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Home My WebLink About224-110Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 08/26/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250826 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 24 50133206390000 214112 7/15/2025 AK E-LINE PPROF T40803 BR 11-86 50733207370000 225057 7/30/2025 AK E-LINE Hoist T40804 BR 11-86 50733207370000 225057 8/4/2025 AK E-LINE Perf T40804 BR 11-86 50733207370000 225057 8/9/2025 AK E-LINE Perf T40804 BRU 212-35T 50283200970000 198161 8/4/2025 AK E-LINE Perf T40805 BRU 212-35T 50283200970000 198161 6/28/2025 AK E-LINE Perf T40805 BRU 224-34T 50283202050000 225044 8/2/2025 AK E-LINE CBL T40806 BRU 224-34T 50283202050000 225044 8/5/2025 AK E-LINE CBL T40806 BRU 224-34T 50283202050000 225044 7/27/2025 AK E-LINE CBL T40806 BRU 224-34T 50283202050000 225044 8/2/2025 AK E-LINE Punch T40806 KTU 43-6XRD2 50133203280200 205117 7/26/2025 AK E-LINE Perf T40807 MPL-13A 50029223350100 223017 8/10/2025 READ CaliperSurvey T40808 NCIU A-21 50883201990000 224086 1/14/2025 AK E-LINE Plug/Perf T40809 ODSN-16 50703206200000 210053 8/10/2025 READ CaliperSurvey T40810 PBU 01-30A 50029216060100 225050 8/7/2025 HALLIBURTON RBT-COILFLAG T40811 PBU 06-11A 50029204280100 225042 7/13/2025 HALLIBURTON RBT-COILFLAG T40812 PBU 11-37A 50029227160100 219062 7/27/2025 HALLIBURTON RBT T40813 PBU 14-43A 50029222960100 225041 7/31/2025 HALLIBURTON RBT-COILFLAG T40814 PBU F-06B 50029200970200 225054 8/5/2025 HALLIBURTON RBT-COILFLAG T40815 PBU L1-10A 50029213400100 225032 8/1/2025 HALLIBURTON RBT-COILFLAG T40816 PCU 02A 50283200220100 224110 7/27/2025 AK E-LINE Perf T40817 SRU 241-33 50133206630000 217047 7/28/2025 AK E-LINE Perf T40818 WhiskeyGulch 1 50231200790000 221046 6/18/2025 AK E-LINE Packer T40819 Please include current contact information if different from above. T40817PCU 02A 50283200220100 224110 7/27/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.08.27 08:12:23 -08'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: CT Fish, N2 Thru Tbg Gravel Pk 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 5,188 feet 4,027 feet true vertical 4,669 feet NA feet Effective Depth measured 4,027 feet 1,873 feet true vertical 3,734 feet 1,873 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth) Tieback 4-1/2" 12.6# / L-80 1,881' MD 1,881' TVD Packers and SSSV (type, measured and true vertical depth) LTP; N/A 1,873' MD/TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Contact Phone: 3,810psi 7,500psi 3,090psi 6,330psi 8,430psi 2,032' 2,032' Burst Collapse 1,540psi Production Liner 2,070' 3,315' Casing Structural 2,070' TOW 4,669' 2,070' TOW 5,188' 339'Conductor Surface Intermediate 20" 13-3/8" 339' 2,032' measured TVD 9-5/9" 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 224-110 50-283-20022-01-00 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: ADL 390780 Pretty Creek / Undefined Gas Pool Pretty Creek Unit (PCU) 02A 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 1220 Size 339' 0 5101507 0 10430 832 Chad Helgeson, Operations Engineer 325-413 & 325-364 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 N/A chelgeson@hilcorp.com 907-777-8405 p k ft t Fra O s Oth 6. A G L PG , k 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 8:39 am, Aug 12, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.08.11 16:20:41 - 08'00' Noel Nocas (4361) BJM 10/1/25 Page 1/2 Well Name: PCU 002A Report Printed: 8/7/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Wellbore API/UWI:50-283-20022-01-00 Field Name:Pretty Creek State/Province:ALASKA Permit to Drill (PTD) #:224-110 Sundry #:325-413 / 325-364 Rig Name/No: Jobs Actual Start Date:4/15/2025 End Date: Report Number 24 Report Start Date 7/18/2025 Report End Date 7/19/2025 Last 24hr Summary Fox crew travel to Beluga. PJSM and PTW. Spot and RU equipment. Attempt to Install injector hose extensions - wrong fittings. Order fittings from Northern Hydraulics for delivery tomorrow. Complete RU except for stabbing pipe in injector. SDFN. Report Number 25 Report Start Date 7/19/2025 Report End Date 7/20/2025 Last 24hr Summary Fox CTU 9 Rig-up. PJSM and PTW. PU injector and stripper. Stab pipe and install new pack offs. Shell test and Test BOPE to 3500 psi per Sundry. No failures. Witness waived by Jim Regg. Add hoses extensions and purge. troubleshoot and purge Wt indicator. SDFN. Report Number 26 Report Start Date 7/20/2025 Report End Date 7/21/2025 Last 24hr Summary Fox CTU 9 Fishing. PJSM and PTW. MU 60' lubricator and YJ Fishing BHA. Pt to 3500 psi. RIH 2-7/8" CTC, Checks, Accelerator jar, weight bar, Oil jar, Disconnect, Circ sub,and 3.50" Hyd overshot (OAL 26.04'). PU/SO Wts 16/10k. Tag @ 3807'. Unable to latch. Set down lightly and roll pump. Latched up. PU 24k over and fired jars. Straight pull to 30K over. Cock jars and PU. Pulled free @ 8K over. Extra 5K drag then 2K. PU 150' w extra weight. RBIH and tag 3' higher @ 3804' CTM. POH w/ 1-2K over to check tools. No recovery. Hyd overshot stuck in released position. Clear overshot and RBIH w/ same. Tag @ 3802'. Unable to latch. Wash over and latch same depth @ 3802' Hit jars at 10, 20, and 42k over. Lose fish engagement each time after setting down to cock jars and very difficult to re-engage. No recovery. SDFN. Report Number 27 Report Start Date 7/21/2025 Report End Date 7/22/2025 Last 24hr Summary PJSM and PTW. MU YJ BHA. PT 3500 psi. WHP 360 psi. RIH w/ YJ 2-7/8" CTC, Checks, Accelerator jar, 7' weight bar, Oil jar, Disconnect, Circ sub,and 3.75" Series 150 overshot (OAL 29.18') Bullead 95 bbls 6% KCL up to 2.5 bpm @ 2030 psi. WT 11/21K. Latch fish @ 3811' CTM. Pulled free @ 11K over. Dragging 5-10k over. POH. Hung up in LTP. Work thru. Dragging up to 15k over occasionally up to 1755'. Appears to be wire. OOH. Recovered SL tool string and no wire. Report Number 28 Report Start Date 7/22/2025 Report End Date 7/23/2025 Last 24hr Summary PJSM and PTW. RU Pollard Wireline. PT 250/3500 psi. MU and RIH w/ Wirefinder and 3.69" LIB. Impression of wire @ 1213' WLM. Run wiregrab. Recover 20' .160 wire @ 1216'. Re-ran and recover (3) pieces wire (6' total) from 2791'. Re-ran and recover 3' wire from 3803'. Ran 4-1/2" GR. Tag @ 3808' Unable to latch screen assy. Deep wire impressions on pulling tool. Ran wire spear to 3810' Good bite and jarred free - No recovery. Ran LIB. Impression of wire on edge of LIB and faint impression of fish neck. Report Number 29 Report Start Date 7/23/2025 Report End Date 7/24/2025 Last 24hr Summary PJSM and PTW. RU Pollard Wireline. WHP 0 psi. Fluid level 350'. Recovered 2' (7) pieces of .160 wire w/ 3.69" magnet in two runs. No recovery on 3rd run to 3808' WLM. Ran 2.75" 3-prong wire grab. No recovery. RIH w/ 3.69" LIB. Impressions of 3 strands of wire on shoulder. Ran 1.90" 3-prong wire grab. Recovered 5' of wire from 3808'. RIH W/ 4-1/2 GR. Latched screen assy @ 3808'. Jar up - no travel. Jar down 15 mins. No travel down. Jar up and GR sheared. Overpull @ Tbg hanger and work into tree. No wire. Inspect tree and lubricator. RIH w/ wirefinder, braided line brush, and 3.69" magnet to drift for obstruction. Tag @ 3808'. Note extra Wt. PU and pulling up to 200# over @ casing collars then slips off. Worked up to 8730'. POH to PU wire spear. Ran wirefinder and spear. Tag @ 1900' and work down to 2730'. 200# overpulls and slips off. Unable to work past 2730'. No recovery. RIH w/ wirefinder and 2.75" 2-prong wire grab. Tag @ 3592'. Recover 6' wire. RIH w/ 4 1/2" GS. Latch, jar up, and shear off @ 3808' WLM (3,827' KB) POH RD SL. SDFN. Report Number 30 Report Start Date 7/24/2025 Report End Date 7/25/2025 Last 24hr Summary Fox CTU 9. PJSM and PTW. Stand-up Inj and lubricator. MU BHA. PT PCE to 250/3500 psi. RIH w/ YJ 2.85" CTC, Checks, Accelerator jar, 7' weight bar, Oil jar, Disconnect, Tempress agitator, Circ sub,and 2.87" Nozzle (OAL 32'). Tag @ 3837' CTM (3826' KB). Ran agitator 20 mins @ 2.65 bpm @ 3300psi CTP w/ 10K down. Screen assy moved downhole. Chase to 3979' (3968' KB) while circulating. Pump 1.5x bttms up. Only fine traces of sand and 1:1 returns. POH. RIH w/ same BHA w 4-1/2 Hyd GS (OAL 31.3'), Latch up @ 3977' CTM (3966' KB). Max. overpull 5K. POH w/ ~1K over. OOH. LD Screen assy, BHA, and CT Lube and Injector. Sent 48 hr Weekly BOP Test notification to AOGCC @ 16:30. MIRU Pollard Wireline. RIH w/ wirefinder and 2.75" 2-prong wiregrab. Tag @ 3992' KB. POH. No recovery. RIH w/ 3.69" LIB to 3992' KB. Impression of Tbg Stop fish neck. RD WL. SDFN. Report Number 31 Report Start Date 7/25/2025 Report End Date 7/26/2025 Last 24hr Summary Fox CTU 9. PJSM and PTW. WHP - Vac. MIRU PT PCE to 250/3500 psi. RIH w/ CTC, 5' stinger, and 2.5" nozzle. Tag Tbg stop @ 4002' CTM (3991' KB) Blow down well to N2. 800 scfm @ 1400 psi CTP. Recovered 46 bbls Final WHP 1100 psi. SD and dry tag @ same depth 3991' KB. POH and pressure up to 2085 psi w/ additional 43,000 scf N2. RD CTU. Bullhead additional 279,000 SCF N2 @ 1400 scfm. Initial/Max./Final WHP: 1790/2220/1625 psi. (Total of 105 bbls 6% KCL lost to formation) Report Number 32 Report Start Date 7/26/2025 Report End Date 7/27/2025 Last 24hr Summary AK E-Line. MIRU. PT 2500 psi. PT 2500 psi. WHP 1137 psi. RIH w/ 2-3/4" x 10' gun. Tag @ 3993'.(6' above bttm perf). RD AK-EL. RU Pollard. PT 3500 psi. Pull AD -2 Stop from 3992' KB. RIH w/ 2-1/2" x 11' pump bailer. Tag 3993' KB. Work 3999' KB. Recovered ~2 gal sand. RIH w/ 3" drive down bailer. Tag @ 4001' KB. Fell thru bridge to 4007' KB. Multiple slow passes 3750 to 4007' KB (8' rathole). No issues. POH. Recovered 1 gal sand. RD and move WL unit to D Pad Page 2/2 Well Name: PCU 002A Report Printed: 8/7/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Report Number 33 Report Start Date 7/27/2025 Report End Date 7/28/2025 Last 24hr Summary AK E-Line Reperf. MIRU. WHP 1110 psi. PT 2500 psi. WHP 1120 psi. RIH w/ 2-3/4" x 10' Geo Razor 15 gms, 6 spf, 60* Phsg. Tag @ 4007' MD. Reperf 10 Sterling C1 sand 3989-3999'. RIH w/ 10' gun and reperf same interval. Sterling C1 sand 3989-3999'. POH. Final WHP 1121 psi. RD. _____________________________________________________________________________________ Updated by CAH 08-11-25 SCHEMATIC Pretty Creek Unit Well: PCU-02A PTD: 224-110 API: 50-283-20022-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 94 / H-40 / Butt 19Surf 339 13-3/8Surface 61 / J-55 / Butt 12.515Surf 2,032 9-5/8" Intermediate 47/43.5 P-100/N-80 8.861Surf 2,070 (TOW) 4-1/2Prod Liner 12.6 / L-80 / GBCD 3.8831,8735,188 4-1/2 Tieback 12.6 / L-80 / JBear & Lion 3.883Surf 1,881 OPEN HOLE / CEMENT DETAIL 20TOC @ Surface 600 sx 13-3/8TOC @ Surface 675 sx (Stg 2 + Top Job) Stg 1 660 sx 9-5/8"Est. TOC @ 1,500 1020 sx Stg 2 / 1110 sx Stg 1 4-1/2TOC @ 2,058 based on CBL on 9-30-24; 253 bbls of 12 ppg Lead and 35.5 bls of 15.3 ppg tail JEWELRY DETAIL No. Depth Item 1 18.95 Cactus 11 x 4-1/2 Hanger, 4 Type H BPV profile 2 1,873Baker 7 x 9.6 SLZXP (HRD-E) Liner top Hanger/Packer 3 1,8817-3/8 Bullet Seal Assembly & WLEG 4 4,120CIBP w/ 15ft of cement mixed with sand TOC 4,027 1/28/25 PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Ft Date Status ST C1 3,989' 3,999' 3,704' 3,712' 10 1/29/25 & 7/27/25 Open ST C5 4,140'4,149'3,823'3,830'9 11/24/24 Isolated Beluga D3 4,251' 4,259' 3,913' 3,919' 8 10/4/24 Isolated NOTES 8.5 Ghost hole from 2714 to 6000 Short Joints (~10ft)3,351, 3616 (w/ RA Tag), 3917 (w/ RA Tag), 4342 (w/ RA Tag) Sterling C1 Sand The Sterling C1 Sand has been perforated 4 times (2ea 1/29/25 & 2ea 7/27/25) 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 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): 5,188'3781 Casing Collapse Structural Conductor Surface 1,540psi Intermediate 3,810psi 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 Other: CT Fish LTP; N/A 1,873' MD / 1,873' TVD; N/A 4,669'4,027'3,734' Pretty Creek Undefined Gas Pool 20" 13-3/8" 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Pretty Creek Unit (PCU) 02AUndefined Gas Same 4,669'4-1/2" 1,897psi 3,315' 4,027 Statewide spacing regulations: 20 AAC 25.055 July 10, 2025 Tieback 4-1/2" 5,188' Perforation Depth MD (ft): 3,989 - 3,999 3,704 - 3,712 6,330psi 3,090psi 339' 2,070' TOW 339' 2,032' Size 339' 9-5/8"2,070' 2,032' MD 2,070' TOW Length Proposed Pools: 12.6# / L-80 TVD Burst 1,881' 8,430psi 2,032' Tubing MD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0390780 224-110 50-283-20022-01-00 Tubing Size: Hilcorp Alaska, LLC Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: chelgeson@hilcorp.com Perforation Depth TVD (ft): 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: PRESENT WELL CONDITION SUMMARY m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov For: Digitally signed by Chad Helgeson (1517) DN: cn=Chad Helgeson (1517) Date: 2025.07.10 11:53:16 - 08'00' Chad Helgeson (1517) 325-413 By Grace Christianson at 2:10 pm, Jul 10, 2025 MEL Rixse (PE) A.Dewhurst 10JUL25MGR11JULY25 * BOPE pressure test to 3500 psi. 48 hour notice to AOGCC. YES DSR-7/16/25 10-404 11JULY2025 JLC 7/21/2025 Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.07.21 16:23:13 -08'00'07/21/25 RBDMS JSB 072225 Well Prognosis Well Name: PCU-2A API Number: 50-283-20022-01-00 Current Status: SI Gas Well Permit to Drill Number: 224-110 First Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Second Call Engineer: Scott Warner (907) 830-8863 Maximum Expected BHP: 1765 psi @ 3601’ TVD (Based on 0.49 psi/ft gradient)) Max. Potential Surface Pressure: 1620 psi (Based on 0.04 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.69 psi/ft using 13.2 ppg EMW FIT at the surface casing shoe 9/11/24 Shallowest Potential Perf TVD: MPSP/(0.69-0.04) = 1620 psi / 0.65 = 2492‘ TVD Well Status: SI gas well with Screen fish in well Brief Well Summary: PCU-2A was drilled in September 2024 targeting the Sterling and Beluga sands. A 2-3/8” screen is stuck in well, but unable to fish with 0.160 wire. Screen was moved up hole before it got stuck. The objective of this sundry is to fish the screen and cleanout well to existing perfs. Wellbore Conditions: - 2-3/8” screen stuck at 3781 with wire next to screen - Tubing pressure 1080 psi - Fluid level tag @ 3720’ (7/9/25) Procedure: 1. MIRU Fox Coil Tubing unit with 1.75” Coil and pressure control equipment (enough lubricator to cover tools and fish) 2. PT lubricator to 250 psi low/ 3500 psi high a. Provide AOGCC 48 hr notice for BOP test 3. RIH & fish screen & SL tool string at 3781 4. POOH and PU fish assembly 5. RIH and fish Eline tool string with coil x Latch/bait fish w/ SL if necessary x Potential for short pieces of SL wire in the well that may need to be removed with RCJB on coil Contingency (Open Hole fishing procedure If unable to close well with fish attached to coil -i.e. fish is too long) i. Once fish at surface and valves will not close ii. Confirm fluid at surface by pumping across flow cross iii. Shut down pump and monitor well for 15 minutes (no flow check) iv. Hold safety meeting 1. Crew and WSS to discuss plan and procedure in case of kick with lubricator removed 2. Review kick contingencies to cover at a minimum: a. Lift fish clear and close tree valves valves b. Lift fish clear and close BOP shear valves Well Prognosis c. Stab back on to well v. Once well is confirmed dead and personnel monitoring trip tank while pumping across flow cross vi. Break off lubricator and lift tool string out of well. vii. Once tool string clear of tree valves close swab. 6. Once fish is removed, PU wash nozzle, RIH and clean well out to AD2 Stop at 4001’. Attachments: 1. Current Well Schematic 2. Fox CT BOP Drawing _____________________________________________________________________________________ Updated by CAH 02-25-25 SCHEMATIC Pretty Creek Unit Well: PCU-02A PTD: 224-110 API: 50-283-20022-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 94 / H-40 / Butt 19”Surf 339’ 13-3/8”Surface 61 / J-55 / Butt 12.515”Surf 2,032’ 9-5/8"Intermediate 47/43.5 P-100/N-80 8.861”Surf 2,070’ (TOW) 4-1/2”Prod Liner 12.6 / L-80 / GBCD 3.883”1,873’5,188’ 4-1/2” Tieback 12.6 / L-80 / JBear & Lion 3.883”Surf 1,881’ OPEN HOLE / CEMENT DETAIL 20”TOC @ Surface 600 sx 13-3/8”TOC @ Surface 675 sx (Stg 2 + Top Job) Stg 1 660 sx 9-5/8"Est. TOC @ 1,500’ 1020 sx Stg 2 / 1110 sx Stg 1 4-1/2”TOC @ 2,058’ based on CBL on 9-30-24; 253 bbls of 12 ppg Lead and 35.5 bls of 15.3 ppg tail JEWELRY DETAIL No.Depth Item 1 18.95 Cactus 11” x 4-1/2” Hanger, 4” Type H BPV profile 2 1,873’Baker 7” x 9.6” SLZXP (HRD-E) Liner top Hanger/Packer 3 1,881’7-3/8” Bullet Seal Assembly & WLEG 43,979’Screen assembly top 24.9ft OAL (See notes below for screen details) 5 4,120’CIBP w/ 15ft of cement mixed with sand – TOC 4,027’ 1/28/25 PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Ft Date Status ST C1 3,989'3,999'3,704'3,712'10 1/29/25 Open ST C5 4,140'4,149'3,823'3,830'9 11/24/24 Isolated Beluga D3 4,251'4,259'3,913'3,919'8 10/4/24 Isolated NOTES Screen Detail AA stop set at 3979 above a D&D Packoff w/ G Fish neck,w/ KOBE KO assembly, w/ 13’ 2-7/8” bakerweld screen on top od AD-2 Stop set at 4001’. (6’ prong w/ 1.9-2.0” swedge to knockout Kobe to equalize before pulling AA stop. 8.5” Ghost hole from 2714’ to 6000’ Short Joints (~10ft)3,351’, 3616’ (w/ RA Tag), 3917’ (w/ RA Tag), 4342’ (w/ RA Tag) From:Rixse, Melvin G (OGC) To:Chad Helgeson Cc:Christianson, Grace K (OGC) Subject:20250711 1102 Verbal approval Sundry 315-413 PCU-02A AOGCC 10-403 CTCO PTD 224-110 Submitted 07-10- 25 - Sundry Application Date:Friday, July 11, 2025 11:04:32 AM Attachments:Hilcorp_PCU_02A_Sundry 325-413 PTD 224-110.pdf Chad, Verbal approval attached for service coil cleanout. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Thursday, July 10, 2025 2:37 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] RE: PCU-02A AOGCC 10-403 CTCO PTD 224-110 Submitted 07-10-25 - Sundry Application Mel, I have submitted a new sundry for this coil fishing. If we can get a verbal before the weekend that would be great, but understand if you aren’t able to get to it with the short notice. Thanks Chad From: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Sent: Thursday, July 10, 2025 2:15 PM To: Donna Ambruz <dambruz@hilcorp.com> Cc: Chad Helgeson <chelgeson@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com> Subject: [EXTERNAL] RE: PCU-02A AOGCC 10-403 CTCO PTD 224-110 Submitted 07-10-25 - Sundry Application CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Hello, This application has been received for processing. Thank you, Grace Christianson Executive Assistant, Alaska Oil & Gas Conservation Commission (907) 793-1230 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 Grace Christianson at (907-793-1230) or (grace.christianson@alaska.gov). From: Donna Ambruz <dambruz@hilcorp.com> Sent: Thursday, July 10, 2025 1:28 PM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Chad Helgeson <chelgeson@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com> Subject: PCU-02A AOGCC 10-403 CTCO PTD 224-110 Submitted 07-10-25 - 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 theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently 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 responsibilityis 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 herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Chad Helgeson Cc:Donna Ambruz Subject:RE: PCU-02A (PTD# 224-110) Sundry # 325-364 Change request Date:Tuesday, July 1, 2025 1:16:00 PM Chad, Change requests below are approved. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Friday, June 27, 2025 8:24 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: PCU-02A (PTD# 224-110) Sundry # 325-364 Change request Bryan, Thank you for processing the PCU-02 Sundry very quickly last week. We started this job by trying to pull the Screen we had in the well and it is stuck, not a big surprise, but when we pulled the packoff we had above the screen the pressure increased to ~1030 psi. Because of this additional pressure, we think there may still be gas in this zone we would like to recover. We are going to try and recover this screen with 0.160 slickline, but if not possible, we may need to use coil tubing to recover the screen. The 2 requests I have for you are: 1. If we need to use coil tubing to recover the screen, can we complete this work on Sundry # 325-364, where we will give AOGCC 48hr notice for BOP test and will test the BOPE to 3500 psi? 2. Once/if we can recover the screen, we would like to reperforate the existing zone to see if we can get it to flow, before we move uphole as planned in this sundry. As part of this sundry, can we get approval to reperforate the Sterling C1 Sand from 3989-3999’? Please let me know if you need any additional information or would like us to submit a separate procedure or change of program for these activities. Thanks Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No 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. 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 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): 5,188'N/A Casing Collapse Structural Conductor Surface 1,540psi Intermediate 3,810psi 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 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: chelgeson@hilcorp.com Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0390780 224-110 50-283-20022-01-00 Tubing Size: Hilcorp Alaska, LLC Proposed Pools: 12.6# / L-80 TVD Burst 1,881' 8,430psi 2,032' Tubing MD (ft): Size 339' 9-5/8"2,070' 2,032' MD 2,070' TOW Length 3,989 - 3,999 3,704 - 3,712 6,330psi 3,090psi 339' 2,070' TOW 339' 2,032' Statewide spacing regulations: 20 AAC 25.055 June 27, 2025 Tieback 4-1/2" 5,188' Perforation Depth MD (ft): 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Pretty Creek Unit (PCU) 02AUndefined Gas Same 4,669'4-1/2" 1,620psi 3,315' 4,027 Other: Thru Tbg Gravel Pack LTP; N/A 1,873' MD / 1,873' TVD; N/A 4,669'4,027'3,734' Pretty Creek Undefined Gas Pool 20" 13-3/8" m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 4:19 pm, Jun 16, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.06.16 15:15:42 - 08'00' Noel Nocas (4361) 325-364 BJM 6/16/25 10-404 A.Dewhurst 17JUN25 DSR-6/18/25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.06.20 13:08:59 -08'00'06/20/25 RBDMS JSB 062325 Well Prognosis Well Name: PCU-2A API Number: 50-283-20022-01-00 Current Status: SI Gas Well Permit to Drill Number: 224-110 First Call Engineer: Chad Helgeson (907) 777-8405 (O)(907) 229-4824 (C) Second Call Engineer: Scott Warner (907) 830-8863 Maximum Expected BHP: 1765 psi @ 3601’ TVD (Based on 0.49 psi/ft gradient)) Max. Potential Surface Pressure: 1620 psi (Based on 0.04 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.69 psi/ft using 13.2 ppg EMW FIT at the surface casing shoe 9/11/24 Shallowest Potential Perf TVD: MPSP/(0.69-0.04) = 1620 psi / 0.65 = 2492‘ TVD Well Status: SI gas well Brief Well Summary: PCU-2A was drilled in September 2024 targeting the Sterling and Beluga sands. The 1st sand tested flowed gas at low rates, the next zone brought in a lot of sand and water. The Sterling C1 sand was perforated in January of 2025 and flowed with a retrievable screen placed in the well. This zone is depleting quickly and will be moving on to the next zones. The objective of this sundry is to plug back the open Sterling C1 perfs and test additional Sterling sands. If we get to the Sterling X3 sand a Thru-tubing gravel pack system will be installed across this sand (procedure and info included in the sundry). Wellbore Conditions: - 2-3/8” screen set with retrievable packoff at 3980’ (6/10/25) - Tubing pressure 550 psi - Fluid level tag @ 3290’ (6/10/25)’ Pre-Sundry work: 1. SL remove screen parts, if possible. Procedure: 1. RU E-line, PT lubricator to 2500 psi 2. Pressure well up with compressor discharge gas and push away any water. 3. RIH and set CIBP @ ~ 3950’ (tag plug and save log of tag) 4. PU dump bailer, RIH and set 25ft of cement on plug 5. RIH and perforate per RE/Geo and test Sterling sands within the interval below, from the bottom up: Sand MD Top MD Base TVD Top TVD Base H ST A1 ±3,567' ±3,575' ±3,369' ±3,375' ±8 ST A3 ±3,641' ±3,658' ±3,428' ±3,442' ±17 ST A5 ±3,754' ±3,762' ±3,518' ±3,525' ±8 ST A5 ±3,772' ±3,796' ±3,533' ±3,552' ±24 ST B1 ±3,819' ±3,832' ±3,570' ±3,580' ±13 ST B2 ±3,853' ±3,858' ±3,597' ±3,601' ±5 Well Prognosis a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations. Pending well production, all perf intervals may not be completed 6. RDMO 7. Turn well over to production & flow test well Thru tubing gravel pack procedure for Sterling X3 sand 1. RU E-line, PT lubricator to 2500 psi 2. PU TTS paragon packer or CIBP (depending on if commingling with zones below) 3. Pump 5bbls of methanol into well (~328ft) 4. Pressure well up to 1600 psi with natural gas or N2 5. RIH and perforate the Sterling X3 Sand Sand MD Top MD Base TVD Top TVD Base H ST X3 ±3,482' ±3,487' ±3,300' ±3,304' ±5 6. Run latch assembly and 125 micron screen assembly with sand height control valve and polish bore receptacle 7. Run vent plug assembly, sting anchor latch into PBR. 8. PU dump bailer and RIH w/ 20/40 carbo lite to 10ft above top of assembly 9. Pump 2-3 bbls of fluid (Methanol or filtered 6% KCl) down into gravel pack (~1 bpm) and dump bailer while pumping, repeat till screens are filled with sand. 10. Pump an additional 1/2 bbl of fluid a. Screen annular volume = 0.0354 x 20ft = 0.708ft^3 b. Blank pipe annular volume = 0.0605 x 30ft = 1.816 ft^3 c. 2.524 ft^3 x 97 lbs/ft = 245 lbs of 20/40 Carbo-Lite 11. Pressure up well with N2 to shear Sand Height Control Valve (2200 psi) 12. Pull vent screen assembly with 3” JDC Pulling Tool 13. RIH and set paragon II packer, stabbed into sealbore 14. RIH and remove vent screen cap 15. Eline set isolation packer with overshot on gravel pack 16. Turn well over to ops, slowly bring on well (bleeding off N2) 17. If well does not flow on its own, SL swab well onto production or push fluid away with N2 or gas Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Proposed Gravel pack Well Schematic 4. TTS Gravel Pack Deployment System _____________________________________________________________________________________ Updated by CAH 02-25-25 SCHEMATIC Pretty Creek Unit Well: PCU-02A PTD: 224-110 API: 50-283-20022-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 94 / H-40 / Butt 19”Surf 339’ 13-3/8”Surface 61/J-55/Butt 12.515”Surf 2,032’ 9-5/8"Intermediate 47/43.5 P-100/N-80 8.861”Surf 2,070’ (TOW) 4-1/2”Prod Liner 12.6 / L-80 / GBCD 3.883”1,873’5,188’ 4-1/2” Tieback 12.6 / L-80 / JBear & Lion 3.883”Surf 1,881’ OPEN HOLE / CEMENT DETAIL 20”TOC @ Surface 600 sx 13-3/8”TOC @ Surface 675 sx (Stg 2 + Top Job) Stg 1 660 sx 9-5/8"Est. TOC @ 1,500’ 1020 sx Stg 2 / 1110 sx Stg 1 4-1/2”TOC @ 2,058’ based on CBL on 9-30-24; 253 bbls of 12 ppg Lead and 35.5 bls of 15.3 ppg tail JEWELRY DETAIL No.Depth Item 1 18.95 Cactus 11” x 4-1/2” Hanger, 4” Type H BPV profile 2 1,873’Baker 7” x 9.6” SLZXP (HRD-E) Liner top Hanger/Packer 3 1,881’7-3/8” Bullet Seal Assembly & WLEG 43,979’Screen assembly top 24.9ft OAL (See notes below for screen details) 5 4,120’CIBP w/ 15ft of cement mixed with sand – TOC 4,027’ 1/28/25 PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Ft Date Status ST C1 3,989'3,999'3,704'3,712'10 1/29/25 Open ST C5 4,140'4,149'3,823'3,830'9 11/24/24 Isolated Beluga D3 4,251'4,259'3,913'3,919'8 10/4/24 Isolated NOTES Screen Detail AA stop set at 3979 above a D&D Packoff w/ G Fish neck,w/ KOBE KO assembly, w/ 13’ 2-7/8” bakerweld screen on top od AD-2 Stop set at 4001’. (6’ prong w/ 1.9-2.0” swedge to knockout Kobe to equalize before pulling AA stop. 8.5” Ghost hole from 2714’ to 6000’ Short Joints (~10ft)3,351’, 3616’ (w/ RA Tag), 3917’ (w/ RA Tag), 4342’ (w/ RA Tag) _____________________________________________________________________________________ Updated by CAH 04-10-25 PROPOSED Pretty Creek Unit Well: PCU-02A PTD: 224-110 API: 50-283-20022-01-00 TD =5,188’MD/4,669’ TVD 20” RKB: GL = 18.95’ 4-1/2” 4 5 8.5” ghost hole 6 13-3/8” 9-5/8” TOW@2,070’ 1 2/3 PBTD =5,098’ MD /4,597’TVD 7 RA 4,342’ RA 3,917’ RA 3,616’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 94 / H-40 / Butt 19” Surf 339’ 13-3/8” Surface 61 / J-55 / Butt 12.515” Surf 2,032’ 9-5/8" Intermediate 47/43.5 P-100/N-80 8.861” Surf 2,070’ (TOW) 4-1/2” Prod Liner 12.6 / L-80 / GBCD 3.883” 1,873’ 5,188’ 4-1/2” Tieback 12.6 / L-80 / JBear & Lion 3.883” Surf 1,881’ OPEN HOLE / CEMENT DETAIL 20” TOC @ Surface 600 sx 13-3/8” TOC @ Surface 675 sx (Stg 2 + Top Job) Stg 1 660 sx 9-5/8" Est. TOC @ 1,500’ 1020 sx Stg 2 / 1110 sx Stg 1 4-1/2”TOC @ 2,058’ based on CBL on 9-30-24; 253 bbls of 12 ppg Lead and 35.5 bls of 15.3 ppg tail JEWELRY DETAIL No. Depth Item 1 18.95 Cactus 11” x 4-1/2” Hanger, 4” Type H BPV profile 2 1,873’ Baker 7” x 9.6” SLZXP (HRD-E) Liner top Hanger/Packer 3 1,881’ 7-3/8” Bullet Seal Assembly & WLEG 4 ±3,470’ TTS Gravel pack system (Paragon Packer w/ ~40ft of delta pore screens w/ vent plug for sand placement & paragon packer on top) see wellfile for details 5 ±3,800’ CIBP w/ 25ft of cement 6 3,979’ Screen assembly top 24.9ft OAL (See notes below for screen details) 7 4,120’ CIBP w/ 15ft of cement mixed with sand – TOC 4,027’ 1/28/25 PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Ft Date Status ST X3 ±3,482' ±3,487' ±3,300' ±3,304' ±5 Proposed TBD ST A1 ±3,567' ±3,575' ±3,369' ±3,375' ±8 Proposed TBD ST A3 ±3,641' ±3,658' ±3,428' ±3,442' ±17 Proposed TBD ST A5 ±3,754' ±3,762' ±3,518' ±3,525' ±8 