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Home My WebLink About220-0641. 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 5,732 feet N/A feet true vertical 3,879 feet N/A feet Effective Depth measured 5,632 feet 590 & 1,283 feet true vertical 3,801 feet 590 & 1,217 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)3/8" Cap String 3,900' MD 2,613' TVD 4-1/2" 12.6# / L-80 636 MD 633 TVD Packers and SSSV (type, measured and true vertical depth) See schematic 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Contact Phone: 7,500psi 2,980psi 6,890psi 8,430psi 1,522' 1,380' Burst Collapse 1,410psi 4,790psi Production Liner 5,082' Casing Structural 3,865'5,718' 120'Conductor Surface Intermediate 16" 7-5/8" 120' 1,522' measured TVD 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 220-064 50-133-20691-00-00 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: Ninilchik Field / Beluga-Tyonek Gas Pool Ninilchik Unit Paxton 10 Plugs Junk measured Length measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 75 Size 120' 0 1082195 0 880 108 Scott Warner, Operations Engineer 325-324 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 827 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 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 2:21 pm, Jul 25, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.07.25 13:39:45 - 08'00' Noel Nocas (4361) BJM 9/25/25 Page 1/1 Well Name: NINU Paxton 10 Report Printed: 6/18/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Wellbore API/UWI:50-133-20691-00-00 Field Name:Ninilchik State/Province:ALASKA Permit to Drill (PTD) #:220-064 Sundry #:325-324 Rig Name/No: Jobs Actual Start Date:5/6/2025 End Date: Report Number 1 Report Start Date 6/3/2025 Report End Date 6/3/2025 Last 24hr Summary PTW, JSA. MIRU Capillary tubing unit. Load 3/8" wooden spool into craddle. Stab tubing into injector. Strip down onto packofff/wellhead. Open static packoffs. PU on cap sring . Pulling free at 1400 lbs. Spool OOH with completion. Recovered foot valve and 4600' of 3/8" SS cap tubing. RDMO Report Number 2 Report Start Date 6/9/2025 Report End Date 6/9/2025 Last 24hr Summary PTW/PJSM. Well flowing 860 mcfd @ 80 psi FTP. MIRU YJ E-line. Shut in well. PT lubricator to 250 psi low - 2000 psi high, good test. RIH w/ 6'x6'x6'x6' 2 3/4" 6SPF 60deg guns on switch and perf BEL_99B (4,881 4,887), BEL_99A (4,863 4,869), and BEL_98 (4,811 4,817). Bottom gun was a misfire. RIH w/ 6'x6'x6'x6' 2 3/4" 6SPF 60deg guns on switch and perf BEL_97 Upper (4,758 4,764), bottom 3 guns misfired. Troubleshoot wiring and connections. RIH w/ 6'x6'x6'x6' 2 3/4" 6SPF 60deg guns on switch and perf BEL_97 Lower (4,775 4,781), BEL_95 (4,670 4,676), BEL_95 (4,659 4,665), and BEL_94 (4,643 4,649). RIH w/ 6'x6'x6'x6' 2 3/4" 6SPF 60deg guns on switch and perf BEL_94 (4,630 4,636), BEL_94 (4,614 4,620), BEL_93 (4,596 4,602), and BEL_93 (4,584 4,590). Secure well and hand over to production to flow overnight. Report Number 3 Report Start Date 6/10/2025 Report End Date 6/10/2025 Last 24hr Summary PTW/PJSM. Well flowing 700 mcfd @ 80 psi FTP. RU YJ E-line. Pinch back well to ~350 psi FTP. RIH w/ 6'x6'x6'x6' 2 3/4" 6SPF 60deg guns on switch and perf BEL_92 (4,550 4,556), BEL_92 (4,513 4,519), BEL_92 (4,487 4,493), and BEL_92 (4,473 4,479). RIH w/ 6'x6' 2 3/4" 6SPF 60deg guns on switch and perf BEL_91 (4,390 4,396) and BEL_90 (4,377 4,383). RIH w/ 17' x 2 3/4" 6SPF 60deg guns and perf BEL_90 (4,354 4,371). RIH w/ 6'x6'x6'x6' 2 3/4" 6SPF 60deg guns on switch and perf BEL_90 (4,335 4,341), BEL_90 (4,322 4,328), BEL_90 (4,286 4,292), and BEL_88 (4,252 4,258). RIH w/ 6'x20' 2 3/4" 6SPF 60deg guns on switch and perf BEL_83 (4,235 4,241) and BEL_82 (4,171 4,191). All guns shot with well flowing. Secure well and hand over to production to flow overnight. Report Number 4 Report Start Date 6/11/2025 Report End Date 6/11/2025 Last 24hr Summary PTW/PJSM. Well flowing 2 mmcfd @ 100 psi FTP. RU YJ E-line. Pinch back well to ~350 psi FTP. RIH w/ 6'x6' 2 3/4" 6SPF 60deg guns on switch and perf BEL_82 (4,191 4,197) and BEL_82 (4,165 4,171). RIH w/ 20' x 2 3/4" 6SPF 60deg guns and perf BEL_80 (4,102 4,122). RIH w/ 15' x 2 3/4" 6SPF 60deg guns, sat down @ 4,118', and perf BEL_80 (4,086 4,101). RIH w/ 10'x10' 2 3/4" 6SPF 60deg guns on switch and perf BEL_78 (4,063 4,073) and BEL_75 (4,037 4,047). RIH w/ 6'x18' 2 3/4" 6SPF 60deg guns on switch and perf BEL_75 (4,016 4,022) and BEL_75 (3,994 4,012). All guns shot with well flowing. Secure well and hand over to production to flow overnight. Report Number 5 Report Start Date 6/12/2025 Report End Date 6/12/2025 Last 24hr Summary PTW/PJSM. Well flowing 1.8 mmcfd @ 350 psi FTP. RU YJ E-line. RIH w/ 10'x10' 2 3/4" 6SPF 60deg guns on switch and perf BEL_74 (3,931 3,941) and BEL_74 (3,946 3,956). Secure well, RDMO YJ E-line and hand over to production. Report Number 6 Report Start Date 6/17/2025 Report End Date 6/18/2025 Last 24hr Summary PTW, JSA . MIRU cap string truck. Load 3/8" spool. Install pack off assembly and foot valve with opening preesure of 2000 psi. Stab on well. PT pack off assembly 250/3500 psi. RIh with 3/8" cap string. RIH wt 400 lbs to 3900' pIck up clean at 1400 lbs. PU to 3380' and lock down cap string. Close in static lock downs. PRessure up dynamic packoff to 3000 psi and isolate. Install 3/8" tubing hanger. Strip off injector head and set on back deck. Set cap spool next to soap skid. cap string install complete. Depart with truck. PTW/PJSM. Well flowing 1.8 mmcfd @ 350 psi FTP. RU YJ E-line. RIH w/ 10'x10' 2 3/4" 6SPF 60deg guns on switch and perf BEL_74 (3,931 3,941) and PTW/PJSM. Well flowing 1.8 mmcfd @ 350 psi FTP. RU YJ E-line. RIH w/ 10'x10' 2 3/4" 6SPF 60deg guns on switch and perf BEL_7 BEL_74 (3,946 3,956). Secure well, RDMO YJ E-line and hand over to production. PTW/PJSM. Well flowing 2 mmcfd @ 100 psi FTP. RU YJ E-line. Pinch back well to ~350 psi FTP. RIH w/ 6'x6' 2 3/4" 6SPF 60deg guns on switch and perf BEL_82 (4,191 4,197) and BEL_82 (4,165 4,171). RIH w/ 20' x 2 3/4" 6SPF 60deg guns and perf BEL_80 (4,102 4,122). RIH w/ 15' x 2 3/4" 6SPF 60deg BEL_82 (4,191 4,197) and BEL_82 (4,165 4,171). RIH w/ 20' x 2 3/4" 6SPF 60deg guns and perf BEL_80 (4,102 4,122). RIH w/ 15' x 2 3/4" 6SPF 60deg guns, sat down @ 4,118', and perf BEL_80 (4,086 4,101). RIH w/ 10'x10' 2 3/4" 6SPF 60deg guns on switch and perf BEL_78 (4,063 4,073) and BEL_75 guns, sat down @ 4,118', and perf BEL_80 (4,086 4,101). RIH w/ 10'x10' 2 3/4" 6SPF 60deg guns on switch and perf BEL_78 (4 (4,037 4,047). RIH w/ 6'x18' 2 3/4" 6SPF 60deg guns on switch and perf BEL_75 (4,016 4,022) and BEL_75 (3,994 4,012). All guns shot with well flowing. PTW/PJSM. Well flowing 700 mcfd @ 80 psi FTP. RU YJ E-line. Pinch back well to ~350 psi FTP. RIH w/ 6'x6'x6'x6' 2 3/4" 6SPF 60deg guns on switch and perf BEL_92 (4,550 4,556), BEL_92 (4,513 4,519), BEL_92 (4,487 4,493), and BEL_92 (4,473 4,479). RIH w/ 6'x6' 2 3/4" 6SPF 60deg guns on switch and BEL_92 (4,550 4,556), BEL_92 (4,513 4,519), BEL_92 (4,487 4,493), and BEL_92 (4,473 4,479). RIH w/ 6'x6' 2 3/4" 6SPF 60deg guns on switch and perf BEL_91 (4,390 4,396) and BEL_90 (4,377 4,383). RIH w/ 17' x 2 3/4" 6SPF 60deg guns and perf BEL_90 (4,354 4,371). RIH w/ 6'x6'x6'x6' 2 3/4" perf BEL_91 (4,390 4,396) and BEL_90 (4,377 4,383). RIH w/ 17' x 2 3/4" 6SPF 60deg guns and perf BEL_90 (4,354 4,371). RIH w/ 6'x6'x6'x6' 2 3/4" 6SPF 60deg guns on switch and perf BEL_90 (4,335 4,341), BEL_90 (4,322 4,328), BEL_90 (4,286 4,292), and BEL_88 (4,252 4,258). RIH w/ 6'x20' 2 6SPF 60deg guns on switch and perf BEL_90 (4,335 4,341), BEL_90 (4,322 4,328), BEL_90 (4,286 4,292), and BEL_88 (4, 3/4" 6SPF 60deg guns on switch and perf BEL_83 (4,235 4,241) and BEL_82 (4,171 4,191). All guns shot with well flowing PTW/PJSM. Well flowing 860 mcfd @ 80 psi FTP. MIRU YJ E-line. Shut in well. PT lubricator to 250 psi low - 2000 psi high, g 6SPF 60deg guns on switch and perf BEL_99B (4,881 4,887), BEL_99A (4,863 4,869), and BEL_98 (4,811 4,817). Bottom gun was a misfire. RIH w/ 6SPF 60deg guns on switch and perf BEL_99B (4,881 4,887), BEL_99A (4,863 4,869), and BEL_98 (4,811 4,817). Bottom g 6'x6'x6'x6' 2 3/4" 6SPF 60deg guns on switch and perf BEL_97 Upper (4,758 4,764), bottom 3 guns misfired. Troubleshoot wiring and connections. RIH w/ 6'x6'x6'x6' 2 3/4" 6SPF 60deg guns on switch and perf BEL_97 Upper (4,758 4,764), bottom 3 guns misfired. Troubleshoot wiring and connections. RIH w/ 6'x6'x6'x6' 2 3/4" 6SPF 60deg guns on switch and perf BEL_97 Lower (4,775 4,781), BEL_95 (4,670 4,676), BEL_95 (4,659 4,665), and BEL_94 (4,643 6'x6'x6'x6' 2 3/4" 6SPF 60deg guns on switch and perf BEL_97 Lower (4,775 4,781), BEL_95 (4,670 4,676), BEL_95 (4,659 4,665), and BEL_94 (4,643 4,649). RIH w/ 6'x6'x6'x6' 2 3/4" 6SPF 60deg guns on switch and perf BEL_94 (4,630 4,636), BEL_94 (4,614 4,620), BEL_93 (4,596 4,602), and BEL_93 4,649). RIH w/ 6'x6'x6'x6' 2 3/4" 6SPF 60deg guns on switch and perf BEL_94 (4,630 4,636), BEL_94 (4,614 4,620), BEL_ (4,584 4,590). Secure well and hand over to production to flow overnight. PTW, JSA . MIRU cap string truck. Load 3/8" spool. Install pack off assembly and foot valve with opening preesure of 2000 assembly 250/3500 psi. RIh with 3/8" cap string. RIH wt 400 lbs to 3900' pIck up clean at 1400 lbs. PU to 3380' and loc Updated by DMA 06-18-25 SCHEMATIC Ninilchik Unit Paxton #10 PTD: 220-064 API: 50-133-20691-00-00 PBTD = 5,632 / TVD = 3,801 TD = 5,732 / TVD = 3,879 RKB to GL = 17.6 PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD FT Size Date Status BEL 74 3,931' 3,944' 2,630' 2,635' 13 2-3/4 6/11/25 Open BEL 74 3,946' 3,956' 2,636' 2,641' 10' 2-3/4 6/11/25 Open BEL 74 3,960' 3,966' 2,643' 2,646' 6' 2-3/4 6/11/25 Open BEL 74 3,970' 3,976' 2,648' 2,651' 6' 2-3/4 6/11/25 Open BEL 75 3,994' 4,012' 2,660' 2,668' 18' 2-3/4 6/11/25 Open BEL 75 4,016' 4,022' 2,670' 2,673' 6' 2-3/4 6/11/25 Open BEL 75 4,037' 4,047' 2,680' 2,685' 10' 2-3/4 6/11/25 Open BEL 78 4,063' 4,073' 2,692' 2,697' 10' 2-3/4 6/11/25 Open BEL 80 4,086' 4,101' 2,704' 2,711' 15' 2-3/4 6/11/25 Open BEL 80 4,102' 4,122' 2,711' 2,721' 20' 2-3/4 6/11/25 Open BEL 82 4,171' 4,191' 2,746' 2,757' 20' 2-3/4 6/11/25 Open BEL 82 4,191' 4,197' 2,757' 2,760' 6' 2-3/4 6/11/25 Open BEL 83 4,235' 4,241' 2,781' 2,785' 6' 2-3/4 6/10/25 Open BEL 88 4,252' 4,258' 2,791' 2,794' 6' 2-3/4 6/10/25 Open BEL 90 4,286' 4,292' 2,811' 2,814' 6' 2-3/4 6/10/2025 Open BEL 90 4,322' 4,328' 2,832' 2,836' 6' 2-3/4 6/10/2025 Open BEL 90 4,335' 4,341' 2,841' 2,844' 6' 2-3/4 6/10/2025 Open BEL 90 4,354' 4,371' 2,852' 2,863' 17' 2-3/4 6/10/2025 Open BEL 90 4,377' 4,383' 2,867' 2,870' 6' 2-3/4 6/10/2025 Open BEL 91 4,390' 4,396' 2,875' 2,879' 6' 2-3/4 6/10/2025 Open BEL 92 4,473' 4,479' 2,930' 2,934' 6' 2-3/4 6/10/2025 Open BEL 92 4,487' 4,493' 2,939' 2,943' 6' 2-3/4 6/10/2025 Open BEL92 4,513' 4,519' 2,957' 2,961' 6' 2-3/4 6/10/2025 Open BEL 92 4,550' 4,556' 2,983' 2,987' 6' 2-3/4 6/9/2025 Open PERFORATION DETAIL - Continued on following page OPEN HOLE / CEMENT DETAIL 7-5/8" 102 BBLs of cement in 9-7/8 hole 27 BBLs Cement to Surface 4-1/2 140 BBLs of cement in 6-3/4 hole zero losses during cement job. 13 bbls spacer back to surface (of 35 pumped). 10/22/20 CBL showed ToC at 1440 MD after 4 days of cement cure. 4/16/21 CBL showed ToC at 780 MD. CASING/TUBING DETAIL Size Type Wt Grade Conn. ID Top Btm 16 Conductor Driven to Set Depth 84 X-56 Weld 15.01 Surf 120' 7-5/8" Surf Csg 29.7 L-80 DWC/C 6.875 Surf 1,522 4-1/2" Prod Csg 12.6 L-80 DWC/C HT 3.958 636 5,718 4-1/2" Tubing 12.6 L-80 IBT 3.958 Surf 636 3/8 Capillary String Surf 3,900 7 16 7-5/8 ToC at 780MD (4/16/21 CBL) 4-1/2 JEWELRY DETAIL No. Depth MD Depth TVD ID Item 1 144 144 3.813 Surface controlled TRSSSV: NE-Slim (Halliburton): Permanently locked open 11/18/21 2 590 587 4.000 D&L Oil Tools 7-5/8 x 4-1/2 Hydraulic permanent packer (TriPoint) 3 599 596 3.813 X-nipple 4 636 633 3.95 Bowen (Baker) Casing Patch (Sealing Overshot with grapple) 5 997 1010 975 997 3.25 X-Span permanent patch (set 5-12-21) 6 1000 978 Incomplete jet cut (4/16/21) 7 1,283 1,217 3.958 Swell Packer 1 2/3 4 Leaking Shoe as of 4/19/21 RTTS MIT fail 5/6 BEL 135-136 BEL 131-134 BEL 74-78 BEL 80-88 BEL 90-99 BEL 120 BEL 100-115 Updated by DMA 06-18-25 SCHEMATIC Ninilchik Unit Paxton #10 PTD: 220-064 API: 50-133-20691-00-00 PERFORATION DETAIL Continued from previous page Sand TOP MD BTM MD TOP TVD BTM TVD FT Size Date Status BEL 93 4,584' 4,590' 3,007' 3,011' 6' 2-3/4 6/9/2025 Open BEL 93 4,596' 4,602' 3,015' 3,020' 6' 2-3/4 6/9/2025 Open BEL 94 4,614' 4,620' 3,028' 3,032' 6' 2-3/4 6/9/2025 Open BEL 94 4,630' 4,636' 3,040' 3,044' 6' 2-3/4 6/9/2025 Open BEL 94 4,643' 4,649' 3,049' 3,054' 6' 2-3/4 6/9/2025 Open BEL 95 4,659' 4,665' 3,061' 3,066' 6' 2-3/4 6/9/2025 Open BEL 95 4,670' 4,676' 3,069' 3,074' 6' 2-3/4 6/9/2025 Open BEL 95 4,684 4,704 3,079 3,095 20 2-7/8 8/29/2022 Open BEL 97 4,758' 4,764' 3,136' 3,141' 6' 2-3/4 6/9/2025 Open BEL 97 4,768 4,771 3,144 3,146 3 2-7/8 8/29/2022 Open BEL 97 4,775' 4,781' 3,149' 3,154' 6' 2-3/4 6/9/2025 Open BEL 98 4,795 4,805 3,165 3,172 10 2-7/8 8/29/2022 Open BEL 98 4,811' 4,817' 3,177' 3,182' 6' 2-3/4 6/9/2025 Open BEL 99 4,830 4,837 3,191 3,197 7 2-7/8 8/29/2022 Open BEL 99A 4,863' 4,869' 3,217' 3,222' 6' 2-3/4 6/9/2025 Open BEL 99B 4,881' 4,887' 3,231' 3,236' 6' 2-3/4 6/9/2025 Open BEL 100 4,901 4,909 3,247 3,253 8 2-7/8 8/26/2022 Open BEL 105 4,936 4,944 3,274 3,280 8 2-7/8 8/26/2022 Open BEL 110u 5,005 5,009 3,328 3,331 4 2-7/8 8/26/2022 Open BEL 115u 5,051 5,056 3,364 3,367 5 2-7/8 8/26/2022 Open BEL 115L 5,080 5,086 3,385 3,390 6 2-7/8 8/26/2022 Open Bel 120u 5,147 5,161 3,436 3,447 14 2-7/8 5/13/2022 Open BEL 120L 5,180 5,184 3,461 3,464 4 2-7/8 8/26/2022 Open BEL 131 5,194 5,198 3,472 3,475 4 2-7/8 8/26/2022 Open BEL 132 5,214 5,217 3,487 3,489 3 2-7/8 8/26/2022 Open BEL 133 5,241 5,244 3,508 3,510 3 2-7/8 8/26/2022 Open Bel 134u 5,260 5,265 3,522 3,526 5 2-7/8 5/13/2022 Open Bel 134L 5,300 5,320 3,552 3,567 20 2-7/8 5/13/2022 Open Bel 135a 5,353 5,361 3,592 3,598 9 2-7/8 5/13/2022 Open Bel 135b 5,398 5,411 3,626 3,635 13 2-7/8 5/13/2022 Open Bel 135c 5,418 5,424 3,641 3,645 6 2-7/8 5/13/2022 Open BEL 135 5,429 5,433 3,649 3,652 4 2-7/8 8/26/2022 Open Bel 135e 5,443 5,459 3,660 3,672 16 2-7/8 5/13/2022 Open Bel 135 5,460 5,480 3,673 3,688 20 2-7/8 6 SPF 11/13/2020 Open Bel 135 5,480 5,500 3,688 3,703 20 2-7/8 6 SPF 11/13/2020 Open Bel 136 5,514 5,520 3,714 3,718 6 2-7/8 6 SPF 11/13/2020 Open Bel 136L 5,523 5,543 3,721 3,737 21 2-7/8 5/13/2022 Open 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: N2 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 5,732'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 D&L Hyd Packer, Swell Packer & FXE WLSSSV 590 (MD) 587 (TVD) / 1,283 (MD) 1,217 (TVD) & 144 (MD) 144 (TVD) 3,879'5,632'3,801' Ninilchik Beluga-Tyonek Gas 16" 7-5/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Ninilchik Paxton 10CO 701C Same 3,865'4-1/2" ~1,265psi 5,082' N/A Length June 5, 2025 4-1/2" 5,718' Perforation Depth MD (ft): See Attached Schematic 2,980psi 6,890psi 120'120' 1,522' Size 120' 1,522' MD Hilcorp Alaska, LLC Proposed Pools: 12.6# / L-80 TVD Burst 636' 8,430psi 1,380' Tubing MD (ft): 4,600'Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0384372 / Fee-Private 220-064 50-133-20691-00-00 Tubing Size: Cap String 3/8" PRESENT WELL CONDITION SUMMARY Scott Warner, Operations Engineer AOGCC USE ONLY Tubing Grade: scott.warner@hilcorp.com 907-564-4506 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: m n P s 66 t 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 9:34 am, May 23, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.05.22 17:57:17 - 08'00' Noel Nocas (4361) 325-324 10-404 A.Dewhurst 30MAY25 If existing patch at 1000' is pulled to install another patch or plug, the patch at 1000' must be re-installed and pressure tested MITIA to 1500 psi. BJM 7/2/25 If plug is installed, place 25' of cement on top. *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.06.02 13:19:07 -08'00'06/02/25 RBDMS JSB 060225 Well Prognosis Well Name: Paxton 10 API Number: 50-133-20691-00-00 Current Status: Producing Gas Well Permit to Drill Number: 220-064 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: 1637 psi @ 3721’ TVD Based on 0.44 psi/ft Max. Potential Surface Pressure: 1265 psi Based on 0.1 psi/ft gas gradient to surface Applicable Frac Gradient: 0.702 psi/ft using 13.5 ppg EMW LOT at the surface casing shoe Shallowest Allowable Perf TVD: MPSP/(0.702-0.1) = 1265 psi / 0.602 = 2101‘ TVD Top of Applicable Gas Pool: 1645’ MD/ 1468’ TVD Well Status: Online Gas Producer flowing at 902 mcfd, 52 bwpd, 78 psi FTP Brief Well Summary Paxton 10 was drilled in 2020 and completed in the lower Beluga. In May 2022 multiple Beluga 95-135 sands were added. One month later a cap string was run to stabilize the slugging flowrate. The well has been on steady decline since. The purpose of this sundry is to perforate additional footage in the BEL 59- BEL 99B sands to increase production. Notes Regarding Wellbore Condition x Inclination o Max deviation of 62° @ 4,065’ MD o Max DLS of 7.43°/100’ @ 1,314’ MD x Min ID o 3.813” @ 144’ MD - SSSV o 3.813” @ 599’ MD- X Nipple o 3.25” @ 997’ MD – 1010’ MD – casing patch x Recent Tags/Fish o 8/29/22 EL perforated sands while flowing from BEL 95-BEL 135 (4684’- 5433’) w/ 2-7/8” guns on switch o 5/10/22 SL removed SSSV at ahead of Eline perfs and capstring install. Drifted w/ 20’, 2-7/8” dummy guns to 5620’ KB. Saw 1 bobble coming out of hole at 1000’ KB. RIH w/ 2” DDB to 5640’ KB and tagged. POOH w/ 2 cups of sand Pre-Sundry Steps: 1. MIRU Cap string truck 2. Pull 3/8” cap string from 4600’ MD 3. RD cap string truck 4. RU slickline 5. PT lubricator to 250 psi low/ 2,000 psi high 6. D&T to TD to find updated tag. Last tag was 5640’ KB in May 2022 7. RDMO slickline Well Prognosis Procedure: 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250 psi low / 2,000 psi high 3. RIH and perforate Beluga 59 – BEL 99B sands from bottom up with 2-3/4” 60 deg phased perf guns: 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 BEL 59 ±3,521' ±3,527' ±2,424' ±2,427' ±6' BEL 59 ±3,601' ±3,607' ±2,464' ±2,467' ±6' BEL 65 ±3,709' ±3,715' ±2,517' ±2,520' ±6' BEL 65 ±3,737' ±3,743' ±2,531' ±2,534' ±6' BEL 70 ±3,765' ±3,771' ±2,545' ±2,548' ±6' BEL 72 ±3,814' ±3,822' ±2,570' ±2,574' ±8' BEL 72 ±3,825' ±3,831' ±2,576' ±2,579' ±6' BEL 72 ±3,844' ±3,850' ±2,585' ±2,588' ±6' BEL 73 ±3,864' ±3,870' ±2,595' ±2,598' ±6' BEL 73 ±3,874' ±3,880' ±2,600' ±2,604' ±6' BEL 74 ±3,905' ±3,915' ±2,616' ±2,621' ±10' BEL 74 ±3,928' ±3,944' ±2,627' ±2,635' ±16' BEL 74 ±3,946' ±3,956' ±2,636' ±2,641' ±10' BEL 74 ±3,960' ±3,966' ±2,643' ±2,646' ±6' BEL 74 ±3,970' ±3,976' ±2,648' ±2,651' ±6' BEL 75 ±3,994' ±4,012' ±2,660' ±2,668' ±18' BEL 75 ±4,016' ±4,022' ±2,670' ±2,673' ±6' BEL 75 ±4,037' ±4,047' ±2,680' ±2,685' ±10' BEL 78 ±4,063' ±4,073' ±2,692' ±2,697' ±10' BEL 80 ±4,086' ±4,101' ±2,704' ±2,711' ±15' BEL 80 ±4,102' ±4,122' ±2,711' ±2,721' ±20' BEL 82 ±4,171' ±4,191' ±2,746' ±2,757' ±20' BEL 82 ±4,191' ±4,197' ±2,757' ±2,760' ±6' BEL 83 ±4,235' ±4,241' ±2,781' ±2,785' ±6' BEL 88 ±4,252' ±4,258' ±2,791' ±2,794' ±6' BEL 90 ±4,286' ±4,292' ±2,811' ±2,814' ±6' BEL 90 ±4,322' ±4,328' ±2,832' ±2,836' ±6' BEL 90 ±4,335' ±4,341' ±2,841' ±2,844' ±6' BEL 90 ±4,354' ±4,371' ±2,852' ±2,863' ±17' BEL 90 ±4,377' ±4,383' ±2,867' ±2,870' ±6' BEL 91 ±4,390' ±4,396' ±2,875' ±2,879' ±6' BEL 92 ±4,473' ±4,479' ±2,930' ±2,934' ±6' BEL 92 ±4,487' ±4,493' ±2,939' ±2,943' ±6' Well Prognosis BEL92 ±4,513' ±4,519' ±2,957' ±2,961' ±6' BEL 92 ±4,550' ±4,556' ±2,983' ±2,987' ±6' BEL 93 ±4,584' ±4,590' ±3,007' ±3,011' ±6' BEL 93 ±4,596' ±4,602' ±3,015' ±3,020' ±6' BEL 94 ±4,614' ±4,620' ±3,028' ±3,032' ±6' BEL 94 ±4,630' ±4,636' ±3,040' ±3,044' ±6' BEL 94 ±4,643' ±4,649' ±3,049' ±3,054' ±6' BEL 95 ±4,659' ±4,665' ±3,061' ±3,066' ±6' BEL 95 ±4,670' ±4,676' ±3,069' ±3,074' ±6' BEL 97 ±4,758' ±4,764' ±3,136' ±3,141' ±6' BEL 97 ±4,775' ±4,781' ±3,149' ±3,154' ±6' BEL 98 ±4,811' ±4,817' ±3,177' ±3,182' ±6' BEL 99A ±4,863' ±4,869' ±3,217' ±3,222' ±6' BEL 99B ±4,881' ±4,887' ±3,231' ±3,236' ±6' a. Proposed perfs are also shown on the proposed schematic in red font b. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation c. Use Gamma/CCL to correlate d. Record Tubing pressures before and after each perforating run at 5 min, 10 min, and 15 min intervals post perf shot (if using switched guns, wait 10 min between shots) e. Pending well production, all perf intervals may not be completed f. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations. i. Patch will most likely be used to avoid shutting off current production. g. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations 4. RDMO 5. If necessary, re- run cap string to aid with water production if encountered post perforating. a. If capstring isn’t ran, WLSSSV will be set within 2 weeks of production start up Attachments: 1. Current Schematic 2. Proposed Schematic 3. Standard Well Procedure – N2 Operations Place 25' of cement on plug, if installed. -bjm Updated by JLL 09/16/22 SCHEMATIC Ninilchik Unit Paxton #10 PTD: 220-064 API: 50-133-20691-00-00 PBTD = 5,632’ / TVD = 3,801’ TD = 5,732’ / TVD = 3,879’ RKB to GL = 17.6’ PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD FT Size Date Status BEL 95 4,684’ 4,704’ 3,079’ 3,095’ 20’ 2-7/8” 08/29/22 Open BEL 97 4,768’ 4,771’ 3,144’ 3,146’ 3’ 2-7/8” 08/29/22 Open BEL 98 4,795’ 4,805’ 3,165’ 3,172’ 10’ 2-7/8” 08/29/22 Open BEL 99 4,830’ 4,837’ 3,191’ 3,197’ 7’ 2-7/8” 08/29/22 Open BEL 100 4,901’ 4,909’ 3,247’ 3,253’ 8’ 2-7/8” 08/26/22 Open BEL 105 4,936’ 4,944’ 3,274’ 3,280’ 8’ 2-7/8” 08/26/22 Open BEL 110u 5,005’ 5,009’ 3,328’ 3,331’ 4’ 2-7/8” 08/26/22 Open BEL 115u 5,051’ 5,056’ 3,364’ 3,367’ 5’ 2-7/8” 08/26/22 Open BEL 115L 5,080’ 5,086’ 3,385’ 3,390’ 6’ 2-7/8” 08/26/22 Open Bel 120u 5,147’ 5,161’ 3,436’ 3,447’ 14’ 2-7/8” 5/13/22 Open BEL 120L 5,180’ 5,184’ 3,461’ 3,464’ 4’ 2-7/8” 08/26/22 Open BEL 131 5,194’ 5,198’ 3,472’ 3,475’ 4’ 2-7/8” 08/26/22 Open BEL 132 5,214’ 5,217’ 3,487’ 3,489’ 3’ 2-7/8” 08/26/22 Open BEL 133 5,241’ 5,244’ 3,508’ 3,510’ 3’ 2-7/8” 08/26/22 Open Bel 134u 5,260’ 5,265’ 3,522’ 3,526’ 5’ 2-7/8” 5/13/22 Open Bel 134L 5,300’ 5,320’ 3,552’ 3,567’ 20’ 2-7/8” 5/13/22 Open Bel 135a 5,353’ 5,361’ 3,592’ 3,598’ 9’ 2-7/8” 5/13/22 Open Bel 135b 5,398’ 5,411’ 3,626’ 3,635’ 13’ 2-7/8” 5/13/22 Open Bel 135c 5,418’ 5,424’ 3,641’ 3,645’ 6’ 2-7/8” 5/13/22 Open BEL 135 5,429’ 5,433’ 3,649’ 3,652’ 4’ 2-7/8” 08/26/22 Open Bel 135e 5,443’ 5,459’ 3,660’ 3,672’ 16’ 2-7/8” 5/13/22 Open Bel 135 5,460’ 5,480’ 3,673’ 3,688’ 20’ 2-7/8” 6 SPF 11/13/20 Open Bel 135 5,480’ 5,500’ 3,688’ 3,703’ 20’ 2-7/8” 6 SPF 11/13/20 Open Bel 136 5,514’ 5,520’ 3,714’ 3,718’ 6’ 2-7/8” 6 SPF 11/13/20 Open Bel 136L 5,523’ 5,543’ 3,721’ 3,737’ 21’ 2-7/8” 5/13/22 Open OPEN HOLE / CEMENT DETAIL 7-5/8" 102 BBL’s of cement in 9-7/8” hole – 27 BBLs Cement to Surface 4-1/2” 140 BBL’s of cement in 6-3/4” hole – zero losses during cement job. 13 bbls spacer back to surface (of 35 pumped). 10/22/20 CBL showed ToC at 1440’ MD after 4 days of cement cure. 4/16/21 CBL showed ToC at 780’ MD. CASING/TUBING DETAIL Size Type Wt Grade Conn. ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 DWC/C 6.875” Surf 1,522’ 4-1/2" Prod Csg 12.6 L-80 DWC/C HT 3.958” 636’ 5,718’ 4-1/2" Tubing 12.6 L-80 IBT 3.958” Surf 636’ 3/8” Capillary String Surf 4,600’ 7 16” 7-5/8” ToC at 780’MD (4/16/21 CBL) 4-1/2” JEWELRY DETAIL No. DepthMD DepthTVD ID Item 1 144’ 144’ 3.813” Surface controlled TRSSSV: NE-Slim (Halliburton): Permanently locked open 11/18/21 2 590’ 587’ 4.000” D&L Oil Tools 7-5/8” x 4-1/2” Hydraulic permanent packer (TriPoint) 3 599’ 596’ 3.813” X-nipple 4 636’ 633’ 3.95” Bowen (Baker) “Casing Patch” (Sealing Overshot with grapple) 5 997’ – 1010’ 975’ – 997’ 3.25” X-Span permanent patch (set 5-12-21) 6 1000’ 978’ Incomplete jet cut (4/16/21) 7 1,283’ 1,217’ 3.958” Swell Packer 1 2/3 4 Leaking Shoe as of 4/19/21 RTTS MIT fail 5/6 BEL 120 –136 BEL 95 – BEL 115 Updated by SRW 5-20-25 PROPOSED Ninilchik Unit Paxton #10 PTD: 220-064 API: 50-133-20691-00-00 PBTD = 5,632’ / TVD = 3,801’ TD = 5,732’ / TVD = 3,879’ RKB to GL = 17.6’ PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD FT Size Date Status BEL 59 ±3,521' ±3,527' ±2,424' ±2,427' ±6' 2-3/4” TBD Proposed BEL 59 ±3,601' ±3,607' ±2,464' ±2,467' ±6' 2-3/4” TBD Proposed BEL 65 ±3,709' ±3,715' ±2,517' ±2,520' ±6' 2-3/4” TBD Proposed BEL 65 ±3,737' ±3,743' ±2,531' ±2,534' ±6' 2-3/4” TBD Proposed BEL 70 ±3,765' ±3,771' ±2,545' ±2,548' ±6' 2-3/4” TBD Proposed BEL 72 ±3,814' ±3,822' ±2,570' ±2,574' ±8' 2-3/4” TBD Proposed BEL 72 ±3,825' ±3,831' ±2,576' ±2,579' ±6' 2-3/4” TBD Proposed BEL 72 ±3,844' ±3,850' ±2,585' ±2,588' ±6' 2-3/4” TBD Proposed BEL 73 ±3,864' ±3,870' ±2,595' ±2,598' ±6' 2-3/4” TBD Proposed BEL 73 ±3,874' ±3,880' ±2,600' ±2,604' ±6' 2-3/4” TBD Proposed BEL 74 ±3,905' ±3,915' ±2,616' ±2,621' ±10' 2-3/4” TBD Proposed BEL 74 ±3,928' ±3,944' ±2,627' ±2,635' ±16' 2-3/4” TBD Proposed BEL 74 ±3,946' ±3,956' ±2,636' ±2,641' ±10' 2-3/4” TBD Proposed BEL 74 ±3,960' ±3,966' ±2,643' ±2,646' ±6' 2-3/4” TBD Proposed BEL 74 ±3,970' ±3,976' ±2,648' ±2,651' ±6' 2-3/4” TBD Proposed BEL 75 ±3,994' ±4,012' ±2,660' ±2,668' ±18' 2-3/4” TBD Proposed BEL 75 ±4,016' ±4,022' ±2,670' ±2,673' ±6' 2-3/4” TBD Proposed BEL 75 ±4,037' ±4,047' ±2,680' ±2,685' ±10' 2-3/4” TBD Proposed BEL 78 ±4,063' ±4,073' ±2,692' ±2,697' ±10' 2-3/4” TBD Proposed BEL 80 ±4,086' ±4,101' ±2,704' ±2,711' ±15' 2-3/4” TBD Proposed BEL 80 ±4,102' ±4,122' ±2,711' ±2,721' ±20' 2-3/4” TBD Proposed BEL 82 ±4,171' ±4,191' ±2,746' ±2,757' ±20' 2-3/4” TBD Proposed BEL 82 ±4,191' ±4,197' ±2,757' ±2,760' ±6' 2-3/4” TBD Proposed BEL 83 ±4,235' ±4,241' ±2,781' ±2,785' ±6' 2-3/4” TBD Proposed BEL 88 ±4,252' ±4,258' ±2,791' ±2,794' ±6' 2-3/4” TBD Proposed PERFORATION DETAIL - Continued on following page OPEN HOLE / CEMENT DETAIL 7-5/8" 102 BBL’s of cement in 9-7/8” hole – 27 BBLs Cement to Surface 4-1/2” 140 BBL’s of cement in 6-3/4” hole – zero losses during cement job. 13 bbls spacer back to surface (of 35 pumped). 