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Home My WebLink About220-0671. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Development Exploratory 3. Address:Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 9,785 feet 7,600, 9,350 feet true vertical 8,385 feet N/A feet Effective Depth measured 7,600 feet 1,321 feet true vertical 6,422 feet 1,221 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 1,321' MD 1,221' MD NA; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date:Contact Name: Contact Email: Authorized Title:Contact Phone: 7,500psi 2,980psi 6,880psi 8,430psi 1,567'1,258' Burst Collapse 1,410psi 4,790psi Casing Structural 8,375'9,775' 127'Conductor Surface Intermediate 16" 7-5/8" 127' 1,567' measured TVD 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 220-067 50-133-20693-00-00 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 Field / Beluga/Tyonek Gas Pool Kalotsa 7 Plugs Junk measured Length Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 51 Size 127' 0 1022100 0 400 59 Production Liner 9,775' Scott Warner, Operations Engineer 325-017 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: WINJ WAG 943 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 N/A scott.warner@hilcorp.com 907-564-4506 measured true vertical Packer Representative Daily Average Production or Injection Data p k ft t Fra O s 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 9:57 am, Mar 17, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.03.14 16:58:19 - 08'00' Noel Nocas (4361) BJM 5/2/25 RBDMS JSB 032525 DSR-3/25/25 Page 1/1 Well Name: NINU Kalotsa 07 Report Printed: 3/5/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Wellbore API/UWI:50-133-20693-00-00 Field Name:Ninilchik State/Province:Alaska Permit to Drill (PTD) #:220-067 Sundry #:325-017 Rig Name/No: Jobs Actual Start Date:2/6/2025 End Date: Report Number 1 Report Start Date 2/12/2025 Report End Date 2/12/2025 Last 24hr Summary D&T w/ 3.75'' g-ring to 6096'kb. Drift dummy guns to 6096'kb no obstruction PTW/PJSM. FTP 45 psi. RU Pollard Slickline. PT lubricator 250 psi low / 2500 psi high - good test. RIH w/ 3.75" GR and tag @ 6,096' RKB. RIH w/ 3.75" blind box- didn't see fluid level. RIH w/ 2 7/8" x 20' dummy gun and tag @ 6,096' RKB. Secure well and RD Pollard. Report Number 2 Report Start Date 2/14/2025 Report End Date 2/14/2025 Last 24hr Summary PTW/PJSM. SITP 220 psi. MIRU YJ Eline. PT lubricator to 250 psi low / 2500 psi high - good test. RIH w/ GPT and tag @ 6,125' - no fluid level. RIH w/ 6'x14' 2 3/4" 6SPF 60DEG guns on switch and perf TY_15 (6,040’ – 6,046’) and TY_14 (5,970’ – 5,984’). RIH w/ 6'x6'x6' 2 3/4" 6SPF 60DEG guns on switch and perf TY_11A (5,506’ – 5,512’), TY_11A Lower (5,454’ – 5,460’), and TY_11A Upper (5,412’ – 5,418’). Secure well and flow test. Report Number 3 Report Start Date 2/15/2025 Report End Date 2/15/2025 Last 24hr Summary PTW/PJSM. SITP 245 psi. RU YJ Eline. RIH w/ 6'x6'x6' 2 3/4" 6SPF 60DEG guns on switch and perf TY_10B Lower (5,392’ – 5,398’), TY_10B Middle (5,378’ – 5,384’), and TY_10B Upper (5,359’ – 5,365’). RIH w/ 10'x6'x6' 2 3/4" 6SPF 60DEG guns on switch and perf TY_10A (5,344’ – 5,354’), TY_9 (5,199’ – 5,205’), and TY_7 Lower (5,117’ – 5,123’). RIH w/ 6'x6'x6' 2 3/4" 6SPF 60DEG guns on switch and perf TY_7 Upper (5,041’ – 5,047’), TY_6 Lower (5,009’ – 5,015’), and TY_6 Middle (4,983’ – 4,989’). RIH w/ 20' 2 3/4" 6SPF 60DEG guns and perf TY_6 Middle (4,963’ – 4,983’). RIH w/ 20' 2 3/4" 6SPF 60DEG guns and perf TY_6 Upper (4,920’ – 4,940’). Secure well and flow test. Report Number 4 Report Start Date 2/16/2025 Report End Date 2/16/2025 Last 24hr Summary PTW/PJSM. SITP 310 psi. RU YJ Eline. RIH w/ 13' 2 3/4" 6SPF 60DEG guns and perf TY_6 Upper (4,907’ – 4,920’). RIH w/ 10'x6'x6' 2 3/4" 6SPF 60DEG guns on switch and perf TY_5a Lower (4,836’ – 4,846’), TY_5a Middle (4,822’ – 4,828’), and TY_5a Upper (4,808’ – 4,814’). RIH w/ 6'x6'x10' 2 3/4" 6SPF 60DEG guns on switch and perf TY_5 (4,788’ – 4,794’), TY_3 Lower (4,705’ – 4,711’), and TY_3 Upper (4,655’ – 4,665’). RIH w/ 24' x 2 3/4" 6SPF 60DEG guns and perf TY_3 Upper (4,631’ – 4,655’). Secure well, RD YJ E-line, and hand off to production. Report Number 5 Report Start Date 2/17/2025 Report End Date 2/17/2025 Last 24hr Summary PTW/PJSM. Well flowing 3.2MM @ 63 psi. RU YJ Eline. RIH w/ 1 11/16" GPT and tag @ 7,467'. Found fluid level @ ~6,130'. Secure well, RDMO YJ E-line. Report Number 6 Report Start Date 2/20/2025 Report End Date 2/20/2025 Last 24hr Summary PTW/PJSM. FTP 59 psi. RU Pollard Slickline. PT 250 low/ 2500 psi. RIH w/ 3.75" GR and tag @ 6,118' RKB. RIH w/ 2 7/8" x 20' dummy gun and tag @ 7,475' RKB. Secure well and RDMO Pollard. Report Number 7 Report Start Date 2/25/2025 Report End Date 2/26/2025 Last 24hr Summary PTW/PJSM. MIRU Yellow Jacket E-line. P-test 250/2,500 psi. Perforate TY_53 Sand (7,424' - 7,434'), TY_37 Sand (6,689' - 6,703'), TY_18 Sand (6,387' - 6,401'), TY_17 Sand (6,281' - 6,289'), TY_17 Sand (6,254' - 6,268'), and TY_17 Sand (6,241' - 6,251') with well shut-in. RDMO. Updated by SRW 2-27-25 Schematic Ninilchik Unit Kalotsa #7 PTD: 220-067 API: 50-133-20693-00-00 PBTD = 7,600’ / TVD = 6,422’ TD = 9,785’ / TVD = 8,385’ RKB to GL = 18’ PERFORATION DETAIL Sands Top (MD)Btm (MD)Top (TVD)Btm (TVD)Ft Date Status TY_3 4,631'4,665'3,803'3,833'34'2/16/25 Open TY_3 4,705'4,711'3,868'3,874'6'2/16/25 Open TY_5 4,788'4,794'3,942'3,947'6'2/16/25 Open TY_5A 4,808'4,814'3,960'3,965'6'2/16/25 Open TY_5A 4,822'4,828'3,972'3,978'6'2/16/25 Open TY_5A 4,836'4,846'3,985'3,994'10'2/16/25 Open TY_6 4,907'4,940'4,085'4,078'33'2/16/25 Open TY_6 4,963'4,989'4,098'4,121'26'2/15/25 Open TY_6 5,009'5,015'4,139'4,144'6'2/15/25 Open TY_7 5,041'5,047'4,167'4,172'6'2/15/25 Open T-6A 5,058’5,078’4,182’4,200’20’1/5/21 Open TY_7 5,117'5,123'4,234'4,239'6'2/15/25 Open T-8 5,146’5,160’4,260’4,272’14’1/5/21 Open T-8 5,164’5,189’4,275’4,297’43’1/5/21 Open TY_9 5,199'5,205'4,306'4,312'6'2/15/25 Open T-9A 5,249’5,261’4,350’4,361’12’1/5/21 Open TY_10A 5,344'5,354'4,434'4,443'10'2/15/25 Open TY_10B 5,359'5,365'4,448'4,453'6'2/15/25 Open TY_10B 5,378'5,384'4,464'4,470'6'2/15/25 Open TY_10B 5,392'5,398'4,477'4,482'6'2/15/25 Open TY_11 5,412'5,418'4,494'4,499'6'2/14/25 Open T-11 5,426’5,435’4,507’4,514’9’1/5/21 Open TY_11 5,454'5,460'4,531'4,536'6'2/14/25 Open TY_11A 5,506'5,512'4,577'4,582'6'2/14/25 Open TY_12 5,631'5,671'4,688'4,724'40'2/14/25 Open TY_14 5,970'5,984'4,986'4,999'14'2/14/25 Open TY_15 6,040'6,046'5,048'5,054'6'2/14/25 Open T-16 6,106’6,115’5,107’5,115’9’1/5/21 Open T-17 6,200’6,237’5,189’5,222’37’1/3/21 Open TY_17 6,241'6,251'5,225'5,234'10'2/25/25 Open TY_17 6,254'6,268'5,237'5,249'14'2/25/25 Open TY_17 6,281'6,289'5,260'5,267'8'2/25/25 Open T-18U 6,328’6,359’5,302’5,329’31’1/2/21 Open T-18L 6,364’6,372’5,334’5,341’8’1/2/21 Open TY_18 6,387'6,401'5,354'5,366'14'2/25/25 Open TY_37 6,689'6,703'5,620'5,632'14'2/25/25 Open TY_53 7,424'7,434'6,266'6,275'10'2/25/25 Open Perforation Detail Continued on Page 2 RA Tags Joint Tops: 1668’, 2077’, 2615’, 3274’, 3729’, 4306’, 4718’, 6129’ (all MD) OPEN HOLE / CEMENT DETAIL 7-5/8"76 bbls of 12ppg lead cement and 32 bbls 15.8ppg tail cement in 9-7/8” hole – 29 bbls returned to surface, no losses during job. 4-1/2” 243 bbls of 12ppg lead cement and 41 bbls 15.3ppg tail cement in 6-3/4” hole – no spacer nor cement to surface. 10 bbl losses during job. Remedial IA cement job pumped on 12/2/20. 22bbls of 15.8 cement. ToC ~1506’ BoC ~1958’ 12/8/20 CBL CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 127' 7-5/8"Surf Csg 29.7 L-80 USS-CDC 6.875”Surf 1,567’ 4-1/2"Prod Csg 12.6 L-80 DWC/C HT 3.958”Surf 9,775’ JEWELRY DETAIL No.Depth ID OD Item 1 1,321’3.958”6.875”Swell Packer 2 7,600’4-1/2” CIBP (1/2/21) 3 9,350’4-1/2” CIBP (12/12/20) 1 16” 7-5/8” 9-7/8” hole 4-1/2” 6-3/4” hole ToC at ~3040’ per 11/18/20 CBL 3 2 T-150 T-146 T-65 to T-140.c T-18U & T-18L T-6A T-8 T-9A T-11 T-16 T-17 Updated by SRW 2-27-25 Schematic Ninilchik Unit Kalotsa #7 PTD: 220-067 API: 50-133-20693-00-00 Perforation Detail Continued from Page 1 T-65 7,631’ 7,662’ 6,450’ 6,477’ 31’ 12/19/20 Isolated (1/2/21) T-67 7,735’ 7,745’ 6,542’ 6,551’ 10’ 12/13/20 Isolated (1/2/21) T-73 7,900’ 7,906’ 6,688’ 6,693’ 6’ 12/13/20 Isolated (1/2/21) T-100 8,437’ 8,449’ 7,162’ 7,172’ 12’ 12/13/20 Isolated (1/2/21) T-140.b 8,865’ 8,882’ 7,539’ 7,554’ 17’ 12/12/20 Isolated (1/2/21) T-140.c 8,888’ 8,904’ 7,559’ 7,574’ 16’ 12/12/20 Isolated (1/2/21) T-146 9,209’ 9,229 7,848’ 7,867’ 20’ 12/12/20 Isolated (1/2/21) T-150 9,363’ 9,393’ 7,990’ 8,017’ 30’ 12/10/20 Isolated (12/12/20) 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): 9,785'N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 7,500psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng scott.warner@hilcorp.com 907-564-4506 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Scott Warner, Operations Engineer AOGCC USE ONLY Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 C061505, ADL384372 220-067 50-133-20693-00-00 Hilcorp Alaska, LLC Proposed Pools: 12.6# L-80 TVD Burst 1,321' 8,430psi 1,258' Size 127' 1,567' MD See Attached Schematic 2,980psi 6,880psi 127'127' 1,567' January 30, 2025 4-1/2" 9,775' Perforation Depth MD (ft): 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 NINU Kalotsa 07CO 701C Same 8,375'4-1/2" ~2131psi 9,775' 7600; 9350 Length Swell Packer ; N/A 1321' / 1221' TVD, N/A 8,385'7,600'6,422' Ninilchik Beluga-Tyonek Gas 16" 7-5/8" See Attached Schematic m n P s 66 t 2 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 11:01 am, Jan 17, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.01.17 10:27:46 - 09'00' Noel Nocas (4361) 325-017 DSR-1/22/25SFD 1/20/2025BJM 1/23/25 10-404 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.01.23 16:02:06 -09'00'01/23/25 RBDMS JSB 012425 Well Prognosis Well Name: Kalotsa 7 API Number: 50-133-20693-00-00 Current Status: Producing Gas Well Permit to Drill Number: 220-067 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: 2757 psi @ 6266’ TVD Based on 0.44 psi/ft Max. Potential Surface Pressure: 2131 psi Based on 0.1 psi/ft gas gradient to surface Applicable Frac Gradient: 1.13 psi/ft using 21.78 ppg EMW LOT at the 7-5/8” surface casing shoe Shallowest Allowable Perf TVD: MPSP/(1.13-0.1) = 2131 psi / 1.03 = 2069‘ TVD Top of Applicable Gas Pool: 1625’ MD/1427’ TVD (Beluga-Tyonek) Well Status: Online Gas producer – 956 mscfd, 0 bwpd, 42 psi FTP Brief Well Summary Kalotsa 7 was drilled and completed in November 2020 but initially failed an MIT-IA which was remedied by an IA downsqueeze in December 2020. Initial perforations were added in the lower Tyonek which got the well flowing around 800 mscfd. Those perforations were isolated in January 2021 and additional perforations were added in the Upper Tyonek that came online at ~7 mmscfd. The objective of this sundry is to add additional infill perforations to the Tyonek sands to increase the rate. Notes Regarding Wellbore Condition x Inclination o Max inclination = 48.97° at 1652’ MD o Max DLS: 7.3° @ 3265’ MD x Min ID o 3.833” – (drift ID of 4-1/2” tubing/liner) x Recent Tags o 9/20/23: RIH W/ 2.25" DD bailer to 6136' KB, dry sand and soap sticks in bailer. Ran PT survey per procedure o 01/21/22 RIH/w flowing survey toolstring, max OD of 2”. Tag TD at 7508’, fluid level seen at 6320’ Pre-Sundry Steps: 1. RU slickline 2. PT lubricator to 250 psi low/ 2,500 psi high 3. D&T to TD w/ large OD drift to find updated tag and ensure wellbore is clean of any sand bridges. Last SL tag was 6136’ KB in September 2023. Note if fluid level is seen. 4. RDMO slickline Procedure: 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250 psi low /2,500 psi high 3. RIH and perforate TY 3 – TY 53 sands from bottom up with 2-7/8” 60 deg phased perf guns: Deepest perf is based on 7990' TVD until perfs are isolated in accordance with 20 AAC 25.112, with cement. Shallowest allowable is ~3750' TVD. -bjm 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 Interval TY_3 ±4,631' ±4,665' ±3,803' ±3,833' ±34' TY_3 ±4,705' ±4,711' ±3,868' ±3,874' ±6' TY_5 ±4,788' ±4,794' ±3,942' ±3,947' ±6' TY_5A ±4,808' ±4,814' ±3,960' ±3,965' ±6' TY_5A ±4,822' ±4,828' ±3,972' ±3,978' ±6' TY_5A ±4,836' ±4,846' ±3,985' ±3,994' ±10' TY_6 ±4,907' ±4,940' ±4,085' ±4,078' ±33' TY_6 ±4,963' ±4,989' ±4,098' ±4,121' ±26' TY_6 ±5,009' ±5,015' ±4,139' ±4,144' ±6' TY_7 ±5,041' ±5,047' ±4,167' ±4,172' ±6' TY_7 ±5,117' ±5,123' ±4,234' ±4,239' ±6' TY_9 ±5,199' ±5,205' ±4,306' ±4,312' ±6' TY_10A ±5,344' ±5,354' ±4,434' ±4,443' ±10' TY_10B ±5,359' ±5,365' ±4,448' ±4,453' ±6' TY_10B ±5,378' ±5,384' ±4,464' ±4,470' ±6' TY_10B ±5,392' ±5,398' ±4,477' ±4,482' ±6' TY_11 ±5,412' ±5,418' ±4,494' ±4,499' ±6' TY_11 ±5,454' ±5,460' ±4,531' ±4,536' ±6' TY_11A ±5,506' ±5,512' ±4,577' ±4,582' ±6' TY_12 ±5,631' ±5,671' ±4,688' ±4,724' ±40' TY_14 ±5,970' ±5,984' ±4,986' ±4,999' ±14' TY_15 ±6,040' ±6,046' ±5,048' ±5,054' ±6' Perforations below this point may not be accessible due to fill TY_17 ±6,241' ±6,251' ±5,225' ±5,234' ±10' TY_17 ±6,254' ±6,268' ±5,237' ±5,249' ±14' TY_17 ±6,281' ±6,289' ±5,260' ±5,267' ±8' TY_18 ±6,387' ±6,401' ±5,354' ±5,366' ±14' TY_37 ±6,689' ±6,703' ±5,620' ±5,632' ±14' TY_53 ±7,424' ±7,434' ±6,266' ±6,275' ±10' 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 Well Prognosis i. Note: A CIBP may be used instead of WRP if it is determined that no cement is needed for operational purposes. g. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations 4. RDMO a. If necessary, re- run cap string to aid with water production if encountered post perforating. Attachments: 1. Current Schematic 2. Proposed Schematic 3. Standard Well Procedure – N2 Operations Updated by CRR 07-14-21 SCHEMATIC Ninilchik Unit Kalotsa #7 PTD: 220-067 API: 50-133-20693-00-00 PBTD = 7,600’ / TVD = 6,422’ TD = 9,785’ / TVD = 8,385’ RKB to GL = 18’ JEWELRY DETAIL No.Depth ID OD Item 1 1,321’3.958”6.875”Swell Packer 2 7,600’4-1/2” CIBP (1/2/21) 3 9,350’4-1/2” CIBP (12/12/20) PERFORATION DETAIL Sands Top (MD)Btm (MD)Top (TVD)Btm (TVD)25’Date Status T-6A 5,058’5,078’4,182’4,200’20’1/5/21 Open T-8 5,146’5,160’4,260’4,272’14’1/5/21 Open T-8 5,164’5,189’4,275’4,297’43’1/5/21 Open T-9A 5,249’5,261’4,350’4,361’12’1/5/21 Open T-11 5,426’5,435’4,507’4,514’9’1/5/21 Open T-16 6,106’6,115’5,107’5,115’9’1/5/21 Open T-17 6,200’6,237’5,189’5,222’37’1/3/21 Open T-18U 6,328’6,359’5,302’5,329’31’1/2/21 Open T-18L 6,364’6,372’5,334’5,341’8’1/2/21 Open T-65 7,631’7,662’6,450’6,477’31’12/19/20 Isolated (1/2/21) T-67 7,735’7,745’6,542’6,551’10’12/13/20 Isolated (1/2/21) T-73 7,900’7,906’6,688’6,693’6’12/13/20 Isolated (1/2/21) T-100 8,437’8,449’7,162’7,172’12’12/13/20 Isolated (1/2/21) T-140.b 8,865’8,882’7,539’7,554’17’12/12/20 Isolated (1/2/21) T-140.c 8,888’8,904’7,559’7,574’16’12/12/20 Isolated (1/2/21) T-146 9,209’9,229 7,848’7,867’20’12/12/20 Isolated (1/2/21) T-150 9,363’9,393’7,990’8,017’30’12/10/20 Isolated (12/12/20) RA Tags Joint Tops: 1668’, 2077’, 2615’, 3274’, 3729’, 4306’, 4718’, 6129’ (all MD) OPEN HOLE / CEMENT DETAIL 7-5/8"76 bbls of 12ppg lead cement and 32 bbls 15.8ppg tail cement in 9-7/8” hole – 29 bbls returned to surface, no losses during job. 4-1/2” 243 bbls of 12ppg lead cement and 41 bbls 15.3ppg tail cement in 6-3/4” hole – no spacer nor cement to surface. 