Proposed TBD ST A5 ±3,772' ±3,796' ±3,533' ±3,552' ±24 Proposed TBD ST B1 ±3,819' ±3,832' ±3,570' ±3,580' ±13 Proposed TBD ST B2 ±3,853' ±3,858' ±3,597' ±3,601' ±5 Proposed TBD ST C1 3,989' 3,999' 3,704' 3,712' 10 1/29/25 Isolated ST C5 4,140' 4,149' 3,823' 3,830' 9 11/24/24 Isolated Beluga D3 4,251' 4,259' 3,913' 3,919' 8 10/4/24 Isolated NOTES Screen Detail AA stop set at 3979 above a D&D Packoff w/ G Fish neck, w/KOBE KO assembly, w/ 13’ 2-7/8” Bakerweld screen on top of AD-2 Stop set at 4001’. (6’ prong w/ 1.9-2.0” swedge to knockout Kobe to equalize before pulling AA stop. 8.5” Ghost hole from 2714’ to 6000’ Short Joints (~10ft) 3,351’, 3616’ (w/ RA Tag), 3917’ (w/ RA Tag), 4342’ (w/ RA Tag) dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ƉƌŽĚƵĐƚƐĂŶĚƐĞƌǀŝĐĞƐĂƌĞƐƵďũĞĐƚƚŽƐƚĂŶĚĂƌĚƚĞƌŵƐĂŶĚĐŽŶĚŝƟŽŶƐ͘hŶůĞƐƐŶŽƚĞĚŽƚŚĞƌǁŝƐĞ͕ƚƌĂĚĞŵĂƌŬƐĂŶĚƐĞƌǀŝĐĞŵĂƌŬƐŶŽƚĞĚŚĞƌĞŝŶĂƌĞƚŚĞ ƉƌŽƉĞƌƚǇŽĨdŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ΞϮϬϭϴ͘dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ůůƌŝŐŚƚƐƌĞƐĞƌǀĞĚ͘ (TTS products are available through authorized service providers.) ǁǁǁ͘ƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵͮͲDĂŝů͗ƩƐΛƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵ 16 dd^DƵůƟƉůĞĂƌƌŝĞƌĞƉůŽǇŵĞŶƚdĞĐŚŶŝƋƵĞƐĂŶĚ^ǇƐƚĞŵƐ YƵŝƚĞŽŌĞŶĚƵƌŝŶŐŶŽŶͲƌŝŐǁĞůůŝŶƚĞƌǀĞŶƟŽŶŽƉĞƌĂƟŽŶƐŝƚŝƐŶĞĐĞƐƐĂƌǇŽƌĚĞƐŝƌĞĚƚŽŝŶƐƚĂůůůŽŶŐƐĞĐƟŽŶƐŽĨƚƵďƵůĂƌƐŝŶƚŽƚŚĞǁĞůů͕ƐƵĐŚ ĂƐƐĂŶĚƐĐƌĞĞŶƐĂŶĚƐŝŵŝůĂƌƚƵďƵůĂƌĂƐƐĞŵďůŝĞƐ͘dŚŝƐŶĞĐĞƐƐŝƚǇĐƌĞĂƚĞƐŵĂŶǇĐŚĂůůĞŶŐĞƐĨŽƌŽƉĞƌĂƚŽƌƐĂŶĚƐĞƌǀŝĐĞĐŽŵƉĂŶŝĞƐǁŝƚŚ ƌĞŐĂƌĚƐƚŽŵĂŝŶƚĂŝŶŝŶŐǁĞůůĐŽŶƚƌŽůĚƵƌŝŶŐƚŚĞƐĞŝŶƐƚĂůůĂƟŽŶƐ͘ ƐŵŽƐƚŶŽŶͲƌŝŐǁĞůůŝŶƚĞƌǀĞŶƟŽŶƐŝŶǀŽůǀĞƚŚĞƵƐĞŽĨĐŽŝůƚƵďŝŶŐŽƌǁŝƌĞůŝŶĞŽƉĞƌĂƟŽŶƐŝŶƚĞƌǀĞŶŝŶŐƚŚƌŽƵŐŚƚŚĞĞǆŝƐƟŶŐƉƌŽĚƵĐƟŽŶ ƚƵďŝŶŐŽŶůŝǀĞǁĞůůƐ͕ĂŵĞĂŶƐďǇǁŚŝĐŚƚŽŝŶƐƚĂůůƚŚĞƐĞůŽŶŐĂƐƐĞŵďůŝĞƐŝŶƚŽƚŚĞǁĞůůǁŚŝůĞŵĂŝŶƚĂŝŶŝŶŐŵƵůƟƉůĞďĂƌƌŝĞƌƐŽĨǁĞůůĐŽŶƚƌŽů ďĞĐŽŵĞƐĂŶĞĐĞƐƐŝƚǇ͘ŽŵŵŽŶƉƌĂĐƟĐĞŚĂƐďĞĞŶƚŽůƵďƌŝĐĂƚĞƚŚĞĂƐƐĞŵďůǇŝŶƚŽƚŚĞǁĞůůďǇƵƐŝŶŐĞŝƚŚĞƌĂǁŝƌĞůŝŶĞůƵďƌŝĐĂƚŽƌĚƵƌŝŶŐ ǁŝƌĞůŝŶĞŝŶƚĞƌǀĞŶƟŽŶƐŽƌĂƌŝƐĞƌĂƐƐĞŵďůǇǁŚĞŶĐŽŝůĞĚƚƵďŝŶŐŝƐƵƐĞĚĨŽƌĐŽŶǀĞǇĂŶĐĞ͘ŽƚŚƐǇƐƚĞŵƐůŝŵŝƚƚŚĞŽǀĞƌĂůůůĞŶŐƚŚŽĨĂƐƐĞŵďůǇ ƚŚĂƚĐĂŶďĞŝŶƐƚĂůůĞĚŝŶƚŚĞǁĞůů͘dŚĞůŝŵŝƚĂƟŽŶŽĨŽǀĞƌĂůůůĞŶŐƚŚƐŽĨƚŚĞƐĞĂƐƐĞŵďůŝĞƐĂƌĞƌĞůĂƟǀĞƚŽŚŽǁŵƵĐŚůĞŶŐƚŚŽĨƌŝƐĞƌŽƌ ůƵďƌŝĐĂƚŽƌƚŚĂƚĐĂŶďĞƌŝŐŐĞĚƵƉŽƌŝŶƐƚĂůůĞĚŽŶƚŽƉŽĨƚŚĞǁĞůůŚƌŝƐƚŵĂƐƚƌĞĞ͘DŽƐƚǁĞůůůŽĐĂƟŽŶƐůŝŵŝƚƚŚĞƚŽƚĂůůĞŶŐƚŚŽĨĞŝƚŚĞƌ ůƵďƌŝĐĂƚŽƌŽƌƌŝƐĞƌƚŽфϭϬϬ͛͘ ƵƌŝŶŐŝŶƐƚĂůůĂƟŽŶŽĨdd^͛ƐdŚƌƵdƵďŝŶŐ'ƌĂǀĞůWĂĐŬ^ǇƐƚĞŵƐ͕ŝƚŝƐĂĐŽŵŵŽŶƌĞƋƵŝƌĞŵĞŶƚƚŽŝŶƐƚĂůůǁĞůůƚƵďƵůĂƌĂƐƐĞŵďůŝĞƐхϮϬϬ͛ŝŶ ŽǀĞƌĂůůůĞŶŐƚŚ͕ǁĞůůŽƵƚƐŝĚĞƚŚĞůŝŵŝƚƐŽĨĐŽŶǀĞŶƟŽŶĂůůƵďƌŝĐĂƚŽƌĂŶĚƌŝƐĞƌƐǇƐƚĞŵƐƵƐĞĚĚƵƌŝŶŐĐŽŝůƚƵďŝŶŐĂŶĚǁŝƌĞůŝŶĞǁĞůůŝŶƚĞƌǀĞŶƟŽŶƐ͘ ƐĂƌĞƐƵůƚ͕dd^ŚĂƐĚĞǀĞůŽƉĞĚƐĞǀĞƌĂůƐǇƐƚĞŵƐͬƚĞĐŚŶŝƋƵĞƐĂůŽŶŐǁŝƚŚƉƌŽƉƌŝĞƚĂƌǇƚŽŽůŝŶŐŝŶŽƌĚĞƌƚŽĂĐĐŽŵŵŽĚĂƚĞƚŚŝƐŶĞĞĚ͘ůů ƚŚĞƐĞƐǇƐƚĞŵƐĂůůŽǁĨŽƌƚŚĞƵŶůŝŵŝƚĞĚŽǀĞƌĂůůůĞŶŐƚŚƐŽĨƚƵďƵůĂƌĂƐƐĞŵďůŝĞƐƚŽďĞŝŶƐƚĂůůĞĚŝŶƚŽƚŚĞǁĞůůǁŚŝůĞŵĂŝŶƚĂŝŶŝŶŐŵƵůƟƉůĞǁĞůů ĐŽŶƚƌŽůďĂƌƌŝĞƌƐ͘dŚŝƐŝƐĂĐĐŽŵƉůŝƐŚĞĚďǇďƌĞĂŬŝŶŐƚŚĞĂƐƐĞŵďůǇŝŶƚŽƐŚŽƌƚŽǀĞƌĂůůƐĞĐƟŽŶůĞŶŐƚŚƐŶĞĞĚĞĚƚŽĂĐĐŽŵŵŽĚĂƚĞƚŚĞůŝŵŝƚƐ ŽĨĐŽŵŵŽŶƌŝƐĞƌĂŶĚůƵďƌŝĐĂƚŽƌƐǇƐƚĞŵƐ͘KŶĐĞƚŚĞƐĞƐŚŽƌƚŽƌĨƌĂĐƟŽŶĂůƐĞĐƟŽŶůĞŶŐƚŚƐŽĨƐƵďũĞĐƚƚƵďƵůĂƌĂƐƐĞŵďůŝĞƐĂƌĞŝŶƐƚĂůůĞĚŽƌ ůƵďƌŝĐĂƚĞĚŝŶƚŽƚŚĞǁĞůůŽŶĞĂƚĂƟŵĞ͕ƚŚĞǇĂƌĞũŽŝŶĞĚƚŽŐĞƚŚĞƌĞŝƚŚĞƌĂƚƚŚĞƉůĂŶŶĞĚůĂŶĚŝŶŐĚĞƉƚŚŝŶƚŚĞǁĞůůŽƌĂƚĂŶƵƉͲŚŽůĞůŽĐĂƟŽŶ ŽĨĐŽŶǀĞŶŝĞŶĐĞĂŶĚƚŚĞŶůŽǁĞƌĞĚĂƐŽŶĞƐĞĐƟŽŶƚŽƚŚĞƉůĂŶŶĞĚůĂŶĚŝŶŐĚĞƉƚŚ͘dŚĞĨŽůůŽǁŝŶŐƉĂŐĞƐŝůůƵƐƚƌĂƚĞƐĞǀĞƌĂůŽĨƚŚĞƐĞDƵůƟƉůĞ ĂƌƌŝĞƌĞƉůŽǇŵĞŶƚ^ǇƐƚĞŵƐ͘&ŽƌŵŽƌĞŝŶĨŽƌŵĂƟŽŶƉůĞĂƐĞĐŽŶƚĂĐƚĂŶǇdd^ƌĞƉƌĞƐĞŶƚĂƟǀĞŽƌŽĸĐĞ͘ Sand Control Systems dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ƉƌŽĚƵĐƚƐĂŶĚƐĞƌǀŝĐĞƐĂƌĞƐƵďũĞĐƚƚŽƐƚĂŶĚĂƌĚƚĞƌŵƐĂŶĚĐŽŶĚŝƟŽŶƐ͘hŶůĞƐƐŶŽƚĞĚŽƚŚĞƌǁŝƐĞ͕ƚƌĂĚĞŵĂƌŬƐĂŶĚƐĞƌǀŝĐĞŵĂƌŬƐŶŽƚĞĚŚĞƌĞŝŶĂƌĞƚŚĞ ƉƌŽƉĞƌƚǇŽĨdŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ΞϮϬϭϴ͘dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ůůƌŝŐŚƚƐƌĞƐĞƌǀĞĚ͘ (TTS products are available through authorized service providers.) ǁǁǁ͘ƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵͮͲDĂŝů͗ƩƐΛƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵ 17 TTS Multiple Barrier Deployment Techniques Retrievable Bridge Plug Deployment (Coiled Tubing) Sand Control Systems Z/,ǁŝƚŚdd^WĂƌĂŐŽŶ ZĞƚƌŝĞǀĂďůĞƌŝĚŐĞWůƵŐŽŶ ǁŝƌĞůŝŶĞ͘^ĞƚZWŶĞĂƌĞŶĚŽĨ ƚƵďŝŶŐ͘KŶĐĞƐĞƚ͕ďůĞĞĚǁĞůů ĚŽǁŶƚŽϬƉƐŝ͘ ŌĞƌƵŶƐĞƫŶŐZW͕Z/,ƚŽ WdǁŝƚŚŽŝů͘ZĞůĞĂƐĞ ƐĐƌĞĞŶĂŶĚƉĞƌĨŽƌŵŐƌĂǀĞů ƉĂĐŬ͘ ŌĞƌŐƌĂǀĞůƉĂĐŬ ƉƌŽĐĞĚƵƌĞ͕ƉůĂĐĞǁĞůů ŽŶƉƌŽĚƵĐƟŽŶ͘ ĞƉůŽǇ^ĐƌĞĞŶŝŶǁĞůůĂŶĚ ĂƩĂĐŚƚŽŽŝůdƵďŝŶŐ͘Z/, ĂŶĚůĂƚĐŚZWĂŶĚƐĞƚĚŽǁŶ ƚŽĞƋƵĂůŝǌĞ͘WŝĐŬƵƉƚŽ ƌĞůĞĂƐĞZW͘ dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ƉƌŽĚƵĐƚƐĂŶĚƐĞƌǀŝĐĞƐĂƌĞƐƵďũĞĐƚƚŽƐƚĂŶĚĂƌĚƚĞƌŵƐĂŶĚĐŽŶĚŝƟŽŶƐ͘hŶůĞƐƐŶŽƚĞĚŽƚŚĞƌǁŝƐĞ͕ƚƌĂĚĞŵĂƌŬƐĂŶĚƐĞƌǀŝĐĞŵĂƌŬƐŶŽƚĞĚŚĞƌĞŝŶĂƌĞƚŚĞ ƉƌŽƉĞƌƚǇŽĨdŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ΞϮϬϭϴ͘dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ůůƌŝŐŚƚƐƌĞƐĞƌǀĞĚ͘ (TTS products are available through authorized service providers.) ǁǁǁ͘ƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵͮͲDĂŝů͗ƩƐΛƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵ 18 Sand Control Systems TTS Multiple Barrier Deployment Techniques J-Anchor Deployment/Stackable *Patent Pending (slickline/e-line) Z/,ǁŝƚŚϭƐƚƐĞĐƟŽŶŽĨ ƐĐƌĞĞŶǁŝƚŚ:ͲŶĐŚŽƌŽŶ ďŽƩŽŵĂŶĚWZŽŶƐůŝĐŬ ůŝŶĞ͘^ƚŽƉŝŶƚƵďŝŶŐĂŶĚ ƉŝĐŬƵƉĂŶĚƐůĂĐŬŽīƚŽƐĞƚ ĂŶĐŚŽƌƚŚĞŶũĂƌĚŽǁŶƚŽ ƌĞůĞĂƐĞWZ͘WKK,ǁŝƚŚ^> Z/,ǁŝƚŚϮŶĚƐĞĐƟŽŶ ŽĨƐĐƌĞĞŶĂŶĚďůĂŶŬ ŽŶ^>͘>ĂƚĐŚŝŶƚŽWZ ƉƌĞǀŝŽƵƐůǇĚĞƉůŽǇĞĚ ĂŶĚũĂƌĚŽǁŶƚŽĞŶƐƵƌĞ ůĂƚĐŚĞĚ͘WKK,ǁŝƚŚ^>͘ Z/,ǁŝƚŚϯƌĚƐĞĐƟŽŶŽĨ ďůĂŶŬĂŶĚǀĞŶƚƐĐƌĞĞŶ ŽŶͲůŝŶĞ͘>ĂƚĐŚŝŶƚŽWZ ƉƌĞǀŝŽƵƐůǇĚĞƉůŽǇĞĚ͘ WŝĐŬƵƉƚŽĞŶƐƵƌĞůĂƚĐŚĞĚ ǁŝƚŚĞǆƚƌĂǁĞŝŐŚƚĂŶĚ ƵŶƐĞƚ:ͲĂŶĐŚŽƌ͘ ŌĞƌƉŝĐŬŝŶŐƵƉƚŽƵŶƐĞƚ :ͲĂŶĐŚŽƌZ/,ǁŝƚŚͲůŝŶĞ ĂŶĚůŽŐƐĐƌĞĞŶŽŶWd͘ ZĞůĞĂƐĞƐĐƌĞĞŶĂƐƐĞŵďůǇ ĂŶĚWKK,͘WĞƌĨŽƌŵ ŐƌĂǀĞůƉĂĐŬ͘ ŌĞƌŐƌĂǀĞůƉĂĐŬ ƉƌŽĐĞĚƵƌĞƉůĂĐĞ ǁĞůůŽŶƉƌŽĚƵĐƟŽŶ͘ dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ƉƌŽĚƵĐƚƐĂŶĚƐĞƌǀŝĐĞƐĂƌĞƐƵďũĞĐƚƚŽƐƚĂŶĚĂƌĚƚĞƌŵƐĂŶĚĐŽŶĚŝƟŽŶƐ͘hŶůĞƐƐŶŽƚĞĚŽƚŚĞƌǁŝƐĞ͕ƚƌĂĚĞŵĂƌŬƐĂŶĚƐĞƌǀŝĐĞŵĂƌŬƐŶŽƚĞĚŚĞƌĞŝŶĂƌĞƚŚĞ ƉƌŽƉĞƌƚǇŽĨdŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ΞϮϬϭϴ͘dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ůůƌŝŐŚƚƐƌĞƐĞƌǀĞĚ͘ (TTS products are available through authorized service providers.) ǁǁǁ͘ƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵͮͲDĂŝů͗ƩƐΛƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵ 19 TTS Multiple Barrier Deployment Techniques Proprietary Surface Deployment (slick/e-line/specialized BOP systems) Sand Control Systems ^ƵƌĨĂĐĞZŝŐƵƉŽĨƚƌĞĞ͕KWƐůŝƉƌĂŵƐ ĨŽƌƉŝƉĞ͕ϰ͛ƐƉĂĐĞƌƐƉŽŽůĂŶĚŐĂƚĞ ǀĂůǀĞ͘ZŝŐƵƉǁŝƌĞůŝŶĞKW͛ƐĂŶĚ ůƵďƌŝĐĂƚŽƌĂďŽǀĞŐĂƚĞǀĂůǀĞ͘ DĂŬĞƵƉƐĐƌĞĞŶĂƐƐĞŵďůǇĂŶĚĂƩĂĐŚ ƚŽǁŝƌĞůŝŶĞ͘WŝĐŬƵƉĂƐƐĞŵďůǇŝŶƚŽ ůƵďƌŝĐĂƚŽƌĂŶĚŵĂŬĞƵƉƚŽŐĂƚĞǀĂůǀĞ͘ WƌĞƐƐƵƌĞƚĞƐƚůƵďƌŝĐĂƚŽƌĂŶĚŽƉĞŶ ŐĂƚĞǀĂůǀĞ͘ >ŽǁĞƌǁŝƌĞůŝŶĞĂŶĚƉůĂĐĞďůĂŶŬƉŝƉĞ ĂĐƌŽƐƐKWƐůŝƉƌĂŵƐ͘ŶƐƵƌĞWZŝƐ ůŽĐĂƚĞĚŝŶϰ͛ƐƉĂĐĞƌƐƉŽŽů͘ůŽƐĞƐůŝƉƌĂŵƐ ƚŚĞŶũĂƌƵƉƚŽƌĞůĞĂƐĞWZƌƵŶŶŝŶŐƚŽŽů͘ WŝĐŬƵƉǁŝƌĞůŝŶĞĂďŽǀĞŐĂƚĞǀĂůǀĞĂŶĚ ĐůŽƐĞǀĂůǀĞ͘ůĞĞĚůƵďƌŝĐĂƚŽƌƚŽϬƉƐŝĂŶĚ ďƌĞĂŬĐŽŶŶĞĐƟŽŶĨŽƌŶĞǆƚĂƐƐĞŵďůǇ͘ dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ƉƌŽĚƵĐƚƐĂŶĚƐĞƌǀŝĐĞƐĂƌĞƐƵďũĞĐƚƚŽƐƚĂŶĚĂƌĚƚĞƌŵƐĂŶĚĐŽŶĚŝƟŽŶƐ͘hŶůĞƐƐŶŽƚĞĚŽƚŚĞƌǁŝƐĞ͕ƚƌĂĚĞŵĂƌŬƐĂŶĚƐĞƌǀŝĐĞŵĂƌŬƐŶŽƚĞĚŚĞƌĞŝŶĂƌĞƚŚĞ ƉƌŽƉĞƌƚǇŽĨdŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ΞϮϬϭϴ͘dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ůůƌŝŐŚƚƐƌĞƐĞƌǀĞĚ͘ (TTS products are available through authorized service providers.) ǁǁǁ͘ƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵͮͲDĂŝů͗ƩƐΛƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵ 20 TTS Multiple Barrier Deployment Techniques Proprietary Surface Deployment (slick/e-line/specialized BOP systems) Sand Control Systems DĂŬĞƵƉƐĐƌĞĞŶĂƐƐĞŵďůǇĂŶĚĂƩĂĐŚ ƚŽǁŝƌĞůŝŶĞ͘WŝĐŬƵƉĂƐƐĞŵďůǇŝŶƚŽ ůƵďƌŝĐĂƚŽƌĂŶĚŵĂŬĞƵƉƚŽŐĂƚĞǀĂůǀĞ͘ WƌĞƐƐƵƌĞƚĞƐƚůƵďƌŝĐĂƚŽƌĂŶĚŽƉĞŶŐĂƚĞ valve. >ŽǁĞƌƐĐƌĞĞŶĂƐƐĞŵďůǇĂŶĚůĂƚĐŚ ĂŶĐŚŽƌƚŽWZůĞŌŝŶϰ͛ƐƉĂĐĞƌ ƐƉŽŽů͘WŝĐŬƵƉƚŽĞŶƐƵƌĞůĂƚĐŚĞĚ͘ KŶĐĞĐŽŶĮƌŵĞĚ͕ŽƉĞŶKWƌĂŵƐ͘ KŶĐĞŽƉĞŶ͕Z/,ǁŝƚŚǁŝƌĞůŝŶĞ͘ ŽŶƟŶƵĞƚŽZ/,ĂŶĚ ůŽŐƐĐƌĞĞŶŽŶWd͘ ZĞůĞĂƐĞƐĐƌĞĞŶĂŶĚ WKK,ǁŝƚŚǁŝƌĞůŝŶĞ͘ WĞƌĨŽƌŵŐƌĂǀĞůƉĂĐŬ͘ ŌĞƌŐƌĂǀĞů ƉĂĐŬƉƌŽĐĞĚƵƌĞ͕ ƉůĂĐĞǁĞůůŽŶ ƉƌŽĚƵĐƟŽŶ͘ dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ƉƌŽĚƵĐƚƐĂŶĚƐĞƌǀŝĐĞƐĂƌĞƐƵďũĞĐƚƚŽƐƚĂŶĚĂƌĚƚĞƌŵƐĂŶĚĐŽŶĚŝƟŽŶƐ͘hŶůĞƐƐŶŽƚĞĚŽƚŚĞƌǁŝƐĞ͕ƚƌĂĚĞŵĂƌŬƐĂŶĚƐĞƌǀŝĐĞŵĂƌŬƐŶŽƚĞĚŚĞƌĞŝŶĂƌĞƚŚĞ ƉƌŽƉĞƌƚǇŽĨdŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ΞϮϬϭϴ͘dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ůůƌŝŐŚƚƐƌĞƐĞƌǀĞĚ͘ (TTS products are available through authorized service providers.) ǁǁǁ͘ƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵͮͲDĂŝů͗ƩƐΛƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵ 21 TTS Multiple Barrier Deployment Techniques Stackable Systems for Mono-bore Wells (slickline/e-line) Sand Control Systems Z/,ǁŝƚŚǁŝƌĞůŝŶĞ ĂŶĚƐĞƚdd^WĂƌĂŐŽŶ //^ƵŵƉWĂĐŬĞƌ͘ ŌĞƌƐĞƚWKK,ǁŝƚŚ ǁŝƌĞůŝŶĞ͘ Z/,ǁŝƚŚǁŝƌĞůŝŶĞĂŶĚ ƐĞƚdd^WĂƌĂŐŽŶ//^ƵŵƉ WĂĐŬĞƌ͘ŌĞƌƐĞƚWKK,ǁŝƚŚ ǁŝƌĞůŝŶĞ͘WĞƌĨŽƌĂƚĞǁĞůůĨŽƌ ƉƌŽĚƵĐƟŽŶ͘ WŝĐŬƵƉĂŶĚZ/,ǁŝƚŚƐĐƌĞĞŶ ƐĞĐƟŽŶƐƵƐŝŶŐdd^ŶĐŚŽƌůĂƚĐŚĞƐ ĂŶĚWZ͛Ɛ͘>ĂƚĐŚŝŶŐĞĂĐŚĂŶĐŚŽƌ ůĂƚĐŚƚŽĞĂĐŚWZĂŶĚƚĂŬŝŶŐ ŽǀĞƌƉƵůůƚŽĞŶƐƵƌĞůĂƚĐŚĞĚ͘ dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ƉƌŽĚƵĐƚƐĂŶĚƐĞƌǀŝĐĞƐĂƌĞƐƵďũĞĐƚƚŽƐƚĂŶĚĂƌĚƚĞƌŵƐĂŶĚĐŽŶĚŝƟŽŶƐ͘hŶůĞƐƐŶŽƚĞĚŽƚŚĞƌǁŝƐĞ͕ƚƌĂĚĞŵĂƌŬƐĂŶĚƐĞƌǀŝĐĞŵĂƌŬƐŶŽƚĞĚŚĞƌĞŝŶĂƌĞƚŚĞ ƉƌŽƉĞƌƚǇŽĨdŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ΞϮϬϭϴ͘dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ůůƌŝŐŚƚƐƌĞƐĞƌǀĞĚ͘ (TTS products are available through authorized service providers.) ǁǁǁ͘ƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵͮͲDĂŝů͗ƩƐΛƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵ 22 TTS Multiple Barrier Deployment Techniques Stackable Systems for Mono-bore Wells (slickline/e-line) Sand Control Systems KŶĐĞƌĞƋƵŝƌĞĚƐĐƌĞĞŶĂŶĚďůĂŶŬ ƐĞĐƟŽŶƐĚĞƉůŽǇĞĚ͕ƉĞƌĨŽƌŵŐƌĂǀĞů ƉĂĐŬ͘ŌĞƌŐƌĂǀĞůƉĂĐŬ͕ƉƵůůƉůƵŐ ĨƌŽŵƚŽƉŽĨĂƐƐĞŵďůǇ͘ ŌĞƌƌĞŵŽǀŝŶŐǀĞŶƚƉůƵŐZ/,ǁŝƚŚ dd^WĂƌĂŐŽŶ//WĂĐŬĞƌĂŶĚŽǀĞƌƐŚŽƚƚŽ ƐĞĂůŽŶƉŽůŝƐŚĞĚŶŝƉƉůĞĨŽƌŐƌĂǀĞůƉĂĐŬ ŝƐŽůĂƟŽŶ͘WKK,ǁŝƚŚǁŝƌĞůŝŶĞ͘ ŌĞƌŐƌĂǀĞůƉĂĐŬƉƌŽĐĞĚƵƌĞ ƉůĂĐĞǁĞůůŽŶƉƌŽĚƵĐƟŽŶ͘ Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 3/2/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250302 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# CLU 11 50133205590000 206058 2/19/2025 AK E-LINE CBL,CIBP CLU 11 50133205590000 206058 2/13/2025 AK E-LINE CIBP END 1-65A 50029226270100 203212 1/27/2025 HALLIBURTON COILFLAG END 2-56A 50029228630100 198058 2/6/2025 HALLIBURTON COILFLAG END 2-72 50029237810000 224016 2/2/2025 HALLIBURTON PPROF MPU F-29 50029226880000 196117 1/31/2025 HALLIBURTON MFC24 MPU L-02A 50029219980100 209147 2/17/2025 READ CaliperSurvey MPU L-36 50029227940000 197148 1/18/2025 HALLIBURTON MFC24 MPU R-144 50029238090000 224148 2/11/2025 HALLIBURTON WFL-TMD3D NCIU A-21 50883201990000 224086 2/18/2025 AK E-LINE Perf ODSN-25 50703206560000 212030 2/16/2025 READ MemoryLeakPoint PBU 06-05A 50029202980100 224115 1/15/2025 BAKER MRPM PBU 06-15A 50029204590200 224108 12/27/2024 HALLIBURTON RBT PBU 06-16B 50029204600200 223072 1/25/2025 BAKER MRPM PBU B-12B 50029203320200 224133 1/19/2025 BAKER MRPM PBU S-126B 50029233630200 224084 2/7/2025 HALLIBURTON RBT PBU V-105 50029230970000 202131 2/9/2025 HALLIBURTON IPROF PBU W-01A 50029218660100 203176 1/19/2025 AK E-LINE CBL PBU W-01B 50029218660200 224149 1/28/2025 HALLIBURTON RBT PCU 02A 50283200220100 224110 1/24/2025 AK E-LINE CIBP Please include current contact information if different from above. T40161 T40161 T40162 T40163 T40164 T40165 T40166 T40167 T40168 T40169 T40170 T40171 T40172 T40173 T40174 T40175 T40176 T40177 T40178 T40179PCU 02A 50283200220100 224110 1/24/2025 AK E-LINE CIBP Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.03.03 10:15:14 -09'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: ______________________ 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 5,188 feet 4,027 feet true vertical 4,669 feet N/A feet Effective Depth measured 4,027 feet 1,873 feet true vertical 3,734 feet 1,873 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)Tieback 4-1/2" 12.6# / L-80 1,881' MD 1,881' TVD Packers and SSSV (type, measured and true vertical depth)LTP; N/A 1,873' MD/TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date:Contact Name: Contact Email: Authorized Title:Contact Phone: 3,810psi 7,500psi 3,090psi 6,330psi 8,430psi 2,032'2,032' Burst Collapse 1,540psi Production Liner 2,070' 3,315' Casing Structural 2,070' TOW 4,669' 2,070' TOW 5,188' 339'Conductor Surface Intermediate 20" 13-3/8" 339' 2,032' measured TVD 9-5/9" 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 224-110 50-283-20022-01-00 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: ADL 390780 Pretty Creek / Undefined Gas Pool Pretty Creek Unit (PCU) 02A 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 270 Size 339' 0 4001631 0 10960 921 Chad Helgeson, Operations Engineer 325-021 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 N/A chelgeson@hilcorp.com 907-777-8405 p k ft t Fra O s O 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 Gavin Gluyas at 11:07 am, Feb 26, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.02.25 17:02:34 - 09'00' Noel Nocas (4361) DSR-2/28/25BJM 4/28/25 RBDMS JSB 030325 Page 1/1 Well Name: PCU 002A Report Printed: 2/25/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Jobs Actual Start Date:9/30/2024 End Date: Report Number 31 Report Start Date 1/24/2025 Report End Date 1/25/2025 Last 24hr Summary Pollard slick line services Bail from 4,142' KB to 4,170'. Due to counter wear, acutal final depth is closer to 4,140'. PJSM, Crew travel to Ivan River, Mob equipment to PCU 002A, Spot in & rig up, Pick up lube & tool string (3.70" GR/CCL), Pressure test 250/2500-good, Run in hole to tag @ 4130', Pull out of hole, Pick up & make up run #2 (CIBP 3.7"), Run in hole tag @ 4122', Correlate, Set plug @ 4120', Pull out of hole, Pick up run #3, ( 3 x 10' x 2.5" bailer, Run in hole, Set down @ 3986', Pull out of hole with bailer, Empty bailer at surface (no cement in wellbore), Secure well & lay down for the night. Report Number 32 Report Start Date 1/25/2025 Report End Date 1/26/2025 Last 24hr Summary PJSM, Crew travel to location, Pick up lube & tool string (3.7" GR), Pressure test 250/2500-good, Run in hole, Tag @ 3926', Pull out of hole, Pick up & make up run #2 (2.5" bailer), Run in hole, Tag @ 3926', Work & pull out of hole, Pick up 2" bailer, Run in the hole, Tag @ 3926', Pull out of the hole, Secure well & rig down Eline Report Number 33 Report Start Date 1/26/2025 Report End Date 1/27/2025 Last 24hr Summary SL bailed solids from 3997'kb to 4054'kb. Report Number 34 Report Start Date 1/27/2025 Report End Date 1/28/2025 Last 24hr Summary SL SD most of day for winds, but when wind died continue to bail to 4058'KB Report Number 35 Report Start Date 1/28/2025 Report End Date 1/29/2025 Last 24hr Summary PJSM SL crew travel to location, Slickline bailing f/ 4062-T/4090, Perform drift run w/ 3.73" GR to tag @ 4106' SLM, Rig down Slickline equipment, Spot in & rig up AK eline, Pick up & make up lube & tool string 2" bailer, PT 250/2500, passed. Run in hole, Tag @ 4082', dump bail 5 gal of cement F/4082-T/4076 Pull out of hole, Make up run #2, Run in the hole, Tag @ 4027', Discuss with town, Pull out of hole with bailer cracked plug (5 gal of cement left in hole), Discussed with engineer, not enough room to dump more cement for next perfs. Rig down AK Eline, Rig up pollard slick line, Bail fluid & solids