' 16" 7-5/8" 120' 4-1/2"5,735' 1,654' Perforation Depth MD (ft): 5,735' See Attached Schematic 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: Friday, May 8, 2020 N/A m n P 66 t Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.04.24 16:18:21 -08'00' Taylor Wellman By Samantha Carlisle at 8:05 am, Apr 27, 2020 320-179 X 10-404 DSR-4/27/2020DLB 04/27/2020gls 4/27/20 q C 4/28/2020 dts 4/28/2020 JLC 4/28/2020 Well Prognosis Well: Kalotsa 6 Date: 4/24/2020 Well Name: Kalotsa 6 API Number: 50-133-20685-00-00 Current Status: Leg: N/A Estimated Start Date: 5/8/2020 Rig: N/A Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 219-114 First Call Engineer: Christina Twogood (907) 777-8443 (O) (907) 378-7323 (M) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (M) AFE Number: Max. Expected BHP: ~ 1,580 psi @ 3,519’ TVD (Based on normal gradient) Max. Possible Surface Pressure: ~ 1,227 psi (Based on expected BHP and gas gradient to surface (0.10psi/ft)) Brief Well Summary Kalotsa 6 was drilled and completed in September 2019 as a grassroots well down to the top of the BEL_134. In October 2019 the BEL_134 was perforated with tractor. The purpose of this work/sundry is to perforate multiple intervals in the Beluga sands. Notes Regarding Wellbore Condition x Last tag to TD (5,702’ MD) during E-Line/Tractor perf operation on 10/16/19 Safety Concerns x Pre-job safety meetings and tailgate safety meetings will be conducted at each appropriate phase of the procedure. x Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter x Consider tank placement based on wind direction and current weather forecast (venting nitrogen during this job) x Ensure all crews are aware of stop job authority E-Line Procedure 1. MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 2,000 psi High. 2. RIH with GPT tool and find fluid level. If fluid level is over the depth of the new perfs, discuss using Nitrogen with the Operations Engineer. 3. If needed, RU Nitrogen Truck, pressure up on well and push water back into formation. Use GPT tool to confirm water level is below interval to perf. 4. RU perf guns. Nitrogen used to displace fluid. Well Prognosis Well: Kalotsa 6 Date: 4/24/2020 5. RIH and perforate the following intervals: Zone Sand Top (MD) Btm (MD) Top (TVD) Btm (MD) FT Beluga BEL_106 +5,338' +5,354' +3,296' +3,309' 16' Beluga BEL_115 +5,424’ +5,442’ +3,370’ +3,385’ 18’ Beluga BEL_131 +5,556’ +5,571’ +3,483’ +3,496’ 15’ Beluga BEL_132 +5,574’ +5,598’ +3,498’ +3,519’ 24’ a. Shoot well while flowing. b. Proposed perfs also shown on the proposed schematic in red font. c. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. d. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer and Geologist for confirmation. e. Use Gamma/CCL to correlate. f. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. g. All perforations in table above are located in the Beluga-Upper Tyonek Gas Pool based on Conservation Order No. 510A. 6. POOH. 7. RD E-Line. 8. Turn well over to production. (Test SSV within 5 days of stable production on well – notify AOGCC 24 hours before testing). E-Line Procedure (Contingency) 1. If any zone produces sand and/or water or needs isolated: 2. MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 2,000 psi High. 3. RIH and set 3-1/2” Casing Patch or 3-1/2” CIBP above the zone and dump 35’ of cement on top of the plug. Coiled Tubing Procedure (Contingency): 1. MIRU Coiled Tubing Unit and BOP equipment. 2. RU Coiled Tubing Stripper and Lubricator. 3. PT BOPE, Stripper and Lubricator to 250 psi Low / 3,500 psi High. (Notify AOGCC 24 hrs in advance on BOP test.) 4. RU E-Line Data Acquisition Unit. (w/ Tractor ?) E-line perfs using E-Coil Well Prognosis Well: Kalotsa 6 Date: 4/24/2020 1. RU perf guns. 2. RIH and perforate the following intervals: Zone Sand Top (MD) Btm (MD) Top (TVD) Btm (MD) FT Beluga BEL_106 +5,338' +5,354' +3,296' +3,309' 16' Beluga BEL_115 +5,424’ +5,442’ +3,370’ +3,385’ 18’ Beluga BEL_131 +5,556’ +5,571’ +3,483’ +3,496’ 15’ Beluga BEL_132 +5,574’ +5,598’ +3,498’ +3,519’ 24’ h. Prior to shooting the BEL_132 and BEL_106 sands, build pressure up to approx. 1,200 psi. i. Prior to shooting the BEL_131 and BEL_115 sands, build up pressure to approx. 800 psi. j. Proposed perfs also shown on the proposed schematic in red font. k. Final perfs tie-in sheet will be provided in the field for exact per intervals. l. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. m. Use Gamma/CCL to correlate. n. Spacing allowance is based on CO 701A. Proposed intervals are in the Beluga/Tyonek Gas Pool. o. Record tubing pressure before and after each perforating run. p. Record 5, 10 and 15 minutes pressures after firing guns. 3. POOH. 4. RD E-Line Unit and Coiled Tubing Unit. 5. Turn well over to production. Coiled Tubing Procedure (Contingency): 1. MU standard coil reel and BHA. 2. RU N2 pumping unit. 3. Drop ball and come online with N2 and jet well dry. 4. RIH with coiled tubing and BHA and tag. 5. PU approx. 5 ft and displace well fluids with Nitrogen. 6. Once well is dry, verify desired surface pressure to leave on well with Operations Engineer (OE). 7. POOH w/ coil. LD BHA. 8. RD standard coil reel. 9. RU E-Coil reel. 10. Proceed with Coiled Tubing Procedure for perforating. Attachments: 1. Current Schematic 2. Proposed Schematic 3. Coiled Tubing BOPE Schematic 4. Standard Well Procedure – N2 Operations Updated by CMT 12-9-2019 SCHEMATIC Ninilchik Unit Kalotsa #6 PTD: 219-114 API: 50-133-20685-00-00 PBTD = 5,710’ MD / 3,614’ = TVD TD = 5,745’ MD / 3,643’ = TVD’ RKB to GL = 18’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 DWC/C 6.875” Surf 1,654’ 4-1/2" Prod Csg 12.6 L-80 DWC/C HT 3.958” Surf 5,735’ 1 16” 7-5/8” 9-7/8” hole 4-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 1,466’ 3.958” 6.875” Swell Packer 6-3/4” hole B-134 PERFORATION DETAIL Zone Sand Top (MD) Btm (MD) Top (TVD) Btm (TVD) Amt SPF Date Status Beluga 134 5,624’ 5,682’ 3,541’ 3,590’ 58’ 6 10/17/19 Open Updated by CMT 4-24-2020 PROPOSED SCHEMATIC Ninilchik Unit Kalotsa #6 PTD: 219-114 API: 50-133-20685-00-00 PBTD = 5,710’ MD / 3,614’ = TVD TD = 5,745’ MD / 3,643’ = TVD’ RKB to GL = 18’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 DWC/C 6.875” Surf 1,654’ 4-1/2" Prod Csg 12.6 L-80 DWC/C HT 3.958” Surf 5,735’ 1 16” 7-5/8” 9-7/8” hole 4-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 1,466’ 3.958” 6.875” Swell Packer 6-3/4” hole B-134 PERFORATION DETAIL Zone Sand Top (MD) Btm (MD) Top (TVD) Btm (TVD) Amt SPF Date Status Beluga BEL_106 +5,338' +5,354' +3,296' +3,309' 16' TBD Proposed Beluga BEL_115 +5,424’ +5,442’ +3,370’ +3,385’ 18’ TBD Proposed Beluga BEL_131 +5,556’ +5,571’ +3,483’ +3,496’ 15’ TBD Proposed Beluga BEL_132 +5,574’ +5,598’ +3,498’ +3,519’ 24’ TBD Proposed Beluga 134 5,624’ 5,682’ 3,541’ 3,590’ 58’ 6 10/17/19 Open BEL_106 BEL_115 BEL_131 BEL_132 Coiled Tubing HydraCo 60K Injector Head & Gooseneck Weight = 3500 lbs 3" 500psi ArmorPak Stripper Bowen Type 5K 5.5" Lubricator 5K CJS ArmorPak Guide Bowen Type 5K x 5-1/8" 10K Flange 5-1/8" 10K Quad BOP 1.ArmorPak 1.5" x 1.5" Pipe Ram 2.ArmorPak 1.5" x 1.5" Pipe Ram 3.Shear Ram 4.Blind Ram 5-1/8 10K Spool with 2-1/16" 10K Outlets - Kill Port Manual Valve 1: 2-1/16" 10K Manual Valve 2: 2-1/16" 10K Manual Valve 3: 2" Weco 1502 Adapter Spool 5-1/8" 10K x 7-1/16" 5K Adapter Spool 7-1/16" 5K x 5-1/8" 5K 5-1/8" 5K ArmorPak 1.5" x 1.5" CT Head Wellhead 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. DATA SUBMITTAL COMPLIANCE REPORT 1/31/2020 Permit to Drill 2191140 Well Name/No. NINILCHIK UNIT KALOTSA 6 Operator Hilcorp Alaska LLC MD 5745 TVD 3643 Completion Date 9/29/2019 Completion Status 1 -GAS REQUIRED INFORMATION ��.� Mud Log �t6 t�/,",`rj0 Samples No DATA INFORMATION List of Logs Obtained: ROP/DGR/EWR-Ph4/ADR/CTN/ALD/Rad CBL/Form Log/Combo/Gas Ratio/Drill Dyn Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval OH / Type Med/Frmt Number Name Scale Media No Start Stop CH ED C 31687 Digital Data 100 5746 ED C 31687 Digital Data ED C 31687 Digital Data ED C 31687 Digital Data ED C 31687 Digital Data ED C 31687 Digital Data ED C 31687 Digital Data ED C 31687 Digital Data ED C 31687 Digital Data ED C 31687 Digital Data ED C 31687 Digital Data ED C 31687 Digital Data ED C 31687 Digital Data ED C 31687 Digital Data ED C 31687 Digital Data ED C 31687 Digital Data ED C 31687 Digital Data Log 31687 Log Header Scans 0 0 Current Status 1 -GAS API No. 50-133.20685-00-00 UIC No Directional Survey Yes (from Master Well Data/Logs) Received Comments 12/13/2019 Electronic Data Set, Filename: Kalotsa 6 LWD AOGCC Page I of Friday, January 31, 2020 Final.las 12/13/2019 Electronic File: Kalotsa 6 LWD Final MD.cgm 12/13/2019 Electronic File: Kalotsa 6 LWD Final TVD.cgm 12/13/2019 Electronic File: Kalotsa 6_Definitive Survey Report.pdf 12/13/2019 Electronic File: Kalotsa 6_Defintive Surveys.xlsx 12/13/2019 Electronic File: Kalotsa 6 DSR.txt 12/13/2019 Electronic File: Kalotsa 6 GIS.txt 12/13/2019 Electronic File: Kalotsa 6_Plan.pdf 12/13/2019 Electronic File: Kalotsa 6_VSec.pdf 12/13/2019 Electronic File: Kalotsa 6 LWD Final MD.emf 12/13/2019 Electronic File: Kalotsa 6 LWD Final TVD.emf 12/13/2019 Electronic File: Kalotsa 6 LWD Final MD.pdf 12/13/2019 Electronic File: Kalotsa 6 LWD Final TVD.pdf 12/13/2019 Electronic File: Kalotsa 6 LWD Final MD.tif 12/13/2019 Electronic File: Kalotsa 6 LWD Final TVD.tif 12/13/2019 Electronic File: EMFView3_1.zip 12/13/2019 Electronic File: Readme.txt 2191140 NINILCHIK UNIT KALOTSA 6 LOG HEADERS AOGCC Page I of Friday, January 31, 2020 DATA SUBMITTAL COMPLIANCE REPORT 1/31/2020 Permit to Drill 2191140 Well Name/No. NINILCHIK UNIT KALOTSA 6 MD 5745 TVD 3643 Completion Date 9/29/2019 Log 31688 Log Header Scans ED C 31688 Digital Data ED C 31688 Digital Data ED C 31688 Digital Data ED C 31689 Digital Data ED C 31689 Digital Data ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C 31689 Digital Data 31689 Digital Data 31689 Digital Data 31689 Digital Data 31689 Digital Data 31689 Digital Data 31689 Digital Data 31689 Digital Data 31689 Digital Data 31689 Digital Data 31689 Digital Data 31689 Digital Data 31689 Digital Data 31689 Digital Data 31689 Digital Data Operator Hilcorp Alaska LLC API No. 50-133-20685-00-00 Completion Status 1 -GAS Current Status 1 -GAS UIC No 0 0 2191140 NINILCHIK UNIT KALOTSA 6 LOG HEADERS 5696 -6 12/13/2019 Electronic Data Set, Filename: KALOTSA_6_RCBL_10OCT19.las 12/13/2019 Electronic File: KALOTSA _6_RC BL_10OCT19.pdf 12/13/2019 Electronic File: KALOTSA_6_RCBL_100CT19_img.tiff 10 5790 12/13/2019 Electronic Data Set, Filename:_ Kalotsa 6.1as 12/13/2019 Electronic File: Hilcorp Kalotsa 6 Nabors AM Report 9-20-19.pdf 12/13/2019 Electronic File: Hilcorp Kalotsa 6 Nabors AM Report 9-21-19.pdf 12/13/2019 Electronic File: Hilcorp Kalotsa 6 Nabors AM Report 9-22-19.pdf 12/13/2019 Electronic File: Hilcorp Kalotsa 6 Nabors AM Report 9-23-19.pdf 12/13/2019 Electronic File: Hilcorp Kalotsa 6 Nabors AM Report 9-24-19.pdf 12/13/2019 Electronic File: Hilcorp Kalotsa 6 Nabors AM Report 9-25-19.pdf 12/13/2019 Electronic File: Hilcorp Kalotsa 6 Nabors AM Report 9-26-19.pdf 12/13/2019 Electronic File: Hilcorp Kalotsa 6 Nabors AM Report 9-27-19.pdf 12/13/2019 Electronic File: Hilcorp Kalotsa 6 Nabors AM Report 9-28-19.pdf 12/13/2019 Electronic File: KALOTSA6.dbf 12/13/2019 Electronic File: kalotsa6.hdr 12/13/2019 Electronic File: KALOTSA6.mdx 12/13/2019 Electronic File: kalotsa6r.dbf 12/13/2019 Electronic File: kalotsa6r.mdx 12/13/2019 Electronic File: KALOTSA6 SCL.DBF 12/13/2019 Electronic File: KALOTSA6 SCL.MDX AOGCC Page 2 of Friday, January 31, 2020 DATA SUBMITTAL COMPLIANCE REPORT 1131/2020 Permit to Drill 2191140 Well Name/No. NINILCHIK UNIT KALOTSA6 Operator Hilcorp Alaska LLC API No. 50-133-20685-00-00 MD 5745 TVD 3643 Completion Date 9/29/2019 Completion Status 1 -GAS Current Status 1 -GAS UIC No ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA6 tvd.dbf ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA6 tvd.mdx ED C 31689 Digital Data 12/13/2019 Electronic File: Kalotsa 6 - Final Well Report.pdf ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - 5in Drilling Dynamics Log MD.pdf ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - Sin Drilling Dynamics Log TVD.pdf ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - Sin Formation Log MD.pdf ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - 5in Formation Log TVD.pdf ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - Sin Gas Ratio Log MO.pdf ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - 5in Gas Ratio Log TVO.pdf ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - Sin LW D Combo Log MD.pdf ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - 5in LW D Combo Log TVD.pdf ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - Drilling Dynamics Log MD.pdf ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - Drilling Dynamics Log TVD.pdf ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - Formation Log MD.pdf ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - Formation Log TVD.pdf ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - Gas Ratio Log MD.pdf ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - Gas Ratio Log TVD.pdf ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - LW D Combo Log MD.pdf ED C 31669 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - LW D Combo Log TVD.pdf AOGCC Page 3 of 6 Friday, January 31, 2020 DATA SUBMITTAL COMPLIANCE REPORT 1/31/2020 Permit to Drill 2191140 Well Name/No. NINILCHIK UNIT KALOTSA 6 Operator Hilcorp Alaska LLC API No. 50-133-20685-00-00 MD 5745 TVD 3643 Completion Date 9/29/2019 Completion Status 1 -GAS Current Status 1 -GAS UIC No ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - 5in Drilling Dynamics Log MD.tif ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - 5in Drilling Dynamics Log TVD.tif ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - 5in Formation Log MD.tif ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - 5in Formation Log TVD.tif ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - 5in Gas Ratio Log MD.tif ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - 5in Gas Ratio Log TVD.tif ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 -5in LWD Combo Log MD.tif ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - 5in LWD Combo Log TVD.tif ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - Drilling Dynamics Log MD.tif ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - Drilling Dynamics Log TVD.tif ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - Formation Log MD.tif ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - Formation Log TVD.tif ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - Gas Ratio Log MD.tif ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - Gas Ratio Log TVD.tif ED C 31689 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - LWD Combo Log MD.tif ED C 31669 Digital Data 12/13/2019 Electronic File: KALOTSA 6 - LWD Combo Log TVD.tif ED C 31689 Digital Data 12/13/2019 Electronic File: Kalotsa 6 Gas Show Report 1 1993-2080.pdf ED C 31689 Digital Data 12/13/2019 Electronic File: Kalotsa 6 Gas Show Report 10 5536-5595.pdf AOGCC Page 4 of 6 Friday, January 31, 2020 DATA SUBMITTAL COMPLIANCE REPORT 1/31/2020 Pefmitto Drill 2191140 Well Name/No. NINILCHIK UNIT KALOTSA6 Operator Hilcorp Alaska LLC MD 5745 TVD 3643 Completion Date 9/29/2019 ED C 31689 Digital Data ED C 31689 Digital Data ED C 31689 Digital Data ED C 31689 Digital Data ED C 31689 Digital Data ED C 31689 Digital Data ED C 31689 Digital Data ED C 31689 Digital Data ED C 31689 Digital Data Log 31689 Log Header Scans Well Cores/Samples Information: Name INFORMATION RECEIVED /� Completion Report V Production Test InformatioY NA Geologic Markers/Tops Q Interval Start Stop API No. 50-133-20685-00-00 Completion Status 1 -GAS Current Status 1 -GAS UIC No 12/13/2019 Electronic File: Kalotsa 6 Gas Show Report 11 5625-5680.pdf 12/13/2019 Electronic File: Kalotsa 6 Gas Show Report 2 2435-2475.pdf 12/13/2019 Electronic File: Kalotsa 6 Gas Show Report 3 3045-3225.pdf 12/13/2019 Electronic File: Kalotsa 6 Gas Show Report 4 3255-3393.pdf 12/13/2019 Electronic File: Kalotsa 6 Gas Show Report 5 3475-3527.pdf 12/13/2019 Electronic File: Kalotsa 6 Gas Show Report 6 4642-4707.pdf 12/13/2019 Electronic File: Kalotsa 6 Gas Show Report 7 4775-4885.pdf 12/13/2019 Electronic File: Kalotsa 6 Gas Show Report 8 4930-5050.pdf 12/13/2019 Electronic File: Kalotsa 6 Gas Show Report 9 5140-5355.pdf 0 0 2191140 NINILCHIK UNIT KALOTSA 6 LOG HEADERS Sample Set Sent Received Number Comments Directional / Inclination Data (Y Mechanical Integrity Test InformationY/Y / NA Daily Operations Summary I Y COMPLIANCE HISTORY �/ Completion Date: 9/29/2019 Release Date: 9/10/2019 AOGCC Page 5 of 6 Mud Logs, Image Files, Digital Data% 0 Core Chips Y 10 Composite Logs, Image, Data Files 0 Core Photographs Y/ Cuttings Samples Y NA Laboratory Analyses Y Friday, January 31, 2020 DATA SUBMITTAL COMPLIANCE REPORT 1/31/2020 Permit to Drill 2191140 Well Name/No. NINILCHIK UNIT KALOTSA 6 Operator Hi lcorp Alaska LLC MD 5745 TVD 3643 Completion Date 9/29/2019 Completion Status 1 -GAS Current Status 1 -GAS Description Date Comments Comments: Compliance Reviewed By: Date: API No. 50-133.20685-00-00 UIC No 113 I i?,ow AOGCC Page of Friday, January 31, 2020 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION GAS WELL OPEN FLOW POTENTIAL TEST REPORT 1a. Test: L�j Initial Lj Annual Lj Special 1b. Type Test: U Stabilized Non Stabilized U Multipoint ❑ Constant Time ❑ ISOGhronal Q Other: Nodal 2. Operator Name: Hiloorp Alaska, LLC 5. Date Completed: 09/29/19 11. Permit to Drill Number: 219-114 3. Address: 3600 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 6. Dale TO Reached: 09/26/19 12. API Number: 50- 133-20685.00-00 4a. Location of Well (Govemmental Section): Surface: 2156' FSL, 437' FWL, Sec 7, TIS, RIM, SM, AK Top of Productive Horizon: 76' FNL, 1746' FEL, Sec 12, TIS, R14W, SM, AK Total Depth: 15' FNL, 1797' FEL, Sec 12, T1 S, R1 4W, SM, AK 7. KB Elevation above MSL (feet): 144.4' 13. Well Name and Number: Kalolsa 6 8. Plug Back Deplh(MD+TVD): 5,710' MD / 3,614' TVD 14. Field/Pool(s): Ninilchik Field Beluga/fyonek Gas Pool 9, Total Depth (MD + TVD): 5,745' MD 13,643' TVD 4b. Location of Well (State Base Plane Coordinates NAD 27): Surface: x- 209834 y-2233431 Zone- 4 TPI: x- 207726 y- 2236445 Zone- 4 Total Depth: x- 207677 y- 2236507 Zone- 4 10. Land Use Permit: N/A 15, Property Designation: C061505/ADL384372 16. Type of Completion (Describe): 4-112" Production String, Perforated 17. Casing Size Weight per foot, Ib. I.D. in Inches Set at ft. 4-1/2" 12.6 3.958" 5,745 19. Perforations: From To 5,624-5,682 18. Tubing Size Weight per foot, Ib. I.D. in Inches Set at ft. 20. Packer set at ft: 1,466 21. GOR cf/bbl: 22. API Liquid Hydrocardbons: 23. Specific Gravity Flowing Fluid (G): 24a. Producing through: ❑ Tubing ❑Q Casing 24b. Reservoir Temp: 88 F° 24c Reservoir Pressure: 375 psia @ Datum 4540 TVDSS 24d. Barometric Pressure (Pa): pea 25. Length of Flow Channel (L): Vertical Depth (H): Gg: 0.06 %CO2: 0 %Nz: 0 %HiS: Prover: Meter Run: Taps: 26. FLOW DATA TUBING DATA CASING DATA No. Prover Choke Pressure Diff. Temp. Line X Orifice Size (in.) Size (in.) psig Hw F" Pressure Temp. psig F° Pressure Temp. psig r Duration of Flow Hr. 1. X 2. X 3. X 4. X 5. X No. Basic Coefficient Flow Temp. (24 -Hour) hP, Pressure Factor Gravity Factor Fb or Fp Pm FI Fg Super Comp. Factor Fpv Rate of Flow O, Mold 1. 2. 3- 4. 5. No. Temperature for Separator Pr T Tr z Gas Gg for Flowing Fluid G 1. 2. 3. Critical Pressure 4. Critical Temperature 5. Form 10-421 Rev. 7/2009 CONTINUED ON REVERSE SIDE Submit In Duplicate Pc pe Pf Pe No. Pt p' pe -pt' Pw Pw' Pe-Pvt Ps PsY Pfl-Ps2 1. 2. 3. 4. 5. 