10/22/20 CBL showed ToC at 1440’ MD after 4 days of cement cure. 4/16/21 CBL showed ToC at 780’ MD. CASING/TUBING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 DWC/C 6.875” Surf 1,522’ 4-1/2" Prod Csg 12.6 L-80 DWC/C HT 3.958” 636’ 5,718’ 4-1/2" Tubing 12.6 L-80 IBT 3.958” Surf 636’ 3/8” Capillary String Surf TBD 7 16” 7-5/8” ToC at 780’MD (4/16/21 CBL) 4-1/2” JEWELRY DETAIL No. Depth MD Depth TVD ID Item 1 144’ 144’ 3.813” Surface controlled TRSSSV: NE-Slim (Halliburton): Permanently locked open 11/18/21 2 590’ 587’ 4.000” D&L Oil Tools 7-5/8” x 4-1/2” Hydraulic permanent packer (TriPoint) 3 599’ 596’ 3.813” X-nipple 4 636’ 633’ 3.95” Bowen (Baker) “Casing Patch” (Sealing Overshot with grapple) 5 997’ – 1010’ 975’ – 997’ 3.25” X-Span permanent patch (set 5-12-21) 6 1000’ 978’ Incomplete jet cut (4/16/21) 7 1,283’ 1,217’ 3.958” Swell Packer 1 2/3 4 Leaking Shoe as of 4/19/21 RTTS MIT fail 5/6 BEL 120 –136 BEL 95 – BEL 115 Updated by SRW 5-20-25 PROPOSED Ninilchik Unit Paxton #10 PTD: 220-064 API: 50-133-20691-00-00 PERFORATION DETAIL – Continued from previous page Sand TOP MD BTM MD TOP TVD BTM TVD FT Size Date Status BEL 90 ±4,286' ±4,292' ±2,811' ±2,814' ±6' 2-3/4” TBD Proposed BEL 90 ±4,322' ±4,328' ±2,832' ±2,836' ±6' 2-3/4” TBD Proposed BEL 90 ±4,335' ±4,341' ±2,841' ±2,844' ±6' 2-3/4” TBD Proposed BEL 90 ±4,354' ±4,371' ±2,852' ±2,863' ±17' 2-3/4” TBD Proposed BEL 90 ±4,377' ±4,383' ±2,867' ±2,870' ±6' 2-3/4” TBD Proposed BEL 91 ±4,390' ±4,396' ±2,875' ±2,879' ±6' 2-3/4” TBD Proposed BEL 92 ±4,473' ±4,479' ±2,930' ±2,934' ±6' 2-3/4” TBD Proposed BEL 92 ±4,487' ±4,493' ±2,939' ±2,943' ±6' 2-3/4” TBD Proposed BEL92 ±4,513' ±4,519' ±2,957' ±2,961' ±6' 2-3/4” TBD Proposed BEL 92 ±4,550' ±4,556' ±2,983' ±2,987' ±6' 2-3/4” TBD Proposed BEL 93 ±4,584' ±4,590' ±3,007' ±3,011' ±6' 2-3/4” TBD Proposed BEL 93 ±4,596' ±4,602' ±3,015' ±3,020' ±6' 2-3/4” TBD Proposed BEL 94 ±4,614' ±4,620' ±3,028' ±3,032' ±6' 2-3/4” TBD Proposed BEL 94 ±4,630' ±4,636' ±3,040' ±3,044' ±6' 2-3/4” TBD Proposed BEL 94 ±4,643' ±4,649' ±3,049' ±3,054' ±6' 2-3/4” TBD Proposed BEL 95 ±4,659' ±4,665' ±3,061' ±3,066' ±6' 2-3/4” TBD Proposed BEL 95 ±4,670' ±4,676' ±3,069' ±3,074' ±6' 2-3/4” TBD Proposed BEL 97 ±4,758' ±4,764' ±3,136' ±3,141' ±6' 2-3/4” TBD Proposed BEL 97 ±4,775' ±4,781' ±3,149' ±3,154' ±6' 2-3/4” TBD Proposed BEL 98 ±4,811' ±4,817' ±3,177' ±3,182' ±6' 2-3/4” TBD Proposed BEL 99A ±4,863' ±4,869' ±3,217' ±3,222' ±6' 2-3/4” TBD Proposed BEL 99B ±4,881' ±4,887' ±3,231' ±3,236' ±6' 2-3/4” TBD Proposed BEL 95 4,684’ 4,704’ 3,079’ 3,095’ 20’ 2-7/8” 08/29/22 Open BEL 97 4,768’ 4,771’ 3,144’ 3,146’ 3’ 2-7/8” 08/29/22 Open BEL 98 4,795’ 4,805’ 3,165’ 3,172’ 10’ 2-7/8” 08/29/22 Open BEL 99 4,830’ 4,837’ 3,191’ 3,197’ 7’ 2-7/8” 08/29/22 Open BEL 100 4,901’ 4,909’ 3,247’ 3,253’ 8’ 2-7/8” 08/26/22 Open BEL 105 4,936’ 4,944’ 3,274’ 3,280’ 8’ 2-7/8” 08/26/22 Open BEL 110u 5,005’ 5,009’ 3,328’ 3,331’ 4’ 2-7/8” 08/26/22 Open BEL 115u 5,051’ 5,056’ 3,364’ 3,367’ 5’ 2-7/8” 08/26/22 Open BEL 115L 5,080’ 5,086’ 3,385’ 3,390’ 6’ 2-7/8” 08/26/22 Open Bel 120u 5,147’ 5,161’ 3,436’ 3,447’ 14’ 2-7/8” 5/13/22 Open BEL 120L 5,180’ 5,184’ 3,461’ 3,464’ 4’ 2-7/8” 08/26/22 Open BEL 131 5,194’ 5,198’ 3,472’ 3,475’ 4’ 2-7/8” 08/26/22 Open BEL 132 5,214’ 5,217’ 3,487’ 3,489’ 3’ 2-7/8” 08/26/22 Open BEL 133 5,241’ 5,244’ 3,508’ 3,510’ 3’ 2-7/8” 08/26/22 Open Bel 134u 5,260’ 5,265’ 3,522’ 3,526’ 5’ 2-7/8” 5/13/22 Open Bel 134L 5,300’ 5,320’ 3,552’ 3,567’ 20’ 2-7/8” 5/13/22 Open Bel 135a 5,353’ 5,361’ 3,592’ 3,598’ 9’ 2-7/8” 5/13/22 Open Bel 135b 5,398’ 5,411’ 3,626’ 3,635’ 13’ 2-7/8” 5/13/22 Open Bel 135c 5,418’ 5,424’ 3,641’ 3,645’ 6’ 2-7/8” 5/13/22 Open BEL 135 5,429’ 5,433’ 3,649’ 3,652’ 4’ 2-7/8” 08/26/22 Open Bel 135e 5,443’ 5,459’ 3,660’ 3,672’ 16’ 2-7/8” 5/13/22 Open Bel 135 5,460’ 5,480’ 3,673’ 3,688’ 20’ 2-7/8” 6 SPF 11/13/20 Open Bel 135 5,480’ 5,500’ 3,688’ 3,703’ 20’ 2-7/8” 6 SPF 11/13/20 Open Bel 136 5,514’ 5,520’ 3,714’ 3,718’ 6’ 2-7/8” 6 SPF 11/13/20 Open Bel 136L 5,523’ 5,543’ 3,721’ 3,737’ 21’ 2-7/8” 5/13/22 Open STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. Kyle Wiseman Hilcorp Alaska, LLC Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 11/23/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20221123 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# PAXTON 6 50133207070000 222054 8/1/2022 Yellowjacket PERF BCU-7A 50133202840100 214060 8/2/2022 Yellowjacket GPT-PERF KBU 43-07Y 50133206250000 214019 8/3/2022 Yellowjacket PERF KBU 22-06Y 50133206500000 215044 8/4/2022 Yellowjacket GPT-PERF SRU 32A-33 50133101640100 191014 8/21/2022 Yellowjacket GPT-PERF HVB 16A 50231200400100 222070 8/23/2022 Yellowjacket PERF PAXTON 10 50133206910000 220064 8/26/2022 Yellowjacket PERF HVB-16A 50231200400100 222070 8/27/2022 Yellowjacket PERF PAXTON 10 50133206910000 220064 8/29/2022 Yellowjacket PERF KALOTSA 4 50133206650000 217063 9/1/2022 Yellowjacket GPT-PERF KALOTSA 4 50133206650000 217063 9/6/2022 Yellowjacket PERF-GPT Please include current contact information if different from above. 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ƚŵ ϭϲ͟ŽŶĚƵĐƚŽƌʹƌŝǀĞŶ ƚŽ^ĞƚĞƉƚŚ ϴϰ yͲϱϲ tĞůĚ ϭϱ͘Ϭϭ͟ ^ƵƌĨ ϭϮϬΖ ϳͲϱͬϴΗ ^ƵƌĨƐŐ Ϯϵ͘ϳ >ͲϴϬ tͬ ϲ͘ϴϳϱ͟ ^ƵƌĨ ϭ͕ϱϮϮ͛ ϰͲϭͬϮΗ WƌŽĚƐŐ ϭϮ͘ϲ >ͲϴϬ tͬ,d ϯ͘ϵϱϴ͟ ϲϯϲ͛ ϱ͕ϳϭϴ͛ ϰͲϭͬϮΗ dƵďŝŶŐ ϭϮ͘ϲ >ͲϴϬ /d ϯ͘ϵϱϴ͟ ^ƵƌĨ ϲϯϲ͛ ϯͬϴ͟ ĂƉ^ƚƌŝŶŐ;ϲͲϭϳͲϮϮͿ ^ƵƌĨ ϱ͕ϱϱϬ͛ ϳ ϭϲ͟ ϳͲϱͬϴ͟ dŽĂƚ ϳϴϬ͛D ;ϰͬϭϲͬϮϭ >Ϳ ϰͲϭͬϮ͟ :t>Zzd/> EŽ͘ ĞƉƚŚD ĞƉƚŚds / /ƚĞŵ ϭ ϭϰϰ͛ ϭϰϰ͛ ϯ͘ϴϭϯ͟ ^ƵƌĨĂĐĞĐŽŶƚƌŽůůĞĚdZ^^^s͗EͲ^ůŝŵ;,ĂůůŝďƵƌƚŽŶͿ͗ WĞƌŵĂŶĞŶƚůǇůŽĐŬĞĚŽƉĞŶϭϭͬϭϴͬϮϭ Ϯ ϱϵϬ͛ ϱϴϳ͛ ϰ͘ϬϬϬ͟ Θ>KŝůdŽŽůƐϳͲϱͬϴ͟ǆϰͲϭͬϮ͟,ǇĚƌĂƵůŝĐƉĞƌŵĂŶĞŶƚ ƉĂĐŬĞƌ;dƌŝWŽŝŶƚͿ ϯ ϱϵϵ͛ ϱϵϲ͛ ϯ͘ϴϭϯ͟ yͲŶŝƉƉůĞ ϰ ϲϯϲ͛ ϲϯϯ͛ ϯ͘ϵϱ͟ ŽǁĞŶ;ĂŬĞƌͿ͞ĂƐŝŶŐWĂƚĐŚ͟;^ĞĂůŝŶŐKǀĞƌƐŚŽƚǁŝƚŚ ŐƌĂƉƉůĞͿ ϱ ϵϵϳ͛ʹϭϬϭϬ͛ ϵϳϱ͛ʹϵϵϳ͛ ϯ͘Ϯϱ͟ yͲ^ƉĂŶƉĞƌŵĂŶĞŶƚƉĂƚĐŚ;ƐĞƚϱͲϭϮͲϮϭͿ ϲ ϭϬϬϬ͛ ϵϳϴ͛ /ŶĐŽŵƉůĞƚĞũĞƚĐƵƚ;ϰͬϭϲͬϮϭͿ ϳ ϭ͕Ϯϴϯ͛ ϭ͕Ϯϭϳ͛ ϯ͘ϵϱϴ͟ ^ǁĞůůWĂĐŬĞƌ ϭ Ϯͬϯ ϰ >ĞĂŬŝŶŐ ^ŚŽĞĂƐŽĨ ϰͬϭϵͬϮϭ Zdd^D/d ĨĂŝů ϱͬϲ >ϭϮϬʹϭϯϲ hƉĚĂƚĞĚďǇ:>>ϬϴͬϭϮͬϮϮ WZKWK^ EŝŶŝůĐŚŝŬhŶŝƚ WĂǆƚŽŶηϭϬ Wd͗ϮϮϬͲϬϲϰ W/͗ϱϬͲϭϯϯͲϮϬϲϵϭͲϬϬͲϬϬ Wdсϱ͕ϲϯϮ͛ͬdsсϯ͕ϴϬϭ͛ dсϱ͕ϳϯϮ͛ͬdsсϯ͕ϴϳϵ͛ Z<ƚŽ'>сϭϳ͘ϲ͛ WZ&KZd/KEd/> ^ĂŶĚ dKW DdDDdKW ds dD ds&d ^ŝǌĞ ĂƚĞ ^ƚĂƚƵƐ >ͺϵϱ цϰ͕ϲϴϰ͛ цϰ͕ϳϬϰ͛ цϯ͕Ϭϳϵ͛ цϯ͕Ϭϵϱ͛ ϮϬ͛ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ >ͺϵϳ цϰ͕ϳϲϴ͛ цϰ͕ϳϳϭ͛ цϯ͕ϭϰϰ͛ цϯ͕ϭϰϲ͛ ϯ͛ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ >ͺϵϴ цϰ͕ϳϵϱ͛ цϰ͕ϴϬϱ͛ цϯ͕ϭϲϱ͛ цϯ͕ϭϳϮ͛ ϭϬ͛ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ >ͺϵϵ цϰ͕ϴϯϬ͛ цϰ͕ϴϯϳ͛ цϯ͕ϭϵϭ͛ цϯ͕ϭϵϳ͛ ϳ͛ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ >ͺϭϬϬ цϰ͕ϵϬϭ͛ цϰ͕ϵϬϵ͛ цϯ͕Ϯϰϳ͛ цϯ͕Ϯϱϯ͛ ϴ͛ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ >ͺϭϬϱ цϰ͕ϵϯϲ͛ цϰ͕ϵϰϰ͛ цϯ͕Ϯϳϰ͛ цϯ͕ϮϴϬ͛ ϴ͛ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ >ͺϭϭϬƵ цϱ͕ϬϬϱ͛ цϱ͕ϬϬϵ͛ цϯ͕ϯϮϴ͛ цϯ͕ϯϯϭ͛ ϰ͛ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ >ͺϭϭϱƵ цϱ͕Ϭϱϭ͛ цϱ͕Ϭϱϲ͛ цϯ͕ϯϲϰ͛ цϯ͕ϯϲϳ͛ ϱ͛ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ >ͺϭϭϱ> цϱ͕ϬϴϬ͛ цϱ͕Ϭϴϲ͛ цϯ͕ϯϴϱ͛ цϯ͕ϯϵϬ͛ ϲ͛ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ ĞůϭϮϬƵ ϱ͕ϭϰϳ͛ ϱ͕ϭϲϭ͛ ϯ͕ϰϯϲ͛ ϯ͕ϰϰϳ͛ ϭϰ͛ ϮͲϳͬϴ͟ ϱͬϭϯͬϮϮ KƉĞŶ >ͺϭϮϬ> цϱ͕ϭϴϬ͛ цϱ͕ϭϴϰ͛ цϯ͕ϰϲϭ͛ цϯ͕ϰϲϰ͛ ϰ͛ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ >ͺϭϯϭ цϱ͕ϭϵϰ͛ цϱ͕ϭϵϴ͛ цϯ͕ϰϳϮ͛ цϯ͕ϰϳϱ͛ ϰ͛ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ >ͺϭϯϮ цϱ͕Ϯϭϰ͛ цϱ͕Ϯϭϳ͛ цϯ͕ϰϴϳ͛ цϯ͕ϰϴϵ͛ ϯ͛ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ >ͺϭϯϯ цϱ͕Ϯϰϭ͛ цϱ͕Ϯϰϰ͛ цϯ͕ϱϬϴ͛ цϯ͕ϱϭϬ͛ ϯ͛ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ ĞůϭϯϰƵ ϱ͕ϮϲϬ͛ ϱ͕Ϯϲϱ͛ ϯ͕ϱϮϮ͛ ϯ͕ϱϮϲ͛ ϱ͛ ϮͲϳͬϴ͟ ϱͬϭϯͬϮϮ KƉĞŶ Ğůϭϯϰ> ϱ͕ϯϬϬ͛ ϱ͕ϯϮϬ͛ ϯ͕ϱϱϮ͛ ϯ͕ϱϲϳ͛ ϮϬ͛ ϮͲϳͬϴ͟ ϱͬϭϯͬϮϮ KƉĞŶ ĞůϭϯϱĂ ϱ͕ϯϱϯ͛ ϱ͕ϯϲϭ͛ ϯ͕ϱϵϮ͛ ϯ͕ϱϵϴ͛ ϵ͛ ϮͲϳͬϴ͟ ϱͬϭϯͬϮϮ KƉĞŶ Ğůϭϯϱď ϱ͕ϯϵϴ͛ ϱ͕ϰϭϭ͛ ϯ͕ϲϮϲ͛ ϯ͕ϲϯϱ͛ ϭϯ͛ ϮͲϳͬϴ͟ ϱͬϭϯͬϮϮ KƉĞŶ ĞůϭϯϱĐ ϱ͕ϰϭϴ͛ ϱ͕ϰϮϰ͛ ϯ͕ϲϰϭ͛ ϯ͕ϲϰϱ͛ ϲ͛ ϮͲϳͬϴ͟ ϱͬϭϯͬϮϮ KƉĞŶ >ͺϭϯϱ цϱ͕ϰϮϵ͛ цϱ͕ϰϯϯ͛ цϯ͕ϲϰϵ͛ цϯ͕ϲϱϮ͛ ϰ͛ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ ĞůϭϯϱĞ ϱ͕ϰϰϯ͛ ϱ͕ϰϱϵ͛ ϯ͕ϲϲϬ͛ ϯ͕ϲϳϮ͛ ϭϲ͛ ϮͲϳͬϴ͟ ϱͬϭϯͬϮϮ KƉĞŶ Ğůϭϯϱ ϱ͕ϰϲϬ͛ ϱ͕ϰϴϬ͛ ϯ͕ϲϳϯ͛ ϯ͕ϲϴϴ͛ ϮϬ͛ ϮͲϳͬϴ͟ϲ^W& ϭϭͬϭϯͬϮϬ KƉĞŶ Ğůϭϯϱ ϱ͕ϰϴϬ͛ ϱ͕ϱϬϬ͛ ϯ͕ϲϴϴ͛ ϯ͕ϳϬϯ͛ ϮϬ͛ ϮͲϳͬϴ͟ϲ^W& ϭϭͬϭϯͬϮϬ KƉĞŶ Ğůϭϯϲ ϱ͕ϱϭϰ͛ ϱ͕ϱϮϬ͛ ϯ͕ϳϭϰ͛ ϯ͕ϳϭϴ͛ ϲ͛ ϮͲϳͬϴ͟ϲ^W& ϭϭͬϭϯͬϮϬ KƉĞŶ Ğůϭϯϲ> ϱ͕ϱϮϯ͛ ϱ͕ϱϰϯ͛ ϯ͕ϳϮϭ͛ ϯ͕ϳϯϳ͛ Ϯϭ͛ ϮͲϳͬϴ͟ ϱͬϭϯͬϮϮ KƉĞŶ KWE,K>ͬDEdd/> ϳͲϱͬϴΗ ϭϬϮ>͛ƐŽĨĐĞŵĞŶƚŝŶϵͲϳͬϴ͟ŚŽůĞʹϮϳ>ƐĞŵĞŶƚƚŽ^ƵƌĨĂĐĞ ϰͲϭͬϮ͟ ϭϰϬ>͛ƐŽĨĐĞŵĞŶƚŝŶϲͲϯͬϰ͟ŚŽůĞʹǌĞƌŽůŽƐƐĞƐĚƵƌŝŶŐĐĞŵĞŶƚũŽď͘ϭϯďďůƐƐƉĂĐĞƌ ďĂĐŬƚŽƐƵƌĨĂĐĞ;ŽĨϯϱƉƵŵƉĞĚͿ͘ϭϬͬϮϮͬϮϬ>ƐŚŽǁĞĚdŽĂƚϭϰϰϬ͛DĂĨƚĞƌϰĚĂǇƐ ŽĨĐĞŵĞŶƚĐƵƌĞ͘ϰͬϭϲͬϮϭ>ƐŚŽǁĞĚdŽĂƚϳϴϬ͛D͘ ^/E'ͬdh/E' d/> ^ŝǌĞ dǇƉĞ tƚ 'ƌĂĚĞ ŽŶŶ͘ / dŽƉ ƚŵ ϭϲ͟ŽŶĚƵĐƚŽƌʹƌŝǀĞŶ ƚŽ^ĞƚĞƉƚŚ ϴϰ yͲϱϲ tĞůĚ ϭϱ͘Ϭϭ͟ ^ƵƌĨ ϭϮϬΖ ϳͲϱͬϴΗ ^ƵƌĨƐŐ Ϯϵ͘ϳ >ͲϴϬ tͬ ϲ͘ϴϳϱ͟ ^ƵƌĨ ϭ͕ϱϮϮ͛ ϰͲϭͬϮΗ WƌŽĚƐŐ ϭϮ͘ϲ >ͲϴϬ tͬ,d ϯ͘ϵϱϴ͟ ϲϯϲ͛ ϱ͕ϳϭϴ͛ ϰͲϭͬϮΗ dƵďŝŶŐ ϭϮ͘ϲ >ͲϴϬ /d ϯ͘ϵϱϴ͟ ^ƵƌĨ ϲϯϲ͛ ϯͬϴ͟ ĂƉ^ƚƌŝŶŐ;ϲͲϭϳͲϮϮͿ ^ƵƌĨ ϱ͕ϱϱϬ͛ ϳ ϭϲ͟ ϳͲϱͬϴ͟ dŽĂƚ ϳϴϬ͛D ;ϰͬϭϲͬϮϭ >Ϳ ϰͲϭͬϮ͟ :t>Zzd/> EŽ͘ ĞƉƚŚD ĞƉƚŚds / /ƚĞŵ ϭ ϭϰϰ͛ ϭϰϰ͛ ϯ͘ϴϭϯ͟ ^ƵƌĨĂĐĞĐŽŶƚƌŽůůĞĚdZ^^^s͗EͲ^ůŝŵ;,ĂůůŝďƵƌƚŽŶͿ͗ WĞƌŵĂŶĞŶƚůǇůŽĐŬĞĚŽƉĞŶϭϭͬϭϴͬϮϭ Ϯ ϱϵϬ͛ ϱϴϳ͛ ϰ͘ϬϬϬ͟ Θ>KŝůdŽŽůƐϳͲϱͬϴ͟ǆϰͲϭͬϮ͟,ǇĚƌĂƵůŝĐƉĞƌŵĂŶĞŶƚ ƉĂĐŬĞƌ;dƌŝWŽŝŶƚͿ ϯ ϱϵϵ͛ ϱϵϲ͛ ϯ͘ϴϭϯ͟ yͲŶŝƉƉůĞ ϰ ϲϯϲ͛ ϲϯϯ͛ ϯ͘ϵϱ͟ ŽǁĞŶ;ĂŬĞƌͿ͞ĂƐŝŶŐWĂƚĐŚ͟;^ĞĂůŝŶŐKǀĞƌƐŚŽƚǁŝƚŚ ŐƌĂƉƉůĞͿ ϱ ϵϵϳ͛ʹϭϬϭϬ͛ ϵϳϱ͛ʹϵϵϳ͛ ϯ͘Ϯϱ͟ yͲ^ƉĂŶƉĞƌŵĂŶĞŶƚƉĂƚĐŚ;ƐĞƚϱͲϭϮͲϮϭͿ ϲ ϭϬϬϬ͛ ϵϳϴ͛ /ŶĐŽŵƉůĞƚĞũĞƚĐƵƚ;ϰͬϭϲͬϮϭͿ ϳ ϭ͕Ϯϴϯ͛ ϭ͕Ϯϭϳ͛ ϯ͘ϵϱϴ͟ ^ǁĞůůWĂĐŬĞƌ ϭ Ϯͬϯ ϰ >ĞĂŬŝŶŐ ^ŚŽĞĂƐŽĨ ϰͬϭϵͬϮϭ Zdd^D/d ĨĂŝů ϱͬϲ >ϭϮϬʹϭϯϲ >ϵϱʹ > ϭϯϱ Kaitlyn Barcelona Hilcorp Alaska, 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 or FAX to 907 564-4422 Received By: Date: Date: 07/11/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL Well API # PTD # Log Date Log Company Log Type Notes BCU 18RD 50133205840100 222033 6/11/2022 Yellowjacket GPT-PERF + Report BCU 18RD 50133205840100 222033 6/18/2022 Yellowjacket GPT-PERF + Report BCU 18RD 50133205840100 222033 6/7/2022 Yellowjacket GPT-PLUG + Report BCU 24 50133206390000 214112 6/16/2022 Halliburton PPROF BCU 24 50133206390000 214112 5/23/2022 Yellowjacket GPT-PERF + Report BCU 24 50133206390000 214112 5/26/2022 Yellowjacket GPT-PERF + Report BCU 7A 50133202840100 214060 6/21/2022 Yellowjacket CBL BCU 7A 50133202840100 214060 6/15/2022 Yellowjacket GAMMA RAY + Report BRU 232-26 50283200770000 184138 5/25/2022 Yellowjacket CBL CLU 01RD 50133203230100 203129 5/19/2022 Yellowjacket PERF + Report CLU 01RD 50133203230100 203129 5/24/2022 Yellowjacket PERF + Report CLU 09 50133205440000 204161 5/27/2022 Yellowjacket PERF + Report CLU-1RD 50133203230100 203129 5/28/2022 Halliburton PPROF + Report END 1-17A 50029221000100 196199 5/26/2022 Halliburton LDL END 1-45 50029219910000 189124 5/23/2022 Halliburton LDL + Report END 3-17F 50029219460600 203216 6/15/2022 AK E-Line PLUG CUT FALLS CREEK 3 50133205240000 203102 6/4/2022 Yellowjacket PERF + Report HVB B-16 50231200400000 212133 6/14/2022 AK E-Line CIBP KALOTSA 1 50133206570000 216132 7/7/2022 Yellowjacket PERF + Report KBU 11-07 50133205560000 205165 6/16/2022 Yellowjacket GPT-PERF + Report KBU 11-07 50133205560000 205165 6/20/2022 Yellowjacket GPT-PERF + Report KBU 33-06X 50133205290000 203183 6/22/2022 Yellowjacket CBL MPU B-28 50029235660000 216027 5/27/2022 Halliburton LDL MPU B-28 50029235660000 216027 5/27/2022 Halliburton MFC + Report MPU B-30 50029235710000 216153 5/18/2022 Halliburton PERF MPU E-06 50029221540000 191048 5/28/2022 Halliburton MFC + Report Kaitlyn Barcelona Hilcorp Alaska, 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 or FAX to 907 564-4422 Received By: Date: MPU E-35 50029236150000 218152 6/15/2022 Halliburton MFC + Report MPU L-50 50029235550000 215132 6/24/2022 Read COIL FLAG PAXTON 10 50133206910000 220064 5/27/2022 Halliburton PPROF + Report PBU C-24B 50029208160200 212063 5/28/2022 Halliburton PPROF + Report PBU C-24B 50029208160200 212063 5/28/2022 Halliburton RBT PBU GNI-03 50029228200000 197189 6/25/2022 Read CALIPER PBU GNI-03 50029228200000 197189 6/25/2022 Read TEMP-PRESS PBU K-01 50029209980000 183121 6/21/2022 Halliburton PPROF + Report PBU M-13A 50029205220100 201165 5/27/2022 Halliburton TMD3D-WFL + Report PBU NGI-05 50029201960000 176014 6/7/2022 Halliburton CAST PBU W-01A 50029218660100 203176 6/8/2022 Halliburton RBT SRU 241-33 50133206630000 217047 6/13/2022 Yellowjacket PERF SRU 241-33B 50133206960000 221053 5/25/2022 Halliburton TEMP-PRESS SRU 32A-33 50133101640100 191014 6/11/2022 AK E-Line PPROF Please include current contact information if different from above. BCU 18RD PTD:222-033 T36747 BCU 24 PTD:214-112 T36748 BCU 7A PTD:214-060 T36749 BRU 232-26 PTD:184-138 T36750 CLU 01RD PTD:203-129 T36751 CLU 09 PTD: 204-161 T36752 CLU1RD PTD:203-129 T36751 END 1-17A PTD:196-199 T36753 END 1-45 PTD:189-124 T36754 END 3-17F PTD:203-216 T36755 Falls Creek 3 PTD:203-102 T36756 HVB B-16 PTD:212-133 T36757 Kalosta 1 PTD:216-132 T36758 KBU 11-7 PTD:205-165 T36759 KBU 33-06X PTD:203-183 T36760 MPU B-28 PTD:216-027 T36761 MPU B-30 PTD:216-153 T36762 MPU E-06 PTD: 191-048 T36763 MPU E-35 PTD:218-152 T36764 MPU L-50 PTD:215-132 T36765 Paxton 10 PTD:220-064 T36766 PBU C-24B PTD:212-063 T36767 PBU GNI-03 PTD:197-189 T36768 PBU K-01 PTD:183-121 T36769 PBU M-13A PTD:201-165 T36770 PBU NGI-05 PTD:176-014 T36771 PBU W-01A PTD:203-176 T36772 SRU 241-33 PTD:217-047 T36773 SRU 241-33B PTD:221-053 T36774 SRU 32A-33 PTD: 191-014 T36775 Kayla Junke Digitally signed by Kayla Junke Date: 2022.07.12 12:56:51 -08'00' From:Jacob Flora To:McLellan, Bryan J (OGC) Cc:Juanita Lovett Subject:RE: [EXTERNAL] RE: Paxton 10 AOGCC 10-403 PTD 220-064 Submitted 06-03-22 - Sundry Application Date:Monday, June 13, 2022 8:59:03 AM Good Morning Bryan, I believe this is still waiting for the commissioner signature. Can we get approval to proceed with the cap string install as detailed in the submitted sundry? We have the truck repaired and see this as our highest priority install. Thanks, Jake From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, June 8, 2022 10:17 AM To: Jacob Flora <Jake.Flora@hilcorp.com> Subject: [EXTERNAL] RE: Paxton 10 AOGCC 10-403 PTD 220-064 Submitted 06-03-22 - Sundry Application Jake, Hilcorp is granted an additional 1-week extension for installing the SSSV. The Cap String installation Sundry is routing through AOGCC system and the 1-week extension is intended to provide time for Hilcorp to install the cap string before the SSSV test is due. It is noted that the Cap String prevents installation of the SSSV, per 20 AAC 25.265(d)(4). Surface Safety valve testing is still required per normal schedule. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Monday, June 6, 2022 1:38 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: Paxton 10 AOGCC 10-403 PTD 220-064 Submitted 06-03-22 - Sundry Application Hello Bryan, On 5/25/22 you allowed a two week extension to re-install the WR-SSSV, which would require it be in the ground by 6/8. We just submitted a cap string install sundry on Friday and included mention in it that the cap string would CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. prohibit the reinstallation of the safety valve. Can we request an additional extension for the WR-SSSV with the intention to give you enough time to review the cap string sundry. We can install it, but then would be pulling it again if the cap string sundry is approved. Thanks for the guidance, Also I have requested the satellite maps for HVB-16 and will get them over to you. Jake From: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Sent: Friday, June 3, 2022 1:26 PM To: Donna Ambruz <dambruz@hilcorp.com> Cc: Jacob Flora <Jake.Flora@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Vanessa Hughes <vhughes@hilcorp.com> Subject: [EXTERNAL] RE: Paxton 10 AOGCC 10-403 PTD 220-064 Submitted 06-03-22 - Sundry Application Received for processing From: Donna Ambruz <dambruz@hilcorp.com> Sent: Friday, June 3, 2022 8:53 AM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Jacob Flora <Jake.Flora@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Vanessa Hughes <vhughes@hilcorp.com> Subject: Paxton 10 AOGCC 10-403 PTD 220-064 Submitted 06-03-22 - Sundry Application Application for Sundry Approval Thank you. Donna Ambruz Operations/Regulatory Tech KEN Asset Team Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 907.777.8305 - Direct dambruz@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. From:McLellan, Bryan J (OGC) To:Jacob Flora Subject:RE: Paxton 10 AOGCC 10-403 PTD 220-064 Submitted 06-03-22 - Sundry Application Date:Wednesday, June 8, 2022 10:17:00 AM Jake, Hilcorp is granted an additional 1-week extension for installing the SSSV. The Cap String installation Sundry is routing through AOGCC system and the 1-week extension is intended to provide time for Hilcorp to install the cap string before the SSSV test is due. It is noted that the Cap String prevents installation of the SSSV, per 20 AAC 25.265(d)(4). Surface Safety valve testing is still required per normal schedule. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Monday, June 6, 2022 1:38 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: Paxton 10 AOGCC 10-403 PTD 220-064 Submitted 06-03-22 - Sundry Application Hello Bryan, On 5/25/22 you allowed a two week extension to re-install the WR-SSSV, which would require it be in the ground by 6/8. We just submitted a cap string install sundry on Friday and included mention in it that the cap string would prohibit the reinstallation of the safety valve. Can we request an additional extension for the WR-SSSV with the intention to give you enough time to review the cap string sundry. We can install it, but then would be pulling it again if the cap string sundry is approved. Thanks for the guidance, Also I have requested the satellite maps for HVB-16 and will get them over to you. Jake From: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Sent: Friday, June 3, 2022 1:26 PM To: Donna Ambruz <dambruz@hilcorp.com> Cc: Jacob Flora <Jake.Flora@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Vanessa CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Hughes <vhughes@hilcorp.com> Subject: [EXTERNAL] RE: Paxton 10 AOGCC 10-403 PTD 220-064 Submitted 06-03-22 - Sundry Application Received for processing From: Donna Ambruz <dambruz@hilcorp.com> Sent: Friday, June 3, 2022 8:53 AM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Jacob Flora <Jake.Flora@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Vanessa Hughes <vhughes@hilcorp.com> Subject: Paxton 10 AOGCC 10-403 PTD 220-064 Submitted 06-03-22 - Sundry Application Application for Sundry Approval Thank you. Donna Ambruz Operations/Regulatory Tech KEN Asset Team Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 907.777.8305 - Direct dambruz@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. 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Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Jacob Flora Cc:Regg, James B (OGC) Subject:RE: 10-403 Paxton 10 PTD 220-064_Sundry_322-227_Approved_050422 Date:Wednesday, May 25, 2022 9:24:00 AM Jake, Hilcorp has approval for an extension of two weeks to install the SSSV in this well, per your request below. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Wednesday, May 25, 2022 8:10 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: 10-403 Paxton 10 PTD 220-064_Sundry_322-227_Approved_050422 Hi Bryan, This well has a WR-SSSV that we pulled on 5/10/22 for add perfs that were shot on 5/13/22. We saw an initial rate increase and now are seeing the rate drop off indicating water entry. In effort to diagnose the water and achieve stable flow, Hilcorp requests a two week extension to reinstall the WR-SSSV. I’m not 100% sure if this request is required per regulations given that we are still working on the well, but wanted to cover our bases and pass on what we are doing. Thanks for your time on this, Jake Jake Flora | Kenai Ops Engineer | Hilcorp Alaska | 720-988-5375 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please 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: 05/24/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL PAXTON 10 (PTD 220-064) PERF 05/13/2022 Please include current contact information if different from above. 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ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞĞŬůǇKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ WĂǆƚŽŶϭϬ ϱϬͲϭϯϯͲϮϬϲϵϭͲϬϬͲϬϬ ϮϮϬͲϬϲϰ ϬϰͬϯϬͬϮϬϮϭͲ&ƌŝĚĂǇ Wdt͕:^ǁŝƚŚĐƌĞǁƐ͘W/ĐŬƵƉƉĞƚƌƐŽĞĐŝŶũĞĐƚŽƌŚĞĂĚĂŶĚŵĂŬĞƵƉϰϬΖŽĨϱ͘ϱΗůƵďƌŝĐĂƚŽƌ͘ϭ͘ϳϱΗdĂŶĚz:K^D,ĂůƌĞĂĚǇ ŵĂĚĞƵƉǁŝƚŚĂĐƵƌƌĞŶƚƉƵůůͬƉƌĞƐƐƵƌĞƚĞƐƚ͘DĂŬĞƵƉzĞůůŽǁũĂĐŬĞƚ,ηϭϮ͘ϴϴΗKĞǆƚĞƌŶĂůƐůŝƉŽŝůĐŽŶŶĞĐƚŽƌ͕ƵĂůĨůĂƉƉĞƌ ĐŚĞĐŬǀĂůǀĞƐ͕>ŽŐĂŶŝŝũĂƌƐ͕d:,ǇĚ͘ĚŝƐĐŽŶŶĞĐƚ͕ĚƵĂůĐŝƌĐƐƵď͕ĂŶĚŵƵůĞƐŚŽĞŽǀĞƌƐŚŽƚůĂƚĐŚĨŽƌtZWĞǆƚĞƌŶĂůĨŝƐŚŶĞĐŬ͘ >ĞŶŐƚŚϭϱ͘ϯϱΖ͘^ƚĂďŽŶǁĞůů͘WdƐƚĂĐŬϮϱϬͬϯϱϬϬƉƐŝ͘ƐǁĂďϮϯ͘ϱƚƵƌŶƐ͕Z/,ǁŝƚŚƚŚĞŝŶƚĞŶƚƚŽůĂƚĐŚĂŶĚƉƵůůtZWĂƚϱϰϱϬΖ Z<͘WƌĞǀŝŽƵƐƐůŝĐŬůŝŶĞĂŶĚǁŝƌĞůŝŶĞƌƵŶƐƐŚŽǁĞĚƉŽƐƐŝďůĞŽďƐƚƌƵĐƚŝŽŶĂƚϭϴϬϬͲϮϯϬϬΖ͘^ƚĂĐŬϭϱŬĚŽǁŶĂƚϮϮϵϰΖdD͘WŝĐŬ ƵƉĐůĞĂŶ͘DĂŬĞŵƵůƚŝƉůĞĂƚƚĞŵƉƐĂŶĚϮĚŽǁŶũĂƌůŝĐŬƐ͘tĞŝŐŚƚŶĞǀĞƌďƌŽŬĞďĂĐŬ͘KďƐƚƌƵĐƚŝŽŶŝƐŚĂƌĚ͘WKK,ƚŽƐƵƌĨĂĐĞ͘Ăůů ŽƵƚz:K^ƐŚŽƉƚŽďƌŝŶŐŵŽƚŽƌŵŝůů͕ǀĞŶƚƵƌŝũƵŶŬďĂƐŬĞƚ͕ĂŶĚ'^ƐƉĞĂƌĂŶĚ&ŝƐŚŶĞĐŬĨŽƌƉŽƚĞŶƚŝĂůďĂƚĞƐƵď͘ĂƚƐƵƌĨĂĐĞ͕ƌŽƉ ƉƵůůŝŶŐƚŽŽůĂŶĚŵĂŬĞƵƉϮϳͬϴΗŵƵĚŵŽƚŽƌ͕ĂŶĚϮϳͬϴΗǀĞŶƚƌƵŝũƵŶŬďĂƐŬĞƚǁŝƚŚϰΖďĂƌƌĞů͘tĂǀĞƉƌŽĨŝůĞĂŶĚĐƵƚƌŝƚĞŽŶƚŚĞ ĞŶĚ͘^ƚĂďŽŶǁĞůů͘WdƐƚĂĐŬZ/,ǁŝƚŚϭƐƚsĞŶƚƵƌŝƌƵŶ͘dĂŐŐĞĚĂƚϮϭŬĚŽǁŶĂƚϮϮϵϴΖdD͘tŚŝůĞƐůĂĐŬĞĚŽĨĨĂƚƚĞŵƉƚƚŽďƌŝŶŐ ŵŽƚŽƌƵƉŝŶƚŽĂƐƚĂůůƚŽůŽĚŐĞĚĞďƌŝƐŝŶƚŽďĂƌƌĞůĞǆƚĞŶƐŝŽŶ͘WŝĐŬƵƉĐůĞĂŶ͘ƐƚĂďůŝƐŚĐŝƌĐƵůĂƚŝŽŶƉĂƌĂŵĞƚĞƌƐϭ͘ϲϱďďůƐͬŵŝŶ ϯϮϬϬƉƐŝĐŝƌĐƉƌĞƐƐƵƌĞ͘tŽƌŬŵŽƚŽƌĂŶĚǀĞŶƚƵƌŝ͘ϱƐƚĂůůƐĂƚϮϮϵϴ͘ϳΖ,ĂƌĚƐƚĂůůƐĂĐƚƐůŝŬĞŵĞƚĂůĚĞďƌŝƐ͘ƚƚĞŵƉƚϯĚŽǁŶũĂƌůŝĐŬƐ ĂĨƚĞƌƐƚĂůůƐĂŶĚŶŽŝŶĐƌĞĂƐĞŝŶĚĞƉƚŚŽƌƐƵďƐƚĂŶƚŝĂůŐĂŝŶŝŶǁĞŝŐŚƚ͘WKK,ƚŽƐƵƌĨĂĐĞ͘&ĞǁŐŽŽĚƐŝǌĞϯΗůŽŶŐƚŚŝŶĐŚƵŶŬƐŽĨ ƐƚĞĞů͘ƐŵĂůůĞƌƐŚĂǀŝŶŐƐƐƵƐƉĞŶĚĞĚŝŶƐƚŝĐŬǇĐůĂǇůŝŬĞƐƵďƐƚĂŶĐĞ͘Ϯ͘ϱĐƵƉƐĞƐƚŝŵĂƚĞĚĂŶĚϯŝŶĚŝǀŝĚƵĂůĐŚƵŶŬƐŽĨůĂƌŐĞƌƐŝǌĞƐƚĞĞů ƌĞĐŽǀĞƌĞĚ͘'ŽŽĚĂŵŽƵŶƚĨŽƌϱͲϴďďůƐĐŝƌĐƵůĂƚĞĚŽŶƌƵŶ͘Z/,ǁŝƚŚϮŶĚǀĞŶƚƵƌŝͬŵŽƚŽƌƌƵŶ͘dĂŐŐĞĚĂƚϮϮϵϵΖWŝĐŬƵƉĐůĞĂŶ ŽŶůŝŶĞϭ͘ϲďďůƐͬŵŝŶ͘ĨƚĞƌϯŚĂƌĚƐƚĂůůƐĂŶĚŽŶĞĚŽǁŶũĂƌůŝĐŬŶŽĚĞƉƚŚŐĂŝŶĞĚ͘WŝĐŬƵƉǁĂƐϱϬϬͲϴϬϬůďƐŽǀĞƌŶŽƌŵĂůƉŝĐŬƵƉ ǁĞŝŐŚƚ͘WKK,ƚŽƐƵƌĨĂĐĞĚƵĞƚŽƚŚĞǁĞŝŐŚƚĐŚĂŶŐĞ͘ZĞĐŽǀĞƌĞĚĂůĂƌŐĞϯΗůŽŶŐĐƵƌǀĞĚŵĞƚĂůĐŚƵŶŬ͕ϮďƌĂƐƐƉĞŶŶǇƐŝǌĞ ƉŝĞĐĞƐĂŶĚĂůĂƌŐĞƐƚĞĞůƐůŝǀĞƌ͘ZĞƐĞĂƌĐŚĚĞďƌŝƐǁŝƚŚ<ͲůŝŶĞ͘'ŽŽĚŝŶĚŝĐĂƚŝŽŶďŽƚƚŽŵƉĂƌƚŽĨKǁĞŶũĞƚĐƵƚ͕Z/,͕ϯƌĚ ǀĞŶƚƵƌŝͬŵŽƚŽƌƌƵŶ͘^ĞƚĚŽǁŶŽŶĚĞďƌŝƐĂƚϮϯϬϭ͘ϮΖdD͘WŝĐŬƵƉĐůĞĂŶƐƚĂƌƚŵŽƚŽƌǁŽƌŬ͘ ƚƚĞŵƉƚƚŽƚŝŵĞŵŝůůĂƚĂƚĞŶƚŚĂĨŽŽƚͬŵŝŶ͘'ŽŽĚŵŽƚŽƌǁŽƌŬ͘WƌĞƐƐƵƌĞďƌĞĂŬŝŶŐďĂĐŬĂŶĚǁĞŝŐŚƚŐĂŝŶƐĐŽƌƌĞƐƉŽŶĚ͘ϱ ƉĞƌŝŽĚŝĐƐƚĂůůƐǁŚŝůĞǁŽƌŬŝŶŐĚŽǁŶĨƌŽŵϮϯϬϭ͘ϮΖͲϮϯϯϳΖdD͘ŵŽƚŽƌǁŽƌŬƐƚŝůůŽďƐĞƌǀĞĚďƵƚǁĞŝŐŚƚƐƚŽƉƉĞĚďƌĞĂŬŝŶŐďĂĐŬ͘ ^ƵĚĚĞŶůŽƐƐŽĨZKW͘sĞŶƚƵƌŝďďůƉŽƐƐŝďůǇĨƵůů͘EŽĨůƵŝĚ,ƚŝƉ͘WKK,͘ƌĞĐŽǀĞƌĞĚƐŵĂůůĞƌďĂůůƐŽĨƉĂƌƌĂĨĨŝŶůŝŬĞŵĂƚĞƌŝĂůǁŝƚŚ ĐŚƵŶŬƐŽĨŵĞƚĂů͘'ŽŽĚĂŵŽƵŶƚŽĨŵĞĚĂůƐŚĂǀŝŶŐƐ͕ϭͬϮďƌĂƐƐƐŚĞĂƌƐĐƌĞǁƌĞĐŽǀĞƌĞĚ͘ŝƐĐƵƐƐĞĚĞĨĨĞĐƚŝǀĞŶĞƐƐŽĨǀĞŶƚƵƌŝ ǀĂĐƵƵŵĞĨĨĞĐƚŽŶĐĞŵĂƚĞƌŝĂůŝƐƌĞĐŽǀĞƌĞĚŝŶǁŝĐŬĞƌƐ͘dŚŝƐǁŽƵůĚŵĂŬĞƚŚĞǀĞŶƚƵƌŝũĞƚƐŶŽƚĨůŽǁĨůƵŝĚĚŽǁŶĂŶĚƵƉƚŚĞǀĞŶƚƵƌŝ͘ dƌĞĂƚŝŶŐĨůƵŝĚǁŽƵůĚďĞƚƵƌŶŝŶŐƚŚĞĐŽƌŶĞƌĂƚƚŚĞŶŽǌǌůĞƐϱΖĂďŽǀĞĞŶĚŽĨDƵůĞƐŚŽĞŽŶsĞŶƚƵƌŝ͘^ǁĂƉƚŽϯ͘ϳϱΗũƵŶŬŵŝůů͕Z/, ǁŝƚŚϱďůĂĚĞĚƌĞǀĞƌƐĞĐůƵƚĐŚũƵŶŬŵŝůůǁŝƚŚĐĂƌďŝĚĞďƵƚƚŽŶƐǀƐĐƵƚƌŝƚĞ͘dĂŐŐĞĚĂƚϮϯϯϳΖdD͘ŵƵůƚŝƉůĞƐƚĂůůƐ͘EŽƚĂďůĞƚŽ ŵĂŬĞŚŽůĞ͘ƚƚĞŵƉƚĞĚϭϬĚŽǁŶũĂƌůŝĐŬƐ͘ϭϱďďůŚŝŐŚǀŝƐĐŽƐŝƚǇƉŽůǇŵĞƌŐĞůƉŝůůĂƚ,͘DĂǆĚĞƉƚŚϮϯϯϳ͘ϴΖƚƚŝŵĞƐǁŚŝůĞ ĂƚƚĞŵƉƚŝŶŐƚŽĞŶŐĂŐĞĚĞďƌŝƐŵŝůůǁŽƵůĚƐƚĂůůŽƵƚůŽƐƚŚŽůĞϯƚŝŵĞƐ͘WKK,ƚŽƐƵƌĨĂĐĞǁŚŝůĞďĂĐŬƌĞĂŵŝŶŐǁŝƚŚŵŝůůĂŶĚĐŚĂƐŝŶŐ 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ƉƌĞƐƐƵƌĞŝƐŶŽƚĐŚĂŶŐŝŶŐǁŚĞŶƚĂŐŐŝŶŐŽŶŽďƐƚƌƵĐƚŝŽŶ͘WKK,͘>ĂǇĚŽǁŶzĞůůŽǁ:ĂĐŬĞƚ,ĂŶĚƐƚĂĐŬĚŽǁŶůƵďƌŝĐĂƚŽƌ͘/ŶƐƚĂůů ŶŝŐŚƚĐĂƉŽŶKWΖƐ͘>&E͘ ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ZŝŐϰϬϭͬdhͬ^> ϰͬϵͬϮϭ &ƵƚƵƌĞ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞĞŬůǇKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ WĂǆƚŽŶϭϬ ϱϬͲϭϯϯͲϮϬϲϵϭͲϬϬͲϬϬ ϮϮϬͲϬϲϰ ϬϱͬϬϯͬϮϬϮϭͲDŽŶĚĂǇ Wdt͕:^ǁŝƚŚĐƌĞǁƐ͘^ƚĂƌƚKWƚĞƐƚ͘Ϯϰ,ƌKWƚĞƐƚǁŝƚŶĞƐƐŶŽƚŝĨŝĐĂƚŝŽŶƐĞŶƚϱͬϮͬϮϭΛϭϲϭϬŚƌƐ͘tŝƚŶĞƐƐǁĂŝǀĞĚďǇ:ŝŵ ZĞŐŐϭϴϬϭŚƌƐ͘dĞƐƚƌĂŵƐĂŶĚǀĂůǀĞƐϮϱϬͬϯϱϬϬƉƐŝĂŶĚĐŚĂƌƚǁŝƚŚ,ŽƚŽŝůƚƌƵĐŬĂĐƋƵŝƐŝƚŝŽŶƐǇƐƚĞŵ͘KWƚĞƐƚ ĐŽŵƉůĞƚĞ͘^ƚĂĐŬƵƉůƵďƌŝĐĂƚŽƌ͘DĂŬĞƵƉƵƌŶƐŚŽĞ,͘^ƚĂďŽŶǁĞůů͘WdůƵďƌŝĐĂƚŽƌϮϱϬͬϯϱϬϬƉƐŝ͘Z/,͘WĞƌĨŽƌŵǁĞŝŐŚƚ ĐŚĞĐŬĂƚϱϰϬϬΖ͘WŝĐŬƵƉϭϮŬǁĞŝŐŚƚ͘ƌǇƚĂŐĂƚϱϰϰϴ͘ϵΖ͘Ͳϭϵ<ĚŽǁŶ͘WŝĐŬƵƉĐůĞĂŶϭϮŬ͘KŶůŝŶĞĚŽǁŶĐŽŝůĞƐƚĂďůŝƐŚ ƉĂƌĂŵĞƚĞƌƐϯϭϬϬƉƐŝΛϭ͘ϴďďůƐͬŵŝŶ͘ƚƚĞŵƉƚƚŽŵĂŬĞŚŽůĞ͘DĂŬĞŝƚĚŽǁŶƚŽϱϰϱϬΖ&ĞǁƌĂŶĚŽŵƐƚĂůůƐ͘ƚϱϰϱϬΖĐŽƵůĚ ŶŽƚŐĞƚŵŽƚŽƌǁŽƌŬŽƌǁĞŝŐŚƚƚŽďƌĞĂŬďĂĐŬ͘WKK,͘ƚƐƵƌĨĂĐĞ͘ƌĞĂŬĚŽǁŶďƵƌŶƐŚŽĞ͘DĂŬĞƵƉsĞŶƚƵƌŝũƵŶŬďĂƐŬĞƚ͘^ƚĂď ŽŶǁĞůů͘WdƐƚĂĐŬZ/,͘EŽŝŶĚŝĐĂƚŝŽŶŽĨďƵƌŶƐŚŽĞŐĞƚƚŝŶŐŽǀĞƌĨŝƐŚŶĞĐŬ͘ϭͬϰΗƐƚĞĞůƚĂƚƚůĞƚĂůĞƐƐƚŝůůŝŶƚĂĐƚ͘Z/,ǁĞŝŐŚƚϰϱϬϬΖ ŝƐͲϮϱϬϬůďƐ͘ƌǇƚĂŐĂƚϱϰϱϬ͘ϱΖ͘ƐƚĂďůŝƐŚĐŝƌĐƵůĂƚŝŽŶϮϳϬϬƉƐŝ͕ΛϮďďůƐͬŵŝŶϱϰϱϭ͘ϭΖΛϰϯϱϬƉƐŝƐƚĂůů͘DĞƚĂůĐŚƵŶŬ ŵŽǀŝŶŐĂƌŽƵŶĚƐƚĂůůĂƚϱϰϰϵ͘ϴΖ͘ƐƚĂůůĂƚϱϰϰϵ͘ϱ͕ϱϰϱϬ͘ϭ͘,ĂǀĞŐŽŽĚŵŽƚŽƌǁŽƌŬĂŶĚǁĞŝŐŚƚďƌĞĂŬďĂĐŬĨƌŽŵϱϰϱϭ͘ϮΖͲ ϱϰϱϭ͘ϴΖ͘WKK,ƚŽƐƵƌĨĂĐĞ͘dĂŐŐĞĚƵƉ͘>ĂƌŐĞŵĞƚĂůĐŚƵŶŬĂŶĚĂĚŽǌĞŶƐŵĂůůĞƌŵĞƚĂůƐůŝǀĞƌƐŝŶũƵŶŬďĂƐŬĞƚ͘ĂƐŬĞƚƉĂĐŬĞĚ ŽĨĨǁŝƚŚĨŽƌŵĂƚŝŽŶƐĂŶĚ͘ ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ZŝŐϰϬϭͬdhͬ^> ϰͬϵͬϮϭ &ƵƚƵƌĞ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞĞŬůǇKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ WĂǆƚŽŶϭϬ ϱϬͲϭϯϯͲϮϬϲϵϭͲϬϬͲϬϬ ϮϮϬͲϬϲϰ ϬϱͬϬϰͬϮϬϮϭͲdƵĞƐĚĂǇ Wdt͕:^ǁŝƚŚWĞƚƌŽƐƉĞĐĐŽŝů͕ĐƌƵǌĐƌĂŶĞŽƉĞƌĂƚŽƌ͕z:K^ƚŚƌƵƚƵďŝŶŐƚŽŽůƐƉĞĐŝĂůŝƐƚ͕ĂŶĚ,ŝůĐŽƌƉtĞůůƐŝƚĞZĞƉ͘WŝĐŬŝŶũĞĐƚŽƌŚĞĂĚ ĂŶĚƐƚĂĐŬƵƉϰϬΖŽĨůƵďƌŝĐĂƚŽƌ͘DĂŬĞƵƉD,͘WƌĞƐƐƵƌĞƚĞƐƚϮϱϬͬϯϱϬϬƉƐŝ͘ ,͗Ϯ͘ϴϴǆƚĐŽŝůĐŽŶŶĞĐƚŽƌ͕Ϯ͘ϴϴ&s͕Ϯ͘ϴϴΗ>ŽŐĂŶŝŝũĂƌƐ͕Ϯ͘ϴϴΗKd:ĚŝƐĐŽ;ϯͬϰΗďĂůůͿ͕Ϯ͘ϴϴΗĚƵĂůĐŝƌĐƐƵď͕Ϯ͘ϴϳϱΗDƵĚĚ DŽƚŽƌ͕Ϯ͘ϴϴΗKǆŽǀĞƌϯ͘ϳϱΗĚƌŝǀĞƐƵďĂŶĚϯ͘ϳϱΗďƵƌŶƐŚŽĞǁŝƚŚĐƵƚƌŝƚĞĂŶĚǁĂǀĞĨŝŶŝƐŚ͘,ϭϱ͘ϱϱΖ͘^ƚĂďŽŶǁĞůů͘WdƐƚĂĐŬ ϮϱϬͬϯϱϬϬƉƐŝ͘ůĞĞĚĚŽǁŶ͘ŝƌĐƵůĂƚĞϮďďůƐͬŵŝŶƚĞƐƚŵŽƚŽƌ͘KƉĞŶŵĂƐƚĞƌĂŶĚƐǁĂďϮϯ͘ϱƚƵƌŶƐ͘Z/,͘t,WϬƉƐŝ͕/ϬƉƐŝ͘ tĞůůďŽƌĞĨůƵŝĚƉĂĐŬĞĚ͘ϱϰϬϬΖtĞŝŐŚƚĐŚĞĐŬϭϭ͘ϱ<͕Z/,ĨŽƌĚƌǇƚĂŐĂƚϱϰϱϬ͘ϱdD͘WŝĐŬƵƉĂŶĚĞƐƚĂďůŝƐŚĐŝƌĐƵůĂƚŝŽŶϮ͘Ϯ ďďůƐͬŵŝŶϯϮϬϬƉƐŝĐŝƌĐƉƌĞƐƐƵƌĞ͘Z/,ƚŽϱϰϱϬ͘ϱΖĂŶĚƐƚĂƌƚƚĂŬŝŶŐƐŵĂůů͘ϭϬΖďŝƚĞƐ͘>ŝŐŚƚŵŽƚŽƌǁŽƌŬĨŽƌŵϱϰϱϬ͘ϴΖdDƚŽ &ŝƌƐƚƐƚĂůůĂƚϱϰϱϭ͘ϱΖdD͘^ŚƵƚĚŽǁŶƉƵŵƉƐ͘WŝĐŬƵƉϭϵ<͘ϴ<ŽǀĞƌƐƚƌŝŶŐǁĞŝŐŚƚ͘WŽƐƐŝďůĞũĂƌĨŝƌĞƚŽƌĞůĞĂƐĞĨƌŽŵŚĞĂǀǇ ŽǀĞƌƉƵůů͘ŽŶůŝŶĞǁŝƚŚƉƵŵƉϮ͘ϮďďůƐͬŵŝŶ͘WhKK,ϭϬϬΖ͘Z/,ĂŶĚƐƚĂƌƚĞŶŐĂŐŝŶŐŵĞƚĂůĚĞďƌŝƐĂƚϱϰϱϭ͘ϱΖ͘^ŚĂƌƉƐƉŝŬĞƐŝŶĐŝƌĐ ƉƌĞƐƐƵƌĞďƵƚŐŽŽĚŵŽƚŽƌǁŽƌŬƵŶƚŝůŚĂƌĚƐƚĂůůĂƚϱϰϱϮ͘ϳΖdD͘WhϮϮ<͕ϭϬ<ŽǀĞƌƐƚƌŝŶŐǁĞŝŐŚƚ͘WƌĞƐƐƵƌĞƵƉŽŶĐŽŝůĂŶĚƐƚĂůů ƉƵŵƉ͘^ůĂĐŬŽĨĨǁĞŝŐŚƚ͘ŽŝůĨƌĞĞĨƌŽŵŽǀĞƌƉƵůů͘ϮŵŽƌĞƐƚĂůůƐĂƚϱϰϱϮ͘ϯΖdDĂŶĚϱϰϱϮ͘ϱΖdD͘/ŶĚŝĐĂƚŝŽŶŽĨ ŵĞƚĂů͕ŝƐĐƵƐƐĞĚǁŝƚŚƚŽǁŶ͘,ͬďƵƌŶƐŚŽĞĂƐƐĞŵďůǇĂĐƚŝŶŐůŝŬĞĞŶŐĂŐŝŶŐůŽŽƐĞŵĞƚĂůĐŚƵŶŬƐ͘WKK,ƚŽƐƵƌĨĂĐĞƚŽƐǁĂƉĨŽƌ ǀĞŶƚƵƌŝũƵŶŬďĂƐŬĞƚƌƵŶ͘dĂŐŐĞĚƵƉ͘ůŽƐĞŵĂƐƚĞƌƐǁĂď͘WŽƉŽĨĨǁĞůů͘ƌĞĂŬĚŽǁŶďƵƌŶƐŚŽĞ͘ϮƚĂƚƚůĞƚĂůĞŝŶĚŝĐĂƚŽƌƐƐƚŝůů ŝŶƚĂĐƚ͘WĂŝŶƚŝŶƐŝĚĞďƵƌŶƐŚŽĞ͘EŽŝŶĚŝĐĂƚŝŽŶƐŽĨĞŶŐĂŐĞŵĞŶƚŽĨĨŝƐŚŶĞĐŬƉƌŽĨŝůĞ͘DhǀĞŶƚƵƌŝƵŶĚĞƌŵŽƚŽƌ͘^ƚĂďŽŶǁĞůů͘Wd ƐƚĂĐŬϮϱϬͬϯϱϬϬ͘Z/,,ĐŚĂŶŐĞĂƚďŽƚƚŽŵŽĨŵŽƚŽƌ͘/ŶƐƚĂůůĞĚϯ͘ϭϯΗKǀĞŶƚƵƌŝũƵŶŬďĂƐŬĞƚǁŝƚŚĐƵƚƌŝƚĞ͘,ůĞŶŐƚŚ ϯϭ͘ϳϲΖ͘tĞŝŐŚƚĐŚĞĐŬĂƚϰϮϬϬΖĐůĞĂŶϭϭ<͘Z/,ǁĞŝŐŚƚͲϮϱϬϬůďƐ͘KŶůŝŶĞǁŝƚŚǀĞŶƚƵƌŝĂƚϮ͘ϮďďůƐͬŵŝŶϯϮϬϬƉƐŝ͘tĂƐŚĚŽǁŶ Ăƚϱϰϱϰ͘ϰΖƐƚĂƌƚƐƚĂĐŬŝŶŐǁĞŝŐŚƚ͘EŽŝŶĐƌĞĂƐĞŝŶŵŽƚŽƌǁŽƌŬ͘tŽƌŬĚŽǁŶĂƚĂƚĞŶƚŚŽĨĂĨŽŽƚ͘tĞŝŐŚƚŝƐĐŽŶƚŝŶƵŝŶŐƚŽĨĂůůŽĨĨ ĨƌŽŵZ/,ǁĞŝŐŚƚƚŽͲϲ<ĚŽǁŶĂŶĚŶŽƚĂďůĞƚŽŽďƚĂŝŶƐŝŐŶƐŽĨŵŽƚŽƌǁŽƌŬ͘WhϱϬΖƚƚĞŵƉƚƚŽZ/,ĂƚϮϱĨƚͬŵŝŶƚŽĞƐƚĂďůŝƐŚ ŵŽƚŽƌǁŽƌŬ͘tĞŝŐŚƚƐƚĂĐŬŝŶŐĂƚƐĂŵĞĚĞƉƚŚŽĨϱϰϱϰ͘ϰΖ͘tĞŝŐŚƚŶŽƚďƌĞĂŬŝŶŐďĂĐŬ͘WKK,ƚŽƐƵƌĨĂĐĞ͘dĂŐŐĞĚƵƉ͘ůŽƐĞ ŵĂƐƚĞƌƐǁĂď͘WŽƉŽĨĨǁĞůů͘KƵƚƐŝĚĞĐŝƌĐƵŵĨĞƌĞŶĐĞŽŶǀĞŶƚƵƌŝďƵƌŶƐŚŽĞƐŚŽǁƐƐŝŐŶŝĨŝĐĂŶƚƐŝŐŶƐŽĨǁĞĂƌ͘ƵƚƌŝƚĞŵĂƚĞƌŝĂů ƌĞŵŽǀĞĚ͘DŝůůďŽĚǇĞǆƉŽƐĞĚĂŶĚƐŵŽŽƚŚ͘sĞŶƚƵƌŝǇŝĞůĚƐϭĐƵƉŽĨŵĂƚĞƌŝĂů͘ŵĞƚĂůƐŚĂǀŝŶŐƐ͕ŵĞƚĂůƐůŝǀĞƌƐĂŶĚĨƌĂĐƐĂŶĚ ƉƌŽƉƉĂŶƚ͘ŝƐĐƵƐƐǁŝƚŚƚŽǁŶ͘^ǁĂƉďĂĐŬƚŽƵƌŶƐŚŽĞ,͘^ƚĂďŽŶǁĞůů͘WdƐƚĂĐŬϮϱϬͬϯϱϬϬ͘Z/,͘ϱϰϬϬΖǁĞŝŐŚƚĐŚĞĐŬ ϭϭŬ͘Z/,ǁĞŝŐŚƚͲϯϱϬϬůďƐ͘ƌǇƚĂŐϱϰϱϰ͘ϰΖdD͘WƵƚŽĞƐƚĂďůŝƐŚĐŝƌĐƌĂƚĞƐϮ͘ϮďďůͬŵŝŶϯϮϬϬƉƐŝ͘ ĂĐŚWhƉƵůůŝŶŐŚĞĂǀǇ͘ƚƚĞŵƉƚZ/,ǁŝƚŚŽƵƚƉƵŵƉŝŶŐ͘WĞƌĨŽƌŵĚŽǁŶũĂƌůŝĐŬ͘WhϮϱ<ŽǀĞƌƐƚƌŝŶŐǁĞŝŐŚƚ͘tŽƌŬĚŽǁŶǁŝƚŚĐŝƌĐ ƉƌĞƐƐƵƌĞĂŶĚƌĞůĞĂƐĞĨƌŽŵŽǀĞƌƉƵůů͘&ŝŶĂůĂƚƚĞŵƉƚǁŝƚŚďƵƌŶƐŚŽĞĂƚϱ͕ϰϱϱΖdDƐƚĂůůĞĚŵŽƚŽƌ͘WhϮϴ<ŽǀĞƌƐƚƌŝŶŐǁĞŝŐŚƚ͘ 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ϱϰϱϰΖZ<tͬdWKK,KK,ͬt^D>>ϰΗ>KE'yϭͬϴΗDd>W/ Z/,ͬtKt^WZ/E'EdZ>/Zͬtϯ͘ϳϱΗ>/dKϱϰϱϰΖZ<tͬdWKK,KK,ͬt/DWZ^^/KEK&KDWK^/d^EKE>z EKDd>DZ<^KZ&/^,/E'E</DWZ^^/KE^ Z/,ͬtϯΗyϳΖWhDW//>ZdKϱϰϱϰΖZ<tͬdKK,ͬtϯΖK&KDWK^/d^E/E/>Z^K>/^EKDd>DZ<^KE dD͕Z/,ͬt^DdKϱϰϯϴΖ^>D;ϱϰϱϲΖZ<ͿtͬdWKK,KK,ͬtDd>,hE<ϰΗ>KE'yϭΗt/^dh</E/>ZdD EK^E KK,>zKtE&KZE/',d^hZZEt>>, >s>Kd/KE ZZ/sdWt>^,KW ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ZŝŐϰϬϭͬdhͬ^> ϰͬϵͬϮϭ &ƵƚƵƌĞ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞĞŬůǇKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ WĂǆƚŽŶϭϬ ϱϬͲϭϯϯͲϮϬϲϵϭͲϬϬͲϬϬ ϮϮϬͲϬϲϰ ϬϱͬϬϴͬϮϬϮϭͲ^ĂƚƵƌĚĂǇ ZZ/sdWt>^,KW ZZ/sKE>Kd/KEKWZD/d:^d'^DZ/'hW^>/<>/EZW<^dh&&/E'KyWͬd>hϭϱϬϬW^^ Z/,ͬtϯΗyϳΖWhDW/>ZdKϱϰϯϴΖ^>D;ϱϰϱϲΖZ<ͿtͬdWKK,KK,ͬtϮΖK&^E Z/,ͬt^DdK^DtͬdWKK,KK,ͬt,>&/^>KK<^>/<dDK&ϮEhddZDK&Z^^ Z/,ͬt^DdK^DtͬdWKK,KK,ͬt^D>>Dd>,hE<E^D>>W/K&Z^^ϯΖK&^E͕Z/,ͬt^DdK ^DtͬdWKK,KK,ͬtϭ,hE<K&Dd>ϯΗyϮΗEK^E Z/,ͬt^DdKϱϰϯϵΖ^>DtͬdWKK,KK,ͬt:h^d&>h/Dd>DZ<^KE/>ZdD Z/,ͬtKt^WZ/E'EdZ>/Zͬtϯ͘ϲϱΗD'EddKϱϰϯϵΖ^>D;ϱϰϱϳΖZ<Ϳtͬd'd>Z'KsZWh>>tͬd&ZWKK, KK,ͬt EKd,/E'hdDZ<^KE^/K&D'Ed;^h^WdKd,Z,>&K&Z^^/^ZKsZZ>/Z^dh<^/ 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Η<ΗǀĂůǀĞƌĞĐŽǀĞƌĞĚ͘,ŽƚƐŚŽƚΗ<ΗǀĂůǀĞƚŽWŽůůĂƌĚĨŽƌƐĞƚƵƉ͘KƉĞŶƚƌĞĞǀĂůǀĞƐ͘&ůŽǁǁĞůů͘ƌŽƉƐŽĂƉƐƚŝĐŬƐ͘ĂůůĨƌŽŵWŽůůĂƌĚ ƐŚŽƉ͘Η<ΗǀĂůǀĞŶŽƚĨƵŶĐƟŽŶŝŶŐ͘>ŝƋƵŝĚůĞĂŬŝŶŐĨƌŽŵƐĞĂůƐ͘ Z/,ǁͬϭϬΖyϭͲϳͬϴΗǁĞŝŐŚƚďĂƌͬϭвΗũĂƌƐͬϭϭͲϳͬϴΗůŽŶŐƐƉĂŶŐƐͬϭ͘ϳϱΗƐĂŵƉůĞďĂŝůĞƌ͘dĂŐŝŶƚƌĞĞ͘^ŽĂƉƐƚŝĐŬƐĚŝĚŶŽƚĨĂůů͘ ůĞĂƌƚŽŽůƐĂŶĚůƵďƌŝĐĂƚŽƌŽĨƐŽĂƉƐƟĐŬƐ͘Z/,ǁͬϭϬΖyϭͲϳͬϴΗǁĞŝŐŚƚďĂƌͬϭвΗũĂƌƐͬϭͲϳͬϴΗůŽŶŐƐƉĂŶŐƐͬϭ͘ϳϱΗƐĂŵƉůĞďĂŝůĞƌ͘ dĂŐΛϵϳϬΖ͘^ĐŚĞŵĂƟĐƐŚŽǁƐƉĂƚĐŚΛϵϵϳΖZ<͘ƩĞŵƉƚƚŽZ/,ϭϮy͘ĂŶŶŽƚŐĞƚƉĂƐƐĞĚŽďƐƚƌƵĐƟŽŶ͘WKK,͘ Z/,ǁͬϭϬΖyϭ͍ΗǁĞŝŐŚƚďĂƌͬϭвΗũĂƌƐͬϭͲϳͬϴΗůŽŶŐƐƉĂŶŐƐͬϮ͘ϮϲΗƐǁĞĚŐŝŶŐƚŽŽů͘ dĂŐΛϱϲϬϲ^>͘ϱϲϮϯ͘ϲZ<͘WĞƌĨƐŽƉĞŶ͘WKK,͘Z^>͘ ϬϱͬϮϮͬϮϬϮϭͲ^ĂƚƵƌĚĂǇ ZZ/sKE>Kd/KE͕^WKdYh/DEd͕/E/d/dWZD/d͘'/EZ/'hW͕D<hWW͕Z/'hWt/Z>/E͘ Z/'hWss/KdKK>^dZ/E'E&hEd/KEd^d͘Wd/^'KK͕ϮϱϬW^/>Kt͕ϭϬϬϬW^/,/',͘KWE^t͕Z/,t/d, ,ͬtͬsDZ;K>Ϯϭ&d͕Ϯ͘ϳϱ/EK͕ϮϯϬ>͕ϭ/E&EͿ͘ ^>Kt>zZhEKtEW^^d,ZKh',^^^s͕ZhEKtEs/tW^^t/d,^^^s>K^͘/Es^d/'d&>WWZt/d, ^/s/t͘Wh>><Kss>sE>K^/d͘td,s>s><z&>WWZt,/>>/E'K&&t>>, WZ^^hZ͘ &dZ>KK</E'dd,s>sKWEE>K^&KZ^sZ>W^^^͕/^/KEDdKWKK, KE^hZ&͕>K^^t͕>KtE>hZ/dKZ '/EZ/'KtE͘/^^^D>sDZ͕Z/'KtEWEt/Z>/E͘&/E/^,W</E'hWYh/WDEd͕>K^Khd WZD/d͘ ůŽŶŐƐƉĂŶŐƐͬϰЪΗyͲůŝŶĞƌƵŶŶŝŶŐƚŽŽůĐͬǁϯ͘ϴϭϯΗyEůŽĐŬǁͬΗ<Η ǀĂůǀĞ͘^ĞƚyͲůŽĐŬΛϭϰϮΖďǇŚĂŶĚ͘ Η<ΗǀĂůǀĞƌĞĐŽǀĞƌĞĚ͘,ŽƚƐŚŽƚΗ<ΗǀĂůǀĞƚŽWŽůůĂƌĚĨŽƌƐĞƚƵƉ͘KƉĞŶƚƌĞĞǀĂůǀĞƐ͘&ůŽǁǁĞůů͘ƌŽƉƐŽĂƉƐƚŝĐŬƐ͘ĂůůĨƌŽŵWŽůůĂƌĚ ƐŚŽƉ͘Η<ΗǀĂůǀĞŶŽƚĨƵŶĐƟŽŶŝŶŐ͘ End Sundry 321-081, begin Sundry 321-256 bjm ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ZŝŐϰϬϭͬdhͬ^> ϰͬϵͬϮϭ &ƵƚƵƌĞ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞĞŬůǇKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ WĂǆƚŽŶϭϬ ϱϬͲϭϯϯͲϮϬϲϵϭͲϬϬͲϬϬ ϮϮϬͲϬϲϰ Zh^>ƵŶŝƚ͘^ƚĂďůƵďƌŝĐĂƚŽƌŽŶǁĞůů͘KƉĞŶƚƌĞĞǀĂůǀĞƐ͘dďŐƉƌĞƐƐƵƌĞΛϵϲƉƐŝ͘^ŚƵƚŝŶĨůŽǁůŝŶĞ͘dďŐƉƌĞƐƐƵƌĞďƵŝůĚƐƚŽϯϯϬ ƉƐŝ͘ Z/,ǁͬϭϬΖyϭͲϳͬϴΗǁĞŝŐŚƚďĂƌͬϭͲϳͬϴΗůŽŶŐƐƉĂŶŐƐͬϰЪΗyͲůŝŶĞƌƵŶŶŝŶŐƚŽŽůĐͬǁϯ͘ϴϭΗyͲůŽĐŬǁͬΗ<ΗǀĂůǀĞ͘ ^ĞƚyͲůŽĐŬΛϭϰϮ^>͘WKK,͘ dĞƐƚΗ<ΗǀĂůǀĞ͘'ŽŽĚƚĞƐƚ͘dĞƐƚƌĂĐŬƉƌĞƐƐƵƌĞƐ͗KƉĞŶŝŶŐĂƚϮϭϬƉƐŝ͕ĐůŽƐŝŶŐĂƚϭϯϬƉƐŝ͘ Z^> ϭϭͬϭϲͬϮϬϮϭͲdƵĞƐĚĂǇ ,ŽůĚddǁŝƚŚĐƌĞǁĂďŽƵƚƌŝŐŐŝŶŐŝŶ^ͬ>ĞƋƵŝƉŵĞŶƚĂŶĚũŽďƚĂƐŬ͘ZŝŐŝŶ^ͬ>ĞƋƵŝƉŵĞŶƚ͕ZŝŐƵƉ͘ϭϮϱΗ^ůŝĐŬůŝŶĞǁŝƚŚϰϬΖŽĨϰϭͬϮΗ >ƵďƌŝĐĂƚŽƌĐͬǁϰϭͬϮΗdŽŽůdƌĂƉĐͬǁϰϭͬϮΗdƌŝƉůĞǁŝƌĞůŝŶĞǀĂůǀĞ͘WƌĞƐƐƵƌĞƚĞƐƚƚŽϯϬϬϬƉƐŝ͕ĂĨƚĞƌƐƵĐĐĞƐĨƵůƚĞƐƚůĞƚŵĞŶƚĂŶŽů ďůĞĞĚďĂĐŬƚŽƚƌŝƉůĞǆ͘Z/,ǁŝƚŚϰ͘ϱΗ'^ĐͬǁϭϱΖϭͬϳϴƚŽŽůƐƚƌŝŶŐ͕ϭϳͬϴ>^^ƚĂŐ<ǀĂůǀĞΛϭϰϭΖ<ũĂƌƵƉϮǆĐŽŵĞƐĨƌĞĞWKK,ǁŝƚŚ ǀĂůǀĞ͘Z/,ǁŝƚŚϯ͘ϴϱΗŐĂƵŐĞĐƵƚƚĞƌĐͬǁϭϱΖϭͬϳϴƚŽŽůƐƚƌŝŶŐ͕ϭϳͬϴ>^^ƚĂŐdZ^sΛϭϰϭΖ<͕WKK,͘Z/,ǁŝƚŚϯ͘ϴΗƐĐƌĂƉƉĞƌͬĐƵƚƚĞƌ ĐͬǁϭϱΖϭͬϳϴƚŽŽůƐƚƌŝŶŐ͕ϭϳͬϴ>^^ƚĂŐƚŽƉŽĨdZ^sΛϭϰϭΖ<͕WKK,͘Z/,ǁŝƚŚϯ͘ϴΗďƌƵƐŚĐͬǁϯ͘ϳΗŐĂƵŐĞĐƵƚƚĞƌďĞůŽǁǁŝƚŚϭϱΖ ϭͬϳϴƚŽŽůƐƚƌŝŶŐ͕ϭϳͬϴ>^^ƚĂŐĂŶĚďƌƵƐŚdZ^sΛϭϰϭΖ<͕ƚƌĂǀĞůďĞůŽǁdZ^sϰΖΛϭϰϱΖ͕WKK,͘Z/,ǁŝƚŚůŽĐŬŽƵƚƚŽŽůĨŽƌE dZ^sƉĞƌĨŽƌŵƉƵůůǁĞŝŐŚƚΛϭϯϬΖͲϰϬϴůďƐǁŝƚŚůŽĐŬŽƵƚƚŽŽů͕ƚĂƉĚŽǁŶϮǆƚŽƐĞƚĂŶĚůŽĐĂƚĞŶŝƉƉůĞƉƌŽĨŝůĞ͕ũĂƌĚŽǁŶŚĂƌĚϮǆƚŽ ƐĞƚŝŶƐŝĚĞƉƌŽĨŝůĞ͘WƵůůϰϬϬůďƐŽǀĞƌƐƚƌŝŶŐǁĞŝŐŚƚĂŶĚƐŝƚĨŽƌϱŵŝŶƐƚŽĐŽŶĨŝƌŵůĂƚĐŚŝŶƉƌŽĨŝůĞ͘'ŽŽĚƚĞƐƚ͕ƐůĂĐŬŽĨĨƚŽŽůƐƚƌŝŶŐ ǁĞŝŐŚƚĂŶĚƐƚĂŶĚďǇĨŽƌĨůƵŝĚĨŽƌƉƵŵƉŝŶŐƉƌŽĐĞĚƵƌĞƐ͕ϭϭ͗ϰϱĂŵƐƚĂƌƚƉƵŵƉŝŶŐĨůƵŝĚƚŽƉƌĞƐƐƵƌĞƵƉŽŶůŽĐŬŽƵƚƚŽŽů͕ƉƵŵƉ Ϯ͘ϱďďůƚŽƉƌĞƐƐƵƌĞƵƉƚŽϭϯϬϬůďƐ͕ďǇƉĂƐƐǀĂůǀĞŽƉĞŶƐŝŶůŽĐŬŽƵƚƚŽŽůĂŶĚƉƌĞƐƐƵƌĞďůĞĞĚƐďĂĐŬ͘:ĂƌĚŽǁŶϱϬǆƚŽĐŽŶĨŝƌŵ ƐĞƚƐĐƌĞǁƐĂƌĞƐŚĞĂƌĞĚĂŶĚĐŽƌĞƌŽĚƌĞůĞĂƐĞΖƐ͕ũĂƌƵƉϲǆƚŽŽůĐŽŵĞƐĨƌĞĞ͕WKK,͘Z/,ǁŝƚŚϯ͘ϳΗŐĂƵŐĞĐƵƚƚĞƌƚŽĐŽŶĨŝƌŵǀĂůǀĞŝƐ ůŽĐŬĞĚŽƉĞŶ͕ǁŝƚŚǀĂůǀĞƉƵŵƉĞĚƵƉǁĞŚĂĚŶŽƉƌŽďůĞŵŐŽŝŶŐĚŽǁŶƚŚƌŽƵŐŚ͕ĂĨƚĞƌƌĞůĞĂƐŝŶŐƉƌĞƐƐƵƌĞŽŶƚŚĞǀĂůǀĞǁĞƌĂŶ ďĂĐŬĚŽǁŶĂŶĚƚĂŐŐĞĚƚŚĞĐůŽƐĞĚǀĂůǀĞ͘ZĞƉĞĂƚƚŚĞƐĂŵĞƐƚĞƉƐĂƐĂďŽǀĞǁŝƚŚŽƉĞŶŝŶŐĂŶĚĐůŽƐŝŶŐƚŚĞǀĂůǀĞƚŽƐĞĞŝĨĂŶǇ ĐŚĂŶŐĞƐŽĐĐƵƌĞ͘EŽůƵĐŬǁŝƚŚĐǇĐůŝŶŐƚŚĞǀĂůǀĞĂĨƚĞƌϱĂƚƚĞŵƉƐ͕ƚŚĞǀĂůǀĞĐŽŶƚŝŶƵĞƐƚŽĐůŽƐĞĂĨƚĞƌƌĞůĞĂƐŝŶŐƉƌĞƐƐƵƌĞ WKK,͘DĂŬĞĐĂůůƐƚŽƚŚĞĂƉƉƌŽƉƌŝĂƚĞŵĂŶĂŐĞŵĞŶƚĂďŽƵƚƉŽƐƐŝďůǇƌĞƌƵŶŶŝŶŐůŽĐŬŽƵƚƚŽŽů͕ŐŝǀĞŶǁŽƌĚƚŚĂƚƚŚĞƚŽŽůǁŽƵůĚŚĂǀĞ ƚŽďĞďƌŽƵŐŚƚŝŶĂŶĚƚŽƌĞĚŽǁŶƚŽĐůĞĂŶĂŶĚƐĞƚƵƉĨŽƌƌĞƌƵŶŶŝŶŐ͘>ĂǇĚŽǁŶ^ͬ>ĞƋƵŝƉŵĞŶƚĂŶĚůĞĂǀĞĞƋƵŝƉŵĞŶƚŽŶůŽĐĂƟŽŶ ĂǁĂŝƚŝŶŐŝŶĨŽƌŵĂƚŝŽŶĂďŽƵƚŵŽǀŝŶŐĨŽƌǁĂƌĚ͘ ϬϲͬϬϲͬϮϬϮϭͲ^ƵŶĚĂǇ ǀĂůǀĞĐŽŶƚŝŶƵĞƐƚŽĐůŽƐĞĂĨƚĞƌƌĞůĞĂƐŝŶŐƉƌĞƐƐƵƌ Z/,ǁͬϭϬΖyϭͲϳͬϴΗǁĞŝŐŚƚďĂƌͬϭͲϳͬϴΗůŽŶŐƐƉĂŶŐƐͬϰЪΗyͲůŝŶĞƌƵŶŶŝŶŐƚŽŽůĐͬǁϯ͘ϴϭΗyͲůŽĐŬǁͬΗ<ΗǀĂůǀĞ͘ dZ^sƉĞƌĨŽƌŵƉƵůůǁĞŝŐŚƚΛϭϯϬΖͲϰϬϴůďƐǁŝƚŚůŽĐŬŽƵƚƚŽŽů͕ƚĂƉĚŽǁŶϮǆƚŽƐĞƚĂŶĚůŽĐĂƚĞŶŝƉƉůĞƉƌŽĨŝůĞ͕ũĂƌĚŽǁŶŚĂƌĚϮǆƚŽ ƐĞƚŝŶƐŝĚĞƉƌŽĨŝůĞ͘W ^ĞƚyͲůŽĐŬΛϭϰϮ^> ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ZŝŐϰϬϭͬdhͬ^> ϰͬϵͬϮϭ &ƵƚƵƌĞ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞĞŬůǇKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ WĂǆƚŽŶϭϬ ϱϬͲϭϯϯͲϮϬϲϵϭͲϬϬͲϬϬ ϮϮϬͲϬϲϰ ϭϭͬϭϴͬϮϬϮϭͲdŚƵƌƐĚĂǇ ,ŽůĚddǁŝƚŚĐƌĞǁĂďŽƵƚƌŝŐŐŝŶŐŝŶ^ͬ>ĞƋƵŝƉŵĞŶƚĂŶĚũŽďƚĂƐŬ͕ŐĞƚƉĂƉĞƌǁŽƌŬƐŝŐŶĞĚ͘ZŝŐŝŶ^ͬ>ĞƋƵŝƉŵĞŶƚ͕ZŝŐƵƉ͘ϭϮϱΗ ^ůŝĐŬůŝŶĞǁŝƚŚϰϬΖŽĨϰϭͬϮΗ>ƵďƌŝĐĂƚŽƌĐͬǁϰϭͬϮΗdŽŽůdƌĂƉĐͬǁϰϭͬϮΗdƌŝƉůĞǁŝƌĞůŝŶĞǀĂůǀĞ͘ WƌĞƐƐƵƌĞƚĞƐƚ^ͬ>ĞƋƵŝƉŵĞŶƚƚŽϯϬϬϬW^/͕ŚŽůĚĨŽƌϱŵŝŶƐ͕ƚĞƐƚŝƐŐŽŽĚ͘dŽŽůƐƚƌŝŶŐͲϮϬΖϭϳͬϴƐƚĞŵ͕ϭϳͬϴ>^^͕Z/,ǁŝƚŚůŽĐŬŽƵƚ ƚŽŽůĨŽƌEdZ^sƉĞƌĨŽƌŵƉƵůůǁĞŝŐŚƚΛϭϮϵΖϰϰϬůďƐǁŝƚŚůŽĐŬŽƵƚƚŽŽů͕ƚĂƉĚŽǁŶϮǆƚŽƐĞƚĂŶĚůŽĐĂƚĞŶŝƉƉůĞƉƌŽĨŝůĞ͕ũĂƌĚŽǁŶ ŚĂƌĚϮǆƚŽƐĞƚŝŶƐŝĚĞƉƌŽĨŝůĞ͘WƵůůϰϬϬůďƐŽǀĞƌƐƚƌŝŶŐǁĞŝŐŚƚĂŶĚƐŝƚĨŽƌϱŵŝŶƐƚŽĐŽŶĨŝƌŵůĂƚĐŚŝŶƉƌŽĨŝůĞ͘'ŽŽĚƚĞƐƚ͕ƐůĂĐŬŽĨĨ ƚŽŽůƐƚƌŝŶŐǁĞŝŐŚƚĂŶĚ;Ϭϵ͗ϭϬͿƐƚĂƌƚƉƵŵƉŝŶŐĨůƵŝĚƚŽƉƌĞƐƐƵƌĞƵƉŽŶůŽĐŬŽƵƚƚŽŽů͕Ϭϵ͗ϯϬƐƚĂŶĚďǇĨŽƌŵŽƌĞĨůƵŝĚ͕ĐŽŶƚŝŶƵĞ ƉƵŵƉŝŶŐŽƉƐ͘ϭϬ͗ϬϬĂŵƐƚĂŶĚďǇĨŽƌŵŽƌĞĨůƵŝĚ͕ϭϬ͗ϮϬĨŝŶŝƐŚƉƵŵƉŝŶŐϮ͘ϲďďůƚŽƉƌĞƐƐƵƌĞƵƉƚŽϭϰϱϬůďƐ͕ďǇƉĂƐƐǀĂůǀĞŽƉĞŶƐŝŶ ůŽĐŬŽƵƚƚŽŽůĂŶĚƉƌĞƐƐƵƌĞďůĞĞĚƐďĂĐŬ͘ ϭϬ͗ϰϰ:ĂƌĚŽǁŶϮϱϬǆƚŽĐŽŶĨŝƌŵƐĞƚƐĐƌĞǁƐĂƌĞƐŚĞĂƌĞĚĂŶĚĐŽƌĞƌŽĚƌĞůĞĂƐĞΖƐ͕ũĂƌƵƉϭϬǆƚŽŽůĐŽŵĞƐĨƌĞĞ͕WKK,͘Z/,ǁŝƚŚϯ͘ϳΗ 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ΛϭϮ͗ϮϬƉŵĂŶĚǁĂƚĐŚƚŽƐĞĞŝĨƉƌĞƐƐƵƌĞďƵŝůĚƐ͘ĨƚĞƌϯϬŵŝŶƐ ƐŚƵƚŝŶƚŚĞǁĞůůďƵŝůĚƐůĞƐƐƚŚĞŶϭƉƐŝ͘WƵŵƉƵƉŽŶƚŚĞĐŽŶƚƌŽůůŝŶĞĂŶĚΛϭϯϬϬƉƐŝƚŚĞ^^^sŽƉĞŶƐĂŶĚƉƌĞƐƐƵƌĞďƵŝůĚƐŽŶƚŚĞ ƚƵďŝŶŐ͘>ĞĂǀĞϰϮϬϬůďƐŽŶƚŚĞĐŽŶƚƌŽůůŝŶĞ͘Z 1 Winston, Hugh E (OGC) From:Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent:Friday, April 16, 2021 8:12 AM To:McLellan, Bryan J (OGC) Cc:Donna Ambruz; Taylor Wellman; Rixse, Melvin G (OGC) Subject:RE: [EXTERNAL] RE: Paxton-10 (PTD#220-064) Failed MIT-IA Nope. All good. Thanks, Bryan Ryan Rupert Kenai Ops Engineer (13146) 907-301-1736 (Cell) 907-777-8503 (Office) From: McLellan, Bryan J (CED) [mailto:bryan.mclellan@alaska.gov] Sent: Friday, April 16, 2021 8:04 AM To: Ryan Rupert <Ryan.Rupert@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com>; Rixse, Melvin G (CED) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] RE: Paxton‐10 (PTD#220‐064) Failed MIT‐IA Thanks Ryan. I’m out of town, so if you need anything urgent give Mel Rixse a call. Do you need any more approvals from us? I think you are good to go. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Thursday, April 15, 2021 11:14 AM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com> Subject: RE: [EXTERNAL] RE: Paxton‐10 (PTD#220‐064) Failed MIT‐IA Bryan‐ I have updated the schematic per your request below. Please see attached for my final lower tubing assembly. Inserting one 30’ joint between the X‐nipple and the overshot, we can get the packer to within ~50’ of the tubing stub. 2 Given the CBL deflection off of free pipe baseline below ~1000’ I’m hesitant to cut any deeper than that joint. Please give me a ring to discuss. We plan to cut pipe first thing tomorrow morning. Thanks, Ryan Rupert Kenai Ops Engineer (13146) 907-301-1736 (Cell) 907-777-8503 (Office) From: McLellan, Bryan J (CED) [mailto:bryan.mclellan@alaska.gov] Sent: Tuesday, April 13, 2021 9:29 AM To: Ryan Rupert <Ryan.Rupert@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com> Subject: [EXTERNAL] RE: Paxton‐10 (PTD#220‐064) Failed MIT‐IA Hi Ryan, I agree with this plan, but would like to see you push the packer as deep as you can, by cutting deeper and/or shortening the tailpipe. I recognize that you may not want to cut much deeper due to the possible presence of cement. Also, please indicate on the diagram that the swell packer is believed to have failed and state the leak rate out the shoe. It might be important for future operations (P&A or RWO) and if it’s on the diagram, people will plan accordingly. Thanks Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Monday, April 12, 2021 3:00 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com>; Ryan Rupert <Ryan.Rupert@hilcorp.com> Subject: RE: Paxton‐10 (PTD#220‐064) Failed MIT‐IA Bryan‐ Per our conversation Hilcorp will continue to pursue diagnostics on the failed MIT‐IA for Pax‐10. If diagnostics point to a leak path out the shoe of the 7‐5/8” casing (failed swell packer and/or cement), we’d like to ask for approval for the below ‘plan B’ to be amended onto sundry #321‐081. Thoughts? ‐ Cut tubing above ToC: cut at ~1000’ MD 3 ‐ Complete with sealing overshot and 7‐5/8” x 4‐1/2” production packer. High level tally would read as follows: o Tubing hanger o 4‐1/2” Joints as needed o TRSSSV @ ~150’MD o 4‐1/2” Joints as needed o 7‐5/8” x 4‐1/2” production packer @ ~900’ MD o Joints as needed o Sealing overshot @ ~1000’ MD Barrier verification would still be a passing MIT‐IA, and a passing MIT‐T against a plug set below the sealing overshot Ryan Rupert Kenai Ops Engineer (13146) 907-301-1736 (Cell) 907-777-8503 (Office) From: Ryan Rupert Sent: Sunday, April 11, 2021 9:17 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Ryan Rupert <Ryan.Rupert@hilcorp.com> Subject: Paxton‐10 (PTD#220‐064) Failed MIT‐IA Bryan‐ As part of sundry #321‐081 we went out on Friday 4/9 to perform our pre‐rig MIT‐IA. It ended up failing. I’ve listed a few data points below. Can you please give me a ring Monday to discuss scope modifications needed to the RWO in order to address this? We still plan to MIRU our RWO rig on Thu 4/15, if possible. Thanks ‐ Timeline o 10/17/20: Rig cement job went well 10/17/20 o 10/22/20: CBL showed ToC at 1440’ MD o 10/29/20: MIT‐IA to 2000psi passed o 4/6/21: MIT‐IA to 1500psi fails ‐ Configuration o Surface casing shoe at 1522’ MD o Logged ToC at 1440’ MD o Swell packer at 1283’ MD ‐ 4/9/21 MIT‐IA o Initial TI reads: (110/5) o Pressured up to ~1800 psi, and kept falling off 4 o Repressured several times with same results o Tubing pressure unaffected during fails. Well was online flowing o Final TI reads: (110/0) o TI reads the next morning: (110/320) We still plan to SI the well at the end of the day tomorrow, Monday 4/12 per the sundry, but we won’t punch/cut tubing, etc… without an agreed path forward from AOGCC. Thanks, Ryan Rupert Kenai Ops Engineer (13146) 907-301-1736 (Cell) 907-777-8503 (Office) The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. 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If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1 Winston, Hugh E (OGC) From:McLellan, Bryan J (OGC) Sent:Tuesday, April 27, 2021 8:11 AM To:Regg, James B (OGC) Subject:FW: Pax-10 (PTD#220-064) BOP test Jim, I should have copied you on this approval to BOP test Paxton 10 to 3500 psi, which is lower pressure than on the Sundry. Note that this is different from your recent communication about a similar issue Paxton 9. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: McLellan, Bryan J (CED) Sent: Monday, April 26, 2021 12:41 AM To: Ryan Rupert <Ryan.Rupert@hilcorp.com>; Rixse, Melvin G (CED) <melvin.rixse@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Robert O'Neal ‐ (C) <roneal@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com> Subject: RE: Pax‐10 (PTD#220‐064) BOP test Ryan, In case you haven’t heard from Mel yet, I approve the CT BOP test to 3500 psi (assuming Mel hasn’t already informed you otherwise). Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Sunday, April 25, 2021 2:20 PM To: Rixse, Melvin G (CED) <melvin.rixse@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Robert O'Neal ‐ (C) <roneal@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com>; McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Subject: Pax‐10 (PTD#220‐064) BOP test Mel‐ 2 We’re getting Petrospec CT onto Pax‐10 (PTD#220‐064) for post‐RWO work as sundried in the attached (#321‐081). The procedure calls for a 4000psi CT BOP test associated with nitrogen use. Because of the low BHP we plan to BOP test to 3500psi high, and not the 4000psi in the sundry. The 3500psi BOP test still exceeds the MASP (165psi) with a comfortable margin. Please let us know if in opposition to this detail modification. Thanks, Ryan Rupert Kenai Ops Engineer (13146) 907-301-1736 (Cell) 907-777-8503 (Office) The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1 Winston, Hugh E (OGC) From:Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent:Friday, December 17, 2021 10:38 AM To:McLellan, Bryan J (OGC) Cc:Dan Marlowe; Juanita Lovett; Donna Ambruz; Ryan Rupert Subject:Pax-10(PTD#217-041) Attachments:Paxton 10 AOGCC 10-403 321-256 PTD 220-064 Approved 05-27-21.pdf; Paxton 10 AOGCC 10-403 321-081 PTD 220-064 Approved 02-18-21.pdf Bryan‐ Just pulling together the 404 to close out sundries #321‐081 and #321‐256 for Paxton‐10(PTD#217‐041). This was the RWO to install a TRSSSV, and subsequent remediation to install a k‐valve, and ultimately lockout the failed TRSSSV valve, then installs WL‐SSSV. Happy to report that all this work has finally been completed, and the well has a working surface controlled SSSV. In combing back through all of our well reports, we realized that the PT details were not recorded for SL rigups on 5/31, 6/3, and 6/6. MPSP for this well is only 165psi, so I’m confident we did in fact PT above MPSP, and executed the job safely, I just don’t have a record of the test pressure. My approved sundry did call for the SL work (install k‐valve) to have a 2000psi PT. These gaps will be closed going forward, but as we continue to comb through legacy activity and reports, clerical discrepancies such as these will be discovered. The 404 should be coming over your way soon, just wanted to flag this issue before that. Thanks, CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 Ryan Rupert Alaska South-Central Team Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. 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: Hilcorp North Slope, LLC Date: 05/27/2021 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 KALOTSA 1 50133206570000 216132 3/27/2021 SET PATCH/GAMMA RAY Yellowjacket KALOTSA 1 50133206570000 216132 4/23/2021 PERF GAMMA RAY / GPT Yellowjacket KALOTSA 2 50133206590000 216155 4/10/2021 PERF GAMMA RAY Yellowjacket PAXTON 2 50133205730000 207164 2/23/2021 PERF GAMMA RAY Yellowjacket PAXTON 9 50133206470000 214173 3/19/2021 PERF GAMMA RAY Yellowjacket PAXTON 9 50133206470000 214173 4/10/2021 PERF GAMMA RAY Yellowjacket PAXTON 9 50133206470000 216132 4/23/2021 PERF GAMMA RAY Yellowjacket PAXTON 10 50133206910000 220064 4/13/2021 SET WRP / CCL Yellowjacket PAXTON 10 50133206910000 220064 4/20/2021 SET WRP / CCL Yellowjacket SD-1A 50133100020100 185208 4/27/2021 PERF GAMMA RAY / GPT Yellowjacket Please include current contact information if different from above. PTD: 2200640 E-Set: 35209 06/02/2021 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: Hilcorp North Slope, LLC Date: 05/27/2021 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 KALOTSA 1 50133206570000 216132 3/27/2021 SET PATCH/GAMMA RAY Yellowjacket KALOTSA 1 50133206570000 216132 4/23/2021 PERF GAMMA RAY / GPT Yellowjacket KALOTSA 2 50133206590000 216155 4/10/2021 PERF GAMMA RAY Yellowjacket PAXTON 2 50133205730000 207164 2/23/2021 PERF GAMMA RAY Yellowjacket PAXTON 9 50133206470000 214173 3/19/2021 PERF GAMMA RAY Yellowjacket PAXTON 9 50133206470000 214173 4/10/2021 PERF GAMMA RAY Yellowjacket PAXTON 9 50133206470000 216132 4/23/2021 PERF GAMMA RAY Yellowjacket PAXTON 10 50133206910000 220064 4/13/2021 SET WRP / CCL Yellowjacket PAXTON 10 50133206910000 220064 4/20/2021 SET WRP / CCL Yellowjacket SD-1A 50133100020100 185208 4/27/2021 PERF GAMMA RAY / GPT Yellowjacket Please include current contact information if different from above. PTD: 2200640 E-Set: 35208 06/02/2021 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: __Install SSSV_____ 2.Operator Name:4. Current Well Class:5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6.API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 5732'none Casing Collapse Structural Conductor 1410 psi Surface 4790 psi Intermediate Production 7500 psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Ryan Rupert Operations Manager Contact Email: Contact Phone: 777-8503 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng ryan.rupert@hilcorp.com 3,879'5,632'3,801'165 psi none Swell PKR ; NE-Slim TRSSSV 1283' MD / 1213' TVD ; 144' MD / 144' TVD 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 Private (Surface), ADL 384372 220-064 50-133-20691-00-00 Paxton 10 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 L-80 TVD Burst 636' 8430 psi MD 2980 psi 6890 psi 120' 1,380' 120' 1,522' 3,865'4-1/2" 16" 7-5/8" 120' 1,522' 5,718' Perforation Depth MD (ft): See Attached Schematic 5,082' 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: May 31, 2021 4-1/2" m n P 66 t _ Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 10:05 am, May 25, 2021 321-256 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.05.25 07:55:47 -08'00' Taylor Wellman (2143) SFD 5/26/021 DSR-5/26/21BJM 5/27/21 10-404 Safety Valve system test within 5 days of SSSV installation. JLC 5/27/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.05.27 10:48:45 -08'00' RBDMS HEW 6/2/2021 Well Prognosis Well: Paxton-10 Date: 5/24/2021 Well Name:Paxton-10 API Number:50-133-20691-00-00 Current Status:Gas Producer Leg:N/A Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:220-064 First Call Engineer:Ryan Rupert (907) 777-8503 (O)(907) 301-1736 (C) Second Call Engineer:Ted Kramer (907) 777-8420 (O)(985) 867-0665 (C) Maximum Expected BHP:~ 535 psi @ 3,703’ TVD (2020 RFT data from the BEL-135) Max. Potential Surface Pressure:~ 165 psi Using Max BHP minus 0.1 psi/ft. gas gradient to surface). Well Summary Paxton 10 was drilled and completed in October-2020. A K-valve was successfully run and operated in this well from 2/12/21 – 4/12/21 while a RWO was prepared to install a surface controlled TRSSSV. That RWO and associated post-rig wellwork was recently completed and the well was brought online. The well has its state test on 5/19, and while the SSV passed, the SSSV failed with a build up rate of 20- 30psi/min. Extensive troubleshooting has been conducted with no success. Downhole video camera does confirm the valve is functioning as designed, but still leaking by. The purpose of this sundry is to install surface controlled WLSSSV and/or a tubing pressure controlled SSSV (K- valve). The well needs either a WLSSSV or a k-valve installed and tested no later than 6/2/21. Notes Regarding Wellbore Condition x Min ID = 3.813” at 144’ MD (seal bore of existing TRSSSV) x Flowing tubing pressure = 200psi. (25% *200 psi = 50psi) x Separator inlet pressure = 85psi (50% * 85psi = 43psi) x SSSV must close when WHP drops below 50psi. (OK to trip at a higher pressure) Well Prognosis Well: Paxton-10 Date: 5/24/2021 SL Set SSSV (K-valve) 1. MIRU SL 2. PT BOP equipment to 250 psi Low / 2,000 psi High. 3. RIH and set K-valve assembly in X-profile at 144’ MD 4. RDMO and turn well over to production 5. Bring well online, and state test SSSV Lock out SSSV and install WLSSSV 1. MIRU SL 2. PT BOP equipment to 250 psi Low / 2,000 psi High. 3. MU lockout tool per vendor 4. RIH and permanently lockout Halliburton NE-Slim TRSSSV 5. PU and RIH with communication tool 6. Establish control line communication per vendor rep 7. RIH and set WL-SSSV at 144’ MD 8. RDMO and turn well over to production 9. Bring well online, and state test SSSV Attachments: 1. Proposed Schematic 2. K-valve design sheet Updated by CRR 5-24-21 SCHEMATIC Ninilchik Unit Paxton #10 PTD:220-064 API: 50-133-20691-00-00 PBTD = 5,632’ / TVD = 3,801’ TD = 5,732’ / TVD = 3,879’ RKB to GL = 17.6’ PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD FT Size Date Status Bel 135 5,460’5,480’3,673’3,688’20’2-7/8” 6 SPF 11/13/20 Open Bel 135 5,480’5,500’3,688’3,703’20’2-7/8” 6 SPF 11/13/20 Open Bel 136 5,514’5,520’3,714’3,718’6’2-7/8” 6 SPF 11/13/20 Open OPEN HOLE / CEMENT DETAIL 7-5/8"102 BBL’s of cement in 9-7/8” hole – 27 BBLs Cement to Surface 4-1/2” 140 BBL’s of cement in 6-3/4” hole – zero losses during cement job. 13 bbls spacer back to surface (of 35 pumped). 10/22/20 CBL showed ToC at 1440’ MD after 4 days of cement cure. 4/16/21 CBL showed ToC at 780’ MD. CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 120' 7-5/8"Surf Csg 29.7 L-80 DWC/C 6.875”Surf 1,522’ 4-1/2"Prod Csg 12.6 L-80 DWC/C HT 3.958”636’5,718’ 4-1/2"Tubing 12.6 L-80 IBT 3.958”Surf 636’ 7 16” 7-5/8” ToC at 780’MD (4/16/21 CBL) 4-1/2” No.Depth ID Item 1144’3.813”Surface controlled TRSSSV: NE-Slim (Halliburton) Insert safety valve (WLSSSV or K-valve) 2590’4.000”D&L Oil Tools 7-5/8” x 4-1/2” Hydraulic permanent packer (TriPoint) 3 599’3.813”X-nipple 4 636’3.95”Bowen (Baker)“Casing Patch” (Sealing Overshot with grapple) 5 997’ – 1010’3.25”X-Span permanent patch (set 5-12-21) 6 1000’Incomplete jet cut (4/16/21) 7 1,283’3.958”Swell Packer 1 2/3 4 Leaking Shoe as of 4/19/21 RTTS MIT fail 5/6 Ver. 4.1 6/6/01 Wireline Work Request Distribution Wireline (4) Well:Reading File Date:Engineer: H2S Level: Problem Description Install K-Valve to produce well. Initial Problem Review Well needs SSSV to flow due to proximity to water, well is almost pure methane. Initial K-Valve design did not close when tested. Remedial Plan - WIRELINE ACTION DSO: Flow well at normal wellhead pressure, valve set to close when well is produced to tanks. Targeted flowing wellhead pressure of 125 psi for valve to close at. FOR HES SHOP INFO ONLY: Set K-Valve to close at 101 psi @ 60 deg F. Date Work Completed Well Status/Results Date by _______ Problem Resolved ? ___ Y ___ N : Well Review (Post GLV or Choke Installation) Pre Installation Post Installation Liquid Rate (STBL/D) Expected NOB: Avg. WC (%) Actual NOB: Lift Gas (MMSCF/D) MGOR used for NOB: TGLR (SCF/STBL/D) FTP (psi)/Steady?MAINTENANCE ONLY CLP (psi)/Steady?