10 bbl losses during job. Remedial IA cement job pumped on 12/2/20. 22bbls of 15.8 cement. ToC ~1506’ BoC ~1958’ 12/8/20 CBL CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 127' 7-5/8"Surf Csg 29.7 L-80 USS-CDC 6.875”Surf 1,567’ 4-1/2"Prod Csg 12.6 L-80 DWC/C HT 3.958”Surf 9,775’ 1 16” 7-5/8” 9-7/8” hole 4-1/2” 6-3/4” hole ToC at ~3040’ per 11/18/20 CBL 3 2 T-150 T-146 T-65 to T-140.c T-18U & T-18L T-6A T-8 T-9A T-11 T-16 T-17 Updated by SRW 1-16-25 PROPOSED Ninilchik Unit Kalotsa #7 PTD: 220-067 API: 50-133-20693-00-00 PBTD = 7,600’ / TVD = 6,422’ TD = 9,785’ / TVD = 8,385’ RKB to GL = 18’ PERFORATION DETAIL Sands Top (MD)Btm (MD)Top (TVD)Btm (TVD)Ft Date Status TY_3 ±4,631'±4,665'±3,803'±3,833'±34'TBD Proposed TY_3 ±4,705'±4,711'±3,868'±3,874'±6'TBD Proposed TY_5 ±4,788'±4,794'±3,942'±3,947'±6'TBD Proposed TY_5A ±4,808'±4,814'±3,960'±3,965'±6'TBD Proposed TY_5A ±4,822'±4,828'±3,972'±3,978'±6'TBD Proposed TY_5A ±4,836'±4,846'±3,985'±3,994'±10'TBD Proposed TY_6 ±4,907'±4,940'±4,085'±4,078'±33'TBD Proposed TY_6 ±4,963'±4,989'±4,098'±4,121'±26'TBD Proposed TY_6 ±5,009'±5,015'±4,139'±4,144'±6'TBD Proposed TY_7 ±5,041'±5,047'±4,167'±4,172'±6'TBD Proposed T-6A 5,058’5,078’4,182’4,200’20’1/5/21 Open TY_7 ±5,117'±5,123'±4,234'±4,239'±6'TBD Proposed T-8 5,146’5,160’4,260’4,272’14’1/5/21 Open T-8 5,164’5,189’4,275’4,297’43’1/5/21 Open TY_9 ±5,199'±5,205'±4,306'±4,312'±6'TBD Proposed T-9A 5,249’5,261’4,350’4,361’12’1/5/21 Open TY_10A ±5,344'±5,354'±4,434'±4,443'±10'TBD Proposed TY_10B ±5,359'±5,365'±4,448'±4,453'±6'TBD Proposed TY_10B ±5,378'±5,384'±4,464'±4,470'±6'TBD Proposed TY_10B ±5,392'±5,398'±4,477'±4,482'±6'TBD Proposed TY_11 ±5,412'±5,418'±4,494'±4,499'±6'TBD Proposed T-11 5,426’5,435’4,507’4,514’9’1/5/21 Open TY_11 ±5,454'±5,460'±4,531'±4,536'±6'TBD Proposed TY_11A ±5,506'±5,512'±4,577'±4,582'±6'TBD Proposed TY_12 ±5,631'±5,671'±4,688'±4,724'±40'TBD Proposed TY_14 ±5,970'±5,984'±4,986'±4,999'±14'TBD Proposed TY_15 ±6,040'±6,046'±5,048'±5,054'±6'TBD Proposed T-16 6,106’6,115’5,107’5,115’9’1/5/21 Open T-17 6,200’6,237’5,189’5,222’37’1/3/21 Open TY_17 ±6,241'±6,251'±5,225'±5,234'±10'TBD Proposed TY_17 ±6,254'±6,268'±5,237'±5,249'±14'TBD Proposed TY_17 ±6,281'±6,289'±5,260'±5,267'±8'TBD Proposed T-18U 6,328’6,359’5,302’5,329’31’1/2/21 Open T-18L 6,364’6,372’5,334’5,341’8’1/2/21 Open TY_18 ±6,387'±6,401'±5,354'±5,366'±14'TBD Proposed TY_37 ±6,689'±6,703'±5,620'±5,632'±14'TBD Proposed TY_53 ±7,424'±7,434'±6,266'±6,275'±10'TBD Proposed Perforation Detail Continued on Page 2 RA Tags Joint Tops: 1668’, 2077’, 2615’, 3274’, 3729’, 4306’, 4718’, 6129’ (all MD) OPEN HOLE / CEMENT DETAIL 7-5/8"76 bbls of 12ppg lead cement and 32 bbls 15.8ppg tail cement in 9-7/8” hole – 29 bbls returned to surface, no losses during job. 4-1/2” 243 bbls of 12ppg lead cement and 41 bbls 15.3ppg tail cement in 6-3/4” hole – no spacer nor cement to surface. 10 bbl losses during job. Remedial IA cement job pumped on 12/2/20. 22bbls of 15.8 cement. ToC ~1506’ BoC ~1958’ 12/8/20 CBL CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 127' 7-5/8"Surf Csg 29.7 L-80 USS-CDC 6.875”Surf 1,567’ 4-1/2"Prod Csg 12.6 L-80 DWC/C HT 3.958”Surf 9,775’ JEWELRY DETAIL No.Depth ID OD Item 1 1,321’3.958”6.875”Swell Packer 2 7,600’4-1/2” CIBP (1/2/21) 3 9,350’4-1/2” CIBP (12/12/20) 1 16” 7-5/8” 9-7/8” hole 4-1/2” 6-3/4” hole ToC at ~3040’ per 11/18/20 CBL 3 2 T-150 T-146 T-65 to T-140.c T-18U & T-18L T-6A T-8 T-9A T-11 T-16 T-17 Updated by SRW 1-16-25 PROPOSED Ninilchik Unit Kalotsa #7 PTD: 220-067 API: 50-133-20693-00-00 Perforation Detail Continued from Page 1 T-65 7,631’ 7,662’ 6,450’ 6,477’ 31’ 12/19/20 Isolated (1/2/21) T-67 7,735’ 7,745’ 6,542’ 6,551’ 10’ 12/13/20 Isolated (1/2/21) T-73 7,900’ 7,906’ 6,688’ 6,693’ 6’ 12/13/20 Isolated (1/2/21) T-100 8,437’ 8,449’ 7,162’ 7,172’ 12’ 12/13/20 Isolated (1/2/21) T-140.b 8,865’ 8,882’ 7,539’ 7,554’ 17’ 12/12/20 Isolated (1/2/21) T-140.c 8,888’ 8,904’ 7,559’ 7,574’ 16’ 12/12/20 Isolated (1/2/21) T-146 9,209’ 9,229 7,848’ 7,867’ 20’ 12/12/20 Isolated (1/2/21) T-150 9,363’ 9,393’ 7,990’ 8,017’ 30’ 12/10/20 Isolated (12/12/20) STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 5/09/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KALOTSA 7 (PTD 220-067) GPT 1/21/2022 Please include current contact information if different from above. PTD:220-067 T36574 Kayla Junke Digitally signed by Kayla Junke Date: 2022.05.10 10:23:02 -08'00' David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt and return one copy of this transmittal or FAX to 907 564-4422 Received By: Date: Hilcorp North Slope, LLC Date: 06/22/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL: FTP Folder Contents: Log Print Files and LAS Data Files: Well API # PTD # Date Log Type Logging Company FALLS CREEK 3 501332052400 203102 12/17/2020 SET PLUG Yellowjacket FALLS CREEK 3 501332052400 203102 1/27/2021 SET PLUG/GPT Yellowjacket GREYSTONE 1 502312005000 216067 8/9/2020 SET PLUG Yellowjacket KALOTSA 2 50133206590000 216155 6/8/2021 PERF / GPT Yellowjacket KALOTSA 3 50133206610000 217028 7/30/2020 PERF / GPT Yellowjacket KALOTSA 7 50133206930000 220067 1/5/2021 PERF Yellowjacket Please include current contact information if different from above. Received By: 06/28/2021 37' (6HW By Abby Bell at 12:22 pm, Jun 28, 2021 Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 01/27/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KALOTSA 7 (PTD 220-067) RCBL FINAL with TEMP 11/18/2020 Please include current contact information if different from above. PTD: 2200670 E-Set: 34892 Received by the AOGCC 01/27/2021 04/06/2021 Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 03/10/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KALOTSA 7 (PTD 220-067) GPT, PLUG, PERF RECORD 01/03/2021 Please include current contact information if different from above. 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(psig)1,2401,2201,2001,1801,1601,1401,1201,1001,0801,0601,0401,0201,000980960940920900880860840820800780760740720700680660640620600580560540520500480460440420400380360340320300280260240220200180160140120100806040Gas Rate (MMscf/day)876543210 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20693-00-00Well Name/No. NINILCHIK UNIT KALOTSA 7Completion Status1-GASCompletion Date12/10/2020Permit to Drill2200670Operator Hilcorp Alaska, LLCMD9785TVD8385Current Status1-GAS2/25/2021UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:Geotap, LWD/MWD Logs, CBL, MudlogsNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF11/16/202020 9880 Electronic Data Set, Filename: Kalotsa 7.las34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 AM Reports.pdf34266EDDigital DataDF11/16/2020 Electronic File: Hilcorp Kalotsa 7 EOW Report.pdf34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 Drilling Dynamics Log MD 2in.pdf34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 Drilling Dynamics Log MD 5in.pdf34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 Drilling Dynamics Log TVD 2in.pdf34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 Drilling Dynamics Log TVD 5in.pdf34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 Formation Log MD 2in.pdf34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 Formation Log MD 5in.pdf34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 Formation Log TVD 2in.pdf34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 Formation Log TVD 5in.pdf34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 Gas Ratio Log MD 2in.pdf34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 Gas Ratio Log MD 5in.pdf34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 Gas Ratio Log TVD 2in.pdf34266EDDigital DataThursday, February 25, 2021AOGCCPage 1 of 6Supplied byOpSupplied byOpKalotsa 7.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20693-00-00Well Name/No. NINILCHIK UNIT KALOTSA 7Completion Status1-GASCompletion Date12/10/2020Permit to Drill2200670Operator Hilcorp Alaska, LLCMD9785TVD8385Current Status1-GAS2/25/2021UICNoDF11/16/2020 Electronic File: Kalotsa 7 Gas Ratio Log TVD 5in.pdf34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 LWD Combo Log MD 2in.pdf34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 LWD Combo Log MD 5in.pdf34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 LWD Combo Log TVD 2in.pdf34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 LWD Combo Log TVD 5in.pdf34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 Drilling Dynamics Log MD 2in.tif34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 Drilling Dynamics Log MD 5in.tif34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 Drilling Dynamics Log TVD 2in.tif34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 Drilling Dynamics Log TVD 5in.tif34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 Formation Log MD 2in.tif34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 Formation Log MD 5in.tif34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 Formation Log TVD 2in.tif34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 Formation Log TVD 5in.tif34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 Gas Ratio Log MD 2in.tif34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 Gas Ratio Log MD 5in.tif34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 Gas Ratio Log TVD 2in.tif34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 Gas Ratio Log TVD 5in.tif34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 LWD Combo Log MD 2in.tif34266EDDigital DataThursday, February 25, 2021AOGCCPage 2 of 6 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20693-00-00Well Name/No. NINILCHIK UNIT KALOTSA 7Completion Status1-GASCompletion Date12/10/2020Permit to Drill2200670Operator Hilcorp Alaska, LLCMD9785TVD8385Current Status1-GAS2/25/2021UICNoDF11/16/2020 Electronic File: Kalotsa 7 LWD Combo Log MD 5in.tif34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 LWD Combo Log TVD 2in.tif34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 LWD Combo Log TVD 5in.tif34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa_7.dbf34266EDDigital DataDF11/16/2020 Electronic File: kalotsa_7.hdr34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa_7.mdx34266EDDigital DataDF11/16/2020 Electronic File: kalotsa_7r.dbf34266EDDigital DataDF11/16/2020 Electronic File: kalotsa_7r.mdx34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa_7_SCL.DBF34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa_7_SCL.MDX34266EDDigital DataDF11/16/2020 Electronic File: KALOTSA_7_tvd.dbf34266EDDigital DataDF11/16/2020 Electronic File: KALOTSA_7_tvd.mdx34266EDDigital DataDF11/16/2020 Electronic File: Kalotsa 7 Gas Show Reports.pdf34266EDDigital Data0 0 2200670 NINILCHIK UNIT KALOTSA 7 LOG HEADERS34266LogLog Header ScansDF12/11/202090 9786 Electronic Data Set, Filename: Kalotsa 7 LWD Final.las34375EDDigital DataDF12/11/2020 Electronic File: Kalotsa 7 Geo-Tap Pressure Tests.cgm34375EDDigital DataDF12/11/2020 Electronic File: Kalotsa 7 LWD Final MD.cgm34375EDDigital DataDF12/11/2020 Electronic File: Kalotsa 7 LWD Final TVD.cgm34375EDDigital DataDF12/11/2020 Electronic File: Kalotsa 7 - Definitive Survey Report.pdf34375EDDigital DataDF12/11/2020 Electronic File: Kalotsa 7 - Definitive Surveys.xlsx34375EDDigital DataDF12/11/2020 Electronic File: Kalotsa 7 DSR Actual - landscape_Plan.pdf34375EDDigital DataDF12/11/2020 Electronic File: Kalotsa 7 DSR Actual -Portrait_VSec.pdf34375EDDigital DataDF12/11/2020 Electronic File: Kalotsa 7 DSR.txt34375EDDigital DataThursday, February 25, 2021AOGCCPage 3 of 6Kalotsa 7 LWD Final.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20693-00-00Well Name/No. NINILCHIK UNIT KALOTSA 7Completion Status1-GASCompletion Date12/10/2020Permit to Drill2200670Operator Hilcorp Alaska, LLCMD9785TVD8385Current Status1-GAS2/25/2021UICNoDF12/11/2020 Electronic File: Kalotsa 7 GIS.txt34375EDDigital DataDF12/11/2020 Electronic File: Kalotsa 7 Geo-Tap Pressure Tests.emf34375EDDigital DataDF12/11/2020 Electronic File: Kalotsa 7 LWD Final MD.emf34375EDDigital DataDF12/11/2020 Electronic File: Kalotsa 7 LWD Final TVD.emf34375EDDigital DataDF12/11/2020 Electronic File: Hilcorp Kalotsa 7 Final Geotap Report.pdf34375EDDigital DataDF12/11/2020 Electronic File: Kalotsa 7 Geo-Tap Pressure Tests.pdf34375EDDigital DataDF12/11/2020 Electronic File: Kalotsa 7 LWD Final MD.pdf34375EDDigital DataDF12/11/2020 Electronic File: Kalotsa 7 LWD Final TVD.pdf34375EDDigital DataDF12/11/2020 Electronic File: Kalotsa 7 Geo-Tap Pressure Tests.tif34375EDDigital DataDF12/11/2020 Electronic File: Kalotsa 7 LWD Final MD.tif34375EDDigital DataDF12/11/2020 Electronic File: Kalotsa 7 LWD Final TVD.tif34375EDDigital DataDF12/11/2020 Electronic File: EMFView3_1.zip34375EDDigital DataDF12/11/2020 Electronic File: Readme.txt34375EDDigital Data0 0 2200670 NINILCHIK UNIT KALOTSA 7 LOG HEADERS34375LogLog Header ScansDF12/23/202018 4522 Electronic Data Set, Filename: Kalotsa-7_RCBL_08-Dec-20_Main Up Pass 30 FPM.las34439EDDigital DataDF12/23/2020 Electronic File: Kalotsa-7_08-Dec-20_MemoryRadialCementBondLog.pdf34439EDDigital DataDF12/23/2020 Electronic File: Kalotsa-7_08-Dec-20_MemoryRadialCementBondLog.tif34439EDDigital Data0 0 2200670 NINILCHIK UNIT KALOTSA 7 LOG HEADERS34439LogLog Header ScansDF1/13/20217474 8968 Electronic Data Set, Filename: KALOTSA_7_PTS_29DEC20_120DWN.las34570EDDigital DataDF1/13/20218971 7474 Electronic Data Set, Filename: KALOTSA_7_PTS_29DEC20_120UP.las34570EDDigital DataDF1/13/20217494 8952 Electronic Data Set, Filename: KALOTSA_7_PTS_29DEC20_60DWN.las34570EDDigital DataThursday, February 25, 2021AOGCCPage 4 of 6 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20693-00-00Well Name/No. NINILCHIK UNIT KALOTSA 7Completion Status1-GASCompletion Date12/10/2020Permit to Drill2200670Operator Hilcorp Alaska, LLCMD9785TVD8385Current Status1-GAS2/25/2021UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDDF1/13/20218950 7494 Electronic Data Set, Filename: KALOTSA_7_PTS_29DEC20_60UP.las34570EDDigital DataDF1/13/20217474 8971 Electronic Data Set, Filename: KALOTSA_7_PTS_29DEC20_90DWN.las34570EDDigital DataDF1/13/20218960 7475 Electronic Data Set, Filename: KALOTSA_7_PTS_29DEC20_90UP.las34570EDDigital DataDF1/13/20210 1837 Electronic Data Set, Filename: KALOTSA_7_PTS_29DEC20_SS7600.las34570EDDigital DataDF1/13/20210 1736 Electronic Data Set, Filename: KALOTSA_7_PTS_29DEC20_SS7675.las34570EDDigital DataDF1/13/20210 339 Electronic Data Set, Filename: KALOTSA_7_PTS_29DEC20_SS7720.las34570EDDigital DataDF1/13/20210 346 Electronic Data Set, Filename: 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Drill2200670Operator Hilcorp Alaska, LLCMD9785TVD8385Current Status1-GAS2/25/2021UICNoCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Compliance Reviewed By:Date:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date: 12/10/2020Release Date:10/20/2020Thursday, February 25, 2021AOGCCPage 6 of 6M. 