25. AOF (Mcfd) 2,560 n Remarks: Kalotsa 6 is perforated in the Beluga 134 sand. BEL134 Is a very thick, high perm sand which Is highly depleted from extensive historical production in offset wells. The well bull( up to-280psi WHP just after the perforation on 10117/2019, however, short shut-in periods since then have built to-350psi. A reservoir pressure of 375psi was selected as it best fit the step rate tests in creating a reasonable IPR curve. I hereby certf y th the regoing is true and correct to the best of my knowledge. Reservoir Engineer Signed Title Datel/2C?120Z0 DEFINITIONS OF SYMBOLS AOF Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producin face were reduced to zero psia Fb Basic orifice factor Mcfd/ PhJv m Fp Basic critical flow prover or positive choke factor Mcfd/psia 0.06 Fg Specific gravity factor, dimensionless Fpv Super compressibility factor= bfZ dimensionless Ft Flowing temperature factor, dimensionless G Specific gravity of flowing fluid (air=1.000), dimensionless Gg Specific gravity of separator gas (air=1.00), dimensionless GOR Gas -oil ratio, cu. ft. of gas (14.65 psia and 60 degrees F) per barrel oil (60 degrees F) hw Meter differential pressure, inches of water H Vertical depth corresponding to L, feet (TVD) L Length of flow channel, feet (MD) n Exponent (slope) of back -pressure equation, dimensionless Pa Field barometric pressure, psia Pc Shut-in wellhead pressure, psia Pf Shut-in pressure at vertical depth H, psia Pm Static pressure at point of gas measurement, psia Pr Reduced pressure, dimensionless Ps Flowing pressure at vertical depth H, psia Pt Flowing wellhead pressure, psia Pw Static column wellhead pressure corresponding to Pt, psia Q Rate of flow, Mcfd (14.65 psia and 60 degrees F) Tr Reduced temperature, dimensionless T Absolute temperature, degrees Rankin Z Compressibility factor, dimensionless Recommended procedures for tests and calculations may be found in the Manual of Back- Pressure Testing of Gas Wells, Interstate Oil Compact Commission, Oklahoma City, Oklahoma. Form 10421 Revised 7/2009 Side 2 Hilcorp Alaska, LLC. - O:\Alaska\Fields\Ninilchik\Kalotsa\Wells\Kalotsa 6\Nodal\Kalotsa_6.Out Pagel ######################################## # INFLOW PERFORMANCE DATA (GAS WELL) # ######################################## Reservoir Model MultiRate C and n Reservoir Pressure 373.02 (psig) Reservoir Temperature 75.00 (deg F) Water -Gas Ratio 0 (STB/MMscf) Condensate Gas Ratio 0 (STB/MMscf) Absolute Open Flow (AOF) 2.580 (MMscf/day) Gas Rate Pressure (MMscf/day) (psig) 1.220 276.28 1.480 248.10 ++++++++++++++++++++++++++++++++++++++++++++++++++++++ + MULTIRATE TEST DATA AND DERIVED MODEL PARAMETERS + ++++++++++++++++++++++++++++++++++++++++++++++++++++++ C 0.052775 (Mscf/day/psi2) n 0.90589 Hilcorp Alaska, LLC. - 0:\Alaska\Fields\Ninilchik\Kalotsa\Wells\Kalotsa 6\Nodal\Kalotsa_6.Out ######################################## # INFLOW PERFORMANCE DATA (GAS WELL) # ######################################## Reservoir Model Jones 16.00 (md) M&G Skin Model Enter Skin By Hand Reservoir Pressure 374.50 (psig) Reservoir Temperature 75.00 (deg F) Water -Gas Ratio 0 (STB/MMscf ) Condensate Gas Ratio 0 (STB/MMscf) Absolute Open Flow (AOF) 2.576 (MMscf/day) Reservoir Permeability 16.00 (md) Reservoir Thickness 80.0 (feet) Drainage Area 360.0 (acres) Dietz Shape Factor 31.4 Wellbore Radius 0.375 (feet) Perforation Interval 60.00 (feet) Calculated Non -Darcy Coefficent (Beta) 834080256 Page 1 Hilcorp Alaska, LLC. - 0:\Alaska\Fields\Ninilchik\Kalotsa\Wells\Kalotsa 6\Nodal\Kalotsa_6.Out Page 2 ++++++++++++++++++++++++++++++++++++++ + MECHANICAL/GEOMETRICAL SKIN DATA + ++++++++++++++++++++++++++++++++++++++ Skin 0 Hilcorp Alaska, LLC. - O:\Alaska\Fields\Ninilchik\Kalotsa\Wells\Kalotsa 6\Nodal\Kalotsa_6.Out Page 3, +++++++++++++++++++++++++++++ + IPR Calculation Results + +++++++++++++++++++++++++++++ dP dP dP Sand Sand dP dP dP dP Total Total Completion Completion Control Control Perforation Damage Penetration Deviation Perforation Damage Rate Pressure Temperature Skin Skin Skin Skin Skin Skin Skin Skin Skin Skin Skin Skin (MMscf/day) (psig) (deg F) (psi) (psi) (psi) (psi) (psi) (psi) (psi) le -5 373.02 75.00 0 0 0 0 0 0 0 0 0 0 0 0 0.1358 365.44 74.47 0 0 0 0 0 0 0 0 0 0 0 0 0.27159 356.54 73.84 0 0 0 0 0 0 0 0 0 0 0 0 0.40738 346.91 73.16 0 0 0 0 0 0 0 0 0 0 0 0 0.54317 336.66 72.43 0 0 0 0 0 0 0 0 0 0 0 0 0.67896 325.81 71.67 0 0 0 0 0 0 0 0 0 0 0 0 0.81475 314.36 70.86 0 0 0 0 0 0 0 0 0 0 0 0 0.95054 302.29 70.01 0 0 0 0 0 0 0 0 0 0 0 0 1.086 289.54 69.11 0 0 0 0 0 0 0 0 0 0 0 0 1.222 276.07 68.16 0 0 0 0 0 0 0 0 0 0 0 0 1.358 261.76 67.16 0 0 0 0 0 0 0 0 0 0 0 0 1.494 246.51 66.10 0 0 0 0 0 0 0 0 0 0 0 0 1.629 230.16 64.96 0 0 0 0 0 0 0 0 0 0 0 0 1.765 212.48 63.74 0 0 0 0 0 0 0 0 0 0 0 0 1.901 193.13 62.42 0 0 0 0 0 0 0 0 0 0 0 0 2.037 171.62 60.97 0 0 0 0 0 0 0 0 0 0 0 0 2.173 147.10 59.36 0 0 0 0 0 0 0 0 0 0 0 0 2.308 117.91 57.50 0 0 0 0 0 0 0 0 0 0 0 0 2.444 79.86 55.20 0 0 0 0 0 0 0 0 0 0 0 0 2.580 1.01 51.35 0 0 0 0 0 0 0 0 0 0 0 0 Penetration Deviation Rate Skin Skin (MMscf/day) le -5 0 0 Hilcorp Alaska, LLC. - O:\Alaska\Fields\Ninilchik\Kalotsa\Wells\Kalotsa 6\Nodal\Kalotsa_6.Out 0.1358 0 0 0.27159 0 0 0.40738 0 0 0.54317 0 0 0.67896 0 0 0.81475 0 0 0.95054 0 0 1.086 0 0 1.222 0 0 1.358 0 0 1.494 0 0 1.629 0 0 1.765 0 0 1.901 0 0 2.037 0 0 2.173 0 0 2.308 0 0 2.444 0 0 2.580 0 0 Total Skin : 0 ( = Entered + Perforation + Damage + Deviation + Partial Penetration ) Completion Skin : 0 (= Entered + Perforation + Damage + Sand Control ) Perforation Skin : 0 Damage Skin: 0 Penetration Skin : 0 Deviation Skin : 0 Sand Control Skin : 0 Calculated Non -Darcy Coefficent (Beta) : +++++++++++++++++++ + End of Report + +++++++++++++++++++ Page 4 370 360 350 340 330 320 310 300 a u 200 u 190 w 180 n` 170 160 150 140 130 120 110 100 90 80 70 60 50 40 30 20 10 0 0 RR R ...........,................................................................. .......... ..............................•----•--.......................... ............................................................................ .w 3--------------------------------------- ............................................................................................................. ,....................... ..._•_-••.......................................................................................................................... ........................................................................................................ ...................... Rale (MMSd/day) 2 75 74.5 74 73.5 73 72.5 72 71.5 71 70.5 70 69.5 69 68.5 68 67.5 67 64.5 3 .64 'm 63.5 'u 63 n 62.5 a 62 m 61.5 = 61 60.5 60 59.5 -59 58.5 58 57.5 • • 57 56.5 56 55.5 55 - 54.5 54 53.5 53 52.5 52 51.5 Hilcorp Alaska, LLC. - 0:\Alaska\Fields\Ninilchik\Kalotsa\Wells\Kalotsa 6\Nodal\Kalotsa_6.Out Page 1 .............................................. . SYSTEM SENSITIVITY ANALYSIS - Input Data . Top Node Pressure : 225.00 (prig) Water Gas Ratio : 0 (STB/MMscf) Condensate Gas Ratio : 0 (STB/MMscf) Surface Equipment Correlation : Hydro -213 Vertical Lift Correlation : Petroleum Experts 2 Solution Node : Bottom Node Rate Method : Automatic - Linear Left -Hand Intersection : DisAllow PES Stability Flag : No Hilcorp Alaska, LLC. - 0:\Alaska\Fields\Ninilchik\Kalotsa\Wells\Kalotsa 6\Nodal\Kalotsa_6.Out Page 2 ########################################### # SYSTEM SENSITIVITY ANALYSIS - Results # ########################################### dP First Gas Water VLP IPR Total dP dP dP Completion Total WellHead WellHead Node dP dP Rate Rate Pressure Pressure Skin Perforation Damage Completion Skin Skin Pressure Temperature Temperature Friction Gravity (MMscf/day) (STB/day) (psig) (psig) (psi) (psi) (psi) (psi) (psig) (deg F) (deg F) (psi) (psi) 0.0025849 0 244.15 373.90 0 0 0 0 0 0 225.00 32.00 32.00 5.2977e-5 19.15 0.13839 0 244.19 366.00 0 0 0 0 0 0 225.00 32.15 32.15 0.036263 19.15 0.2742 0 244.27 356.90 0 0 0 0 0 0 225.00 32.29 32.29 0.12382 19.15 0.41 0 244.41 347.11 0 0 0 0 0 0 225.00 32.43 32.43 0.25712 19.15 0.54581 0 244.59 336.73 0 0 0 0 0 0 225.00 32.58 32.58 0.43406 19.15 0.68161 0 244.81 325.78 0 0 0 0 0 0 225.00 32.72 32.72 0.6534 19.16 0.81742 0 245.08 314.25 0 0 0 0 0 0 225.00 32.86 32.86 0.91434 19.16 0.95322 0 245.39 302.11 0 0 0 0 0 0 225.00 33.00 33.00 1.22 19.17 1.089 0 245.74 289.31 0 0 0 0 0 0 225.00 33.15 33.15 1.56 19.18 1.225 0 246.13 275.79 0 0 0 0 0 0 225.00 33.29 33.29 1.94 19.19 1.361 0 246.57 261.46 0 0 0 0 0 0 225.00 33.43 33.43 2.36 19.21 1.496 0 247.05 246.20 0 0 0 0 0 0 225.00 33.57 33.57 2.82 19.22 1.632 0 247.56 229.85 0 0 0 0 0 0 225.00 33.71 33.71 3.33 19.24 1.768 0 248.12 212.18 0 0 0 0 0 0 225.00 33.85 33.85 3.86 19.26 1.904 0 248.72 192.88 0 0 0 0 0 0 225.00 33.99 33.99 4.44 19.28 2.040 0 249.36 171.43 0 0 0 0 0 0 225.00 34.13 34.13 5.06 19.30 2.175 0 250.04 147.01 0 0 0 0 0 0 225.00 34.27 34.27 5.71 19.32 2.311 0 250.75 117.98 0 0 0 0 0 0 225.00 34.41 34.41 6.40 19.35 2.447 0 251.51 80.24 0 0 0 0 0 0 225.00 34.54 34.54 7.13 19.37 2.583 0 252.30 4.75 0 0 0 0 0 0 225.00 34.68 34.68 7.89 19.40 Total Maximum Maximum Maximum PE5 Erosional Maximum Turner Gas NoSlip Erosional C Grain Erosion Corrosion Stability Velocity Turner Velocity Rate Velocity Velocity Factor Diameter Rate Rate Flag Flag Velocity Flag (MMscf/day) (ft/sec) (ft/sec) (inches) (0.001 inches/year) (0.001 inches/year) (ft/sec) Hilcorp Alaska, LLC. - 0:\Alaska\Fields\Ninilchik\Kalotsa\Wells\Kalotsa 6\Nodal\Kalotsa_6.Out Page 3 0.0025849 0.019747 457.891 0.01725 0.0001 No No 0.13839 1.057 457.891 0.92352 0.0012138 No No 0.2742 2.094 457.843 1.8296 0.0047687 No No 0.41 3.130 457.751 2.73523 0.010658 No No 0.54581 4.165 457.618 3.64016 0.018897 No No 0.68161 5.197 457.458 4.5443 0.029485 No No 0.81742 6.228 457.2815.44761 0.042424 No No 0.95322 7.256 457.065 6.34967 0.057711 No No 1.089 8.280 456.810 7.25026 0.075349 No No 1.225 9.301 456.517 8.14915 0.095336 No No 1.361 10.317 456.185 9.04614 0.11758 No No 1.496 11.328 455.819 9.94104 0.14208 No No 1.632 12.350 455.695 10.8403 0.16891 No No 1.768 13.378 455.715 11.7427 0.19796 No No 1.904 14.408 455.744 12.6455 0.22908 No No 2.040 15.438 455.789 13.5488 0.26228 No No 2.175 16.471 455.85114.4529 0.29762 No No 2.311 17.504 455,912 15.3572 0.33503 No No 2.447 18.537 455.972 16.2617 0.37451 No No 2.583 19.571 456.031 17.1664 0.41595 No No Hilcorp Alaska, LLC. - 0:\Alaska\Fields\Ninilchik\Kalotsa\Wells\Kalotsa 6\Nodal\Kalotsa_6.Out ...................I . Solution Point . Gas Rate : 1.489 (MMscf/day) Oil Rate : 0 (STB/day) Water Rate : 0 (STB/day) Liquid Rate : 0 (STB/day) Solution Node Pressure : 247.02 (psig) dP Friction : 2.80 (psi) dP Gravity : 19.22 (psi) dP Total Skin : 0 (psi) dP Perforation : 0 (psi) dP Damage : 0 (psi) dP Completion : 0 (psi) Completion Skin : 0 Total Skin : 0 Wellhead Liquid Density : 48,060 (Ib/ft3) Wellhead Gas Density : 0.7712 (Ib/ft3) Wellhead Liquid Viscosity : 1.7899 (centipoise) Wellhead Gas Viscosity : 0.010757 (centipoise) Wellhead Superficial Liquid Velocity : 0 (ft/sec) Wellhead Superficial Gas Velocity : 11.257 (ft/sec) Wellhead Z Factor : 0.95775 Wellhead Interracial Tension : 13.6554 (dyne/cm) Wellhead Pressure : 225.00 (psig) Wellhead Temperature : 33.56 (deg F) First Node Liquid Density : 48.060 (Ib/ft3) First Node Gas Density : 0.7712 (Ib/ft3) First Node Liquid Viscosity : 1.7899 (centipoise) First Node Gas Viscosity : 0.010757 (centipoise) First Node Superficial Liquid Velocity : 0 (ft/sec) First Node Superficial Gas Velocity : 11.257 (ft/sec) First Node Z Factor : 0.95775 First Node Interfacial Tension : 13.6554 (dyne/cm) First Node Pressure : 225.00 (psig) First Node Temperature : 33.56 (deg F) Page 4 Hilcorp Alaska, LLC. - 0:\Alaska\Fields\Ninilchik\Kalotsa\Wells\Kalotsa 6\Nodal\Kalotsa_6.Out +++++++++++++++++++ + End of Report + +++++++++++++++++++ Page 7 1 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Ninilchik Field, Beluga/Tyonek Gas Pool, Kalotsa 6 Permit to Drill Number: 219-114 Sundry Number: 319-561 Dear Mr. York: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Jerrice Chair DATED this 12 day of December, 2019. 3BDMS '� DEC 19 2019 RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION DEC 11 2019 APPLICATION FOR SUNDRY APPROVALS/ �S/��/Z413 (!p 20 AAC 25.260 A s ) l 7l .l . 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: Capillary String Q 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development ❑� Stratigraphic ❑ Service ❑ 219-114 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: r Anchorage Alaska 99503 50-133-20685-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 701A r Will planned perforations require a spacing exception? Yes ❑ No ❑ Kalotsa 6 9. Property Designation (Lease Number): 10. Field/Pool(s): C061505 / ADL384372 ' Ninilchik - Beluga/Tyonek Gas Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 5,745' 3,643' 5,710' TBD -1,210 N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 120' 16" 120' Surface 1,654' 7-5/8" 1,654' 1,257' 6,890psi 4,790psi Intermediate 5,735' 4-1/2" 5,735' 3,635' 8,430psi 7,500psi Production Liner Perforation Depth MD(ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic N/A N/A N/A Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Swell Pkr; N/A 1,466' MD/1,209' TVD; N/A, N/A 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development ❑+ Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: December 23rd, 2019 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS Q WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Be York 777-8345 Contact Name: Christina Twogood Authorized Title: Operations Manager Contact Email: CtW0qoodlcDhiIcorp.com Contact Phone: 777-8443 � Authorized Signature: - Date: i v t9e r COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance Other: 3BDMS1� DEC 19 2019 Post Initial Injection MIT Req'd? Yes ❑ No❑�y` c./ Spacing Exception Required? Yes ❑ No LJ Subsequent Form Required: APPROVED BY ApproveVb COMMISSIONER THE COMMISSION Date: 1 (u� G 3�G j- Submit Form and Fey, e y'I d 4 17 Approved application is va o 4J f �tt��YYY f approval. Aft a hments in Duplicate Well Prognosis Well: Kalotsa 6 Date: 12/9/2019 Well Name: Kalotsa 6 API Number: 50-133-20685-00-00 Current Status: Producing Gas Well Leg: N/A Estimated Start Date: December 23rd, 2019 Rig: N/A Reg. Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 219-114 First Call Engineer: Christina Twogood (907) 777-8443 (0) (907) 378-7323 (M) Second Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (M) AFE Number: Max. Expected BHP: — 1,569 psi @ 3,590' TVD (Based on normal gradient) Max. Potential Surface Pressure: — 1,210 psi (Based on expected BHP and gas gradient to surface (0.1 psi/ft)) Brief Well Summary Zo1 Kalotsa 6 was drilled and completed as a grassroots well in 2019. In October203 , the Beluga B-134 sand was perforated and the well was brought online. The purpose of this work/sundry is to install a capillary string. The capillary string will be inserted into the tubing and the chemical injected at or above the base perforation. Capillary String Procedure: 1. MIRU Cap String Truck, PT lubricator to 250 psi Low / 2,500 psi High. 2. Install new wellhead pack -off. 3. PU 3/8" capillary string. RIH and set at +/- 5,682' MD. 4. Set spool of remaining line near well. 5. Rig down Cap String Truck. 6. Turn well over to production. Attachments S S v 1. Actual Schematic 2. Proposed Schematic RKB to GL= 18' 16" At^ i 9 7/8' ' 13� hole r 1 { _ e 7-5/8" r i� v k� 6-3/4" ~ hale I• r-� L' - kr B-134 F_ i.. L . 4-1/2" Xi PBTD = 5,710' M D / 3,614' = ND TD = 5,745' MD / 3,643'= ND' S�:HEMATIC CASINC, DFTAIL Ninilchik Unit Kalotsa #6 PTD: 219-114 API: 50-133-20685-00-00 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 1,654' 4-1/2" Prod Csg 12.6 L-80 DWC/C HT 3.958" Surf 5,735' JEWELRY DETAIL PERFORATION DETAIL Zone Sand p Btm Top Btm Amt SPF Date Status (MD) (MD) (ND) (ND) Beluga 134 5,624' 5,682' 3,541' 3,590' S8' 6 10/17/19 Open Updated by CMT 12-9-2019 16" hole RKB to GL =18' 7-5/8" �.T hole 2 PROPLaED SCHEMATIC 1 B-134 4-1/Y' Y?s-��i �iili PBTD = 5,710' MD / 3,614' = TVD TD = 5,745' MD / 3,643'= TVD' [ASING nFTAII Ninikhik Unit Kalotsa #6 PTD: 219-114 API: 50-133-20685-00-00 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 1,654' 4-1/2" Prod Csg 12.6 L-80 DWC/C HT 3.958" Surf 5,735' JEWELRY DETAIL No. Depth ID OD It 1 1,466' 3.958" 6.875" Swell Packer 2 +5,682' 1 Capillary String PERFORATION DETAIL Zone Sand Amt SPF Date Status (MD) (MD) (TVD) (TVD) Beluga 134 5,624' 5,682' 3,541 3,590' S8' 6 1 10/17/19 1 Open Updated by CMT 12-9-2019 DATE 12/13/2019 De, -a Oudean GeoTech Hilcorp Alaska, LLC 3800 Centerpoint Drive Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 219114 RECEIVED DEC 13 2019 AQGCC HALLIBURTON CBL 3 16 8 7 FIELD PRINT KALOTSA 6 CBL_1D_OCT_2... 10/14/2019 9.29 AM PDF Document KALOTSA b CBL_10oct2019 10/14/2019930AM LAS File HALLIBURTON LWD 3 1 6 8 8 KALOTSA 6 RCBL_10GCT19 10/18/201910:11 ... LAS File L KALOTSA 6 RCBL 100CT19 10/181201910:11 ... PDF Document KAL0TSA_6_RCBL_100CT19 img 10/19/201910:11 ... TIFF File NABORS 3 1 6 8 9 LAS Data 12113/201910:22 ... Log PDFs 101291201910:14... Log TIFFS 12/13/201910:24... Show Reports 12/13/201910:25 ... Daily Reports 12,113/201910,25 ... DML Data 12,113/201910:25 ... Final Well Report 10/29/201910:14... Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION iJM/ n r omn WELL COMPLETION OR RECOMPLETION REPORT ANDUY6 1a. Well Status: Oil ❑ Gas❑✓ SPLUG ❑ Other ❑ Abandoned ❑ Suspended[] zonc 25,105 zoanc 25.1 1G GINJ ❑ WINJ ❑ WAC WDSPL ❑ No. of Completions: _ 1 1b. Well Class: 80 Development J G - Explore ory❑ Service ❑ Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Date Comp., Susp., or Abend.: 9/29/2019 14. Permit to Drill Number/ Sundry: ' 219-114 / 319-447 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: September 19, 2019 15. API Number: 50-133-20685-00-00 ' 4a. Location of Well (Governmental Section): Surface: 2156' FSL, 437' FWL, Sec 7, Ti S, R1 3W, SM, AK Top of Productive Interval: 76' FNL, 1746' FEL, Sec 12, T1S, R14W, SM, AK Total Depth: 15' FNL, 1797' FEL, Sec 12, T1 S, R14W, SM, AK 8. Date TD Reached: September 26, 2019 16. Well Name and Number: Kalotsa 6 - 9. Ref Elevations: KB: 144.4'. GL: 126.4' . BF: 126.4' 17. Field / Pool(s): Ninilchik Field Belugalryonek Gas Pool 10. Plug Back Depth MD/TVD: • 5,710' MD / 3,614' TVD • 18. Property Designation: _ C061505 / ADL384372 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 209834 y- 2233431 - Zone- 4 TPI: x- 207726 y- 2236445 Zone- 4 Total Depth: x- 207677 y- 2236507 Zone- 4 11. Total Depth MDf VD: - 5,745' MD / 3,643' TVD • 19. DNR Approval Number: N/A 12. SSSV Depth MD/TVD: N/A I 20. Thickness of Permafrost MD/TVD N/A 5. Directional or Inclination Survey: Yes J (attached) No ❑ Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: N/A (ft MSL) I 21. Re-drill/Lateral Top Window MD[TVD: N/A 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary ROP / DGR / EWR-Phase 4 / ADR / CTN / ALD / RADIAL CBL / FORMATION LOG MD -TVD / Iwd Combo Log MD -TVD / Gas Ratio MD -TVD / Drilling Dynamics MD -TVD 23. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING FT GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 16" 84# X-56 Surface 120' Surface 120' Driven Driven 7-5/8" 29.7# L-80 Surface 1,654' Surface 1,257' 9-7/8" L - 180 sx / T - 155 sx 30 bbls 4-1/2" 12.6# L-80 Surface 5,735' Surface 3,635' 6-3/4" L - 300 sx / T - 80 sx 24. Open to production or injection? Yes Q No ❑ If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): 5,624' - 5,644' MD / 3541'- 3558' TVD on 10/16/19 5,6421- 5,662' MD 13556'- 3573' TVD on 10/16/19 5,662' - 5,682' MD / 3573'- 3590' TVD on 10/16/19 COMPLETION 2-7/8", 6 SPF �D/�j�TE �/^ T VE. OD 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) N/A 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes No 121 Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: 10/21/2019 Method of Operation (Flowing, gas lift, etc.): Flowing Date of Test: 10/26/2019 Hours Tested: 24 Production for Test Period Oil -Bbl: 0 Gas -MCF: 2,798 Water -Bbl: 0 Choke Size: N/A Gas -Oil Ratio: N/A Flow Tubing Press. 253 Casing Press: 186 lCalculated 24 -Hour Rate Oil -Bbl: 0 12,798 Gas -MCF: Water -Bbl: 0 Oil Gravity - API (corr): 1 N/A Farm 10-407 Revised 5/2017 CONTINUED 01_=E 2 RBDMS !�J NOV 0 B 1019 ub�it (I�NIIAAL or„�r Pe /-3 —Z O �/ VF 28. CORE DATA Conventional Corals): Yes ❑ No Q Sidewall Cores: Yes ❑ No Q ' 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. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑� - If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top N/A NIA Permafrost - Base N/A N/A Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval 5,624' 3,541' information, including reports, per 20 AAC 25.071. Beluga 100 5,283' 3,248' Beluga 106 5,331' 3,289' Beluga 110 5,372' 3,325' Beluga 115 5,420' 3,366' Beluga 120 5,457' 3,398' Beluga 131 5,555' 3,482' Beluga 134 5,612' 3,531' Formation at total depth: IB135 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Survey, Casing and Cement Reports Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Monty Myers Contact Name: Cody Dinger Authorized Title: nqvanager 4 Contact Email: Cdif1 er hIICOr .COm Authorized,r/ 1. Contact Phone: 777-8389 Signature: ,_'°""� Date: (G INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 1 a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1b: Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 19: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10-407 Revised 5/2017 Submit ORIGINAL Only 9-7/8" hole 7-5/8" RKB to GL=18' hole } 5' PROFUSED SCHEMATIC 9 y Y 4 i' fia Y L.. '.. '• Sal PBTD = 5,710' MD / 3,614'= TVD TD = 5,745' MD / 3,643' = TVD' CASING DETAIL Ninilchik Unit Kalotsa #6 PTD: 219-114 API: 50-133-20685-00-00 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 1,654' 4-1/2" rod Csg 12.6 L-80 DWC/C HT 3.958" Surf 5,735' M t A t _Od S r S Ft SD JEWELRY DETAIL No. Depth ID I OD 1 Item 1 1 1.466' I 3.958" 1 6.1975" 1 Swell Parker PERFORATION DETAII Zone Sand Top gtm (MD) Top Amt SPF Date Status (MD) (TVD) (TV (TVD) Beluga 134 5,624 5,682' 3,541' 3,594 58 6 10/16/19 Open UM r� �Q v i nc. , k"J CtA"4� 01L - J/300 110-C) i S°t'u1, Updated by DH 11-05-19 n Well Name: NINU Kalotsa 6 Field: Ninilchik County/State: , Alaska t (LAT/LONG): evation (RKB): 18 API #: Spud Date: Job Name: 1914702D Kalotsa 6 Drilling Contractor HEC 169 AFE #: AFE 6: Hilcorp Energy Company Composite Report Activity Date I Ops Summary 9/17/2019 Load sub and pony walls on trucks and transported to Kalotsa Pad. Spot pony walls, spot cranes and set sub on pony walls, set carrier on sub, set derrick on carrier, cont set rig mats, set backyard modules, raise doghouse, raise pit roofs, string cords and hoses. Prep to raise derrick,;string drill line on draw -works, raised derrick and scoped up, hung torque tube. 9/18/2019 Continue rigging up rig, prep to scope derrick, Install catwalk and beaver slide spot gas buster and prep t/ raise, move camps/offices f/ CINGSA pad, spot on location and hook up Iines.;Pre spud meeting KGF.;Continue rigging up rig, running electrical lines, mud lines and hydraulic lines, scope derrick, hang torque tube, raise gas buster, hook up utube, P/U top drive and trolley install on torque tube, M/U blocks remove from cradle lay cradle down off load tracks and stage equipment around pad.;Continue hooking up rig components, Hang rig tongs and prep rig floor, set in 3 rd party shacks and wire in, stage surface riser in cellar.;Continue R/U Misc equipment, work on rig acceptance check list, prep to P/U OF, peak hauling water and spud mud f/ G&I, get DSA f/ Surface Riser. 