(e.g. Fix AC, Shallower for Slugging) Casing Press. (psi)/Steady?RATE (Non-Post-WW) Orifice Depth:(e.g. deepen, optimize orifice) IA Fluid Level:Post-Wellwork Date of FL Survey: / / Follow-up Recommendations: Paxton-10 Paxton-10 2/10/2021 John Paul Kenda Date: Test Date 02/03/21 Gross Fluid Rate 0 BLPD Flowing Well Head Pressure 99 psi Flowing Well Head Temperature 30 deg F GOR scf/bbl TGLR scf/bbl Flowing Pressure Calculations Based on Hagedorn-Brown Multiphase Flow Correlation "K" Valve Setting Depth TVD 150 ft Flowing Tubing Pressure With Gas Lift NA psi Flowing Tubing Pressure Without Gas Lift NA psi Valve set to close at 125 psi Pwh Flowing Tubing Pressure @ 125 psi Pwh 125 psi "K" Valve Test Rack Set Pressure at 60 deg F 101 psi 4.5" 1.314 "K" Valve Calculation Sheet Paxton-10 Valve Size & Volume Ratio Tubing Pressure at Valve 125 BPT (psia)139 >1238 <1238 Temperature (deg F) at Valve 30 a -5.52E-06 -9.162E-06 b 0.93106 0.94198 Base Pressure 147.934694 c -131.39 -139.3322 Base Temp (TV-60) -30 141.23699 148.1275936 Corrected Pressure 148.127594 psia TCF 1.06260828 Volume Ratio for Valve Size =1.314 Pb @ 60 = 132.826034 Test Rack Pressure =101 Volume Ratios 4 1/2" & 5 1/2" 1.314 3 1/2" 1.257 2 7/8" 1.211 2 3/8" 1.204 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: 05/04/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL PAXTON 10 (PTD 220-064) TBG CUT, CBL 04/16/2021 Please include current contact information if different from above. PTD: 2200640 E-Set: 35088 Received by the AOGCC 05/04/2021 05/04/2021 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: 05/04/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL PAXTON 10 (PTD 220-064) Caliper Survey Report with 3D Viewer 04/22/2021 Please include current contact information if different from above. PTD: 2200640 E-Set: 35086 Received by the AOGCC 05/04/2021 05/04/2021 STATE OF ALASKA Reviewed By: iv - OIL AND GAS CONSERVATION COMMISSION P•I. Supry Sq?Z*7� ROPE Test Report for: NINILCHIK UNIT PAXTON 10 Comm Contractor/Rig No.: Hilcorp 401 Operator: Hilcorp Alaska, LLC Type Operation: WRKOV Sundry No: Type Test: [NIT 321-081 ' PTD#: 2200640 DATE: 4/15/2021 - Operator Rep: Rob O'Neal Test Pressures: Rams: Annular: Valves: MASP: 250/2500 - 250/2500 - 250/2500 - 165 - FLOOR SAFTY VALVES: Quantity TEST DATA MISC. INSPECTIONS: _ _0_ __'_ MUD SYSTEM: Lower Kelly P/F NA Visual Alarm Location Gen.: _P Trip Tank NA NA_ Housekeeping: P _ " Pit Level Indicators P - P PTD On Location P _ Flow Indicator NA NA' Standing Order Posted P Meth Gas Detector P P Well Sign P 1-12S Gas Detector P P ' Drl. Rig __P MS Misc _NA NA_ Hazard Sec. P BOP Misc 0 Misc NA FLOOR SAFTY VALVES: Inspector Jeff Jones - Insp Source Rig Rep: Chris Hannevold Inspector Inspection No: bop1J210422091602 Related Insp No: ACCUMULATOR SYSTEM: Time/Pressure P/F Quantity P/F Upper Kelly _ _0_ __'_ NA Lower Kelly __O,_' NA Ball Type 2 P' Inside BOP 0 NA FSV Misc 0NA_ 6(W 2000 Inspector Jeff Jones - Insp Source Rig Rep: Chris Hannevold Inspector Inspection No: bop1J210422091602 Related Insp No: ACCUMULATOR SYSTEM: Time/Pressure P/F System Pressure 2950 P Pressure After Closure 1900 P 200 PSI Attained 41 P Full Pressure Attained _ 171 P Blind Switch Covers: All P Nitgn. Bottles (avg): 6(W 2000 - P ACC Misc 0 NA BOP STACK: Quantity Size P/F Stripper _O _ _ _ _NA Annular Preventer 1 - 135/8 - _ P #1 Rams 1 2 7/8 x 5.5 ' P ' #2 Rams 1 Blind P ' #3 Rams 0 NA #4 Rams 0 NA_ #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 - 21/16 P ' HCR Valves 1 2 1/16 P Kill Line Valves 2 "2 1/16 P . Check Valve 0 NA BOP Misc 0 NA CHOKE MANIFOLD: Quantity P/F No. Valves _8 _P. Manual Chokes 2 P ' Hydraulic Chokes _ 0 NA CH Misc 0 NA INSIDE REEL VALVES: (Valid for Coil Rigs Only) Quantity P/F Inside Reel Valves 0 NA Number of Failures: 0 ✓ Test Results Test Time 9 Remarks: All American Oilfield personnel performed the tests today in a safe manner with no failures observed. The gas detection and pity volume totalizer alarm systems were tested and operated properly. From:McLellan, Bryan J (CED) To:Ryan Rupert Cc:Donna Ambruz; Taylor Wellman Subject:RE: Paxton-10 (PTD#220-064) Failed MIT-IA Date:Tuesday, April 13, 2021 9:28:00 AM Hi Ryan, I agree with this plan, but would like to see you push the packer as deep as you can, by cutting deeper and/or shortening the tailpipe. I recognize that you may not want to cut much deeper due to the possible presence of cement. Also, please indicate on the diagram that the swell packer is believed to have failed and state the leak rate out the shoe. It might be important for future operations (P&A or RWO) and if it’s on the diagram, people will plan accordingly. Thanks Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Monday, April 12, 2021 3:00 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com>; Ryan Rupert <Ryan.Rupert@hilcorp.com> Subject: RE: Paxton-10 (PTD#220-064) Failed MIT-IA Bryan- Per our conversation Hilcorp will continue to pursue diagnostics on the failed MIT-IA for Pax-10. If diagnostics point to a leak path out the shoe of the 7-5/8” casing (failed swell packer and/or cement), we’d like to ask for approval for the below ‘plan B’ to be amended onto sundry #321-081. Thoughts? Cut tubing above ToC: cut at ~1000’ MD Complete with sealing overshot and 7-5/8” x 4-1/2” production packer. High level tally would read as follows: Tubing hanger 4-1/2” Joints as needed TRSSSV @ ~150’MD 4-1/2” Joints as needed 7-5/8” x 4-1/2” production packer @ ~900’ MD Joints as needed Sealing overshot @ ~1000’ MD Barrier verification would still be a passing MIT-IA, and a passing MIT-T against a plug set below the sealing overshot Ryan Rupert Kenai Ops Engineer (13146) 907-301-1736 (Cell) 907-777-8503 (Office) From: Ryan Rupert Sent: Sunday, April 11, 2021 9:17 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Ryan Rupert <Ryan.Rupert@hilcorp.com> Subject: Paxton-10 (PTD#220-064) Failed MIT-IA Bryan- As part of sundry #321-081 we went out on Friday 4/9 to perform our pre-rig MIT-IA. It ended up failing. I’ve listed a few data points below. Can you please give me a ring Monday to discuss scope modifications needed to the RWO in order to address this? We still plan to MIRU our RWO rig on Thu 4/15, if possible. Thanks Timeline 10/17/20: Rig cement job went well 10/17/20 10/22/20: CBL showed ToC at 1440’ MD 10/29/20: MIT-IA to 2000psi passed 4/6/21: MIT-IA to 1500psi fails Configuration Surface casing shoe at 1522’ MD Logged ToC at 1440’ MD Swell packer at 1283’ MD 4/9/21 MIT-IA Initial TI reads: (110/5) Pressured up to ~1800 psi, and kept falling off Repressured several times with same results Tubing pressure unaffected during fails. Well was online flowing Final TI reads: (110/0) TI reads the next morning: (110/320) We still plan to SI the well at the end of the day tomorrow, Monday 4/12 per the sundry, but we won’t punch/cut tubing, etc… without an agreed path forward from AOGCC. Thanks, Ryan Rupert Kenai Ops Engineer (13146) 907-301-1736 (Cell) 907-777-8503 (Office) The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. 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ressure1-IPR PressureVLP Pressure, IPR Pressure (psig)3403353303253203153103053002952902852802752702652602552502452402352302252202152102052001951901851801751701651601551501451401351301251201151101051009590858075706560555045403530252015105Gas Rate (MMscf/day)43210 1.Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: __Install SSSV_____ 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 5732'none Casing Collapse Structural Conductor 1410 psi Surface 4790 psi Intermediate Production 7500 psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Ryan Rupert Operations Manager Contact Email: Contact Phone: 777-8503 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng ryan.rupert@hilcorp.com 3,879'5,632'3,801'165 psi none Swell PKR 1283' MD / 1213' TVD 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 Private (Surface), ADL 384372 220-064 50-133-20691-00-00 Paxton 10 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 NA TVD Burst NA 8430 psi MD 2980 psi 6890 psi 120' 1,380' 120' 1,522' 3,865'4-1/2" 16" 7-5/8" 120' 1,522' 5,718' Perforation Depth MD (ft): See Attached Schematic 5,718' Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: April 1, 2021 NA 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 9:50 am, Feb 12, 2021 321-081 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.02.11 23:24:03 -09'00' Taylor Wellman (2143) SFD 2/16/2020 BOP test to 2500 psi, rig 401. Continued production with existing K-valve allowed until 4/13/2021 per Sundry 321-070. Pull Tubing DSR-2/16/21 _Install SSSV_ rig 401 10-404 X Notify AOGCC to witness test of SCSSSV. Test must be conducted no later then 5 days after placing the well in service following installation. BJM 2/17/21 Comm 2/18/21 dts 2/17/2021 JLC 2/17/2021 RBDMS HEW 2/25/2021 Well Prognosis Well: Paxton-10 Date: 2/10/2020 Well Name:Paxton-10 API Number:50-133-20691-00-00 Current Status:Gas Producer Leg:N/A Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:220-064 First Call Engineer:Ryan Rupert (907) 777-8503 (O)(907) 301-1736 (C) Second Call Engineer:Jake Flora (907) 777-8442 (O)(720) 988-5375 (C) Maximum Expected BHP:~ 535 psi @ 3,703’ TVD (2020 RFT data from the BEL-135) Max. Potential Surface Pressure:~ 165 psi Using Max BHP minus 0.1 psi/ft. gas gradient to surface). Well Summary Paxton 10 was drilled and completed in October-2020. The well passed an MIT-IA to 2000psi on 10/29/20 11days after the swell packer was RIH and the cement was in place. The well is currently a steady online producer at ~3000MCFD wide open to LP at ~100psi FTP. The purpose of this sundry is to install a surface controlled SSSV. Objectives x Protect the current open intervals x Install a SCSSSV that still maintains a monobore x Keep the 7-5/8” x 4-1/2” annulus monitorable x Keep reservoir fluids off the swell packer / ToC long term Notes Regarding Wellbore Condition x Min ID = 3.833” (drift ID of 4-1/2” pipe) x Max inclination = 62 degrees at 4065’ MD x Max DLS = 7 degree/100’ at 1314’ MD x Drift: 11/13/20: 2-7/8” x 20’ gun made it down to 5500’ Risks x Nitrogen o Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. o Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job) o Ensure all crews are aware of stop work authority x Damaging the current perfs o Keep water off perfs. o Set deep plug pre-RWO o Don’t pull plug until well is blown dry above Note: K-valve installed and tested 2.14.21 TRSSV(ScSSSV) must be installed in 60 days or less. (ie by 4/13/21 per sundry 321-070) The purpose of this sundry is to install a surface controlled SSSV. Well Prognosis Well: Paxton-10 Date: 2/10/2020 Pre-rig Procedure 1. MIT-IA to 1500psi for 30 charted minutes 2. RU EL and PT BOP equipment to 250psi low / 2500psi high 3. Drift with 3.80” gauge ring and sample bailer to PBTD. a. Area around 500’ is critical to ensure there’s no cement sheath b. Collect water sample and send to Anchorage Office 4. RIH with GPT tool and find FL. 5. Obtain static BHP at 5480’MD 6. RIH with 4-1/2” retrievable plug and set at ±5450’ MD. Protect fishing neck, if necessary (sand, etc…) 7. Load well with source water (~8.3ppg). WBV = 83bbls 8. MIT-T to 1500psi for 30 minutes Confirm both MIT’s have passed before proceeding 9. RIH with tubing puncher and punch just above a collar at ±500’ a. Ensure IAP is bled down to 0psi b. IA will be fluid packed with cement spacer (10.5ppg) c. Ensure we are overbalanced to the IA before punch (need to hold ~100psi on tubing during punch) 10. Break circulation to confirm successful punch 11. RDMO EL 12. Displace IA fluid out of well: 7 bbls inside tubing above punches, 13 bbls in IA above cut (20bbls total) 13. CMIT-TxIA to 1500psi (verifies tubing punches have not compromised surface casing) Confirm both MIT’s have passed before proceeding WRPB at 5450 ft (pull K-valve) Well Prognosis Well: Paxton-10 Date: 2/10/2020 Rig 401 Procedure 1. MIRU 401 workover rig. Provide 24hr notice to AOGCC of BOP Test. 2. Set BPV, ND Tree, NU BOP. 3. Perform BOP Test to 250 psi low & 2,500 psi high, annular to 250 psi low & 2,500 psi high. Test BOP’s on 2-7/8” and 4-1/2” pipe. Record with chart & submit to AOGCC within 5 days of test. 4. Backout LDS and unseat tubing hanger. 5. RU EL and PT BOP equipment to 250psi low / 2500psi high 6. Pull tubing into tension, RIH and cut 4-1/2” tubing at ±500’ a. Want to cut ~4’ below collar b. Punches should be above the same collar 7. POOH with tubing, and rack back 8. PU 2-7/8” work string 9. Makeup casing scraper + dressoff BHA 10. RIH and dressoff tubing stub per vendor for eventual sealing overshot. POOH 11. MU sealing overshot and RIH with 4-1/2” completion with TRSSSV at ±150’ MD 12. Engage tubing stub per vendor, space out and land completion, RILDS 13. MIT-T to 1500psi for 30 charted minutes 14. MIT-IA to 1500psi for 30 charted minutes 15. Once pass, ND BOP, NU tree, and RDMO Post-rig Procedure 1. MIRU CT 2. Perform BOP test to 250psi low / 4000 high a. Notify AOGCC 24hrs in advance b. If SLB CT, covered under weekly BOP testing requirement 3. RIH and wash / cleanup top of 4-1/2” retrievable plug 4. RU Nitrogen and blow well down evacuating all fluid (WBV = 83 bbls) 5. Leave 700 psi nitrogen on well (may adjust based on pre-rig pressure measurement) 6. RU pulling tool, RIH and latch retrievable plug (equalize first, if possible) 7. Pull 4-1/2” Retrievable plug 8. RD Coiled Tubing Unit and turn well over to production. a. The new SSSV must be performance-tested within 5 days after stabilized production is achieved. Attachments: 1. Current schematic 2. Proposed Schematic 3. Rig 401 BOP schematic 4. RWO change form 5. Standard Well procedure – N2 Operations (CMIT after jet cut) Punches should be above the same collar Want to cut ~4’ below collar consider mech casing cutter to minimize damage to tubing and surface casing. gls gls 2/17/21 Notify AOGCC 24 hrs in advance. SSSV Test required within 5 days of placing the well in service per 20AAC25.265(h)(4). (notify Inspector to witness if CTU is not SLB unit) Review N2 SOP before pumping Updated by CRR 2-2-21 SCHEMATIC Ninilchik Unit Paxton #10 PTD:220-064 API: 50-133-20691-00-00 PBTD = 5,632’ / TVD = 3,801’ TD = 5,732’ / TVD = 3,879’ RKB to GL = 17.6’ PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD FT Size Date Status Bel 135 5,460’5,480’3,673’3,688’20’2-7/8” 6 SPF 11/13/20 Open Bel 135 5,480’5,500’3,688’3,703’20’2-7/8” 6 SPF 11/13/20 Open Bel 136 5,514’5,520’3,714’3,718’6’2-7/8” 6 SPF 11/13/20 Open CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 120' 7-5/8"Surf Csg 29.7 L-80 DWC/C 6.875”Surf 1,522’ 4-1/2"Prod Csg 12.6 L-80 DWC/C HT 3.958”Surf 5,718’ 1 16” 7-5/8” ToC at 1440’MD (10/22/20 CBL) 4-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 1,283’3.958”6.875”Swell Packer OPEN HOLE / CEMENT DETAIL 7-5/8"102 BBL’s of cement in 9-7/8” hole – 27 BBLs Cement to Surface 4-1/2”140 BBL’s of cement in 6-3/4” hole – zero losses during cement job. 13 bbls spacer back to surface (of 35 pumped) Updated by CRR 2-2-20 PROPOSED SCHEMATIC Ninilchik Unit Paxton #10 PTD:220-064 API: 50-133-20691-00-00 PBTD = 5,632’ / TVD = 3,801’ TD = 5,732’ / TVD = 3,879’ RKB to GL = 17.6’ PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD FT Size Date Status Bel 135 5,460’5,480’3,673’3,688’20’2-7/8” 6 SPF 11/13/20 Open Bel 135 5,480’5,500’3,688’3,703’20’2-7/8” 6 SPF 11/13/20 Open Bel 136 5,514’5,520’3,714’3,718’6’2-7/8” 6 SPF 11/13/20 Open CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 120' 7-5/8"Surf Csg 29.7 L-80 DWC/C 6.875”Surf 1,522’ 4-1/2"Prod Csg 12.6 L-80 DWC/C HT 3.958”500’5,718’ 4-1/2"Tubing 12.6 L-80 DWC/C HT 3.958”Surf 500’ 3 16” 7-5/8” ToC at 1440’MD (10/22/20 CBL) 4-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 ±150’Surface controlled TRSSSV 2 ±500’Sealing Overshot 3 1,283’3.958”6.875”Swell Packer OPEN HOLE / CEMENT DETAIL 7-5/8"102 BBL’s of cement in 9-7/8” hole – 27 BBLs Cement to Surface 4-1/2”140 BBL’s of cement in 6-3/4” hole – zero losses during cement job. 13 bbls spacer back to surface (of 35 pumped) 1 2 ScSSV MIT-IA to 1500 psi 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. The picture can't be displayed.The picture can't be displayed.The picture can't be displayed.The picture can't be displayed. 11" Spherical Annular Height: 42" 11" LWS Double BOP 2-7/8" to 5" Multirams top Blind rams bottom Height:33" 11" Mud Cross W/ 4-1/16" Outlets Dual 2-1/16" Manual Gate Valves W/ DSA to 4-1/16" Width to flange: 34" 2-1/16" Manual Gate Valve & 2-1/16" HCR W/ DSA to 4- 1/16" Full Mud Cross Assy. width w/ valves installed Width: 96" Kill side Choke side BOP Stack Width: 96" @ valves Height Addition for Ring Gaskets: .75" BOP Total Height: 101.75" 11" 5m BOP Package W/ 2-1/16" Valves Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Rig Work Over Sundry ProcedureSubject: Changes to Approved Sundry Procedure for Well Paxton-10 (PTD 220-064)Sundry #:Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change.SecPageDateProcedure ChangeNew 403Required?Y / NHAKPreparedBy(Initials)HAKApprovedBy(Initials)AOGCC WrittenApproval Received(Person and Date)Approval:Asset Team Operations Manager DatePrepared:First Call Operations Engineer Date Ninilchik Unit Paxton #10 01/30/2021 Valve, Master, CIW-FLS, 4 1/16 5M FE, HWO, EE trim Valve, Upper master, CIW-FLS, 4 1/16 5M FE, HWO, EE trim Valve, Swab, CIW-FLS 4 1/16 5M FE, HWO, EE trim Valve, Wing, CIW-FC, 3 1/8 5M FE, HWO, EE trim BHTA, Otis, 4 1/16 5M FE x 6.5 Otis quick union top 16'’ 7 5/8'’ 4 ½’’ Starting head, Cactus C-29L, 16 3/4 3M x 16 SOW, w/ 2- 2 1/16 5M SSO Tubing head, Cactus C-29L- HPS, 16 3/4 3M x 11 5M, w/ 2- 2 1/16 5M SSO Ninilchik Unit Paxton #10 16 x 7 5/8 x 4 ½ Tubing hanger, Cactus-EN- CCL, 4 ½ EUE 8rd lift and susp x w 6 ¼ od ext neck, 4'’ type H BPV profile, DD-NL material Valve, Wing, SSV, WKM-M, 3 1/8 5M FE, w/ 15'’ Hydraulic operator Adapter, 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DatasetNumberNameIntervalList of Logs Obtained:MWD/LWD logs, Mudlog, CBL 10-22-20, GeotapNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF10/30/202010 5820 Electronic Data Set, Filename: Paxton 10 LAS.las34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 Daily Reports.pdf34151EDDigital DataDF10/30/2020 Electronic File: Hilcorp Paxton 10 EOW Report.pdf34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 Drilling Dynamics Log MD 2in.pdf34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 Drilling Dynamics Log MD 5in.pdf34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 Drilling Dynamics Log TVD 2in.pdf34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 Drilling Dynamics Log TVD 5in.pdf34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 Formation Log MD 2in.pdf34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 Formation Log MD 5in.pdf34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 Formation Log TVD 2in.pdf34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 Formation Log TVD 5in.pdf34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 Gas Ratio Log MD 2in.pdf34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 Gas Ratio Log MD 5in.pdf34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 Gas Ratio Log TVD 2in.pdf34151EDDigital DataWednesday, December 16, 2020AOGCCPage 1 of 5Supplied byOpSupplied byOp: Paxton 10 LAS.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20691-00-00Well Name/No. NINILCHIK UNIT PAXTON 10Completion Status1-GASCompletion Date11/13/2020Permit to Drill2200640Operator Hilcorp Alaska, LLCMD5733TVD3879Current Status1-GAS12/16/2020UICNoDF10/30/2020 Electronic File: Paxton 10 Gas Ratio Log TVD 5in.pdf34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 LWD Combo Log MD 2in.pdf34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 LWD Combo Log MD 5in.pdf34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 LWD Combo Log TVD 2in.pdf34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 LWD Combo Log TVD 5in.pdf34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 Drilling Dynamics Log MD 2in.tif34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 Drilling Dynamics Log MD 5in.tif34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 Drilling Dynamics Log TVD 2in.tif34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 Drilling Dynamics Log TVD 5in.tif34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 Formation Log MD 2in.tif34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 Formation Log MD 5in.tif34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 Formation Log TVD 2in.tif34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 Formation Log TVD 5in.tif34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 Gas Ratio Log MD 2in.tif34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 Gas Ratio Log MD 5in.tif34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 Gas Ratio Log TVD 2in.tif34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 Gas Ratio Log TVD 5in.tif34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 LWD Combo Log MD 2in.tif34151EDDigital DataWednesday, December 16, 2020AOGCCPage 2 of 5 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20691-00-00Well Name/No. NINILCHIK UNIT PAXTON 10Completion Status1-GASCompletion Date11/13/2020Permit to Drill2200640Operator Hilcorp Alaska, LLCMD5733TVD3879Current Status1-GAS12/16/2020UICNoDF10/30/2020 Electronic File: Paxton 10 LWD Combo Log MD 5in.tif34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 LWD Combo Log TVD 2in.tif34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 LWD Combo Log TVD 5in.tif34151EDDigital DataDF10/30/2020 Electronic File: Paxton10.dbf34151EDDigital DataDF10/30/2020 Electronic File: paxton10.hdr34151EDDigital DataDF10/30/2020 Electronic File: Paxton10.mdx34151EDDigital DataDF10/30/2020 Electronic File: paxton10r.dbf34151EDDigital DataDF10/30/2020 Electronic File: paxton10r.mdx34151EDDigital DataDF10/30/2020 Electronic File: Paxton10_SCL.DBF34151EDDigital DataDF10/30/2020 Electronic File: Paxton10_SCL.MDX34151EDDigital DataDF10/30/2020 Electronic File: PAXTON10_TVD.DBF34151EDDigital DataDF10/30/2020 Electronic File: PAXTON10_TVD.mdx34151EDDigital DataDF10/30/2020 Electronic File: Paxton 10 Show Reports.pdf34151EDDigital Data0 0 2200640 NINILCHIK UNIT PAXTON 10 LOG HEADERS34151LogLog Header ScansDF11/11/202075 5700 Electronic Data Set, Filename: Paxton 10 LWD Final.las34239EDDigital DataDF11/11/2020 Electronic File: Paxton 10 Geo-Tap Pressure Tests.cgm34239EDDigital DataDF11/11/2020 Electronic File: Paxton 10 LWD Final MD.cgm34239EDDigital DataDF11/11/2020 Electronic File: Paxton 10 LWD Final TVD.cgm34239EDDigital DataDF11/11/2020 Electronic File: Paxton #10_Definitive Survey Report.pdf34239EDDigital DataDF11/11/2020 Electronic File: Paxton #10_Definitive Surveys.txt34239EDDigital DataDF11/11/2020 Electronic File: Paxton #10_Definitive Surveys.xlsx34239EDDigital DataDF11/11/2020 Electronic File: Paxton #10_GIS.txt34239EDDigital DataDF11/11/2020 Electronic File: Paxton 10 Geo-Tap Pressure Tests.emf34239EDDigital DataWednesday, December 16, 2020AOGCCPage 3 of 5: Paxton 10 LWD Final.