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ϮϮϬͲϬϲϳ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ϬϭͬϬϱͬϮϬϮϭͲdƵĞƐĚĂǇ WdtĂŶĚ:^͘^ƉŽƚĞƋƵŝƉŵĞŶƚĂŶĚƌŝŐƵƉůƵďƌŝĐĂƚŽƌ͘WdƚŽϮϱϬƉƐŝůŽǁĂŶĚϰ͕ϬϬϬƉƐŝŚŝŐŚ͘dWͲϰϮϬƉƐŝ͘Z/,ǁͬ'ƵŶϭ;dͲ ϴhͿ͕ϮͲϳͬϴΗǆϭϰΖ,͕ϲƐƉĨ͘ϲϬĚĞŐƉŚĂƐĞĂŶĚƚŝĞŝŶƚŽK,>͘ZƵŶĐŽƌƌĞůĂƚŝŽŶůŽŐĂŶĚƐĞŶĚƚŽƚŽǁŶ͘'ĞƚŽŬƚŽƉĞƌĨĨƌŽŵ ϱ͕ϭϰϲΖƚŽϱ͕ϭϲϬΖ͘^ƉŽƚĂŶĚĨŝƌĞŐƵŶǁͬϰϰϲ͘ϳƉƐŝ͘ĨƚĞƌϱŵŝŶͲϰϲϮƉƐŝ͕ϭϬŵŝŶͲϰϲϵ͘ϰƉƐŝĂŶĚϭϱŵŝŶͲϰϳϳ͘ϵƉƐŝ͘WKK,͘ůů ƐŚŽƚƐĨŝƌĞĚͬŐƵŶǁĂƐĚƌǇ͘Z/,ǁͬ'ƵŶϮ;dͲϭϲͿͿ͕ϮͲϳͬϴΗǆϭϮΖ,͕ϲƐƉĨ͘ϲϬĚĞŐƉŚĂƐĞĂŶĚƚŝĞŝŶƚŽK,>͘ZƵŶĐŽƌƌĞůĂƚŝŽŶůŽŐ ĂŶĚƐĞŶĚƚŽƚŽǁŶ͘'ĞƚŽŬƚŽƉĞƌĨĨƌŽŵϲ͕ϭϬϲΖƚŽϲ͕ϭϭϱΖǁͬϱϬϲƉƐŝ͘^ƉŽƚĂŶĚĨŝƌĞŐƵŶǁϱϬϲƉƐŝ͘ĨƚĞƌϱŵŝŶͲϱϭϮ͘ϲƉƐŝ͕ϭϬ ŵŝŶͲϱϭϰ͘ϲĂŶĚϭϱŵŝŶͲϱϭϳ͘ϵƉƐŝ͘WKK,͘ůůƐŚŽƚƐĨŝƌĞĚͬŐƵŶǁĂƐĚƌǇ͘Z/,ǁͬ'ƵŶϯ;dͲϭϭͿ͕ϮͲϳͬϴΗǆϵΖ,͕ϲƐƉĨ͘ϲϬĚĞŐ ƉŚĂƐĞĂŶĚƚŝĞŝŶƚŽK,>͘ZƵŶĐŽƌƌĞůĂƚŝŽŶůŽŐĂŶĚƐĞŶĚƚŽƚŽǁŶ͘'ĞƚŽŬƚŽƉĞƌĨĨƌŽŵϱ͕ϰϮϲΖƚŽϱ͕ϰϯϱΖǁͬϱϯϱƉƐŝ͘^ƉŽƚĂŶĚ ĨŝƌĞĚŐƵŶǁͬϱϯϱ͘ĨƚĞƌϱŵŝŶͲϱϯϱ͘ϯƉƐŝ͕ϭϬŵŝŶͲϱϯϲ͘ϯƉƐŝĂŶĚϭϱŵŝŶͲϱϯϳ͘ϭƉƐŝ͘WKK,͘ůůƐŚŽƚƐĨŝƌĞĚͬ'ƵŶƌǇ͘dŽǁŶ ĚĞĐŝĚĞĚƚŽƐŬŝƉ^ĂŶĚdͲϭϬ͘Z/,ǁͬ'ƵŶϰ;dͲϵͿ͕ϮͲϳͬϴΗǆϭϮΖ,͕ϲƐƉĨ͘ϲϬĚĞŐƉŚĂƐĞĂŶĚƚŝĞŝŶƚŽK,>͘ZƵŶĐŽƌƌĞůĂƚŝŽŶůŽŐ ĂŶĚƐĞŶĚƚŽƚŽǁŶ͘dŽǁŶƐĂŝĚƚŽĂĚĚϭΖ͘ĚĚĞĚϭΖ͕ƐƉŽƚƚĞĚĂŶĚĨŝƌĞĚŐƵŶĨƌŽŵϱ͕ϮϰϵΖƚŽϱ͕ϮϲϭΖǁͬϱϱϵ͘ϳƉƐŝ͘ĨƚĞƌϱŵŝŶͲ 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ƚŽϲ͕ϮϯϳΖǁͬϭϭϲ<ͬϰϵƉƐŝĂŶĚĨŝƌĞĚŐƵŶ͘ĨƚĞƌϱŵŝŶͲϭϰϵ<ͬϱϲƉƐŝ͕ϭϬŵŝŶͲϭϲϭ<ͬϱϵƉƐŝĂŶĚϭϱŵŝŶͲϭϳϭ<ͬϲϭƉƐŝ͘WKK,͘ ůůƐŚŽƚƐĨŝƌĞĚĂŶĚŐƵŶǁĂƐĚƌǇ͘Z/,ǁͬϮͲϳͬϴΗǆϭϳΖ,͕ϲƐƉĨ͕ϲϬĚĞŐƉŚĂƐĞĂŶĚƚŝĞŝŶƚŽK,>͘ZƵŶĐŽƌƌĞůĂƚŝŽŶůŽŐĂŶĚ ƐĞŶĚƚŽƚŽǁŶ͘dŽǁŶƐĂŝĚƚŽĂĚϭΖƚƉůŽŐ͘ĚĚĞĚϭΖƚŽůŽŐ͘^ƉŽƚƚĞĚĂŶĚĨŝƌĞĚŐƵŶĨƌŽŵϲ͕ϮϬϬΖƚŽϲ͕ϮϭϳΖǁŝƚŚϮϰϳŬͬϳϮƉƐŝ͘ ĨƚĞƌϱŵŝŶͲϮϲϱ<ͬϳϰƉƐŝ͕ϭϬŵŝŶͲϮϱϵͬϳϰ͘ϰƉƐŝ͕ϭϱŵŝŶͲϮϳϬ<ͬϳϱƉƐŝ͘WKK,͘ůůƐŚŽƚƐĨŝƌĞĚĂŶĚŐƵŶǁĂƐĚƌǇ͘ZŝŐĚŽǁŶ ĞƋƵŝƉŵĞŶƚĂŶĚƚƵƌŶǁĞůůŽǀĞƌƚŽĨŝĞůĚ͘ hƉĚĂƚĞĚďǇDϬϭͲϭϰͲϮϭ ^,Dd/ EŝŶŝůĐŚŝŬhŶŝƚ <ĂůŽƚƐĂηϳ Wd͗ϮϮϬͲϬϲϳ W/͗ϱϬͲϭϯϯͲϮϬϲϵϯͲϬϬͲϬϬ Wdсϳ͕ϲϬϬ͛ͬdsсϲ͕ϰϮϮ͛ dсϵ͕ϳϴϱ͛ͬdsсϴ͕ϯϴϱ͛ Z<ƚŽ'>сϭϴ͛ :t>Zzd/> EŽ͘ĞƉƚŚ/K/ƚĞŵ ϭϭ͕ϯϮϭ͛ϯ͘ϵϱϴ͟ϲ͘ϴϳϱ͟^ǁĞůůWĂĐŬĞƌ Ϯϳ͕ϲϬϬ͛ϰͲϭͬϮ͟/W;ϭͬϮͬϮϭͿ ϯϵ͕ϯϱϬ͛ϰͲϭͬϮ͟/W;ϭϮͬϭϮͬϮϬͿ WZ&KZd/KEd/> ^ĂŶĚƐdŽƉ;DͿƚŵ;DͿdŽƉ;dsͿƚŵ;dsͿϮϱ͛ĂƚĞ^ƚĂƚƵƐ dͲϲϱ͕Ϭϱϴ͛ϱ͕Ϭϳϴ͛ϰ͕ϭϴϮ͛ϰ͕ϮϬϬ͛ϮϬ͛ϭͬϱͬϮϭKƉĞŶ dͲϴϱ͕ϭϰϲ͛ϱ͕ϭϲϬ͛ϰ͕ϮϲϬ͛ϰ͕ϮϳϮ͛ϭϰ͛ϭͬϱͬϮϭKƉĞŶ dͲϴϱ͕ϭϲϰ͛ϱ͕ϭϴϵ͛ϰ͕Ϯϳϱ͛ϰ͕Ϯϵϳ͛ϰϯ͛ϭͬϱͬϮϭKƉĞŶ dͲϵϱ͕Ϯϰϵ͛ϱ͕Ϯϲϭ͛ϰ͕ϯϱϬ͛ϰ͕ϯϲϭ͛ϭϮ͛ϭͬϱͬϮϭKƉĞŶ dͲϭϭϱ͕ϰϮϲ͛ϱ͕ϰϯϱ͛ϰ͕ϱϬϳ͛ϰ͕ϱϭϰ͛ϵ͛ϭͬϱͬϮϭKƉĞŶ dͲϭϲϲ͕ϭϬϲ͛ϲ͕ϭϭϱ͛ϱ͕ϭϬϳ͛ϱ͕ϭϭϱ͛ϵ͛ϭͬϱͬϮϭKƉĞŶ dͲϭϳϲ͕ϮϬϬ͛ϲ͕Ϯϯϳ͛ϱ͕ϭϴϵ͛ϱ͕ϮϮϮ͛ϯϳ͛ϭͬϯͬϮϭKƉĞŶ 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% +$,&%7 7>10;<$00 5)2- , ':,&7+ 2$&'' 2,(&%7 : $,,&$ $ :'&($ B% 2:'&%: ('%&+ 2 27' 7+$&2 2(' +,'&:$ (&%2 % +%2&72 7>10;<$00 5)2- , +'(&,7 $,&( 2,$&+ : 2'+&, $ ,2&, B% 7('&$: $$2&2, 2 27' 7+,&,, 2(' +'&+ 7&(, % ++%&(( 7>10;<$00 5)2- , $2&77 $&2( 2,$&%$ : 7$'&(7 $ ,,&,7 B% 727&:: $(&'7 2 27' 7&'+ 2(' +'&: %&( % +:7&%2 7>10;<$00 5)2- , %&(: $+&7 2,(&:$ : 7%:&7( $ :(7&'% B% 777&$%: 2(7&:( 2 27' 7:$&%( 2(' +%:&+( 2&%% % +,7&%+ 7>10;<$00 5)2- , :'&(( $+&7 2,(&:$ : 7:%&+: $ :(&7% B% 7%7&$7: 2%(&$: 2 27' 7:'&%7 2(' +7:&( (&(( % (%&$% ".C*/*/ 6!@6!@ @ Benjamin Hand Digitally signed by Benjamin Hand Date: 2020.11.03 17:32:01 -09'00'Chelsea Wright Digitally signed by Chelsea Wright Date: 2020.11.04 08:44:39 -09'00' 7' 6KRH'HSWK 3%7' -WV Ϯ ϯϲ <HV ;1R ;<HV 1R )OXLG'HVFULSWLRQ /LQHUKDQJHU,QIR0DNH0RGHO /LQHUWRS3DFNHU" <HV y 1R /LQHUKDQJHUWHVWSUHVVXUH;<HV 1R &HQWUDOL]HU3ODFHPHQW 3UHIOXVK6SDFHU 7\SH 'HQVLW\SSJ 9ROXPHSXPSHG%%/V /HDG6OXUU\ 7\SH6DFNV <LHOG 'HQVLW\SSJ 9ROXPHSXPSHG%%/V 0L[LQJ3XPSLQJ5DWHESP 7DLO6OXUU\ 7\SH6DFNV <LHOG 'HQVLW\SSJ 9ROXPHSXPSHG%%/V 0L[LQJ3XPSLQJ5DWHESP 3RVW)OXVK6SDFHU 7\SH 'HQVLW\SSJ5DWHESP9ROXPH 'LVSODFHPHQW 7\SH 'HQVLW\SSJ 5DWHESP 9ROXPHDFWXDOFDOFXODWHG )&3SVL 3XPSXVHGIRUGLVSy zĞƐ EŽ &DVLQJ5RWDWHG" <HV y 1R 5HFLSURFDWHG"y <HV 1R 5HWXUQVGXULQJMRE &HPHQWUHWXUQVWRVXUIDFH"y <HV 1R 6SDFHUUHWXUQV"<HV y 1R 9ROWR6XUI &HPHQW,Q3ODFH$W 'DWH (VWLPDWHG72& 0HWKRG8VHG7R'HWHUPLQH72& WŽƐƚ:ŽďĂůĐƵůĂƚŝŽŶƐ͗ &DOFXODWHG&PW9RO#H[FHVV 7RWDO9ROXPHFPW3XPSHG &PWUHWXUQHGWRVXUIDFH &DOFXODWHGFHPHQWOHIWLQZHOOERUH 2+YROXPH&DOFXODWHG 2+YROXPHDFWXDO $FWXDO:DVKRXW &DVLQJ2U/LQHU'HWDLO &ůŽĂƚ^ŚŽĞ ϴϱͬϴ 5RWDWH&VJ 5HFLS&VJ )W0LQ33* 6KRH#)&#7RSRI/LQHU )ORDWV+HOG 6SXG0XG &$6,1*5(&25' &RXQW\6WDWH $ODVND 6XSY3HGHUVRQ5LOH\ Hilcorp Energy Company &$6,1* &(0(17,1*5(3257 /HDVH :HOO1R1,18.DORWVD'DWH5XQ 2FW 6HWWLQJ'HSWKV ŽŵƉŽŶĞŶƚ 6L]H :W*UDGH 7+'0DNH /HQJWK %RWWRP 7RS tĞĂƚŚĞƌĨŽƌĚ ϭ͘ϲϯ ϭ͕ϱϲϳ͘ϰϭ ϭ͕ϱϲϱ͘ϳϴ &VJ:W2Q+RRN7\SH)ORDW&ROODU:HDWKHUIRUG1R+UVWR5XQ ),56767$*(7XQHG ϲϲͬϲϴ ϭϬϯϳ Ϯϵ &HPHQW7UXFN %XPSSUHVV 5HWXUQV %XPS3OXJ" &(0(17,1*5(3257 &VJ:W2Q6OLSV 6SXG0XG 7\SHRI6KRH%XOOQRVH&DVLQJ&UHZ:HDWKHUIRUG ǁǁǁ͘ǁĞůůĞǌ͘ŶĞƚtĞůůǌ/ŶĨŽƌŵĂƚŝŽŶDĂŶĂŐĞŵĞŶƚ>>ǀĞƌͺϬϰϴϭϴďƌ (YHU\RWKHUMRLQWXSWR WRWDO ĂƐŝŶŐ ϳϱͬϴ Ϯϵ͘ϳ >ͲϴϬ h^^ϴϬ͘ϳϮ ϭ͕ϱϲϱ͘ϳϴ ϭ͕ϰϴϱ͘Ϭϲ &ůŽĂƚŽůůĂƌ ϴϱͬϴ ϭ͘Ϯϵ ϭ͕ϰϴϱ͘Ϭϲ ϭ͕ϰϴϯ͘ϳϳ ĂƐŝŶ ϳϱͬϴ Ϯϵ͘ϳ >ͲϴϬ h^^ϭ͕ϰϱϴ͘ϱϱ ϭ͕ϰϴϯ͘ϳϳ Ϯϱ͘ϮϮ WƵƉ:ŽŝŶƚ ϳϱͬϴ Ϯϵ͘ϳ >ͲϴϬ h^^Ϯ͘ϰϬ Ϯϱ͘ϮϮ ϮϮ͘ϴϮ ,ĂŶŐĞƌ ϭϲ ĂĐƚƵƐ Ϭ͘ϵϮ ϮϮ͘ϴϮ Ϯϭ͘ϵϬ 7\SH,,, &ODVV* Actual washout appears to be 0% based on cement volume return to surface. bjm 7' 6KRH'HSWK 3%7' -WV Ϯ ϮϬϯ ϯϭ <HV ;1R ;<HV 1R )OXLG'HVFULSWLRQ /LQHUKDQJHU,QIR0DNH0RGHO /LQHUWRS3DFNHU" <HV 1R /LQHUKDQJHUWHVWSUHVVXUH;<HV 1R &HQWUDOL]HU3ODFHPHQW 3UHIOXVK6SDFHU 7\SH 'HQVLW\SSJ 9ROXPHSXPSHG%%/V /HDG6OXUU\ 7\SH6DFNV <LHOG 'HQVLW\SSJ 9ROXPHSXPSHG%%/V 0L[LQJ3XPSLQJ5DWHESP 7DLO6OXUU\ 7\SH6DFNV <LHOG 'HQVLW\SSJ 9ROXPHSXPSHG%%/V 0L[LQJ3XPSLQJ5DWHESP 3RVW)OXVK6SDFHU 7\SH 'HQVLW\SSJ 5DWHESP 9ROXPH 'LVSODFHPHQW 7\SH 'HQVLW\SSJ 5DWHESP 9ROXPHDFWXDOFDOFXODWHG )&3SVL 3XPSXVHGIRUGLVSy zĞƐ EŽ &DVLQJ5RWDWHG" <HV y 1R 5HFLSURFDWHG"y <HV 1R 5HWXUQVGXULQJMRE &HPHQWUHWXUQVWRVXUIDFH" <HV y 1R 6SDFHUUHWXUQV" <HV y 1R 9ROWR6XUI &HPHQW,Q3ODFH$W 'DWH (VWLPDWHG72& 0HWKRG8VHG7R'HWHUPLQH72& WŽƐƚ:ŽďĂůĐƵůĂƚŝŽŶƐ͗ &DOFXODWHG&PW9RO#H[FHVV 7RWDO9ROXPHFPW3XPSHG &PWUHWXUQHGWRVXUIDFH &DOFXODWHGFHPHQWOHIWLQZHOOERUH 2+YROXPH&DOFXODWHG 2+YROXPHDFWXDO $FWXDO:DVKRXW 7\SH,, 7\SH,, ϭϵ͘ϵϵ ϭϵ͘ϯϬ Ϯ͘ϱϲ ϮϮ͘ϱϱ ϭϵ͘ϵϵ ĂĐƚƵƐ,ĂŶŐĞƌ ϭϬϯͬϰ t ĂĐƚƵƐ Ϭ͘ϲϵ WƵƉũƚ ϰϭͬϮ ϭϮ͘ϲ >ͲϴϬ t sĂŵ ϭ͕ϯϬϲ͘ϭϴ ĂƐŝŶŐ ϰϭͬϮ ϭϮ͘ϲ >ͲϴϬ t sĂŵ ϭ͕Ϯϴϯ͘ϲϯ ϭ͕ϯϬϲ͘ϭϴ ϮϮ͘ϱϱ ϵ͕ϲϴϵ͘ϵϭ ϭ͕ϯϯϱ͘ϳϵ ^ǁĞůůƉĂĐŬĞƌͬWƵƉƐ ϳ t ϱ͘ϵϱ ϭ͕ϯϯϱ͘ϳϵ ϭ͘Ϯϳ ϵ͕ϲϵϭ͘ϭϴ ϵ͕ϲϴϵ͘ϵϭ ĂƐŝŶŐ ϰϭͬϮ ϭϮ͘ϲ >ͲϴϬ t sĂŵ ϴ͕ϯϱϰ͘ϭϮ &ůŽĂƚĐŽůůĂƌ ϱ t ŶƚĞůŽƉĞ ILEHUJODVVFHQWUDOL]HUUDQDQGPHWDOFHQWUDOL]HUV ĂƐŝŶŐ ϰϭͬϮ ϭϮ͘ϲ >ͲϴϬ t sĂŵ ϴϮ͘ϭϴ ϵ͕ϳϳϯ͘ϯϲ ϵ͕ϲϵϭ͘ϭϴ ǁǁǁ͘ǁĞůůĞǌ͘ŶĞƚtĞůůǌ/ŶĨŽƌŵĂƚŝŽŶDĂŶĂŐĞŵĞŶƚ>>ǀĞƌͺϬϰϴϭϴďƌ 7\SHRI6KRH$QWHORSH &DVLQJ&UHZ:272& &(0(17,1*5(3257 &VJ:W2Q6OLSV .&/3+3$ %XPSSUHVV%XPS3OXJ" ϭϰϴͬϭϰϴ ϭϵϳϭ Ϯϰϯ +(6),56767$*(7XQHVSDFHU &VJ:W2Q+RRN7\SH)ORDW&ROODU$QWHORSH 1R+UVWR5XQ t ŶƚĞůŽƉĞ ϭ͘ϰϬ ϵ͕ϳϳϰ͘ϳϲ ϵ͕ϳϳϯ͘ϯϲ 6HWWLQJ'HSWKV ŽŵƉŽŶĞŶƚ 6L]H :W *UDGH 7+' 0DNH /HQJWK %RWWRP 7RS Hilcorp Energy Company &$6,1* &(0(17,1*5(3257 /HDVH :HOO1R1,18.DORWVD'DWH5XQ 1RY &$6,1*5(&25' &RXQW\ 6WDWH $ODVND 6XSY+DXFN5LFKDUGVRQ )ORDWV+HOG .&/3+3$ 5RWDWH&VJ 5HFLS&VJ )W0LQ 33* 6KRH#)&# 7RSRI/LQHU &DVLQJ2U/LQHU'HWDLO &ůŽĂƚƐŚŽĞ ϱ unable to determine OH actual without cement or spacer to surface. bjm 0 Actual TOC verified by CBL 11/18/2020 at 3040'. Suspect actual losses were much higher than reported. bjm David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-5256 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: Date: 12/22/2020 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL KALOTSA 7 (PTD 220-067) Radial Cement Bond Log 12/08/2020 Please include current contact information if different from above. PTD: 2200670 E-Set: 34439 Received by the AOGCC 12/23/2020 Abby Bell 12/23/2020 1.Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: __N2 and/or Patch_____ 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 9,785'none Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 7,500psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Ryan Rupert Operations Manager Contact Email: Contact Phone: 777-8503 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng ryan.rupert@hilcorp.com 8,385'9,350'7,977'~3085 9,350' Swell Packer ; n/a 1321' / 1221' TVD, n/a Perforation Depth TVD (ft):Tubing Size: COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 C061505, ADL384372 220-067 50-133-20693-00-00 Kalotsa-07 Ninilchik Field / Beluga/Tyonek Gas Pool Length Size CO 701C Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY 12.6# L-80 TVD Burst 1,321' 8,430psi MD 2,980psi 6,880psi 127' 1,258' 127' 1,567' 8,375'4-1/2" 16" 7-5/8" 127' 1,567' 9,775' Perforation Depth MD (ft): See Attached Schematic 9,775' Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: December 18, 2020 4-1/2" m n P s 66 t _ Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 9:51 am, Dec 15, 2020 320-520 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.12.14 21:34:47 -09'00' Taylor Wellman DSR-12/17/2020 Plug Perforationss 10-404 Perforate DLB 12/15/2020 gls 12/17/20 __N2 and/or Patch_ Xq C 12/18/2020 dts 12/17/2020 JLC 12/17/2020 RBDMS HEW 12/21/2020 Well: Kalotsa-07 Date: 12/14/2020 Well Name:Kalotsa-07 API Number:50-133-20693-00-00 Current Status:New drill Gas Producer Leg:N/A Estimated Start Date:12/18/20 Rig:EL Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:220-067 First Call Engineer:Ryan Rupert (907) 777-8503 (O)(907) 301-1736 (C) Second Call Engineer:Todd Sidoti (907) 632-4113 (C) Maximum Expected BHP:~ 3801 psi @ 7,162’ TVD (Based on T-100 RFT pressure acquired 11/4/20) Max. Potential Surface Pressure:~ 3085 psi Using Max BHP minus 0.1 psi/ft. gas gradient to surface). Well Summary Kalotsa-07 is a new drill well TD’d 11/3/20. The well initially failed an MIT-IA. A cement downsqueeze was performed 12/5/20 and as of 12/14/20, the failing MIT-IA has been remedied. Initial perforations have been shot and the well is online flowing as of 12/14/20 at ~800mcfd at 750psi FTP. Additional perforations are proposed below to increase the rate. Notes Regarding Wellbore Condition x Min ID = 3.833” (drift ID of 4-1/2” tubing/liner) x Max deviation = 49 degrees at 1652’ MD x A 30’ x 2-7/8” perf gun made it down to 9393’ MD on 12/10/20 with no issues x A 4-1/2” CIBP made it down to 9350’ MD with no issues on 12/12/20 Safety Concerns - Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. - Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job) - Ensure all crews are aware of stop work authority Perforation work 1. MIRU EL and pressure control equipment. PT lubricator to 4,000 psi Hi 250 Low. 2. RU perf guns. Likely 2-7/8”guns with 6 spf 3. RIH and perforate the below intervals bottom up per Geo/RE: * followup CBL run on 12/8/20 after IA squeeze 2 Well: Kalotsa-07 Date: 12/14/2020 Sand MD Top MD Bottom TVD Top TVD Bottom Total Footage (MD) Expected BHP (psi) T-6A ± 5,057’± 5,080’± 4,181’± 4,201’23’1,953 (RFT) T-8 ± 5,146’± 5,189’± 4,260’± 4,297’43’1,159 (RFT) T-9A ± 5,248’± 5,270’± 4,350’± 4,369’22’1,784 (RFT) T-10A ± 5,340’± 5,354’± 4,431’± 4,443’14’1,995 (0.45psi/ft) T-11 ± 5,412’± 5,444’± 4,494’± 4,522’32’2,030 (0.45psi/ft) T-12 ± 5,634 ± 5,666’± 4,691’± 4,719’32’680 (RFT) T-16 ± 6,097’± 6,116’± 5,099’± 5,116’19’2,706 (RFT) T-17 ± 6,195’± 6,248’± 5,185’± 5,231’53’540 (RFT) T-17A ± 6,283’± 6,287’± 5,262’± 5,266’4’2,368 (0.45psi/ft) T-18 ± 6,325’± 6,400’± 5,299’± 5,365’75’2,398 (0.45psi/ft) T-65 ± 7,631’± 7,698’± 6,450’± 6,509’67’980 (RFT) T-69 ± 7,794’± 7,814’± 6,594’± 6,611’20’2,971 T-83 ± 8,010’± 8,046’± 6,786’± 6,818’36’641 (RFT) T-87 ± 8,176’± 8,181’± 6,933’± 6,937’5’400 (Est.) T-90U ± 8,204’± 8,240’± 6,958’± 6,989’36’400 (Est.) T-90L ± 8,268’± 8,316’± 7,014’± 7,056’48’400 (Est.) T-98 ± 8,348’± 8,358’± 7,084’± 7,093’10’3,190 T-115 ± 8,539’± 8,564’± 7,252’± 7,274’25’440 (RFT) a. Consult with OE for what WHP to use for each perf set. Some may be shot while the well is flowing, also. b. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. c.Use Gamma/CCL to correlate. d. Record initial and 5/10/15 minute tubing pressures after firing e. Consult with RE/Geo between each perf interval: i. Anthony McConkey: RE - 529-6199 ii. Matthew Petrowsky: Geo – 814-421-6753 4. Once sufficient production has been added per RE/Geo, RD E-Line Unit and turn well over to production. CONTINGENT: If a zone is shown to make undesirable sand/water, set plug or patch for shut-off 5. MIRU EL unit 6. PT BOP equipment to 250 psi Low / 4500 psi High. (Notify AOGCC 24 hrs. in advance on BOP test.) 7. If necessary, displace well with N2 taking returns into open formation 8. MU 4-1/2” patch and/or plug per vendor recommendation 9. RIH and set over identified perf interval 10. RDMO EL Attachments: 1. Current schematic 2. Proposed Schematic 3. Standard Well procedure – N2 Operations Updated by CRR 12-14-2020 SCHEMATIC Ninilchik Unit Kalotsa #7 PTD:220-067 API: 50-133-20693-00-00 PBTD = 9,690’ / TVD = 8,294’ TD = 9,785’ / TVD = 8,385’ RKB to GL = 18’ JEWELRY DETAIL No.Depth ID OD Item 1 1,321’3.958”6.875”Swell Packer 2 9350’4-1/2” CIBP (12/12/20) Sands Top (MD)Btm (MD)Top (TVD)Btm (TVD)FT Date Status T-67 ± 7,735’± 7,745’± 6,542’± 6,551’10’12/13/20 Open T-73 ± 7,900’± 7,906’± 6,688’± 6,693’6’12/13/20 Open T-100 ± 8,437’± 8,449’± 7,162’± 7,172’12’12/13/20 Open T-140.b ± 8,865’± 8,882’± 7,539’± 7,554’17’12/12/20 Open T-140.c ± 8,888’± 8,904’± 7,559’± 7,574’16’12/12/20 Open T-146 ± 9,209’± 9,229 ± 7,848’± 7,867’20’12/12/20 Open T-150 9363’9393’7990’8017’30’12/10/20 Isolated (12/12/20) RA Tags Joint Tops:1668’, 2077’, 2615’, 3274’, 3729’, 4306’, 4718’, 6129’ (all MD) OPEN HOLE / CEMENT DETAIL 7-5/8"76 bbls of 12ppg lead cement and 32 bbls 15.8ppg tail cement in 9-7/8” hole – 29 bbls returned to surface, no losses during job. 4-1/2”243 bbls of 12ppg lead cement and 41 bbls 15.3ppg tail cement in 6-3/4” hole – no spacer nor cement to surface. 