9/19/2019 Continue Rigging up rig floor, check end play and throw in top drive bearings, Load pipe, strap and tally, handi berm installed berming around rig, total safety tested gas alarms around dg.;P/U DP stand back in derrick 34 stands, P/U HWDP 5 stands stand back in the derrick, install centrifuge feed pump and control panel w/ crane, run power and hook up mud Iines.;Continue P/U DP standing back in derrick, riser and Mud product on Iocation.;N/U riser and flow line hook up turn buckles.;Fill Lines and hole and check for leaks, test surface lines U 2000 psi.;R/U Floor bring BHA to racks and load, M/U BHA Bit and motor.;Clean out rathole U 116' Drill ahead to accommodate smart tools w/ 400 gpm 700 psi 50 rpm 3k tq. 9/20/2019 Pull out of the hole from 250' to motor racking back HWDP, Drain motor and break out bit, Bit arrived on location @ 09:00hrs.;M/U 9 7/8" Baker Kymera bit to 7" TerraForce Lobe 6.Ostg , P/U 6.75" directional BHA to TM collar.;Upload MWD tools, Shallow hole test MWD, P/U and load sources.;P/U and RIH with flex collars XO & 2 stands of HWDP from 1 10'to 240', Toolface was walking left thought it may be due to magnetic interference, Pull to TM Collar to inspect, Toolface walking due to top drive walking left while in neutral, Wash to btm from 240' to 250'@ 445gpm 800psi.;Slide form 250' to 267', Mad pass stand of HWDP, Rack back and replace with jars, Continue drilling ahead as per directional plan from 267'to 424' 540 gpm/1550psi, TO 3/41k RPM -60 WOB -2/1 Ok. P/U 22k ROT 22k S/0 22k.;Continue drilling ahead 9 7/8" surface hole from 424'to 858'540 gpm/1600psi, TO 3/4k RPM -60 WOB -2/10k (mad passing all slides).;Continue drilling ahead 9 7/8" surface hole from 858' to 1228'540 gpm/ 1475psi, TQ 3500k RPM -60 WOB -2/10k (mad passing all slides). Directional Plan 8.48' High 3.41' Left. 9/21/2019 Continue Drilling Ahead f/ 1228' U 1290'545 gpm 1600 psi 60 rpm 4.5k tq on 4k tq off 10k WOB 54k PUW 48k SOW 49k ROT.;Circulate hi vis sweep around, 100 % increase in cuttings 100 stks late 545 gpm 1650 psi 60 rpm 4k tq.;POOH on elevators f/ 1290'V 271' no hole issues hole took correct fill.;Service rig and top drive.;RIH it 271'tt 1290' no hole issues hole took correct displacement.;Continue Drilling ahead f/ 1290't/ 1660' as per DD/MWD 545 gpm 1850 psi 60 rpm 5200 tq on 4700 tq off, MW 9.0 ppg Max gas 145 units 5-10k WOB PUW 50k SOW 40k ROT 42k, ECD 9.9 ppg.;Circulate hi vis sweep around 545 gpm 1800 psi 60 rm 3800 tq sweep came back on time 75% increase in cuttings circulate until shakers cleaned up.;POOH on elevators it 1660'11 549'.;Stand back and UD BHA f/ 549't/1 13'.;Clear rig floor of clay and debris, PJSM W/Rig Crew & Sperry, Unload sources & download MWD.;Lay down remaining pieces of the BHA from 113' to surface, Break out bit and lay down, Kymera Grade Cones: 1 -1 -NO -A -E -1 -NO -TD PDC:1-1-NO-A-X-1-NO-TD KREVS:45.2, Total footage 1410' @ 166ff/hr.;Clear rig floor of tools and subs, PJSM W/Weatherford, Rig up Weatherford casing equipment.;Pick up landing joint and dummy run hanger.;P/U Shoe track, Check Floats and RIH W77 5/8" casing top filling of the fly and topping off every 5 joints to 1630' (no issues).;P/U & M/U hanger and swedge to top drive in preparation to circulate.;Break circulation @ 2.7bpm, 140psi, Stage pumps up to 5bpm, Condition mud for cement job while swapping out bails on top drive from drilling bails to casing bails, Stage Halliburton pump truck and bulk trucks on DS of catwalk, Rig up Halliburton cement equipment. 9/22/2019 Continue pumping cement as per detail 12 ppg lead 77.5 bbls, followed by 32.5 bbls 15.8 pog tail, drop top plug kick out plug w/ 5 bbls water, displace cement w/ y 64.5 bbls Spud mud, Plugs bumped 69.5 bbls into displacement calculated vol 72 bbls, FCP 550 Pressure up t/ 1150 f/ 5 min bleed off check.;floats held CIP lq1 0741 firs, Wash Up Cementers.;R/D Cementers, Flush riser and flow line to cuttings box, drain riser and suck out cellar.;Nipple down riser and N/U B Section of C^A wellhead test seals t/ 250/5000 psi f/ 10 min.;Spot in BOPE Cradle and crane, pull beaver slide out crane in stack transfer to bridge cranes, Nipple up stack on wellhead, time HCRs, install choke and kill lines, Hook up hydraulic fittings for koomey hoses.;Open ram cavity on BOP and install 4.5" solid body rams, Install �j UV ti�♦ flow box, bell nipple and flow line. Continue building KCL mud for next hole section.;Rack, tally, pick up and rack back 50 joints 4.5" CDS-40 drill pipe (25 stands) in the derrick.;Clean rig floor, Change out weight indicator and recalibrate hookload.;P/U 4.5" test joint and make up test plug, Run test joint in hole, Fill BOP and choke manifold with water, Purge air from system in preparation to test BOP with State witness Jeff Jones. 9/2312019 Test SOP's w/ 4.5" test jt to 250/3500 psi f/ 5 min each State inspector Jeff Jones Waived Witness, test CMV 1-13 Test upper lower and Blind rams, annular, TIW and Dart, Auto and man TIW, HCR and Man choke and kill, test kill line valve, Accumulator and draw down test, Total Safety test gas alarm.;R/D Test equipment pull test plug install wear ring R/U V test casing.;Test 7 5/8" Csaing V 3500 psi f/ 30 min good test.;R/D test equipment, blow down choke manifold and top drive suck out gas buster, prime mud pumps stage BHA subs and XO's.;P/U BHA as per DD/MWD scribe tools, shallow pulse test tools and Load sources.;Continue picking up remaining BHA components, Flex collars, jars and HWDP.;Trip in the hole with 4.5" drill pipe from 360' to 1479'.;Wash down from 1479' to 1569'staging up pumps to 260gpm, 260gpm 1470psi, Tag top of plugs @ 1569'.;Drill out shoe track @ 270gpm 1550psi 2-5kwob 30rpm from 1569'to 1654' Shoe depth @ 1654. Drill out 20' of new formation from 1660' to 1680'@ 270gpm 1550psi 2-5kwob 3-3.5ktrq 30rpm.;Circulate bottoms up and Pull up inside the shoe from 1680 to 1653', Line up to conduct FIT to 12.5ppg EMW, Purge air out of test lines, Close UPR, Pressure up down the backside and down the drill pipe to 230psi 12.5E.MWTotal gallons pumped 7.5. Total gallons bled back 7.;Circulate and condition KCL mud while cleaning spud mud out of pit 7 and 2 @ 2.8bpm staging up to 4bpm.;Screen down shaker 2 and 3 from 2x170 and 2x120 to 4x120 on all 3 shakers.;Circulate and condition KCL mud while cleaning spud mud out of pit 7 and 2 @ 4bpm staging up to 6bpm.;Drill ahead as per directional plan from 1680'to 1975' @ 275gpm 1180psi 3-6kwob TRQ-3400- / 4300ftlbs 40-60rpm P/U 39K S/O 28K ROT 34K. 1- 9/24/2019 Cont directional drilling 6 3/4" hole from 1975' to 2472'. Sliding wob 8K, 270gpm-1300 psi, 150 psi diff, 50 ft/hr ROP. Rot wob 5K, 272 gpm-1189 psi, 70 rpm -3700 flAbs on bolt torque, 145 f thr ROP, MW 9.1/vis 50, ECD's at 10.4 ppg, BGG 25 units. Mad passing slide intewals.;Cont drilling 6 3/4" hole from 2472' to 2655'. Rot wob 8K, 278 gpm-1337 psi, 70 rpm -0300 It/lbs on bott torque, 163 Nhr ROP. Sliding wob 9K, 278 gpm-1329 psi, 187 psi diff, 144 Whir ROP, MW 9.1/vis 49, ECD's at 10.2 ppg, BGG 15 units, max gas 248 units.;Pumped 20 bbl hi -vis nutplug sweep around with a 25% increase in cuttings. 273 gpm-1180 psi, 70 rpm - 4000 Nibs off bott torque. Sweep on time. Once shakers cleaned up obtained SPR's and survey.;Pulled up hole on elevators from 2655' to 1656' with no issue. Hole in good shape.;Serviced rig and topdrive.;TIH on elevators from 1656' to 2589' with no issue. MU last stand, filled pipe and washed to bottom.;Cont drilling 6 3/4" hole from 2655'to 3110'@ 271 -GPM 1350psi-SPP 70 -RPM 10.81ppg-ECD MW-9.15ppg VIS49.;Cont drilling 6 3/4" hole from 3110' to 3525' @ 271 -GPM 1450psi-SPP 70 -RPM 11 ppg-ECD MW-9.2ppg VIS -52. 9/25/2019 Cont directionally drilling 6 3/4" hole from 3525' to 3648'. Rot wob 3K, 273 gpm-1450 psi, 70 rpm -5600 ft/lbs on bolt torque, 100 ft/hr ROP, MW 9.2tvis 51, ECD's at 11.1 ppg, BGG 161 units. Obtained survey at 3648'.;Pumped a 20 bbl hi -vis nutplug sweep at 280 gpm-1383 psi, 70 rpm -5550 ftAbs off bott torque. Had 25% increase of cuttings to surface with sweep back on time. Cont circ until shakers cleaned up and obtained SPR's.;Pulled up hole on elevators from 3648' to 2656' with no issues. Up wt 60K. Hole in good shape.;Serviced rig and topdrive, greased crown sheaves.;TIH on elevators from 2656' to 3648', dwn wt 36K. Had a few spots starting into slide sections that took weight. We worked through those on elevators once or twice each, and built another sweep to pump once back to bottom. Washed last stand down and made connection.;Cont directional drilling from 3648'to 3709' once sweep cleared the bit. Sliding wob 5K, 276 gpm-1420 psi, 183 psi diff, 115 ftmr ROP. Rot wob 4K, 276 gpm-1450 psi, 65 rpm -5860 fl/lbs on bolt torque, 113 Nhr ROP, MW 9.2/vis 52, ECD's at 10.8 ppg, BGG 29 units, 50% increase cuttings w/sweep.;Cont directional drilling from 3709'to 4045'. Rot wob 5K, 274 gpm-1470 psi, 70 rpm -5840 ftAbs on bott torque, 115 ft1hr ROP. Sliding wob 6K, 274 gpm-1404 psi, 180 psi diff, 120 ft/hr ROP, MW 9.2/vis 49, ECD's at 10.5 ppg, BGG 17 units, max gas 349 units. Received second load 4 1/2" Iiner.;Cont directional drilling from 4045'to 4390' 276gpm, 1650psi-spp, 70rpm, 6500-7400ftibs-trq, MW 9.25NIS 60, 11.16ppg-ECD, background gas 34units.;Cont directional drilling from 4390'to 4702'@ 274gpm, 1600psi-spp, 70rpm, 7500-9300ff1bs-trq, MW 9.25NIS 55, 10.92ppg-ECD, Background gas 44units.;Pump 20bbl. hi-vis/nutplug sweep around with 50 % increase in cuttings back to surface.;Rack back 1 stand of 4.5" drill pipe and flow check well (static), POOH on elevators from 4702' to 4267' with no overpull or hole issues. 9/26/2019 Cont pulling wiper trip from 4267'to 3646' with no issue. Up wt at 4267' = 65K. S/O and parked string at 3707'.;Serviced rig and topdrive.;TIH on elevators, dwn wt 34K, from 3707'to 4636' with no issue. Filled pipe and washed last stand to bottom at 4702'. Made next connection.;Pumped a 20 bbl hi -vis nutplug sweep. Once that cleared the bit resumed drilling ahead from 4702' to 5002'. Rot wob 5K, 276 gpm-1723 psi, 60 rpm -8000 fVlbs on bott torque, 75 Nhr ROP, MW 9.3/vis 55, ECD's at 11.0 ppg, BGG 29 units, max gas 190 units. Sweep increased cuttings to 300% when back.;Cont drilling 6 3/4" hole from 5002'to 5380'. Sliding wob 5- 13K, 276 gpm-1704 psi, 258 psi diff, 40 Nhr ROP. Rol wob 7K, 277 gpm-1753 psi, 60 rpm -8300 ftAbs on bott torque, 70 to 100 ft/hr ROP, MW 9.3/vis 57, ECD's at 11.2 ppg, BGG 49 units, max gas 299 units. Pumped sweep at 5197', 50% increase;Cont drilling 6 3/4" hole from 5380' to 5709'@ 274 gpm-1780psi, 210 psi diff, 100 f 1hr ROP,60 rpm -8700 tilts on bott torque,/ 1.Oppg-ECD,9.3Nis 57 ;Cont drilling 6 3/4" hole from 5709'to 5745' TD @ 274 gpm-1570psi, 25-75 psi diff, 100 It/hr ROP, 11.0ppg-ECD,9.3/vis 57.;Pump 20bbl hi -vis sweep w/nutplug @ 275 -GPM 70 -RPM, 100% increase in cuttings at return to surlace.;Rack back 1 stand, Flow check (Static), Pull up the hole from 5745' to 1663' with no overpull or hole issues, P/U 98k S/O 40k with no pumps.;Circulate bottom up @ 260gpm 1087psi 0% increase in cuttings at btm up. 9/27/2019 With bit parked at 1729' cont CBU at 262 gpm-1089 psi, while servicing rig. No noticeable increase in cuttings to surface at bottoms up, shut down and serviced topdrive.;TIH from 1729'to 5695' on elevators. Had some drag between 2600' and 3600' as in previous wiper trip, but did no pumping or rotating to get through it. MU last stand, filled pipe and washed to bottom at 5745'.;Pumped a 20 bbl hi -vis nutplug sweep around at 275 gpm-1584 psi, 55 rpm -9500 fVlbs off bolt torque. MW 9.3/vis 56, ECD's dropped to 10.9 ppg, BGG 4 units. Flow check = static. Pumped inhibited dryjob while prepping rig floor for LD DP.;POOH from 5745' LD 4 1/2" DP. Using vac to clean pipe with wiper balls. Cleaning and doping threads, then installing thread protectors for pipe storage.;UD 4.5" HWDP, Jars , XO's, & Flex collars.;PJSM W/Halliburton MWD, DO & Rig crew on removing sources, Monitor well on trip tank while Removing -Unloading sources from directional BHA, Download MWD data from tools prior to laying tools down, Clean and clear rig floor while downloading data.;Kymera bit grade. PDC- 1-1 -WT-A-X-1-NO-TD. Roller Cone - 1-1-WT-A-E-I-NO-TD.;Run 6 stands of 4.5" drill pipe and 3 stands of 4.5" HWDP in the hole and pull out of the hole laying down, Clean rig floor.;Drain BOP, P/U wear bushing puller & pull wear bushing.;PJSM WANeatherford and rig crew, Rig Up Weatherford casing running equipment, Stage 4.5" shoe track on catwalk, Get centralizers to the rig floor.;Dummy run hanger, P/U shoe track and check floats (float opens and closes), Run in the hole with 4.5" liner to 1230'. 9/28/2019 Cont PU single in hole with 4 1/2" L-80 12.6# DWC/C casing from 1230'to 1645'. MU circ swedge and topdrive.;Just inside surface shoe, CBU at 166 gpm-105 psi. Up wt 29K, dwn wt 28K. Shut down and removed topdrive and circ swedge.;Cont PU single in hole from 1645'to 2861'. MU circ swedge and topdrive.;CBU at 173 gpm-134 psi. Up wt 34K, dwn wt 26K. Shut down and removed topdrive and circ swedge.;Cont PU single in hole from 2861' to 5668' Qnt 129) with no issues. MU circ swedge and topdrive. Installed 6 1/16" swell packer to sit at 1465' when string Ianded.;Circulate at 172 gpm-273 psi. RD Weatherford air slips and changed over to long bails on topdrive. Shut down pump, broke off topdrive and circ swedge.;lnstalled circ swedge in last jnt (#130) PU, MU topdrive and washed down to 5712'. Had to work string free prior to slack off, acts like differential sticking. MU circ swedge in landing joint, PU and MU same, washed down and landed hanger in wellhead. Had to work string loose again. Shoe at 5735'.;Up wt 65K, dwn wt 37K, circulated with hanger on seat4 bpm -297 psi, RD Weatherford tongs and Sperry cords and monitor from doghouse. Stage plug launcher on rig floor, staged chicksans and manifold on rig floor. Broke off topdrive and circ swedge. Loaded plugs in launcher, MU launcher on stump.;RU manifold and circ lines, resumed circulating at 5 bpm436 psi, MU hardline from pump truck, held PJSM with rig team and cementers.;Halliburton loaded lines with 5 bbls water and checked for leaks. Halliburton pressure tested lines at 840 low, 4960 high, good tests. Halliburton pumped 35 bbis 10.5 ppa Spacer at 4 b m-409 psi. followed by 126 bbls Q00 sx) 12 ma Class A lead cement at 5 bnm-200 ns followed by 17 8 hhiq 80 sx 15.3 ppQ Class A tail cement 'burton dropped top plug, then displaced with 6% KCL brine at 6 bpm -980 psi. Slowed pump to 2 bpm with 10 bbl to go. Did bump the plug at 85 bbls into displacement (calculated 86.7 bbls). Held 1800 psi (FCP of 928 psi) for 3 minutes, bled off and;floats held. Bled back .75 bbls to truck. Had 17 bbls of Spacer returns to surface and 0 bbls lead cement to surface. Added LCM to both lead and tail cement at 1/4 ppb. Mix water temp 73 deg. Pumped 25% excess on both lead and tail. Lost 7.1 bbls throughout the job. Did not reciprocate pipe due;to 10 %" OD of hanger in 11" BOP stack. CIP at 17:50, 9-28-19. RD and released Halliburton.;Drained BOP stack and flushed with water, pulled landing joint, MU packoff assembly, ran in and installed same. RILD's, installed BPV and released wellhead Rep.;Remove casing bails from top drive, Blow down top drive, bleeder line, and kill line, Clean and yt remove all pipe handling equipment from rig floor, Empty and top wash pit 6 and 7, Build corrosion inhibitor/cleaner pill in pit 6, Flush mud pumps, Kill line, Choke line, Choke manifold, Gas buster.;Flush all surface lines, Pop -offs, Bleeders, Top Drive and BOP with corrosion inhibitor/cleaner pill, Blow corrosion inhibitor/cleaner to pits to eliminate getting on the ground when rigging down Iines.;Bleed off accumulator unit, Open ram cavities and remove ram blocks from upper pipe rams, blind rams & lower pipe rams, Close ram cavities and con8nue nippling down BOP equipment, Remove flow line from flow box, Remove bell nipple and flow box.;lnstall Bridge crane beam in the substructure, Hook bridge cranes to BOP lift plate, Remove BOP from B -Section and trolley out from under substructure.;Tail wellhead into sub via winch and loader, Clean ring groove and grease neck seals, Install wellhead on B -section and torque bolts. 9/29/2019 Cont NU drvhole tree with wellhead Rep. Wellhead Rep tested void at 250 low f/5 min and 5000 high for 15 min, good test. Removed BPV. Cont cleaning pits.;RU test pump on tree top, pumped 45 gallons and tested 4 %" casing at 3500 psi for 30 min on chart, good test, bled back 45 gallons.;Blew down surface lines, cont cleaning pits, scrub upper derrick, pressure wash on floor, pull rig pumps apart for pickling, change oilflters on both rig pump engines, removed washpipe from topdrive, checked quill shaft end play, removed hyd fittings from BOP stack and plugged outlets, installed;shipping beams in cellar, shipped out three DP tubs, two trailers mud product, one trailer Baroid drum products, trailer of Weatherford equipment, vac out containment of mass amounts rain water, shipped Sperry directional tools. Both Canrig and Sperry shacks are rigged down ready to ship.;Cont pickling rig pumps, cont cleaning pits, cont cleaning derrick, Motorman and electrician working on EAM PM's, prepping to rig down, Rig Released 09-29-2019 gQ 23:59hrs.;Scmb and pressure wash mast, Disconnect koomey lines from sub, Disconnect jumper hoses between pits and pumps, clean out hopper rooms, suck out all centrifugal pumps and piping in the hopper rooms, Motorman and mechanic performing mist. PM as per EAM.;Remove saver sub and double ball valve from top drive, Pull rotary table cover and wash out rotary, Inspect pulsation dampener on MP #2, Rig up test equipment to test IA, Continue prepping rig for move to Peak yard. 9/30/2019 Cont cleaning throughout the rig, RU test pump on OA, topped off with 110 gallons water (was on vac when OA valve was opened) and attempted to test to 2500 psi. Pressure bled 120 psi every 10 minutes to 1620 psi and stabilized. Attempted test numerous times with same results. Notified Dri ing; ngineer an ecision made to hold off on OA test CBL 4 V Bled r/ until after of casing. off and RD test pump.;Cont cleaning in pump houses, pits, draw -works. Changed oil in topdrive, e broke down iron roughneck for internal cleaning. Shipped out 400 bbl upright tank, shipped assorted rig equipment.;RU Pollard e -line at noon and RIH with CBL % tool down to 1460', then had to fight to get to 1540'. Pollard called out more roller boggies and cont trying to get deeper. loaded and shipped available rig mats, loaded and shipped Sperry shack and tool locker, Swam Rep installed shipping blocks in;centrifuge, Total Safety RD all gas detection equipment, loaded and shipped out screen connex, drilling cennex and Baker bits. Pollard could not get any deeper than 1588'. performed CBL to surface from there RD and released e - fcradle line. Prepped to RD topdrive.;Remove bails from top drive, Unpin top drive from torque bushing and remove torque bushing from the floor, Pick up top drive and chain to the derrick to Pin top drive in the stabilize, cradle, Unpin blocks from top drive and hook up lay down lines, Rig down top drive HPU;Lay down top drive onto the catwalk, Remove die blocks from the Iron roughneck and repair, Rig down and lower vacuum degasser into tank 4, Rig down centrifuge panel and feed pump, Rig down hurricane Peak vac system, Stage all 3" hose on a 40' fl mat in preparation to be shipped to peak,;Remove lights from derrick to be converted to LED, Bridle up derrick in preparation to scope down derrick, Continue cleaning mezzanine deck and sub structure. 10/1/2019 Removed torque tube "T" bar, cont molly misting and wrapping piping connections in pump rooms, shipped Canrig and Baroid labs, shipped gen 3 skid and Peak vac unit. Shipped Swam centrifuge, feed pump and control panel. Shipped topdrive and bulk fuel tank. Folded over beaver slide, transitioned BOP;stack from bridge cranes to crane and set same in cradle. Folded beaver slide back over to rig floor.;Cleaned poorboy degasser skid, layed over vessel and removed vent line from vessel. RD Pason gas trap. Shipped new and used oil drums. Unplugged upper derrick cords and prep to scope derrick down. Held PJSM, removed lower torque tube section, scoped down derrick. Spooled up electric cords for pil;secbons, removed lights from roof tops and folded over roof panels. Lowered all three pit roof tops, hung off blocks in derrick, spooled drill line off drum, coiled up and hung off in derrick.;Prep to lay derrick over, hung Kelley hose & service loop in derrick, removed brake linkage & drive shaft, unplugged connection from dog house to sub, laid over derrick, removed lights on top of modules being used, pulled the three remaining lights form the derrick & converted them to led fixtufes,;R/D rig HPU, blew down water lines, R/D water jumper hoses, R/D boiler house, hooked up short water loop to cont. pressure washing around rig while vacuuming out containment, cleaned up cellar, conductor, tree, and vacuumed out cellar.;Held PTSM, crew change, R/D HYD service loop from derrick to sub, cont. pressure wash rig, prepped dog house to be lowered, vacuumed out water tank, R/D grasshopper from mud pump skid, prepped tool room for move, broke down Handy -berm around rig, scoped in dog house & lower into rig tank,;cont. cleaning up around rig & prepping rig for move to Peak yard at 07:00 hrs. Plan is to break tower with rig crews at 06:00 hrs and work day light towers only. 10/2/2019 Finished vac up of rainwater from cuttings box, containment and cellar box. Peak on location at 07:00 and held PJSM. Tore out catwalk and staged for loading, tore out doghouse, gen 1-2 skid, boiler, degasser skid and pump skids, tore out HPU skid and three pit modules. Loaded and shipped both pumps,;degasser skid, gen 1-2 skid and pit module #3.;Spotted crane, picked iron roughneck off rig floor, lowered derrick board wind walls, R/U crane to derrick and picked derrick off carrier, loaded boiler, pits 20, picked drill line spool & set w/ derrick,;folded up out riggers on rig floor, secured handrails , picked carrier off sub, shipped boiler, pits 2 & 3, & derrick, picked sub off pony wall & Ioaded.;Loaded rig water tank/dog house, removed pony subs of matting boards, shipped sub, water tank/dog house, loaded remainder of rig mats onto trailers along w/ pony subs & shipped, cleaned & PIU liner/felt, back bladed pad from cellar box out,;Loaded & hauled off first on two cranes, loaded remainder of mist. tools & equip. onto trailers. Second rig crew went to Peaks yard to lay felt/liner, unable to lay felt/liner due to location being graded, rig crew worked on additional house keeping on rig while at Peaks yard.;Laid down both rig crews by 18:00 hrs. Last report for Kalotsa 6;Had Peak night crew cont. to haul off trailers through out the night of rig mats & mist. equip. along w/ general house keeping around the pad. Peak trucks will be on location at 10:00 hrs. to haul off company man, tool pusher, & break shack trailers. Well Name: NINU Kalotsa 6 Field: Ninilchik County/State: , Alaska i (LAT/LONG): evation (RKB): API #: Hilcorp Energy Company Composite Report Spud Date: Job Name: 1914702C Kalotsa 6 Completion Contractor AFE #: 1914702C AFE $: Activity Date Ops Summary 10/8/2019 PTW, JSA.,MIRU SLB CTU 13 with 1.75" CT x.1 56 wall.,24 BOPE test witness notification sent 10/7/19 @ 0917 AM. Bob Noble responded via phone call. Start BOPE test. Test all rams and valves 250/4000 psi. Perform draw down test. BOPE test complete., 10/9/2019 PTW, JSA,Pick injector head. Makeup 20' lubricator. MU external slip coil connector. 