overnight. Report Number 36 Report Start Date 1/29/2025 Report End Date 1/30/2025 Last 24hr Summary Bail fluid from well. Bail fluid with slick line at 4030' SLM, Rig down Slick line & rig up Eline, Pick up lube & tool string (CCL/GR/GUN 2.75"), Pressure test 250/2500-good, Run in hole, Tag @ 4006', Correlate, Perf C1 3989-3999, Pull out of hole, Flow well with production, Incident boom truck crowned (dropped object incident with boom truck) Make repairs, Pick up & make up run #2 (GPT), Run in hole, (No Fluid), Tag @ 4014, Pull out of hole, Secure well & rig down for the night. Report Number 37 Report Start Date 1/30/2025 Report End Date 1/31/2025 Last 24hr Summary PJSM, Crew travel to location, Lock out & tag out well, Swap out 2 x swabs for a single swab, Pressure test 250/2500-good, Pick up lube & tool string (CCL/GUN 2- 3/4"), Run in hole, Tag @ 4003', Correlate, Perf C1 (3989-3999), Pull out of hole, Rig down & release AK Eline, Rig up Pollard slick line, Pick up Lube & tool String (AD2 Stop), Run in the hole, Set AD2 @ 4001', Pull out of hole, Pick up run #2 (3.47' screen), Pull out of the hole, Pick up run #3 (Seal Pack off 3.71") Top of screen assembly 3980', Pull out of hole, Pick up run #4 (AA-Stop), Run in the hole & set @ 3979', Pull out of the hole, Rig down & release Pollard slick line services Field: Pretty Creek Sundry #: State: ALASKA Rig/Service:Permit to Drill (PTD) #:Permit to Drill (PTD) #:224-110 Wellbore API/UWI:50-283-20022-01-00 ), Set plug @ 4120', _____________________________________________________________________________________ Updated by CAH 02-25-25 SCHEMATIC Pretty Creek Unit Well: PCU-02A PTD: 224-110 API: 50-283-20022-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 94 / H-40 / Butt 19”Surf 339’ 13-3/8”Surface 61 / J-55 / Butt 12.515”Surf 2,032’ 9-5/8"Intermediate 47/43.5 P-100/N-80 8.861”Surf 2,070’ (TOW) 4-1/2”Prod Liner 12.6 / L-80 / GBCD 3.883”1,873’5,188’ 4-1/2” Tieback 12.6 / L-80 / JBear & Lion 3.883”Surf 1,881’ OPEN HOLE / CEMENT DETAIL 20”TOC @ Surface 600 sx 13-3/8”TOC @ Surface 675 sx (Stg 2 + Top Job) Stg 1 660 sx 9-5/8"Est. TOC @ 1,500’ 1020 sx Stg 2 / 1110 sx Stg 1 4-1/2”TOC @ 2,058’ based on CBL on 9-30-24; 253 bbls of 12 ppg Lead and 35.5 bls of 15.3 ppg tail JEWELRY DETAIL No.Depth Item 1 18.95 Cactus 11” x 4-1/2” Hanger, 4” Type H BPV profile 2 1,873’Baker 7” x 9.6” SLZXP (HRD-E) Liner top Hanger/Packer 3 1,881’7-3/8” Bullet Seal Assembly & WLEG 43,979’Screen assembly top 24.9ft OAL (See notes below for screen details) 5 4,120’CIBP w/ 15ft of cement mixed with sand – TOC 4,027’ 1/28/25 PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Ft Date Status ST C1 3,989'3,999'3,704'3,712'10 1/29/25 Open ST C5 4,140'4,149'3,823'3,830'9 11/24/24 Isolated Beluga D3 4,251'4,259'3,913'3,919'8 10/4/24 Isolated NOTES Screen Detail AA stop set at 3979 above a D&D Packoff w/ G Fish neck,w/ KOBE KO assembly, w/ 13’ 2-7/8” bakerweld screen on top od AD-2 Stop set at 4001’. (6’ prong w/ 1.9-2.0” swedge to knockout Kobe to equalize before pulling AA stop. 8.5” Ghost hole from 2714’ to 6000’ Short Joints (~10ft)3,351’, 3616’ (w/ RA Tag), 3917’ (w/ RA Tag), 4342’ (w/ RA Tag) 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: 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): 5,188'N/A Casing Collapse Structural Conductor Surface 1,540psi Intermediate 3,810psi 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 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: chelgeson@hilcorp.com Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 390780 224-110 50-283-20022-01-00 Tubing Size: Hilcorp Alaska, LLC Proposed Pools: 12.6# / L-80 TVD Burst 1,881' 8,430psi 2,032' Size 339' 9-5/8"2,070' 2,032' MD 2,070' TOW Length See Attached Schematic 6,330psi 3,090psi 339' 2,070' TOW 339' 2,032' Tubing MD (ft): January 29, 2025 Tieback 4-1/2" 5,188' Perforation Depth MD (ft): See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Pretty Creek Unit (PCU) 02AUndefined Gas Same 4,669'4-1/2" ~1469psi 3,315' N/A Statewide spacing regulations: 20 AAC 25.055 LTP; N/A 1,873' MD / 1,873' TVD; N/A 4,669'5,098'4,597' Pretty Creek Undefined Gas Pool 20" 13-3/8" m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 8:12 am, Jan 21, 2025 325-021 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.01.20 12:31:19 - 09'00' Noel Nocas (4361) A.Dewhurst 23JAN25BJM 1/22/25 Separate sundry required for gravel pack operation. DSR-1/22/25 10-404 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.01.24 10:28:18 -09'00'01/24/25 RBDMS JSB 012425 Well Prognosis Well Name: PCU-2A API Number: 50-283-20022-01-00 Current Status: SI Gas Well Permit to Drill Number: 224-110 First Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Second Call Engineer: Scott Warner (907) 830-8863 Maximum Expected BHP: 1846 psi @ 3768’ TVD (Based on 0.49 psi/ft gradient)) Max. Potential Surface Pressure: 1469 psi (Based on 0.1 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.69 psi/ft using 13.2 ppg EMW FIT at the surface casing shoe 9/11/24 Shallowest Potential Perf TVD: MPSP/(0.69-0.1) = 1469 psi / 0.59 = 2490‘ TVD Well Status: SI sanded up gas well Brief Well Summary: PCU-2A was drilled in September 2024 targeting the Sterling and Beluga sands. The 1st sand tested flowed gas at low rates, the next zone brought in a lot of sand and water. The objective of this sundry is to plug back the open perfs in Beluga & Sterling sands and perforate the Sterling C1 sand. Wellbore Conditions: - SL tagged sand @3798 (1/16/25) - Tubing pressure 1100 psi - IA pressure 270 psi - Fluid level tag @ 2500’ Pre-Sundry work: 1. SL bail fill from well to ~ 4050’ Procedure: 1. RU E-line, PT lubricator to 2500 psi 2. RIH and set CIBP @ ~ 4,050’ (tag plug) 3. PU dump bailer, RIH and set 10ft of cement on plug 4. RIH and perforate per RE/Geo and test Beluga sands within the interval below, from the bottom up: Sand MD Top MD Base TVD Top TVD Base H ST X3 ±3,482' ±3,487' ±3,300' ±3,304' ±5 ST A1 ±3,567' ±3,575' ±3,369' ±3,375' ±8 ST A3 ±3,641' ±3,658' ±3,428' ±3,442' ±17 ST A5 ±3,754' ±3,762' ±3,518' ±3,525' ±8 ST A5 ±3,772' ±3,796' ±3,533' ±3,552' ±24 ST B1 ±3,819' ±3,832' ±3,570' ±3,580' ±13 ST B2 ±3,853' ±3,858' ±3,597' ±3,601' ±5 ST C1 ±3,989' ±4,002' ±3,704' ±3,715' ±13 ST C1 ±4,014' ±4,030' ±3,724' ±3,737' ±16 Well Prognosis a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations. Pending well production, all perf intervals may not be completed b. Post perforating Sterling C1 sand (3989’-4002’), PU packer and screen assembly and set above the perfs, prior to production. Setting the bottom of the screens at approximately 3970’. 5. RDMO 6. Turn well over to production & flow test well Thru tubing gravel pack (Contingency) It is expected that the Sterling X3 sand will need to be gravel packed before it flows: 1. RU E-line, PT lubricator to 2500 psi 2. PU TTS paragon plug, set below perfs 3. Run latch assembly and 125 micron screen assembly with sand height control valve and polish bore receptacle 4. Run vent plug assembly, sting anchor latch into PBR. 5. PU Dump bailer and RIH w/ 30/50 or 20/40 carbo lite to 10ft above top of assembly 6. Pump 2-3 bbls of fluid down into gravel pack (~1 bpm) and dump bailer while pumping, repeat till screens are filled with sand. 7. Pump an additional 1/2 bbl of fluid a. Screen annular volume = 0.0354 x 20ft = 0.708ft^3 b. Blank pipe annular volume = 0.0605 x 30ft = 1.816 ft^3 c. 2.524 ft^3 x 97 lbs/ft = 245 lbs of 30/50 Carbo-Lite 8. Pressure up well to shear Sand Height Control Valve (2200 psi) 9. Pull vent screen assembly with 3” JDC Pulling Tool 10. RIH and set paragon II packer, stabbed into sealbore. 11. RIH and remove vent screen cap 12. Eline set isolation packer with overshot on well. 13. Turn well over to ops, slowly bring on well 14. If well does not flow on its own, SL swab well onto production. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Proposed Gravel pack Well Schematic 4. TTS Gravel Pack Deployment System Gravel pack contingency not approved as part of this sundry. Separate sundry required. -bjm _____________________________________________________________________________________ Updated by CJD 12-9-24 Current Pretty Creek Unit Well: PCU-02A PTD: 224-110 API: 50-283-20022-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 94 / H-40 / Butt 19”Surf 339’ 13-3/8”Surface 61 / J-55 / Butt 12.515”Surf 2,032’ 9-5/8"Intermediate 47/43.5 P-100/N-80 8.861”Surf 2,070’ (TOW) 4-1/2”Prod Liner 12.6 / L-80 / GBCD 3.883”1,873’5,188’ 4-1/2” Tieback 12.6 / L-80 / JBear & Lion 3.883”Surf 1,881’ OPEN HOLE / CEMENT DETAIL 20”TOC @ Surface 600 sx 13-3/8”TOC @ Surface 675 sx (Stg 2 + Top Job) Stg 1 660 sx 9-5/8"Est. TOC @ 1,500’ 1020 sx Stg 2 / 1110 sx Stg 1 4-1/2”TOC @ 2,058’ based on CBL on 9-30-24; 253 bbls of 12 ppg Lead and 35.5 bls of 15.3 ppg tail JEWELRY DETAIL No.Depth Item 1 18.95 Cactus 11” x 4-1/2” Hanger, 4” Type H BPV profile 21,873’Baker 7” x 9.6” SLZXP (HRD-E) Liner top Hanger/Packer 3 1,881’7-3/8” Bullet Seal Assembly & WLEG PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Ft Date Status ST C5 4,140'4,149'3,823'3,830'9 11/24/24 Open Beluga D3 4,251'4,259'3,913'3,919'8 10/4/24 Open NOTES 8.5” Ghost hole from 2714’ to 6000’ Short Joints (~10ft)3,351’, 3616’ (w/ RA Tag), 3917’ (w/ RA Tag), 4342’ (w/ RA Tag) _____________________________________________________________________________________ Updated by CAH 01-13-25 PROPOSED Pretty Creek Unit Well: PCU-02A PTD: 224-110 API: 50-283-20022-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 94 / H-40 / Butt 19”Surf 339’ 13-3/8”Surface 61 / J-55 / Butt 12.515”Surf 2,032’ 9-5/8"Intermediate 47/43.5 P-100/N-80 8.861”Surf 2,070’ (TOW) 4-1/2”Prod Liner 12.6 / L-80 / GBCD 3.883”1,873’5,188’ 4-1/2” Tieback 12.6 / L-80 / JBear & Lion 3.883”Surf 1,881’ OPEN HOLE / CEMENT DETAIL 20”TOC @ Surface 600 sx 13-3/8”TOC @ Surface 675 sx (Stg 2 + Top Job) Stg 1 660 sx 9-5/8"Est. TOC @ 1,500’ 1020 sx Stg 2 / 1110 sx Stg 1 4-1/2”TOC @ 2,058’ based on CBL on 9-30-24; 253 bbls of 12 ppg Lead and 35.5 bls of 15.3 ppg tail JEWELRY DETAIL No.Depth Item 1 18.95 Cactus 11” x 4-1/2” Hanger, 4” Type H BPV profile 21,873’Baker 7” x 9.6” SLZXP (HRD-E) Liner top Hanger/Packer 3 1,881’7-3/8” Bullet Seal Assembly & WLEG 4 ±3,970’WL Packer w/ 20ft of screens hung off bottom 5 ±4,050’CIBP w/ 10ft of cement PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Ft Date Status ST X3 ±3,482'±3,487'±3,300'±3,304'±5 Proposed TBD ST A1 ±3,567'±3,575'±3,369'±3,375'±8 Proposed TBD ST A3 ±3,641'±3,658'±3,428'±3,442'±17 Proposed TBD ST A5 ±3,754'±3,762'±3,518'±3,525'±8 Proposed TBD ST A5 ±3,772'±3,796'±3,533'±3,552'±24 Proposed TBD ST B1 ±3,819'±3,832'±3,570'±3,580'±13 Proposed TBD ST B2 ±3,853'±3,858'±3,597'±3,601'±5 Proposed TBD ST C1 ±3,989'±4,002'±3,704'±3,715'±13 Proposed TBD ST C1 ±4,014'±4,030'±3,724'±3,737'±16 Proposed TBD ST C5 4,140'4,149'3,823'3,830'9 11/24/24 Open Beluga D3 4,251'4,259'3,913'3,919'8 10/4/24 Open NOTES 8.5” Ghost hole from 2714’ to 6000’ Short Joints (~10ft)3,351’, 3616’ (w/ RA Tag), 3917’ (w/ RA Tag), 4342’ (w/ RA Tag) _____________________________________________________________________________________ Updated by CAH 01-20-25 PROPOSED W/ Gravel pack Pretty Creek Unit Well: PCU-02A PTD: 224-110 API: 50-283-20022-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 94 / H-40 / Butt 19”Surf 339’ 13-3/8”Surface 61 / J-55 / Butt 12.515”Surf 2,032’ 9-5/8"Intermediate 47/43.5 P-100/N-80 8.861”Surf 2,070’ (TOW) 4-1/2”Prod Liner 12.6 / L-80 / GBCD 3.883”1,873’5,188’ 4-1/2” Tieback 12.6 / L-80 / JBear & Lion 3.883”Surf 1,881’ OPEN HOLE / CEMENT DETAIL 20”TOC @ Surface 600 sx 13-3/8”TOC @ Surface 675 sx (Stg 2 + Top Job) Stg 1 660 sx 9-5/8"Est. TOC @ 1,500’ 1020 sx Stg 2 / 1110 sx Stg 1 4-1/2”TOC @ 2,058’ based on CBL on 9-30-24; 253 bbls of 12 ppg Lead and 35.5 bls of 15.3 ppg tail JEWELRY DETAIL No.Depth Item 1 18.95 Cactus 11” x 4-1/2” Hanger, 4” Type H BPV profile 21,873’Baker 7” x 9.6” SLZXP (HRD-E) Liner top Hanger/Packer 3 1,881’7-3/8” Bullet Seal Assembly & WLEG 4 ±3,470’ TTS Gravel pack system (Paragon Packer w/ ~40ft of delta pore screens w/ vent plug for sand placement & paragon packer on top) see wellfile for details 5 ±3,800’CIBP w/ 10ft of cement 6 ±3,970’WL Packer w/ 20ft of screens hung off bottom 7 ±4,050’CIBP w/ 10ft of cement PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Ft Date Status ST X3 ±3,482'±3,487'±3,300'±3,304'±5 Proposed TBD ST A1 ±3,567'±3,575'±3,369'±3,375'±8 Proposed TBD ST A3 ±3,641'±3,658'±3,428'±3,442'±17 Proposed TBD ST A5 ±3,754'±3,762'±3,518'±3,525'±8 Proposed TBD ST A5 ±3,772'±3,796'±3,533'±3,552'±24 Proposed TBD ST B1 ±3,819'±3,832'±3,570'±3,580'±13 Proposed TBD ST B2 ±3,853'±3,858'±3,597'±3,601'±5 Proposed TBD ST C1 ±3,989'±4,002'±3,704'±3,715'±13 Proposed TBD ST C1 ±4,014'±4,030'±3,724'±3,737'±16 Proposed TBD ST C5 4,140'4,149'3,823'3,830'9 11/24/24 Open Beluga D3 4,251'4,259'3,913'3,919'8 10/4/24 Open NOTES 8.5” Ghost hole from 2714’ to 6000’ Short Joints (~10ft)3,351’, 3616’ (w/ RA Tag), 3917’ (w/ RA Tag), 4342’ (w/ RA Tag) dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ƉƌŽĚƵĐƚƐĂŶĚƐĞƌǀŝĐĞƐĂƌĞƐƵďũĞĐƚƚŽƐƚĂŶĚĂƌĚƚĞƌŵƐĂŶĚĐŽŶĚŝƟŽŶƐ͘hŶůĞƐƐŶŽƚĞĚŽƚŚĞƌǁŝƐĞ͕ƚƌĂĚĞŵĂƌŬƐĂŶĚƐĞƌǀŝĐĞŵĂƌŬƐŶŽƚĞĚŚĞƌĞŝŶĂƌĞƚŚĞ ƉƌŽƉĞƌƚǇŽĨdŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ΞϮϬϭϴ͘dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ůůƌŝŐŚƚƐƌĞƐĞƌǀĞĚ͘ (TTS products are available through authorized service providers.) ǁǁǁ͘ƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵͮͲDĂŝů͗ƩƐΛƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵ 16 dd^DƵůƟƉůĞĂƌƌŝĞƌĞƉůŽǇŵĞŶƚdĞĐŚŶŝƋƵĞƐĂŶĚ^ǇƐƚĞŵƐ YƵŝƚĞŽŌĞŶĚƵƌŝŶŐŶŽŶͲƌŝŐǁĞůůŝŶƚĞƌǀĞŶƟŽŶŽƉĞƌĂƟŽŶƐŝƚŝƐŶĞĐĞƐƐĂƌǇŽƌĚĞƐŝƌĞĚƚŽŝŶƐƚĂůůůŽŶŐƐĞĐƟŽŶƐŽĨƚƵďƵůĂƌƐŝŶƚŽƚŚĞǁĞůů͕ƐƵĐŚ ĂƐƐĂŶĚƐĐƌĞĞŶƐĂŶĚƐŝŵŝůĂƌƚƵďƵůĂƌĂƐƐĞŵďůŝĞƐ͘dŚŝƐŶĞĐĞƐƐŝƚǇĐƌĞĂƚĞƐŵĂŶǇĐŚĂůůĞŶŐĞƐĨŽƌŽƉĞƌĂƚŽƌƐĂŶĚƐĞƌǀŝĐĞĐŽŵƉĂŶŝĞƐǁŝƚŚ ƌĞŐĂƌĚƐƚŽŵĂŝŶƚĂŝŶŝŶŐǁĞůůĐŽŶƚƌŽůĚƵƌŝŶŐƚŚĞƐĞŝŶƐƚĂůůĂƟŽŶƐ͘ ƐŵŽƐƚŶŽŶͲƌŝŐǁĞůůŝŶƚĞƌǀĞŶƟŽŶƐŝŶǀŽůǀĞƚŚĞƵƐĞŽĨĐŽŝůƚƵďŝŶŐŽƌǁŝƌĞůŝŶĞŽƉĞƌĂƟŽŶƐŝŶƚĞƌǀĞŶŝŶŐƚŚƌŽƵŐŚƚŚĞĞǆŝƐƟŶŐƉƌŽĚƵĐƟŽŶ ƚƵďŝŶŐŽŶůŝǀĞǁĞůůƐ͕ĂŵĞĂŶƐďǇǁŚŝĐŚƚŽŝŶƐƚĂůůƚŚĞƐĞůŽŶŐĂƐƐĞŵďůŝĞƐŝŶƚŽƚŚĞǁĞůůǁŚŝůĞŵĂŝŶƚĂŝŶŝŶŐŵƵůƟƉůĞďĂƌƌŝĞƌƐŽĨǁĞůůĐŽŶƚƌŽů ďĞĐŽŵĞƐĂŶĞĐĞƐƐŝƚǇ͘ŽŵŵŽŶƉƌĂĐƟĐĞŚĂƐďĞĞŶƚŽůƵďƌŝĐĂƚĞƚŚĞĂƐƐĞŵďůǇŝŶƚŽƚŚĞǁĞůůďǇƵƐŝŶŐĞŝƚŚĞƌĂǁŝƌĞůŝŶĞůƵďƌŝĐĂƚŽƌĚƵƌŝŶŐ ǁŝƌĞůŝŶĞŝŶƚĞƌǀĞŶƟŽŶƐŽƌĂƌŝƐĞƌĂƐƐĞŵďůǇǁŚĞŶĐŽŝůĞĚƚƵďŝŶŐŝƐƵƐĞĚĨŽƌĐŽŶǀĞǇĂŶĐĞ͘ŽƚŚƐǇƐƚĞŵƐůŝŵŝƚƚŚĞŽǀĞƌĂůůůĞŶŐƚŚŽĨĂƐƐĞŵďůǇ ƚŚĂƚĐĂŶďĞŝŶƐƚĂůůĞĚŝŶƚŚĞǁĞůů͘dŚĞůŝŵŝƚĂƟŽŶŽĨŽǀĞƌĂůůůĞŶŐƚŚƐŽĨƚŚĞƐĞĂƐƐĞŵďůŝĞƐĂƌĞƌĞůĂƟǀĞƚŽŚŽǁŵƵĐŚůĞŶŐƚŚŽĨƌŝƐĞƌŽƌ ůƵďƌŝĐĂƚŽƌƚŚĂƚĐĂŶďĞƌŝŐŐĞĚƵƉŽƌŝŶƐƚĂůůĞĚŽŶƚŽƉŽĨƚŚĞǁĞůůŚƌŝƐƚŵĂƐƚƌĞĞ͘DŽƐƚǁĞůůůŽĐĂƟŽŶƐůŝŵŝƚƚŚĞƚŽƚĂůůĞŶŐƚŚŽĨĞŝƚŚĞƌ ůƵďƌŝĐĂƚŽƌŽƌƌŝƐĞƌƚŽфϭϬϬ͛͘ ƵƌŝŶŐŝŶƐƚĂůůĂƟŽŶŽĨdd^͛ƐdŚƌƵdƵďŝŶŐ'ƌĂǀĞůWĂĐŬ^ǇƐƚĞŵƐ͕ŝƚŝƐĂĐŽŵŵŽŶƌĞƋƵŝƌĞŵĞŶƚƚŽŝŶƐƚĂůůǁĞůůƚƵďƵůĂƌĂƐƐĞŵďůŝĞƐхϮϬϬ͛ŝŶ ŽǀĞƌĂůůůĞŶŐƚŚ͕ǁĞůůŽƵƚƐŝĚĞƚŚĞůŝŵŝƚƐŽĨĐŽŶǀĞŶƟŽŶĂůůƵďƌŝĐĂƚŽƌĂŶĚƌŝƐĞƌƐǇƐƚĞŵƐƵƐĞĚĚƵƌŝŶŐĐŽŝůƚƵďŝŶŐĂŶĚǁŝƌĞůŝŶĞǁĞůůŝŶƚĞƌǀĞŶƟŽŶƐ͘ ƐĂƌĞƐƵůƚ͕dd^ŚĂƐĚĞǀĞůŽƉĞĚƐĞǀĞƌĂůƐǇƐƚĞŵƐͬƚĞĐŚŶŝƋƵĞƐĂůŽŶŐǁŝƚŚƉƌŽƉƌŝĞƚĂƌǇƚŽŽůŝŶŐŝŶŽƌĚĞƌƚŽĂĐĐŽŵŵŽĚĂƚĞƚŚŝƐŶĞĞĚ͘ůů ƚŚĞƐĞƐǇƐƚĞŵƐĂůůŽǁĨŽƌƚŚĞƵŶůŝŵŝƚĞĚŽǀĞƌĂůůůĞŶŐƚŚƐŽĨƚƵďƵůĂƌĂƐƐĞŵďůŝĞƐƚŽďĞŝŶƐƚĂůůĞĚŝŶƚŽƚŚĞǁĞůůǁŚŝůĞŵĂŝŶƚĂŝŶŝŶŐŵƵůƟƉůĞǁĞůů ĐŽŶƚƌŽůďĂƌƌŝĞƌƐ͘dŚŝƐŝƐĂĐĐŽŵƉůŝƐŚĞĚďǇďƌĞĂŬŝŶŐƚŚĞĂƐƐĞŵďůǇŝŶƚŽƐŚŽƌƚŽǀĞƌĂůůƐĞĐƟŽŶůĞŶŐƚŚƐŶĞĞĚĞĚƚŽĂĐĐŽŵŵŽĚĂƚĞƚŚĞůŝŵŝƚƐ ŽĨĐŽŵŵŽŶƌŝƐĞƌĂŶĚůƵďƌŝĐĂƚŽƌƐǇƐƚĞŵƐ͘KŶĐĞƚŚĞƐĞƐŚŽƌƚŽƌĨƌĂĐƟŽŶĂůƐĞĐƟŽŶůĞŶŐƚŚƐŽĨƐƵďũĞĐƚƚƵďƵůĂƌĂƐƐĞŵďůŝĞƐĂƌĞŝŶƐƚĂůůĞĚŽƌ ůƵďƌŝĐĂƚĞĚŝŶƚŽƚŚĞǁĞůůŽŶĞĂƚĂƟŵĞ͕ƚŚĞǇĂƌĞũŽŝŶĞĚƚŽŐĞƚŚĞƌĞŝƚŚĞƌĂƚƚŚĞƉůĂŶŶĞĚůĂŶĚŝŶŐĚĞƉƚŚŝŶƚŚĞǁĞůůŽƌĂƚĂŶƵƉͲŚŽůĞůŽĐĂƟŽŶ ŽĨĐŽŶǀĞŶŝĞŶĐĞĂŶĚƚŚĞŶůŽǁĞƌĞĚĂƐŽŶĞƐĞĐƟŽŶƚŽƚŚĞƉůĂŶŶĞĚůĂŶĚŝŶŐĚĞƉƚŚ͘dŚĞĨŽůůŽǁŝŶŐƉĂŐĞƐŝůůƵƐƚƌĂƚĞƐĞǀĞƌĂůŽĨƚŚĞƐĞDƵůƟƉůĞ ĂƌƌŝĞƌĞƉůŽǇŵĞŶƚ^ǇƐƚĞŵƐ͘&ŽƌŵŽƌĞŝŶĨŽƌŵĂƟŽŶƉůĞĂƐĞĐŽŶƚĂĐƚĂŶǇdd^ƌĞƉƌĞƐĞŶƚĂƟǀĞŽƌŽĸĐĞ͘ Sand Control Systems dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ƉƌŽĚƵĐƚƐĂŶĚƐĞƌǀŝĐĞƐĂƌĞƐƵďũĞĐƚƚŽƐƚĂŶĚĂƌĚƚĞƌŵƐĂŶĚĐŽŶĚŝƟŽŶƐ͘hŶůĞƐƐŶŽƚĞĚŽƚŚĞƌǁŝƐĞ͕ƚƌĂĚĞŵĂƌŬƐĂŶĚƐĞƌǀŝĐĞŵĂƌŬƐŶŽƚĞĚŚĞƌĞŝŶĂƌĞƚŚĞ ƉƌŽƉĞƌƚǇŽĨdŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ΞϮϬϭϴ͘dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ůůƌŝŐŚƚƐƌĞƐĞƌǀĞĚ͘ (TTS products are available through authorized service providers.) ǁǁǁ͘ƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵͮͲDĂŝů͗ƩƐΛƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵ 17 TTS Multiple Barrier Deployment Techniques Retrievable Bridge Plug Deployment (Coiled Tubing) Sand Control Systems Z/,ǁŝƚŚdd^WĂƌĂŐŽŶ ZĞƚƌŝĞǀĂďůĞƌŝĚŐĞWůƵŐŽŶ ǁŝƌĞůŝŶĞ͘^ĞƚZWŶĞĂƌĞŶĚŽĨ ƚƵďŝŶŐ͘KŶĐĞƐĞƚ͕ďůĞĞĚǁĞůů ĚŽǁŶƚŽϬƉƐŝ͘ ŌĞƌƵŶƐĞƫŶŐZW͕Z/,ƚŽ WdǁŝƚŚŽŝů͘ZĞůĞĂƐĞ ƐĐƌĞĞŶĂŶĚƉĞƌĨŽƌŵŐƌĂǀĞů ƉĂĐŬ͘ ŌĞƌŐƌĂǀĞůƉĂĐŬ ƉƌŽĐĞĚƵƌĞ͕ƉůĂĐĞǁĞůů ŽŶƉƌŽĚƵĐƟŽŶ͘ ĞƉůŽǇ^ĐƌĞĞŶŝŶǁĞůůĂŶĚ ĂƩĂĐŚƚŽŽŝůdƵďŝŶŐ͘Z/, ĂŶĚůĂƚĐŚZWĂŶĚƐĞƚĚŽǁŶ ƚŽĞƋƵĂůŝǌĞ͘WŝĐŬƵƉƚŽ ƌĞůĞĂƐĞZW͘ dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ƉƌŽĚƵĐƚƐĂŶĚƐĞƌǀŝĐĞƐĂƌĞƐƵďũĞĐƚƚŽƐƚĂŶĚĂƌĚƚĞƌŵƐĂŶĚĐŽŶĚŝƟŽŶƐ͘hŶůĞƐƐŶŽƚĞĚŽƚŚĞƌǁŝƐĞ͕ƚƌĂĚĞŵĂƌŬƐĂŶĚƐĞƌǀŝĐĞŵĂƌŬƐŶŽƚĞĚŚĞƌĞŝŶĂƌĞƚŚĞ ƉƌŽƉĞƌƚǇŽĨdŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ΞϮϬϭϴ͘dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ůůƌŝŐŚƚƐƌĞƐĞƌǀĞĚ͘ (TTS products are available through authorized service providers.) ǁǁǁ͘ƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵͮͲDĂŝů͗ƩƐΛƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵ 18 Sand Control Systems TTS Multiple Barrier Deployment Techniques J-Anchor Deployment/Stackable *Patent Pending (slickline/e-line) Z/,ǁŝƚŚϭƐƚƐĞĐƟŽŶŽĨ ƐĐƌĞĞŶǁŝƚŚ:ͲŶĐŚŽƌŽŶ ďŽƩŽŵĂŶĚWZŽŶƐůŝĐŬ ůŝŶĞ͘^ƚŽƉŝŶƚƵďŝŶŐĂŶĚ ƉŝĐŬƵƉĂŶĚƐůĂĐŬŽīƚŽƐĞƚ ĂŶĐŚŽƌƚŚĞŶũĂƌĚŽǁŶƚŽ ƌĞůĞĂƐĞWZ͘WKK,ǁŝƚŚ^> Z/,ǁŝƚŚϮŶĚƐĞĐƟŽŶ ŽĨƐĐƌĞĞŶĂŶĚďůĂŶŬ ŽŶ^>͘>ĂƚĐŚŝŶƚŽWZ ƉƌĞǀŝŽƵƐůǇĚĞƉůŽǇĞĚ ĂŶĚũĂƌĚŽǁŶƚŽĞŶƐƵƌĞ ůĂƚĐŚĞĚ͘WKK,ǁŝƚŚ^>͘ Z/,ǁŝƚŚϯƌĚƐĞĐƟŽŶŽĨ ďůĂŶŬĂŶĚǀĞŶƚƐĐƌĞĞŶ ŽŶͲůŝŶĞ͘>ĂƚĐŚŝŶƚŽWZ ƉƌĞǀŝŽƵƐůǇĚĞƉůŽǇĞĚ͘ WŝĐŬƵƉƚŽĞŶƐƵƌĞůĂƚĐŚĞĚ ǁŝƚŚĞǆƚƌĂǁĞŝŐŚƚĂŶĚ ƵŶƐĞƚ:ͲĂŶĐŚŽƌ͘ ŌĞƌƉŝĐŬŝŶŐƵƉƚŽƵŶƐĞƚ :ͲĂŶĐŚŽƌZ/,ǁŝƚŚͲůŝŶĞ ĂŶĚůŽŐƐĐƌĞĞŶŽŶWd͘ ZĞůĞĂƐĞƐĐƌĞĞŶĂƐƐĞŵďůǇ ĂŶĚWKK,͘WĞƌĨŽƌŵ ŐƌĂǀĞůƉĂĐŬ͘ ŌĞƌŐƌĂǀĞůƉĂĐŬ ƉƌŽĐĞĚƵƌĞƉůĂĐĞ ǁĞůůŽŶƉƌŽĚƵĐƟŽŶ͘ dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ƉƌŽĚƵĐƚƐĂŶĚƐĞƌǀŝĐĞƐĂƌĞƐƵďũĞĐƚƚŽƐƚĂŶĚĂƌĚƚĞƌŵƐĂŶĚĐŽŶĚŝƟŽŶƐ͘hŶůĞƐƐŶŽƚĞĚŽƚŚĞƌǁŝƐĞ͕ƚƌĂĚĞŵĂƌŬƐĂŶĚƐĞƌǀŝĐĞŵĂƌŬƐŶŽƚĞĚŚĞƌĞŝŶĂƌĞƚŚĞ ƉƌŽƉĞƌƚǇŽĨdŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ΞϮϬϭϴ͘dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ůůƌŝŐŚƚƐƌĞƐĞƌǀĞĚ͘ (TTS products are available through authorized service providers.) ǁǁǁ͘ƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵͮͲDĂŝů͗ƩƐΛƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵ 19 TTS Multiple Barrier Deployment Techniques Proprietary Surface Deployment (slick/e-line/specialized BOP systems) Sand Control Systems ^ƵƌĨĂĐĞZŝŐƵƉŽĨƚƌĞĞ͕KWƐůŝƉƌĂŵƐ ĨŽƌƉŝƉĞ͕ϰ͛ƐƉĂĐĞƌƐƉŽŽůĂŶĚŐĂƚĞ ǀĂůǀĞ͘ZŝŐƵƉǁŝƌĞůŝŶĞKW͛ƐĂŶĚ ůƵďƌŝĐĂƚŽƌĂďŽǀĞŐĂƚĞǀĂůǀĞ͘ DĂŬĞƵƉƐĐƌĞĞŶĂƐƐĞŵďůǇĂŶĚĂƩĂĐŚ ƚŽǁŝƌĞůŝŶĞ͘WŝĐŬƵƉĂƐƐĞŵďůǇŝŶƚŽ ůƵďƌŝĐĂƚŽƌĂŶĚŵĂŬĞƵƉƚŽŐĂƚĞǀĂůǀĞ͘ WƌĞƐƐƵƌĞƚĞƐƚůƵďƌŝĐĂƚŽƌĂŶĚŽƉĞŶ ŐĂƚĞǀĂůǀĞ͘ >ŽǁĞƌǁŝƌĞůŝŶĞĂŶĚƉůĂĐĞďůĂŶŬƉŝƉĞ ĂĐƌŽƐƐKWƐůŝƉƌĂŵƐ͘ŶƐƵƌĞWZŝƐ ůŽĐĂƚĞĚŝŶϰ͛ƐƉĂĐĞƌƐƉŽŽů͘ůŽƐĞƐůŝƉƌĂŵƐ ƚŚĞŶũĂƌƵƉƚŽƌĞůĞĂƐĞWZƌƵŶŶŝŶŐƚŽŽů͘ WŝĐŬƵƉǁŝƌĞůŝŶĞĂďŽǀĞŐĂƚĞǀĂůǀĞĂŶĚ ĐůŽƐĞǀĂůǀĞ͘ůĞĞĚůƵďƌŝĐĂƚŽƌƚŽϬƉƐŝĂŶĚ ďƌĞĂŬĐŽŶŶĞĐƟŽŶĨŽƌŶĞǆƚĂƐƐĞŵďůǇ͘ dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ƉƌŽĚƵĐƚƐĂŶĚƐĞƌǀŝĐĞƐĂƌĞƐƵďũĞĐƚƚŽƐƚĂŶĚĂƌĚƚĞƌŵƐĂŶĚĐŽŶĚŝƟŽŶƐ͘hŶůĞƐƐŶŽƚĞĚŽƚŚĞƌǁŝƐĞ͕ƚƌĂĚĞŵĂƌŬƐĂŶĚƐĞƌǀŝĐĞŵĂƌŬƐŶŽƚĞĚŚĞƌĞŝŶĂƌĞƚŚĞ ƉƌŽƉĞƌƚǇŽĨdŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ΞϮϬϭϴ͘dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ůůƌŝŐŚƚƐƌĞƐĞƌǀĞĚ͘ (TTS products are available through authorized service providers.) ǁǁǁ͘ƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵͮͲDĂŝů͗ƩƐΛƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵ 20 TTS Multiple Barrier Deployment Techniques Proprietary Surface Deployment (slick/e-line/specialized BOP systems) Sand Control Systems DĂŬĞƵƉƐĐƌĞĞŶĂƐƐĞŵďůǇĂŶĚĂƩĂĐŚ ƚŽǁŝƌĞůŝŶĞ͘WŝĐŬƵƉĂƐƐĞŵďůǇŝŶƚŽ ůƵďƌŝĐĂƚŽƌĂŶĚŵĂŬĞƵƉƚŽŐĂƚĞǀĂůǀĞ͘ WƌĞƐƐƵƌĞƚĞƐƚůƵďƌŝĐĂƚŽƌĂŶĚŽƉĞŶŐĂƚĞ valve. >ŽǁĞƌƐĐƌĞĞŶĂƐƐĞŵďůǇĂŶĚůĂƚĐŚ ĂŶĐŚŽƌƚŽWZůĞŌŝŶϰ͛ƐƉĂĐĞƌ ƐƉŽŽů͘WŝĐŬƵƉƚŽĞŶƐƵƌĞůĂƚĐŚĞĚ͘ KŶĐĞĐŽŶĮƌŵĞĚ͕ŽƉĞŶKWƌĂŵƐ͘ KŶĐĞŽƉĞŶ͕Z/,ǁŝƚŚǁŝƌĞůŝŶĞ͘ ŽŶƟŶƵĞƚŽZ/,ĂŶĚ ůŽŐƐĐƌĞĞŶŽŶWd͘ ZĞůĞĂƐĞƐĐƌĞĞŶĂŶĚ WKK,ǁŝƚŚǁŝƌĞůŝŶĞ͘ WĞƌĨŽƌŵŐƌĂǀĞůƉĂĐŬ͘ ŌĞƌŐƌĂǀĞů ƉĂĐŬƉƌŽĐĞĚƵƌĞ͕ ƉůĂĐĞǁĞůůŽŶ ƉƌŽĚƵĐƟŽŶ͘ dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ƉƌŽĚƵĐƚƐĂŶĚƐĞƌǀŝĐĞƐĂƌĞƐƵďũĞĐƚƚŽƐƚĂŶĚĂƌĚƚĞƌŵƐĂŶĚĐŽŶĚŝƟŽŶƐ͘hŶůĞƐƐŶŽƚĞĚŽƚŚĞƌǁŝƐĞ͕ƚƌĂĚĞŵĂƌŬƐĂŶĚƐĞƌǀŝĐĞŵĂƌŬƐŶŽƚĞĚŚĞƌĞŝŶĂƌĞƚŚĞ ƉƌŽƉĞƌƚǇŽĨdŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ΞϮϬϭϴ͘dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ůůƌŝŐŚƚƐƌĞƐĞƌǀĞĚ͘ (TTS products are available through authorized service providers.) ǁǁǁ͘ƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵͮͲDĂŝů͗ƩƐΛƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵ 21 TTS Multiple Barrier Deployment Techniques Stackable Systems for Mono-bore Wells (slickline/e-line) Sand Control Systems Z/,ǁŝƚŚǁŝƌĞůŝŶĞ ĂŶĚƐĞƚdd^WĂƌĂŐŽŶ //^ƵŵƉWĂĐŬĞƌ͘ ŌĞƌƐĞƚWKK,ǁŝƚŚ ǁŝƌĞůŝŶĞ͘ Z/,ǁŝƚŚǁŝƌĞůŝŶĞĂŶĚ ƐĞƚdd^WĂƌĂŐŽŶ//^ƵŵƉ WĂĐŬĞƌ͘ŌĞƌƐĞƚWKK,ǁŝƚŚ ǁŝƌĞůŝŶĞ͘WĞƌĨŽƌĂƚĞǁĞůůĨŽƌ ƉƌŽĚƵĐƟŽŶ͘ WŝĐŬƵƉĂŶĚZ/,ǁŝƚŚƐĐƌĞĞŶ ƐĞĐƟŽŶƐƵƐŝŶŐdd^ŶĐŚŽƌůĂƚĐŚĞƐ ĂŶĚWZ͛Ɛ͘>ĂƚĐŚŝŶŐĞĂĐŚĂŶĐŚŽƌ ůĂƚĐŚƚŽĞĂĐŚWZĂŶĚƚĂŬŝŶŐ ŽǀĞƌƉƵůůƚŽĞŶƐƵƌĞůĂƚĐŚĞĚ͘ dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ƉƌŽĚƵĐƚƐĂŶĚƐĞƌǀŝĐĞƐĂƌĞƐƵďũĞĐƚƚŽƐƚĂŶĚĂƌĚƚĞƌŵƐĂŶĚĐŽŶĚŝƟŽŶƐ͘hŶůĞƐƐŶŽƚĞĚŽƚŚĞƌǁŝƐĞ͕ƚƌĂĚĞŵĂƌŬƐĂŶĚƐĞƌǀŝĐĞŵĂƌŬƐŶŽƚĞĚŚĞƌĞŝŶĂƌĞƚŚĞ ƉƌŽƉĞƌƚǇŽĨdŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ΞϮϬϭϴ͘dŚƌƵͲdƵďŝŶŐ^ǇƐƚĞŵƐ͕/ŶĐ͘ůůƌŝŐŚƚƐƌĞƐĞƌǀĞĚ͘ (TTS products are available through authorized service providers.) ǁǁǁ͘ƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵͮͲDĂŝů͗ƩƐΛƚŚƌƵƚƵďŝŶŐƐǇƐƚĞŵƐ͘ĐŽŵ 22 TTS Multiple Barrier Deployment Techniques Stackable Systems for Mono-bore Wells (slickline/e-line) Sand Control Systems KŶĐĞƌĞƋƵŝƌĞĚƐĐƌĞĞŶĂŶĚďůĂŶŬ ƐĞĐƟŽŶƐĚĞƉůŽǇĞĚ͕ƉĞƌĨŽƌŵŐƌĂǀĞů ƉĂĐŬ͘ŌĞƌŐƌĂǀĞůƉĂĐŬ͕ƉƵůůƉůƵŐ ĨƌŽŵƚŽƉŽĨĂƐƐĞŵďůǇ͘ ŌĞƌƌĞŵŽǀŝŶŐǀĞŶƚƉůƵŐZ/,ǁŝƚŚ dd^WĂƌĂŐŽŶ//WĂĐŬĞƌĂŶĚŽǀĞƌƐŚŽƚƚŽ ƐĞĂůŽŶƉŽůŝƐŚĞĚŶŝƉƉůĞĨŽƌŐƌĂǀĞůƉĂĐŬ ŝƐŽůĂƟŽŶ͘WKK,ǁŝƚŚǁŝƌĞůŝŶĞ͘ ŌĞƌŐƌĂǀĞůƉĂĐŬƉƌŽĐĞĚƵƌĞ ƉůĂĐĞǁĞůůŽŶƉƌŽĚƵĐƟŽŶ͘ 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): Pretty Creek Unit GL: 82' BF: N/A 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 N/A (ft MSL) 22.Logs Obtained: 23. BOTTOM 4-1/2"L-80 4,669' 4-1/2"L-80 1,881' 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 Sr Res EngSr Pet GeoSr Pet Eng N/A N/A Oil-Bbl:Water-Bbl: 0 01090275 11/29/2024 24 Flow Tubing 0 500 N/A5000 Choke Size: 1,873' Per 20 AAC 25.283 (i)(2) attach electronic information 12.6 5,188' Water-Bbl: PRODUCTION TEST 11/3/2024 Date of Test:Oil-Bbl: Flowing *** Please see attached schematic for perforation detail *** Gas-Oil Ratio: 1,873' Tieback Assy. 8-1/2" SIZE DEPTH SET (MD)If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date perf'd or liner run): 12.6 Surface 1,881'Surface Tieback N/A 2,070' MD / 2,070' TVD N/A 5,188' MD / 4,669' TVD 5,098' MD / 4,597' TVD 604' FNL, 1790' FEL, Sec 33, T14N, R9W, SM, AK 27' FNL, 1586' FEL, Sec 33, T14N, R9W, SM, AK AMOUNT PULLED 342899 343109 TOP SETTING DEPTH MD suspension, or abandonment; or within 90 days of acquisition of the log, 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 only if necessary. GRADE CEMENTING RECORD 2655864 SETTING DEPTH TVD 2656439 TOP HOLE SIZEBOTTOMCASINGWT. PER FT. 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 342548 2654865 50-283-20022-01-00September 11, 2024 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 10/4/2024 224-110 / 324-540 N/A PCU 02ASeptember 18, 20241608' FNL, 2128' FEL, Sec 33, T14N, R9W, SM, AK 100.5' Undefined Gas Pool ADL 390780 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 L - 606 sx / T - 180 sx CBL 9-30-24, Mudlogs, LWD (DGR, PCG, ADR, CTN, ALD, PWD, DDSR) +PB1, Tie In/Perf Logs PACKER SET (MD/TVD) N/A G s d 1 0 p d B P L s (att Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment By James Brooks at 8:54 am, Dec 12, 2024 Completed 10/4/2024 JSB RBDMS JSB 121724 GDSR-4/7/25BJM 3/13/25 SFD 2/6/2025 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD N/A N/A Top of Productive Interval ST C5 4140' 4149' 3554' 3359' 3795' 3551' 3979' 3696' 4131' 3816' 4186' 3861' 4219' 3887' 4287' 3942' 4702' 4276' 4911' 4445' 5046' 4554' 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 Digital Signature with Date:Contact Email:cdinger@hilcorp.com Contact Phone: 907-777-8389 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 Name at TD: 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. Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). 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; or 90 days after log acquisition, whichever occurs first. Bel F10 Bel F7 ST C5 ST A1 Bel D Bel F ST B1 ST C1 Bel D3 Bel D6 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. 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). This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 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). Authorized Name and Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. INSTRUCTIONS Wellbore Schematic, Drilling and Completion Reports, Defintive Directional Surveys +PB1, Csg and Cmt Report. Authorized Title: Drilling Manager If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired. Yes No Well tested? Yes No 28. CORE DATA If Yes, list intervals and formations tested, briefly summarizing test results for each. Attach separate pages if needed and submit detailed test info including reports and Excel or ASCII tables per 20 AAC 25.071. NAME Permafrost - Top Permafrost - Base 29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered)FORMATION TESTS N Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2024.12.11 15:09:25 - 09'00' Sean McLaughlin (4311) _____________________________________________________________________________________ Updated by CJD 12-9-24 Current Pretty Creek Unit Well:PCU-02A PTD:224-110 API: 50-283-20022-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 94 / H-40 / Butt 19”Surf 339’ 13-3/8”Surface 61 / J-55 / Butt 12.515”Surf 2,032’ 9-5/8"Intermediate 47/43.5 P-100/N-80 8.861”Surf 2,070’ (TOW) 4-1/2”Prod Casing 12.6 / L-80 / GBCD 3.883”1,873’5,188’ 4-1/2” Tieback 12.6 / L-80 / JBear & Lion 3.883”Surf 1,881’ OPEN HOLE / CEMENT DETAIL 20”TOC @ Surface 600 sx 13-3/8”TOC @ Surface 675 sx (Stg 2 + Top Job) Stg 1 660 sx 9-5/8"Est. TOC @ 1,500’ 1020 sx Stg 2 / 1110 sx Stg 1 4-1/2”TOC @ 2,058’ based on CBL on 9-30-24; 253 bbls of 12 ppg Lead and 35.5 bls of 15.3 ppg tail JEWELRY DETAIL No.Depth Item 1 18.95 Cactus 11” x 4-1/2” Hanger, 4” Type H BPV profile 21,873’Baker 7” x 9.6” SLZXP (HRD-E) Liner top Hanger/Packer 3 1,881’7-3/8” Bullet Seal Assembly & WLEG PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Ft Date Status ST C5 4,140'4,149'3,823'3,830'9 11/24/24 Open Beluga D3 4,251'4,259'3,913'3,919'8 10/4/24 Open NOTES 8.5” Ghost hole from 2714’ to 6000’ Short Joints (~10ft)3,351’, 3616’ (w/ RA Tag), 3917’ (w/ RA Tag), 4342’ (w/ RA Tag) Page 1/5 Well Name: PCU 002A Report Printed: 12/9/2024WellViewAdmin@hilcorp.com Well Operations Summary Jobs Actual Start Date:9/7/2024 End Date:9/24/2024 Report Number 1 Report Start Date 9/7/2024 Report End Date 9/8/2024 Operation Continue rigging down modules and prep f/ movers, crane off centrifuge and L/D Gas buster, split apart back yard remove pumps and pits, lay felt liner and mats on well, pick up and transport mats to new location spot in cranes and remove derrick and draw works from sub, pull gen skid and dog house pull sub and pony wall from well and load on trailers transport all to location, Pull mats and transport cranes to location, spot pony subs over well Set pony sub. Spotted CCI cranes, picked & set subbase, carrier, and derrick on pony subs. Craned IR to rig floor and pinned. Spotted & set with winch trucks, doghouse/rig tank, gen skid, and pit module #1. Stood up handrails on rig floor, top of dog house, and sun deck. Raised pit roof and dog house to rig floor. Folded out landings on gen skid and rig water tank. Began R/U power cables & lights. Laid down rig movers for the night. Finished plugging electrical cords and lights. Fired gen. powered up lights. Performed derrick inspection. Held PJSM. Raised derrick. Powered up lower section of derrick lights. Installed floor plates and remaining handrails. R/U draworks brake linkage and drive line. Lowered drill line, service loop, and Kelly hose from derrick. Lowered & R/U monkey board. Unstowed boom line from travel postion. Installed upper section of TQ tube turnbuckles. Spooled on drill line, unhung blocks, and prepared derrick for scoping. R/U accumulator hoses from substructure to accumulator. Filled rig water tank. Report Number 2 Report Start Date 9/8/2024 Report End Date 9/9/2024 Operation Continue Rigging up modules, spot in pit modules and pumps, spot top drive HPU, hook up modules, rig down office and change shack transport to location Spot in office trailers and hook up power and sewer, work on getting coms up and running, spot in catwalk and raise beaver slide, prep to scope derrick. R/U centrifuge and bump tested. Removed shipping pins and tested shakers. Funtion tested degasser. Hammered up MGS lines. Checked pressure on accumlator bottles, recharged 12 out of 15 bottles. R/U TDS lifting cables/snatch block. Held PJSM. Hoisted TDS to rig floor. Hung TDS on dog bones. P/U TQ bushing, Hung TQ bushing onto TQ tube. Pinned TDS to TQ bushing. Hooked up service loop & Kelley hose to TDS. M/U HYD lines on TDS. Laid over fingers on monkey board. Cont. trucking misc. equip./tools from J pad. Built mud dock by MP #2 skid. Crew change, held PTSM. Cont. with R/U. Funtion tested robotics on TDS. Started working through rig acceptance check list. Commission tested MP's. R/U tongs. Changed gear oil in TDS. R/U IR and funtion tested. Verified Kelley hose was clocked correctly. Charged TDS compensators. Installed flow line & paddle. Spotted, set, and plugged in service shacks. R/U Pason hook load sensor. Report Number 3 Report Start Date 9/9/2024 Report End Date 9/10/2024 Operation Continue Rigging up modules, get handling equipment to floor, finish welding project, install saver sub, install windwalls on pits, continue working on rig acceptance checklist, test gas alarms. Finish installing rig floor, bring handling equipment to floor, Finish rig acceptance checklist. Remove night cap and N/U BOP stack, change orientation of stack to accomodate doors opening. Jim Reggs waived witness of BOP test. Attempted to N/U BOP's, UPR contacting substructure. Trollied back, broke double gate from mud cross and reclocked double gate to mud cross to allow clearance to UPR. Stabbed BOP on well head, M/U bolts. Replaced choke HCR valve on stack. Hammered up choke & kill line. Hooked up accumulator lines to stack. Energized koomey. Verified no leaks on accmulator lines. Recalibrated rig smart parameters. Installed riser adapter. Started hauling used 9.4 ppg 6% KCL PHPA mud from tank farm to mud pits. Crew change, held PTSM. Re-tighted bolts on mud cross, double gate, spacer spool, and kill/choke flanges. installed riser, bleeder hose, hole fill, and R/U chains/binders on stack. Pressure tested surface lines T/2500 psi (ok). Tested BOP remote panel to function test annular, rams, and HCR's. R/U testing equip. Flooded stack, choke manifold, and mud lines. Purged out air. Performed shell test on 4.5" test jt. Currently testing BOP's on 4.5" test jt. as per AOGCC regulation. 