10 bbl losses during job. CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 127' 7-5/8"Surf Csg 29.7 L-80 USS-CDC 6.875”Surf 1,567’ 4-1/2"Prod Csg 12.6 L-80 DWC/C HT 3.958”Surf 9,775’ 1 16” 7-5/8” 9-7/8” hole 4-1/2” 6-3/4” hole ToC at ~3040’ per 11/18/20 CBL 2 IA downsqueeze 12/2/20 22bbls cement IA downsqueeze on 12-2-20 Updated by CRR 12-14-2020 PROPOSED SCHEMATIC Ninilchik Unit Kalotsa #7 PTD:220-067 API: 50-133-20693-00-00 PBTD = 9,690’ / TVD = 8,294’ TD = 9,785’ / TVD = 8,385’ RKB to GL = 18’ JEWELRY DETAIL No.Depth ID OD Item 1 1,321’3.958”6.875”Swell Packer 2 9350’4-1/2” CIBP (12/12/20) Sands Top (MD)Btm (MD)Top (TVD)Btm (TVD)FT Date Status T-6A ± 5,057’± 5,080’± 4,181’± 4,201’23’TBD Proposed T-8 ± 5,146’± 5,189’± 4,260’± 4,297’43’TBD Proposed T-9A ± 5,248’± 5,270’± 4,350’± 4,369’22’TBD Proposed T-10A ± 5,340’± 5,354’± 4,431’± 4,443’14’TBD Proposed T-11 ± 5,412’± 5,444’± 4,494’± 4,522’32’TBD Proposed T-12 ± 5,634 ± 5,666’± 4,691’± 4,719’32’TBD Proposed T-16 ± 6,097’± 6,116’± 5,099’± 5,116’19’TBD Proposed T-17 ± 6,195’± 6,248’± 5,185’± 5,231’53’TBD Proposed T-17A ± 6,283’± 6,287’± 5,262’± 5,266’4’TBD Proposed T-18 ± 6,325’± 6,400’± 5,299’± 5,365’75’TBD Proposed T-65 ± 7,631’± 7,698’± 6,450’± 6,509’67’TBD Proposed T-67 ± 7,735’± 7,745’± 6,542’± 6,551’10’12/13/20 Open T-69 ± 7,794’± 7,814’± 6,594’± 6,611’20’TBD Proposed T-73 ± 7,900’± 7,906’± 6,688’± 6,693’6’12/13/20 Open T-83 ± 8,010’± 8,046’± 6,786’± 6,818’36’TBD Proposed T-87 ± 8,176’± 8,181’± 6,933’± 6,937’5’TBD Proposed T-90U ± 8,204’± 8,240’± 6,958’± 6,989’36’TBD Proposed T-90L ± 8,268’± 8,316’± 7,014’± 7,056’48’TBD Proposed T-98 ± 8,348’± 8,358’± 7,084’± 7,093’10’TBD Proposed T-100 ± 8,437’± 8,449’± 7,162’± 7,172’12’12/13/20 Open T-115 ± 8,539’± 8,564’± 7,252’± 7,274’25’TBD Proposed T-140.b ± 8,865’± 8,882’± 7,539’± 7,554’17’12/12/20 Open T-140.c ± 8,888’± 8,904’± 7,559’± 7,574’16’12/12/20 Open T-146 ± 9,209’± 9,229 ± 7,848’± 7,867’20’12/12/20 Open T-150 9363’9393’7990’8017’30’12/10/20 Isolated (12/12/20) RA Tags Joint Tops:1668’, 2077’, 2615’, 3274’, 3729’, 4306’, 4718’, 6129’ (all MD) OPEN HOLE / CEMENT DETAIL 7-5/8"76 bbls of 12ppg lead cement and 32 bbls 15.8ppg tail cement in 9-7/8” hole – 29 bbls returned to surface, no losses during job. 4-1/2”243 bbls of 12ppg lead cement and 41 bbls 15.3ppg tail cement in 6-3/4” hole – no spacer nor cement to surface. 10 bbl losses during job. CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 127' 7-5/8"Surf Csg 29.7 L-80 USS-CDC 6.875”Surf 1,567’ 4-1/2"Prod Csg 12.6 L-80 DWC/C HT 3.958”Surf 9,775’ 1 16” 7-5/8” 9-7/8” hole 4-1/2” 6-3/4” hole ToC at ~3040’ per 11/18/20 CBL 2 IA dowsqueeze on 12-2-20 STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 777-8510. Received By: Date: Date: 12/11/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KALOTSA 7 (PTD 220-067) FINAL LWD FORMATION EVALUATION LOGS (10/22/2020 to 11/03/2020) •ROP, DGR, GM, ADR, ALD, CTN (2” & 5” MD / TVD Color Logs) •GEOTAP - Formation Pressure Tester •Final Definitive Directional Survey SFTP Transfer - Data Folders: Received by the AOGCC 12/11/2020 PTD: 2200670 E-Set: 34375 Abby Bell 12/11/2020 Hilvirp Alaska.IJA. Date: 12/01/2020 David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 CenterPoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com To: Alaska Oil & Gas Conservation Commission t /2-L Cewe-i C, _e'6 333 W 7th Ave Ste 100 Anchorage, AK 99501 / 15'Gv��s- DATA TRANSMITTAL KALOTSA 7 (PTD 220-067) Washed and Dried Well Samples B Set - 6 Boxes: WELL BOX SAMPLE INTERVAL (FEET / MD) KALOTSA 7 BOX 1 OF 6 1440'- 3000' MD KALOTSA 7 BOX 2 OF 6 3000'- 4500' MD KALOTSA 7 BOX 3 OF 6 4500'- 6300' MD KALOTSA 7 BOX 4 OF 6 6300'- 7980' MD KALOTSA 7 BOX 5 OF 6 7980'- 9510' MD KALOTSA 7 BOX 6 OF 6 9510' - 9785' MD (TD) Please include current contact information if different from above. o"go-o6--f- l T(A) RECEIVED DEC 0 1 202U Please acknowledge receipt by signing and returning one copy of this transmittal via Email or FAX to: (907) 777-8510 Received<1_y_�n k O Date: o? r l Z—O —J- 13 VMS 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 and/or Patch_____ 2. Operator Name:4. Current Well Class:5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6.API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 9,785'none Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 7,500psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Ryan Rupert Operations Manager Contact Email: Contact Phone: 777-8503 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng ryan.rupert@hilcorp.com 8,385'9,690'8,294'~3085 none Swell Packer ; n/a 1321' / 1221' TVD, n/a Perforation Depth TVD (ft):Tubing Size: COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 C061505, ADL384372 220-067 50-133-20693-00-00 Kalotsa-07 Ninilchik Field / Beluga/Tyonek Gas Pool Length Size CO 701C Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY 12.6# L-80 TVD Burst 1,321' 8,430psi MD 2,980psi 6,880psi 127' 1,258' 127' 1,567' 8,375'4-1/2" 16" 7-5/8" 127' 1,567' 9,775' Perforation Depth MD (ft): See Attached Schematic 9,775' 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: November 15, 2020 4-1/2" m n P s 66 t _ Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 10:41 am, Nov 16, 2020 320-483 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.11.13 16:05:46 -09'00' Taylor Wellman 10-407 GAS Perforate Initial completion - gls 11/18/20 (final well report) X DLB X DLB11/24/2020 DSR-11/24/2020 CTU *Passing MIT-IA required before perforating wellbore. __N2 and/or Patch___ gls 11/26/20 * T-150 must be isolated before perforating upper zones per CO 701C. *4000 psi BOPE test (CT) X : Comm. 11/27/2020 dts 11/27/2020 JLC 11/27/2020 RBDMS HEW 11/30/2020 Well: Kalotsa-07 Date: 11/25/2020 Well Name: Kalotsa-07 API Number: 50-133-20693-00-00 Current Status: New drill Gas Producer Leg: N/A Estimated Start Date: 11/27/20 Rig: CT / EL / Pumping Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 220-067 First Call Engineer: Ryan Rupert (907) 777-8503 (O) (907) 301-1736 (C) Second Call Engineer: Todd Sidoti (907) 632-4113 (C) Maximum Expected BHP: ~ 3801 psi @ 7,162’ TVD (Based on T-100 RFT pressure acquired 11/4/20) Max. Potential Surface Pressure: ~ 3085 psi Using Max BHP minus 0.1 psi/ft. gas gradient to surface). Well Summary Kalotsa-07 is a new drill well TD’d 11/3/20. The objective of this below intervention is to obtain the required CBL and MIT-IA (covered under approved PTD 220-067), and initially complete the well. After the IA was found to bleed back gas on 11/17/20 with no signs of tapering off, the MIT-IA attempt was canceled. The program below has been modified to address this, and gain a hard bottom in the IA. Updates are in red. Notes Regarding Wellbore Condition x Min ID = 3.833” (drift ID of 4-1/2” tubing/liner) x Max deviation = 49 degrees at 1652’ MD x On rig casing scraper (3.75” OD) tagged PBTD at 9681’ on 11/10/20 (driller depth) x Well was left with 6% KCL x MIT-T to 3630 psi passed on 11/11/20 on rig Safety Concerns - Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. - Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job) - Ensure all crews are aware of stop work authority Pre-perf work: (Covered under approved PTD 220-067) 1. MIT-IA to at least 2000psi. Failed. Bled gas back. 2. MIRU Coiled Tubing, PT BOPE to 4,000 psi Hi 250 Low. (notify AOGCC 24 hrs. in advance) 3. RIH with memory CBL and lightly tag PBTD 4. Log CBL from PBTD to surface a. Contingency: CBL may be run on EL, if scheduling dictates. If so BOP test would be to 2500 psi high and 250 psi low. EL completed CBL 11/18/20 note: TOC at approx 3000 ft. gls 11/24/20 Well: Kalotsa-07 Date: 11/25/2020 NEED AOGCC Approval before below steps IA Downsqueeze - Objectives o Create a hard bottom in 4-1/2” x 7-5/8” annulus capable of passing an MIT-IA to 2000 psi o Get some cement outside the surface casing shoe o Leave an uncemented moniterable annulus above Target ±1185’ MD ToC Target ToC no shallower than ±500’ 500’ planned ToC is a “no-higher-than” depth if the well locks up just as the cement hits the swell packer. Per the design below, if no bridging off, we’ll plan to stop pumping with 10bbls left inside the annulus (ToC ±1185’ MD), and 12 bbls in the openhole annulus. - Volumes o 35 bbls to swell packer o 41 bbls to 7-5/8” shoe - IA Injectivity test results: o See table below o All results shown below are after a 50bbl fillup/sweep volume was pumped o Shows sufficient injectivity to perform cement downsqueeze at high rate o Also shows openhole does provide some backpressure (not on a vacuum) Rate (bpm) Pump pressure (psi) 0.9 730 1.3 760 1.7 790 2.2 820 2.5 855 3.2 905 3.7 940 5.0 1120 1. MIRU cementing equipment 2. Test surface cement lines to 4500 psi 3. Re-establish injectivity down the IA, and confirm still sufficient for downsqueeze 4. Pump a 22 bbl IA cement downsqueeze per vendor schedule. a. Target 10 bbls left in the 7-5/8” x 4-1/2” annulus. ToC no deeper than ±1185’ MD b. If IA locks up while still pumping cement: i. Stop cementing operations ii. Circulate across the top (out companion IA valve) until cement is out of lines iii. Ramp up to max pressure at 4500 psi with displacement fluid and hold there while continuing to monitor rate iv. If no movement after 30 mins, RDMO and bleed pressure to ~50psi. Will reevaluate to make a remediation plan c. If IA locks up while pumping displacement fluid i. Pressure up no more than 500psi over baseline pump pressure and continue to monitor rates (4.5" x 7 5/8") Well: Kalotsa-07 Date: 11/25/2020 ii. If it will take fluid, slowly displace cement to target ToC = ±1185’ MD, then shut down iii. If no fluid movement, hold there and discuss results with OE 5. Bleed IAP down to ~50psi and shut in IA 6. RD cementers 7. WoC 8. MIT-IA to 2000 psi Completion work 1. MIRU Coiled Tubing, PT BOPE to 4,000 psi Hi 250 Low. (notify AOGCC 24 hrs. in advance) 2. MU Jet nozzle and memory GR/CCL sub and RIH. 3. RU N2 pumping unit. 4. RIH to PBTD, and come online with N2 and jet well dry down to PBTD. a) Estimated volume of displaced 6% KCl is (+/-) 145 bbls. 5. Once well is dry, leave 3000 psi on the well for first perforation interval. 6. POOH w/ coil. LD BHA. 7. RDMO CT 8. MIRU EL and pressure control equipment. PT lubricator to 4,000 psi Hi 250 Low. a) Note that the well is pressurized with nitrogen. 9. PU perf gun per below for the T-150 interval, and RIH 10. Bleed WHP per OE 11. Tie in to formation and perforate the T-150 sand Sand MD Top MD Bottom TVD Top TVD Bottom Total Footage (MD) Expected BHP (psi) T-150 ± 9,363’ ± 9,393’ ± 7,990’ ± 8,017’ 30’ 3,754 a. Record initial and 5/10/15 minute tubing pressures after firing b. CO 701C covers sands down to and including the T-148. Sands deeper than that are outside of the current CO. i. Rule 2 of Conservation Order 701C defines “The Ninilchik Beluga/Tyonek Gas Pool as the intervals common to and correlating between the measured depths of 1,555’ and 9,035’ in the Kalotsa no. 3 well” ii. The proposed perfs in the T-150 sand fall below the defined base of the Ninilchik Beluga/Tyonek Gas Pool iii. Hilcorp proposes to shoot this zone individually (no commingling) and test for production. If this zone proves productive, Hilcorp will apply to AOGCC for a spacing exception. iv. If this zone proves non-productive, the interval will be plugged back before any other zones are perforated. 12. POOH with EL ensure all shots fired, LD spent perf gun 13. Bring well onto production. If sufficient rate per Geo/RE, no further action is necessary, RDMO EL. T-150 ± 9,363’± 9,393’± 7,990’± 8,017’30’3,754 (Send MIT-IA chart to AOGCC) Do not continue operations until passing MIT-IA is obtained. gls 11/25/20 Well: Kalotsa-07 Date: 11/25/2020 If rate from T-150 is insufficient, proceed with the below steps. In all circumstances, the T-150 may NOT be produced with other sand intervals. A plug must be set isolating the T-150 before adding any uphole sands. 14. MIRU N2 pumping unit 15. Bullhead displace well to nitrogen a) Note starting SITP before pumping b) Likely will take a while given the high pressure interval c) Likely will have water to surface, and will need to displace entire WBV (145 bbls) into open perfs d) Track N2 pumped and only rigup EL after the majority of a WBV has been pumped (at 4000psi will require 240,000scf) e) Leave at least 2000 psi on well 16. MIRU EL and pressure control equipment. PT lubricator to 4,000 psi Hi 250 Low. a) Note that the well is pressurized with nitrogen. 17. MU 4-1/2” CIBP and GPT tool. 18. RIH and use GPT tool on plug set BHA to ensure fluid has been pushed below 9240’ MD 19. Set 4-1/2” plug 9,355’ MD avoiding collars a) If FL is found higher, but below T-146 perf interval, ok to set plug higher b) Deeper the better for plug set to maximize rathole. 20. Ensure at least 2000 psi nitrogen pressure is on well after plug set. 21. RU perf guns. Likely 2-7/8”guns with 6 spf 22. RIH and perforate the below intervals bottom up per Geo/RE: Sand MD Top MD Bottom TVD Top TVD Bottom Total Footage (MD) Expected BHP (psi) T-67 ± 7,735’ ± 7,745’ ± 6,542’ ± 6,551’ 10’ 3,519 T-69 ± 7,794’ ± 7,814’ ± 6,594’ ± 6,611’ 20’ 2,971 T-73 ± 7,900’ ± 7,906’ ± 6,688’ ± 6,693’ 6’ 3,456 T-98 ± 8,348’ ± 8,358’ ± 7,084’ ± 7,093’ 10’ 3,190 T-100 ± 8,437’ ± 8,449’ ± 7,162’ ± 7,172’ 12’ 3,801 T-140.b ± 8,865’ ± 8,882’ ± 7,539’ ± 7,554’ 17’ 2,886 T-140.c ± 8,888’ ± 8,904’ ± 7,559’ ± 7,574’ 16’ 2,886 T-146 ± 9,209’ ± 9,229 ± 7,848’ ± 7,867’ 20’ 3,046 a. Consult with OE for what WHP to use for each perf set. Some may be shot while the well is flowing, also. b. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. c. Use Gamma/CCL to correlate. d. Record initial and 5/10/15 minute tubing pressures after firing e. Consult with RE/Geo between each perf interval: i. Anthony McConkey: RE - 529-6199 ii. Matthew Petrowsky: Geo – 814-421-6753 NOTE: CIBP set to isolate T-150 d w Well: Kalotsa-07 Date: 11/25/2020 f. CO 701C covers sands down to and including the T-148. Sands deeper than that are outside of the current CO. i. The rest of the perforations in table above are fall within the defined Ninilchik Beluga/Tyonek Gas Pool, as currently defined. ii. T-150 sand MUST be isolated before any uphole perfs are shot 23. Once sufficient production has been added per RE/Geo, RD E-Line Unit and turn well over to production. CONTINGENT: If a zone is shown to make undesirable sand/water, set plug or patch for shut-off 24. MIRU EL unit 25. PT BOP equipment to 250 psi Low / 4500 psi High. (Notify AOGCC 24 hrs. in advance on BOP test.) 26. If necessary, displace well with N2 taking returns into open formation 27. MU 4-1/2” patch and/or plug per vendor recommendation 28. RIH and set over identified perf interval 29. RDMO EL Attachments: 1. Current schematic 2. Proposed Schematic 3. Standard Well procedure – N2 Operations gy y ii.T-150 sand MUST be isolated before any uphole perfs are shot CO 701C covers sands down to and including the T-148. Well: Kalotsa-07 Date: 11/12/2020 Well Name:Kalotsa-07 API Number:50-133-20693-00-00 Current Status:New drill Gas Producer Leg:N/A Estimated Start Date:11/19/20 Rig:CT / EL Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:220-067 First Call Engineer:Ryan Rupert (907) 777-8503 (O)(907) 301-1736 (C) Second Call Engineer:Todd Sidoti (907) 632-4113 (C) Maximum Expected BHP:~ 3801 psi @ 7,162’ TVD (Based on T-100 RFT pressure acquired 11/4/20) Max. Potential Surface Pressure:~ 3085 psi Using Max BHP minus 0.1 psi/ft. gas gradient to surface). Well Summary Kalotsa-07 is a new drill well TD’d 11/3/20. The objective of this below intervention is toobtain the requiredCBL and MIT-IA (covered under approved PTD 220-067), and initially complete the well. Notes Regarding Wellbore Condition x Min ID = 3.833” (drift ID of 4-1/2” tubing/liner) x Max deviation = 49 degrees at 1652’ MD x On rig casing scraper (3.75” OD) tagged PBTD at 9681’ on 11/10/20 (driller depth) x Well was left with 6% KCL x MIT-T to 3630 psi passed on 11/11/20 on rig Safety Concerns - Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. - Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job) - Ensure all crews are aware of stop work authority Pre-perf work:(Covered under approved PTD 220-067) 1. MIT-IA to at least 2000psi. 2. MIRU Coiled Tubing, PT BOPE to 4,000 psi Hi 250 Low. (notify AOGCC 24 hrs. in advance) 3. RIH with memory CBL and lightly tag PBTD 4. Log CBL from PBTD to surface 5. Confirm good data a. Contingency: CBL may be run on EL, if scheduling dictates. If so BOP test would be to 2500 psi high and 250 psi low. (forward chart to AOGCC) Forward CBL and MIT-IA data to AOGCC prior to perforating. MIT-IA CBL NOTE : MIT-IA did not pass. 11/20/20 Superceded Well: Kalotsa-07 Date: 11/12/2020 Sundry completion work (NEED AOGCC Approval before continue): 1. MU Jet nozzle and memory GR/CCL sub and RIH. 2. Pull logging pass up from PBTD to 9100’ Flag pipe at ~9330’ for upcoming perf run 3. RU N2 pumping unit. 4. Run back to PBTD, and come online with N2 and jet well dry down to PBTD. a) Estimated volume of displaced 6% KCl is (+/-)145 bbls. 5. Once well is dry, leave 3000 psi on the well for first perforation interval. 6. POOH w/ coil. LD BHA. 7. Download data, and tie in coil flag per Geo/RE 8. PU perf gun per below for the T-150 interval, and RIH 9. Bleed WHP to ~2000psi 10. Tie in to corrected coil flag and shoot T-150 (a few feet of depth uncertainty is acceptable for this sand) Sand MD Top MD Bottom TVD Top TVD Bottom Total Footage (MD) Expected BHP (psi) T-150 ± 9,363’± 9,393’± 7,990’± 8,017’30’3,754 a. Record initial and 5/10/15 minute tubing pressures after firing b. CO 701C covers sands down to and including the T-148.Sands deeper than that are outside of the current CO. i. Rule 2 of Conservation Order 701C defines “The Ninilchik Beluga/Tyonek Gas Pool as the intervals common to and correlating between the measured depths of 1,555’ and 9,035’ in the Kalotsa no. 3 well” ii. The proposed perfs in the T-150 sand fall below the defined base of the Ninilchik Beluga/Tyonek Gas Pool iii. Hilcorp proposes to shoot this zone individually (no commingling) and test for production. If this zone proves productive, Hilcorp will apply to AOGCC for a spacing exception. iv. If this zone proves non-productive, the interval will be plugged back before any other zones are perforated. 11. POOH w/ coil, ensure all shots fired, LD spent perf gun, and RDMO CT 12. Bring well onto production. If sufficient rate per Geo/RE, no further action is necessary. If rate from T-150 is insufficient, proceed with the below steps.In all circumstances, the T-150 may NOT be produced with other sand intervals. A plug must be set isolating the T-150 before adding any uphole sands. 13. MIRU N2 pumping unit 14. Bullhead displace well to nitrogen a) Note starting SITP before pumping b) Likely will take a while given the high pressure interval c) Likely will have water to surface, and will need to displace entire WBV (145 bbls) into open perfs T-150 ± 9,363’± 9,393’± 7,990’± 8,017’30’3,754 Will use Eline to perforate the T-150 sand per email from Hilcorp. gls 11/17/20 f rate from T-150 is insufficient, proceed with the below steps.In all circumstances, the T-150 may NOT be produced with other sand intervals. A plug must be set isolating the T-150 before adding any uphole sands. ????? sand cannot be co-mingled. DLB 11/24/2020 Not needed. T-150 SUPERCEDED superceded Well: Kalotsa-07 Date: 11/12/2020 d) Track N2 pumped and only rigup EL after the majority of a WBV has been pumped (at 4000psi will require 240,000scf) e) Leave at least 2000 psi on well 15. MIRU EL and pressure control equipment. PT lubricator to 4,500 psi Hi 250 Low. a) Note that the well is pressurized with nitrogen. b) Pressures as high as 4500 psi may be necessary to overcome reservoir pressure and for N2 to effectively displace the wellbore. 16. MU 4-1/2” CIBP and GPT tool. 17. RIH and use GPT tool on plug set BHA to ensure fluid has been pushed below 9240’ MD 18. Set 4-1/2” plug 9,355’ MD avoiding collars a) If FL is found higher, but below T-146 perf interval, ok to set plug higher b) Deeper the better for plug set to maximize rathole. 19. Ensure at least 2000 psi nitrogen pressure is on well after plug set. 20. RU perf guns. Likely 2-7/8”guns with 6 spf 21. RIH and perforate the below intervals bottom up per Geo/RE: Sand MD Top MD Bottom TVD Top TVD Bottom Total Footage (MD) Expected BHP (psi) T-67 ± 7,735’± 7,745’± 6,542’± 6,551’10’3,519 T-69 ± 7,794’± 7,814’± 6,594’± 6,611’20’2,971 T-73 ± 7,900’± 7,906’± 6,688’± 6,693’6’3,456 T-98 ± 8,348’± 8,358’± 7,084’± 7,093’10’3,190 T-100 ± 8,437’± 8,449’± 7,162’± 7,172’12’3,801 T-140.b ± 8,865’± 8,882’± 7,539’± 7,554’17’2,886 T-140.c ± 8,888’± 8,904’± 7,559’± 7,574’16’2,886 T-146 ± 9,209’± 9,229 ± 7,848’± 7,867’20’3,046 b. Consult with OE for what WHP to use for each perf set. Some may be shot while the well is flowing, also. c. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. d.Use Gamma/CCL to correlate. e. Record initial and 5/10/15 minute tubing pressures after firing f. Consult with RE/Geo between each perf interval: i. Anthony McConkey: RE - 529-6199 ii. Matthew Petrowsky: Geo – 814-421-6753 g. CO 701C covers sands down to and including the T-148. Sands deeper than that are outside of the current CO. i. The rest of the perforations in table above are fall within the defined Ninilchik Beluga/Tyonek Gas Pool, as currently defined. ii. T-150 sand MUST be isolated before any uphole perfs are shot 22. Once sufficient production has been added per RE/Geo, RD E-Line Unit and turn well over to production. Note: Plug must isolate T-150 sand before perfing the upper sands as listed. gls Superceded Well: Kalotsa-07 Date: 11/12/2020 CONTINGENT: If a zone is shown to make undesirable sand/water, set plug or patch for shut-off 23. MIRU EL unit 24. PT BOP equipment to 250 psi Low / 4500 psi High. (Notify AOGCC 24 hrs. in advance on BOP test.) 25. If necessary, displace well with N2 taking returns into open formation 26. MU 4-1/2” patch and/or plug per vendor recommendation 27. RIH and set over identified perf interval 28. RDMO EL Attachments: 1. Proposed Schematic 2. Standard Well procedure – N2 Operations Superceded Updated by CRR 11-10-2020 PROPOSED SCHEMATIC Ninilchik Unit Kalotsa #7 PTD:220-067 API: 50-133-20693-00-00 PBTD = 9,690’ / TVD = 8,294’ TD = 9,785’ / TVD = 8,385’ RKB to GL = 18’ PERFORATION DETAIL Sands Top (MD)Btm (MD)Top (TVD)Btm (TVD)FT SPF Date Status Proposed Perfs per Completion Sundry RA Tags Joint Tops:1668’, 2077’, 2615’, 3274’, 3729’, 4306’, 4718’, 6129’ (all MD) OPEN HOLE / CEMENT DETAIL 7-5/8"76 bbls of 12ppg lead cement and 32 bbls 15.8ppg tail cement in 9-7/8” hole – 29 bbls returned to surface, no losses during job. 4-1/2”243 bbls of 12ppg lead cement and 41 bbls 15.3ppg tail cement in 6-3/4” hole – no spacer nor cement to surface. 10 bbl losses during job. Estimated ToC @ 420’ with 20% washout CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 127' 7-5/8"Surf Csg 29.7 L-80 USS-CDC 6.875”Surf 1,567’ 4-1/2"Prod Csg 12.6 L-80 DWC/C HT 3.958”Surf 9,775’ 1 16” 7-5/8” 9-7/8” hole 4-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 1,321’3.958”6.875”Swell Packer 6-3/4” hole T-150 IA will not test.... Cement top below surface casing shoe. CBL indicates TOC approx 3000 ft MD 1567ft 1321 ft Must isolate T150 before upper zones are perfed. gls CBL indicates TOC approx. 3000 ft md gls 11/24/20 STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: Date: 11/16/2020 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL KALOTSA 7 (PTD 220-067) GEOLOG: EOW DRILL REPORTS (11/03/2020) 1.DAILY DRILLING REPORTS 2.FINAL EOW REPORT 3.SHOW REPORTS 4.LWD LOGS 5.MUDLOGS Folder Contents: Please include current contact information if different from above. PTD: 2200670 E-Set: 34266 Received by the AOGCC 11/16/2020 Abby Bell 11/16/2020 Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 01/12/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KALOTSA 7 (PTD 220-067) PRESSURE, TEMP, SPINNER LOG 12/29/2020 Please include current contact information if different from above. PTD: 2200670 E-Set: 34570 Received by the AOGCC 01/13/2021 Abby Bell 01/14/2021 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Monty M Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Ninilchik Field, Beluga/Tyonek Gas Pool, Kalotsa 7 Hilcorp Alaska, LLC Permit to Drill Number: 220-067 Surface Location: 2201' FSL, 539' FWL, Sec 7, T1S, R13W, SM, AK Bottomhole Location: 1179' FNL, 1404' FWL, Sec 12, T1S, R14W, SM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced development well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jeremy M. Price Chair DATED this ___ day of October, 2020. 20 Jeremy M. Price Digitally signed by Jeremy M. Price Date: 2020.10.20 10:07:12 -08'00' 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 9,781' TVD: 8,345' 4a. Location of Well (Governmental Section):7. Property Designation: Surface: Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date: Total Depth:9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 144.5' 15. Distance to Nearest Well Open Surface: x- 209937 y- 2233474 Zone-4 126.5' to Same Pool: 1044' to SD 4 16. Deviated wells:Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 47 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Cond 16" 84# J-55 Weld 120' Surface Surface 120' 120' 9-7/8" 7-5/8" 29.7# L-80 USS CDC 1,550' Surface Surface 1,550' 1,381' 6-3/4" 4-1/2" 12.6# L-80 DWC/C HT 9,781' Surface Surface 9,781' 8,345' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned?Yes No 20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number:50- Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Sr Pet Eng Sr Pet Geo Sr Res Eng 5008' to nearest unit boundary 10/28/2020 Authorized Name: Monty Myers Authorized Title: Drilling Manager Frank Roach frank.roach@hilcorp.com 777-8413 18. Casing Program:Top - Setting Depth - BottomSpecifications Kalotsa 7 Ninilchik Field Beluga/Tyonek Gas Pool 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp Alaska, LLC 2201' FSL, 539' FWL, Sec 7, T1S, R13W, SM, AK C061505, ADL384372 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 L - 1355 ft3 / T - 90 ft3 2920 2143' FNL, 1014' FEL, Sec 12, T1S, R14W, SM, AK 1179' FNL, 1404' FWL, Sec 12, T1S, R14W, SM, AK N/A 4762 3755 Total Depth MD (ft):Total Depth TVD (ft): Cement Quantity, c.f. or sacks Cement Volume MDSize Plugs (measured): (including stage data) Driven L - 408 ft3 / T - 181 ft3 Effect. Depth TVD (ft): Conductor/Structural Length Production Liner Casing Intermediate Commission Use Only Effect. Depth MD (ft): Authorized Signature: See cover letter for other requirements. Perforation Depth MD (ft): 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): 10/1/2020 es N ype of W L l R L 1b S Class: os N es No s N o D s s s D 84 o : well is p G S S 20 S S S es No s No S G E S es No s Form 10-401 Revised 3/2020 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) By Samantha Carlisle at 9:23 am, Oct 01, 2020 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2020.10.01 08:28:24 -08'00' Monty M Myers 133-20693-00-00 9,781 X (TD pending LOT results) *CBL and MIT-IA required before perforating well DLB 10/06/2020 X X Development - Gas DSR-10/1/2020 X *3500 psi BOPE test *Forward FIT/LOT data to AOGCC for review *Separate Sundry required for well completion (perforations) *Diverter Waived per 20 AAC 25.035(h)(2) gls 10/15/20 220-067 X X X 10/20/2020 10/20/2020Jeremy M. Price Digitally signed by Jeremy M. Price Date: 2020.10.20 10:10:09 -08'00' Kalotsa #7 Drilling Program Ninilchik Unit Rev 0 September 30th, 2020 Kalotsa #7 Drilling Procedure Contents 1.0 Well Summary ................................................................................................................................. 2 2.0 Management of Change Information ............................................................................................ 3 3.0 Tubular Program: ........................................................................................................................... 4 4.0 Drill Pipe Information: ................................................................................................................... 4 5.0 Internal Reporting Requirements ................................................................................................. 5 6.0 Planned Wellbore Schematic ......................................................................................................... 6 7.0 Drilling / Completion Summary .................................................................................................... 7 8.0 Mandatory Regulatory Compliance / Notifications ..................................................................... 8 9.0 R/U and Preparatory Work ......................................................................................................... 10 10.0 N/U 16” Conductor Riser ............................................................................................................. 10 11.0 Drill 9-7/8” Hole Section ............................................................................................................... 