2.26" OD x .84' Pull test 25K. 2.13" OD x 1.16' DFCV, 2.15" OD x 4.4' Bi Di jars, 2.13" OD x 1.57' hyd disco (5/81) ball, 2.13" OD x 1.14' circ sub, PT MHA to 3500 psi. Makeup 2.13" OD x 10.5' motor, 2.88" OD x .3' x over, 3.83"OD x 1.81' string mill, 3.83" OD x.96'5 bladed junk mill. Stab on well. Confirm motor spinning.,PT stack 250/3500 psi. T/IA both zero. RIH. 65 fill pumping at 1.2 bbls/min. Perform weight checks as needed. Tao PBTD at 5680' CTMD. Corrected to RBK puts CT at 5688' RKB. This is right where the bottom pert needs to be shot. Called town to discuss. nirpntad to min 2n' rat hole Stan milling. Free spin 2300 psi at 1.3 bbls/min. 5690' stall, Multiple stalls at 5690'. Milling float collar from 5690'to 5691.7'. Continue to mill cement to 5710'. Trip OOH pumping and cleaning tubing. Pump bottoms up.,Tdp OOH pumping and cleaning tubing. Pump bottoms up. 1630 tagged up at surface. Close master and swab. Pop off well and inspect mill and string reamer. Rig down MHA. Rig down injector head. Install night rap on well. 10/10/2019 PTW, JSA with SLB, Cruz, Halliburton, and Hilcorp. Mobs to location. Well is a cased 4.5" mono bore loaded with 6% KCL. No perfs.,Pick injector head with " 30' of lubricator. 2.125" CC, 2.125" DFCV, 2.125" hyd disco, 2.125" gutted circulation sub. 2.125" x over to 5/8" sucker rod, 2x 2.0" sucker rod knuckle joints, 1.69" OD x 1.32' battery, 1.69" OD x 1.03' Uitrawire Memory tool, 1.69" OD x 1.92' Gamma Ray, 1.69" x 1.56' CCL, 1.69" OD x 2.77' roller centralizer, 1.69" x 9.93' bond tool, 1.69" OD x 2.77' centralizer, 1.69" OD x .22' bullnose.,Wait for memory delay to activate. 15 minute delay. Confirm tool is "clicking". Zero tool string at bottom of lubricator. Stab on well. Correct to RBK depth by adding +8', PT stack 250/4000 psi. Bleed down. Open swab 23.5 turns. T/IA 0 psi. RIH.,RIH at 85 ff/min. Park at 1003.992' CT depth. Memory acquisition 1004.37'. Both depth transmitters tracking. Continue in hole 85 f lmin. Slow down and park at 5700' RKB. Both transmitters on depth. Pick up to 5670' and paint flag. (flag painted for depth correlation in the event CT is used for TCP perforating). RIH to 5700'. Wait 5 minutes to show delay on log prior to Iogging.,Log OOH at 50 ft/min to surface. Tagged up at pack off assembly. Close swab. Pop off well. Break down memory tools. Halliburton confirming data. Rin up test pump to IA and fluid pack in prep for MIT -Pressure test 7 5/8" x 4 'V IQ" Mh no to 25nn ns for a0 minutes and chart Gmr! test Remove DFCV from MHA. Install x over and 2.25" ball drop/reverse nozzle. Stab on well. �e Halliburton confirmed data is complete.,PT stack 250/4000 psi. RIH cooling down N2 pump (2100 gal on board). Online with N2 down 4.5" production casing taking returns up 1.75" CT. 1000 scf/min. Park CT at 5700' 114 bbls returned to surface before N2 hit. 2300 psi WHP before breakover.,POOH from 17 5700'. Shut down N2 at 4000' RKB. Work choke while POOH . Tagged up at surface. Close master and swab valve. 1310 psi N2 SITP. 800 gallons of N2 left. 1300 gallons pumped or 121,056 SCF.,Rig down SLB CTU 13. Move equipment to edge of pad to make room for construction crew arriving in AM to fabricate and assemble flow lines., 10/15/2019 PTW and JSA. SCADA stuff was finishing up . Rig up as much as we can. Cut 50' of wire off and re -headed. SCADA got done. Rig up lubricator, PT 250 psi low and 3500 psi high. TP - 1302 psL,RIH w/2-7/8" x 25' HC Razor, 6 spf. 60 deg phase pert gun with 3 roller bogies in the tool string. Tools set down at 1604' finally got tools to 1736' using different speeds and depths. It is 78 deo incl. at that depth. Tried a lot of different things but could not get past the high angles in the well. Called town and discussed. Will get Weltec tractor people out here and they will test their tractor for the pert job in,the morning. POOH and had what looked like was slurry of pipe dope, wireline grease and water mixture. It wasn't a real heavy mixture more like it was that laying on the low side of the well. It didn't help any but I don't believe that was the cause of not getting down.,Finishing rig down and get ready to check WELTEC tractor out on wireline. WEWLTEC on location so checking tools out. Will be back at 0700 firs in the morning to perf. 10/16/2019 PTW, JSA and SIMOPS with AKE-Line and Welltec tractor hands. Rig up lubricator and go thru Welltec perforating checklist. Pressure test lubricator to 250 psi low and 3500 psi high. TP - 1000 psi,RIH w/Welltec tractor, 2-7/8"x20' HC Razor, 6 spf, 60 deg perf gun to 1512' (71-76 Deg angle). Turn tractor on and tractor (� tools to 3159. Turn tractor off and RIH to tag depth at 5702' correlated to OHL. Run correlation log and send to town. Got ok to cert from 5662' to 5682'. Bled well n down to 501 psi. Spotted and fired gun with 501 psi on tubing.. Lost approx. 400 Ib of line tension. After 5 min - 509 psi,, 10 min - 515 psi and 15 min - 523 psi. psi POOH. All shots fired and gun was dry.,Replace oil in tractor and go over Welltec perforating check. RIH wM/elltec tractor, 2-7/8'X20' HC Razor, 6 spf, 60 deg erf gun to 1586' (71-76 Deg angle). Tum tractor on and tractor tools to 3203'. Tum tractor off and RIH to tag depth at 5702' correlated to OHL. Run correlation og and send to town.. Said we were 2' high on our log so pert from 5642' to 5662'. Bled TP down to 601 psi, spotted and fired gun. Lost 400,lbs line tension. After [[ ,� 5 min - 6-19 psi, 10 min - 628 psi and 15 min - 637 psi. POOH all shots fired and gun was dry.,Replace oil in tractor and go over Welitec perforating check. RIH Y\ w/Welltec tractor, 2-7/8"x20' HC Razor, 6 spf, 60 deg pert gun to 1543' (71-76 Deg angle). Turn tractor on and tractor tools to 3200'. Turn tractor off and RIH to tag depth at 5702' correlated to OHL. Run correlation log and send to town.. Adjusted oerf death from 5624' to 5644' Bled well down to 624.7 psi. Spotted and fired gun. After 5 min - 635 psi;,10 min - 652 psi and 15 min - 660.4 psi. POOH. All shots fired and gun was dry.,Rig down lubricator, tractor, e4ine tools. Will let well build up pressure overnight. Hilcorp Alaska, LLC Ninilchik Unit Kalotsa Kalotsa 6 501332068500 Sperry Drilling Definitive Survey Report 27 September, 2019 HALLIBURTON Sperry Drilling Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well Kalotsa 6 Project: Ninilchik Unit TVD Reference: As -Built @ 144.40usft (HEC 169) Site: Kalotsa MD Reference: As -Built @ 144.40usft (HEC 169) Well: Kalotsa 6 North Reference: True Wellbore: Kalotsa 6 Survey Calculation Method: Minimum Curvature Design: Kalotsa 6 Database: NORTH US + CANADA Project Ninilchik Unit Nap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Seo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Nap Zone: Alaska Zone 04 Using geodetic scale factor Well Kalotsa 6 Well Position +NIS +E/ -W Position Uncertainty Wellbore Kalotsa 6 Magnetics Model Name Design Audit Notes: Version: Vertical Section: 0.00 usft Northing: 2,233,430.6720 usfl 0.00 usft Easting: 209,833.9930 usfl 0.50 usft Wellhead Elevation: usfl Sample Date Declination (0) BGGM2018 8113/2019 Kalotsa 6 15.08 Latitude: 60° 6'14.4328 N Longitude: 151 ° 35'24.6810 W Ground Level: 126.40usft Dip Angle (1) 73.05 Field Strength (nT) 55,009.18717818 1.0 Phase: ACTUAL Tie On Depth: 18.00 Depth From (TVD) +N/ -S +E/ -W Direction (usft) (usft) (usft) (') 18.00 0.00 0.00 325.02 Survey Program Date 9/27/2019 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 198.91 1,623.21 MWD+IFRI+MS+Sag(1)(Kalotsa 6) 3_MWD+IFRI+MS+Sag A010Mb: IFR dec&multi-station analysis +sac 09/18/2019 1,690.94 5,708.77 MWD+IFRI+MS+Sag (2) (Kalotsa 6) 3_MWD+IFRI+MS+Sag A010Mb: IFR dec & multi -station analysis +sac 09/24/2019 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (0) (1 (usft) (usft) (usft) (usft) (ft) (ft) (1/1001) (ft) Survey Tool Name 18.00 0.00 0.00 18.00 -126.40 0.00 0.00 2,233,430.67 209,833.99 0.00 0.00 UNDEFINED 198.91 0.45 215.15 198.91 54.51 -0.58 -0.41 2,233,430.10 209,833.57 0.25 -0.24 3_MWD+IFR1+MS+Sag(1) 265.03 2.07 310.03 265.01 120.61 -0.03 -1.47 2,233,430.68 209,832.52 3.26 0.82 3_MWD+IFRI+MS+Sag(1) 325.97 5.34 316.38 325.82 181.42 2.74 4.27 2,233,433.51 209,829.79 5.40 4.69 3_MWD+IFRI+MS+Sag (1) 386.51 7.73 318.43 385.96 241.56 7.82 -8.92 2,233,438.71 209,825.27 3.97 11.52 3_MWD+IFRI+MS+Sag(1) 447.24 9.82 319.33 445.98 301.58 14.81 -15.00 2,233,445.84 209,819.35 3.45 20.73 3_MWD+IFR1+MS+Sag(1) 508.80 12.70 316.61 506.35 361.95 23.71 -23.08 2,233,454.93 209,811.49 4.76 32.65 3_MWD+IFRI+MS+Sag(1) 571.85 16.27 313.13 567.38 422.98 34.79 -34.29 2,233,466.27 209,800.55 5.83 48.16 3_MWD+IFRI+MS+Sag(1) 635.07 19.96 312.37 627.46 483.06 48.12 -48.73 2,233,479.95 209,786.44 5.85 67.36 3 MWD+IFRI+MS+Sag(1) 696.38 23.40 311.89 684.42 540.02 63.30 -65.53 2,233,495.53 209,770.01 5.62 89.43 3_MWD+IFRI+MS+Sag(1) 758.85 27.48 313.25 740.82 596.42 81.47 -85.27 2,233,514.17 209,750.71 6.60 115.64 3_MWD+IFR1+MS+Sag(1) 820.36 31.04 313.82 794.48 650.08 102.18 -107.05 2,233,535.40 209,729.43 5.81 145.09 3 MWD+IFRI+MS+Sag(1) 881.21 34.42 314.52 845.66 701.26 125.11 -130.64 2,233,558.89 209,706.40 5.59 177.40 3_MWD+IFRI+MS+Sag(1) 927/2019 2:25:33PM Page 2 COMPASS 5000.15 Build 91 Company: Hilcorp Alaska, LLC Project: Ninilchik Unit Site: Kalotsa Well: Kalotsa 6 Wellbore: Kalotsa 6 Design: Kalotsa 6 Survey Halliburton Definitive Survey Report Local Coordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Map MD Inc Azi TVD TVDSS +NIS +EI -W Northing (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) 944.46 36.37 313.76 897.22 752.82 150.62 -156.93 2,233,585.02 1,005.74 39.87 314.30 945.42 801.02 176.91 -184.12 2,233,611.96 1,068.11 43.40 314.75 992.03 847.63 205.96 -213.66 2,233,641.72 1,129.13 47.85 315.38 1,034.69 890.29 236.84 -244.45 2,233,673.32 1,191.71 51.22 316.15 1,075.30 930.90 270.95 -277.65 2,233,708.22 1,252.95 54.40 316.15 1,112.31 967.91 306.13 -311.44 2,233,744.20 1,315.11 60.47 316.32 1,145.75 1,001.35 343.95 -347.66 2,233,782.88 1,377.41 64.03 316.32 1,174.76 1,030.36 383.81 -385.73 2,233,823.65 1,438.66 68.48 315.66 1,199.41 1,055.01 424.12 424.68 2,233,864.89 1,501.51 71.52 315.47 1,220.91 1,076.51 466.29 466.02 2,233,908.04 1,562.87 76.05 315.78 1,238.04 1,093.64 508.39 -507.22 2,233,951.12 1,623.21 78.56 315.93 1,251.30 1,106.90 550.63 -548.21 2,233,994.33 1,690.94 78.44 314.58 1,264.80 1,120.40 597.77 -594.93 2,234,042.58 1,753.89 78.95 313.98 1,277.14 1,132.74 640.86 -639.13 2,234,086.73 1,815.62 79.51 313.07 1,288.68 1,144.28 682.63 -683.10 2,234,129.53 1,877.16 78.32 314.52 1,300.51 1,156.11 724.42 -726.69 2,234,172.36 1,939.78 78.63 314.58 1,313.02 1,168.62 767.46 -770.41 2,234,216.45 2,001.79 78.57 313.98 1,325.28 1,180.88 809.90 -813.93 2,234,259.92 2,063.33 80.26 314.90 1,336.58 1,192.18 852.26 -857.12 2,234,303.30 2,125.12 80.57 314.45 1,346.87 1,202.47 895.09 -900.45 2,234,347.17 2,187.04 80.70 314.19 1,356.95 1,212.55 937.78 -944.16 2,234,390.89 2,248.74 80.88 313.66 1,366.82 1,222.42 980.03 -988.02 2,234,434.18 2,310.97 81.14 313.42 1,376.55 1,232.15 1,022.37 -1,032.58 2,234,477.59 2,373.05 79.63 314.42 1,386.91 1,242.51 1,064.82 -1,076.67 2,234,521.09 2,434.55 79.33 313.63 1,398.14 1,253.74 1,106.85 -1,120.14 2,234,564.14 2,496.15 78.56 315.97 1,409.96 1,265.56 1,149.44 -1,163.04 2,234,607.76 2,557.31 77.87 318.79 1,422.45 1,278.05 1,193.49 -1,203.58 2,234,652.77 2,619.14 77.82 321.30 1,435.47 1,291.07 1,239.82 -1,242.39 2,234,700.02 2,680.96 76.99 323.67 1,448.95 1,304.55 1,287.67 -1,279.13 2,234,748.74 2,743.62 75.59 325.04 1,463.80 1,319.40 1,337.14 -1,314.60 2,234,799.04 2,805.28 73.41 325.60 1,480.28 1,335.88 1,385.99 -1,348.41 2,234,848.70 2,868.02 70.94 325.86 1,499.49 1,355.09 1,435.35 -1,382.04 2,234,898.85 2,929.58 67.97 325.73 1,521.09 1,376.69 1,483.02 -1,414.44 2,234,947.29 2,992.24 65.51 326.70 1,545.83 1,401.43 1,530.86 -1,446.45 2,234,995.88 3,053.12 64.26 328.30 1,571.67 1,427.27 1,577.34 -1,476.07 2,235,043.07 3,116.49 62.55 328.85 1,600.04 1,455.64 1,625.69 -1,505.62 2,235,092.11 3,177.98 62.06 329.48 1,628.62 1,484.22 1,672.44 -1,533.53 2,235,139.52 3,239.44 60.14 328.82 1,658.32 1,513.92 1,718.63 -1,561.11 2,235,186.36 3,302.42 58.25 329.20 1,690.57 1,546.17 1,765.00 -1,588.97 2,235,233.39 3,364.48 56.50 328.68 1,724.03 1,579.63 1,809.78 -1,615.93 2,235,278.80 Well Kalotsa 6 As -Built @ 144.40usft (HEC 169) As -Built @ 144.40usft (HEC 169) True Minimum Curvature NORTH US + CANADA Map Vertical Easting DLS Section (ft) (°11001) (ft) Survey Tool Name 209,680.73 3.16 213.38 3_MWD+IFRI+MS+Sag(1) 209,654.18 5.74 250.51 3_MWD+IFRI+MS+Sag(1) 209,625.35 5.68 291.25 3_MWD+IFRI+MS+Sag(1) 209,595.31 7.33 334.19 3_MWD+IFRI+MS+Sag(1) 209,562.94 5.47 381.18 3 MWD+IFRI+MS+Sag(1) 209,530.01 5.19 429.38 3_MWD+IFRI+MS+Sag(1) 209,494.71 9.77 481.12 3_MWD+IFRI+MS+Sag(1) 209,457.61 5.71 535.62 3_MWD+IFRI+MS+Sag(1) 209,419.64 7.33 590.97 3_MWD+IFRI+MS+Sag(1) 209,379.32 4.85 649.22 3_MWD+IFRI+MS+Sag(1) 209,339.16 7.40 707.34 3_MWD+IFRI+MS+Sag(1) 209,299.19 4.17 765.44 3_MWD+IFRI+MS+Sag(1) 209,253.62 1.96 830.85 3_MWD+IFRI+MS+Sag (2) 209,210.47 1.24 891.50 3_MWD+IFRI+MS+Sag (2) 209,167.52 1.71 950.92 3_MWD+IFRI+MS+Sag(2) 209,124.95 3.01 1,010.16 3 MWD+IFRI+MS+Sag (2) 209,082.27 0.50 1,070.49 3_MWD+IFRI+MS+Sag (2) 209,039.79 0.95 1,130.21 3_MWD+IFRI+MS+Sag (2) 208,997.63 3.11 1,189.68 3_MWD+IFRI+MS+Sag(2) 208,955.35 0.88 1,249.61 3_MWD+IFRI+MS+Sag (2) 208,912.68 0.46 1,309.65 3_MWD+IFRI+MS+Sag (2) 208,869.84 0.90 1,369.41 3_MWD+IFRI+MS+Sag(2) 208,826.32 0.57 1,429.65 3_MWD+IFRI+MS+Sag(2) 208,783.26 2.90 1,489.71 3_MWD+IFRI+MS+Sag (2) 208,740.81 1.35 1,549.06 3_MWD+IFRI+MS+Sag(2) 208,698.95 3.93 1,608.56 3_MWD+IFRI+MS+Sag (2) 208,659.49 4.65 1,667.89 3_MWD+IFRI+MS+Sag(2) 208,621.80 3.97 1,728.10 3_MWD+IFRI+MS+Sag(2) 208,586.22 3.98 1,788.37 3_MWD+IFRI+MS+Sag(2) 208,551.95 3.08 1,849.23 3_MWD+IFRI+MS+Sag (2) 208,519.33 3.64 1,908.65 3_MWD+IFRI+MS+Sag(2) 208,486.89 3.96 1,968.37 3_MWD+IFRI+MS+Sag(2) 208,455.65 4.83 2,026.00 3_MWD+IFRI+MS+Sag(2) 208,424.80 4.18 2,083.55 3_MWD+IFRI+MS+Sag (2) 208,396.30 3.14 2,138.62 3_MWD+IFRI+MS+Sag (2) 208,367.93 2.81 2,195.17 3 MWD+IFRI+MS+Sag(2) 208,341.16 1.21 2,249.47 3_MWD+IFRI+MS+Sag(2) 208,314.69 3.26 2,303.14 3_MWD+IFRI+MS+Sag (2) 208,287.96 3.05 2,357.10 3_MWD+IFRI+MS+Sag(2) 208,262.08 2.91 2,409.24 3_MWD+IFRI+MS+Sag(2) 9/272019 2:25:33PM Page 3 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Project: Ninilchik Unit Site: Kalotsa Well: Kalotsa 6 Wellbore: Kalotsa 6 Design: Kalotsa 6 Survey MD Inc Azi TVD TVDSS +N/.S (usft) r) (1) (usft) (usft) (usft) 3,426.15 55.10 328.71 1,758.69 1,614.29 1,853.35 3,487.79 53.64 328.43 1,794.60 1,650.20 1,896.10 3,549.12 52.49 330.16 1,831.45 1,687.05 1,938.25 3,611.48 51.41 331.53 1,869.89 1,725.49 1,981.13 3,673.61 48.78 332.26 1,909.74 1,765.34 2,023.16 3,735.61 46.81 333.47 1,951.39 1,806.99 2,064.03 3,797.15 44.84 333.63 1,994.28 1,849.88 2,103.54 3,859.39 42.08 334.11 2,039.45 1,895.05 2,141.97 3,921.75 39.65 334.47 2,086.61 1,942.21 2,178.73 3,983.01 38.11 335.69 2,134.29 1,989.89 2,213.60 4,045.32 36.37 335.96 2,183.90 2,039.50 2,247.99 4,107.00 34.47 336.41 2,234.16 2,089.76 2,280.69 4,169.75 33.03 337.75 2,286.33 2,141.93 2,312.80 4,232.46 32.72 340.66 2,339.00 2,194.60 2,344.61 4,293.83 33.44 339.98 2,390.43 2,246.03 2,376.15 4,356.69 31.31 339.46 2,443.51 2,299.11 2,407.72 4,418.76 29.40 337.91 2,497.07 2,352.67 2,436.94 4,480.60 29.29 336.64 2,550.98 2,406.58 2,464.90 4,542.04 29.86 336.03 2,604.41 2,460.01 2,492.67 4,603.69 29.53 338.32 2,657.97 2,513.57 2,520.81 4,665.69 29.69 337.48 2,711.87 2,567.47 2,549.19 4,727.12 30.47 336.38 2,765.03 2,620.63 2,577.52 4,789.55 29.37 338.56 2,819.14 2,674.74 2,606.27 4,851.09 29.58 338.35 2,872.71 2,728.31 2,634.44 4,914.17 30.09 337.23 2,927.43 2,783.03 2,663.49 4,977.22 30.56 335.61 2,981.86 2,837.46 2,692.66 5,038.62 29.14 337.59 3,035.11 2,890.71 2,720.70 5,100.26 29.23 336.64 3,088.93 2,944.53 2,748.39 5,161.51 29.30 335.07 3,142.36 2,997.96 2,776.71 5,223.40 29.45 333.53 3,196.29 3,051.89 2,803.06 5,285.16 29.93 331.64 3,249.95 3,105.55 2,830.21 5,347.82 30.31 330.18 3,304.15 3,159.75 2,857.69 5,409.62 30.61 328.53 3,357.42 3,213.02 2,884.64 5,472.39 30.64 325.85 3,411.44 3,267.04 2,911.51 5,533.83 31.14 323.73 3,464.16 3,319.76 2,937.27 5,595.37 31.57 322.13 3,516.72 3,372.32 2,962.82 5,657.62 32.10 320.35 3,569.60 3,425.20 2,988.42 5,708.77 32.46 319.26 3,612.85 3,468.45 3,009.28 5,745.00 32.46 319.26 3,643.42 3,499.02 3,024.02 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well Kalotsa 6 As -Built @ 144.40usft (HEC 169) As -Built @ 144.40usft (HEC 169) True Minimum Curvature NORTH US + CANADA 9272019 2:25.33PM Page 4 COMPASS 5000.15 Build 91 Map Map Vertical +E/ -W Northing Easting DLS Section (usft) (ft) (ft) (°17oo,) (ft) Survey Tool Name -1,642.43 2,235,323.00 208,236.64 2.27 2,460.14 3 MWD+IFR1+MS+Sag(2) -1,668.55 2,235,366.37 208,211.55 2.40 2,510.14 3_MWD+IFR1+MS+Sag(2) -1,693.59 2,235,409.10 208,187.54 2.93 2,559.03 3_MWD+IFRI+MS+Sag (2) -1,717.52 2,235,452.54 208,164.65 2.45 2,607.88 3_MWD+IFRI+MS+Sag (2) -1,739.97 2,235,495.10 208,143.21 4.33 2,655.19 3_MWD+IFR1+MS+Sag(2) -1,760.92 2,235,536.46 208,123.25 3.49 2,700.68 3_MWD+IFRI+MS+Sag (2) -1,780.58 2,235,576.44 208,104.55 3.21 2,744.33 3_MWD+IFRI+MS+Sag (2) -1,799.44 2,235,615.31 208,086.62 4.47 2,786.63 3_MWD+IFRI+MS+Sag(2) -1,817.14 2,235,652.48 208,069.81 3.91 2,826.89 3_MWD+IFRI+MS+Sag (2) -1,833.35 2,235,687.73 208,054.45 2.81 2,864.75 3 MWD+IFRI+MS+Sag (2) -1,848.79 2,235,722.49 208,039.83 2.80 2,901.79 3_MWD+IFRI+MS+Sag (2) -1,863.23 2,235,755.53 208,026.19 3.11 2,936.86 3_MWD+IFRI+MS+Sag(2) -1,876.81 2,235,787.95 208,013.38 2.58 2,970.95 3_MWD+IFRI+MS+Sag (2) -1,888.89 2,235,820.04 208,002.07 2.57 3,003.95 3_MWD+IFRI+MS+Sag (2) -1,900.18 2,235,851.84 207,991.55 1.32 3,036.26 3_MWD+IFRI+MS+Sag (2) -1,911.84 2,235,883.69 207,980.65 3.42 3,068.81 3 MWD+IFRI+MS+Sag (2) -1,923.23 2,235,913.17 207,969.97 3.33 3,099.28 3_MWD+IFRI+MS+Sag (2) -1,934.93 2,235,941.40 207,958.94 1.02 3,128.90 3_MWD+IFRI+MS+Sag (2) -1,947.11 2,235,969.46 207,947.43 1.05 3,158.63 3_MWD+IFRI+MS+Sag(2) -1,958.95 2,235,997.88 207,936.27 1.92 3,188.48 3_MWD+IFRI+MS+Sag (2) -1,970.48 2,236,026.53 207,925.43 0.72 3,218.35 3_MWD+IFRI+MS+Sag (2) -1,982.55 2,236,055.14 207,914.04 1.55 3,248.47 3_MWD+IFRI+MS+Sag (2) -1,994.49 2,236,084.17 207,902.80 2.48 3,278.88 3_MWD+IFRI+MS+Sag (2) -2,005.61 2,236,112.59 207,892.36 0.38 3,308.33 3_MWD+IFRI+MS+Sag (2) -2,017.47 2,236,141.92 207,881.20 1.20 3,338.93 3_MWD+IFRI+MS+Sag (2) -2,030.21 2,236,171.39 207,869.17 1.50 3,370.14 3_MWD+IFR1+MS+Sag(2) -2,042.35 2,236,199.71 207,857.70 2.81 3,400.07 3_MWD+IFRI+MS+Sag(2) -2,054.04 2,236,227.68 207,846.68 0.77 3,429.46 3_MWD+IFRI+MS+Sag (2) -2,066.29 2,236,255.28 207,835.10 1.26 3,458.87 3_MWD+IFRI+MS+Sag (2) -2,079.45 2,236,282.95 207,822.59 1.24 3,488.83 3_MWD+IFRI+MS+Sag (2) -2,093.54 2,236,310.43 207,809.16 1.70 3,519.15 3_MWD+IFRI+MS+Sag(2) -2,108.83 2,236,338.26 207,794.54 1.32 3,550.42 3_MWD+IFRI+MS+Sag(2) -2,124.80 2,236,365.59 207,779.23 1.44 3,581.66 3_MWD+IFR1+MS+Sag(2) -2,142.12 2,236,392.86 207,762.55 2.18 3,613.61 3_MWD+IFRI+MS+Sag(2) -2,160.31 2,236,419.06 207,744.99 1.95 3,645.14 3_MWD+IFRI+MS+Sag(2) -2,179.61 2,236,445.06 207,726.31 1.52 3,677.14 3 MWD+IFRI+MS+Sag(2) -2,200.17 2,236,471.15 207,706.37 1.73 3,709.90 3_MWD+IFR1+MS+Sag(2) -2,217.80 2,236,492.43 207,689.25 1.34 3,737.11 3_MWD+IFR1+MS+Sag(2) -2,230.49 2,236,507.47 207,676.92 0.00 3,756.45 PROJECTED to TO 9272019 2:25.33PM Page 4 COMPASS 5000.15 Build 91 Company: Hilcorp Alaska, LLC Project: Ninilchik Unit Site: Kalotsa Well: Kalotsa 6 Wellbore: Kalotsa 6 Design: Kalotsa 6 Checked By: Chelsea Wright Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well Kalotsa 6 As -Built @ 144.40usft (HEC 169) As -Built @ 144.40usfi (HEC 169) True Minimum Curvature NORTH US + CANADA Approved By: Benjamin Hand m „ — — Date: 09-27-2019 927/2019 2:25:33PM Page 5 COMPASS 5000.15 Build 91 Lease & Well No. County TO Hilcorp Energy Company ( CASING & CEMENTING REPORT I NINU Kalotsa 6 State Alaska Supv. CASING RECORD Surface � 1.660. on Shne nenth 1 654 An PRTn Date Run 21 -Sep -19 Riley/Davis Csg Wt. On Hook: Csg Wt. On Slips: Rotate Csg Yes Fluid Description: Spud Mud Liner hanger Info (Make/Model): Liner hanger test pressure: Centralizer Placement: Type Float Collar: Type of Shoe: X No Recip Csg Casing (Or Liner) Detail No. Hrs to Run: Casing Crew: _ No Ft. Min. Liner top Packer?: Floats Held 4 Weatherford 9 PPG _Yes _ No X Yes _ No Setting Depths its. Component Size Wt. Grade THD Make Length Bottom Top Float Shoe 85/8 Preflush (Spacer) DWC 1.64 1,654.40 1,652.76 2 75/8"DWC Casing its 75/8 29.7 L-80 DWC 82.06 1,652.76 1,570.70 Float Collar 85/8 DWC 1.33 1,570.70 1,569.37 38 75/8"DWC Casing its 75/8 29.7 L-80 DWC 1,544.86 1,569.37 24.51 7 5/8" Casing Pup it 75/8 29.7 L-80 DWC 2.42 24.51 22.09 Hanger 131/2 Sacks: 155 Yield: 1.18 DWC 1.11 1 22.09 20.98 Csg Wt. On Hook: Csg Wt. On Slips: Rotate Csg Yes Fluid Description: Spud Mud Liner hanger Info (Make/Model): Liner hanger test pressure: Centralizer Placement: Type Float Collar: Type of Shoe: X No Recip Csg Bullnose Antelope X Yes No. Hrs to Run: Casing Crew: _ No Ft. Min. Liner top Packer?: Floats Held 4 Weatherford 9 PPG _Yes _ No X Yes _ No CEMENTING REPORT Shoe @ 1654 FC @ 1,569.00 Top of Liner Preflush (Spacer) Type: Mud Push Density (ppg) 10.5 Volume pumped (BBLs) 29 Lead Slurry Type: Lead Class A Sacks: 180 Yield: 2.41 Density (ppg) 12 Volume pumped (BBLs) 77.5 Mixing / Pumping Rate (bpm): 4 Tail Slurry Type: Tail Class A Sacks: 155 Yield: 1.18 Density (ppg) 15.8 Volume pumped (BBLs) 32.5 Mixing / Pumping Rate (bpm): 4 Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Spud Mud Density (ppg) 9 Rate (bpm): 5 Volume (actual / calculated): 69.5/72 FCP (psi): 550 Pump used for disp: Haliburton Bump Plug? X Yes _ No Bump press 1150 Casing Rotated? _Yes X No Reciprocated? X Yes % Returns during job 100 ' Cement returns to surface? X Yes —No Spacer returns? _No X Yes No Vol to Surf. 30 Cement In Place At: 7:41 Date: 9/22/2019 Estimated TOC: 0 Method Used To Determine TOC: Returns Post Calculated Cmt Vol @ 0% excess: Cmt returned to surface: OH volume Calculated: Total Volume cmt Pumped: _ 30 Calculated cement left in wellbore: 79.73 OH volume actual: Actual % Washout: lez.net WellEz Information Management LLC ver 109.73 Lease & Well No. County Hilcorp Energy Company CASING 8: CEMENTING REPORT NINU Kalolsa 6 Date Run 28 -Sep -19 State Alaska Supv. R Pederson / B Davis CASING RECORD Production � TO 5.745.00 Shoe DeDth: 5.735.26 PBTD: 5 fi90 44 Csg Wt. On Hook: 65 Type Float Collar: Antelope Casing (Or Liner) Detail Csg Wt. On Slips: Type of Shoe: Setting Depths As. Component Size Wt. Grade THD Make Length Bottom Top Estimated TOC: Float Shoe 5 DWC/C Summit 2.12 5,735.26 5,733.14 1 Casing 41/2 12.6 L-80 DWC/C VAM 41.39 5,733.14 5,691.75 Float Collar 5 DWC/C Antelope 1.31 5,691.75 5,690.44 97 Casing 41/2 12.6 L-80 DWC/C VAM 4,211.13 5,690.44 1,479.31 Pup Joint 41/2 12.6 L-80 DWC/C VAM 1.33 1,479.31 1,477.98 Swell Packer 6 DWC/C Baker 11.68 1,477.98 1,466.30 Pup Joint 41/2 12.6 L-80 DWC/C VAM 6.37 1,466.30 1,459.93 35 Casing 41/2 12.6 L-80 DWC/C VAM 1,437.57 1,459.93 22.36 Pup Joint 41/2 12.6 L-80 DWC/C VAM 2.32 22.36 20.04 Hanger 103/4 DWC/C Cactus 0.70 20.04 19.34 Csg Wt. On Hook: 65 Type Float Collar: Antelope No. Hrs to Run: Csg Wt. On Slips: Type of Shoe: Bullnose Casing Crew: Rotate Csg Yes X No Recip Csg Yes X No Ft. Min. Fluid Description: 6% KCL Mud Liner hanger Info (Make/Model): Liner hanger test pressure: Centralizer Placement: One per joint up to swell packer CEMENTING REPORT 11 S `9.3 V PPG Liner lop Packer?: _Yes X No Floats Held X Yes No Shoe @ 5735.26 FC @ 5,690.44 Top of Liner ush (Spacer) Lead Slurry Type: Class A Density (ppg) _ Tail Slurry m Type: Class A Density (ppg) _ y Post Flush (Spacer) N a Type: LL Density (ppg) 10.5 12 Volume pumped (BBLs) 15.3 Volume pumped (BBLs) 126 17.8 Volume pumped (BBLs) 35 Sacks: 300 Yield: 2.35 Mixing / Pumping Rate (bpm): 5 Sacks: 80 Yield: 1.24 Mixing / Pumping Rate (bpm): 2 Density (ppg) Rate (bpm): Volume: : 6% KCL Brine Density (ppg) 8.6 Rate (bpm): 6 Volume (actual / calculated): 85 (psi): 928 Pump used for disp: Halliburton Bump Plug? X Yes No Bump press ig Rotated? _Yes X No Reciprocated? _Yes X No % Returns during job 100 ant returns to surface? _Yes X No Spacer returns? X Yes -No Vol to Surf: 0 ant In Place At: 17:50 Date: 9/28/2019 Estimated TOC: 1,059 od Used To Determine TOC: Spacer Returns Post Job Calculations: 60, Calculated Cmt Vol @ 0% excess: 142.9 Total Volume cmt Pumped: 143.6 Cmt returned to surface: 0 Calculated cement left in wellbore: 143.6 OH volume Calculated: 102.3 OH volume actual: 102.3 Actual % Washout: www.wellez.net WellEz Information Management LLC ver 04818br 1200 1250 1300 1350 1600 1650 A -I 114 1450 1500 1550 1600 1650 A -I 114 1700 1750 m 1850 1900 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Ninilchik Field, Beluga/Tyonek Gas Pool, Kalotsa 6 Permit to Drill Number: 219-114 Sundry Number: 319-447 Dear Mr. York: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 WW W.aogcc.alaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, 2,soiel.'llunielowski Commissioner DATED this 4f day of October, 2019. RBDMS�jOCT 9 71019 STATE OF ALASKA ll -{ it '' '%r," ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 911 AAL` 95 9Rn 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑Z Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Initial Completion, CTCO, N2 ❑✓ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development 9 Stratigraphic ❑ Service ❑ r 219-114 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-133-20685-00-00 r 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 701A Will planned perforations require a spacing exception? Yes ❑ No 0 Kalotsa 6 9. Property Designation (Lease Number): . 10. Field/Pool(s): C061505 / ADL384372 Ninilchik - Beluga7iyonek Gas Pool it. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 5,745' 3,643' TBD TBD - 1,219 psi 1,466' N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 120' 16" 120' Surface 1,654' 7-5/8" 1,654' 1,257' 6,890psi 4,790psi Intermediate 5,735' 4-1/2" 5,735' 3,635' 8,430psi 7,500psi Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic N/A N/A N/A Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Swell Pkr; N/A 1,466' MD/1,209' TVD; N/A, N/A 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch Exploratory ❑ Stratigraphic ❑ Development E Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: October 16, 2019 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑✓ r WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Bo York 777-8345 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramernc.hilcoro.com Contact Phone: 777-8420 �- Authorized Signature: Date: •� - ' COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ OP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: i y coo `c s; .6c)#0 ! e- C rb- , Post Initial Injection MIT Req'd? Yes ❑ No ❑_Z RBDMS� OCT 0 71019 Spacing Exception Required? Yes EI No Subsequent Form Required: C) -- L/ U / APPROVED BY Approved by: C.1 11 COMMISSIONER THE COMMISSION Date: L.' I INqI bmR Form and Form 1 3 Revised 4/20 Approved applicati I ��jjjpa dat:� approval. Attachments in D kale {0/Z� U Hilwrp Masi., LU Well Prognosis Well: Kalotsa #6 Date: 10/1/2019 Well Name: Kalotsa #6 API Number: 50-133-20685-00 Current Status: New Grassroots Well Leg: N/A Estimated Start Date: October 16th, 2019 Rig: Coil Unit/ E -line Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 219-114 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (C) Second Call Engineer: Christina Twogood (907) 777-8443 (0) (907) 378-7323 (C) AFE Number: 1914702C Maximum Expected BHP: — 1,580 psi @ 3613' TVD (Based on normal gradient of 0.437 psi/ft and the lowest TVD) Max. Potential Surface Pressure: — 1,219 psi (Based on expected BHP and gas gradient to surface (0.10psi/ft) Brief Well Summary Kalotsa #6 is a grass roots high angle development well targeting gas sands in the Tyonek formation. This new well reached TD on 9/27/19 and completed 10/1/19. The purpose of this work/sundry is to clean out if necessary W/CT, jet the well dry with CT and Nitrogen, and perforate via tractor. Notes Regarding Wellbore Condition • Hole is currently full w/ 6% KCL. • E -line will complete CBL prior to starting sundry work. Electronic copy of CBL to be sent to AOGCC when completed. • An MIT -IA (7-5/8" x 4-1/2") will be performed to 2,SO sig for 30 minutes using the coiled tubing pumps prior to beginning of sundry work. • Coil will clean out well to 5700' 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 job authority Coiled Tubing Procedure (start of Sundry work) 1. MIRU Coiled Tubing, PT BOPE to 4,000 psi Hi 250 Low. Notify AOGCC 24 hrs. in advance of BOP test. If slickline or eline tags cement shallower than 55,690'. Fo owow s�& 9-11. 2. MU Mill and Motor BHA. 3. RIH and mill cement and cleanout to 5,700' MD. 4. Circulate hole clean with 2 bottoms up, ensure any rubber or cement is free from the hole. 5. RU N2 pumping unit. 6. Drop ball and come online with N2 and jet well dry. • Estimated volume of displaced 6% KCI is 87 bbls (5,720'). If slickline or eline tags cement deeper than 5,700; Proceed with steps 7-11. Well Prognosis Well: Kalotsa #6 nilmrp Alaska. LL' Date: 10/1/2019 7. RIH w/ coiled tubing and jet nozzle BHA and tag PBTD. 8. PU 5ft and displace well fluids with Nitrogen. • Estimated volume of displaced 6% KCI is 87 bbl. 9. Once well is dry, verify desired surface pressure to leave on well with Operations Engineer. 10. POOH w/ coil. LD BHA. 11. RD Coiled Tubing. E -Line Procedure Note: Due to the deviation of this well bore, a tractor may be required. 12. MIRU a -line and pressure control equipment. PT lubricator to 3,500 psi Hi 250 Low. Note that the well is pressurized with nitrogen. • If necessary, bleed pressure down as requested by the RE / OE to establish a drawdown on the formation. 13. Perforate the following Beluga sands with 2-7/8" 6 SPF 60 deg phased perf guns (up to 12 SPF with 2 perf runs) �aox a. b. C. d. e. f. Zone Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Beluga 134 ±5,623' ±5,688' ±3,541 ±3,595' 65' Beluga 131 ±5,555' ±5,597 ±3,482' ±3,519' 42' Beluga 120 ±5,486' ±5,553' ±3,423' ±3,481' 67' Beluga 115 ±5,423' ± 5,443' ±3,369' ±3,386' 20' Beluga 110 ±5,372' ± 5,404' ±3,325 ±3,353' 32' Beluga 106 ±5,338' ±5,360' ±3,295' ±3,314' 22' Beluga 100 ±5,261' ±5,310' ±3,229' ±3,271' 49' 14. POOH. Proposed perfs also shown on the proposed schematic in red font. Final Perfs tie-in sheet will be provided in the field for exact pert intervals. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. Use Gamma/CCL to correlate. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. Rule 2 of Conservation Order 701A defines the Ninilchik Beluga/Tyonek Gas Pool as the intervals common to and correlating between the measured depths of 1,480' in the Paxton #5 well and 9,600' in the Paxton #1 well. 15. RD a -line. 16. Turn well over to production. (Test SSV with -in 5 days of stable production on well —notify AOGCC 24hrs before testing) E -line Procedure (Contingency): 1. If any zone produces sand and/or water or needs isolated 2. MIRU E -line, PT lubricator to 3,500 psi Hi 250 Low. 3. RIH and set 4-1/2" CIBP at depth above zone. Or 4. RIH and set 4-1/2" Casing Patch across the zone. Attachments: 1. Actual and Proposed Well Schematics 2. Coil BOPE Schematic 3. CT Flow Diagrams (Forward Jetting) 4. Wellhead Diagram S. Blank RWO Change Form 6. Standard Well Procedure — N2 Operations Well Prognosis Well: Kalotsa #6 Date: 10/1/2019 rorp Alwke, LLC RKB to GL =18' 16" Q, 9 7/8" hole _ 7-5/8" r +r ti kX t S 6-3/4" - .eJ hole L' r�YT1 13 9 , ff Ls 4` *r��t It - It =_. PBTD = TBD' MD / TBD' = TVD TD = 5,745' MD / 3,643' = TVD' SuHEMATIC CASING DFTAII Ninilchik Unit Kalotsa #6 PTD: 219-114 API: 50-133-20685-00-00 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 1,654' 4-1/2" Prod Csg 12.6 L-80 DWC/CHT 3.958" Surf 5,735' M t IA JEWELRY DETAIL No. Depth ID OD 1 Item 1 1 1.466' 1 3.958" 1 6.875" 1 Swell Packer OPEN HOLE/ CEMENT DETAIL 7-5/8" 108 BBL's of cement in 9-7/8" hole— Returns to surface (50% excess) 4-1/2" 135 BBL's of cement in 6-3/4" hole. Est. TOC Q 1.414' (20% excess) Updated by DMA 10-01-19 16 9-7/8" hole 7 -5/8 - Ninilchik Unit 11 PROPOJED SCHEMATIC PTDt2 96114 API: 50-133-20685-00-00 Hilrorp Nwku, LLC RKB to GL= 18' PBTD =TBD' MD /TBD' =TVD TO = 5,745' MD / 3,643'= TVD' 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 1,654' 4-1/2" Prod Csg 12.6 L-80 DWC/C HT 3.958" Surf 5,735' JEWELRY DETAIL No. Depth ID OD Item l 56bb Updated by DMA 10-01-19 PERFORATION DETAIL Zone Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt SPF Date Status Beluga 100+3,26 ' ±5,310' 3,229' ±3,271' 49' 6 Proposed TBD Beluga 106 ±5,338' 5,360' ±3,295' ±3,314' 22' 6 Proposed TBD Belugo 110 ±5,372' ±5,404' ±3,325 ±3,353' 32' 6 Proposed TBD Belugo 115 ±5,423' ±5,443' 3,369' 3,386' 20' 6 Proposed TBD Beluga 120 ±5,486' ±5,553' 3,423' ±3,481' 67' 6 Proposed TBD Beluga 1 131 1 5,555' ±5,597 3,482' ±3,519' 42' 6 Proposed TBD Beluga 134 1 +5,623' 1 +5,688' 3,541 1 ±3,595' 1 65' 1 6 1 Proposed I TBD l 56bb Updated by DMA 10-01-19 Kill M WH P: 2" 1502 x 2-11 Flanged V: (Mand 2-1/16 1OK 10K flange (Mani. Coil Tubing BOP Coiled Tubing HR580 Injector Head & Gooseneck Weight = 12,850 lbs 4-1116" 1OK Conventional Stripper 5K C062 Lubricator I 5K C062 x 4-1116" 1 OK Flange 4-1116" 10K Combi BOP Top Set ainalshear Second Set Pipe'Sli 4-1/16" 10K Flow Cross Manta 2x2 Valve 1:2" 1502 x 2-1/16' 10K flange Manu 2x2 Valve 2'. 2-1116" 1OK x 2-1/16" 1OK flarge Manual 2x2 Vatve 3'. 2-1/16" 10K x2-1116' IN Flange Marl 2x2 Valve 4: 2" 15W x24116' 10K Range 4-1116" 10K x Wellhead Adapter Flange Wellhead 0 Ninbchik unit Falotsa B6 16a 25/6x6% Vahe, Upper master, CIW-FU, 41/165M FE, HWO, EE td. Tubing head Cams C -ML - Hp ,135/85M x 115M, w/ 2-21/165M 55O Stwdp6 head, CKWS G29L, 13 5/B SM x 16 WW, w/2.2 1/165M 55O BHTR, OBs, O 1/165M FE x 6.5 Obs puick uMpn tap Ninilchik Unit Kalotsa #6 10/01/2019 C.M8I w,. CW, 11 x4% DWC/C bw btm x6.125" RH stub acne box tap, w/ 25/B W neck. 4" NK H BP/ praM1le. DD NL material VaNC Whk3,%V. W6M-K 31/95M FE, w/ 15' Hydmulic operator '55Y 5t UHilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well Kalotsa 6 (PTD 219-144) Sundry #: XXX -XXX Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) "first call' engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? Y / N HAK Prepared By Initials HAK Approved By Initials AOGCC Written Approval Received (Person and Date) Approval: Prepared: Asset Team Operations Manager Date First Call Operations Engineer Date 11 STANDARD WELL PROCEDURE unearp:uagka.LLC NITROGEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre -job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4 -gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 12/08/2015 FINAL vl Page 1 of 1 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 w .aogcc.alaska.gov Re: Ninilchik Field, Beluga/Tyonek Gas Pool, Kalotsa 6 Hilcorp Alaska, LLC Permit to Drill Number: 219-114 Surface Location: 2570' FSL, 437' FWL, SEC. 7, TIS, R13W, SM, AK Bottomhole Location: 118' FSL, 1774' FEL, SEC. 1, TIS, 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, 2esie1. Chmielowski Commissioner DATED this 10 day of September, 2019. STATE OF ALASKA A._ .o KA OIL AND GAS CONSERVATION COMb„oSION PERMIT TO DRILL 20 AAC 25.005 { 1 a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas ❑ Service- WAG ❑ Service - Disp ❑ 1c. Specify if well is proposed for: Drill [] - Lateral ❑ Straligraphic Test ❑ Development - Oil ❑ Service- Winj ❑ Single Zone [] Coalbed Gas ❑ Gas Hydrates ❑ Reddll ❑ Reentry 01 Exploratory -Oil ❑ Development -Gas [l - Service -Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket ❑' • Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 • Kalotsa 6 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 6,000' • TVD: 3,882' Ninilchik Field Beluga/Tyonek Gas Pool 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: 2156' FSL, 437' FWL, Sec 7, TIS, R13W, SM, AK • C061505 / ADL384372 Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 2570' FSL, 1 01'FWL, Sec 7, T1 S, R1 3W, SM, AK N/A 9/20/2019 9. Acres in Property: 14. Distance to Nearest Property: Total Depth: 118' FSL, 1774' FEL, Sec 1, TIS, R14W, SM, AK 4762 3865'to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KS Elevation above MSL (ft): 144.4 15. Distance to Nearest Well Open Surface: x-2 2e_qgy' 2233430 Zone -4 GL / BF Elevation above MSL (ft): 126.4. to Same Pool: 2116'to Paxton 4 16. Deviated wells: �, f f Kickoff depth: 250 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) ' ,h"4- Maximum Hole Angle: 79 degrees Downhole: 1746 Surface: 1358 . 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f, or sacks Hole Casing Weight Grade I Coupling Length MD TVD MD TVD (including stage data) Cond 16" 84# X-56 Weld 120' Surface 120' Surface 120' Driven 9-7/8" 7-5/8" 29.7# L-80 DWC/C 1,614' Surface 1,614' Surface 1,255' L-429.4 ft3/T-181.7 ft3 6-3/4" 4-1/2" 12.6# L-80 DWC/C HT 6,000' Surface 6,000' Surface 3,882' L - 673.3 ft3 / T - 89.7 ft3 19. PRESENT WELL CONDITION SUMMARY (To be completed for Reddll 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 ❑� 20. Attachments: Property Plat O BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch B Seabed Report e Drilling Fluid Program e✓ 20 AAC 25.050 requirements e 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: David Gorm Authorized Name: Monty Myers Contact Email: d orm hllCor .Com Authorized Title: Drilling Manager Contact Phone: 777-8333 Authorized Signature: Date: 9 Commission Use Only Permit to Drill I Number: Permit Approval See cover letter for other Number: —�� _ 50 - Date: MIDI I requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed met ane, gas hydrates, or gas contained in shales: J r[+-]Y� Other: 5-00 P S� 450/' SF- Samples req'd: Yes ❑ No� Mud log req'd: Yes❑ Nou�. H,S measures: Yes ❑ No t� Directional svy req'd: Yes 2 No ❑' 4C��✓m.^4I'e_r 4A a': ,04 /yeA Spacing excepy'on eq'd: Yes No Inclination -only svy req'd: Yes El No[T Z.1'. Crit 4 jii) Post initial injection MIT req'd: Yes ❑ No ❑ APPROVED BY �y -1 Approved by: , (�.- COMMISSIONER THE COMMISSION Date: -1 oh Submik Form sand Form 401 Revised 5/201 This permit Is valid for®Rl7 s r t a a�1roval per 20 AAC 26.005 Attach m is in Duplicate IVA �!% °�rl 8 �3 Hilcorp Alaska, LLC Kalotsa #6 Drilling Program Ninilchik Unit Rev 0 August 28th, 2019 U Hilcorp F.nv Company Contents Kalotsa #6 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..............................................................................................................11 11.0 Drill 9-7/8" Hole Section...............................................................................................................13 12.0 Run 7-5/8" Surface Casing...........................................................................................................16 13.0 Cement 7-5/8" Surface Casing.....................................................................................................19 14.0 BOP N/U and Test.........................................................................................................................23 15.0 Drill 6-3/4" Hole Section...............................................................................................................24 16.0 Run 4-1/2" Production Casing.....................................................................................................27 17.0 Cement 4-1/2" Production Casing...............................................................................................30 18.0 RDMO............................................................................................................................................32 19.0 BOP Schematic..............................................................................................................................33 20.0 Wellhead Schematic......................................................................................................................34 21.0 Days Vs Depth................................................................................................................................35 22.0 Geo-Prog.........................................................................................................................................36 23.0 Anticipated Drilling Hazards.......................................................................................................37 24.0 Saxon Rig 169 Layout...................................................................................................................39 25.0 FIT Procedure................................................................................................................................40 26.0 Choke Manifold Schematic...........................................................................................................41 27.0 Casing Design Information...........................................................................................................42 28.0 6-3/4" Hole Section MASP............................................................................................................43 29.