250 psi Low/2500 psi High 5/5 min. Report Number 4 Report Start Date 9/10/2024 Report End Date 9/11/2024 Operation Continue testing BOP's t/ 250/2500 psi f/ 5 min each, witness waived by Jim Regg No Fail Passes R/D test plug and test equipment, set wear ring. Clean and clear floor, strap and tally DP Trouble shoot rig smart system RIH P/U 42 jts of CDS 40 DP POOH racking back DP Service rig and top drive, grease blocks and crown, inspect draw works and brake linkage RIH w/ Scraper assembly, P/U drill collars and HWDP, RIH P/U DP single Tag up on CIBP @ 2139' Displace well t/ 9.2ppg 6% KCL polymer mud L/D single. POOH f/2133' t/ surface. L/D scraper assembly. P/U-58K, S/O-58K. PJSM w/ crew and WIS rep. P/U trimill and bit sub and M/U on bottom of 5" HWDP. Scribe from starter mill to top of HWDP. M/U Whipstock to starter mill. Ease whipstock through stack and set slips on 5"HWDP. M/U float and UBHO. Orient UBHO inset to scribe. RIH w/ 6" drill collars t/181'. RIH out of derrick f/181' t/2062'. P/U-59K, S/O-59K. R/U AK E-LIne and Gyrodata gyro. RIH with gyro and orient to 22 degrees. Report Number 5 Report Start Date 9/11/2024 Report End Date 9/12/2024 Field: Pretty Creek Sundry #: State: ALASKA Rig/Service: HEC 147Permit to Drill (PTD) #: Wellbore API/UWI:50-283-20022-01-00 Page 2/5 Well Name: PCU 002A Report Printed: 12/9/2024WellViewAdmin@hilcorp.com Well Operations Summary Operation POOH R/D Eline Slack off and trip anchor set on CIBP @ 2139' P/U and very anchor tripped, P/U to whipstock setting depth of 2093'. TOW-2070' BOW-2084'. Begin Milling window @ 2070' 85 rpm 402 gpm 475 psi 6-9k torque, mill window t/ 2084', drill 20' of new hole t/ 2104' drift window x 4 all clean. Recovered 386 pounds of metal. R/U test equipment and perform FIT. Pressure up to 442psi for a 13.2ppg MWE. Pumped 0.23bbl bled back 0.23bbl. Current mud weight 9.2ppg. R/D test equipment, blow down choke and test pump. Grease drawworks, top drive, brake linkage, crown, iron roughneck and blocks. Check oil in floor motor, and top drive. Inspect saver sub and brake linkage POOH f/2070' t/181'. P/U-59K, S/O-58K. Hole fillL: Act-15.59. Calc-16.53. L/D Milling BHA as per WIS rep. Lower mill 1/8" under gauge, Middle mill 1/16" under gauge, upper mill in gauge. Cleand and clear rig floor. Stage directional BHA on catwalk. PJSM with rig crew and Sperry hands. P/U directional BHA #3. M/U new HDBS pdc bit to Sperry drill. P/U directional collar and perform RFO. Cont M/U rest of MWD tools and orient UBHO to motor bend. M/U flex collars, first stand of HWDP and shallow pulse test-good. RIH w/ 2 stands of HWDP, P/U Yellow Jacket jars and HWDP single from catwalk. RIH with 5 stands of HWDP from derrick. Report Number 6 Report Start Date 9/12/2024 Report End Date 9/13/2024 Operation RIh f/ 687' t/ 2066' P/U 42 jt of DP from rack Fill pipe R/U and perform Gyro obtain tool face, POOH w/ eline, slack off through window clean, no issues Drill Ahead 8 1/2'' hole section f/ 2104' t/ 2224' Obtaining Gyro every stand 445 gpm 1075 psi 57k PUW 56k SOW Drilling Ahead 8 1/2'' Hole section f/ 2224' t/ 2631' 402 gpm 1010 psi 65 rpm 3.5k tq on bottom 2-5k WOB,PUW 57k SOW 56k ROT 56k, Obtained 2 clean surveys release gyro and eline Drilling Ahead 8 1/2'' Hole section f/ 2631' t/ 3134'(2956' TVD) 405 gpm 1120 psi 50 rpm 4-5k tq on bottom 2-8k WOB,PUW 60k SOW 60k ROT 61k. Drilling Ahead 8 1/2'' Hole section f/ 3134' t/ 3566'(2956' TVD) 405 gpm 1120 psi 50 rpm 4-5k tq on bottom 2-8k WOB,PUW 60k SOW 60k ROT 61k. End of build section at 3218'. Report Number 7 Report Start Date 9/13/2024 Report End Date 9/14/2024 Operation Drill Ahead 8 1/2'' Hole Section f/ 3566' t/ 3629' 405 gpm 1180 psi 53 rpm 4-5k tq on bottom, WOB 2-8k, 74k PUW 57k SOW 63k ROT Circulate Bottoms up, flow check well, Obtain SPR's POOH f/ 3629' t/ 2069' without issues. Slip and cut drilling line 8 wraps, inspect brakes and linkage, inspect deadman and dog knot, Service rig and crown grease top drive and adjust RPM magnets, tighten rieneer motor bolts on top drive. RIH f/ 2069' P/U 40 jts of DP off rack, RIH w/ stands f/ derrick t/ 3629' without issue Pump Hi Vis Sweep around Back on time 100% increase in coal returns to surface 1-2'' chunks and lots of smaller chips Drill Ahead 8 1/2'' Hole Section f/ 3629' t/ 3819' 400 gpm 1200 psi 50 rpm 4.6k tq on bottom 2-6k WOB, 64k PUW 57k SOW 60k ROT. Control drilled at 60’/hr through coal package collecting samples as per geo f/3629’ t/3693’. Drill Ahead 8 1/2'' Hole Section f/ 3819' t/ 4196' 450 gpm 1460 psi 55 rpm 6k tq on bottom 2-8k WOB, 64k PUW 57k SOW 60k ROT. Max gas 572 units. Started seeing more coal and larger pieces coming over the shakers and seeing some erratic torque. CBU at 450GPM=1470, 55RPM= 3.3-5.9k TQ. Drill Ahead 8 1/2'' Hole Section f/ 4196' t/ 4693' 450 gpm 1460 psi 55 rpm 6k tq on bottom 2-8k WOB, 74k PUW 57k SOW 63k ROT Max Gas:654 units. Report Number 8 Report Start Date 9/14/2024 Report End Date 9/15/2024 Operation Drill Ahead 8 1/2'' Hole Section f/ 4693' t/ 4817' 450 gpm 1875 psi 56 rpm 5-6k tq on bottom, 2-10k WOB 10 ppg MW, 78k PUW 58k SOW 64k ROT CBU, Obtain survey and SPR's Flow Check well static Make Wiper trip f/ 4817' t/ 3632' without issues Service rig and top drive, inspect draw works and brake linkage, grease blocks and top drive, service camp gen RIH f/ 3632' t/ 4817' without issues wash last stand to bottom Circulate Hi Vis Sweep around, Sweep back on time 20% increase in cuttings, some large chunks of coal 2-3'' pieces, Max Gas on bottoms up 2661 units Drilling Ahead 8 1/2'' Hole Section f/ 4817' t/ 5194' 450 gpm 1950 psi 56 rpm 8k tq on bottom, 4-10k WOB 10 ppg MW 80k PUW 58k SOW 68k ROT Drilling Ahead 8 1/2'' Hole Section f/ 5194' t/ 5570' 450 gpm 2100 psi 56 rpm 5-6k tq on bottom, 2-10k WOB 10 ppg MW 80k PUW 59k SOW 69k ROT, Max Gas 125 units Drilling Ahead 8 1/2'' Hole Section f/ 5570' t/ TD at 6000' 450 gpm 2100 psi 70 rpm 5-7k tq on bottom, 2-10k WOB 10 ppg MW 86k PUW 59k SOW 69k ROT, Max Gas 540 units Pump hi-vis sweep sweep around. Sweep back 200 strokes early 100% increase in cuttings. 455GPM=1975PSI, 75RPM=6.2k TQ. Max Gas 50 units. Obtain SPR's. Flow check well-slight seepage. POOH on elevators f/6000' t/5759'. P/U-88K, S/O-64K. Report Number 9 Report Start Date 9/15/2024 Report End Date 9/16/2024 Operation Unable to work through swabbing, BROOH f/ 5759' t/ 4134' multiple attempts to pull on elevators unable, @ 4134' stalling out torque. Irculate bottoms up and untill shakers cleaned up, hole unloaded larger chunks of coal and cuttings, still unable to pull on elevators Continue BROOH f/ 4134' t/ 2811' 450 gpm 50 rpm POOH on elevators f/ 2811' t/ 580' without issues passed through window clean no drag. Rack Back HWDP and Jars, L/D Drill Collars, Download MWD, L/D MWD tools. P/U and check bit. Bit Graded 1-1-CT-S-X-I-ER-TD Field: Pretty Creek Sundry #: State: ALASKA Rig/Service: HEC 147 Page 3/5 Well Name: PCU 002A Report Printed: 12/9/2024WellViewAdmin@hilcorp.com Well Operations Summary Operation P/U MAD Pass assembly. Re-run same bit. Verify RFO. M/U Sperry tripple combo MAD Pass BHA. Download MWD tools. Perform shallow pulse test-good. PJSM w/Sperry and rig crew, load nuclear sources. RIH w/ 3 stands of HWDP, M/U jar stand and pull corrosion ring out of jars. RIH w/ 5 stands of HWDP. RIH out of derrick f/682' t/1621'. P/U-40K, S/O-33K. Grease drawworks, top drive, crown, and brake linkage. Inspect saver sub, brakes and brake linkage. Check fluid levels in floor motor and top drive. RIH f/1621' t/2189'. P/U-50K, S/O-38K. MAD Pass Open hole f/2189' t/2875'. 460GPM=1415PSI, 80RPM=3.5K TQ, Control running speed at 225'/hr. Report Number 10 Report Start Date 9/16/2024 Report End Date 9/17/2024 Operation MAD Pass open Hole f/ 2875' t/ 3690' 450 gpm 1400 psi 75 rpm 5k tq MAD Pass Open Hole F/ 3690' t/ 4316' 440 gpm 1800 psi 70 rpm 7k tq pumped hi Vis Sweep around at 4139' back on time 100% increase in cuttings . Stop at 4316' at which point the assembly was taking more weight than expected and had a slower running speed 60'/hr instead of the 225'/hr MAP Passing sped. Sperry took a check shot survey and that showed that we were sidetracked. Unpon further investigation into the surveys, it showed that we had sidetracked at 2714'. After dicussion with the Engineers and Geologist it was deicded to make a wiper trip to the window while coming up with a plan forward. Obtain SPR's and flow check well-slight seepage. POOH on elevators f/4316' t/4063' where the assembly was pulling tight and swabbing. BROOH f/4063' t/3121'. Had 1330 units of gas at first BU. Assmelby torqueing up and stalling topdrive. Having to pull up the hole slowly. 500GPM=1800PSI, 60RPM=4-18k TQ. Cont BROOH f/3121' t/2499'. Pumped a hi-vis sweep at 3014', back 150 strokes with 50% increase. 500GPM=1600PSI, 60RPM=4-18k TQ. P/U-70K, S/O-52K, ROT-56K. Contined full stall stick slip and stalling top drive, while pullng very slow. Report Number 11 Report Start Date 9/17/2024 Report End Date 9/18/2024 Operation Cont POOH from 2499' to 2059' with no issue on elevators. Calc hole fill = 2.8 bbls, actual hole fill = 3.26 bbls. Serviced rig and topdrive, inspected derrick, checked saver sub. Loss rate at .6 bph on trip tank during service. Wait on orders from town on forward plan. TIH on elevators from 2059', down wt 55K, to 2752' and shot survey, ran two more stands survaying each stand to verify we are in new hole. Cont TIH on elevators to 4143' where we set down three times. MU topdrive, washed and reamed stand down to 4187' and saw nothing. Cont TIH on elevators to 4253' with no issue. MU topdrive, filled pipe, washed/reamed to bottom at 4316'. Started a tandem sweep (lo-vis low wt, hi-vis hi wt) around at 376 gpm-1225 psi, 40 rpm. Sweep back 100 strokes late and had 100% increase in cuttings, mostly fines and clay. Followed with an additional CBU while waiting on approval from State to drill ahead. Racked back stand after CBU, cont to work stands and CBU each time then rack back from 4316' up to 3940', 453 gpm-1557 psi, 40 rpm-4200 ft/lbs off bott torque. Receieved verbal approval from state to drill ahead at 16:00 hrs. TIH from 3940' to 4316' with no issue, down wt 62K, up wt 78K. Sperry mode switched their tools from mad pass to drilling, Resumed drilling 8 1/2" hole from 4316' to 4377', rot wob 6K, 450 gpm-1793 psi, 50 rpm-5300 ft/lbs on bott torque, 60 to 90 ft/hr ROP, reducing ROP to 60 ft/hr through large coals. MW 10+/vis 54, ECD 10.6 ppg, BGG 26 units, max gas 35 units. Drill 8 1/2" hole from 4377' to 4751', 450 gpm-1789 psi, 50 rpm-4-5 ft/lbs on bott torque, 60 to 90 ft/hr ROP, reducing ROP to 60 ft/hr through large coals. MW 10+/vis 55, ECD 10.6 ppg, BGG 28 units, max gas 38 units. Drill 8 1/2" hole from 4751' to 5100', 450 gpm-1789 psi, 50 rpm-5-6 ft/lbs on bott torque, 60 to 90 ft/hr ROP, reducing ROP to 60 ft/hr through large coals. MW 10+/vis 55, ECD 10.6 ppg, BGG 28 units, max gas 38 units. Report Number 12 Report Start Date 9/18/2024 Report End Date 9/19/2024 Operation Cont drilling 8 1/2" hole from 5100' to 5128', obtained on bottom survey and sent logs to Geologist. Circ hole clean rotating/reciprocating at 468 gpm-1731 psi, 50 rpm-4600 ft/lbs off bott torque while waiting on word from Geo on TD depth. Geo requested to drill one more stand. L/D kelly jnt. Drilled from 5128' to TD at 5188' md/ 4669' tvd. Rot wob 5-6K, 469 gpm-1930 psi, 50 rpm-6200 ft/lbs on bott torque, 90 ft/hr ROP. MW 10.1/vis 52, ECD 10.9 ppg, BGG 24 units, max gas 77 units. Surveyed on bottom and sent logs to Geo. TD confirmed. CBU twice at 456 gpm-1677 psi, 50 rpm-5100 ft/lbs off bott torque. 10 minute flow check fluid dropped 2'. Pulled up hole on elevators from 5188' to 4950' and had to start working slight overpulls, up wt 88K. At 4680' saw 30K over thr ee times, MU topdrive, backreamed to 4310' at 354 gpm-1196 psi, 20 rpm-5600 ft/lbs torque. CBU twice at 459 gpm-1651 psi, 80 rpm-5500 ft/lbs off bott torque. Max gas 52 units. Hole unloaded prior to and at first bottoms up. Serviced rig and topdrive. Sent 48 hr notice to State for witness of MIT's. TIH on elevaotrs from 4310' to 5123' with no issue. MU topdrive on last stand, filled pipe, washed/reamed to bottom and started tandem sweep down string. Witness of MIT's was waived by AOGCC Rep Jim Regg at 13:25. Circulated low vis low weight-hi vis hi weight sweep around at 456 gpm-1684 psi, 80 rpm-5100 to 5400 ft/lbs off bott torque. Hole started unloading 800 strokes prior to bottoms up, sweep back on time with 75% increase in clay. Max trip gas 82 units, ECD down to 10.7 ppg after sweep with 10.1 ppg MW. Obtained SPR's, 10 minute flow check fluid dropped 2' in wellbore. Pulled up hole on elevators from 5188', up wt 84K to 4116' w here we started seeing 20K overpull and could not work through it. MU topdrive, backreamed up hole to 3810' and hole unloading clay. Cont to circulate hole clean while building a tandem sweep, pumped sweep around. Sweep back 100 strokes late and 50% increase in cuttings. Cementers loaded silo with lead cement. Attemp to pull on elevators-observed 30k overpoull and swabbing. Cont BROOH f/3810' t/3351' at 450GPM=1500PSI, 50RPM=5K Tq. At 3351' hole started unloading again. Shakers cleaned up at 1.5 BU. Cont to BROOOH f/3351' t/2801'. 