12 12.0 Run 7-5/8” Surface Casing ........................................................................................................... 14 13.0 Cement 7-5/8” Surface Casing ..................................................................................................... 17 14.0 BOP N/U and Test ......................................................................................................................... 21 15.0 Drill 6-3/4” Hole Section ............................................................................................................... 22 16.0 Run 4-1/2” Production Casing ..................................................................................................... 25 17.0 Cement 4-1/2” Production Casing ............................................................................................... 28 18.0 RDMO ............................................................................................................................................ 30 19.0 BOP Schematic .............................................................................................................................. 31 20.0 Wellhead Schematic ...................................................................................................................... 32 21.0 Days Vs Depth ............................................................................................................................... 33 22.0 Geo-Prog ........................................................................................................................................ 34 23.0 Anticipated Drilling Hazards ....................................................................................................... 35 24.0 Hilcorp Rig 169 Layout ................................................................................................................ 37 25.0 FIT/LOT Procedure...................................................................................................................... 38 26.0 Choke Manifold Schematic .......................................................................................................... 39 27.0 Casing Design Information .......................................................................................................... 40 28.0 6-3/4” Hole Section MASP ........................................................................................................... 41 29.0 Spider Plot (NAD 27) (Governmental Sections) ......................................................................... 42 30.0 Surface Plat (NAD 27) .................................................................................................................. 43 31.0 Directional Plan (wp08a) .............................................................................................................. 45 Page 2 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 1.0 Well Summary Well Kalotsa #7 Pad & Old Well Designation Kalotsa #7 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 9,781’ MD / 8,345’ TVD PBTD, MD / TVD 9,701’ MD / 8,274’ TVD Surface Location (Governmental) 2201' FSL, 539' FWL, Sec 7, T1S, R13W, SM, AK Surface Location (NAD 27) X=209937.09, Y=2233474.16 Top of Productive Horizon (Governmental) 2143' FNL, 1014' FEL, Sec 12, T1S, R14W, SM, AK TPH Location (NAD 27) X=208407.99, Y=2234361.19 BHL (Governmental) 1179' FNL, 1404' FWL, Sec 12, T1S, R14W, SM, AK BHL (NAD 27) X=205570.13, Y=2235394.36 AFE Number 2013112 AFE Drilling Days 3 MOB, 23 DRLG AFE Completion Days 10 AFE Drilling Amount $5,818,651 AFE Completion Amount $1,097,984 Maximum Anticipated Pressure (Surface) 2920 psi Maximum Anticipated Pressure (Downhole/Reservoir) 3755 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB – GL 144.5’(126.5 + 18) Ground Elevation 126.5’ BOP Equipment 11” 5M T3-Energy Annular BOP 11” 5M T3-Energy Double Ram 11” 5M T3-Energy Single Ram Page 3 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 2.0 Management of Change Information (and approved by AOGCC) Page 4 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 3.0 Tubular Program: Hole Section OD (in) ID (in) Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 16” 15.01” 14.822 17” 84 J-55 Weld 2980 1410 - 9-7/8” 7-5/8” 6.875” 6.750” 8.5” 29.7 L-80 USS CDC 6880 4790 683 6-3/4” 4-1/2” 3.958” 3.833” 5.0” 12.6 L-80 DWC/C HT 8430 7500 288 4.0 Drill Pipe Information: Hole Section OD (in) ID (in) TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 4-1/2” 3.826 2.6875” 5.25” 16.6 S-135 CDS40 17,693 16,769 468k All casing will be new 8430 6880 Page 5 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellez. x Report covers operations from 6am to 6am x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry tab. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. 5.2 Afternoon Updates x Submit a short operations update each work day to Frank.Roach@hilcorp.com, mmyers@hilcorp.coma and cdinger@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. Each rig will be assigned a username to login with. 5.4 EHS Incident Reporting x Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don’t wait until an emergency to have to call around and figure it out!!!! a. John Coston: O: (907) 777-6726 C: (907) 227-3189 b. Matt Hogge: O: (907) 777-8418 C: (907) 227-9829 2. Spills: Keegan Fleming: O:907-777-8477 C:907-350-9439 x Notify Drlg Manager 1. Monty M Myers: O: 907-777-8431 C: 907-538-1168 x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to Frank.Roach@hilcorp.com and cdinger@hilcorp.com 5.6 Casing and Cmt report x Send casing and cement report for each string of casing to Frank.Roach@hilcorp.com and cdinger@hilcorp.com Page 6 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 6.0 Planned Wellbore Schematic FIT/LOT Min = 14 ppg EMW Forward data to AOGCC MIT-IA to 2000 psi Sundry approval required to perforate well CBL required over 4.5" casing Page 7 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 7.0 Drilling / Completion Summary Kalotsa #7 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 and Tyonek sands. The base plan is a directional wellbore with a kick off point at 300’ MD. Maximum hole angle will be 47° and TD of the well will be 9,781’ MD/ 8,345’ TVD, ending with 28° inclination left in the hole. Vertical section will be 4,770 ft. Drilling operations are expected to commence approximately October 28th, 2020. The Hilcorp Rig # 169 will be used to drill the wellbore then run casing and cement. Surface casing will be run to 1,550’ MD / 1,380’ TVD and cemented to surface to ensure protection of any shallow freshwater resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed, a Temp log will be run between 6 – 18 hrs after CIP to determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. General sequence of operations: 1. MOB Hilcorp Rig # 169 to well site 2. N/U conductor riser. (No diverter, diverter waiver requested) 3. Drill 9-7/8” hole to 1,550’ MD. Run and cmt 7-5/8” surface casing. 4. ND conductor riser, N/U & test 11” x 5M Townsend BOP. 5. Drill 6-3/4” hole section to 9,781’ MD. Perform Wiper trip. 6. Make cleanout run 7. POOH laying down drill pipe. 8. Run and cmt 4-1/2” production casing. 9. N/D BOP, N/U temp abandonment cap, RDMO. Reservoir Evaluation Plan: 1. Surface hole: GR + Res (LWD) 2. Production Hole: GR + Res + Den/Neu (LWD). 3. Mud loggers from surface casing point to TD. Kalotsa #7 is a S-shaped directional grassroots development well to be drilled off of the Kalotsa pad. pg pp Reservoir analysis and subsurface mapping has identified an optimal location for infill development of they Beluga and Tyonek sands. Page 8 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling of Kalotsa #7. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3500 psi & subsequent tests of the BOP equipment will be to 250/3500 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements” x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. Regulation Variance Requests: x Diverter waiver requested due to the recent drilling of Kalotsa #1, Kalotsa #2, Kalotsa #3, and Kalotsa #4 nearby. 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 1380’ TVD on Kalotsa #7. No shallow hydrocarbon zones will be penetrated. Diverter waiver approved... gls 10/15/20 Page 9 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 9-7/8” x No diverter utilized n/a 6-3/4” x 11” x 5M Annular BOP x 11” x 5M Double Ram o Blind ram in btm cavity x Mud cross x 11” x 5M Single Ram x 3-1/8” 5M Choke Line x 2-1/16” x 5M Kill line x 3-1/8” x 2-1/16” 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3500 (Annular 2500 psi) Subsequent Tests: 250/3500 (Annular 2500 psi) x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Additional requirements may be stipulated on APD and Sundry. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov Guy Schwartz / Petroleum Engineer / (O): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / Email: melvin.rixse@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email: victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 10 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 9.0 R/U and Preparatory Work 9.1 Set 16” conductor at +/-120’ below ground level. 9.2 Dig out and set impermeable cellar. 9.3 Install 16-3/4” 3M “A” section. Ensure to orient wellhead so that tree will line up with flowline later. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of rig. 9.6 R/U Hilcorp Rig # 169, spot service company shacks, spot & R/U company man & toolpusher offices. 9.7 RU Mud loggers on surface hole section for gas detection only. No samples required 9.8 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.9 Mix mud for 9-7/8” hole section. 9.10 Install 5-1/2” liners in mud pumps. xx HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes with 5-1/2” liners 10.0 N/U 16” Conductor Riser 10.1 N/U 16” Conductor Riser x Ensure line does not direct flow from trip tank straight down the flowline. Fill up line and flowline should be oriented 90 degrees to each other at approx. the same height. x Ensure flowline outlet installed so that enough slope exists to carry cuttings to the shakers. x Consider adding additional drainage points at the bottom of the conductor riser if deemed necessary. x R/U fill up line to conductor riser. 10.2 Set wear bushing in wellhead. R/U Hilcorp Rig # 169, spot service company shacks, spot & R/U company man & toolpusher Diverter waived per 20 AAC 25.035 (h)(2) gls 10/15/20 Page 11 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 10.3 Rig Orientation on Kalotsa pad: Page 12 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 11.0 Drill 9-7/8” Hole Section 11.1 P/U 9-7/8” directional drilling assy: xx Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Workstring will be 4.5” 16.6# S-135 CDS40 11.2 9-7/8” BHA (GR and Res are included in BHA): 11.3 PU 9-7/8” bit, 4-1/2” HWDP, Jars, & Workstring 11.4 Begin drilling out from 16” conductor at reduced flow rates to avoid broaching the conductor. 11.5 Drill 9-7/8” hole section to 1,550’ MD/ 1,380’ TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate. x Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team. x Keep swab and surge pressures low when tripping. x Make wiper trips every 500’ or every couple days unless hole conditions dictate otherwise. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. x TD the hole section in a good shale between 1550’ MD and 1600’ MD. x Take MWD surveys every stand drilled (60’ intervals). 11.6 9-7/8” hole mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. System Type: 8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Page 13 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 120-1550’ 8.8 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0 System Formulation: Aquagel + FW spud mud Product Concentration FRESH WATER SODA ASH AQUAGEL CAUSTIC SODA BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT ALDACIDE G X-TEND II 0.905 bbl 0.5 ppb 12-15 ppb 0.1 ppb (9 pH) as needed as required for weight if required for <12 FL 0.1 ppb 0.02 ppb 11.7 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16” conductor shoe. 11.8 TOH with the drilling assy, handle BHA as appropriate. 8.8 – 9.5 Note: EMW needed per P. 41: 5.6 - 8.7 ppg. DLB Page 14 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 12.0 Run 7-5/8” Surface Casing 12.1 R/U and pull wear-bushing. 12.2 R/U Weatherford 7-5/8” casing running equipment. xx Ensure 7-5/8” CDC x CDS 40 XO on rig floor and M/U to FOSV. x R/U fill-up line to fill casing while running. x Ensure all casing has been drifted on the location prior to running. x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ float shoe bucked on (thread locked). x (1) Joint with coupling thread locked. x (1) Joint with float collar bucked on pin end & thread locked. x Install (2) centralizers on shoe joint over a stop collar. 10’ from each end. x Install (1) centralizer, mid tube on thread locked joint and on FC joint. x Ensure proper operation of float equipment. 12.5 Continue running 7-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x M/U connections to the base of the triangle stamped on the pin end. Note M/U torque values required to achieve this position. x After making up several connections, use the torque required to M/U to base of triangle as the M/U torque and continue running string. x Install (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the event a top out job is needed. x Utilize a collar clamp until weight is sufficient to keep slips set properly. 7-5/8” USS-CDC Estimated M/U Torque Casing OD Minimum Maximum Yield Torque 7-5/8” 14,000 ft-lbs 17,000 ft-lbs 20,900 ft-lbs Page 15 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 Page 16 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.7 Slow in and out of slips. 12.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 12.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 12.11 After circulating, lower string and land hanger in wellhead again. Page 17 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 13.0 Cement 7-5/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Cementers equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface. x Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. 13.2 Document efficiency of all possible displacement pumps prior to cement job 13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.4 Pump 5 bbls 10 ppg spacer. Test surface cmt lines. 13.5 Pump remaining 30 bbls of 10 ppg spacer. 13.6 Drop bottom plug. Mix and pump cmt per below recipe. 