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20691-00-00Well Name/No. NINILCHIK UNIT PAXTON 10Completion Status1-GASCompletion Date11/13/2020Permit to Drill2200640Operator Hilcorp Alaska, LLCMD5733TVD3879Current Status1-GAS12/16/2020UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYMud 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 HISTORYDF11/11/2020 Electronic File: Paxton 10 LWD Final MD.emf34239EDDigital DataDF11/11/2020 Electronic File: Paxton 10 LWD Final TVD.emf34239EDDigital DataDF11/11/2020 Electronic File: Paxton 10 Geo-Tap Pressure Tests.pdf34239EDDigital DataDF11/11/2020 Electronic File: Paxton 10 GeoTap Report - Final - All Pretests.pdf34239EDDigital DataDF11/11/2020 Electronic File: Paxton 10 LWD Final MD.pdf34239EDDigital DataDF11/11/2020 Electronic File: Paxton 10 LWD Final TVD.pdf34239EDDigital DataDF11/11/2020 Electronic File: Paxton 10 Geo-Tap Pressure Tests.tif34239EDDigital DataDF11/11/2020 Electronic File: Paxton 10 LWD Final MD.tif34239EDDigital DataDF11/11/2020 Electronic File: Paxton 10 LWD Final TVD.tif34239EDDigital Data0 0 2200640 NINILCHIK UNIT PAXTON 10 LOG HEADERS34239LogLog Header ScansDF11/18/20205638 390 Electronic Data Set, Filename: Paxton 10, RCBL, 10-22-20, Final Log.las34285EDDigital DataDF11/18/2020 Electronic File: Paxton 10, RCBL, 10-22-20, Final Log.pdf34285EDDigital Data0 0 2200640 NINILCHIK UNIT PAXTON 10 LOG HEADERS34285LogLog Header Scans10/26/20201552 573331767CuttingsWednesday, December 16, 2020AOGCCPage 4 of 5 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20691-00-00Well Name/No. NINILCHIK UNIT PAXTON 10Completion Status1-GASCompletion Date11/13/2020Permit to Drill2200640Operator Hilcorp Alaska, LLCMD5733TVD3879Current Status1-GAS12/16/2020UICNoComments:Compliance Reviewed By:Date:Date CommentsDescriptionCompletion Date:11/13/2020Release Date:9/22/2020Wednesday, December 16, 2020AOGCCPage 5 of 5M. Guhl12/16/2020 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): GL: 148.4' BF:148.4' Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 (ft MSL) 22. Logs Obtained: 23. BOTTOM 16" X-56 120' 7-5/8" L-80 1,382' 4-1/2" L-80 3,871' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, TUBING RECORD N/A SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): L - 280 sx / T - 75 sx Cond Surface 1,522' L - 167 sx / T - 150 sx Driven STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 11/13/2020 969' FNL, 3039' FEL, Sec 13, T1S, R14W, SM, AK 2544' FNL, 1863' FEL, Sec 12, T1S, R14W, SM, AK 220-064 / 320-449 Ninilchik Field / Beluga/Tyonek Gas Pool 166' 5,632' MD / 3,801' TVD HOLE SIZE AMOUNT PULLED 50-133-20691-00-00 Paxton 10 206284 2230394 2547' FSL, 1919' FEL, Sec 12, T1S, R14W, SM, AK CEMENTING RECORD 2233792 SETTING DEPTH TVD 2233979 BOTTOM TOP 6-3/4" 149 bbls Surface 9-7/8"Surface CASING WT. PER FT.GRADE 207488 207549 TOP SETTING DEPTH MD Surface Per 20 AAC 25.283 (i)(2) attach electronic information 12.6# Surface DEPTH SET (MD) PACKER SET (MD/TVD) 84# 29.7# 120' Surface 5,718' Gas-Oil Ratio:Choke Size:Water-Bbl: PRODUCTION TEST 11/14/2020 Date of Test: 0 11/26/2020 24 Flow Tubing 0 3279 Oil-Bbl: suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary 03279 Flowing **Please see attached schematic for perforation detail** 0 MWD/LWD logs, Mudlog, CBL 10-22-20, Geotap Sr Res EngSr Pet GeoSr Pet Eng N/A N/A Oil-Bbl: Water-Bbl: 00144 October 14, 2020 October 8, 2020 Private / ADL384372 LOCI 04-007 N/A N/AN/A N/A 5,733' MD / 3,879' TVD WINJ SPLUGOther Abandoned Suspended Stratigraphic Test No No (attached) No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment By Samantha Carlisle at 10:38 am, Dec 01, 2020 RBDMS HEW 12/3/2020 Completion Date 11/13/2020 HEW G gls gls 12/12/20 SFD 12/3/2020 27 bbls cmt DSR-12/14/2020 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD Top of Productive Interval Bel 135 5,460' 552' 532' 1705' 1474' 5048' 3344' 5091' 3377' 5249' 3493' 5324' 3552' 5503' 3688' 5633' 3786' Tyonek 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Cody Dinger Contact Email:cdinger@hilcorp.com Authorized Contact Phone: 777-8389 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: FORMATION TESTS Permafrost - Top ST 1 This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. Authorized Name: Monty Myers Authorized Title: Drilling Manager Bel 135 Bel 136 Permafrost - Base 29. GEOLOGIC MARKERS (List all formations and markers encountered): Yes No Well tested? Yes No 28. CORE DATA If yes, list intervals and formations tested, briefly summarizing test results. Attach separate pages to this form, if needed, and submit detailed test information, including reports, per 20 AAC 25.071. NAME T 2 Bel 134 Bel 10 Bel 115 Formation at total depth: Bel 120 Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Reports. Signature w/Date: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. INSTRUCTIONS Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. TPI (Top of Producing Interval). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment, whichever occurs first. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). No NoSidewall Cores: Yes No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2020.11.30 16:17:18 -09'00' Monty M Myers Updated by CJD 11-30-20 SCHEMATIC Ninilchik Unit Paxton #10 PTD: 220-064 API: 50-133-20691-00-00 PBTD = 5,632’ / TVD = 3,801’ TD = 5,732’ / TVD = 3,879’ RKB to GL = 17.6’ PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD FT Size Date Status Bel 135 5,460’ 5,480’ 3,673’ 3,688’ 20’ 2-7/8” 6 SPF 11/13/20 Open Bel 135 5,480’ 5,500’ 3,688’ 3,703’ 20’ 2-7/8” 6 SPF 11/13/20 Open Bel 136 5,514’ 5,520’ 3,714’ 3,718’ 6’ 2-7/8” 6 SPF 11/13/20 Open CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 DWC/C 6.875” Surf 1,522’ 4-1/2" Prod Csg 12.6 L-80 DWC/C HT 3.958” Surf 5,718’ 1 16” 7-5/8” 9-7/8” hole 4-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 1,283’ 3.958” 6.875” Swell Packer OPEN HOLE / CEMENT DETAIL 7-5/8" 102 BBL’s of cement in 9-7/8” hole – 27 BBLs Cement to Surface 4-1/2” 140 BBL’s of cement in 6-3/4” hole – zero losses during cement job 6-3/4” hole (CBL dated 10-22-20) MIT-IA to 2000 psi passed (10-28-20) TOC at approx 1400 ft. Activity Date Ops Summary 10/5/2020 Cleaned out Kalotsa 5 cellar box, removed 4" ball valves from conductor outlets, tore out three service shacks and gen#3, HandyBerm Rep on location and RD tall berm around fuel ISO, rig crew RD rig berm, moved catwalk to expose rib mats. Peak staged loader at Paxton pad and on our location at 09:00.;Held PJSM with rig crew and Peak crew, tore out boiler skid, tore out fuel ISO, sent crew to Paxton and start lay out of felt/liner, Peak staged backyard modules on Kalotsa pad. Set crane and picked choke house.;Crane picked iron roughneck off rig floor, L/D "V" door windwall, picked derrick house off board, L/D derrick windwalls. Tore out topdrive HPU. Brought in second crane, RU on derrick, picked derrick off carrier, picked carrier off sub, picked sub off pony walls. Shipped out used GeoTap tool.;Cont setting rig mats on Paxton 10, transported pony walls, mats, sub, carrier and cranes to Paxton pad. Set pony walls.;Finished setting rig mats on Paxton, set pony walls around cellar, set iron roughneck HPU & shock hoses inside pony walls, spotted cranes, trucked in sub, picked & set w/ cranes on pony walls, picked & set carrier on sub. Brought in derrick, picked, set, and pinned w/ crane.;Spotted & set w/ winch trucks- mud pit module #1, MP #1 skid, dog house/ rig water tank, gen 1&2 skid, and TD HPU. Released Peak rig movers for the night @ 23:30 hrs. Started R/U misc. electrical & HYD lines. Cont. P/U rig mats, liner & felt on Kalotsa #5.;Crew change, Held PTSM. Cont. R/U electrical, HYD, and air lines, fired gen, R/U lights on modules & roof of dog house, raised roof on pit module 1, scoped up dog house from rig water tank and extended over rig floor, hooked up mud line to from pump skid to sub, hooked up TD HPU HYD & electric lines;R/U driller counsel hoses & cables. Finished P/U liner & felt on Kalotsa #5. Cont. loading misc. equip. onto trailers & P/U trash around pad. 10/6/2020 Load service shack for transport at Kalotsa, cont loading floats with assorted equipment at Kalotsa, Peak on Paxton pad at 08:00, held PJSM, staged crane and set choke house, raised "V" door wind wall, raised derrick windwalls and set;derrick house. Set pit #2& 3 and pump skid #2, set centrifuge with crane, set iron roughneck, installed jumper hoses between pump skids, equalizers between pits, raised vacuum degasser in pit 4. Replace broken bolt in crown leg,;inspected remaining bolts (ok), ordered new set of bolts to change out remaining bolts. Stood derrick & pinned in place.;Transport shop to Paxton pad, R/D office trailer on Kalotsa #5, raised roof on pits 2&3, set boiler skid & R/U, set & bermed in aux fuel tank, set Gen #3, moved in and spotted service shacks, set, raised, and R/U poor boy gas buster. Cont.;R/U fuel, HYD, and electrical around rig, laid felt, liner, & mats for catwalk and set in place. raised V-door, craned in & installed wind walls on pits, prepped derrick to scope, installed turn buckles on TQ tube, R/U choke lines in choke house & pits,;R/U hooch over centrifuge. Set vertical water tank, cement silo, & bermed around rig. Cont. R/U shakers in pits and loading out misc. equip. on Kalotsa #5 and hauling to Paxton #10.;Spooled drill line on drum, unhung blocks, scoped derrick, R/U HYD lines to derrick, installed T-bar to TQ tube, R/U Pason cables around rig, install ed choke hose to cellar, R/U rigging to pick TD, P/U TD to rig floor, pinned blocks to;TD dog bones & hooked up compensator cylinders. Installed jumper hoses between pits & pumps, equalizers between pits, hooked water, air, & steam lines in pits and pump skid 1&2.;Held PTSM, crew change. Cont. R/U and working on rig acceptance check list. cont. R/U TD, function tested service loop/ TD robotics, R/U Gai-Tronics, installed tarp on derrick lift cylinders. Made up Kelley hose and tested for correct R/U centrifuge,;travel up and down derrick. R/U centrifuge, set up mud product dock w/ liner by boiler. Cont. hauling misc. equip from Kalotsa #5.;Hauled 0 bbls Solids to G&I Total Solids Hauled = 0 Hauled 0 bbls Trash Fluid to G&I Total Trash Fluid Hauled = 0 Hauled 0 bbls Cement to G&I Total Cement Hauled = 0 Daily Losses to Hole = 0 Total Losses to Hole = 0 10/7/2020 Cont. R/U TDS, R/U bails, link tilt, & elevator. M/U saver sub to TD & TQ to spec. Adjusted spacing on load collar of TDS. Topped off gear oil in TD and pumped up compensators, R/U & inspected tongs & slips. Performed rig service. Unfolded & dressed derrick board.;Removed shipping blocks in centrifuge, function tested pit equip. R/U Gen #3 & tested. Hooked up electrical to service shacks. prepped flow line for installation, took on water in rig tank, R/U Pason weight indicator, functioned tested iron roughneck, tested hole fill pump, R/U bleeder manifold,;dressed shakers w/ API 120 screens, organized drilling conex, brought out welder, welded handrail pin on rig floor and hinge on stairs to rig floor. R/U test pump in choke house. Installed Pason sensor on upright water tank, R/U gas alarm system & tested.;Filled accumulator w/ HYD oil, R/U Geronimo line & anchor. Trouble shot transmission reverse issue and repair same.;Set test plug, N/U DSA & surface riser to wellhead, R/U flow line, installed chains & binders to riser, hooked up drain hoses from bird baths to cellar, filled boiler w/ potable water & fired boiler. Plumbed in water line from well to rig, took on water, Hydro tested pits w/ water,;brought in spud mud. Repaired parking brake on rig loader and put back into service. Cont. working on rig acceptance check list and hauling misc. loads from Kalotsa pad to Paxton pad and organize same.;Hung tarps on sub, rig floor, pits, & TD HPU, installed long mouse hole, pulled test plug & installed 14" ID wear ring, obtained RKB's from ground level (18.15') & LDS (21.60'). Primed & commissioned MP's, pressured tested surface line to 3500 psi, R/U catwalk pipe racks.;loaded 4.5" DP on racks. strap & tally pipe, Held PJSM on P/U pipe, P/U & M/U mule shoe to first jt. of DP.;Crew change, held PTSM. Tested crown-o-matic, verified TQ values against TD, IR, Tongs, P/U DP and tagged bottom @ 128'. Accepted rig @ 00:00 hrs. Cont. P/U & 4.5" CDS-40 DP and racking back in the derrick and rabbiting pipe (2.6" Drift) and loading out misc. items on Kalotsa #5.;Hauled 0 bbls Solids to G&I Total Solids Hauled = 0 Hauled 0 bbls Trash Fluid to G&I Total Trash Fluid Hauled = 0 Hauled 0 bbls Cement to G&I Total Cement Hauled = 0 Daily Losses to Hole = 0 Total Losses to Hole = 0 18 n (LAT/LONG): evation (RKB): API #: Well Name: Field: County/State: NINU Paxton 10 Ninilchik Hilcorp Energy Company Composite Report , Alaska Contractor AFE #: AFE $: Job Name:2013111D Paxton 10 Drilling Spud Date: j Accepted rig @ 00:00 hrs. Cont. 10/8/2020 Continue P/up rabbiting and strapping 4-1/2" dp and racking back on ODS total 80 std = 4955'.;Complete rig acceptance chk list / Test Rig ESD (ok) and chk accumulator nitrogen and pre-charge and add as necessary and bleed air out of system. install rig floor heater.;Rack and strap 11 jts 4-1/2" HWDP and one jar P/up rack back same.;Service rig preform derrick inspection, load walk and strap bha # 1 and finish building dry and wet docks while moving last of equipment to Paxton pad and organizing same.;Held PJSM, M/U 9-7/8" directional BHA #1, Plugged in tool and performed confidence test (ok).;Cont. working on housekeeping around rig and prepping location for spud. Loaded out old batteries & empty nitrogen bottles, tied up cables on trailers to keep off ground, connected ground wire to conductor, painted two 40’ 3” hoses for suppling mud to cmt’s and prepped surface casing.;Up loaded MW D tools, displaced conductor to 8.7 ppg spud mud, shallow tested MWD tools (ok), held PJSM, loaded nukes, M/U first std. of HWDP and tagged bottom.;Spudded surface: Drilled first stage of 9-7/8" surface hole F/128'-T/299' to bury MWD tools. GPM-500 SPP-1350 psi RPM-60 TQ-2.5K P/U-26K S/O-29K ROT-29K.;POOH F/299'-T/115', P/U & RIH w/ second stage, flex collars, HWDP, and Jars F/115'-T/299', P/U-29K S/O-28K.;Resumed directional drilling 9-7/8" surface hole F/299'-T/427'. GPM- 550 SPP-1620 psi RPM-60 TQ-2.5K P/U-30K S/O-29K ROT-29K.;Crew change, held PTSM. Cont. directional drilling 9-7/8" surface hole F/427'-T/690'. GPM- 550 SPP-1650 psi RPM-60 TQ-5K Max gas 64 units WOB-4k Flow 46% P/U-36K S/O-35K ROT-36K.;Cont. directional drilling 9-7/8" surface hole F/690'-T/977'. CBU at current time, prepping for wiper trip. GPM-550 SPP-1870 psi RPM-60 TQ-4.4K Max gas 109 units WOB-5k Flow 47% P/U-39K S/O-37K ROT-38K Krevs-30 Distance to plan: 3.93' 2' High 3' Low.;Hauled 23 bbls Solids to G&I Total Solids Hauled = 23 Hauled 68 bbls Trash Fluid to G&I Total Trash Fluid Hauled = 68 Hauled 0 bbls Cement to G&I Total Cement Hauled = 0 Daily Losses to Hole = 0 Total Losses to Hole = 0 10/9/2020 CBU and Pooh on elevators f/ 977' t/ 240' w/ no issues.;Service rig while monitoring static hole.;Rih on elevators t/ 919' kelly up and ream last std to btm w/ no fill.;Resume drilling 9-7/8" directional hole as per DD and mwd mad passing slides @ 200 fph f/ 977' t/1552' TD of hole section up/dn/rot 41/39/40k SPP 1920psi @ 550 gpm tq @ 5k w/ max gas 70 units pump 20 bbl high vis sweep around while rotating @ 1010' back 4 bbls late w/ 10% increase.;Circ btm up for TD sample 50% clay stone and 50% sand and flow chk w/ seepage losses.;Pooh short trip t/ jars 240' with no issues, flow checked w/ slight seepage, P/U- 46K S/O-40K @1500'. Cal Hole fill=10.1 bbls Act=12.8 bbls Diff=+2.7 bbls.;Serviced rig- level derrick, cleaned & cleared rig floor, static loss rate=1.6 bph.;TIH on elevators F/240'-T/1538' w/ no issues, P/U-45K S/O-39K, Cal pipe displacement=10.1 bbls Act=23.3 bbls Diff=13.2 bbls 15 bbls to fill pipe -1.8 bbls lost for trip.;Broke circ. filled pipe, washed to bottom w/ no signs of fill, pumped 20 Hi-Vis walnut/condet sweep, had 10% increase in cuttings, sweep came back 5 bbls late. Circ. additional BU. GPM-550 SPP-1850 psi RPM-60 TQ-4K, flow check, slight seepage, pumped 10 bbl dry job 2.5lbs over MW, blew down TD.;POOH on elevators F/1552'-T/174' w/ no issues, L/D jars on the way out. P/U-45K S/O-39K.;Held PJSM on L/D BHA, L/D flex collar and removed nukes from string.;Crew change, Held PTSM. Cont. L/D BHA #1, down loaded MWD data, removed pulsar F/TM collar, L/D remaining MWD tool, milked motor, broke out bit. Bit grade- in gauge PDC- 1-1-CT-T-X-I-NO-TD Roller cone- 1-1-WT-A-E-I-NO-TD.;Cleaned & cleared rig floor, P/U test plug, BOLD's, removed wear ring, P/U and test run hanger. R/U WOTC casing equip. Load racks w/ 7-5/8" casing, stage centralizer. Static loss rate=.9 bph.;Held PJSM on running casing, P/U & M/U and Bakerlock shoe track, tested floats (ok), Cont. running 7-5/8" 29.7# L-80 DWC casing as per run tally, filling on the fly and topping off every 10 jts.;Distance to plan:17.90' 2' High 17' Right;Hauled 104 bbls Solids to G&I Total Solids Hauled = 127 Hauled 347 bbls Trash Fluid to G&I Total Trash Fluid Hauled = 415 Hauled 0 bbls Cement to G&I Total Cement Hauled = 0 Daily Losses to Hole = 16 Total Losses to Hole = 16 10/10/2020 Cont. running 7-5/8" 29.7# L-80 DWC casing as per run tally, filling on the fly and topping off every 10 jts. Tag TD @ 1556' found error in running tally L/dn jt csg and land hanger w/ shoe @ 1522'.;R/up circ swedge brk circ stage up rate t/ 6 bpm reciprocate pipe and conditioned mud for cmt, spotted cmt equipment, r/up cmt lines.;Crew chg / load plugs, install cmt head, bail extensions, and hook up lines.;PJSM flush line to cutting box and brk circ / pressure test 970 low (ok) 4000 high failed chg out valve and retested (ok) Halliburton pumped 37 bbls of 10.5 ppg spacer @ 4 bpm & dropped btm plug and mix and pump 71.5 bbls (167 SX) of 12.0 ppg lead cmt w/ 2.4lb/sx bridge maker LCM @ 4 bpm,;followed by 31 bbls (150 sx ) of 15.8 ppg tail cmt w/ .04 lb/sx of well life 1094 @ 4 bpm and dropped top plug and displaced w/ 9.1 ppg mud @ 5 bpm slowed pump @ 56 bbls/ away t/ 2 bpm and bump plug 2 bbls early @ 64 bbls away w/ FCP at 490 psi pressured up t/ 1060 had held for 3 min (ok);bled back 1/2 bbl to truck and floats held, CIP @ 14:49 hrs / 37 bbls of spacer and 27 bbls of cmt back to surface and lost 5.7 bbls throughout job. Off line finished first batch of 6% KCL PHPA mud.;Wash up cmt lines and, r/dn cmt equipment and released cmt's. R/D elevators & bail extensions, drained & flushed stack w/ black water, pulled landing jt. M/U pack of to running tool & pack off to landing jt. run in & set pack off, RILD's, tested pack off seals T/500 psi Low for 5 min & 3000 psi.;High for 15 min (ok). L/D landing jt. & pack off running tool, pulled & L/D mouse hole, laid over V-door. Cont. hauling off spud mud & cleaning pits, cont. working on building second batch of 6% KCL PHPA mud.;R/D chains, binders, & flow line from flow nipple, N/D flow nipple & DSA, cont. hauling off spud mud, cleaning pits, & building production mud.;M/U B section to well head (tubing head), and tested void T/500 psi Low for 5 min & 3000 psi High for 15 min (ok), M/U 2 spacer spool, set BOP stack inside cellar w/ crane, transferred & set BOP's on spacer spool & M/U. Installed choke & kill lines to BOP's. Finished hauling off mud & cleaning pit.;Crew change, held PTSM. Cont. N/U BOP's- TQ choke & kill lines and spacer spool flange. Installed flow box, bell nipple, riser, and flow line. Drained HYD fluid from annular, spotted Geo-span unit in cellar, M/U test jts. Installed test plug in well, energized koomey. Functioned annular and rams;R/U testing equip. flooded choke & stack w/ water, purged out air.;Started testing BOP as per AOGCC regulations to 250 Low/3500 High for 5/5 min on 4.5” & 2-7/8” test jts. State has been notified.;Hauled 54 bbls Solids to G&I Total Solids Hauled = 181 Hauled 536 bbls Trash Fluid to G&I Total Trash Fluid Hauled = 951 Hauled 27 bbls Cement to G&I Total Cement Hauled = 27 Daily Losses to Hole = 28 Total Losses to Hole = 44 p gp Halliburton pumped 37 bbls of 10.5 ppg spacer @ 4 bpm & dropped btm plug and mix and () g g () p p ppgp @ p pp p g pump 71.5 bbls (167 SX) of 12.0 ppg lead cmt w/ 2.4lb/sx bridge maker LCM @ 4 bpm,;followed by 31 bbls (150 sx ) of 15.8 ppg tail cmt w/ .04 lb/sx of well lifepp ( ) ppg g @ p y ( ) ppg 1094 @ 4 bpm and dropped top plug and displaced w/ 9.1 ppg mud @ 5 bpm slowed pump @ 56 bbls/ away t/ 2 bpm and bump plug 2 bbls early @ 64 bbls@p pp ppg p ppg @p pp@ y p ppg y@ away w/ FCP at 490 psi pressured up t/ 1060 had held for 3 min (ok);bled back 1/2 bbl to truck and floats held, CIP @ 14:49 hrs / 37 bbls of spacer and 27 bbls yppp of cmt back to surface and lost 5.7 bbls throughout job. surface cement 75/8" Cont. running 7-5/8" 29.7# L-80 DWC casing as per run tally, Continue P/up rabbiting and strapping 4-1/2" dp and racking back on ODS total 80 std = 4955'.;C p ;POOH on elevators F/1552'-T/174' w/ no issues, L/D jars on the way out. p ;Spudded surface: Drilledppg p ( ) first stage of 9-7/8" surface hole F/128'-T/299' to bury MWD tools jpggy gqp pg ;Started testing BOP as per AOGCC regulations to 250 Low/3500 High for 5/5 min on 4.5” & 2-7/8” test jts. State has been notified.;Hauled 54 bbls Solids Load racks w/ 7-5/8" casing, stage centralizer 10/11/2020 Continue testing BOP as per AOGCC regulations to 250 Low/3500 High for 5/5 min on 4.5” & 2-7/8” test jts. w/ 2 F/P chart recorder battery died on test #8 low replaced same retested (ok) & test #9 work UPR service inside manual choke valve and purge air and re tested ok.;Witness waived my Mr. Jim Regg 10-11- 2020. Mechanic traveled to rig 147 to assist w/ TD issues.;L/dn test jt pull test plug and install 9" ID wear ring fluid pack choke line and purge air and shut blinds and prep for csg test Crew change and test csg t/ 3683 psi w/ 39.1 gals on chart for 30 min t/ 3661 psi good test bled back 1/2 bbl.;finish r/up geo-span unit and test surface lines t/ 3500 psi ok / while finish houses keeping and Painting project / load walk and strap Bha #2 / Rack and strap 4-1/2 csg / safe out cellar grating and install mouse hole. Expeditor & Toolpusher traveled to CLU and staked up and coming CLU #16 well.;Held PJSM, P/U BHA #2 as per Sperry, plugged in and uploaded MWD data, shallow tested tools (ok), loaded nukes, P/U collars & Jars, TIH w/ 4.5" HWDP T/575'. P/U-29K S/O-29K.;P/U & RIH 6 jts on 4.5" DP of walk , cont. TIH on elevators F/758'-T/1379'. P/U-40K S/O-35K Cal pipe displacement=10.9 bbls Act=25 bbls fill pipe=14 bbls Diff- .1 bbls.;Broke circ. Filled pipe, started washing down F/1379', started seeing cmt strings at 1381', cont. washing down, tagged plugs at 1435', (top of FC), established drilling parameters, drilled out plugs, shoe track, and cmt F/1435'-T/1552'. GPM-250 SPP-1500 psi WOB-8K Diff-100 RPM-30 TQ-3K.;Crew change, held PTSM & weekly safety meeting w/ rig hands. Held PJSM on mud displacement, lined up and pumped 20 bbls of 9.0 ppg spacer, follow by new 6% KCL PHPA 9.0 ppg mud. Once new mud returned to surface, shut down pump and cleaned possum & under shaker.;Brought on pump & cont. circ. Sperry had issues communicating w/ there ARD tool (code 255), after cycling pumps multiple time and down linking, tool came alive.;Cont. drilling ahead 20' on new hole F/1552'- T/1572', CBU to even out MW @ 8.9 ppg. shut down pump.;R/U testing equip, purged air from lines. Performed FIT to 13.5 ppg EMW =330 psi, (ok), pumped in 6.3 gal and bled back 3.2 gal, R/D tested equip. blew down kill & choke line, and choke manifold.;Serviced rig- greased blocks, crown, TD, IR, and brake linkage. checked bolts on drive line.;Resumed directional drilling ahead to current depth of 1633'. P/U-40K S/O-32K ROT-36K GPM-298 SPP-1330 psi WOB-4K Diff-100 RPM-40 TQ-3K. Distance to plan: 17.90' 2' High 17' Right.;Hauled 0 bbls Solids to G&I Total Solids Hauled = 181 Hauled 0 bbls Trash Fluid to G&I Total Trash Fluid Hauled = 951 Hauled 0 bbls Cement to G&I Total Cement Hauled = 27 Daily Losses to Hole = 0 Total Losses to Hole = 44 10/12/2020 Continued drilling 6-3/4" directional hole f/ 1633' t/ 2183' and Mad passing slides to maintain WP #07 P/U-42K S/O-33K ROT-37K GPM-300 SPP-1530 psi WOB-4K, RPM-80 TQ-4.6K, BGG = 32, max gas 330 units, ECD @ 10.06 ppg.;Continued drilling 6-3/4" directional hole f/ 2183' t/ 2555' and Mad passing slides to maintain WP #07 P/U-53K S/O-40K ROT-44K GPM-300 SPP-1650 psi WOB-4K, RPM-80 TQ-5K, BGG = 40, max gas 933 units from beluga #43 ECD @ 10.35 ppg.;Circ. hole clean, 2X BU, GPM-300 SPP-1470 psi RPM-80 TQ-4.5K, Flow checked well, had slight seepage, recorded SPR's.;POOH on elevators F/2555'-T/1500' w/ no issues, P/U-54K S/O-40K Cal hole fill=6.7 bbls Act=8.7 bbls Diff=2 bbls.;Serviced rig- Adjusted brakes handle height, greased & inspected crown, blocks, TD, brake linkage, DWKS, drive shaft, IR, and wash pipe. Performed static flow check=1 bph loss rate.;TIH on elevators F/1500'- T/2555', washed last std. down w/ no fill on bottom. Pumped 20 bbl Hi-Vis sweep w/ walnut & condet, sweep came back on time w/ a 30% increase in cuttings. P/U-53K S/O-30K Cal pipe displacement=6.3 bbls Act=16.6 bbls Fill pipe=9.6 Diff=+.7 bbls.;Resumed directional drilling 6.75" production hole F/2555'-T/2990' P/U-53K S/O-38K ROT-44K GPM-300 SPP-1750 psi WOB-5K, RPM-80 TQ-5K, BGG = 40, max gas 745 units from beluga #53 ECD @ 10.3 ppg.;Crew change, held PTSM. Cont. directional drilling 6.75" production hole F/2990'-T/3017', pumped 20 bbl Hi-Vis sweep w/ walnut & condet maintenance sweep while drilling ahead T/3049', sweep came back on time w/ a 50% increase in cuttings.;Cont. directional drilling 6.75" production hole F/3049'-T/3545'. P/U-59K S/O- 37K ROT-45K GPM-300 SPP-1830 psi WOB-5K, RPM-80 TQ-5K, BGG = 30, max gas 587 units from Beluga #58 ECD @ 10.6 ppg.;Drilled to wiper trip depth, pumped 20 bbl Hi-Vis sweep w/ walnut & condet, sweep came back on time w/ 15% increase in cuttings. Currently flow checking and prepping for wiper trip. Distance to plan:4.00' 3.46' Low 2.0 Left.;Hauled 90 bbls Solids to G&I Total Solids Hauled = 271 Hauled 360 bbls Trash Fluid to G&I Total Trash Fluid Hauled = 1311 Hauled 0 bbls Cement to G&I Total Cement Hauled = 27 Daily Losses to Hole = 29 Total Losses to Hole = 73 10/13/2020 Obtain SPR / flow check w/ slight seepage.;Short trip OOH f/ 3548' t/ 2493' on elevators w/ no issues and .4 bbl over calculated hole displacement.;Service rig while monitor well w/ 1 bph static loss rate.;Short trip RIH t/ 