450GPM=1500PSI, 50RPM=3-5k Tq. Hole started unloading again at 2801'. Circulate hole clean-CBUx1.5. POOH on elevators f/2801' t/2682' (above sidetrakck point at 2714').RIH back down t/2801' and take a check shot survey to ensure assembly would go into new hole. Cont. to POOH on elevators f/2801' t/1365'. (Flow check at window dropped 2.5' in 15 minutes). Field: Pretty Creek Sundry #: State: ALASKA Rig/Service: HEC 147 Page 4/5 Well Name: PCU 002A Report Printed: 12/9/2024WellViewAdmin@hilcorp.com Well Operations Summary Operation POOH f/1365' to BHA at 682'. Rack back HWDP and L/D jar stand. PJSM and remove radio active sources. Download MWD data. L/D directional BHA #4. Bit graded: 1-1-CT-S-X-I-ER_TD Clean and clear rig floor. PJSM. R/U Parker TRS 4.5" casing equipment. M/U and Baker loc shoe joint and float collar. Report Number 13 Report Start Date 9/19/2024 Report End Date 9/20/2024 Operation PU and MU shoe track Baker Lok'd each connection, filled pipe and checked FE (good). Cont PU single in hole total 78 jnts of 4 1/2" GB CD BTC 12.6# L-80 liner, torqued to 4875 ft/lbs, to 3293'. No issue exiting window at 2084' or at sidetrack intersection at 2714'. Filled on the fly, topped off every 10 jnts. MU XO and topdrive, broke circ staging up from 2 bpm-135 psi to 4 bpm-136 psi, up wt 42K, dwn wt 38K. PU Baker SLZXP (HRD-E) liner hanger/packer assembly, installed plug catcher, stabbed into stump, MU XO to liner stump and torgued the 7" TXP connection as per Baker Rep. Upon slacking off and removing protective wrap, found the lower packer cone to be damaged. Baker Rep notified his Engineer, Drilling Engineer also notified. After discussion it was decided to run and hanger assembly in hopes packer element will seal. Baker Rep removed two pins, mixed and poured xanplex. MU XO on 1st stand DP, S/O to 3389', dwn wt 40K and MU topdrive. Circulated liner string volume at 118 gpm-220 psi and obtained rotating parameters at 10 rpm-1600 ft/lbs, 20 rpm-1900 ft/lbs and 30 rpm-2200 ft/lbs rotating torque. Cont ease in hole 29 stands and a single from 3389' to 5154'. Filled pipe with topdrive at 4017', 4644' and 5150'. Washed down on single to 5184' with no tag, made hook and washed down tagged bottom at 5193' liner string measurement, 3 bpm-230 psi, Up wt 64K, dwn wt 56K. Cont to circ at 127 gpm-218 psi while staging cement head and install 15' pup on bottom. Called out cementers, layed down liner for pump truck, racked back stand, PU and MU cement head, tied in cement hose, resumed circ while staging trucks and stringing displacement hose from pits. Halliburton pumped 5 bbls water to flush and fill lines. Shut in at Baker cement head and PT lines at 1020psi low 4784psi high. Good tests. Lined up Baker cement head to Halliburton, pumped 45 bbls 10.5 ppg Tuned Spacer at 3.5 bpm-290 to 200psi, followed with 253.4 bbls (606 sx) 12 ppg Type I II Lead cement at 3.5 bpm-187, followed with 35.5 bbls (180 sx) 15.3 ppg Type I II Tail cement at 3.5 bpm-345 to 275 psi. Had 2 pps of Bridgemaker LCM in lead & tail? Baker released top plug, Halliburton then displaced with 10.1 ppg 6% KCL mud at 3.5 bpm-74 to 685 psi. With 20 bbls to go, reduced rate to 3 bpm-610 to 885 psi and bumped plug on landing collar at 73 bbls into displacement (calculated at 75 bbls). FCP 885 psi. Halliburton increased to and held 1457 psi (572 over fcp) for 3 minutes, bled back 0.5bbl to truck and floats held. Brought pressure up to 2600psi for 5 minutes to set hanger. Slacked off on blocks from 44K to 16K, giving us a good indication hanger was set. CIP at 23:42 on 9-19-2024. Pressured up to 4100 psi on setting tool for 5 min, seen packer set at 3526psi and running tool release. P/U to 41K with good indication of release. R/D cmt hoses and L/D Baker cmt head. M/U TD to stump to circulate. Pressured up to 700 psi on drill string and PU 11’ and pressure dumped. CBU x2 at 480 gpm- 450 psi. Had 45 bbls spacer and 134 bbls cement/contaminated mud circulated to surface. Lost 0 bbls during the job. Rotated and reciprocated through out the job. RD and released Halliburton. Close UPR's and pressure up to 538 psi to test packer. Bled off to 496psi in 5 minutes. POOH f/1859' t/ surface. L/D Baker running tool. Displacement: Calc-11.2bbl, Act-11.68bbl. Break down XO's and pup jnts from cement head. P/U johnny whacker and flush stack with black water. M/U poslish mills as per Baker rep. RIH f/ surface t/1810'. P/U-38K, S/O-38K. Report Number 14 Report Start Date 9/20/2024 Report End Date 9/21/2024 Operation Ease down from 1810' to 1872', dwn wt 38K, 113 gpm-106 psi, 20 rpm-1350 ft/lbs torque and tagged liner top. Dressed liner top with 10K weight on mill, 6100 ft/lbs as per Baker Rep, worked lower mill in SBR couple times. Held PJSM, displaced upper wellbore to 8.4 ppg inhibited fresh water. 213 gpm-167 psi. With clean fluid to surface shut down to clean under shakers and troughs. Monitor well for flow 30 minutes, no flow, closed upper rams and watched for any pressure build on choke manifold for 1 hr, no pressure built. Opened rams. POOH LD DP from 1872'. CCI vac'd wiper balls on pipe rack, cleaned and dried threads and installed thread protectors. LD polish mill and XO. RU test equipment on mezz kill, purged air, closed blinds, pumped 87.5 gallons to achieve 2570 psi, Held 30 min on chart, good test. Bled back 87.5 gallons. RD test equipment and opened blinds. Start offloading mud from pits, TIH from derrick to 1320' Circ string volume to clean pipe, loaded Sperry tools for staging at barge landing, POOH LD DP, strapped tubing on H pad. RIH from derrick to 1500' and circ string volume. POOH L/D DP f/1500' t/ surface. Disp: Calc-9.8 bbl Act-10.62 bbl. RIH w/ HWDP and remaining DP out of derrick t/1100'. Circulated a pipe volume to clean pipe. Disp: Calc-10.1bbl Act-12.21 bbl. POOH L/D DP f/1100' t/ surface. Drain stack and pull wear ring. R/U up Parker TRS. M/U Baker bullet seal assembly and XO's. RIH w/ 4.5" tieback as per tally t/1206'. Cont to RIH with 4.5" tieback f/1206' t/1882' and land out on no-go. L/D tag joint. P/U hanger and M/U space out pups A, F and D. L/D out hanger with no-go 1.22' off of seat. Install packoff. R/U and perform MIT-T/IA. R/U on tubing and pressure up to 2500PSI/30min-good test. Pumped 0.77bbl bled back 0.77bbl. R/U on IA and pressure up to 2500psi/30min-good test. Pumped 1.16bbl bled back 1.16bbl. R/D test equipment. Install TWC in hanger. R/D Parker TRS equipment. Flush surface equipment with Barakleen. Report Number 15 Report Start Date 9/21/2024 Report End Date 9/22/2024 Operation Flushed surface equipment and plumbing with BaraKlean, water and BaraCorr solutions, blew all plumbing down. Removed flowline and riser, loaded assorted equipment and mud product on trailers. Removed choke and kill lines. Shipped out upright water tank and cement silo, shipped out trash fluids and start cleaning pits, ship pipe bunk, cont loading mud product and equipment on trailers, opened ram doors and cleaned inside stack, buttoned up doors and removed stack from wellhead. Installed dry hole tree and wellhead rep tested void, hanger neck seals and tree at 5000 psi for 10 minutes. Good tests. Pulled 2 way check and closed master. Broke mudcross off stack and aligned with rams to fit on cradle. Field: Pretty Creek Sundry #: State: ALASKA Rig/Service: HEC 147 Page 5/5 Well Name: PCU 002A Report Printed: 12/9/2024WellViewAdmin@hilcorp.com Well Operations Summary Operation Opened ram doors, cleaned, inspected, and applied corrosion inhibitor. Removed cap, pulled bag cleaned and inspected. Disassembled fluid end on MP#2 and inspected. Changed ujoints on floor motor drivelline. Removed flow box. Cleaned mud tanks and flushed mud lines. Re-moved cap and inspected degasser. Started cleaning derrick and top drive. Cont. cleaning derrick. Clean, lubricate, and inventory hoses. Clean and organize BOP Box and components. Remove all subs from backets, clean, dope, install thread protectors and inventory. Remove fitings from BOP and install plugs. Report Number 16 Report Start Date 9/22/2024 Report End Date 9/23/2024 Operation Shipped out mud product and casing equipment trailers for barging, cleaned pit mod 3, wash derrick from top to bottom. Sort subs and handling tools that need inspection, removed rotary table cover, removed torque blocks/rollers from iron roughneck and cleaned same. Inspected fluid end of pump 2 and re-assembled same. Offload connex’s and re-load for barging. Cont scrubbing and power washing, clean pit mod 2. Removed bails from top drive. Remove pins from rotary table, and clean. Fill agitators with gar oil. Remove 4" valve on stand pipe greased valve and re-assemble. Clean iron roughneck and cellar area. Clean hopper house #3. Clean pump houses and auxiliary bubble. Take inventory of pump parts. Clean hopper house #2. Pull oil out of koomey through filter cart and clean resivior. Remove mats and clean bird baths. Report Number 17 Report Start Date 9/23/2024 Report End Date 9/24/2024 Operation Cont cleaning, inspecting, greasing equipment for storage, prep connex’s for storing and those that will barge to east side, remove standpipe transducers, clean, inspect, lube, re-install, clean 1 and 2 hopper rooms, cont cleaning pits in pit mod 3, filter oil from HPU’s then add back to HPU’s. Remove cement manifold, clean, inspect and re-assemble. Cont cleaning in sub base. Brought in boiler skid and cleaned inside, staged same at Cottonwood, RD mudlab, changed oil/filter on camp gen. Cont cleaning hopper room 1 and 2, cont cleaning pit mod 2, cont prep connex's for shipping or storage, Wash pump room roof tops and radiators on pump engines, removed auto and manual chokes on CVM, cleaned, inspected, installed, then filled CVM with hyd oil for storage. Installed shipping beams in cellar, cleaned pit mod 1 and windwalls, cleaned choke house and catwalk, cleaned koomey room, hopper house 3, removed saver sub and IBOP from topdrive, cleaned grabber box housing and actuator, cont cleaning in sub base, drained oil from topdrive gear box and swivel, palletized spare nitrogen bottles, start cleaning doghouse. Rig released from PCU-02A at 06:00 on 9-24-24 Field: Pretty Creek Sundry #: State: ALASKA Rig/Service: HEC 147 Page 1/1 Well Name: PCU 002A Report Printed: 12/10/2024WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Jobs Actual Start Date:9/30/2024 End Date: Report Number 1 Report Start Date 9/30/2024 Report End Date 10/1/2024 Last 24hr Summary PJSM, Crew travel to location, Spot in & rig up, PIck up lube & tool string (CBL), Perform calibrations, Run in hole & calibrate to free pipe, Trouble shoot CBL, Pull out of hole & lay down tools. Report Number 2 Report Start Date 10/1/2024 Report End Date 10/2/2024 Last 24hr Summary PJSM, Crew travel to location, Pick up lube & tools, Perform air calibrations, Pressure test 250/3000 psi-good, Run in hole, Calibrate on free pipe, Continue running in hole & perform CBL pass, Tag @ 5065', Log up to 1650', Pull out of the hole & release AK eline, Spot in & rig up Fox coil, Nipple up BOPE, Pressure test 250/3000-Pass, Secure well for the night. Report Number 3 Report Start Date 10/2/2024 Report End Date 10/3/2024 Last 24hr Summary PJSM, Crew travel to location, Pick up injector & lube, Load reel, Test injector & lube 250/3000-good, Run in the hole, Tag @ 5101', Displace wellbore to fresh water, Reverse wellbore with N2, Recovered 113 bbls/Calculated 119 bbls, Pull out of the hole and secure 2150 psi, Rig down & release Fox Coil tubing. Report Number 4 Report Start Date 10/4/2024 Report End Date 10/5/2024 Last 24hr Summary PJSM, Crew travel to location, Spot in & rig up, Pick up tools & gun #1, Pressure test 250/3000-good, Run in hole to 4500', Perform corrrelation pass, Perf BEL D3 4251'-4259', Pull out of the hole & release AK Eline, Flow well in 150 psi increments & record pressures 15 & 30 min. Draw down to 900 psi & let build overnight. Report Number 5 Report Start Date 10/5/2024 Report End Date 10/6/2024 Last 24hr Summary Flow well and record data Report Number 6 Report Start Date 10/6/2024 Report End Date 10/7/2024 Last 24hr Summary PTW/PJSM, Ran GPT Tag @ 5080', Fluid level @ 5070'. Report Number 7 Report Start Date 11/24/2024 Report End Date 11/25/2024 Last 24hr Summary PJSM. P Test 250/3000 PSI. Good. RIH GPT to 5050'. FL at 5010'. Perforate ST C5 zone 4140' to 4149'. Made 2nd run and Perforated same interval. RDMO E-Line. Turn well over to production. Field: Pretty Creek Sundry #: 324-540 State: ALASKA Rig/Service:Permit to Drill (PTD) #:Permit to Drill (PTD) #:224-110 Wellbore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age 1/1 Well Name: PCU 002A Report Printed: 12/9/2024 WellViewAdmin@hilcorp.com Casing Liner Wellbore Wellbore Name: Sidetrack 2 Total Depth of Wellbore (ftKB): 5,188.00 Original KB/RT Elevation (ft): 100.50 RKB to GL (ft): 18.00 KB-Casing Flange Distance (ft): 81.55 KB-Tubing Hanger Distance (ft): PBTDs Depth (ftKB): Casing Casing Description: Liner Run Date: 9/19/2024 Set Depth (ftKB): 5,186.00 Casing Weight on Slips (1000lbf): 19,000.0 Pick Up Weight (1000lbf): 70,000.0 Block Weight (1000lbf): 15,000.0 Make-Up Contractor: Parker Casing Number Hrs to Run (hr): 13.00 Ft/Min (ft/min): 6.65 Run Job: 241-00149 PCU-02A Drilling, Drilling - Drilling, 9/7/2024 06:00 Set Depth (ftKB): 5,186.00 Set Depth (TVD) (ftKB): 4,668.1 Centralizer Detail: 78 Attribute Subtype: Value: Pipe Reciprocated?: Yes Pipe Rotated?: Yes Float Failed?: Yes Test Subtype: Pressure (psi): Casing (Or Liner) Details Jts Item Des OD Nominal (in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make Section Length (ft)Btm (ftKB) Top (ftKB) 1 Liner Hanger 6.53 4.78 21.62 1,888.98 1,867.36 1 XO 5 1/2 3.92 H563 1.70 1,890.68 1,888.98 35 Blank Liner 4 1/2 3.92 13.50 L-80 GBCD-BTC 1,460.75 3,351.43 1,890.68 1 Marker Joint 4 1/2 3.92 13.50 L-80 GBCD-BTC 9.66 3,361.09 3,351.43 6 Blank Liner 4 1/2 3.92 13.50 L-80 GBCD-BTC 249.58 3,610.67 3,361.09 1 Marker Joint 4 1/2 3.92 13.50 L-80 GBCD-BTC 10.09 3,620.76 3,610.67 7 Blank Liner 4 1/2 3.92 13.50 L-80 GBCD-BTC 291.41 3,912.17 3,620.76 1 Marker Joint 4 1/2 3.92 13.50 L-80 GBCD-BTC 10.08 3,922.25 3,912.17 10 Blank Liner 4 1/2 3.92 13.50 L-80 GBCD-BTC 415.06 4,337.31 3,922.25 1 Marker Joint 4 1/2 3.92 13.50 L-80 GBCD-BTC 10.05 4,347.36 4,337.31 18 Blank Liner 4 1/2 3.92 13.50 L-80 GBCD-BTC 750.98 5,098.34 4,347.36 1 Landing Collar 5.04 2.41 BTC 1.05 5,099.39 5,098.34 1 Float Joint 4 1/2 3.92 13.50 L-80 GBCD-BTC 41.74 5,141.13 5,099.39 1 Float Collar 5.04 2.41 BTC 1.36 5,142.49 5,141.13 1 Float Joint 4 1/2 3.92 12.60 L-80 GBCD-BTC 42.05 5,184.54 5,142.49 1 Shoe 5.04 2.41 BTC 1.46 5,186.00 5,184.54 Page 1/1 Well Name: PCU 002A Report Printed: 12/9/2024 WellViewAdmin@hilcorp.com Cement Liner Cement Type Casing Description Liner Cement Cemented String Liner, 5,186.00ftKB Wellbore Sidetrack 2 Job 241-00149 PCU-02A Drilling, Drilling - Drilling, 9/7/2024 06:00 Cementing Start Date 9/19/2024 Cementing End Date 9/19/2024 Top Depth (ftKB) 2,058.0 Cement Stages Stage Number: 1 Description Liner Cement Top Depth (ftKB) 2,058.0 Bottom Depth (ftKB) 5,188.0 Top Measurement Method CBL Pump Start Date 9/19/2024 Cement in Place At 9/19/2024 Final Circulating Pressure (psi) 885.0 Plug Bump Pressure (psi) 1,457.0 Full Return? Yes Returns During Job (%) 100 Volume to Surface (bbl) 134.0 Volume Lost (bbl) 0.0 Bump Plug? Yes Float Failed? Yes Pipe Reciprocated? Yes Pipe Rotated? Yes Slurry Type Class Amount (sacks) Yield (ft³/sack) Dens (lb/gal) Actual Volume Pumped (bbl) Calculated Volume Pumped (bbl)Q Avg (bbl/min) Pump Used Preflush (Spacer)10.50 45.0 50.0 4 Halliburton Lead Slurry 606 3.82 12.00 253.4 255.0 4 Halliburton Tail Slurry 180 2.39 15.30 35.5 37.0 4 Halliburton Displacement Halliburton Post Job Calculations Subtype Value David Douglas Hilcorp Alaska, LLC Sr. GeoTechnician 3800 CenterPoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Date: 12/10/2024 To: Alaska Oil & Gas Conservation Commission Petroleum Geology Assistant 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: PCU C-02A + PB1 PTD: 224-110 API: 50-283-20022-01-00 (PCU 02A) API: 50-283-20022-70-00 (PCU 02APB1) PCU 02A Washed and Dried Well Samples (09/15/2024) 30'Frequency B Set (4 Boxes): . WELL BOX , SAMPLE WMRVAL (FEET I MD) PCU-02A BOX 1 OF 4 2070' - 3300' MD PCU-02A BOX 2 OF 4 3300' - 4500' MD PCU-02A BOX 3 OF 4 4500' - 5400' MD PCU-02A BOX 4 OF 4 5400' - 6000' MD PCU 02APB1 Washed and Dried Well Samples (09/15/2024) 30'Frequency B Set (1 Box): 1fYE� l BOX SAMPLE WMRVAL (FELT IUD), PCU-02APB1 BOX 1 OF 1 4316' - 5188' MD Please include current contact information if different from above. 