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................44 30.0 Surface Plat (NAD 27)...................................................................................................................45 31.0 Directional Plan (wp06)................................................................................................................46 n Hilcorp E��Pwy 1.0 Well Summary Kalotsa #6 Drilling Procedure Rev 0 Well Kalotsa #6 Pad & Old Well Designation Kalotsa 46 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 6,000' MD / 3,880' TVD PBTD, MD / TVD 5,920' MD / 3,810' TVD Surface Location Governmental) 2156' FSL, 437' FWL, Sec 7, Tl S, R13 W, SM, AK Surface Location (NAD 27) X=209833.98, Y=2233430.67 - Surface Location (NAD 83) X=1349853.31, Y=2233189.91 Top of Productive Horizon Governmental 2570' FSL, 101' FWL, Sec 7, TIS, R13W, SM, AK TPH Location AD 27) X=209509.04, Y=2233767.11 TPH Location AD 83) X=1349528.34, Y=2233526.34 BHL Governmental 118' FSL, 1774' FEL, Sec 1, TIS, R14W, SM, AK BHL (NAD 27) X=207702.33, Y=2236639.08 BHL (NAD 83) X=1347721.487, Y=2236398.29 AFE Number AFE Drilling Das 5 MOB, 15 DRLG AFE Completion Days AFE Drilling Amount $3,288,387 AFE Completion Amount Maximum Anticipated Pressure (Surface) 1,358 psi Maximum Anticipated Pressure (Downhole/Reservoir) 1,746 psi Work String 4-1/2" 16.69 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 H Hilcorp Ene CamT 2.0 Management of Change Information Kalotsa #6 Drilling Procedure Rev 0 11 Hilcorp Alaska, LLC Hililcoor Changes to Approved Permit to Drill Date: August r, 2019 Subject: Changes to Approved Permit to Drill for Kalotsa #6 File #: Kalotsa 96 Drilling and Completion Program Any modifications to Kalotsa #6 Drilling & Completion Program will be documented and approved belmv. Changes to an approved APD will be cqnr1W4K a_te= the BLM and AOGCC. YY fApppproved Sec Page Date Procedure Change Approved 13Y BY Approval: Drilling Wnager Prepared: David Gorm Date Drilling Engineer Date Page 3 Version 0 August, 2019 H Hilcorp E.c C2!x 3.0 Tubular Program: Kalotsa #6 Drilling Procedure Rev 0 Hole Section OD (in) ID (in) Drift in Conn OD in Wt #/ft Grade Conn Burst Tensi Cond 16" 15.01" 14.822 17" 84 J-55 Weld 2980 t7500 9-7/8" 7-5/8" 6.875" 6.75" 8.5" 29.7 L-80 Dwac 6890683 6-3/4" 4-1/2" 3.958" 3.833" 5.0" 12.6 L-80 Dwcic xT 8430288 4.0 Drill Pipe Information: e Section OD (in) ID (in) TJ ID in TJ ODoon in 1 Burst Leo apse (psi) G (psi) ension (k -lbs) All 4-1/2" 3.826 2.6875" 5.25" 16.6 1 S-135 I CDS40 17.693 16 769 468k All casing will be new Page 4 Version 0 August, 2019 H Hilcorp E�C 5.0 Internal Reporting Requirements Kalotsa #b Drilling Procedure Rev 0 5.1 Fill out daily drilling report and cost report on Wellez. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry tab. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. 5.2 Afternoon Updates • Submit a short operations update each work day to deonn e.hilcorp.com. mmyers@hilcorp.com e.hilcorp.com and cdinger@hilcorp.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. Each rig will be assigned a username to login with. 5.4 EHS Incident Reporting • Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don't wait until an emergency to have to call around and figure it out!!!! 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 firs 5.5 Casing Tally • Send final "As -Run" Casing tally to dgonn@hilcorp.com and cdinger@hilcort).com 5.6 Casing and Cmt report • Send casing and cement report for each string of casing to dgorm@hilcoa2.com and cdinger@hilcorp.com Page 5 Version 0 August, 2019 U Hilcorp Lnegy Company 6.0 Planned Wellbore Schematic Kalotsa #6 Drilling Procedure Rev 0 Ninilchik Unit PROPOSED SCHEMATIC PTD: TBD TBD PT API: TBD CASING DETAIL Size Type M I Grad! DOIIh ID Top BtM IC -Dre th iven84 to Set C %.56 1 Weld 15.01" Suri 120' 7-5$' 1 Surf 2S7L-80ONCK 6.875" Surf 1,61J' 4- Ial I Pros Cw 1 126 1 L-87 I DIV CifT 3958' Su�1 6000 Iapo JEWELRY DETAIL No. I Depth ID GD 1 ftM ] 1 J00' 3.452" 6.975' 1 Swell Packer r 1 ✓v Y, M1 `. t1 p8T0=5,920' MD/P'D=3,810' TD 00' = 6,0MD/ TV0 = 3,880' OPEN HOLE / CEMENT DETAIL 7 -!WW 110888L'sW cenrnt in97(8'Mlr-Seturm tasurfa 50%.. 4-1/2' 113S BBL's W cemec; in b3 J'tulr. EsL TDC 1 J1W OM. cea Page 6 Version 0 August, 2019 U Hilcorp $�C..P* 7.0 Drilling / Completion Summary Kalotsa #6 Drilling Procedure Rev 0 Kalotsa #6 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 kickoff point at 300' MD. Maximum hole angle will be 80° and TD of the well will be 6,000 MD/ 3,882' TVD, ending with 30° inclination left in the hole. Vertical section will be 3,852 ft. Drilling operations are expected to commence approximately September 20' 2019. The Hilcorp Rig # 169 will be used to drill the wellbore then run casing and cement. Surface casing will be run to 1,614' 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 Ins after CIP to determine TOC. Necessary remedial action will then be discussed with AOGCC authorities.✓ All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. � General sequence of operations: 1. MOB Hilcorp Rig # 169 to well site 2. N/U conductor riser. (No diver -ter, diverter waiver requested) 3. Drill 9-7/8" hole to 1,614' MD. Run and curt 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 6,000' 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, NIU temp abandonment cap, RDMO. Reservoir Evaluation Plan: 1. Surface hole: GR + Res + Den/Neu (LWD). 2. Production Hole: GR + Res + Den/Neu (LWD). 3. Mud loggers from surface casing point to TD. Page 7 Version 0 August, 2019 0 Hilcorp Kalotsa #6 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. • BOPs shall be tested at (2) week intervals during the drilling of Kalotsa #6. Ensure to provide AOGCC 24 hrs notice prior to testing BOPS. • The initial testof B99P equipment will be to 250,628<psi & subsequent tests of the BOP equipment will be to 250/ psi for 5/10 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tes s). 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 #6. No shallow hydrocarbon zones will be penetrated. b i( Page 8 Version 0 August, 2019 U Hilcorp B� Summary of BOP Equipment and Test Requirements Kalotsa #6 Drilling Procedure Rev 0 Hole Section Equipment Test Pressure(psi) 9-7/8" • No diverter utilized n/a • 11" x 5M Townsend Annular BOP Initial Test: 250/26or • 11" x 5M Townsend Double Ram o Blind ram in him cavity (Annular 2500 psi) • Mud cross 6-3/4" 11" x 5M Townsend Single Ram • 3-1/8" 5M Choke Line Subsequent Tests- 250/859lr • 2-1/l6 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). ZP • Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: • Well control event (BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPS. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. 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(acr�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/TestWitnessNotif.html 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 #6 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. YY 9.3 Install 16-3/4" 3M "A" section. Ensure to orient wellhead so that tree will line up with flowline later. 9.9 9.10 Level pad and ensure enough room for layout of rig footprint and R/U. Layout Herculite on pad to extend beyond footprint of rig. R/U Hilcorp Rig # 169, spot service company shacks, spot & R/U company man & toolpusher offices. RU Mud loggers on surface hole section for gas detection only. No samples required After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. Mix mud for 9-7/8" hole section. 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. Page 10 Version 0 August, 2019 Diameter of Liner 6i4" 6l" 6" 5'h" 5" 4th" Rated pressure 2730 psi 16.3 MPa 2558 psi 17.6 MPa 3000 psi 20.7 We 3572 psi 24.6 MPa 4322 psi 29.8 MPa 5000 psi 34.5 MPa S rake Rated power Discharge capacity GPM "P" kW HP 6'/." 150 799 1071 697 646 551 463 382 310 140' 746• 1000' 651 603 514 432 357 289 130 692 928 604 560 477 401 331 269 120 639 857 558 517 441 370 306 248 110 585 785 511 474 404 339 280 227 100 532 714 465 431 367 309 255 207 90 479 642 418 388 330 278 229 186 Page 10 Version 0 August, 2019 H Hilcorp En�gy,2x 10.0 N/U 16" Conductor Riser 10.1 N/U 16" Conductor Riser Kalotsa #6 Drilling Procedure Rev 0 • 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 11 Version 0 August, 2019 U Hilcorp 10.3 Rig Orientation on Kalotsa pad: Kalotsa #6 Drilling Procedure Rev 0 Page 12 Version 0 August, 2019 11.0 Drill 9-7/8" Hole Section 11.1 PIU 9-7/8" directional drilling assy: Kalotsa #6 Drilling Procedure Rev 0 • 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" 16.6# S-135 CDS40 COMPONENT Item DATA Description Serial Number .. (in) to (in) Gauge"Mw� (in) (Ibpf) Top Connection Length (it) Cumulative Length (111) 1 9-7/8" PDC 6.020 2250 9.875 83.45 P 4-112" REG 0.89 0.89 2 7' SperryDrill Lobe 718- 7.5 stg 7.000 4.952 95.69 B 4-1/2" IF 30.00 30.89 Stabilizer 9.625 3 d66-314" Integral Blade 9 3'4" 6.760 2.500 9.750 105.59 B 4-112" IF 6.99 37.88 4 6-314" Float Sub 6.800 2.375 108.67 B 4-112" IF 3.00 40.88 5 6 314" DM Collar (Directional) 6.720 3.125 103.40 B 4-1/2" IF 9.20 50.08 6 314" DGR Collar (Gamma) ✓ 6.710 1.920 97.80 B 4-1/2" IF 6.50 56.58 7 6 314" EWR-P4 Collar (Resistivity) 6.710 2.000 104.30 B 4.1/2" IF 1200. 68.58 a 6 314" PWD Collar (Pressure) / 6.720 1.905 96.30 B 4-1,2" IF 4.44 73.02 9 6 314" HCIM Cellar (Processor) 6.750 1.920 101.70 B 4-12" IF 6.50 79.52 10 6 314" TM Collar (Telemetry) 6.550 3.250 103.60 B 4-12" IF 9.90 89.42 11 6.75" NM Flex Collar 6.450 2.875 8923 B 4.12" IF 3D.00 119.42 12 X -Over Sub 4-112 IF x CDS 40 6.450 2.625 92.91 B 4.5*CDS 3.00 122.42 13 3#a 4-12"HWDP 4.500 2.813 36.86 93.00 215.42 14 X -Over Sub CDs 40 x 4-12 IF 6.300 2.625 -F7 79 B 4-12" IF 3.00 218.42 15 6-1/4" Weatherford Jar 6.270 2250 91.68 B 4-12" IF 30.00 248.42 16 X -Over Sub 4-112 IF x CDS 40 6230 2.625 65.44 B 4.5" CDS40 3.00 251.42 17 5jis 4-12" HWDP 4.500 2.813 36.86 155.00 406.42 406A2 Page 13 Version 0 August, 2019 N Hilcorp s�C.".UY 11.3 PU 9-7/8" bit, 4-1/2" HWDP, Jars, & Workstring Kalotsa #6 Drilling Procedure Rev 0 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 1,614' 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 1,500' MD and 1,700' MD. • 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 Properties: Depths Densfty I Viscosity Plastic Viscosity Yield Point AN FIL H 120-1 8.8-9.5 1 85-150 1 20-40 25-45 <10 1 8.5-9.0 Page 14 Version 0 August, 2019 K Hilcorp 11.7 11.8 Kalotsa #6 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 II 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 15 Version 0 August, 2019 12.0 Run 7-5/8" Surface Casing 12.1 R/U and pull wear -bushing. Kalotsa #6 Drilling Procedure Rev 0 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 16 Version 0 August, 2019 n Hilc T Ene Camryuy Technical Specifications Connection Type: Size(O.D.): DWC1C Casing 7-5/8 in STANDARD Material L-80 Grade 80,000 Minimum Yield Strength (psi.) 95,000 Minimum Ultimate Strength (psi.) Weight (Wall): 29.70 Ib/ft (0.375 in) 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.) Weight (Wall): 29.70 Ib/ft (0.375 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 Lass (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.4bs.) 25,100 Maximum Final Torque (ft.4bs.) 28,500 Connection Yield Torque (ft. -lbs.) Kalotsa #b Drilling Procedure Rev 0 Grade: L-80 "SAM -USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston, TX 77041 Phone: 713479-3200 Fax: 713-479-3234 E -mad: VAMUSAsalesnn vam-usa.cam Page 17 Version 0 August, 2019 H Hilcorp E.m CmnT Kalotsa #6 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 18 Version 0 August, 2019 U HilmwF.m Cmnpany 13.0 Cement 7-5/8" Surface Casing Kolotsa #6 Drilling Procedure Rev 0 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 WE spacer. Test surface curt 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 19 Version 0 August, 2019 H Hilcorp Kalotsa #6 Drilling Procedure Rev 0 SURFACE CEMENT CALCULATIONS Lead Slurry (1,114' MD to surface) Tail Slurry (1,114' to 1,614' MD) CSG 7 518 CSG BTM ft 1,614 Size Density Section: Calculation: Vol Vol Yield (BBLS) (ft3) LEAD: Mixed Water 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: Description Concentration Code Description Concentration (1,114'— 120') x.046 bpf x 1.5 G Cement 9-7/8" OH x 7-5/8" A 57.03 320.2 Casing annulus: Retarder 0.15 gal/sk BWOC D046 Total LEAD: Additives 76.48 429.4 0.2 % BWOC TAIL: Dispersant 0.4 % BWOC D079 Extender (1,614'-1,114') x .038 bpf x 1.5 5002 CaC12 0.35 % BWOC 9-7/8" OH x 7-5/8" D020 28.69 161.1 Casing annulus: CaC12 0.1 % BWOC TAIL: 80 x .046 bpf = 3.67 20.6 7-5/8" Shoe track: Total TAIL: 32.36 181.7 Total Cement: ViOS.84 1 611.1 Cement Slurry Design: 17q Sx Page 20 Version 0 August, 2019 Lead Slurry (1,114' MD to surface) Tail Slurry (1,114' to 1,614' 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 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 20 Version 0 August, 2019 U Hi1COt E.a Czix Kalotsa #6 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: 1,614'- 80' = 1534' x .046 bpf = 71 bbls oLL-- 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'/2 shoe track volume. Total volume in shoe track is 3.6 bbls. Be prepared for cement returns to surface. If curt returns are not observed to surface, be prepared to run a temp log between 12 — 18 hours after CIP. Be prepared with small OD top out tubing in the event atop 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 21 Version 0 August, 2019 a H Hilcorp E.c Czjx 13.18 Lay down landing joint and pack -off running tool. Kalotsa #6 Drilling Procedure Rev 0 Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface & volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the successor problems during the cement job Send final "As -Run" casing tally & casing and cement report to cdinper(ahilcorp.com and mmyers(a hilcoro.com. This will he included with the EOW documentation that goes to the AOGCC. Page 22 Version 0 August, 2019 H Hilcorp Energy C,2,T 14.0 BOP N/U and Test Kalotsa #6 Drilling Procedure Rev 0 14.1 N/U wellhead assy. Install 7-5/8" packoff P -seals. Test to 3000 psi. 14.2 NIU 11" x 5M T3 -Energy BOP as follows: • BOP configuration from Top down: 1 I" x 5M T3 -Energy annular BOP/11" x 5M T3 -Energy Model 601 li double ram /11" x 5M mud cross/l I" 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 him 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). • Test BOP to 250pS0 Rsi 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. 14.8 Rack back as much 4-1/2" DP in derrick as possible to be used while drilling the hole section. Page 23 Version 0 August, 2019 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. Kalotsa #6 Drilling Procedure Rev 0 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. COMPONENT hem.. 1 DATA .. HDBS MMD84 (in) 4.750 1 (in) 1.500 Gauge (in) 8.750 Weight (IbpQ Sa37 Top Connection P 312- REG Length (to 0.80 curnulative Length (11) 0.80 2 4 3/4' SpertyDrO lobe 5%- 8.3 sig 4.750 2.794 44.57 8 3-12^ IF 26.70 27.50 Stabdeer 6.375 3 4 34- NM Integral Blade Stabi4xer 4.750 2313 6.500 46.07 B 3.12' IF 5.60 33.10 4 4 a4- DM Cattle (DreCBone) 4.750 2.610 47.00 8 3.172' IF 9.18 4228 5 4 3/4' PW D 25KSI (Pressure) 4.750 1.250 47.90 8 NC 38 923 51.51 6 Inane Stebilim (ILS) 4.760 1.250 6.500 5521 8 3.12' IF 3.00 54.51 7 4 3+4- SP4 (Resistwity/Gamma) 4.750 1.250 48.20 B NC 38 22.50 77.02 e Infix Stabrtim (ILS) 4-750 1250 6.500 5621 B 3-W IF 3.00 80.02 9 4 3W ALD Collar (Density) 4.750 1250 6.375 45.50 8 NC 38 14.35 94.37 Stabdoer 6.375 /0 4 374' CTN Coca (Porosity) 4.750 1250 50.50 B NC 38 11.14 105.51 11 4 314' TM Collar (Telemetry) 4.750 2.812 46.10 8 NC 38 10.86 116.37 12 4-34' NM Flax 4.750 2.313 46.07 8 3-12' IF 30.00 146-37 13 4 3(4" NM Flex 4.750 2.313 46.07 B 312' IF 30.00 176.37 14 4314'NM Flex 4.750 2.313 46.07 83-1/21F 30.00 206.37 15 4 314' Float Sub 4.750 2250 46.84 B 3.12- IF 1 2.50 206.87 to 41/2' IF P to XT -39 8 XO Sub 4.750 2-500 1 43.86 B a� XT39 1.67 210.54 17 10 4. 14WDP XT -39 4.000 2.503 25.24 31.50 242.04 18 4 V4- Hydraulic Jar 4.835 2250 43.95 B 4' XT39 29.30 271.34 19 4 its 4- MDP XT -39 4.000 2563 25.24 126.00 397-34 20 4' DP XT -39 4.00D 3240 14.73 31.50 428.64 428.84 Page 24 Version 0 August, 2019 H HilwEnm P+oY 15.9 6-3/4" hole section mud program summary: Kolotsa #6 Drilling Procedure Rev 0 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 Mu Water Plast c KCI 22 ppb (29 K chlorides) Caustic MD ht Viscosity EZ MUD DP Yield Point pH HPHT PAC -L Weioty BARACARB 5/25/50 15 - 20 ppb (5 ppb of each) BAROID 41 as required for a 9.0-10.0 ppg ALDACIDE G 1,614'-6,000' 9.0-9.5 1 40-53 1 15-25 15-25 8.5-9.5 511.0 System formulation: 6% KCL EZ Mud DP Product Concentration Water 0.905 bbi KCI 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. Q° 15.11 R/U and test casing to UL04 si / 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 25 Version 0 August, 2019 U Hilcorp E..W C.W, Kalotsa #6 Drilling Procedure Rev 0 15.14 Conduct FIT to 12.5 ppg EMW. f Kick tolerance = (12.5-9.5)X(1250/3880) = 0.96 15.15 Drill 6-3/4" hole section to 6,000' MD / 3,880' 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 26 Version 0 August, 2019 16.0 Run 4-1/2" Production Casing Kalotsa #6 Drilling Procedure Rev 0 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 5,500' MD. • Install solid body centralizers on every other joint to 7-5/8" shoe. Leave the centralizers free floating. • Pickup swell packer and place in string at approximately 1,400' 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 27 Version 0 August, 2019 H Hilcorp Em c2,T Technical Specifications Connection Type: Size(O.D.): DWC/C Tubing 4-1/2 in standard Material L-80 Grade 80,000 Minimum Yield Strength (psi) 95,000 Minimum Ultimate Strength (psi) Pipe Dimensions 4.500 Nominal Pipe Body O.D. (in) 3.958 Nominal Pipe Body I.D.(in) 0271 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) Kalotsa #6 Drilling Procedure Rev 0 Weight (Wall): 12.60 Wit (0.271 in) Appoximated Field End Torque Values 5,800 Minimum Final Torque (ft-Ibs) 6,500 Maximum Final Torque (ft-Ibs) 7,200 Connection Yield Torque (ft-Ibs) Grade: L-80 "%P" USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston, TX 77041 Phone: 713-479-3200 Fax 713-479-3234 E-mail: VAMUSAsales®vam�.mm Page 28 Version 0 August, 2019 Pipe Body Performance Properties 288,000 Minimum Pipe Body Yield Strength (Ibs) 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-Ibs) 6,500 Maximum Final Torque (ft-Ibs) 7,200 Connection Yield Torque (ft-Ibs) Grade: L-80 "%P" USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston, TX 77041 Phone: 713-479-3200 Fax 713-479-3234 E-mail: VAMUSAsales®vam�.mm Page 28 Version 0 August, 2019 Connection Dimensions 5.000 Connection O.D. (in) 3.958 Connection I.D. (in) 3.833 Connection Drift 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-Ibs) 6,500 Maximum Final Torque (ft-Ibs) 7,200 Connection Yield Torque (ft-Ibs) Grade: L-80 "%P" USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston, TX 77041 Phone: 713-479-3200 Fax 713-479-3234 E-mail: VAMUSAsales®vam�.mm Page 28 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 (Ibs) 288,000 Compression Rating (Ibs) 7,500 API Collapse Pressure Rating (psi) 8,430 API Internal Pressure Resistance (psi) 81.5 Maximum Uniaxial Bend Rating [degrees/100 ft] Appoximated Field End Torque Values 5,800 Minimum Final Torque (ft-Ibs) 6,500 Maximum Final Torque (ft-Ibs) 7,200 Connection Yield Torque (ft-Ibs) Grade: L-80 "%P" USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston, TX 77041 Phone: 713-479-3200 Fax 713-479-3234 E-mail: VAMUSAsales®vam�.mm Page 28 Version 0 August, 2019 U E1CO� 16.6. Run in hole w/ 4-1/2" casing to the 7-5/8" casing shoe. Kalotsa #6 Drilling Procedure Rev 0 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 maker to be placed at approximately 1,400' MD. 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. Circulate until hole and mud is in good condition for cementing. Page 29 Version 0 August, 2019 17.0 Cement 4-1/2" Production Casing Kalotso #6 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 30 Version 0 August, 2019 H Hilcorp Lvw Kalotsa #6 Drilling Procedure Rev 0 Production CEMENT CALCULATIONS Lead (5,50(Y -1,414') Tail (6000'- 5,500') CSG 41/2 CSG BTM ft 6,000 Size 15.3 Ib/gal Section: Calculation: Vol Vol 14.11 gal/sk 5.55 gal/sk (BBLS) (113) LEAD: Code Description Concentration 7-5/8" x 4-1/2" (1,614'-1,414) x .026 bpf = 5.25 29.5 Casing annulus: Typel Cement 94 lb/sk Additives LEAD: 0. 21%BWOC WeIlLife 1094 Monofilament 0.20%BWOC fiber 6-3/4" OH x 4-1/2" (5,500'— 1,614') x.025 bpf x 114.67 643.8 1.20 = Casing annulus: Total LEAD: 119.91 673.3 TAIL: (6,000'-5,500') 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: 1 15.97 1 89.7 Total Cement: I135.89 762.9 0? YO s r `7(sx Page 31 Version 0 August, 2019 Lead (5,50(Y -1,414') Tail (6000'- 5,500') System VARICEM (TM) CEMENT EXPANDACEM (TM) SYSTEM Density 12 Ib/gal 15.3 Ib/gal Yield 2.386 ft3/sk 1.237 ft3/sk Mixed Water 14.11 gal/sk 5.55 gal/sk Expected Thickening 6:28 HR:MIN 3:52 HR:MIN Code Description Concentration Code Description Concentration Typel Cement 94 lb/sk Typel Cement 94 lb/sk Additives WeIlLife Monofilament 1094 fiber 0. 