3486' on elevators / ream last stand to btm @ 3548' w/ no fill and .4 under cal. pipe displacement.;Resume drilling 6-3/4" directional hole f/ 3548' t/3825' and mad passing slides to maintain WP#07 / Gpm 300, SPP 1830, RPM 80 TQ 5.5 WOB 5 up/dn/rot 59/37/44k max gas 578 units.;Continue drilling 6-3/4" directional hole f/ 3825' t/4040' and mad passing slides to maintain WP#07 / Gpm 294, SPP 1608, RPM 80 TQ 5.5 WOB 5 up/dn/rot 59/37/44k max gas 1225 units.;Preform clean up cycle / Pump 20 bbls high vis sweep while working full std and circ clean ECD @ 10.5.;Drill Ahead 6.75'' Section f/ 4040' t/ 4598' 284 gpm 1722 psi 80 rpm 7.2k tq on 6.8k tq off PUW 70k SOW 42k ROT 52k ECD 10.9 ppg MW 9.3 ppg.;Circulate bottoms up obtain sample f/ GeoLog, Obtain survey and SPR's, Flow check Well Slight seepage loss.;Make wiper trip f/ 4598' t/ 3525' with no hole issues.;Service rig and top drive, inspect draworks, monitor well on trip tank 1.4bph loss rate.;RIH f/ 3525' t/ 4598' No issues.;Circulate Hi Vis Sweep around hole unloaded on bottoms up and when sweep came back cuttings increased 20% and sweep was back on time ECD start 11.08 ppg after 10.6 ppg.;Drilling Ahead f/ 4598' t/ 4920' 284 gpm 1707 psi 80 rpm 7.9k tq on 7k tq off PUW 70k SOW 40k ROT 58k Distance to plan 3.96' 3.89' Low .74' Right.;Hauled 67.5 bbls Solids to G&I Total Solids Hauled = 338 Hauled 202.5 bbls Trash Fluid to G&I Total Trash Fluid Hauled = 1513 Hauled 0 bbls Cement to G&I Total Cement Hauled = 27 Daily Losses to Hole = 43 Total Losses to Hole = 115.6 FIT to 13.5 ppg gg lines. Performed FIT to 13.5 ppg EMW =330 psi, (ok), Continued drilling 6-3/4" directional hole f/ 1633' t/ 2183' and Mad passing slides pg ;Drill Ahead 6.75'' Section f/ 4040' t/ 4598' 284 gjppg Crew change and test csg t/ 3683 psi w/ 39.1 gals on chart for 30 min 10/14/2020 Continue Drilling 6-3/4" directional hole f/ 4920' t/ 5092' 285 gpm 1970 psi 80 rpm 8.4k tq on 8.8k tq off PUW 78k SOW 42k ROT 54k ECD 10.91 w/ 9.3 MW.;Preform clean up cycle by rotating and reciprocating and Circ btm up and pumping 20 bbl high vis sweep around back 7 bbls early w/ 10% increase continue circ clean X3 btm up w/ ECD dn to 10.8 ppg.;Resume drilling ahead f/ 5092' t/ TD @ 5732' w/ slides as necessary to maintain WP #7 and mad passing same / 285 gpm 2000 psi 80 rpm 11.4tq on 10k tq off PUW 100k SOW 50k ROT 64k ECD 10.91 w/ 9.3 MW.;Circ btm up obtain sample pump 20 bbl sweep around back 4 bbls early w/ 20% increase / circ clean / SPR and flow chk w/ seepage losses, circulate until shakers cleaned up, obtain survey and SPR's.;POOH on elevators f/ 5732' t/ 1843' w/ no issues.;Circulate bottoms up 250 gpm 1171 psi.;POOH on elevators f/ 1843' t/ 1520' w/ no issues.;Service rig and top drive, grease and inspect draworks.;RIH on elevators f/ 1520' t/ 5732'.;Pump Hi Vis sweep around back on time 10% increase in cuttings add lubes to active system.;Begin Geo tapping stations as per MWD and GEO #1 5538', #2 5494', #3 5450', #4 5421'.;Hauled 49.5 bbls Solids to G&I Total Solids Hauled = 387.5 Hauled 220.5 bbls Trash Fluid to G&I Total Trash Fluid Hauled = 1733.5 Hauled 0 bbls Cement to G&I Total Cement Hauled = 27 Daily Losses to Hole = 42 Total Losses to Hole = 157.6 10/15/2020 Continue Pooh mad passing and tieing in and Geo tapping stations as per MWD and GEO's Priority list #5 @ 5514 md , #6 @ 5466' md, #7 @ 5427' md, #8 @ 5371' md, #9 @ 5290'md, #10 @ 5261' md, #11 @ 5192' md, #12 @ 5115' md, #13 @ 5047' md;#14 @ 5012' md.;Continue Mad passing and geo tapping stations 14 - 23 as per MWD/Geo.;Continue Mad passing and geo tapping stations 24 - 31 as per MWD/ Geo.;Continue Mad passing and geo tapping stations 31 - 39.;Hauled 14 bbls Solids to G&I Total Solids Hauled = 401.5 Hauled 166 bbls Trash Fluid to G&I Total Trash Fluid Hauled = 1899.5 Hauled 0 bbls Cement to G&I Total Cement Hauled = 27 Daily Losses to Hole = 20 Total Losses to Hole = 177.6 10/16/2020 Continue Pooh mad passing and tieing in and Geo tapping stations as per MWD and GEO's Priority list f/ station #39 t/ station #46 w/ total of 58 test taken w/ no issue.;Pull into shoe t/ 1501' service rig while monitoring static well w/ no losses.;Rih f/ 1501 t/ 3255' w/ no issue.;Fill pipe brk circ stage up rate t/ 244 gpm @ 1270 psi and circ STS and warm mud.;Resume rih t/ 5702' fill pipe ream dn last jt tag TD w/ no fill @ 5732'.;Circ btm up pump 20 bbl sweep around Back 4 bbls late w/ 10% increase circ shakers clean, flow check well slight seepage, pump dry job.;POOH L/D 4.5'' DP Via Mouse hole f/ 5732' t/ 575' dropping wiper balls through every jt and installing thread protectors.;L/D BHA Via mouse hole, Unload sources and Download MWD, clean and clear floor.;Hauled 17 bbls Solids to G&I Total Solids Hauled = 418.5 Hauled 423 bbls Trash Fluid to G&I Total Trash Fluid Hauled = 2322.5 Hauled 0 bbls Cement to G&I Total Cement Hauled = 27 Daily Losses to Hole = 20 Total Losses to Hole = 177.6 10/17/2020 Finish l/dn and chking bha #2 bit graded 1-1-WT-A-X-I-NO-TD ( Mtr did have good 1/4" or more slop in thrust and throw).;Clean and clear rig floor / Pull wear ring / dummy run and mark hanger.;R/up casers and prep to run csg.;PJSM p/up 12.6# L-80 4-1/2" csg shoe track baker lok and chk same (ok) Continue run csg / installing centralizers and R/A marker jts as per drillers running tally / filling on the fly and topping off every 10 t/ 1483'.;Fill pipe brk circ circ btm/up establish parameters Up/Dn/Rot all =23k 10-rpm =1450k / 20 rpm = 2100k / 30 rpm = 2230k.;Resume Running 4-1/2" csg as per drillers running tally f/ 1483' t/3294' installing centralizers and R/A marker jts as per drillers running tally / filling on the fly and topping off every 10.;Brk circ Pump csg volume.;Resume Running 4-1/2" csg as per drillers running tally f/ 3294' ' t/5732'' installing centerlizers and R/A marker jts and swell prk as per drillers running tally / filling on the fly and topping off every 10 / P/up hanger and landing jt and land hander w/ shoe @ 5718'.;fill pipe brk circ and stage up rate t/ 6 bpm @ 330 psi while r/up cmters.;R/U Halliburton Cement Commander Plug Launcher, and circulating equipment, circulate through top drive while holding PJSM.;MU plug launcher and hardline, Halliburton loaded lines with 5 bbls water and checked for leaks. Halliburton pressure tested lines at 700 low 4200 high, good tests. Halliburton pumped 35 bbls 10.5 ppg Spacer at 4 bpm and shut down. Halliburton dropped bottom plug and pumped 124 bbls (280 sx) 12 ppg;Type 1 II lead cement at 4.7 bpm, followed by 16 bbls (75 sx) 15.3 ppg Premium G tail cement at 3 bpm. Halliburton dropped top plug, then displaced with 85 bbls 9.3 ppg 6% KCL PHPA at 5 bpm. Slowed to 3 bpm with 20 bbl to go. Did bump the plug 85 bbls into displacement (calculated 85.6 bbls),;held 1400 psi (FCP of 930 psi) for 3 minutes, bled off and floats held. Bled back .5 bbls to truck. Had 13 bbls Spacer returns to surface and 0 bbls lead cement to surface. Added LCM to lead cement at 4.7 ppb. Mix water at 72° Pumped 20 excess on both lead and tail. Lost 0 bbls during job.;Reciprocate pipe till mud displacement. CIP at 12:15, 10-18-20. RD and released Halliburton.;R/D Cement head and circulating equipment, Halliburton washing up to box, L/D all circulating equipment f / floor and L/D plug Launcher, Pull landing jt set and test pack off 250 low 5000 high.;Load racks w/ 2 7/8'' Work String, strap and tally, R/U rig floor handling equipment, R/U Weatherford.;M/U Scraper Assembly RIH t/ 554'.;Hauled 0 bbls Solids to G&I Total Solids Hauled = 418.5 Hauled 180 bbls Trash Fluid to G&I Total Trash Fluid Hauled = 2502.5 Hauled 0 bbls Cement to G&I Total Cement Hauled = 27 Daily Losses to Hole = 20 Total Losses to Hole = 177.6 gjp Running 4-1/2" csg as per drillers running tally f/ 3294' ' t/5732'' TD @ 5732 ft gp)g ;PJSM p/up 12.6# L-80 4-1/2" csg shoe track baker lok and chk same gpppgg ;Resume drilling ahead f/ 5092' t/ TD @ 5732' Continue Drilling 6-3/4" directional hole f/ 4920' t/ 5092' 285 gpm cement 41/2"CSG gqp g p g pg Halliburton pressure tested lines at 700 low 4200 high, good tests. Halliburton pumped p gg p 35 bbls 10.5 ppg Spacer at 4 bpm and shut down. Halliburton dropped bottom plug and pumped 124 bbls (280 sx) 12 ppg;Type 1 II lead cement at 4.7 bpm, ppg p p pp p g p p ( ) ppg yp p followed by 16 bbls (75 sx) 15.3 ppg Premium G tail cement at 3 bpm. Halliburton dropped top plug, then displaced with 85 bbls 9.3 ppg 6% KCL PHPA at 5 y ( ) ppg p pp p p g p ppg bpm. Slowed to 3 bpm with 20 bbl to go. Did bump the plug 85 bbls into displacement (calculated 85.6 bbls),;held 1400 psi (FCP of 930 psi) for 3 minutes, bled ppgppgp( ) off and floats held. Bled back .5 bbls to truck. Had 13 bbls Spacer returns to surface and 0 bbls lead cement to surface 10/18/2020 Continue single in hole w/ Bha #3 Scraper Assembly rabbiting and strapping 2-7/8" PH-6 work string f/ 554' t/ 5603' circ 2x STS while strapping rack of pipe @ 2590' Kelly up attempt brk circ pressure to high for 5-1/2" liners kept killing pump mtr.;Service rig and chg MP#2 t/ 5" liners.;Brk circ wash dn f/ 5603' t/ Tag @ 5620' confirm tag +-9' shallow from casing tally.;Pump spacer and chg well over to 6% KCL brine @ 164 gpm @ 1884 psi.;POOH L/ D2 7/8'' Work String.;Clean and clear floor, R/D Weatherford casing running equipment.;R/U and test Casing t/ 3500 psi f/ 30 min on chart, good test 44 gal to pressure up 41 gal bled back.;Drain stack and flush lines, flush and blow down choke manifold and mud lines, remove Geo Span unit f/ cellar, set BPV as per wellhead hand.;N/D flow line, choke and kill lines, flow box and riser, hook up bridge cranes and remove spool and stack from wellhead, trolley stack out of the way, P/U tree and clean API ring grooves.;N/U tree, tighten bolts, fill and test void t/ 250/5000 psi, continue sucking out and cleaning pits, begin rigging down rig components, strip rig floor handling equipment.;Total Solids Hauled = 418.5 Hauled 180 bbls Trash Fluid to G&I Total Trash Fluid Hauled = 2502.5 Hauled 0 bbls Cement to G&I Total Cement Hauled = 27 Daily Losses to Hole = 20 Total Losses to Hole = 177.6 Activity Date Ops Summary 10/22/2020 Sign in at Pax. PTW and JSA. Spot equipment and lubricator. PT lubricator to 250 psi low and 3000 psi high.,RIH with CBL tool and tie into OHL. Tag at 5620'. Logged up to 400'. Found good TOC at 1440'.,Rig down and secure well. Take crane over to Pax 3 to make sure we can pull well house tomorrow. 11/11/2020 Safety discussion with crew regarding staging equipment in dark, RU and testing of BOP.,Move in and rig up coil unit,Test BOP per Sundry. Test to 250 psi low / 4000 psi high. Witness waived by AOGCC.,Prepare location for operations in am. Secure location. 11/12/2020 Prep for making up BHA. MU nozzle BHA and stab on. Pressure test lubricator.,Strap tank, 19 bbls. RIH with Nozzle BHA to 5600', PBTD at 5609'. Begin displacement with Nitrogen from 5600', slowly pick up and stage nozzle at 5590' md coil depth. Tank strap at 65 bbls, begin to slowly pick up while displacing. Pull to 200', run back to bottom. Returns diminished. Calculated well volume 85 bbls, tank strap at end 105 bbls. Pressure left on well 2050 psi.,Pop off, begin rig down. stage equipment over to Paxton 2 while rigging down. 11/13/2020 PTW and JSA. SIMOPS w/SLB Coil tubing, Spot equipment and rig up lubricator. PT to 250 psi low and 4000 psi high. TP - 2000 psi,RIH w/Gun # 1, 2-7/8"x6' HC Razor, 6 spf, 60 deg phase, tie into OHL. and tag at 5620'. Ran correlation log and send to town. Told to shift log down 3'. Shifted log down and spotted gun from 5514' to 5520'. Bled tubing from 2000 psi to 321.6 psi. Fired gun with 321.6 psi. After 5, 10 and 15 min pressure was 322.3 psi. All shots/Gun dry.,RIH w/Gun #2, 2- 7/8"x20' HC Razor, 6 spf, 60 deg phase and tie into OHL. Ran correlation log and send to town. Get ok to perf from 5480' to 5500'. Spotted and fired gun with 324.5 psi. After 5 min - 333.7 psi, 10 min - 338.7 psi and 15 min - 340.5 psi. POOH All shots fired/Gun Dry.,RIH w/Gun #3, 2-7/8"x20' HC Razor, 6 spf, 60 deg phase and tie into OHL. Ran correlation log and send to town. Get ok to perf from 5460' to 5480'. Spotted and fired gun with 344.2 psi on tubing. After 5 min - 346.2 psi, 10 min - 346.5 psi and 15 min - 346.4 psi. POOH. All shots fired and gun dry.,Rig off well and turn it over to field to flow. 11/14/2020 PTW and JSA. Well came alive overnight. Making 1.8MM at ~12% open. Decision was made to bump open the choke some and test for a couple days. Re-head AKE-Line wireline. Check equipment. Will leave equipment staged for a couple days to see how well it performs. n (LAT/LONG): evation (RKB): API #: Well Name: Field: County/State: NINU Paxton 10 Ninilchik Hilcorp Energy Company Composite Report , Alaska Contractor AFE #: AFE $: Job Name:2013111C Paxton 10 Completion Spud Date: ,RIH with CBL tool and tie into OHL. Tag at 5620'.gpqp Logged up to 400'. Found good TOC at 1440'., Making 1.8MM at ~12% open. pgp g g g gpg 5514' to 5520'. Bled tubing from 2000 psi to 321.6 psi. Fired gun with 321.6 psi. After 5, 10 and 15 min pressure was 322.3 psi. All shots/Gun dry.,RIH w/Gun #2, 2- CBL 3 gun runs N 2 discplace w/ CT CBL . Begin pgp p displacement with Nitrogen from 5600', slowly pick up and stage nozzle at 5590' md coil depth. COMPLETION REPORTS Sundry 320-449 15 October, 2020 Ninilchik Unit Paxton Paxton #10 501332069100 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Ninilchik Unit Paxton Halliburton Definitive Survey Report Well: Wellbore: Paxton #10 Paxton #10 Survey Calculation Method:Minimum Curvature Actual @ 166.00usft (HEC 169) Design:Paxton #10 Database:NORTH US + CANADA MD Reference:Actual @ 166.00usft (HEC 169) North Reference: Well Paxton #10 True Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Ninilchik Unit Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: Paxton #10 usft usft 0.00 0.00 2,230,394.876 206,284.253 148.40Wellhead Elevation:usft0.50 60° 5' 43.697 N 151° 36' 33.224 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) Paxton #10 Model NameMagnetics BGGM2020 8/25/2020 14.42 72.93 54,908.45817483 Phase:Version: Audit Notes: Design Paxton #10 1.0 ACTUAL Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:17.60 18.050.000.0017.60 From (usft) Survey Program DescriptionTool NameSurvey (Wellbore) To (usft) Date 10/15/2020 Survey Date 3_MWD+IFR1+MS+Sag A010Mb: IFR dec & multi-station analysis + sag140.66 1,499.90 Paxton #10 MWD+IFR1+MS+Sag (1) (Pa 09/30/2020 3_MWD+IFR1+MS+Sag A010Mb: IFR dec & multi-station analysis + sag1,587.36 5,696.90 Paxton #10 MWD+IFR1+MS+Sag (2) (Pa 10/12/2020 MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 17.60 0.00 0.00 17.60 0.00 0.00-148.40 2,230,394.88 206,284.25 0.00 0.00 UNDEFINED 140.66 0.70 93.98 140.66 -0.05 0.75-25.34 2,230,394.81 206,285.00 0.57 0.18 3_MWD+IFR1+MS+Sag (1) 201.20 1.12 92.98 201.19 -0.11 1.7135.19 2,230,394.73 206,285.96 0.69 0.43 3_MWD+IFR1+MS+Sag (1) 265.05 2.72 67.42 265.00 0.44 3.7399.00 2,230,395.23 206,287.99 2.78 1.58 3_MWD+IFR1+MS+Sag (1) 327.43 5.26 59.71 327.23 2.45 7.57161.23 2,230,397.14 206,291.88 4.15 4.68 3_MWD+IFR1+MS+Sag (1) 388.77 6.88 51.15 388.22 6.17 12.86222.22 2,230,400.74 206,297.26 3.02 9.85 3_MWD+IFR1+MS+Sag (1) 448.25 7.64 41.44 447.23 11.37 18.25281.23 2,230,405.80 206,302.77 2.42 16.47 3_MWD+IFR1+MS+Sag (1) 511.11 8.26 38.39 509.48 18.05 23.82343.48 2,230,412.34 206,308.50 1.19 24.54 3_MWD+IFR1+MS+Sag (1) 572.89 9.71 37.05 570.50 25.68 29.71404.50 2,230,419.83 206,314.58 2.37 33.63 3_MWD+IFR1+MS+Sag (1) 634.83 11.38 36.23 631.39 34.78 36.47465.39 2,230,428.76 206,321.56 2.71 44.37 3_MWD+IFR1+MS+Sag (1) 696.32 13.34 35.42 691.46 45.46 44.17525.46 2,230,439.24 206,329.52 3.20 56.91 3_MWD+IFR1+MS+Sag (1) 758.07 14.93 34.46 751.34 57.82 52.80585.34 2,230,451.39 206,338.45 2.60 71.34 3_MWD+IFR1+MS+Sag (1) 819.73 17.61 34.55 810.52 72.06 62.59644.52 2,230,465.39 206,348.58 4.35 87.90 3_MWD+IFR1+MS+Sag (1) 10/15/2020 3:29:07PM COMPASS 5000.15 Build 91E Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Ninilchik Unit Paxton Halliburton Definitive Survey Report Well: Wellbore: Paxton #10 Paxton #10 Survey Calculation Method:Minimum Curvature Actual @ 166.00usft (HEC 169) Design:Paxton #10 Database:NORTH US + CANADA MD Reference:Actual @ 166.00usft (HEC 169) North Reference: Well Paxton #10 True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 881.53 20.24 35.18 868.97 88.50 74.05702.97 2,230,481.54 206,360.44 4.27 107.08 3_MWD+IFR1+MS+Sag (1) 942.32 23.00 35.99 925.48 106.70 87.09759.48 2,230,499.43 206,373.91 4.57 128.44 3_MWD+IFR1+MS+Sag (1) 1,005.50 25.27 34.51 983.14 127.81 101.99817.14 2,230,520.16 206,389.32 3.72 153.12 3_MWD+IFR1+MS+Sag (1) 1,067.91 27.59 32.82 1,039.02 150.93 117.37873.02 2,230,542.90 206,405.26 3.91 179.87 3_MWD+IFR1+MS+Sag (1) 1,128.98 30.90 31.33 1,092.30 176.22 133.19926.30 2,230,567.80 206,421.69 5.55 208.81 3_MWD+IFR1+MS+Sag (1) 1,190.56 34.91 28.51 1,143.99 205.22 149.83977.99 2,230,596.39 206,439.04 6.97 241.55 3_MWD+IFR1+MS+Sag (1) 1,252.55 38.24 26.97 1,193.77 237.92 167.001,027.77 2,230,628.66 206,457.00 5.57 277.95 3_MWD+IFR1+MS+Sag (1) 1,314.22 42.64 24.98 1,240.70 273.88 184.491,074.70 2,230,664.18 206,475.36 7.43 317.56 3_MWD+IFR1+MS+Sag (1) 1,376.07 45.51 22.69 1,285.13 313.23 201.851,119.13 2,230,703.10 206,493.67 5.31 360.36 3_MWD+IFR1+MS+Sag (1) 1,437.81 48.76 20.02 1,327.13 355.37 218.301,161.13 2,230,744.83 206,511.14 6.14 405.53 3_MWD+IFR1+MS+Sag (1) 1,499.90 50.78 16.66 1,367.23 400.36 233.191,201.23 2,230,789.44 206,527.12 5.26 452.91 3_MWD+IFR1+MS+Sag (1) 1,587.36 52.63 15.47 1,421.43 466.32 252.171,255.43 2,230,854.92 206,547.71 2.37 521.51 3_MWD+IFR1+MS+Sag (2) 1,650.19 53.43 14.92 1,459.22 514.76 265.331,293.22 2,230,903.03 206,562.04 1.45 571.64 3_MWD+IFR1+MS+Sag (2) 1,711.39 54.25 14.55 1,495.33 562.55 277.901,329.33 2,230,950.49 206,575.76 1.43 620.97 3_MWD+IFR1+MS+Sag (2) 1,773.37 54.87 14.35 1,531.27 611.45 290.501,365.27 2,230,999.07 206,589.55 1.03 671.37 3_MWD+IFR1+MS+Sag (2) 1,834.98 54.32 17.01 1,566.97 659.79 304.061,400.97 2,231,047.07 206,604.29 3.63 721.53 3_MWD+IFR1+MS+Sag (2) 1,897.02 54.78 17.53 1,602.95 708.05 319.071,436.95 2,231,094.95 206,620.46 1.01 772.07 3_MWD+IFR1+MS+Sag (2) 1,958.85 56.95 16.48 1,637.64 756.99 334.031,471.64 2,231,143.51 206,636.61 3.78 823.23 3_MWD+IFR1+MS+Sag (2) 2,020.14 57.39 16.38 1,670.87 806.39 348.591,504.87 2,231,192.53 206,652.38 0.73 874.71 3_MWD+IFR1+MS+Sag (2) 2,082.77 58.03 15.96 1,704.33 857.24 363.341,538.33 2,231,243.01 206,668.35 1.17 927.63 3_MWD+IFR1+MS+Sag (2) 2,145.68 58.56 15.79 1,737.39 908.72 377.981,571.39 2,231,294.12 206,684.24 0.87 981.11 3_MWD+IFR1+MS+Sag (2) 2,208.08 59.21 16.10 1,769.64 960.08 392.651,603.64 2,231,345.11 206,700.16 1.13 1,034.50 3_MWD+IFR1+MS+Sag (2) 2,270.32 59.92 15.30 1,801.16 1,011.74 407.171,635.16 2,231,396.40 206,715.94 1.59 1,088.11 3_MWD+IFR1+MS+Sag (2) 2,331.97 60.51 15.10 1,831.79 1,063.38 421.201,665.79 2,231,447.68 206,731.22 1.00 1,141.55 3_MWD+IFR1+MS+Sag (2) 2,394.79 61.29 15.21 1,862.34 1,116.36 435.551,696.34 2,231,500.30 206,746.86 1.25 1,196.37 3_MWD+IFR1+MS+Sag (2) 2,457.10 59.37 16.47 1,893.18 1,168.44 450.321,727.18 2,231,552.00 206,762.89 3.55 1,250.47 3_MWD+IFR1+MS+Sag (2) 2,517.99 59.81 16.69 1,924.00 1,218.77 465.311,758.00 2,231,601.95 206,779.10 0.79 1,302.96 3_MWD+IFR1+MS+Sag (2) 2,579.67 60.39 16.24 1,954.75 1,270.05 480.461,788.75 2,231,652.85 206,795.49 1.13 1,356.41 3_MWD+IFR1+MS+Sag (2) 2,642.06 61.19 16.10 1,985.20 1,322.35 495.631,819.20 2,231,704.76 206,811.93 1.30 1,410.84 3_MWD+IFR1+MS+Sag (2) 2,703.99 58.95 16.40 2,016.10 1,373.87 510.641,850.10 2,231,755.91 206,828.19 3.64 1,464.48 3_MWD+IFR1+MS+Sag (2) 2,766.65 59.19 16.55 2,048.30 1,425.42 525.891,882.30 2,231,807.06 206,844.69 0.43 1,518.21 3_MWD+IFR1+MS+Sag (2) 2,828.71 60.21 16.15 2,079.61 1,476.83 540.971,913.61 2,231,858.09 206,861.02 1.74 1,571.77 3_MWD+IFR1+MS+Sag (2) 2,891.42 61.12 16.19 2,110.33 1,529.34 556.191,944.33 2,231,910.21 206,877.52 1.45 1,626.41 3_MWD+IFR1+MS+Sag (2) 2,953.20 61.70 15.93 2,139.90 1,581.47 571.201,973.90 2,231,961.96 206,893.79 1.01 1,680.62 3_MWD+IFR1+MS+Sag (2) 3,014.73 59.30 16.34 2,170.20 1,632.91 586.082,004.20 2,232,013.03 206,909.91 3.94 1,734.14 3_MWD+IFR1+MS+Sag (2) 3,075.80 59.63 16.29 2,201.22 1,683.39 600.862,035.22 2,232,063.13 206,925.92 0.54 1,786.72 3_MWD+IFR1+MS+Sag (2) 3,138.58 58.30 17.38 2,233.59 1,734.87 616.432,067.59 2,232,114.23 206,942.74 2.59 1,840.49 3_MWD+IFR1+MS+Sag (2) 3,200.95 58.88 17.11 2,266.09 1,785.71 632.212,100.09 2,232,164.66 206,959.75 1.00 1,893.72 3_MWD+IFR1+MS+Sag (2) 3,263.82 59.73 16.81 2,298.19 1,837.42 647.982,132.19 2,232,215.97 206,976.78 1.41 1,947.77 3_MWD+IFR1+MS+Sag (2) 3,325.51 60.60 16.75 2,328.88 1,888.66 663.432,162.88 2,232,266.82 206,993.47 1.41 2,001.27 3_MWD+IFR1+MS+Sag (2) 10/15/2020 3:29:07PM COMPASS 5000.15 Build 91E Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Ninilchik Unit Paxton Halliburton Definitive Survey Report Well: Wellbore: Paxton #10 Paxton #10 Survey Calculation Method:Minimum Curvature Actual @ 166.00usft (HEC 169) Design:Paxton #10 Database:NORTH US + CANADA MD Reference:Actual @ 166.00usft (HEC 169) North Reference: Well Paxton #10 True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 3,387.10 61.15 16.32 2,358.86 1,940.23 678.742,192.86 2,232,318.01 207,010.03 1.08 2,055.05 3_MWD+IFR1+MS+Sag (2) 3,448.43 61.90 16.26 2,388.10 1,991.98 693.862,222.10 2,232,369.37 207,026.41 1.23 2,108.94 3_MWD+IFR1+MS+Sag (2) 3,511.30 59.63 16.03 2,418.80 2,044.67 709.122,252.80 2,232,421.68 207,042.94 3.62 2,163.77 3_MWD+IFR1+MS+Sag (2) 3,572.32 59.87 15.60 2,449.54 2,095.39 723.482,283.54 2,232,472.03 207,058.54 0.72 2,216.44 3_MWD+IFR1+MS+Sag (2) 3,634.60 60.59 15.37 2,480.46 2,147.49 737.922,314.46 2,232,523.76 207,074.23 1.20 2,270.44 3_MWD+IFR1+MS+Sag (2) 3,696.08 61.21 14.88 2,510.36 2,199.35 751.932,344.36 2,232,575.26 207,089.51 1.23 2,324.09 3_MWD+IFR1+MS+Sag (2) 3,758.63 59.13 15.42 2,541.47 2,251.72 766.112,375.47 2,232,627.27 207,104.96 3.41 2,378.28 3_MWD+IFR1+MS+Sag (2) 3,819.53 59.07 18.04 2,572.75 2,301.76 781.152,406.75 2,232,676.93 207,121.21 3.69 2,430.52 3_MWD+IFR1+MS+Sag (2) 3,880.88 59.80 17.81 2,603.95 2,352.02 797.412,437.95 2,232,726.78 207,138.69 1.23 2,483.34 3_MWD+IFR1+MS+Sag (2) 3,942.29 60.56 17.26 2,634.49 2,402.82 813.462,468.49 2,232,777.18 207,155.97 1.46 2,536.62 3_MWD+IFR1+MS+Sag (2) 4,003.61 61.29 16.98 2,664.29 2,454.04 829.242,498.29 2,232,827.99 207,172.99 1.26 2,590.20 3_MWD+IFR1+MS+Sag (2) 4,065.54 62.19 16.66 2,693.61 2,506.25 845.022,527.61 2,232,879.81 207,190.04 1.52 2,644.74 3_MWD+IFR1+MS+Sag (2) 4,127.46 59.77 16.31 2,723.65 2,558.17 860.392,557.65 2,232,931.34 207,206.66 3.94 2,698.86 3_MWD+IFR1+MS+Sag (2) 4,189.82 57.31 16.38 2,756.19 2,609.21 875.352,590.19 2,232,982.00 207,222.87 3.95 2,752.03 3_MWD+IFR1+MS+Sag (2) 4,251.19 54.97 16.60 2,790.38 2,658.07 889.822,624.38 2,233,030.49 207,238.52 3.82 2,802.97 3_MWD+IFR1+MS+Sag (2) 4,313.48 52.59 17.30 2,827.18 2,706.14 904.462,661.18 2,233,078.19 207,254.33 3.93 2,853.21 3_MWD+IFR1+MS+Sag (2) 4,375.35 50.92 17.27 2,865.48 2,752.53 918.902,699.48 2,233,124.22 207,269.89 2.70 2,901.79 3_MWD+IFR1+MS+Sag (2) 4,437.61 48.49 17.09 2,905.74 2,797.90 932.932,739.74 2,233,169.23 207,285.02 3.91 2,949.27 3_MWD+IFR1+MS+Sag (2) 4,499.94 46.75 16.48 2,947.75 2,841.98 946.222,781.75 2,233,212.97 207,299.39 2.88 2,995.30 3_MWD+IFR1+MS+Sag (2) 4,561.66 45.20 17.34 2,990.65 2,884.44 959.132,824.65 2,233,255.10 207,313.32 2.70 3,039.67 3_MWD+IFR1+MS+Sag (2) 4,622.37 43.40 16.95 3,034.10 2,924.95 971.632,868.10 2,233,295.30 207,326.80 3.00 3,082.06 3_MWD+IFR1+MS+Sag (2) 4,684.76 41.53 16.79 3,080.12 2,965.26 983.852,914.12 2,233,335.30 207,340.01 3.00 3,124.17 3_MWD+IFR1+MS+Sag (2) 4,746.86 39.26 16.64 3,127.41 3,003.80 995.432,961.41 2,233,373.54 207,352.52 3.66 3,164.40 3_MWD+IFR1+MS+Sag (2) 4,808.45 39.33 15.69 3,175.07 3,041.26 1,006.293,009.07 2,233,410.73 207,364.28 0.98 3,203.38 3_MWD+IFR1+MS+Sag (2) 4,871.54 38.90 16.72 3,224.03 3,079.48 1,017.393,058.03 2,233,448.67 207,376.32 1.24 3,243.16 3_MWD+IFR1+MS+Sag (2) 4,933.35 38.66 16.35 3,272.21 3,116.59 1,028.413,106.21 2,233,485.50 207,388.24 0.54 3,281.86 3_MWD+IFR1+MS+Sag (2) 4,994.88 38.76 15.83 3,320.22 3,153.56 1,039.083,154.22 2,233,522.20 207,399.80 0.55 3,320.32 3_MWD+IFR1+MS+Sag (2) 5,057.28 40.71 16.90 3,368.21 3,191.83 1,050.323,202.21 2,233,560.18 207,411.97 3.31 3,360.19 3_MWD+IFR1+MS+Sag (2) 5,120.13 40.58 16.11 3,415.90 3,231.08 1,061.953,249.90 2,233,599.14 207,424.55 0.84 3,401.11 3_MWD+IFR1+MS+Sag (2) 5,183.11 40.84 16.05 3,463.64 3,270.55 1,073.333,297.64 2,233,638.32 207,436.89 0.42 3,442.17 3_MWD+IFR1+MS+Sag (2) 5,244.44 40.83 17.45 3,510.04 3,308.95 1,084.893,344.04 2,233,676.43 207,449.38 1.49 3,482.26 3_MWD+IFR1+MS+Sag (2) 5,306.37 41.20 17.44 3,556.77 3,347.73 1,097.073,390.77 2,233,714.89 207,462.50 0.60 3,522.90 3_MWD+IFR1+MS+Sag (2) 5,368.10 41.74 17.00 3,603.02 3,386.77 1,109.173,437.02 2,233,753.63 207,475.55 0.99 3,563.77 3_MWD+IFR1+MS+Sag (2) 5,430.53 40.19 17.55 3,650.16 3,425.85 1,121.323,484.16 2,233,792.41 207,488.65 2.55 3,604.69 3_MWD+IFR1+MS+Sag (2) 5,491.95 40.31 16.76 3,697.04 3,463.77 1,133.033,531.04 2,233,830.03 207,501.27 0.85 3,644.37 3_MWD+IFR1+MS+Sag (2) 5,554.42 40.87 16.59 3,744.48 3,502.71 1,144.693,578.48 2,233,868.67 207,513.88 0.91 3,685.01 3_MWD+IFR1+MS+Sag (2) 5,616.30 40.93 16.90 3,791.25 3,541.51 1,156.363,625.25 2,233,907.17 207,526.49 0.34 3,725.51 3_MWD+IFR1+MS+Sag (2) 5,696.90 40.92 16.23 3,852.15 3,592.11 1,171.413,686.15 2,233,957.40 207,542.77 0.54 3,778.29 3_MWD+IFR1+MS+Sag (2) 5,733.00 40.92 16.23 3,879.43 3,614.82 1,178.023,713.43 2,233,979.93 207,549.93 0.00 3,801.93 PROJECTED to TD 10/15/2020 3:29:07PM COMPASS 5000.15 Build 91E Page 4 5,733.00 40.92 16.23 3,879.43 3,614.82 1,178.02 2,233,979.93 207,549.93 0.00 3,801.93 PROJECTED to TD Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Ninilchik Unit Paxton Halliburton Definitive Survey Report Well: Wellbore: Paxton #10 Paxton #10 Survey Calculation Method:Minimum Curvature Actual @ 166.00usft (HEC 169) Design:Paxton #10 Database:NORTH US + CANADA MD Reference:Actual @ 166.00usft (HEC 169) North Reference: Well Paxton #10 True Approved By:Checked By:Date: 10/15/2020 3:29:07PM COMPASS 5000.15 Build 91E Page 5 Chelsea Wright Digitally signed by Chelsea Wright Date: 2020.10.15 12:33:27 -08'00'Benjamin Hand Digitally signed by Benjamin Hand Date: 2020.10.15 13:37:19 -08'00' TD Shoe Depth: PBTD: No. Jts. Returned Jts. 2 34 Yes X No X Yes No 30 Fluid Description: Liner hanger Info (Make/Model):Liner top Packer?: Yes No Liner hanger test pressure:X Yes No Centralizer Placement: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp: X Yes No Casing Rotated? Yes X No Reciprocated?X Yes No % Returns during job Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: Cmt returned to surface: Calculated cement left in wellbore: OH volume Calculated: OH volume actual: Actual % Washout: Type 1 II 167 2.4 Class G 150 1.16 4 16.6" hanger 16 DWC/C 1.73 23.33 21.60 1,436.95 25.73 Pup 7 5/8 29.7 L-80 DWC/C Vam 2.40 25.73 1.34 1,438.29 1,436.95 Casing 7 5/8 29.7 L-80 DWC/C Vam 1,411.22 Float collar 8 5/8 DWC/C Innovex 17 total centralizer, 4 of the 17 on the shoe track are the bow spring style. Type 336 semi-bow centralizer Casing 7 5/8 29.7 L-80 DWC/C Vam 82.23 1,520.52 1,438.29 www.wellez.net WellEz Information Management LLC ver_04818br 4 No. Jts. Delivered 39 No. Jts. Run 36 3 Type of Shoe:Innovex Casing Crew:WOTC 12 71.5 1,522.061,552.20 1,436.95 CEMENTING REPORT Csg Wt. On Slips:31,000 Spud Mud 14:49 10/10/2020 22 15.8 31 Bump pressBump Plug? 64/66 1060 149 HalliburtonFIRST STAGE10.5Tune spacer 37 9.1 5 98 490 Csg Wt. On Hook:46,000 Type Float Collar:Innovex No. Hrs to Run:5.5 DWC/C Innovex 1.54 1,522.06 1,520.52 Setting Depths Component Size Wt. Grade THD Make Length Bottom Top Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.NINU Paxton 10 Date Run 10-Oct-20 CASING RECORD County State Alaska Supv.Hauck / Richardson 1,436.95 Floats Held 69 103 27 76 Spud Mud Rotate Csg Recip Csg Ft. Min. PPG9.1 Shoe @ 1522.06 FC @ Top of Liner 57 62.7 10 Casing (Or Liner) Detail Shoe 8 5/8 27 bbls cmt to surface... gls 12/12/20 Cmt returned to surface: 27 Jts. Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp: X Yes No Casing Rotated? Yes X No Reciprocated?X Yes No % Returns during job Cement returns to surface? Yes X No Spacer returns?X Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: Cmt returned to surface: Calculated cement left in wellbore: OH volume Calculated: OH volume actual: Actual % Washout: 4 1/2'' RA Casing jt 4 1/2'' RA Casing Jt 4 1/2'' Casing Pup Jt Casing (Or Liner) Detail Float Shoe 4 1/2'' RA Casing Jt 4 1/2'' Casing Jts 5 Shoe @ 5717.8 FC @ Top of Liner5,631.61 138 0138 6% KCL Polymer Mud CASING RECORD County State Alaska Supv.Hauck / Riley Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.NINU Paxton 10 Date Run 17-Oct-20 Setting Depths Component Size Wt. Grade THD Make Length Bottom Top DWC 1.36 5,717.80 5,716.44 3,024.09 2,983.20 40.97 3,439.58 3,398.61 3,398.614 1/2 12.6 L-80 DWC 374.52 DWC 4 1/2 12.6 L-80 DWC 3,024.09 DWC 622.82 4 1/2 12.6 4 1/2 12.6 L-80 4 1/2'' Casing Jts 4 1/2 12.6 L-80 1,920.53 40.89 L-80 DWC 4 1/2'' Casing Jts 4 1/2 12.6 L-80 DWC 1,283.01 L-80 8.70 1,297.714 1/2 1,267.99 2,983.20 1,961.48 40.95 1,961.48 1,920.53 15.02 1,289.01 1,021.72 6.00 L-80 DWC 4 1/2'' Casing Pup Jt 4 1/2 9.3 5 100 930FIRST STAGE10.5Tune Primed 35 4 1/2 85/85.6 1400 0 Halliburton 15.3 16 Bump press CBL Bump Plug? 12:15 10/18/2020 1,440 CEMENTING REPORT 4 1/2'' Casing Jts L-80 DWC 12 124 DWC12.6 12.6 22.74 1,297.71 1,245.25 1,267.99 1,289.01 1,283.01 12.6 www.wellez.net WellEz Information Management LLC ver_04818br 3 4 1/2'' Casing Jts 4 1/2 12.6 L-80 DWC 83.59 5,716.44 5,632.85 Float Collar 5 DWC 1.24 5,632.85 5,631.61 4 1/2'' Casing Jts 4 1/2 12.6 L-80 DWC 530.85 5,631.61 5,100.76 4 1/2'' RA Casing Jt 4 1/2 12.6 L-80 DWC 41.03 5,100.76 5,059.73 4 1/2'' Casing Jts 4 1/2 12.6 L-80 DWC 456.16 5,059.73 4,603.57 4 1/2'' RA Casing Jt 4 1/2 12.6 L-80 DWC 41.02 4,603.57 4,562.55 4 1/2'' Casing Jts 4 1/2 12.6 L-80 DWC 666.44 4,562.55 3,896.11 4 1/2'' RA Casing Jt 4 1/2 12.6 L-80 DWC 40.96 3,896.11 3,855.15 4 1/2'' Casign Jts 4 1/2 12.6 L-80 DWC 415.57 3,855.15 3,439.58 Swell Packer 7 DWC Type 1 ll 280 2.41 Class G 75 1.24 5 Passed MIT-IA 2000 psi 1,289.01 Note: got 13 bbls spacer to surface . gls Swell Packer 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: 11/18/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL PAXTON 10 (PTD 220-064) FINAL ALASKA E-LINE SERVICES Radial Sector Cement Bond Log (10-22-2020) Files: Please include current contact information if different from above. Received by the AOGCC 11/18/2020 PTD: 2200640 E-Set: 34285 Abby Bell 11/18/2020 David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: Date: 11/11/2020 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL PAXTON 10 (PTD 220-064) Final LWD Logs (10/08/2020 to 10/14/2020) Final Definitive Directional Survey GeoTap Final Report MD / TVD Prints •ROP Rate of Penetration •DGR Dual Gamma Ray •PCG-K Gamma Module •ADR Azimuthal Deep Resistivity •ALD Azimuthal Lithodensity •CTN Compensated Thermal Neutron Time Log Print •GEOTAP Formation Pressure Tester Folder Contents: Please include current contact information if different from above. PTD: 2200640 E-Set: 34239 Received by the AOGCC 11/11/2020 Abby Bell 11/12/2020 David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: Date: 10/30/2020 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL PAXTON 10 (PTD 220-064) EOW DRILLING REPORTS-LWD LOGS-MUDLOGS Please include current contact information if different from above. PTD: 2200640 E-Set: 34151 Received by the AOGCC 10/30/2020 Abby Bell 10/30/2020 From:Loepp, Victoria T (CED) To:Jake Flora - (C) Subject:Re: [EXTERNAL] RE: Paxton 10 CBL (Sundry: 320-449, PTD: 220-064, API: 50-133-20691) Date:Friday, October 30, 2020 9:27:54 AM Jake, Thank you for the MIT-IA. It looks good. Victoria Sent from my iPhone On Oct 30, 2020, at 8:24 AM, Jake Flora - (C) <Jake.Flora@hilcorp.com> wrote: Hello Victoria, Please find attached the Paxton 10 MITIA to 2000psi for 30 minutes on 10-29-2020. We will be mobilizing coil tubing to the well as early as tomorrow to blow the well down with nitrogen in preparation for perforating operations. Thanks, Jake Flora From: Loepp, Victoria T (CED) [mailto:victoria.loepp@alaska.gov] Sent: Wednesday, October 28, 2020 9:52 AM To: Jake Flora - (C) <Jake.Flora@hilcorp.com> Subject: [EXTERNAL] RE: Paxton 10 CBL (Sundry: 320-449, PTD: 220-064, API: 50-133- 20691) Jake, Has the MIT-IA been done? Thanx, Victoria From: Jake Flora - (C) <Jake.Flora@hilcorp.com> Sent: Tuesday, October 27, 2020 2:29 PM To: Loepp, Victoria T (CED) <victoria.loepp@alaska.gov> Subject: Paxton 10 CBL (Sundry: 320-449, PTD: 220-064, API: 50-133-20691) Hello Victoria, Please find attached CBL for the recently completed Paxton 10. The TOC is inside the surface casing. We will be performing the MITIA shortly. Thanks, Jake Jake Flora | Kenai Ops Engineer | Hilcorp Alaska | 720-988-5375 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited.If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only forthe use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out suchvirus and other checks as it considers appropriate. <Paxton 10 MITIA 2000psi 10-29-2020.pdf> From:Loepp, Victoria T (CED) To:Jake Flora - (C) Cc:Schwartz, Guy L (CED) Subject:Paxton 10 CBL (Sundry: 320-449, PTD: 220-064, API: 50-133-20691) Date:Tuesday, October 27, 2020 3:11:00 PM Jake, Thank you for submitting the CBL for review. I have reviewed the CBL and the cement looks good up into the surface casing. Please forward the MIT-IA results as soon as available. Thanx, Victoria Victoria Loepp Senior Petroleum Engineer State of Alaska Oil & Gas Conservation Commission 333 W. 7th Ave Anchorage, AK 99501 Work: (907)793-1247 Victoria.Loepp@alaska.gov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Victoria Loepp at (907)793-1247 or Victoria.Loepp@alaska.gov From: Jake Flora - (C) <Jake.Flora@hilcorp.com> Sent: Tuesday, October 27, 2020 2:29 PM To: Loepp, Victoria T (CED) <victoria.loepp@alaska.gov> Subject: Paxton 10 CBL (Sundry: 320-449, PTD: 220-064, API: 50-133-20691) Hello Victoria, Please find attached CBL for the recently completed Paxton 10. The TOC is inside the surface casing. We will be performing the MITIA shortly. Thanks, Jake Jake Flora | Kenai Ops Engineer | Hilcorp Alaska | 720-988-5375 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Hdl irp Allaska. U.0 DATE:10/26/2020 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 333 W 7th Ave Ste 1005 Anchorage, AK 99501 DATA TRANSMITTAL PAXTON 10 (PTD 220-064) WELL BOX SAMPLE INTERVAL (FEET / MD) PAXTON 10 BOX 1 OF 3 1552'- 3050' MD PAXTON 10 BOX 2 OF 3 3050'- 4550' MD PAXTON 10 BOX 3 OF 3 4550'- 5733' MD (TD) Please include current contact information if different from above. RECEIVED OCT 2 6 2020 AOGCC Please acknowledge receipt by signing and returning one copy of this transmittal via Email or FAX to: (907) 777-8510 Receivelc�1, ',U Date: 1()/ 3019_91_-P4_� 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: _____Nitrogen_________ 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): 5732' Casing Collapse Structural Conductor 1410 psi Surface 4790 psi Intermediate Production 7500 psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Jake Flora Operations Manager Contact Email: Contact Phone: 777-8442 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng jake.flora@hilcorp.com 3,879'5,632'3,801'1297 psi Swell PKR 1283' MD / 1213' TVD 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 Private (Surface), ADL 384372 220-064 50-133-20691-00-00 Paxton 10 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 NA TVD Burst NA 8430 psi MD 2980 psi 6890 psi 120' 1,380' 120' 1,522' 3,865'4-1/2" 16" 7-5/8" 120' 1,522' 5,718' Perforation Depth MD (ft): See Attached Schematic 5,718' 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 4, 2020 NA Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 10:44 am, Oct 21, 2020 320-449 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.10.21 07:23:14 -08'00' Taylor Wellman _Nitrogen__ X Perforate 10-404 Submit CBL and MIT-IA results to AOGCC as soon as available DLB10/21/2020 X CTU BOP test to 4000 psig X VTL 10/23/20 DSR-10/22/2020Comm. 10/23/2020 dts 10/23/2020 RBDMS HEW 11/9/2020 Well Prognosis Well: Paxton-10 Date: 10/19/2020 Well Name: Paxton-10 API Number: 50-133-20691-00-00 Current Status: New drill Gas Producer Leg: N/A Estimated Start Date: 11/04/20 Rig: E-line Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 220-064 First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) Maximum Expected BHP: ~ 1667 psi @ 3706’ TVD (Based on a 0.45 psi/ft gradient) Max. Potential Surface Pressure: ~ 1297 psi Using Max BHP minus 0.1 psi/ft. gas gradient to surface). Well Summary Paxton 10 is a new drill well TD’d 10/15/20. The objective is to obtain the required CBL, MIT-IA, 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 = 61 degrees at 2394’ MD x Well drifted to 5609’ w/ 3.75” bit and scraper assembly x Well filled with 6% KCL Pre-perf work: (Covered under approved PTD) 1. MIT-IA to at least 2000psi and submit to the AOGCC. 2. RU E-Line, log CBL from PBTD to surface and submit to AOGCC. Sundry completion work: 3. NOTIFY AOGCC 24hrs in advance of CTU BOP Test. 4. MIRU Coiled Tubing Unit. 5. PT BOP equipment to 250 psi Low / 4,000 psi High. (Notify AOGCC 24 hrs. in advance on BOP test. 6. MU nozzle, and RIH. 7. RU N2 pumping unit. 8. Blow well dry with N2 taking returns to tanks (~85 bbl WBV) 9. Once well is dry, leave N2 pressure on well per OE for the first perforation interval. 10. POOH w/ coil. RDMO CTU. 11. RU E-Line. 12. RU perf guns. Likely 2-3/4” – 3-3/8” guns with 4-6 spf 13. RIH and perforate the below intervals per Geo/RE: Sand MD Top MD Bottom TVD Top TVD Bottom Total Footage (MD) BEL_10 ±1,708' ±1,746' ±1,493' ±1,515' 38' Paxton 10 is a new drill well TD’d 10/15/20. The objective is to obtain the required CBL, MIT-IA, and initially RU E-Line, log CBL from PBTD to surface and submit to AOGCC. complete the well. MIT-IA to at least 2000psi and submit to the AOGCC. Well Prognosis Well: Paxton-10 Date: 10/19/2020 BEL_13 ±1,769' ±1,787' ±1,528' ±1,539' 18' BEL_30 ±2,062' ±2,077' ±1,693' ±1,701' 15' BEL_37 ±2,107' ±2,120' ±1,717' ±1,724' 14' BEL_37 ±2,148' ±2,163' ±1,739' ±1,746' 15' BEL_41 ±2,253' ±2,272' ±1,792' ±1,802' 19' BEL_44 ±2,338' ±2,369' ±1,835' ±1,850' 31' BEL_45 ±2,378' ±2,431' ±1,854' ±1,880' 53' BEL_45 ±2,444' ±2,465' ±1,886' ±1,897' 22' BEL_48 ±2,545' ±2,572' ±1,937' ±1,951' 27' BEL_49 ±2,657' ±2,673' ±1,993' ±2,001' 16' BEL_50 ±2,764' ±2,813' ±2,047' ±2,071' 49' BEL_51 ±2,831' ±2,934' ±2,080' ±2,131' 104' BEL_53 ±3,041' ±3,094' ±2,183' ±2,211' 54' BEL_56 ±3,256' ±3,299' ±2,294' ±2,315' 43' BEL_74 ±3,904' ±3,979' ±2,615' ±2,652' 75' BEL_74 ±3,987' ±4,011' ±2,656' ±2,668' 24' BEL_78 ±4,063' ±4,078' ±2,692' ±2,699' 15' BEL_80 ±4,099' ±4,121' ±2,710' ±2,720' 22' BEL_82 ±4,172' ±4,203' ±2,747' ±2,763' 31' BEL_83 ±4,231' ±4,253' ±2,779' ±2,791' 23' BEL_90 ±4,287' ±4,309' ±2,811' ±2,824' 22' BEL_90 ±4,320' ±4,338' ±2,831' ±2,842' 18' BEL_90B ±4,350' ±4,387' ±2,850' ±2,873' 37' BEL_92-1 ±4,472' ±4,497' ±2,929' ±2,945' 25' BEL_92-6 ±4,545' ±4,556' ±2,979' ±2,986' 11' BEL_93 ±4,587' ±4,600' ±3,008' ±3,018' 14' BEL_94 ±4,612' ±4,622' ±3,026' ±3,034' 11' BEL_95 ±4,681' ±4,705' ±3,077' ±3,096' 25' BEL_97 ±4,757' ±4,775' ±3,135' ±3,149' 19' BEL_98 ±4,789' ±4,816' ±3,160' ±3,181' 28' BEL_99 ±4,826' ±4,843' ±3,188' ±3,201' 17' BEL_99B ±4,881' ±4,890' ±3,231' ±3,238' 9' BEL_100 ±4,899' ±4,911' ±3,245' ±3,255' 13' BEL_105 ±4,935' ±4,947' ±3,273' ±3,282' 12' BEL_110 ±5,005' ±5,016' ±3,328' ±3,336' 12' BEL_115 ±5,049' ±5,060' ±3,361' ±3,370' 12' BEL_115 ±5,080' ±5,089' ±3,385' ±3,392' 10' BEL_120 ±5,144' ±5,161' ±3,434' ±3,447' 18' BEL_120 ±5,176' ±5,185' ±3,458' ±3,465' 10' BEL_131 ±5,205' ±5,219' ±3,480' ±3,491' 15' BEL_134 ±5,258' ±5,268' ±3,520' ±3,528' 10' BEL_134 ±5,300' ±5,327' ±3,552' ±3,572' 27' BEL_135 ±5,347' ±5,363' ±3,587' ±3,599' 16' Well Prognosis Well: Paxton-10 Date: 10/19/2020 BEL_135 ±5,396' ±5,412' ±3,624' ±3,636' 16' BEL_135 ±5,417' ±5,434' ±3,640' ±3,652' 17' BEL_135 ±5,439' ±5,502' ±3,656' ±3,705' 64' BEL_136 ±5,504' ±5,553' ±3,706' ±3,743' 49' 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 14. Once sufficient production has been added per RE/Geo, RD E-Line Unit and Coiled Tubing Unit and turn well over to production. 15. CONTINGENT: If a zone is shown to make undesirable sand/water, set plug or patch for shut-off a. MIRU coil tubing unit b. PT BOP equipment to 250 psi Low / 4,000 psi High. (Notify AOGCC 24 hrs. in advance on BOP test.) c. If necessary, displace well with N2 taking returns into open formation d. RU E-Line Data Acquisition Unit. e. MU 4-1/2” patch and/or plug per vendor recommendation f. RIH and set over identified perf interval g. RDMO e-coil Attachments: 1. Proposed Schematic 2. Standard Well procedure – N2 Operations Updated by JMF 10-19-2020 PROPOSED SCHEMATIC Ninilchik Unit Paxton #10 PTD: 220-064 API: 05-133-20691-00-00 PBTD = 5,632’ / TVD = 3,801’ TD = 5,732’ / TVD = 3,879’ RKB to GL = 18’ PERFORATION DETAIL Sand TOP MD BTM MD TOP TVD BTM TVD FT Date Status TBD Perfs. See sundry procedure CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7-5/8" Surf Csg 29.7 L-80 DWC/C 6.875” Surf 1,522’ 4-1/2" Prod Csg 12.6 L-80 DWC/C HT 3.958” Surf 5,718’ 1 16” 7-5/8” 9-7/8” hole 4-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 1,283’ 3.958” 6.875” Swell Packer OPEN HOLE / CEMENT DETAIL 7-5/8" 102 BBL’s of cement in 9-7/8” hole – 27 BBLs Cement to Surface 4-1/2” 140 BBL’s of cement in 6-3/4” hole – zero losses during cement job 6-3/4” hole STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Monty M. Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Ninilchik Field, Beluga/Tyonek Gas Pool, Paxton 10 Hilcorp Alaska, LLC Permit to Drill Number: 220-064 Surface Location: 969' FNL, 3039' FEL, Sec 13, T1S, R14W, SM, AK Bottomhole Location: 2555' FNL, 1867' FEL, Sec 12, T1S, R14W, SM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jeremy M. Price Chair DATED this ___ day of September 2020. Sincerely, 22 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: 5,712' TVD: 3,866' 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): 166.4' 15. Distance to Nearest Well Open Surface: x-206284 y- 2230394 Zone-4 148.4' to Same Pool: 579' to Paxton 8 16. Deviated wells: Kickoff depth: 250 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 60 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Cond 16" 84# X-56 Weld 120' Surface Surface 120' 120' 9-7/8" 7-5/8" 29.7# L-80 DWC/C 1,525' Surface Surface 1,525' 1,389' 6-3/4" 4-1/2" 12.6# L-80 DWC/C HT 5,712' Surface Surface 5,712' 3,866' 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 5157' to nearest unit boundary 10/8/2020 Authorized Name: Monty Myers Authorized Title: Drilling Manager Frank Roach frank.roach@hilcorp.com 777-8413 18. Casing Program: Top - Setting Depth - BottomSpecifications Paxton 10 Ninilchik Field Beluga/Tyonek Gas Pool 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp Alaska, LLC 969' FNL, 3039' FEL, Sec 13, T1S, R14W, SM, AK ADL384372 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 L - 685 ft3 T - 90 ft3 1220 2410' FSL, 1960' FEL, Sec 12, T1S, R14W, SM, AK 2555' FNL, 1867' FEL, Sec 12, T1S, R14W, SM, AK LOCI 04-007 3508 1569 Total Depth MD (ft): Total Depth TVD (ft): Cement Quantity, c.f. or sacks Cement Volume MDSize Plugs (measured): (including stage data) Driven L - 401 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): Stratigraphic Test No Mud log req'd: Yes No No Directional svy req'd: Yes No Seabed ReportDrilling Fluid Program 20 AAC 25.050 requirements BOP SketchDrilling Program Time v. Depth Plot Shallow Hazard Analysis Single Well Gas Hydrates No Inclination-only svy req'd: Yes No Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal No No Form 10-401 Revised 3/2020 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) 8.31.2020 By Samantha Carlisle at 11:25 am, Aug 31, 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: 2020.08.31 11:06:25 -08'00' Monty M Myers Private (Surface), 220-064 SFD 8/31/2020 50-133-20691-00-00 SFD 9/1/2020 DSR-9/18/2020 pDevelopment - Gas Rig 169 *3500 psi BOPE test *Sundry required to complete/ perforate well *CBL and MIT-IA required Post rig *Diverter Waiver approved per 20 AAC 25.035 (h)(2) gls 9/18/20ls 9/18/20 9/22/2020 9/22/2020 Paxton #10 Drilling Program Ninilchik Unit Rev 0 August 28th, 2020 Paxton #10 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 .......................................................................................................... 13 12.0 Run 7-5/8” Surface Casing ...................................................................................................... 15 13.0 Cement 7-5/8” Surface Casing ................................................................................................. 18 14.0 BOP N/U and Test.................................................................................................................... 22 15.0 Drill 6-3/4” Hole Section .......................................................................................................... 23 16.0 Run 4-1/2” Production Casing ................................................................................................. 26 17.0 Cement 4-1/2” Production Casing ........................................................................................... 29 18.0 RDMO ...................................................................................................................................... 31 19.0 BOP Schematic ........................................................................................................................ 32 20.0 Wellhead Schematic ................................................................................................................. 33 21.0 Days Vs Depth .......................................................................................................................... 34 22.0 Geo-Prog .................................................................................................................................. 35 23.0 Anticipated Drilling Hazards .................................................................................................. 36 24.0 Hilcorp Rig 169 Layout ........................................................................................................... 38 25.0 FIT Procedure .......................................................................................................................... 39 26.0 Choke Manifold Schematic ...................................................................................................... 40 27.0 Casing Design Information ...................................................................................................... 41 28.0 6-3/4” Hole Section MASP ....................................................................................................... 42 29.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 43 30.0 Surface Plat (NAD 27) ............................................................................................................. 44 31.0 Directional Plan (wp07a) ......................................................................................................... 46 Page 2 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 1.0 Well Summary Well Paxton #10 Pad & Old Well Designation Paxton #10 is a grass roots well on Paxton Pad Planned Completion Type 4-1/2” Production tubing Target Reservoir(s) Beluga Planned Well TD, MD / TVD 5,712 MD / 3,866’ TVD PBTD, MD / TVD 5,632’ MD / 3,805’ TVD Surface Location (Governmental) 969' FNL, 3039' FEL, Sec 13, T1S, R14W, SM, AK Surface Location (NAD 27) X=206284.25, Y=2230394.87 Top of Productive Horizon (Governmental) 2410' FSL, 1960' FEL, Sec 12, T1S, R14W, SM, AK TPH Location (NAD 27) X=207444, Y=2233656 BHL (Governmental) 2555' FNL, 1867' FEL, Sec 12, T1S, R14W, SM, AK BHL (NAD 27) X=207545, Y=2233969 AFE Number 2013111 AFE Drilling Days 4 MOB, 18 DRLG AFE Completion Days 10 AFE Drilling Amount $3,416,000 AFE Completion Amount $1,098,000 Maximum Anticipated Pressure (Surface) 1220 psi Maximum Anticipated Pressure (Downhole/Reservoir) 1569 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB – GL 166.4’(148.4 + 18) Ground Elevation 148.4’ 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 Paxton #10 Drilling Procedure Rev 0 2.0 Management of Change Information , and approved in advance by the AOGCC. SFD 8/31/2020 Page 4 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 3.0 Tubular Program: Hole Section OD (in)ID (in)Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 16” 15.01”14.822 17” 84 J-55 Weld 2980 1410 - 9-7/8” 7-5/8” 6.875” 6.75” 8.5” 29.7 L-80 DWC/C 6890 4790 683 6-3/4” 4-1/2” 3.958”3.833” 5.0” 12.6 L-80 DWC/C HT 8430 7500 288 4.0 Drill Pipe Information: Hole Section OD (in)ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 4-1/2”3.826 2.6875” 5.25” 16.6 S-135 CDS40 17,693 16,769 468k All casing will be new 6890 p) 2980 8430 Page 5 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellez. x Report covers operations from 6am to 6am x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry tab. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. 