13.7 Cement volume based on annular volume + 50% open hole excess. Job will consist of lead & tail, TOC brought to surface. Cement volume based on annular volume + 50% open hole excess. Job will consist of lead & tail, TOC brought to surface. Page 18 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 SURFACE CEMENT CALCULATIONS CSG BTM (ft) 1,550 CSG Size 7 5/8 Section: Calculation: Vol (BBLS) Vol (ft3) LEAD: 120’ x .162 bpf = 19.45 109.2 16” Conductor x 7-5/8” Casing annulus: LEAD: (1,050’ – 120’) x .038 bpf x 1.5 = 53.36 299.6 9-7/8” OH x 7-5/8” Casing annulus: Total LEAD: 72.71 408.2 TAIL: (1,550’-1,050’) x .038 bpf x 1.5 = 28.68 160.0 9-7/8” OH x 7-5/8” Casing annulus: TAIL: 80 x .046 bpf = 3.67 20.6 7-5/8” Shoe track: Total TAIL: 32.36 180.6 Total Cement: 105.1 588.8 Cement Slurry Design: Lead Slurry (1050’ MD to surface) Tail Slurry (1550’ to 1050’ MD) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.46 ft3/sk 1.22 ft3/sk Mixed Water 14.349 gal/sk 5.507 gal/sk Mixed Fluid 14.469 gal/sk 5.507 gal/sk Additives Code Description Concentration Code Description Concentration G Cement 94#/sk A Cement 94#/sk D110 Retarder 0.15 gal/sk BWOC D046 Anti Foam 0.2 % BWOC D046 Anti Foam 0.2 % BWOC D065 Dispersant 0.4 % BWOC D079 Extender 2.0 % BWOC S002 CaCl2 0.35 % BWOC D020 Extender 3.0 % BWOC D177 CaCl2 0.1 % BWOC 165 SX 147 SX 2.46 ft3/sk 1.22 ft3/s Page 19 Version 0 August, 2020 Kalotsa #7 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: 1550’- 80’ = 1470’ x .046 bpf = 68 bbls 13.12 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.13 Do not over-displace by more than ½ shoe track volume. Total volume in shoe track is 3.7 bbls. x Be prepared for cement returns to surface. If cmt returns are not observed to surface, be prepared to run a temp log between 12 – 18 hours after CIP. x Be prepared with small OD top out tubing in the event a top out job is required. The AOGCC will require us to run steel pipe through the hanger flutes. The ID of the flutes is 1.5”. 13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 13.15 R/D cement equipment. Flush out wellhead with FW. 13.16 Back out and L/D landing joint. Flush out wellhead with FW. 13.17 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. p 1550’- 80’ = 1470’ x .046 bpf = 68 bbls Page 20 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 13.18 Lay down landing joint and pack-off running tool. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com, Frank.Roach@hilcorp.com, and mmyers@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 21 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 14.0 BOP N/U and Test 14.1 N/U wellhead assy. Install 7-5/8” packoff P-seals. Test to 3000 psi. 14.2 N/U 11” x 5M T3-Energy BOP as follows: xx BOP configuration from Top down: 11” x 5M T3-Energy annular BOP/11” x 5M T3-Energy Model 6011i double ram /11” x 5M mud cross/11” x 5M T3-Energy Model 6011i single ram x Double ram should be dressed with 2-7/8 x 5” VBRs in top cavity, blind ram in btm cavity. x Single ram should be dressed with 2-7/8 x 5” VBRs. x N/U bell nipple, install flowline. x Install (1) manual valves & (1) HCR valve on kill side of mud cross. x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 14.3 Run 4-1/2” BOP test assy, land out test plug (if not installed previously). x Test BOP to 250/3500 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. x Ensure to leave “B” section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.4 R/D BOP test assy. 14.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.6 Mix 9.0 ppg 6% KCL PHPA mud system. 14.7 R/U mud loggers for production hole section. 14.8 Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section. 3500 PSI BOPE TEST Page 22 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 15.0 Drill 6-3/4” Hole Section 15.1 Pull test plug, run and set wear bushing 15.2 Ensure BHA components have been inspected previously. 15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 15.4 TIH, Conduct shallow hole test of MWD and confirm Gamma Ray and Resistivity LWD functioning properly. 15.5 Ensure TF offset is measured accurately and entered correctly into the MWD software. 15.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. 15.7 Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 15.8 6-3/4” hole section mud program summary: Weighting material to be used for the hole section will be salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. System Type: 9.0 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 1,550’- 9,781’ 9.0 – 10.0 40-53 15-25 15-25 8.5-9.5 11.0 9.0 – 10.0 g Note: EMW needed per P. 41: 8.1 - 9.4 in T-10B. DLB Page 23 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 System Formulation: 6% KCL EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for a 9.0 – 10.0 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 15.9 TIH w/ 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. 15.10 R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on LOT graph. AOGCC requirement is 50% of burst. 7-5/8” burst is 6890 psi / 2 = 3445 psi. 15.11 Drill out shoe track and 20’ of new formation. 15.12 CBU and condition mud for LOT. 15.13 Conduct LOT to determine kick tolerance. Target minimum: 14.0 ppg EMW. Note: Only FITs have been performed on Kalotsa wells so the predicted frac gradient at the shoe is at least 13.5 ppg EMW. Offset field test data predicts frac gradient at the 7-5/8” shoe to be between 11 - 13 ppg EMW. A 14.0 ppg FIT results in a 4.5 ppg kick margin while drilling with the planned MW of 9.5 ppg. Results of the LOT will determine Well TD. Kick tolerance = (14.0-9.5)X(1380/8345) = 0.74 15.14 Drill 6-3/4” hole section to planned TD of 9,781’ MD / 8,345’ TVD. Depending on the LOT, this may be shortened to provide adequate kick tolerance for the interval. xx Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 225 - 300 gpm. Ensure shaker screens are set up to handle this flowrate. x Keep swab and surge pressures low when tripping. x Make wiper trips every 500’ unless hole conditions dictate otherwise. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed necessary. Approval for final TD to be determined after discussion with AOGCC. 14ppg LOT results in a 5 bbl kick tolerance. gls 10/15/20 2500 psi gls Long OH section below surface shoe. Forward LOT/FIT data to AOGCC for review gls 10-15-20 Page 24 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 15.15 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8” shoe. 15.16 POOH LDDP and BHA 15.17 4-1/2” pipe rams previously installed in BOP stack and tested. Page 25 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 16.0 Run 4-1/2” Production Casing 16.1. R/U Weatherford 4-1/2” casing running equipment. xx Ensure 4-1/2” DWC/C HT x CDS 40 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill casing while running. x Ensure all casing has been drifted prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.2. P/U shoe joint, visually verify no debris inside joint. 16.3. Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). x (1) joint casing, threadlocked (coupling also thread locked) x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x Solid body centralizers will be pre-installed on shoe joint an FC joint. x Leave centralizers free floating so that they can slide up and down the joint. x Ensure proper operation of float shoe and float collar. x Utilize a collar clamp until weight is sufficient to keep slips set properly 16.4. Continue running 4-1/2” production casing x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install solid body centralizers on every joint to 1,700’ MD. Leave the centralizers free floating. x Pick up swell packer and place in string at approximately 1,350’ MD. 16.5. Continue running 4-1/2” production casing 4-1/2” DWC/C HT M/U torques Casing OD Minimum Maximum Yield Torque 4-1/2” 5,800 ft-lbs 6,500 ft-lbs 8,400 ft-lbs Page 26 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 Page 27 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 16.6. Run in hole w/ 4-1/2” casing to the 7-5/8” casing shoe. 16.7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole dictates. 16.8. Obtain slack off weight, PU weight, rotating weight and torque of the casing. 16.9. Circulate 2X bottoms up at shoe, ease casing thru shoe. 16.10. Continue to RIH w/ casing no faster than 1 jt./minute. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.11. Set casing slowly in and out of slips. 16.12. PU swell packer to be placed at approximately 1,350’. 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, pick-up, and rotating (if possible) 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. Rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. swell packer Page 28 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 17.0 Cement 4-1/2” Production Casing 17.1. Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Cementers equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. x Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. x Document efficiency of all possible displacement pumps prior to cement job. 17.2. Attempt to reciprocate the casing during cmt operations until hole gets sticky 17.3. Pump 5 bbls of 10.5 ppg Mud Push spacer. 17.4. Test surface cmt lines to 4500 psi. 17.5. Pump remaining 30 bbls 10.5 ppg Mud Push spacer. 17.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed weight. Job is designed to pump 20% OH excess. Page 29 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 Production CEMENT CALCULATIONS CSG BTM (ft) 6,249 CSG Size 4 1/2 Section: Calculation: Vol (BBLS) Vol (ft3) LEAD: (1,550'-1,050') x .026 bpf = 13.12 73.7 7-5/8" x 4-1/2" Casing annulus: LEAD: (9,281’ – 1,550’) x .025 bpf x 1.20 = 228.12 1280.8 6-3/4" OH x 4-1/2" Casing annulus: Total LEAD: 241.24 1354.5 TAIL: (9,781’-9,281’) x .025 bpf x 1.20 = 14.75 82.8 6-3/4" OH x 4-1/2" Casing annulus: TAIL: 80 x .015 bpf = 1.22 6.8 4-1/2” Shoe track: Total TAIL: 15.97 89.7 Total Cement: 257.21 1444.2 17.7. Drop wiper plug and displace with 6% KCl 17.8. If hole conditions allow – continue reciprocating casing throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 17.9. If elevated displacement pressures are encountered, position casing at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 17.10. Bump the plug and pressure up to 500 psi over final lift pressure. Hold pressure for 3 minutes. 17.11. Do not over-displace by more than ½ shoe track. Shoe track volume is 1.2 bbls. 17.12. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 17.13. RD cementers and flush equipment. Page 30 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 17.14. WOC minimum of 12 hours, test casing to 3500 psi and chart for 30 minutes. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to Frank.Roach@hilcorp.com and mmyers@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 18.0 RDMO 18.1. Install BPV in wellhead 18.2. N/D BOPE 18.3. N/U temp abandonment cap 18.4. RDMO Hilcorp Rig #169 NOTE: Separate sundry to complete well needed. CBL and MIT-IA to 2000 psi will be required prior to perforating the well. gls 10/15/20 MIT 4 1/2" casing Page 31 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 19.0 BOP Schematic VBR BLINDS VBR Page 32 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 20.0 Wellhead Schematic Page 33 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 21.0 Days Vs Depth Page 34 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 22.0 Geo-Prog Reference Plan: Beluga 1 sandstone gas 1214 1,145.3 -1001 2,233,576.90 209,649.30 515 0.45 Beluga 9 sandstone depleted gas 1615 1,423.6 -1279 2,233,732.10 209,406.30 599 0.42 Beluga 10 sandstone depleted gas 1656 1,451.2 -1307 2,233,748.20 209,381.30 541 0.37 Beluga 13 sandstone depleted gas 1713 1,490.0 -1345 2,233,770.90 209,346.10 507 0.34 Beluga 16 sandstone depleted gas 1752 1,516.6 -1372 2,233,786.50 209,321.90 440 0.29 Beluga 20 sandstone gas 1838 1,575.1 -1431 2,233,820.70 209,269.00 709 0.45 Beluga 30 sandstone gas 1932 1,639.0 -1495 2,233,858.10 209,211.00 738 0.45 Beluga 41 sandstone depleted gas 2105 1,756.4 -1612 2,233,926.70 209,104.60 684 0.39 Beluga 44 sandstone gas 2179 1,806.6 -1662 2,233,956.10 209,059.10 813 0.45 Beluga 47 sandstone depleted gas 2268 1,867.0 -1723 2,233,991.50 209,004.30 820 0.44 Beluga 49 sandstone gas 2394 1,953.1 -1809 2,234,041.80 208,926.30 879 0.45 Beluga 50 sandstone depleted gas 2461 1,998.8 -1854 2,234,068.50 208,884.80 711 0.36 Beluga 51 sandstone depleted gas 2516 2,036.0 -1892 2,234,090.30 208,851.10 704 0.35 Beluga 52 sandstone depleted gas 2573 2,074.7 -1930 2,234,112.90 208,816.10 741 0.36 Beluga 53 sandstone depleted gas 2617 2,104.7 -1960 2,234,130.40 208,788.90 507 0.24 Beluga 55 sandstone depleted gas 2743 2,190.1 -2046 2,234,180.40 208,711.40 788 0.36 Beluga 56 sandstone depleted gas 2803 2,231.1 -2087 2,234,204.30 208,674.30 965 0.43 Beluga 58 sandstone depleted gas 2870 2,277.1 -2133 2,234,230.30 208,633.70 907 0.40 Beluga 58A sandstone depleted gas 2934 2,323.7 -2179 2,234,253.70 208,595.60 462 0.20 Beluga 59 sandstone depleted gas 3004 2,375.9 -2231 2,234,277.00 208,556.10 727 0.31 Beluga 60 sandstone depleted gas 3063 2,422.3 -2278 2,234,295.30 208,523.60 871 0.36 Beluga 73 sandstone depleted gas 3223 2,553.6 -2409 2,234,336.70 208,442.90 1056 0.41 Beluga 80 sandstone gas 3348 2,662.7 -2518 2,234,361.00 208,386.70 1198 0.45 Beluga 83 sandstone gas 3426 2,731.5 -2587 2,234,373.60 208,353.00 1229 0.45 Beluga 92-2 sandstone gas 3618 2,901.7 -2757 2,234,404.50 208,268.70 1306 0.45 Beluga 100 sandstone gas 3970 3,213.2 -3069 2,234,461.20 208,114.30 1446 0.45 Beluga 105 sandstone gas 3999 3,238.6 -3094 2,234,465.80 208,101.80 1457 0.45 Beluga 110 sandstone gas 4053 3,286.4 -3142 2,234,474.50 208,078.10 1479 0.45 Beluga 115 sandstone depleted gas 4107 3,334.4 -3190 2,234,483.30 208,054.30 1028 0.31 Beluga 120 sandstone depleted gas 4145 3,367.4 -3223 2,234,489.30 208,038.00 1009 0.30 Beluga 131 sandstone depleted gas 4232 3,444.2 -3300 2,234,503.20 208,000.00 1069 0.31 Beluga 132 sandstone gas 4253 3,463.5 -3319 2,234,506.70 207,990.40 1559 0.45 Beluga 134 sandstone depleted gas 4285 3,491.3 -3347 2,234,511.80 207,976.60 916 0.26 Beluga 135 sandstone depleted gas 4349 3,548.1 -3404 2,234,522.10 207,948.50 438 0.12 T-2 sandstone depleted gas 4616 3,784.5 -3640 2,234,565.10 207,831.40 847 0.22 T-5 sandstone depleted gas 4766 3,916.5 -3772 2,234,589.20 207,766.00 1727 0.44 T-6 sandstone depleted gas 4917 4,050.1 -3906 2,234,613.50 207,699.80 1143 0.28 T-7 sandstone depleted gas 5109 4,220.7 -4076 2,234,644.50 207,615.30 1450 0.34 T-8 sandstone depleted gas 5151 4,257.5 -4113 2,234,651.20 207,597.10 1869 0.44 T-9A sandstone depleted gas 5248 4,343.1 -4199 2,234,666.80 207,554.70 1901 0.44 T-10A sandstone depleted gas 5327 4,413.2 -4269 2,234,679.50 207,519.90 720 0.16 T-10B sandstone depleted gas 5366 4,447.5 -4303 2,234,685.80 207,503.00 2172 0.49 T-11 sandstone depleted gas 5423 4,497.9 -4353 2,234,694.90 207,478.00 2044 0.45 T-11A sandstone depleted gas 5473 4,542.1 -4398 2,234,703.00 207,456.10 2206 0.49 T-12 sandstone depleted gas 5587 4,642.9 -4498 2,234,721.30 207,406.20 2114 0.46 T-17 sandstone depleted gas 6181 5,167.9 -5023 2,234,816.80 207,146.10 2173 0.42 T-83 sandstone depleted gas 7974 6,753.9 -6609 2,235,105.40 206,360.50 696 0.10 T-90 sandstone depleted gas 8154 6,912.8 -6768 2,235,134.30 206,281.80 564 0.08 T-110 sandstone depleted gas 8467 7,190.0 -7046 2,235,184.70 206,144.50 1606 0.22 T-140 sandstone depleted gas 8809 7,492.5 -7348 2,235,239.80 205,994.70 3337 0.45 T-142A sandstone depleted gas 8956 7,622.2 -7478 2,235,263.40 205,930.40 3337 0.44 T-150 sandstone gas 9346 7,967.6 -7823 2,235,326.20 205,759.40 3585 0.45 T-151 sandstone gas 9504 8,107.2 -7963 2,235,351.60 205,690.20 3648 0.45 T-155 sandstone gas 9772 8,344.1 -8200 2,235,394.69 205,572.86 3755 0.45 Kalotsa 7 wp08ANTICIPATED FORMATION TOPS & GEOHAZARDS TOP NAME LITHOLOGY EXPECTED FLUID MD (FT) TVD (FT) TVDSS (FT)NORTHING EASTING Est. Pressure Gradient Page 35 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 23.0 Anticipated Drilling Hazards 9-7/8” Hole Section: Lost Circulation: Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Maintain YP between 25 – 45 to optimize hole cleaning and control ECD. Wellbore stability: Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity. Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP of ~50 - ~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200’ of drilling to reduce the likelihood of washing out the conductor shoe. To help insure good cement to surface after running the casing, condition the mud to a YP of 25 – 30 prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be achieved. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. Page 36 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 6-3/4” Hole Section: Lost Circulation: Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP between 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. H2S: H2S is not present in this hole section. No abnormal temperatures are present in this hole section. Page 37 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 24.0 Hilcorp Rig 169 Layout Page 38 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 25.0 FIT/LOT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. NOTE: Forward LOG data to AOGCC for review. Page 39 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 26.0 Choke Manifold Schematic Page 40 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 27.0 Casing Design Information Page 41 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 28.0 6-3/4” Hole Section MASP Page 42 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 29.0 Spider Plot (NAD 27) (Governmental Sections) Page 43 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 30.0 Surface Plat (NAD 27) Page 44 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 Page 45 Version 0 August, 2020 Kalotsa #7 Drilling Procedure Rev 0 31.0 Directional Plan (wp08a) !"# 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500True Vertical Depth (1000 usft/in)-500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 Vertical Section at 292.36° (1000 usft/in) Kalotsa #7 wp08a Beluga 135 7-5/8" x 9-7/8" 4-1/2" x 6-3/4" 5 0 0 1 0 0 0 15002000250030003 5 0 0 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 5 0 0 7 0 0 0 7 5 0 0 8 0 0 0 8 5 0 0 9 0 0 0 9 5 0 0 9 7 8 1Kalotsa 7 wp08a Start Dir 4º/100' : 300' MD, 300'TVD Start Dir 5º/100' : 500' MD, 499.35'TVD End Dir : 1344.53' MD, 1240.1' TVD Start Dir 4º/100' : 2845.23' MD, 2266.29'TVD Start Dir 3º/100' : 3345.84' MD, 2662.5'TVD End Dir : 3367.36' MD, 2681.51' TVD Total Depth : 9780.59' MD, 8344.5' TVD Beluga 1 Beluga 9 Beluga 20 Beluga 41 Beluga 44 Beluga 47 Beluga 49 Beluga 50 Beluga 80 Beluga 115 Beluga 132 Beluga 134 T-140 T-142A Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: Plan: Kalotsa 7 126.50 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2233474.160 209937.090 60° 6' 14.885 N 151° 35' 22.669 W SURVEY PROGRAM Date: 2020-08-13T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.00 1550.00 Kalotsa 7 wp08a (Kalotsa 7)3_MWD+IFR1+MS+Sag 1550.00 9780.59 Kalotsa 7 wp08a (Kalotsa 7)3_MWD+IFR1+MS+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 1145.50 1001.00 1213.76 Beluga 1 1423.50 1279.00 1612.74 Beluga 9 1575.50 1431.00 1835.02 Beluga 20 1756.50 1612.00 2099.71 Beluga 41 1806.50 1662.00 2172.83 Beluga 44 1867.50 1723.00 2262.04 Beluga 47 1953.50 1809.00 2387.80 Beluga 49 1998.50 1854.00 2453.61 Beluga 50 2662.50 2518.00 3345.84 Beluga 80 3334.50 3190.00 4106.86 Beluga 115 3463.50 3319.00 4252.95 Beluga 132 3491.50 3347.00 4284.66 Beluga 134 7492.50 7348.00 8815.72 T-140 7622.50 7478.00 8962.94 T-142A REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: Kalotsa 7, True North Vertical (TVD) Reference:RKB Plan @ 144.50usft (HEC 169) Measured Depth Reference:RKB Plan @ 144.50usft (HEC 169) Calculation Method:Minimum Curvature Project:Ninilchik Unit Site:Kalotsa Well:Plan: Kalotsa 7 Wellbore:Kalotsa 7 Design:Kalotsa 7 wp08a Ninilchik Unit Kalotsa Plan: Kalotsa 7 Kalotsa 7 Kalotsa 7 wp08a 5.800 CASING DETAILS TVD TVDSS MD Size Name 1380.60 1236.10 1550.00 7-5/8 7-5/8" x 9-7/8" 8344.50 8200.00 9780.59 4-1/2 4-1/2" x 6-3/4" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 18.00 0.00 0.00 18.00 0.00 0.00 0.00 0.00 0.00 2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 4º/100' : 300' MD, 300'TVD 3 500.00 8.00 250.00 499.35 -4.77 -13.10 4.00 250.00 10.30 Start Dir 5º/100' : 500' MD, 499.35'TVD 4 1344.53 46.86 301.42 1240.10 142.46 -346.50 5.00 58.07 374.64 End Dir : 1344.53' MD, 1240.1' TVD 5 2845.23 46.86 301.42 2266.29 713.22 -1280.97 0.00 0.00 1455.97 Start Dir 4º/100' : 2845.23' MD, 2266.29'TVD 6 3345.84 28.00 290.00 2662.50 850.00 -1550.00 4.00 -164.25 1756.81 Start Dir 3º/100' : 3345.84' MD, 2662.5'TVD 7 3367.36 27.99 288.62 2681.51 853.34 -1559.53 3.00 -91.36 1766.90 End Dir : 3367.36' MD, 2681.51' TVD 8 8902.92 27.99 288.62 7569.50 1683.07 -4021.54 0.00 0.00 4359.45 Kalotsa #7 wp08a Beluga 135 9 9780.59 27.99 288.62 8344.50 1814.62 -4411.90 0.00 0.00 4770.50 Total Depth : 9780.59' MD, 8344.5' TVD -33303336671000133316672000233326673000South(-)/North(+) (500 usft/in)-4333 -4000 -3667 -3333 -3000 -2667 -2333 -2000 -1667 -1333 -1000 -667 -333 0West(-)/East(+) (500 usft/in)Kalotsa #7 wp08a Beluga 1357-5/8" x 9-7/8"4-1/2" x 6-3/4"2505 0 0 7501000125015001750200022502500275030003250350037504000425045004750500052505500575060006250650067507000725075007750800082508345Kalotsa 7 wp08aStart Dir 4º/100' : 300' MD, 300'TVDStart Dir 5º/100' : 500' MD, 499.35'TVDEnd Dir : 1344.53' MD, 1240.1' TVDStart Dir 4º/100' : 2845.23' MD, 2266.29'TVDStart Dir 3º/100' : 3345.84' MD, 2662.5'TVDEnd Dir : 3367.36' MD, 2681.51' TVDTotal Depth : 9780.59' MD, 8344.5' TVDProject: Ninilchik UnitSite: KalotsaWell: Plan: Kalotsa 7Wellbore: Kalotsa 7Plan: Kalotsa 7 wp08aWELL DETAILS: Plan: Kalotsa 7126.50+N/-S +E/-WNorthingEastingLatittudeLongitude0.000.002233474.160209937.09060° 6' 14.885 N 151° 35' 22.669 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: Kalotsa 7, True NorthVertical (TVD) Reference:RKB Plan @ 144.50usft (HEC 169)Measured Depth Reference:RKB Plan @ 144.50usft (HEC 169)Calculation Method:Minimum CurvatureCASING DETAILSTVD TVDSS MD Size Name1380.60 1236.10 1550.00 7-5/8 7-5/8" x 9-7/8"8344.50 8200.00 9780.59 4-1/2 4-1/2" x 6-3/4" -3670367733110014671833220025672933South(-)/North(+) (550 usft/in)-4400 -4033 -3667 -3300 -2933 -2567 -2200 -1833 -1467 -1100 -733 -367 0 367West(-)/East(+) (550 usft/in)Kalotsa #7 wp08a Beluga 1351750200022502500275030003250350037503805Paxton #42505007501000125015001750200022502500275030003250350037503914Kalotsa 5 Wp102505007501000125015001750200022502500275030003250350037504000425045004750500052505500Kalotsa 3250500750100012501500175020002250250027503000325035003644Kalotsa 62505007501000125015001750200022502500275030003 2 5 0 3 5 0 0 3 7 5 0 4 0 0 0 4 2 5 0 4 5 0 0 4 7 5 0 5 0 0 0 52 5 0 5 5 0 0 5 7 5 0 6 0 0 0 6 2 5 0 6 5 0 0 6 7 5 0 7 0 0 0 7 2 5 0 7 5 0 0 77507958Kalotsa 42505007501000125015001750200022502500275030003250350037504000425045004750500052505500575060006250650067507 0 0 07250750077507857 Kalotsa 2275030003250350037503845Paxton #10 Wp07a25 00 2 7 5 0 3 0 0 0 3 2 5 0 3 5 0 0 3 7 5 0 4 0 0 0 4 2 50 4500 4 7 5 0 5 0 0 0 5 2 5 0 5 5 0 0 5 7 5 0 60006250650067507000725075007750800082508355Susan Dionne #425050075010001250150017502000225025002750300032503500375040004250450047505000525055005750600062506500675070007250750077507773Kalotsa 12505007501000125015001517Kalotsa 57-5/8" x 9-7/8"4-1/2" x 6-3/4"2505 0 0 750100012501500175020002250250027503000350037504000425045004750500052505500575060006250650067507000725075007750800082508345Kalotsa 7 wp08aProject: Ninilchik UnitSite: KalotsaWell: Plan: Kalotsa 7Wellbore: Kalotsa 7Plan: Kalotsa 7 wp08aWELL DETAILS: Plan: Kalotsa 7126.50+N/-S +E/-WNorthingEastingLatittudeLongitude0.000.002233474.160 209937.09060° 6' 14.885 N 151° 35' 22.669 W $ % & ' ()* ' + , , +-% + ." ! 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"0,+&*/ .&%."+0.&- ( % !"("#$/(/(&':; -&, %.; &, %.4 , %.:; -& %= - -1= %%-1;*4 21 % '!1"$18 %1; -&1 )& * +&,'-%.%&'!( !"("("#$; -&, %. 9-; /' 5 4.( 5 4.( 5 4 "0.*&%/ +0/& +"%&,/ "0)&"" .&%+"+0/& ( 5 4.( 5 4.( 5 4 "0."&* +0,.&" +"+& ""0,&/, .&//,+0,.&"- ( =, %.>, %. +? +>"+& "0%%& ' ,+ *672!"!7 ! 1"0%%& )0,+&%) ' ,+ *672!"!7 ! 1 8 5 9:(& 5 ;&- 5 5 $ &- < $#= $( >& 1 ;; & 5 517858-5 9 5 8& 0.001.503.004.50Separation Factor0 550 1100 1650 2200 2750 3300 3850 4400 4950 5500 6050 6600 7150 7700 8250 8800 9350 9900 10450Measured DepthKalotsa 4Kalotsa 2Susan Dionne #4No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: Kalotsa 7 NAD 1927 (NADCON CONUS)Alaska Zone 04126.50+N/-S +E/-W Northing EastingLatittudeLongitude0.000.002233474.160 209937.090 60° 6' 14.885 N 151° 35' 22.669 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: Kalotsa 7, True NorthVertical (TVD) Reference:RKB Plan @ 144.50usft (HEC 169)Measured Depth Reference:RKB Plan @ 144.50usft (HEC 169)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-08-13T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool18.00 1550.00 Kalotsa 7 wp08a (Kalotsa 7) 3_MWD+IFR1+MS+Sag1550.00 9780.59 Kalotsa 7 wp08a (Kalotsa 7) 3_MWD+IFR1+MS+Sag0.0030.0060.0090.00120.00150.00Centre to Centre Separation (50.00 usft/in)0 550 1100 1650 2200 2750 3300 3850 4400 4950 5500 6050 6600 7150 7700 8250 8800 9350 9900 10450Measured DepthKalotsa 5 Wp10Kalotsa 3Kalotsa 6Kalotsa 4Kalotsa 2Kalotsa 1Kalotsa 5GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference18.00 To 9780.59Project: Ninilchik UnitSite: KalotsaWell: Plan: Kalotsa 7Wellbore: Kalotsa 7Plan: Kalotsa 7 wp08aLadder / S.F. PlotsCASING DETAILSTVD TVDSS MD Size Name1380.60 1236.10 1550.00 7-5/8 7-5/8" x 9-7/8"8344.50 8200.00 9780.59 4-1/2 4-1/2" x 6-3/4" Revised 2/2015 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: ____________________________ POOL: ______________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit No. _____________, API No. 50-_______________________. Production should continue to be reported as a function of the original API number stated above. Pilot Hole In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name (_______________________PH) and API number (50-_____________________) from records, data and logs acquired for well (name on permit). Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. (_____________________________) as Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for well ( ) until after ( ) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (________________________) must contact the AOGCC to obtain advance approval of such water well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (_______________________________) in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. 220-067 Ninilchik X X X Beluga/Tyonek Gas Kalotsa 7 WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:KALOTSA 7Initial Class/TypeDEV / PENDGeoArea820Unit51432On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2200670NINILCHIK, BELUGA-TYONEK GAS - 562503NA1 Permit fee attachedYes2 Lease number appropriateYes3 Unique well name and numberYes4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For sNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 16" conductor set at 120 ft18 Conductor string providedYes 7 5/8" surf casing set at 1550 ft and fully cemented19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes 4.5" will be cemented to 7 5/8" shoe… swell packer at 1300 ft21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes BTC calculations are provided.23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitNA grassroots well25 If a re-drill, has a 10-403 for abandonment been approvedYes No issues.26 Adequate wellbore separation proposedNA Diverter waived… several wells pad drilled without shallow gas issues.27 If diverter required, does it meet regulationsYes Max form pressure = 3755 psi (8.7 ppg EMW) will drill with 9-10 ppg mud28 Drilling fluid program schematic & equip list adequateYes Rig 169 has 11" BOPE. 5000 PSI WP29 BOPEs, do they meet regulationYes MASP = 2920 PSI will test BOPE tot 3500 psi30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes sundry requried to perforate well (cement packer wellbore)32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S is not anticipated based on nearby wells.35 Permit can be issued w/o hydrogen sulfide measuresYes36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprDLBDate10/1/2020ApprGLSDate10/15/2020ApprDLBDate10/1/2020AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateCBL and MIT-IA required before perfing well. The TD of well will be determined after LOT of surface casing shoe is completed. Will discuss with AOGCC staff for final TD of well. GlsDaniel T. Seamount, Jr.Digitally signed by Daniel T. Seamount, Jr. Date: 2020.10.20 09:01:39 -08'00'Jeremy M. PriceDigitally signed by Jeremy M. Price Date: 2020.10.20 10:23:50 -08'00'