21%BWOC WeIlLife 1094 Monofilament 0.20%BWOC fiber Page 31 Version 0 August, 2019 U Hilcorp Kalotsa #6 Drilling Procedure Rev 0 Production CEMENT CALCULATIONS CSG 41/2 CSG BTM ft 6,000 Size Section: Calculation: Vol Vol (BBLS) (ft3) LEAD: 7-5/8" x 4-1/2" (1,614'-1,414') x .026 bpf = 5.25 29.5 Casing annulus: LEAD: (5,500' — 1,614') x .025 bpf x 6-3/4" OH x 4-1/2" 1.20 = 114.67 643.8 Casing annulus: Total LEAD: 119.91 673.3 TAIL: (6,000'-5,500') 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: 135.89 1 762.9 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 ''/z 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 31 Version 0 August, 2019 H Hilcorp EncW cumWy Kalotsa #6 Drilling Procedure Rev 0 17.14. WOC minimum of 12 hours, test casing to 3500 psi and chart for 30 minutes. Ensure to report thefollowing on wellez: At (-r— TA • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight CW13 C • 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" casin tally & casino and cement report to mmyersna 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 Hileorp Rig # 169 )E G' V--3 ,/� — t c "J2 6 A tvl. l T TA 4r> z-OOD /-5 6 Page 32 Version 0 August, 2019 H Hilc a� c�emr 19.0 BOP Schematic Kalotsa #6 Drilling Procedure Rev 0 Page 33 Version 0 August, 2019 H Hilcorp F.nclgy Cmnp=y 20.0 Wellhead Schematic Tubing head,( HM, 13 5/8 SH 2-21/16 Starting Head,1 135/85M x 16 1/165k Ninilcbik Unit l(almaa r1 and 2 16 x)5/8 x 4 A B A, Otiz, 41/165M FE 6.S O ht qulek union top Kalotsa #6 Drilling Procedure Rev 0 Caring banger, CW, 11 x 4 Y OWC/C box b[m x 6125' RH stub acme box I.P. w/ ] 5/9 od neck, 4" type H OW profile, DO -NL material Page 34 Version 0 August, 2019 21.0 Days Vs Depth 0 1000 2000 9 MI: 4000 Kolotsa #6 Drilling Procedure Rev 0 Days Vs Depth •11 7000 CIIIIII] 10000 0 5 10 15 Days 20 25 30 Page 35 Version 0 August, 2019 H Hilcorp Erwn, Catapi 22.0 Geo -frog Kalotsa #6 Drilling Procedure Rev 0 Ka,forsa_ 6HiELU: _Pro aendsrone 20979363 osed STATE: 1,142 -997 233471.38 TVD REF DATIILI 514 0.45 TVD REF ELEV aardsfoce _- WB ELEVATION 1.440 -1295 VAD27 AKS True Norr_h GROUND ELEV 646 0.45 WATER DEPTH rds rote 000' LID high -angle Brass roots well at Ninilchlk Field (Pax -Dionne Sducturel prirnant, targeting undeveloped sands at the top and on the west side of the Pax -Dionne antidine. Eero3a v _ aendsrone Poasmb pea 1.314 1,142 -997 2.233,756 88 21P9.4a2.84 514 0.45 Bato9a f0 _ aardsfoce _- 2.641 1.440 -1295 2.234.77404 208. MS. f4 646 0.45 Beluga 13 rds rote ® 2.792 1,478 -1333 34 2.2.875.15 208.512.99 486 0.33 Sakii 16 sandanoee 2,919 1.519 -1374 2.234981.51 208,424.23 425 0.28 eemga 20 _ safM mne 3.044 1.567 422 2.235.069.40 208.380.29 705 0.45 hrga Be30 I saMslone 3.194 1.6 4 34 -1489 2135.176.13 208.380.29 725 0.41 Beluga 34 sanitation. 3.250 1,862 -1517 2235.226.38 208.355.17 746 095 Beluga 37 1 eandsfone 3.283 1.679 -1534 2235.25775 208.33634 755 0.45 Beluga 40 sardslone 3.372 1.727 -1582 2235.32053 208.32318 777 0.45 Beluga 41 _ _ sandsfana 3.432 1,762 -1617 2.233.380.94 208.302.24 669 0.39 Beluga 44 sandstone 3.518 1,812 -1667 2,235.425.74 208272.38 725 0.40. Gatti 45 sandstone dapfaledpas 3.560 1.&10 -1695 2.235.47662 208.234.30 396 0.21' Behrga 47A _._. _ sandstone 3.627 1.894 -1739 2,235.509.76 208.209.45 848 0.45'. Beluga 50 sandstone 3.920 2.019 -1874 2235,61451 208. f58.06 705 0.35 Beloga 5l _ sandstone 3.875 2,060 -1915 2,235,6]675 208.133.90 700 0.34 Beluga 52 sandsbrw depfafed pas 3.926 2.090 -1954 2.235.70290 208.115.11 462 0.12 Beiu9a 53A sandstone daplaf•dgaa 4.IX13 2,158 -2014 2.235.726 55 208.125.16 237 0.11 Beluga 58A _ awldast. depleled gas 4245 2.3110 -2215 2,235.8644] 208.08516 472 0.20 Beluga 59 sandsrone 4.310 2,416 -2271 2235,91312 208.046.35 725 030 Beluga 60 _ sandstan. 4.365 2.464 -2319 2.235.933.43 208.026. W 1010 0.41 Beluga 65 samtslone 4.410 2,503 -2358 2.235,94328 208.036.50 876 0.35 Beluga 70 sendtafmle deplimaidt pea 4.450 2.537 -2392 2.235.953.13 208.046.35 431 0.17 Beluga 72 sandslone d•pi•aed pas 4.478 2562 -2417 2.235.948.24 208.027.76 384 0.15 Bels'. 82 smdemis. 4.686 2.742 -2597 2,236.044.93 20798478 622 0.30 Beluga 92-2 sandal.® 4933 2.956 -2811 2.236.1]3.84 207941.81 9480.32 Eelu00 ga 1andarone s 5.290 3.265 -3120 2.236,334.99 2079]7.35 914 029 Beluga 110 sandsion9 5.370 3.334 .3189 2.23635647 207.888.10 967 0.29 beluga 115 1 tandstw.5415 3.373 3229 2.236,389 70 20].877.35. 1012 0.30 Beruga 120 sandst9ne 5.448 3.402 7257 2.236.4!0.19 207.834.3_9 966 0.29 fieluga 131 sandstone 5.538 3.480 7335 2.236.45316 2(8.855.87 1044 0.30 6.1,9.134 aandarone deptaed ges 5.601 3,534 -3389 2,236.461.34 207.923.19 919 026 Beluga 134A sandstone depfarod gas 5.634 3,563 7418 2,236.46977 207.948.47 926 0.26 Beluga 135 sandstom depleted pea 5.654 3.560 7435 2.236,461 34 207.823.18 394 0.11 Beluga 136 sandi ds,~ gas 5746 3,680 �5f5 2.236.46263 207.925.19 329 0.09 Surface to TD. Samples, collected at 20' intervals. Cutdnd descrlotiom Provided at no areater than 100' in S; eny LWD triple combo at. ..in, string; Spam, LW O Triple Camba produdion etmig • - • This well is to be dnlied from the Cannep, Loop Pad f and will be drilled to the ENE- Page 36 Version 0 August, 2019 K Hilcorp 23.0 Anticipated Drilling Hazards Kalotsa #6 Drilling Procedure Rev 0 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 37 Version 0 August, 2019 n Hilcorp Kalotsa #6 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. • 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: H2S is not present in this hole section. No abnormal temperatures are present in this hole section. Page 38 Version 0 August, 2019 H Hilcorp EneW Compmy 24.0 Hilcorp Rig 169 Layout Kalotsa #6 Drilling Procedure Rev 0 Page 39 Version 0 August, 2019 25.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: Kalotsa #6 Drilling Procedure Rev 0 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 40 Version 0 August, 2019 H Hilcorp GneW C=pa y 26.0 Choke Manifold Schematic Kalotsa #6 Drilling Procedure Rev 0 Page 41 Version 0 August, 2019 ` V a +MN ■1�� 1 +.��r r n MON ��111%� Fl f3 I,wir I1�A i'?4 . e riwA ' ■ � � F.7 n' Page 41 Version 0 August, 2019 U Hilc Emorp ,zw 27.0 Casine Design Information Kalotsa #6 Drilling Procedure Rev 0 0 0 1 DWC Case SafeNFactor Cfensioni € 13.37 v 4.02 Worst Case SafetvFactor (Coll aose) 8.52 4.30 Worstcasesafetyfactor(Burst) i 5.07 j 6.21 Page 42 Version 0 August, 2019 DATE:8-74-2019 WELL:* Kalotsa 5 FIELD: Ninilchik DESIGN BY: David Gorm Design Criteria: Hole Size 9-718' Mud Density: 9. ppg Hole Size 6-314' Mud Density: 9.5 ppg Drilling Mode MASP: 1358 Production Mode MASP: 1358 psi (See attached MASP determination 8 calculation) rllapse Calculation: Section Calculation 1 Normal gradient external stress (0.45 psi1R) and the casing evacuated forthe internal stress 0 0 1 DWC Case SafeNFactor Cfensioni € 13.37 v 4.02 Worst Case SafetvFactor (Coll aose) 8.52 4.30 Worstcasesafetyfactor(Burst) i 5.07 j 6.21 Page 42 Version 0 August, 2019 28.0 6-3/4" Hole Section MASP Kalotsa #b Drilling Procedure Rev 0 I Kalota4 1 3.0-3.50o01 1.368 1 6.387 I 2017 I Orad 0.65 0.45 0 33 0.28 0.45 0.45 0.45 0.45 0.45 0.38 0.4 0.21 0.45 0.0 0.34 0.22 0.11 0.2 0.3 0.41 0.35 0.17 0.15 0.3 0.32 0.28 0.23 0.3 0.23 0.3 0.26 D.26 0.11 0.03 ssumpticns: 1. Maximum phnned mud density for the 6-3/4 hoe section is 3.5 ppV. 2. Caleuhtions pssame rese v.i a contain 100%ops (worst nse1. 3. _Calculations assume wort ease event is complete evacuation of wellbore to ops. 4. Anticipated fracture gradient et 1.250' TVD =13.5 ppo EMW Fracture Pressure at 7-518' shoe considering a Full column of gas From shoe to surface: 1,250 (ft) x 0.70 (poitft)= 875 i STS (p.i)-[0.1(poiln)'1.250(A)7= 1 750 poi MRSP from pore pressure; entire wellbore ewaeuated to gas From TD 3,880 (ft) x 0.45 (p%Jftj= 1746 if (/ 1,746 (psil - [OA (ppilftl'3,880 (ft11= 1358 ci Summary: 1. MRSP while drilling 6.314" production hole i- governed b, frac pre ^.ur<et 7-518" ehoc with entire wellbore ew ted to oas. Page 43 Version 0 August, 2019 H Hilcorp E.W Company Kalotsa #6 Drilling Procedure Rev 0 0 1,00014Feet 2.000 Ninilchik Unit Kalotsa 6 Feet Nasky State Plane Zone 4, NAO27 llikwr M.A.. LIX wp04 Map Date: 8/262019 A Page 44 Version 0 August, 2019 H H11COI�7 F.m Compavy 30.0 Surface Plat (NAD 27) GOVT LOT 2 GOVT LOT 3 xxioTSAVAo Q,o rouorsAm e d: nAemsAp• NALOTSAp4 RALmsAn s WV.Ol5A k50 , 2156' FSL (NTS) Kalotsa #6 Drilling Procedure Rev 0 i� ASP NAD83, ZONE 4 2,233,189.914 1,349,853.316 ASP NAD83, GEOGRAPHIC LAT.: N 60'06'12.2937' LONG.: W 151'35'32.6412" LONG.: ELEV.: 126.4 PAD KALOTSA WELL A6 AS -BUILT ASP NAD27, ZONE 4 N: 2,233,430.672 209,633.993 ASP NAD27, GEOGRAPHIC LAT.: N 60106'14.4326' LONG.: W 151'35'24.6610" NG 29 ELEV.: 126.4 PAD i LOT I KN 65-129 t. 80. IS OF GE00E11c CONTROL ANO N+O63 POSITION OM 'is m OPUS SOLUTION i FROM NGS COORgW11ES STATtONS'P(ENSOQiSARP'_ TSEA C ARP,ANO�TWA t CORSAWTOESTABLISHTHEP06RIONW9103'ON SUSAN OIONNE PAG. THE GEODETIC POSRKIN OF 0103 WAS OEIERNR4-DTO iWVEALATITUOE OFH]'0693995NANDA i'fRNE OF 9513435.1TZW. 11£ '� I ALASKASTAIERAKE COORIXNATES (ASPIZONZONE6� V..1 •••••..9y, ELEVELEV 139'i 7(NGVp2Bl *�tf � 15 � 2. Bl51S OF VERi1CN OONRiOt IS NGS BM VB2 ROTT05S6 LOGTEp AT l '."""""""'"'-'"""-""'-'.•.� lWh OFTHE STERLING HGNNAYHAWW AN E AT W26..%FEET N%Dn I 4� ACCORDING TO NGS PLIIILI pWTA SCALE 3 m yel. COORDINATE CONVERSIONS INADBS TO NA02TI WERE DONEl15tlNG CCRPSCCN 9 Aw SOFRNARE VEREI«a so.I. HEFT �� HILCORP ALASKA, LLC 7„F KALOTSA #6 er. acc NINILCHIK ALASKA v:m AS -BUILT SURFACE LOCATION r�%N;a SEC. 07 TOTS R13W (: T .w>r<��ru m Hilarorp Alux4u, LI. SEWARD MERIDIAN, ALASKA Page 45 Version 0 August, 2019 H Hilc Enc�gy Campaoy 31.0 Directional Plan (wp04) Kalotsa #6 Drilling Procedure Rev 0 Page 46 Version 0 August, 2019 Hilcorp Alaska, LLC Ninilchik Unit Kalotsa Kalotsa 6 Kalotsa 6 Plan: Kalotsa 6 Wp04 Standard Proposal Report 22 August, 2019 HALLIBURTON Sperry Drilling Services NALLIBURTON Sperry Drilling Project: Ninilchik Unit Site: Kalotsa Well: Kalotsa 6 Wellbore: Kalotsa 6 Design: Kalotsa 6 Wp04 Ninilchik Unit Kalotsa Kalotsa 6 Kalotsa 6 Kalotsa 6 Wp04 5.965 ND 120.00 1250.00 3882.13 Hilwrp Alaska, LLC MD Inc Calcula8an Method: Minimum Curvature Co-ordinate (NE) Reference: Well Kalooa 6, True North Error System: ISCWSA +EI -W Vertical (TVD) Reference: As -Built ®144.40us8 (HEC 169) Scan Method: Closest Approach 3D VSect Measured Depth Reference: As -Built @ 144.40usIt (HEC 169) Error Surface: Pedal Curve 1 Calculation Method: Minimum Curvature Warning Method: Error Ratio 0.00 18.00 Sec MD Inc Ad ND +N/-5 +EI -W Dleg TFace VSect Target Annotation 1 18.00 0.00 0.00 18.00 0.00 000 0.00 Goa 0.00 7-5/8 7 5/8" x 9-7/8" 2 250.00 Ooll 0.00 250.00 0.00 ao0 0.110 0.00 0.00 Beluga 52 _ - _ _ _ _ _ StartDir4°1100':250'MD,250WD 3 450.00 8.00 314.51 449.35 9.77 -9.94 4.00 314.51 13.71 Validated: Yes Version: Start Dir6°I100':450'MD,449.35T 13 4 1641.94 79.52 31665 1255.44 552.03 -559.27 6.00 0.14 772.93 Endow : llutIS4'M0, 1255.44'7VD 5 2249.87 79.52 314.65 1366.05 972.10 -984.57 0.00 0.00 1360.93 StartDir 3°1100' : 2249ST MD, 1366.05T 13 6 2589.39 79.00 325.00 1429,50 1226.58 1199.49 3.00 93.87 1692.65 Kalotsa 6 Beluga 10 Start Dir Y/100': 2589.39' MD, 1429.MWD 7 4250.98 30.00 337.28 2367.43 2349.53 -1870.54 3.00 172.00 2997.46 End Dir : 4250.90' MD, 2367.43' ND 8 5678.27 30.00 337.28 3603.50 3007.82 -2146.13 0.00 0.00 3694,82 Kalotsa 6 Beluga 135 9 6000.00 30.00 337.28 3882.13 3156.21 -2208.25 0.00 0.00 3852.01 Total Depth: 6000.00' MD, 3882.13' ND I 1 fi" Start Dir4°/100' : 250' MD, 250'ND - 500 - - - - - - Start Dir 6°/100' : 450' MD, 449.35'ND End Dir : 1641.94' MD, 1255.44' ND Start Dir 3-/100': 2249.87' MD, 1366.05'ND O 0 TVDPath TVDssPath MDPath Formation 1141.40 997.00 1312.59 Beluga 1 1439.40 1295.00 2638.12 Beluga 10 1661.40 151700 3246.84 Beluga 34 1811.40 1667.00 3512.30 Beluga 44 1839.40 1695.00 3556.77 Beluga t5 1883.40 1739.00 3624.29 Beluga 47A 2059.40 1915.00 3872.00 Beluga 51 2098.40 1954.00 3923.13 Beluga 52 2359.40 2215.00 4241.69 Beluga 58A 2415.40 2271.00 4306.37 Beluga 59 2502.40 2358.00 4406.63 Beluga 65 2536.40 2392.00 4446.09 Beluga 70 2561.40 2417.00 4474.96 Beluga 72 2741.40 2597.00 4682.80 Beguile 82 3479.40 3335.00 5534.97 Beluga 131 3533.40 3389.00 5597.32 Beluga 134 3659.40 3515.00 5742.82 Beluga 136 .. _.. _. .. ....� 110 _ --- -1-- WELL DETAILS: Kalotsa 6 o Start Dir 3°/100' :2589.39' MD, 1429.50'NC NDSS MD Size Name 126.40 -24.40 120.00 16 16" N/ -S -E/-W Northing Easting Latlftude Longitude 1105.60 1614.22 7-5/8 7 5/8" x 9-7/8" 0.00 0.00 2233430.6720 209833.9930 6W 614 4328 N 151' 35'24.6810 W 3737.73 6000.00 4-1/2 41/2°x6-3/4' Beluga 51 0 Beluga 52 _ - _ _ _ _ _ ____00 - _ - _ _ _ - _ - _ - _ - _ - _ IN H- 22754 Beluga SBA SURVEY PROGRAM Beluga 59-_ - .._. _ - __. .. _. __ __. _ ___. _. _ _ Beluga 65 - _ _ _ __ _- - -.._ -- Date: 2019-08-13TOO 00:00 Validated: Yes Version: - -_. - . 2600 j Betuga 72 Depth From Depth To Survey/Plan Tool 18.00 1614.00 Kalotsa 6 Wood (Kelolsa 6) 3_MWD+IFRI+MS+Sa 1614.00 6000.00 Kalotsa 6 Wp04 (Kalotsa 6) 3_MWD+IFR1+MS+Sa I 1 fi" Start Dir4°/100' : 250' MD, 250'ND - 500 - - - - - - Start Dir 6°/100' : 450' MD, 449.35'ND End Dir : 1641.94' MD, 1255.44' ND Start Dir 3-/100': 2249.87' MD, 1366.05'ND O 0 TVDPath TVDssPath MDPath Formation 1141.40 997.00 1312.59 Beluga 1 1439.40 1295.00 2638.12 Beluga 10 1661.40 151700 3246.84 Beluga 34 1811.40 1667.00 3512.30 Beluga 44 1839.40 1695.00 3556.77 Beluga t5 1883.40 1739.00 3624.29 Beluga 47A 2059.40 1915.00 3872.00 Beluga 51 2098.40 1954.00 3923.13 Beluga 52 2359.40 2215.00 4241.69 Beluga 58A 2415.40 2271.00 4306.37 Beluga 59 2502.40 2358.00 4406.63 Beluga 65 2536.40 2392.00 4446.09 Beluga 70 2561.40 2417.00 4474.96 Beluga 72 2741.40 2597.00 4682.80 Beguile 82 3479.40 3335.00 5534.97 Beluga 131 3533.40 3389.00 5597.32 Beluga 134 3659.40 3515.00 5742.82 Beluga 136 .. _.. _. .. ....� 110 _ End Dir _4250.98' MD, 2367.43' ND Beluga 82 _ - _ - _ - _ _\ ppp0 Total Depth : 6000.00' MD, 3882.13' ND Beluga 131 Bewga 134 -- -- _--- - --- Kalotsa 6 Beluga 135 - _ _ - - - - - - - - - - - - _ - --- _ _ - - - - - - - - - - Beluga 138 - _" 1 " Kalotsa 6 Wp04 \ 47/2'x6-3/4"----- -- --._I I I I I F r r_ -'r-T 0 325 650 975 1300 1625 1950 2275 2600 2925 3250 3575 3900 4225 4550 Vertical Section at 325.02' (650 usft/in) Beluga 1 o Start Dir 3°/100' :2589.39' MD, 1429.50'NC 1300 75/8"x9-7/8 "� �- o o - - - - - - - _- Beluga 10 - - - - - - - - - ,oy- - - - - - - - 1625 Beluga 34 Ka uga lotsa 6 Bel10 t .. _.. 0 Q Beluga 44 41 t Bewga 45- U 1950-I Beluga 47A -L Beluga 51 0 Beluga 52 _ - _ _ _ _ _ ____00 - _ - _ _ _ - _ - _ - _ - _ - _ IN H- 22754 Beluga SBA 'L Beluga 59-_ - .._. _ - __. .. _. __ __. _ ___. _. _ _ Beluga 65 - _ _ _ __ _- - -.._ -- -�. Bahia. 7a - -_. - . 2600 j Betuga 72 End Dir _4250.98' MD, 2367.43' ND Beluga 82 _ - _ - _ - _ _\ ppp0 Total Depth : 6000.00' MD, 3882.13' ND Beluga 131 Bewga 134 -- -- _--- - --- Kalotsa 6 Beluga 135 - _ _ - - - - - - - - - - - - _ - --- _ _ - - - - - - - - - - Beluga 138 - _" 1 " Kalotsa 6 Wp04 \ 47/2'x6-3/4"----- -- --._I I I I I F r r_ -'r-T 0 325 650 975 1300 1625 1950 2275 2600 2925 3250 3575 3900 4225 4550 Vertical Section at 325.02' (650 usft/in) HALLIBURTON Project: Ninilchik Unit Site: Kalotsa ep`e'e o`00ng Well: Kalotsa 6 Wellbore: Kalotsa 6 ff Plan: Kalotsa 6 Wp04 2025 0 sl 675 ToW Depth: 60011.00' MID, 3882.13'TVD 41a"x6-3/4" _.�6W0 WELL DEfAE : Kalotsa6 126.40 +N/ -S +EI -W NoMins Eaning [allude Longiu 0.00 0.00 223343067M 209833.9930 60e 6' 14.4328 N 151-35-46810W REFERENCE INFORMATION C rdinale(NE) Reference: well Ketols. s. T.A NOM Venicel(ND) Reference: M -Built® 144.4ousn(HEC 169) Measured OepM Refers.: As -Built @ 144.40u ft (HEC 169) Calwlation Method: Minimum CurnWre TVD TVDss 120.00 -24.40 r25n na Iinc en MD Sin Name 120.00 16 16" 161. 77 7-11. 7 5/8" x 9-7/8" 4 In" y 6-3/4" -2475 -2250 -2025 -1800 -1575 -1350 -1125 -900 -675 West( -)/Fast(+) (450 mfUin) T) M:450' MD, 449.35'TVD Sint Dir 4°/100': 250'MD, 2511` VD I6" -450 -225 0 225 450 61 -2700 -2400 -2100 -1800 -1500 -@00 -900 -600 -300 0 300 West( -)/East(+) (450 usft/in) HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Proiect: Ninilchik Unit Site: Kalotsa Well: Kalotsa 6 Wellbore: Kalotsa 6 Design: Kalotsa 6 Wp04 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Kalotsa 6 TVD Reference: As -Built @ 144.40usft (HEC 169) MD Reference: As -Built @ 144.40usft (HEC 169) North Reference: True Survey Calculation Method: Minimum Curvature Proiect Ninilchik Unit Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) _ Usum Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor site Kalotsa Site Position: From: Map Position Uncertainty: Well Kalotsa 6 Well Position +N/S +E/ -W Position Uncertainty TVD Northing: Eastmo: 0.00 Usti Slot Radius: 0.00 usft Northing: 0.00 usft Fasting: 0.50 usft Wellhead Elevation: 2,233,473.8990 usft Latitude: 209,844.1600 usft Longitude: 13-3/16' Grid Convergence: 2,233,430.6720 usft Latitude: 209,833.9930 usft Longitude: usft Ground Level: Wellbore Kalotsa 6 Magnetics Model Name Sample Date Declination (°) BGGM2018 8/13/2019 15.08 Design Kalotsa 6 Wp04 Audit Notes: Vetslon: Phase: PLAN Vertical Section: Depth From (TVD) -N/.S (usft) (usft) 18.00 0.00 60' 6' 14.8608 N 151°35'24.5010W 1.38 ° J 60° 6' 14.43281 N 151' 35' 24.6810 W . 12fi 40 usft Dip Angle Field Strength (I mT) 73.05 55,009.18717818 I Tie On Depth: +E/.W (usft) 0.00 18.00 Direction (9 325.02 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclinatio Azimut Depth System +N/ -S +E/ -W Rate Rate Rate Tool Face (usft) n h (usft) usft (usft) (usft) (°/t00usft) (°1100usft (°1100usft (°) 18.00 0.00 0.00 18.00 -126.40 0.00 0.00 0.00 0.00 0.00 0.00 250.OD 0.00 0.00 250.00 105.60 0.00 0.00 0.00 0.00 0.00 0.00 450.00 8.00 314.51 449.35 304.95 9.77 -9.94 4.00 4.00 0.00 314.51 1,641.94 79.52 314.65 1,255.44 1,111.04 552.03 -559.27 6.00 6.00 0.01 0.14 2,249.87 79.52 314.65 1,366.05 1.221.65 972.10 -984.57 0.00 0.00 0.00 0.00 2,589.39 79.00 325.00 1,429.50 1,285.10 1,226.58 -1,199.49 3.00 -0.15 3.05 93.87 4,250.98 30.00 337.28 2,367.43 2,223.03 2,349.53 -1,870.54 3.00 -2.95 0.74 172.00 5,678.27 30.00 337.28 3,603.50 3,459.10 3,007.82 -2,146.13 0.00 0.00 0.00 0.00 6,000.00 30.00 337.28 3,882.13 3,737.73 3,156.21 -2,208.25 0.00 0.00 0.00 0.00 8222019 2:30:44PM Pace 2 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Companv: Hilcorp Alaska, LLC Project: Niniichik Unit Site: Kalotsa Well: Kalotsa 6 Wellbore: Kaiotsa 6 Design: Kaloisa 6 Wp04 Planned Survey Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Kalotsa 6 TVD Reference: As -Built @ 144.40usft (HEC 169) MD Reference: As -Built @ 144.40usft (HEC 169) North Reference: True Survev Calculation Method: Minimum Curvature Measured Map Map Vertical +EI -W Depth Inclination Azimuth Depth TVDss +NIS (usft) (°) (') (usft) usft (usft) 18.00 0.00 0.00 18.00 -126.40 0.0( 100.00 0.00 0.00 100.00 -44A0 0.0( 120.00 0.00 0.00 120.00 -24.40 0.0( 16" 209,833.9930 0.0000 0.00 -0.62 2,233,431.2985 200.00 0.00 0.00 200.00 55.60 0.0( 250.00 0.00 0.00 250.00 105.60 0.0( Stan Dir 4°/100' : 250' MD, 2507M -15.82 2,233,446.6073 209,818.5489 300.00 2.00 314.51 299.99 155.59 0.61 400.00 6.00 314.51 399.73 255.33 5.5( 450.00 8.00 314.51 449.35 304.95 9.77 Start Dir 6°1100' : 450' MD, 449.35'TVD 209,710.7360 6.0000 500.00 11.00 314.55 498.66 354.26 15.5E 600.00 17.00 314.59 595.64 451.24 32.53 700.00 23.00 314.60 689.57 545.17 56.53 800.00 29.00 314.61 779.41 635.01 87.30 900.00 35.00 314.62 864.18 719.78 124.51 1,000.00 41.00 314.63 942.94 798.54 167.73 1,100.00 47.00 314.63 1,014.84 870.44 216.51 1,200.00 53.00 314.63 1,079.09 934.69 270.31 1,300.00 59.00 314.64 1,134.98 990.58 328.53 1,312.59 59.76 314.64 1,141.40 997.00 336.14 Beluga 1 -739.81 2,234,178.6004 209,111.9747 0.0000 1,022.53 1,400.00 65.00 314.64 1,181.91 1,037.51 390.54 1,500.00 71.00 314.64 1,219.35 1,074.95 455.66 1,600.00 77.00 314.64 1,246.91 1,102.51 523.17 1,614.22 77.85 314.64 1,250.00 1,105.60 532.93 7 5/8" x 9-7/8" -1,085.31 2,234,536.3331 208,774.9839 3.0000 1,641.94 79.52 314.65 1,255.44 1,111.04 552.03 End Dir : 1641.94' MD,1255.44' TVD 3.0000 1,692.65 .1,205.45 1,700.00 79.52 314.65 1,266.00 1,121.60 592.15 1,800.00 79.52 314.65 1,284.20 1,139.80 661.24 1,900.00 79.52 314.65 1,302.39 1,157.99 730.34 2,000.00 79.52 314.65 1,320.59 1,176.19 799.44 2,100.00 79.52 314.65 1,338.78 1,194.38 868.54 2,200.00 79.52 314.65 1,356.98 1,212.58 937.64 2,249.87 79.52 314.65 1,366.05 1,221.65 972.10 Start Dir 3°/100' : 2249.87' MD, 1366.05 TVD 2,300.00 79.42 316.17 1,375.22 1,230.82 1,007.19 2,400.00 79.25 319.22 1,393.73 1,249.33 1,079.86 2,500.00 79.10 322.27 1,412.52 1,268.12 1,155.91 2,589.39 79.00 325.00 1,429.50 1,285.10 1,226.58 Start Dir 3°/100' : 2589.39' MD, 1429.50'TVD . Kalotsa 6 Beluga 10 2,600.00 78.68 325.05 1,431.55 1,287.15 1,235.10 2,638.12 77.55 325.21 1,439.40 1,295.00 1,265.71 Beluga 10 8/222019 2:30:44PM Pace 3 COMPASS 5000.15 Build 91 Map Map +EI -W Northing Easting DLS Vert (usft) (usft) (usft) -126.40 Section 0.00 2,233,430.6720 209,833.9930 0.0000 0.00 0.00 2,233,430.6720 209,833.9930 0.0000 0.00 0.00 2,233,430.6720 209,633.9930 0.0000 0.00 0.00 2,233,430.6720 209,833.9930 0.0000 0.00 0.00 2,233,430.6720 209,833.9930 0.0000 0.00 -0.62 2,233,431.2985 209,833.3856 4.0000 0.86 -5.60 2,233,436.3059 209,828.5312 4.0000 7.72 -9.94 2,233,440.6807 209,824.2901 4.0000 13.71 -15.82 2,233,446.6073 209,818.5489 6.0000 21.82 -33.05 2,233,463.9869 209,801.7360 6.0000 45.60 -57.39 2,233,488.5676 209,777.9772 6.0000 79.22 -88.59 2,233,520.0803 209,747.5326 6.0000 122.32 -126.29 2,233,558.1796 209,710.7360 6.0000 174.41 -170.09 2,233,602.4482 209,667.9903 6.0000 234.94 -219.50 2,233,652.4010 209,619.7641 6.0000 303.24 -273.99 2,233,707.4907 209,566.5856 6.0000 378.55 -332.96 2,233,767.1138 209,509.0375 6.0000 460.06 -340.67 2,233,774.9119 209,501.5112 6.0000 470.72 -395.76 2,233,830.6169 209,447.7504 6.0000 546.87 461.70 2,233,897.3045 209,383.3955 6.0000 638.03 -530.06 2,233,966.4457 209,316.6782 6.0000 732.54 -539.93 2,233,976.4332 209,307.0412 6.0000 746.19 -559.27 2,233,995.9956 209,288.1657 6.0000 772.93 -599.89 2,234,037.0771 209,248.5272 0.0000 829.08 -669.85 2,234,107.8387 209,180.2510 0.0000 925.81 -739.81 2,234,178.6004 209,111.9747 0.0000 1,022.53 -809.77 2,234,249.3621 209,043.6985 0.0000 1,119.25 -879.73 2,234,320.1237 208,975.4223 0.0000 1,215.97 -949.69 2,234,390.8854 208,907.1460 0.0000 1,312.70 -984.57 2,234,426.1730 208,873.0979 0.0000 1,360.93 -1,019.17 2,234,462.0930 208,839.3517 3.0000 1,409.52 -1,085.31 2,234,536.3331 208,774.9839 3.0000 1,506.98 -1,147.45 2,234,613.8516 208,714.6882 3.0000 1,604.92 -1,199.49 2,234,685.7500 208,664.3700 3.0000 1,692.65 .1,205.45 2,234,694.4175 208,658.6116 3.0000 1,703.05 -1,226.78 2,234,725.5230 208,638.0274 3.0000 1,740.35 8/222019 2:30:44PM Pace 3 COMPASS 5000.15 Build 91 i Halliburton H A L L I B U R TO N Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Kalolsa 6 Company: Hilcorp Alaska, LLC TVD Reference: As -Built @ 144.40usft (HEC 169) Project: Ninilchik Unit MD Reference: As -Built @ 144.40usft (NEC 169) Site: Kalotsa North Reference: True Well: Kalotsa 6 Survev Calculation Method: Minimum Curvature Wellbore: Kalotsa 6 Depth Inclination Azimuth Design: Kalotsa 6 Wp04 +NlS +E/ -W Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NlS +E/ -W Northing Easting DLS Vert (usft) (°) (°) (usft) usft (usft) (usft) (usft)(usft) 1,309.31 Section 2,700.00 75.71 325.48 1,453.71 1,309.31 1,315.23 -1,261.02 2,234,775.8536 208,604.9922 3.0000 1,800.56 2,800.00 72.74 325.92 1,480.88 1,33648 1,394.71 -1,315.25 2,234,856.6225 208,552.6899 3.0000 1,896.77 2,900.00 69.78 326.38 1,513.00 1,368.60 1,473.35 -1,368.00 2,234,936.5027 208,501.8480 3.0000 1,991.44 3,000.00 66.81 326.85 1,549.99 1,405.59 1,550.91 .1,419.12 2,235,015.2754 208,452.6059 3.0000 2,084.31 3,100.00 63.84 327.35 1,591.73 1,447.33 1,627.20 -1,468.48 2,235,092.7247 208,405.0986 3.0000 2,175.11 3,200.00 60.88 327.87 1,638.11 1,493.71 1,701.99 -1,515.93 2,235,168.6381 208,359.4563 3.0000 2,263.59 3,246.84 59.49 328.13 1,661.40 1,517.00 1,736.45 -1,537.47 2,235,203.6076 208,338.7551 3.0000 2,304.18 Beluga 34 3,300.00 57.92 328.42 1,689.01 1,544.61 1,775.09 -1,561.36 2,235,242.8078 208,315.8041 3.0000 2,349.53 3,400.00 54.96 329.01 1,744.29 1,599.89 1,846.29 -1,604.63 2,235,315.0303 208,274.2616 3.0000 2,432.67 3,500.00 52.00 329.65 1,803.80 1,659.40 1,915.40 -1,645.62 2,235,385.1078 208,234.9427 3.0000 2,512.80 3,512.30 51.64 329.73 1,811.40 1,667.00 1,923.75 -1,650.50 2,235,393.5679 208,230.2663 3.0000 2,522.44 Beluga 44 3,556.77 50.32 330.03 1,839.40 1,695.00 1,953.64 -1,667.84 2,235,423.8647 208,213.6511 3.0000 2,556.87 Beluga 45 3,600.00 49.05 330.34 1,867.37 1,722.97 1,982.23 -1,684.23 2,235,452.8481 208,197.9552 3.0000 2,589.69 3,624.29 48.33 330.51 1,883.40 1,739.00 1,998.10 -1,693.23 2,235,468.9278 208,189.3347 3.0000 2,607.86 Beluga 47A 3,700.00 46.10 331.09 1,934.82 1,790.42 2,046.60 -1,720.34 2,235,518.0656 208,163.4004 3.0000 2,663.14 3,800.00 43.16 331.92 2,005.98 1,861.58 2,108.33 -1,753.86 2,235,580.5815 208,131.3731 3.0000 2,732.93 3,872.00 41.04 332.58 2,059.40 1,915.00 2,151.04 -1,776.34 2,235,623.8230 208,109.9283 3.0000 2,780.82 Beluga 51 3,900.00 40.22 332.85 2,080.65 1,936.25 2,167.25 -1,784.70 2,235,640.2244 208,101.9611 3.0000 2,798.89 3,923.13 39.54 333.08 2,098.40 1,954.00 2,180.46 -1,791.44 2,235,653.5942 208,095.5387 3.0000 2,813.58 Beluga 52 4,000.00 37.29 333.90 2,158.62 2,014.22 2,223.20 -1,812.77 2,235,696.8310 208,075.2449 3.0000 2,860.82 4,100.00 34.38 335.09 2,239.68 2,095.28 2,276.02 -1,838.00 2,235,750.2460 208,051.2978 3.0000 2,918.56 4,200.00 31.47 336.48 2,323.61 2,179.21 2,325.57 -1,860.31 2,235,800.3230 208,030.1855 3.0000 2,971.96 4,241.69 30.27 337.13 2,359.40 2,215.00 2,345.24 -1,868.74 2,235,820.1828 208,022.2344 3.0000 2,992.90 Beluga 58A 4,250.98 30.00 337.28 2,367.43 2,223.03 2,349.53 -1,870.54 2,235,824.5233 208,020.5322 3.0000 2,997.46 End Dir : 4250.98' MD, 2367.43' TVD 4,300.00 30.00 337.28 2,409.88 2,265.48 2,372.14 -1,880.01 2,235,847.3528 208,011.6140 0.0000 3,021.41 4,306.37 30.00 337.28 2,415.40 2,271.00 2,375.08 -1,881.24 2,235,850.3191 208,010.4552 0.0000 3,024.52 Beluga 59 4,400.00 30.00 337.28 2,496.49 2,352.09 2,418.26 -1,899.32 2,235,893.9252 207,993.4208 0.0000 3,070.27 4,406.83 30.00 337.28 2,502.40 2,358.00 2,421.41 -1,900.63 2,235,897.1053 207,992.1785 0.0000 3,073.60 Beluga 65 4,446.09 30.00 337.28 2,536.40 2,392.00 2,439.52 -1,908.21 2,235,915.3895 207,985.0359 0.0000 3,092.78 Beluga 70 4,474.96 30.00 337.28 2,561.40 2,417.00 2,452.84 -1,913.79 2,235,928.8338 207,979.7839 0.0000 3,106.89 Beluga 72 4,500.00 30.00 337.28 2,583.09 2,438.69 2,464.39 -1,918.62 2,235,940.4976 207,975.2276 0.0000 3,119.13 4,600.00 30.00 337.28 2,669.69 2,525.29 2,510.51 -1,937.93 2,235,987.0700 207,957.0343 0.0000 3,167.98 4,682.80 30.00 337.28 2,741.40 2,597.00 2,548.70 -1,953.92 2,236,025.6327 207,941.9701 0.0000 3,208.44 Beluga 82 8!222019 2:30:44PM Page 4 COMPASS 5000.15 Build 91 HALLIBURTON Halliburton Standard Proposal Report Database: Companv: Protect: Site: Well: Wellbore: Design: NORTH US +CANADA Hiicorp Alaska, LLC Ninilchik Unit Kalotsa Kalotsa 6 Kalatsa 6 Kalotsa 6 Wp04 +E/ -W Northing Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well Kalotsa 6 As -Built @ 144.40usft (NEC 169) As -Built @ 144.40usft (HEC 169) True Minimum Curvature (usft) (usft) Planned Survey (usft) 0.00 0.00 1,429.50 1,226.58 -1,199.49 2,234,685.7500 208,664.3700 0.00 0.00 3,603.50 3,007.82 -2,146.13 2,236,489.2500 207,760.8600 (usft) Measured ("l Vertical 1,614.22 1,250.00 7 518" x 9-718" Map 9-7/8 Map 6,000.00 3,882.13 41/2"x6-3/4' Depth Inclination 6-314 Azimuth Depth TVDSs +N/ -S +E/ -W Northing Easting DLS Vert (usft) (°) (1 (usft) usft (usft) (usft) (usft) (usft) 2,611.89 Section 4,700.00 30.00 337.28 2,756.29 2,611.89 2,556.63 -1,957.24 2,236,033.6423 207,938.8411 0.0000 3,216.84 4,800.00 30.00 337.28 2,842.90 2,698.50 2,602.75 -1,976.55 2,236,080.2147 207,920.6479 0.0000 3,265.70 4,900.00 30.00 337.28 2,929.50 2,785.10 2,648.87 -1,995.86 2,236,126.7871 207,902.4547 0.0000 3,314.56 5,000.00 30.00 337.28 3,016.10 2,871.70 2,694.99 -2,015.17 2,236,173.3595 207,884.2615 0.0000 3,363.42 5,100.00 30.00 337.28 3,102.70 2,958.30 2,741.11 -2,034.48 2,236,219.9318 207,866.0683 0.0000 3,412.28 5,200.00 30.00 337.28 3,189.31 3,044.91 2,787.24 -2,053.78 2,236,266.5042 207,847.8751 0.0000 3A61.14 5,300.00 30.00 337.28 3,275.91 3,131.51 2,833.36 -2,073.09 2,236,313.0766 207,829.6819 0.0000 3,510.00 5,400.00 30.00 337.28 3,362.51 3,218.11 2,879.48 -2,092.40 2,236,359.6490 207,811.4887 0.0000 3,558.86 5,500.00 30.00 337.28 3,449.11 3,304.71 2,925.60 -2,111.71 2,236,406.2214 207,793.2955 0.0000 3,607.72 5,534.97 30.00 337.28 3,479.40 3,335.00 2,941.73 -2,118.46 2,236,422.5080 207,786.9332 0.0000 3,624.80 Beluga 131 5,597.32 30.00 337.28 3,533.40 3,389.00 2,970.49 -2,130.50 2,236,451.5477 207,775.5890 0.0000 3,655.27 Beluga 134 5,600.00 30.00 337.28 3,535.72 3,391.32 2,971.72 -2,131.02 2,236,452.7937 207,775.1023 0.0000 3,656.58 5,678.27 30.00 337.28 3,603.50 3,459.10 3,007.82 -2,146.13 2,236,489.2467 207,760.8622 0.0000 3,694.82 Kalotsa 6 Beluga 135 5,700.00 30.00 337.28 3,622.32 3,477.92 3,017.84 -2,150.33 2,236,499.3661 207,756.9091 0.0000 3,705.44 5,742.82 30.00 337.28 3,659.40 3,515.00 3,037.59 -2,158.59 2,236,519.3069 207,749.1193 0.0000 3,726.36 Beluga 136 5,800.00 30.00 337.28 3,708.92 3,564.52 3,063.96 -2,169.64 2,236,545.9385 207,738.7159 0.0000 3,754.30 5,900.00 30.00 337.28 3,795.52 3,651.12 3,110.08 -2,188.94 2,236,592.5109 207,720.5227 0.0000 3,803.16 6,000.00 - 30.00 337.28 3,882.13 • 3,737.73 3,156.21 -2,208.25 2,236,639.0832 207,702.3294 0.0000 3,852.01 Total Depth : 6000.00' MD, 3882.13' TVD -41/2" x 6-314" Targets Target Name - hit/miss target -Shape Kalotsa 6 Beluga 10 - plan hits target center - Circle (radius 100.00) Kalotsa 6 Beluga 135 - plan hits target center -Circle (radius 100.00) Dip Angle Dip Dir. TVD +Nl-S +E/ -W Northing Easting (usft) (usft) (usft) (usft) (usft) 0.00 0.00 1,429.50 1,226.58 -1,199.49 2,234,685.7500 208,664.3700 0.00 0.00 3,603.50 3,007.82 -2,146.13 2,236,489.2500 207,760.8600 Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usftl (usft) Name ("l 1,614.22 1,250.00 7 518" x 9-718" 7-5/8 9-7/8 6,000.00 3,882.13 41/2"x6-3/4' 4-1/2 6-314 120.00 120.00 16" 16 24 8/222019 2:30:44PM Pace 5 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US + CANADA Company: Hiloorp Alaska, LLC Project: Ninilchik Unit +N/ -S Site: Kalotsa (usft) Well: Kalotsa 6 (usft) Wellbore: Kalotsa 6 250.00 Design: Kalotsa 6 Wp04 Formations 450.00 449.35 9.77 Measured Vertical Vertical 1,641.94 Depth Depth Depth SS -559.27 (usft) (usft) 1,366.05 3,923.13 2,098.40 Start Dir 3°/100' : 2249.87' MD, 1366.05'TVD 2,638.12 1,439.40 1,226.58 4,474.96 2,561.40 4,250.98 5,597.32 3,533.40 -1,870.54 3,872.00 2,059.40 3,882.13 3,556.77 1,839.40 Total Depth : 6000.00' MD, 3882.13' TVD 3,246.84 1,661.40 5,534.97 3,479.40 1,312.59 1,141.40 4,406.83 2,502.40 3,624.29 1,883.40 4,306.37 2,415.40 4,241.69 2,359.40 4,682.80 2,741.40 3,512.30 1,811.40 4,446.09 2,536.40 5,742.82 3,659.40 Plan Annotations Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Name Beluga 52 Beluga 10 Beluga 72 Beluga 134 Beluga 51 Beluga 45 Beluga 34 Beluga 131 Beluga 1 Beluga 65 Beluga 47A Beluga 59 Beluga 58A Beluga 82 Beluga 44 Beluga 70 Beluga 136 Halliburton Standard Proposal Report Well Kalotsa 6 As -Built @ 144.40usft (HEC 169) As -Built @ 144.40usft (HEC 169) True Minimum Curvature Dip Dip Direction Lithology (1) (') Measured Vertical Local Coordinates Depth Depth +N/ -S +El -W (usft) (usft) (usft) (usft) Comment 250.00 250.00 0.00 0.00 Start Dir 4°/100':250' MD, 250'TVD 450.00 449.35 9.77 -9.94 Start Dir 6'/100': 450' MD, 449.36TVD 1,641.94 1,255.44 552.03 -559.27 End Dir : 1641.94' MD, 1255.44' TVD 2,249.87 1,366.05 972.10 -984.57 Start Dir 3°/100' : 2249.87' MD, 1366.05'TVD 2,589.39 1,429.50 1,226.58 -1,199.49 Start Dir 3°/100': 2589.39'MD, 1429.50'TVD 4,250.98 2,367.43 2,349.53 -1,870.54 End Dir :4250.98' MD, 2367.43' TVD 6,000.00 3,882.13 3,156.21 -2,208.25 Total Depth : 6000.00' MD, 3882.13' TVD 8222019 2:30:44PM Pace 6 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Ninilchik Unit Kalotsa Kalotsa 6 Kalotsa 6 Kalotsa 6 Wp04 Sperry Drilling Services Clearance Summary Anticollision Report 22 August, 2019 Closest ApPraach 3D Proximity Scan oa Current Survey Data (North Reference) Reference Design: Keleher - emotes 6 - Kali 6 - Kdolsa 6 Went Well Coordinates: 2,233,430.67 N, 209,633.99 E(60°06'1443 N, 151.35'24.60"W) Datum Height: AsBuiltft, 1"Aar ift (HEC 169) Sean Range: 0.00 to 600LG0 u ift Measured Depth. Scan Radius is Unlimited. Clearance Factor smog is Unlimited. Max Ellipse Separation is I'la W us% Geodetic Scale Factor Applied Version 5000.15 Build 91 Scan Type: GLOBAL FILTER APPLIED: All wellpalhe when 200410011000 ofeelerem'z Seen Type; 2500 HALLIBURTON Sperry Drilling Services HALLIBURTON Anticollision Report for Kalotsa 6 - Kalotsa 6 Wp04 Closest Approach 3D Pr0aimity Soan on Cu pant Survey Data Worth Reterencel Reference Design: Kem. -Kalotsa 6- Needs. 6 -Kalotsa 6 Wi," Seen Renpe. 0.00 to 6,000.00 man. Measured Depth. Seen Radius is Unlimited. Clearance Factor cutoff Is UnIlmNed. Max Ellipse Separation is 1,000.00 use Measure Minimum OTMeasure See Name d Distance d Comparison Well Name - Wellbore Name-neelgn o.mn Cum o.mh Kalotsa Kaloba 1- Kalotsa 1 - Kalotsa 1 934.51 40AS 934.51 Kabtsa l - Kaloba 1-Ka10&a1 950.00 40.29 95000 Kab1581 -Kalotsa 1- Kalotsa 1 975.00 41.14 97500 Ketones 2-Kalotsa 2- Koons 2 585.30 65.64 565.30 Kalotsa 2-Kalotsa 2- Kalotsa 2 650.00 68.65 650.00 Kalotsa 3 -lesions 3- Obtain 3 18,00 107,90 18.00 Kalotsa 3 - Kalesa 3- Ketone 3 100 011 108.01 100.00 Kalotsa 3- Kabba 3 -Kaloba 3 1,075.00 159 78 1,075.00 Kelplse 4- Kam. 4- "loss 4 864.65 103.93 864.65 Kalotsa 4-Kalo15a 4-Kate..4 875.00 103.98 875.00 Kabtea 4-Kalotsa 4- Komar 4 95000 107.50 950.00 Katotm 5-Kelmusa 5-Keletaa5 WD03 100.00 46.38 100.00 Ketone 5-Kabotaa 5-Kalosi5 Wp03 179.13 4636 179.13 Kalmar 5-Kalemsa 5-Kalotsa 5 W003 425.00 57,84 42500 Susan Dionne Susan Dianne ild-Susan Dionne as - Susan Dionne Ar 5,05944 250.73 5,669.44 Susan Dionne #4 -Susan Dionne 114 -Susan Dianne# 5,750.00 25924 5,750.00 Susan Dionne #4 -Susan Dianne #4 -Susan Dionne# 5,77500 265.09 5,77500 Survev tool oragrarg From To SumeylPlan 1 -ft, /meet 10.00 1,614.00 Kelm.6 Wp04 1,61400 a0sen00 Kalotsa 6 Wp0i Hilcorp Alaska, LLC Ninilchik Unit Ellipse sipsasam Osumnce Summaryaased Separation d F.m, on Minimum Separation Warning mzel n.mh 3242 910.91 5.190 Centre Distance Pass - 32.39 934.02 5.104 Ellipse Separation Pass - 33.01 95636 5.061 Clearance Factor Pass - 61.28 581.35 15.068 Ellipse Separation Paea- 0.03 642.74 14.243 Clearance Factor Pass - 106.08 18.00 59.353 Centre Olstanee Pass - 105.96 9981 52.920 Ellipse Separation Pass - 150.76 1,019.89 17.723 Clearanee Feeler Pass - 9] 25 862.67 15.503 Centre Distance Pas. - 9Z23 072.89 15,402 Ellipse Separation Pass - 100.35 940.95 14887 Clearance Fahr Pass - 43.55 100.10 16405 Ellipse Separation Pass - 44.12 179.23 20.544 Centre Distance Pass - 54.05 419.57 15.237 Claimer. Factor Pass - 103.74 6,001.56 1306 Centre Distance Pass - 9189 6,847.03 1,549 Ellipse Separation Pass - 93.03 6.862,62 1.541 Clearance Factor Pass - Survey T001 3 MWD+IFRI+MS+Sag 3_1,1WUHFRI+0S+Sag 22 Aussua6 2019 - 14:18 Page I0I5 COMPASS HALLIBURTON Anticollision Report for Kalotsa 6 - Kalotsa 6 Wp04 Ellipse enar terms are correlated across sure tool tie -on points. Calculated ellipses inmParate surface amens. Separation is the actual disiame between ellipsoids. Dintanm Between canoes is Me sozght line distance between wellbore maims, Clemmos EaCWy Olstanm Betemn Profiles(Olstanm BeNrcen Profiles- Ellipse Sepamdon). All station coordinates ware m1culatad using Ste Minimum CumaNre method. Hilcorp Alaska, LLC Niniichik Unit 22 Austral, 2019 - 1418 Page 3 ots COMPASS HALLIBRTCN BPI, Orlill Nelafsa K.1.11. 2 Pmjecl: NInndnk LI Site Kaloba Well: Kelotaa 6 Wellbore: KNalsa 6 Plan: Kel. 5 W'm Ladder/ S.F. Plots REFERENCE INFORMATION ale 1N/El Nefeners Wq NMpafi. True NylM1 elp Iq ,veerco-' Aalal®fJJ..IEC1591 Mrvavu�mGkWlion 4kNM ektinu �C1N�Iepu¢61.EC 1881 sumEV lmDDgnu Wb'281ae81]llp%eW wRWe1. Yv VMm. DepN Fm n¢yN b sumyNlan Tod m 6IleaWW106 aMVOrlFgleMav&g fefAW I..W I. W 6 [d lWbPe61 7_MxD�IFg1rM5.ya Measured Depth %M DETAJUX w6 W 192](NApCON CONL51 AWFa .. 126 J0 ENua Intilrvh Im®wh O.W DW •�IIJ]0.6]20 O.wY.67'0 2W8119910 151°JS W.6BIOW GLOBAL FILTER APPLIED: All mPa016 unman 200'+ IOOIION of Me - 16.00 Ta IWOODo CASING DETAILS TVD TVDSS No Sim Name 120.00-2d 40 12000 16 16' 1250.00 110560 161422 7518 754'.9-]/8° 3882.13 3737.73 6000.0 6lP 41-x6-3/4" 3850 4200 Measured Depth Schwartz, Guy L (CED) From: David Gorm <dgorm@hilcorp.com> Sent: Monday, September 9, 2019 1:45 PM To: Schwartz, Guy L (CED) Subject: RE: [EXTERNAL] Kalotsa #6 ( PTD 219-114) Attachments: Kalotsa 6 drilling program, Cement.pdf Guy, 1) Please see attached file with the Cement blend and volumes 2) The mud push spacer does not have corrosion inhibitor. Let me know if you have any other questions. Thanks, David Gorm Drilling Engineer Hilcorp Alaska Office: 907-777-8333 Cell: 505-215-2819 From: Schwartz, Guy L (CED) [mailto:guy.schwartz@alaska.gov) Sent: Monday, September 9, 2019 11:04 AM To: David Gorm <dgorm@hilcorp.com> Subject: [EXTERNAL] Kalotsa #6 ( PTD 219-114) David, 1) For the 4.5" cement job I don't see what type of cement is being used for the lead and tail. Can you send me the info on that.. 2) Does the 10.5 ppg mud push spacer have any corrosion inhibitors in it? I think I have asked Monty that before but don't recall what he said. 3) 1 bumped BOPE test pressure to 3500 psi (from 2500 psi) to match the required casing pressure tests. 4) Submit a separate sundry to perforate the well after rig moves. You may have to use a tractor or CTU. 5) The IA will need to be tested to 2000 psi after WOC as well as a CBL to verify TOC in the 4.5". Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged Remark: AOGCC Coordinate Check PTD 219-114 30 August 2019 INPUT Geographic, NAD27 OUTPUT State Plane, NAD27 5004 - Alaska 4, U.S. Feet Kalotsa-6 1/1 Latitude: 60 06 14.43280 Northing/Y: 2233430.668 Longitude: 151 35 24.68100 Easting/X: 209833.994 Convergence: -1 22 43.22518 Scale Factor: 0.999995821 Corpscon v6.0.1, U.S. Army Corps of Engineers TRANSMITTAL LETTER CHECKLIST WELL NAME: PTD: Development _ Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: /Y� i1 I ,'/C l G� , POOL: fes/ a. uz d S 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 for also required 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 Field & Pool NINILCHIK, BELUGA-TYONEK GAS - 562503 PTO* 2191140 Company H I_com_Alas_ta LC Initial Class/Type Well Name: NINILCHIK UNIT KALOTSA 6 Program DEV Well bore seg ❑ DEV / PEND GeoArea 820 Unit 51432 On/Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached --------- ---------------------------- NA __----....---_-----_... Commissioner: 2 Lease number appropriate. - - _ - - - - - - - - - - - - - - - - -- - - - - - Yes - - - .... Surface location on fee-CIRl.property; top. prod. interval and TD in ADL 384372_ ►SSS 3 Unique well-name and number - - - - - - - - - _ . Yes � �/lo �� 4 Well located in a. defined pool - . . . .... . . . . . . ..... Yes - - - - _ NINILCHIK, BELUGA-TYONEK GAS - 562503, governed by CO 701C. 5 .Well located proper distance from drilling unit boundary- - ...... ... - - - - .. - . Yes - - - - - CO 701C, Rule 3 Well Spacing: As planned, this well. conforms-to CO 701C, Rule.3 (Well Spacing). - - 6 Well located proper distance from other wells. .. ... Yes 7 Sufficient acreage available in drilling unit- - - - - - - - - - - ----- - - - - Yes 8 If deviated. is wellbore plat included - - - - - ... - - - - - - - - Yes 9 Operator only affected party ...................................... Yes 10 Operator has appropriate_ bond in forceYes --------------------- - -- --- 11 Permit can be issued without Conservation order . ........ . . . . . . . Yes Appr Date 12 Permit can be issued without administrativeapproval- - - - - - - _ .. .. _ Yes - - - -- - - - - - - - ------- - - - - - - - - -- - - i13 Can permit be approved before 15-day wait Yes- SFD 9/9/2019 - - _ - - - - .... - _ 14 Welllocated within area and strata authorized by Injection Order # (put 10# In.comments) (For- NA - - - - 15 All wells. within 114. mile area of review identified (For service well only)- - NA 16 Pre-produced injector; duration of pre-production Less than 3 months,(For.servfce welt only) - ..NA.. - - - - - - - - 17 Nionconven. gas conforms to AS31,05.030Q.1.A),Q.2.A-D) _______ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA. _ _ _ _ _ . - - - - - - - - _ - ....... 18 Conductor stringprovided. - _ _ _ _ __ _ _ _ _ _ _ _ _ _ _ Yes - - - ... 16" conductor set at 115 ft.. Engineering 19 Surface casingprotectsall known USDWs - - - - - - ----- - - - - - - - - ........ NA - permafrost area waiver from EPA 20 CMT vol adequate to circulate on conductor & surf csg .. - - - - - - - - --- - - - - - Yes - 7 5/8". casing will be set at 1600 ft and fully cemented..... - - 21 CMT vot adequate. to tie-in long string to surf csg..... . . . . . . . . ....... - - Yes 4.5" production casing will be cemented back t0.7 518" and also use swell. packer. 22 CMT will cover all known productive horizons----- - - - - - - - - ----- - - - - - - - - Yes 23 Casing designs adequate for C, T, B &. permafrost- - _ .. - .. - - - . - - .. Yes - - - - BTC calculations are provided.. Easily meet API standards.... - - 24 Adequate tankage-or reserve pit ..... - - - - - - . - ..... - - - .. Yes - - Rig has steel pits,.., waste will be transported to KGF.G & J - 25 Jf,a. re-drill, has 10-403 for abandonment been approved. ................. NA_.---_____.. 26 Adequate wellbore separation proposed- _ - - - _ - - - - - - - - - ....... Yes - - - - - - No close crossing issues..... 27 If diverter required, does it meet regulations_ - _ .. _ - NA_ - - . - Diyarter waiver per 20 AAC 25.035(h)(2) -. _. no shallow gas on pad Appr Date 28 Drilling fluid_ program schematic & equip list adequate- - - - - - - - _ - - - Yes ...... _ Max formation_ press= 1746-psi- (8.6_ppg EM.W) will drill with 9.5-.10 ppg mud - - GLS 9/9/2019 29 BOPEs,-do they meet regulation - - - - - - - - - - - - - - - - _ _ - - _ _ - - No _ - . -rig 169 has 5000 psi WP ROPE .. 11"_ 30 BOPE-press rating appropriate; test to _(put psig in comments)- - - - - - - - - - - - - - Yes . - . - ... MASP = 13&8 psi, Will test BOPE to 3500 for casing test limit. 31 Choke manifold complies w/API_RP-51(May 84)-__-_-- -.-. ....--.--..:Yes ------------------------------------------ 32 Work will occur without operation shutdown. - - - - - - - - - .... _ . Yes - - - - - Need sundry for perforations...... . . . . . ..... 33 Is presence of 1-12S gas probable - - - ----------- - - - - - - - - - - - - - No- 34 Mecbanical condition of wells within AOR verified (For service well only) - - - - - - - - - - - - - - NA.... - - - - - - - - .... - - _ _ _ - _ _ _ _ . _ .. . 35 Permit can be issued w/o hydrogen sulfide measures . ............. . . . . . . ..... Yes - - - - - 1-12S is not anticipated based on nearby wells. Geology 36 Data presented on potential overpressure zones - - - - - - - - - - - - - - - - - - - ------ - -- Yes - - - - - Operator's_ planned_ mudprogramappears adequate tocontrolforecast pressures.. Appr Date 37 Seismic analysis of shallow gaszones. . . . . ........ - - - - - - - ... NA - - - - - - - - - SFD 9/9/2019 38 Seabed condition survey (if offshore) _ _ _ _ _ _ _ _ _ _ _ ____ - . NA 39 Conlact name/phone for weekly-progress reports [exploratory only] - _ NA . . . . . . . .... ..... . . . . . - - _ Geologic Date: Engineering Public CBL and MIT -IA required after rig leaves. GIs Commissioner: Commissioner: Date Commissioner Date ►SSS 5 � 1R � �/lo ��