5.2 Afternoon Updates x Submit a short operations update each work day to Frank.Roach@hilcorp.com, mmyers@hilcorp.com and cdinger@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. Each rig will be assigned a username to login with. 5.4 EHS Incident Reporting x Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don’t wait until an emergency to have to call around and figure it out!!!! a. John Coston: O: (907) 777-6726 C: (907) 227-3189 b. Matt Hogge: O: (907) 777-8418 C: (907) 227-9829 2. Spills: Keegan Fleming: O:907-777-8477 C:907-350-9439 x Notify Drlg Manager 1. Monty M Myers: O: 907-777-8431 C: 907-538-1168 x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to Frank.Roach@hilcorp.com and cdinger@hilcorp.com 5.6 Casing and Cmt report x Send casing and cement report for each string of casing to Frank.Roach@hilcorp.com and cdinger@hilcorp.com Page 6 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 6.0 Planned Wellbore Schematic CBL required over 4.5" casing (cement packer completion) Swell packer MIT-IA to 2000 psi post rig Page 7 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 7.0 Drilling / Completion Summary Paxton #10 is a S-shaped directional grassroots development well to be drilled off of the Paxton pad. Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the Beluga sands. The base plan is a directional wellbore with a kick off point at 300’ MD. Maximum hole angle will be 60° and TD of the well will be 5,712’ MD/ 3,866’ TVD, ending with 40° inclination left in the hole. Drilling operations are expected to commence approximately October 8th, 2020. The Hilcorp Rig # 169 will be used to drill the wellbore then run casing and cement. Surface casing will be run to 1,525’ MD / 1,389’ 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 1,525’ 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 5,712’ 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. Post rig: CBL and MIT-IA (2000 psi) approved per 20 AAC 25.035(h)(2) (several wells within 500 ft of SC depth. ) gls Drilling operations are expected to commence approximately October 8th, 2020. The Hilcorp Rig # 169 will be used to drill the wellbore then run casing and cement. gp p pp Page 8 Version 0 August, 2020 Paxton #10 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 Paxton #10. 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 drilling of Paxton #5, Paxton #7, Paxton #8, and Paxton #9. No issues were experienced while drilling the surface hole. Surface casing for these wells were set at the following depths: Paxton #5 – 777’ TVD, Paxton #7 – 1375’ TVD, Paxton #8 – 2987’ TVD, and Paxton #9 – 1395’ TVD. Surface casing is requested to be set at ~1389’ TVD on Paxton #10. No shallow hydrocarbon zones will be penetrated. Approved... gls 9 /18/20 Page 9 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 9-7/8”x 21-1/4” x 2M Hydril MSP diverter Function Test Only 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 Paxton #10 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 21-1/4” Hydril MSP 2M diverter System. x N/U 16-3/4” 3M x 21-1/4” 2M DSA (Hilcorp) on 16-3/4” 3M wellhead. x N/U 21-1/4” diverter “T”. x Knife gate, 16” diverter line. x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). 10.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the vent line tip. “Warning Zone” must include: Diverter Waived Page 11 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 xx A prohibition on vehicle parking. x A prohibition on ignition sources or running equipment. x A prohibition on staged equipment or materials. x Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set wear bushing in wellhead. Page 12 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 10.5 Rig Orientation on Paxton pad: Page 13 Version 0 August, 2020 Paxton #10 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 1,525’ MD/ 1,389’ 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 1,500’ MD and 1,600’ 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 14 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 120-1525’ 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 Page 15 Version 0 August, 2020 Paxton #10 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” DWC x CDS 40 XO on rig floor and M/U to FOSV. x R/U fill-up line to fill casing while running. x Ensure all casing has been drifted on the location prior to running. x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ float shoe bucked on (thread locked). x (1) Joint with coupling thread locked. x (1) Joint with float collar bucked on pin end & thread locked. x Install (2) centralizers on shoe joint over a stop collar. 10’ from each end. x Install (1) centralizer, mid tube on thread locked joint and on FC joint. x Ensure proper operation of float equipment. 12.5 Continue running 7-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x M/U connections to the base of the triangle stamped on the pin end. Note M/U torque values required to achieve this position. x After making up several connections, use the torque required to M/U to base of triangle as the M/U torque and continue running string. x Install (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the event a top out job is needed. x Utilize a collar clamp until weight is sufficient to keep slips set properly. 7-5/8” DWC Estimated M/U Torque Casing OD Minimum Maximum Yield Torque 7-5/8”21,700 ft-lbs 25,100 ft-lbs 28,500 ft-lbs Page 16 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 Page 17 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.7 Slow in and out of slips. 12.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 12.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 12.11 After circulating, lower string and land hanger in wellhead again. Page 18 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 13.0 Cement 7-5/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Cementers equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface. x Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. 13.2 Document efficiency of all possible displacement pumps prior to cement job 13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.4 Pump 5 bbls 10 ppg spacer. Test surface cmt lines. 13.5 Pump remaining 30 bbls of 10 ppg spacer. 13.6 Drop bottom plug. Mix and pump cmt per below recipe. 13.7 Cement volume based on annular volume + 50% open hole excess. Job will consist of lead & tail, TOC brought to surface. Page 19 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 SURFACE CEMENT CALCULATIONS CSG BTM (ft) 1,848 CSG Size 7 5/8 Section:Calculation:Vol (BBLS) Vol (ft3) LEAD: 120’ x .162 bpf = 19.45 109.216” Conductor x 7-5/8” Casing annulus: LEAD:(1,025’ – 120’) x .038 bpf x 1.5 =51.93 291.59-7/8” OH x 7-5/8” Casing annulus: Total LEAD: 71.38 400.7 TAIL:(1,525’-1,025’) x .038 bpf x 1.5 =28.68 160.09-7/8” OH x 7-5/8” Casing annulus: TAIL:80 x .046 bpf = 3.68 20.67-5/8” Shoe track: Total TAIL: 32.36 180.6 Total Cement: 103.7 581.3 Cement Slurry Design: Lead Slurry (1,025’ MD to surface)Tail Slurry (1,525’ to 1,025’ 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 2.46 ft3/sk 162 sx 1.22 ft3/s 147 sx 103.7 581.3 Page 20 Version 0 August, 2020 Paxton #10 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: 1525’- 80’ = 1445’ x .046 bpf = 66.5 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 1525’- 80’ = 1445’ x .046 bpf = 66.5 bbls Page 21 Version 0 August, 2020 Paxton #10 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 22 Version 0 August, 2020 Paxton #10 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. If mud weight at surface TD was greater than 9.0 ppg, increase density of new mud to match. 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. BOPE test 3500 psi Page 23 Version 0 August, 2020 Paxton #10 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 LWD tools functioning properly. 15.5 Ensure TF offset is measured accurately and entered correctly into the MWD software. 15.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. 15.7 Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 15.8 6-3/4” BHA: Triple Combo GR/Res/Den/Neu + PWD 15.9 6-3/4” hole section mud program summary: Weighting material to be used for the hole section will be salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. System Type:9.0 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 1,525’- 5,712’ 9.0 – 11.0 40-53 15-25 15-25 8.5-9.5 11.0 g 9.0 – 11.0 Page 24 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 System Formulation:6% KCL EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for a 9.0 – 10.0 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 15.10 TIH w/ 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. 15.11 R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst.7-5/8” burst is 6890 psi / 2 = 3445 psi. 15.12 Drill out shoe track and 20’ of new formation. 15.13 CBU and condition mud for FIT. 15.14 Conduct FIT to 13.5 ppg EMW. Note: Offset field test data predicts frac gradient at the 7-5/8” shoe to be between 11 - 13 ppg EMW. A 13.5 ppg FIT results in a 4 ppg kick margin while drilling with the planned MW of 9.5 ppg. Kick tolerance = (13.5-9.5)X(1389/3866) = 1.43 15.15 Drill 6-3/4” hole section to 5,712’ MD / 3,866’ TVD 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. 15.16 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8” shoe. Conduct FIT to 13.5 ppg EMW. FIT 13.5 2500 psi. Surface casing variance . glsMIT casing 2500 psi Page 25 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 15.17 POOH LDDP and BHA 15.18 4-1/2” pipe rams previously installed in BOP stack and tested. Page 26 Version 0 August, 2020 Paxton #10 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 7-5/8” shoe. Leave the centralizers free floating. x Pick up swell packer and place in string at approximately 1275’ 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 27 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 Page 28 Version 0 August, 2020 Paxton #10 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 1275’. Swell packer should have 10’ handling pups installed on both ends with bow spring centralizers on pups. 16.13. Swedge up and wash last 2 joints to bottom. P/U 5’ off bottom. Note slack-off and pick-up weights. 16.14. Stage pump rates up slowly to circulating rate. Circ and condition mud with casing on bottom. Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the shakers are clean. Reduce the low end rheology of the drilling fluid by adding water and thinners. 16.15. Rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 29 Version 0 August, 2020 Paxton #10 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 30 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 Production CEMENT CALCULATIONS CSG BTM (ft) 6,249 CSG Size 4 1/2 Section:Calculation:Vol (BBLS) Vol (ft3) LEAD: (1,525'-1025') x .026 bpf = 13.12 73.77-5/8" x 4-1/2" Casing annulus: LEAD:(5,212’ – 1,525’) x .025 bpf x 1.20 =108.79 610.86-3/4" OH x 4-1/2" Casing annulus: Total LEAD: 121.91 684.5 TAIL:(5,712’-5,212’) x .025 bpf x 1.20 =14.75 82.86-3/4" OH x 4-1/2" Casing annulus: TAIL:80 x .015 bpf = 1.22 6.84-1/2” Shoe track: Total TAIL: 15.97 89.7 Total Cement: 137.88 774.2 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. 278 sx 73 sx Page 31 Version 0 August, 2020 Paxton #10 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 Sundry required to perforated well: 4.5" POST RIG: CBL and MIT-IA to be completed and results forwarded to AOGCC before perfing well Page 32 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 19.0 BOP Schematic Page 33 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 20.0 Wellhead Schematic SSV Page 34 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 21.0 Days Vs Depth Page 35 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 22.0 Geo-Prog Page 36 Version 0 August, 2020 Paxton #10 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 37 Version 0 August, 2020 Paxton #10 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 38 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 24.0 Hilcorp Rig 169 Layout Page 39 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 25.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 40 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 26.0 Choke Manifold Schematic Page 41 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 27.0 Casing Design Information Page 42 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 28.0 6-3/4” Hole Section MASP Page 43 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 29.0 Spider Plot (NAD 27) (Governmental Sections) Page 44 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 30.0 Surface Plat (NAD 27) Page 45 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 Page 46 Version 0 August, 2020 Paxton #10 Drilling Procedure Rev 0 31.0 Directional Plan (wp07a) ! "#$ -275 0 275 550 825 1100 1375 1650 1925 2200 2475 2750 3025 3300 3575 3850 4125True Vertical Depth (550 usft/in)0 275 550 825 1100 1375 1650 1925 2200 2475 2750 3025 3300 3575 3850 Vertical Section at 18.04° (550 usft/in) Paxton #10 Tgt2 7 5/8" x 9 7/8" 4 1/2" x 6 3/4" 50 0 1 0 0 0 1500200025003000350040004500500055005712Paxton #10 Wp07 Start Dir 3º/100' : 250' MD, 250'TVD Start Dir 4º/100' : 450' MD, 449.63'TVD End Dir : 1525' MD, 1389.42' TVD Start Dir 4º/100' : 1575' MD, 1423.29'TVD End Dir : 1896.65' MD, 1613.44' TVD Start Dir 3º/100' : 4096.65' MD, 2713.44'TVD End Dir : 4763.31' MD, 3139.79' TVD Total Depth : 5711.83' MD, 3866.4' TVD Beluga 1 Beluga 9 Beluga 16 Beluga 20 Beluga 41 Beluga 44 Beluga 47 Beluga 49 Beluga 50 Beluga 80 Beluga 115 Beluga 132 Beluga 134 T-2 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: Paxton #10 148.40 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2230394.88 206284.25 60° 5' 43.697 N 151° 36' 33.224 W SURVEY PROGRAM Date: 2020-08-25T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.00 3_MWD+IFR1+MS+Sag .00 .00Paxton #10 Wp07a (Paxton #10) 5711.83Paxton #10 Wp07a (Paxton #10) 3_MWD+IFR1+MS+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 1206.40 1040.00 1276.41 Beluga 1 1447.40 1281.00 1611.08 Beluga 9 1553.40 1387.00 1784.00 Beluga 16 1611.40 1445.00 1892.58 Beluga 20 1778.40 1612.00 2226.57 Beluga 41 1826.40 1660.00 2322.57 Beluga 44 1888.40 1722.00 2446.57 Beluga 47 1989.40 1823.00 2648.57 Beluga 49 2024.40 1858.00 2718.57 Beluga 50 2685.40 2519.00 4040.57 Beluga 80 3359.40 3193.00 5049.99 Beluga 115 3486.40 3320.00 5215.78 Beluga 132 3513.40 3347.00 5251.02 Beluga 134 3807.40 3641.00 5634.81 T-2 REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Paxton #10, True North Vertical (TVD) Reference: As-Built RKB @ 166.40usft (HEC 169) Measured Depth Reference: As-Built RKB @ 166.40usft (HEC 169) Calculation Method:Minimum Curvature Project:Ninilchik Unit Site:Paxton Well:Paxton #10 Wellbore:Paxton #10 Design:Paxton #10 Wp07a Ninilchik Unit Paxton Paxton #10 Paxton #10 Paxton #10 Wp07a 5.746 CASING DETAILS TVD TVDSS MD Size Name 1389.42 1223.02 1525.00 7-5/8 7 5/8" x 9 7/8" 3866.40 3700.00 5711.83 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 2 250.00 0.00 0.00 250.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 250' MD, 250'TVD 3 450.00 6.00 40.00 449.63 8.01 6.73 3.00 40.00 9.70 Start Dir 4º/100' : 450' MD, 449.63'TVD 4 750.00 18.00 40.00 742.54 55.71 46.74 4.00 0.00 67.45 5 1525.00 47.36 19.51 1389.42 425.19 223.24 4.00 -30.00 473.42 End Dir : 1525' MD, 1389.42' TVD 6 1575.00 47.36 19.51 1423.29 459.86 235.52 0.00 0.00 510.19 Start Dir 4º/100' : 1575' MD, 1423.29'TVD 7 1896.65 60.00 16.51 1613.44 705.94 314.94 4.00 -11.74 768.77 End Dir : 1896.65' MD, 1613.44' TVD 8 4096.65 60.00 16.51 2713.44 2532.64 856.38 0.00 0.00 2673.35 Start Dir 3º/100' : 4096.65' MD, 2713.44'TVD 9 4763.31 40.00 16.51 3139.79 3019.80 1000.78 3.00 -180.00 3181.27 End Dir : 4763.31' MD, 3139.79' TVD 10 5711.83 40.00 16.51 3866.40 3604.36 1174.04 0.00 0.00 3790.75 Total Depth : 5711.83' MD, 3866.4' TVD 0 333 667 1000 1333 1667 2000 2333 2667 3000 3333 3667 4000 4333 South(-)/North(+) (500 usft/in)-667 -333 0 333 667 1000 1333 1667 2000 2333 2667 West(-)/East(+) (500 usft/in) Paxton #10 Tgt2 7 5/8" x 9 7/8" 4 1/2" x 6 3/4" 250500 750 1000 1250 1500 1750 2000 2250 2500 2750 3000 3250 3500 3750 3866 Paxton #10 Wp07a Start Dir 3º/100' : 250' MD, 250'TVD Start Dir 4º/100' : 450' MD, 449.63'TVD End Dir : 1525' MD, 1389.42' TVD Start Dir 4º/100' : 1575' MD, 1423.29'TVD End Dir : 1896.65' MD, 1613.44' TVD Start Dir 3º/100' : 4096.65' MD, 2713.44'TVD End Dir : 4763.31' MD, 3139.79' TVD Total Depth : 5711.83' MD, 3866.4' TVD Project: Ninilchik Unit Site: Paxton Well: Paxton #10 Wellbore: Paxton #10 Plan: Paxton #10 Wp07a WELL DETAILS: Paxton #10 148.40 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2230394.88 206284.25 60° 5' 43.697 N 151° 36' 33.224 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Paxton #10, True North Vertical (TVD) Reference:As-Built RKB @ 166.40usft (HEC 169) Measured Depth Reference:As-Built RKB @ 166.40usft (HEC 169) Calculation Method:Minimum Curvature CASING DETAILS TVD TVDSS MD Size Name 1389.42 1223.02 1525.00 7-5/8 7 5/8" x 9 7/8" 3866.40 3700.00 5711.83 4-1/2 4 1/2" x 6 3/4" 0 333 667 1000 1333 1667 2000 2333 2667 3000 3333 3667 4000 4333 South(-)/North(+) (500 usft/in)-667 -333 0 333 667 1000 1333 1667 2000 2333 2667 West(-)/East(+) (500 usft/in) Paxton #10 Tgt2 025 0500750 1000 1250 1500 1750 2000 2250 2500 2750 3000 32503500 37 5 0 4000 4250450047505000525055005750600 0 6250 6500 6 7 5 0 7 0 0 0 7 2 5 0 7 5 0 0 7750 7 9 8 0 Paxton #2 Surveys 2505 0 0750 1 0 0 0 1 2 5 0 1 5 0 0 1 7 5 0 2 0 0 0 2 2 5 0 2 5 0 0 2 7 5 0 Paxton #1 2505 0 0 7 5 0 10 00 1250 1500 1750 2000 2250 Paxton #9 250 500 7 5 0 1 0 0 0 12 50 1 5 0 0 1 7 5 0 200 0 21 9 3 Paxton #7 2 5 0500 7 5 0 1 0 0 0 1 2 5 0 1 5 0 0 Paxton #6 Wp1.a 200022502500275030003250350037504000425045004750500052505500575060006250650067507000725075007 7 5 0 7 9 8 0 Kalotsa 4 250 5007501000 1 2 5 0 1 5 0 01750 2000 2250 25002574Paxton #5 250500750 1000 1250 1500 1750 2000 2250 2500 2750 3000 3250 3500 3750 4000 4250 4500 4750 5000 5250 5500 5750 6000 6250 6500 6750 7000 7250 7500 7750 80008037 Paxton #8 1750200022502500275030003 5 0 0 37 50 4 0 0 0 4 2 5 04500475050005250 Kalotsa 7 wp06 7 5/8" x 9 7/8" 4 1/2" x 6 3/4" 250500 750 1000 1250 1500 1750 2000 2250 2500 2750 3000 3250 3500 3750 3866 Paxton #10 Wp07a Project: Ninilchik Unit Site: Paxton Well: Paxton #10 Wellbore: Paxton #10 Plan: Paxton #10 Wp07a WELL DETAILS: Paxton #10 148.40 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 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"+,",&( .&/(."+.&0 ) 12-) 12-) 12- (-&.( ".& (,&,* ".&% /&-./".& ) 12-) 12-) 12- -&* (,%& ..&*/ (*"&., /&/,(,%&0 ) % !"( !"#$ <+ %-=+ %- *? *=".& "+%%& 12"6, /786!"!8 ! 9"+%%& %+,""&./ 12"6, /786!"!8 ! 9 : 3 45)& 3 ;&0 3 3 $ &0 < $#= $) >& 9 ;; & 3 398:3:03 4 3 :& 0.001.503.004.50Separation Factor0 350 700 1050 1400 1750 2100 2450 2800 3150 3500 3850 4200 4550 4900 5250 5600 5950Measured DepthPaxton #2 SurveysNo-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:Paxton #10 NAD 1927 (NADCON CONUS)Alaska Zone 04148.40+N/-S +E/-W Northing EastingLatittudeLongitude0.000.002230394.88 206284.25 60° 5' 43.697 N 151° 36' 33.224 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Paxton #10, True NorthVertical (TVD) Reference:As-Built RKB @ 166.40usft (HEC 169)Measured Depth Reference:As-Built RKB @ 166.40usft (HEC 169)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-08-25T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool18.00 .00Paxton #10 Wp07a (Paxton #10)3_MWD+IFR1+MS+Sag.005711.83Paxton #10 Wp07a (Paxton #10)3_MWD+IFR1+MS+Sag0.0030.0060.0090.00120.00150.00Centre to Centre Separation (50.00 usft/in)0 350 700 1050 1400 1750 2100 2450 2800 3150 3500 3850 4200 4550 4900 5250 5600 5950 6300Measured DepthPaxton #9Paxton #7Paxton #8Equivalent Magnetic DistanceGLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference18.00 To 5711.83Project: Ninilchik UnitSite: PaxtonWell: Paxton #10Wellbore: Paxton #10Plan: Paxton #10 Wp07aLadder / S.F. PlotsCASING DETAILSTVD TVDSS MD Size Name1389.42 1223.02 1525.00 7-5/8 7 5/8" x 9 7/8"3866.40 3700.00 5711.83 4-1/2 4 1/2" x 6 3/4" 1 Davies, Stephen F (CED) From:Davies, Stephen F (CED) Sent:Tuesday, September 1, 2020 5:17 PM To:Frank Roach; Cody Terrell Subject:RE: [EXTERNAL] Paxton 10 (PTD 220-064) - Question Thank you Frank and Cody. Stay safe, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. From: Frank Roach <Frank.Roach@hilcorp.com> Sent: Tuesday, September 1, 2020 5:15 PM To: Davies, Stephen F (CED) <steve.davies@alaska.gov> Subject: RE: [EXTERNAL] Paxton 10 (PTD 220‐064) ‐ Question Mr. Davies, Please see the attached email from our land group, confirming that as planned, Paxton 10 will conform to the spacing requirement of Conservation Order 701C, Rule 3B. Regards, Frank V Roach Drilling Engineer 907.854.2321 (c) 907.777.8413 (o) From: Davies, Stephen F (CED) [mailto:steve.davies@alaska.gov] Sent: Monday, August 31, 2020 16:02 To: Frank Roach <Frank.Roach@hilcorp.com> Subject: [EXTERNAL] Paxton 10 (PTD 220‐064) ‐ Question Frank, I’m reviewing Hilcorp’s Permit to Drill application for the Paxton 10 well. As planned, will Paxton 10 conform to the spacing requirement of Conservation Order 701C, Rule 3B? That rule states: “(B) No gas well shall be drilled or completed less than 1,500 feet from an uncommitted tract within the Ninilchik Unit unless the well and the uncommitted tract both lie within the same Participating Area.” Thanks for your help, Steve Davies Senior Petroleum Geologist 2 Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1 Davies, Stephen F (CED) From:Cody Terrell <cterrell@hilcorp.com> Sent:Tuesday, September 1, 2020 3:09 PM To:Frank Roach; Anthony McConkey Cc:Monty Myers; Cody Dinger Subject:RE: [EXTERNAL] Paxton 10 (PTD 220-064) - Question The answer to Davies question is yes. Paxton 10 will conform to all rules under CI 701C, especially Rule 3B. Regards, Cody T. Terrell Landman Hilcorp Alaska, LLC Direct: 907-777-8432 Cell: 713-870-4532 From: Frank Roach Sent: Tuesday, September 1, 2020 7:53 AM To: Anthony McConkey <amcconkey@hilcorp.com>; Cody Terrell <cterrell@hilcorp.com> Cc: Monty Myers <mmyers@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com> Subject: FW: [EXTERNAL] Paxton 10 (PTD 220‐064) ‐ Question Anthony/Cody, I need some help with the below question from Steve, about the conservation order. This is new territory for me so I’m in need of an education here. Regards, Frank V Roach Drilling Engineer 907.854.2321 (c) 907.777.8413 (o) From: Davies, Stephen F (CED) [mailto:steve.davies@alaska.gov] Sent: Monday, August 31, 2020 16:02 To: Frank Roach <Frank.Roach@hilcorp.com> Subject: [EXTERNAL] Paxton 10 (PTD 220‐064) ‐ Question Frank, I’m reviewing Hilcorp’s Permit to Drill application for the Paxton 10 well. As planned, will Paxton 10 conform to the spacing requirement of Conservation Order 701C, Rule 3B? That rule states: “(B) No gas well shall be drilled or completed less than 1,500 feet from an uncommitted tract within the Ninilchik Unit unless the well and the uncommitted tract both lie within the same Participating Area.” Thanks for your help, 2 Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:NINILCHIK UNIT PAXTON 10Initial Class/TypeEXP / PENDGeoArea820Unit51432On/Off ShoreOnProgramEXPField & PoolWell bore segAnnular DisposalPTD#:2200640NINILCHIK, BELUGA-TYONEK GAS - 562503NA1 Permit fee attachedYes Surface location on private acreage, top prod int and TD in ADL 384372.2 Lease number appropriateYes3 Unique well name and numberYes NINILCHIK, BELUGA-TYONEK GAS – 562503, governed by CO 701C4 Well located in a defined poolYes 8/31: Operator notified. 9/1: Operator landman replies that as planned, well meets all spacing requirements.5 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) (ForNA15 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 conductor set on pad18 Conductor string providedYes 7 5/8" surface casing will be set and cemented at 1500 ft19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes 4.5" casing will be cemented back to 1200 ft (swell packer)21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes BTC calcs are supplied.23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes No issues with close crossing26 Adequate wellbore separation proposedNA Diverter waiver per 20 AAC 25.035 (h()2) …27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes Rig 169 has 5000 psi T3 BOPE29 BOPEs, do they meet regulationYes MASP = 1200 psi Will test BOPe to 3500 psi (annular to 2500 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes MIT-IA and CBL required Post rig .32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S is not anticipated based on nearby wells.35 Permit can be issued w/o hydrogen sulfide measuresYes Maximum expected reservoir pressure is 8.7 ppg EMW; however, most sands encountered are expected36 Data presented on potential overpressure zonesNA to be depleted to severely depleted. Production interval will be drilled using 9.5 to 11.0 ppg mud.37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate9/1/2020ApprGLSDate9/18/2020ApprSFDDate8/31/2020AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateDiverter waived per 20 AAC 25.035 (h)(2). Several wells on pad close to same Surf casing point with no gas issue. Gls Need CBL and MIT-IA before perforating wellbore.Daniel T. Seamount, Jr.Digitally signed by Daniel T. Seamount, Jr. Date: 2020.09.22 08:44:41 -08'00'JMP9/22/2020JLC 9/22/2020