19,17 191lb RECEIVED DEC 10 2024 AOGCC Please acknowledge receipt by signing and returning one copy of this transmittal. Received B Date: (L-g\D v�S 12I I I � Z-1 Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 12/05/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20241205 Well API #PTD #Log Date Log Company Log Type AOGCC ESet AN 15(GRANITE PT ST 18742 15) 50733200700000 167082 11/18/2024 AK E-LINE Perf BRU 221-26 50283202010000 224098 10/24/2024 AK E-LINE Perf BRU 233-23T 50283202000000 224088 10/21/2024 AK E-LINE Perf BRU 233-23T 50283202000000 224088 10/30/2024 AK E-LINE Perf BRU 241-23 50283201910000 223061 11/8/2024 AK E-LINE Perf BRU 241-26 50283201970000 224068 11/12/2024 AK E-LINE Plug/Perf END 2-72 50029237810000 224016 10/16/2024 HALLIBURTON COILFLAG END 2-72 50029237810000 224016 10/18/2024 HALLIBURTON COILFLAG MGS-ST 17595-05 50733100710000 165038 10/6/2024 AK E-LINE CBL MPU F-109 50029235960000 218014 10/28/2024 READ CaliperSurvey MPU J-02 50029220710000 190096 11/16/2024 READ CaliperSurvey MPU J-47 50029238010000 224120 11/9/2024 READ LeakPointSurvey MPU D-01 50029206640000 181144 10/23/2024 AK E-LINE TubingPunch MPU F-02 50029226730000 196070 11/18/2024 READ CaliperSurvey MPU I-08 50029228210000 197192 10/22/2024 AK E-LINE TubingPunch MPU I-08 50029228210000 197192 10/26/2024 HALLIBURTON JETCUT MPU L-60 50029236780000 220048 10/26/2024 HALLIBURTON MFC24 MRU M-25 50733203910000 187086 11/15/2024 AK E-LINE Plug NCIU A-21 50883201990000 224086 11/9/2024 AK E-LINE Perf NCIU A-21 50883201990000 224086 10/19/2024 AK E-LINE Perf NCIU A-21 50883201990000 224086 10/30/2024 AK E-LINE Perf NCIU A-21 50883201990000 224086 10/30/2024 AK E-LINE Plug/Perf PBU 06-07A 50029202990100 224043 9/30/2024 HALLIBURTON RBT PBU 14-41A 50029222900100 224076 11/8/2024 HALLIBURTON RBT PBU H-36A 50029226050100 200025 10/26/2024 HALLIBURTON RBT PCU 02A 50283200220100 224110 11/24/2024 AK E-LINE Perf Please include current contact information if different from above. T39808 T39809 T39810 T39810 T39811 T39812 T39813 T39813 T39814 T39815 T39816 T39817 T39818 T39819 T39820 T39820 T39821 T39822 T39823 T39823 T39823 T39823 T39824 T39825 T39826 T39827PCU 02A 50283200220100 224110 11/24/2024 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.05 14:52:46 -09'00' David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 10/31/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: PCU-02A + PB1 PTD: 224-110 API: 50-283-20022-01-00 (PCU-02A) API: 50-283-20022-70-00 (PCU-02APB1) FINAL LWD FORMATION EVALUATION LOGS (09/07/2024 to 09/20/2024) x ROP, DGR, PCG, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs) x ALD DIP INTERPRETATION x Final Definitive Directional Survey Main Folders: Final LWD Data Folders: Final DIP Inerpretation Folder: Please include current contact information if different from above. T39730 T39731 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.11.01 08:32:27 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 10/30/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20241030 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BRU 221-26 50283202010000 224098 10/20/2024 AK E-LINE Perf BRU 233-23T 50283202000000 224088 10/14/2024 AK E-LINE Perf BRU 241-23 50283201910000 223061 10/12/2024 AK E-LINE Perf GP-ST-18742-33 50733203060000 177032 10/9/2024 AK E-LINE LeakDetect/Packer IRU 11-06 50283201300000 208184 10/4/2024 AK E-LINE Plug/Perf MPU B-28 50029235660000 216027 10/4/2024 READ CaliperSurvey MPU F-13 50029225490000 195027 10/15/2024 READ CaliperSurvey MPU L-36 50029227940000 197148 10/17/2024 READ CaliperSurvey MRU G-01RD 50733200370100 191139 10/10/2024 AK E-LINE Hoist NCIU A-21 50883201990000 224086 10/8/2024 AK E-LINE CBL NCIU B-01B 50883200930200 224097 10/1/2024 AK E-LINE CBL NCIU B-01B 50883200930200 224097 10/11/2024 AK E-LINE Perf PBU 06-18B 50029207670200 223071 10/2/2024 HALLIBURTON RBT PBU 14-32B 50029209990200 224073 10/13/2024 HALLIBURTON RBT PBU C-18B 50029207850200 209071 10/2/2024 HALLIBURTON RBT PBU C-18B 50029207850200 209071 10/2/2024 HALLIBURTON WSTT PBU NK-26A 50029224400100 218009 10/14/2024 HALLIBURTON PPROF PCU 02A 50283200220100 224110 9/30/2024 AK E-LINE CBL PCU 02A 50283200220100 224110 10/4/2024 AK E-LINE Perf SDI 3-25B 50029221250200 203021 10/17/2024 AK E-LINE Patch Please include current contact information if different from above. T39726 T39727 T39728 T39732 T39733 T39734 T39735 T39736 T39737 T39738 T39739 T39739 T39740 T39741 T39742 T39742 T39743 T39744 T39744 T39745 PCU 02A 50283200220100 224110 9/30/2024 AK E-LINE CBL PCU 02A 50283200220100 224110 10/4/2024 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.11.01 13:27:33 -08'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Chad Helgeson Cc:Donna Ambruz Subject:RE: PC-02A (PTD# 224-110) Cement Bond log Date:Wednesday, October 2, 2024 5:37:00 PM Chad, Hilcorp has approval to perforate per the approved sundry. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Wednesday, October 2, 2024 9:19 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: PC-02A (PTD# 224-110) Cement Bond log Bryan, Please find attached the preliminary Cement Bond Log for PC-2A. Very similar to other logs where we have cement from bottom of the well to the liner lap, and across the liner lap, it looks a little different. I think we are still waiting to receive the approved sundry on this one. Thanks Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently 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 responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Rance Pederson - (C) To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC) Subject:PCU-02A MIT Test Report Date:Saturday, September 21, 2024 7:05:30 AM Attachments:MIT Hilcorp 147 09-21-24.xlsx PCU-02A Casing Test and MIT"s Chart.pdf Please see the attached MIT test form and chart for PCU-02A in Beluga. Rance Pederson Drilling Foreman Pretty Creek Unit 907-776-6776 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. 3UHWW\&UHHN8QLW$ 37' Submit to: OOPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2241100 Type Inj N Tubing 0 2610 2600 2600 Type Test P Packer TVD 1889 BBL Pump 0.8 IA 0 225 225 225 Interval O Test psi 2600 BBL Return 0.8 OA 0 0 0 0 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2241100 Type Inj N Tubing 0 150 150 150 Type Test P Packer TVD 1889 BBL Pump 1.2 IA 0 2600 2600 2600 Interval O Test psi 2600 BBL Return 1.2 OA 0 0 0 0 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: Hilcorp Alaska, LLC Beluga River / Pretty Creek Unit / Pretty Creek Pad Witness Waived Justin Gruenberg 09/21/24 Notes:Post completion 4 1/2" tieback string and liner. SLZXP Liner Top Packer at 1889' tvd Notes: Notes: Notes: Pretty Creek 02A Pretty Creek 02A STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes:Post completion 9 5/8" x 4 1/2" annulus. SLZXP Liner Top Packer at 1889' tvd Notes: Notes: Form 10-426 (Revised 01/2017)2024-0921_MITP_PCU_02A 9999 9 9 9 999 9 9 9 9 -5HJJ 15% 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: Initial Completion, 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): 5,188'N/A Casing Collapse Structural Conductor Surface 1,540psi Intermediate 3,810psi 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 chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior writte n approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 390780 224-110 50-283-20022-01-00 Hilcorp Alaska, LLC Proposed Pools: 12.6# / L-80 TVD Burst ±1,867' 8,430psi 2,032' Size 339' 9-5/8"2,070' 2,032' MD See Attached Schematic 6,330psi 3,090psi 339' 2,070' TOW 339' 2,032' October 2, 2024 Tieback 4-1/2" ±5,188' Perforation Depth MD (ft): 2,070' TOW 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Pretty Creek Unit (PCU) 02AUndefined Same ±5,188'4-1/2" ~1529pai ±3,321' N/A Length LTP; N/A ±1,857' MD / ±1,857' TVD; N/A 4,669'±5,098'±4,596' Pretty Creek Undefined Gas Pool 20" 13-3/8" See Attached Schematic m n P s 66 t 2 N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 11:47 am, Sep 20, 2024 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.09.20 11:05:43 - 08'00' Noel Nocas (4361) 324-540 Yes for CTCO only 9/30/24 Bryan McLellan BJM 9/30/24 CT BOP test to 3000 psi 4669' bjm Statewide spacing regulations: 20 AAC 25.055 SFD DSR-9/27/24SFD 9/23/2024 X 10-404 Submit CBL to AOGCC and obtain approval before perforating. *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.10.01 11:40:38 -08'00'10/01/24 RBDMS JSB 100224 Well Prognosis Well Name: PCU-2A API Number: 50-283-20022-01-00 Current Status: New Drill Well Permit to Drill Number: 224-110 First Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Second Call Engineer: Scott Warner (907) 830-8863 Maximum Expected BHP: 1920 psi @ 3919’ TVD (Based on 0.49 psi/ft gradient)) Max. Potential Surface Pressure: 1529 psi (Based on 0.1 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.69 psi/ft using 13.2 ppg EMW FIT at the surface casing shoe 9/11/24 Shallowest Potential Perf TVD: MPSP/(0.69-0.1) = 1529 psi / 0.59 = 2591‘ TVD Well Status: New Drill Initial Completion Brief Well Summary: PCU-2A is the final drill well in the Hilcorp 2024 West Side drilling program targeting the Sterling and Beluga sands. The objective of this sundry is to clean out the liner with coil tubing/nitrogen, and perforate Beluga and Sterling sands. Wellbore Conditions: - Liner will be full of 10.1 ppg 6% KCl mud - Tubing and IA will be displaced to 8.4 ppg CIW - T & IA will be pressure tested to 3000 psi Pre-Sundry work: 1. Review all approved COAs 2. MIRU E-line and pressure control equipment 3. Log well with CBL tool in 4-1/2” liner (send results to AOGCC to review) 4. RDMO E-line Procedure: 1. MIRU Coil Tubing and pressure control equipment 2. PT lubricator to 250psi low / 3000psi high a. Provide AOGCC 48hr notice for BOP test 3. RIH & clean out wellbore to PBTD (~5098’), displace liner to 8.4 ppg water 4.Reverse out wellbore with nitrogen, trap ~1500 psi on wellbore o ~78 bbls total wellbore volume 5. RDMO coil tubing 6. RU E-line, PT lubricator to 2500 psi 7. Ops bleed N2 from well as directed by OE/RE for desired perforating pressure by zone (typically targeting 20% underbalance) 8. RIH and perforate per RE/Geo and test Beluga sands within the interval below, from the bottom up: Sand MD Top MD Base TVD Top TVD Base H ST X3 ±3,482' ±3,487' ±3,300' ±3,304' ±5 ST A1 ±3,567' ±3,575' ±3,369' ±3,375' ±8 ST A3 ±3,641' ±3,658' ±3,428' ±3,442' ±17 targeting the Sterling and Beluga sands. , equivalent to about 2,617' MD.SFD Well Prognosis ST A5 ±3,754' ±3,762' ±3,518' ±3,525' ±8 ST A5 ±3,772' ±3,796' ±3,533' ±3,552' ±24 ST B1 ±3,819' ±3,832' ±3,570' ±3,580' ±13 ST B2 ±3,853' ±3,858' ±3,597' ±3,601' ±5 ST C1 ±3,989' ±4,002' ±3,704' ±3,715' ±13 ST C1 ±4,014' ±4,030' ±3,724' ±3,737' ±16 ST C2 ±4,061' ±4,069' ±3,761' ±3,768' ±8 ST C5 ±4,139' ±4,154' ±3,823' ±3,835' ±15 Beluga D3 ±4,251' ±4,259' ±3,913' ±3,919' ±8 a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations. Pending well production, all perf intervals may not be completed 9. RDMO 10. Turn well over to production & flow test well 11. Test SVS as necessary once well has reached stable flow rates a. Notify state 48hrs prior to testing within 5 days of stable production Coil Procedure (Contingency) If necessary to cleanout or unload well with coiled tubing: 1. MIRU Coiled Tubing Unit, PT BOPE to 3,000 psi High/250 psi Low 2. Provide AOGCC 24hrs notice of BOP test 3. PU wash nozzle, RIH and cleanout well to below perfs or proposed plug depth 4. PU CT jet nozzle and RIH, unload fluid from the wellbore with nitrogen a. Reverse circ out any fluid if perfs are isolated/plugged back and in cased hole 5. RDMO coil tubing Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Coil Tubing BOP Diagram 4. Standard Nitrogen Operations _____________________________________________________________________________________ Updated by DMA 09-20-24 CURRENT SCHEMATIC Pretty Creek Unit Well: PCU-02A PTD: 224-110 API: 50-283-20022-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 94 / H-40 / Butt 19”Surf 339’ 13-3/8”Surface 61 / J-55 / Butt 12.515”Surf 2,032’ 9-5/8"Intermediate 47/43.5 P-100/N-80 8.861”Surf 2,070’ (TOW) 4-1/2”Prod Casing 12.6 / L-80 / GBCD 3.883”1,867’5,188’ 4-1/2”Tieback 12.6 / L-80 / GBCD 3.883”Surf 1,867’ OPEN HOLE / CEMENT DETAIL 20”TOC @ Surface 600 sx 13-3/8”TOC @ Surface 675 sx (Stg 2 + Top Job) Stg 1 660 sx 9-5/8"Est. TOC @ 1,500’ 1020 sx Stg 2 / 1110 sx Stg 1 4-1/2”TOC @ ±1,850’ L – 255 bbls / T – 36.5 bbls JEWELRY DETAIL No.Depth Item 1 ±1,850’Liner Top Packer 2 ±1,867’Baker 7” x 9.6” SLZXP (HRD-E) Liner top hanger/Packer NOTES 8.5” Ghost hole from 2714’ to 6000’ Short Joints (~10ft)3,351’, 3610’ (w/ RA Tag), 3912’ (w/ RA Tag), 4337’ (w/ RA Tag) _____________________________________________________________________________________ Updated by DMA 09-20-24 PROPOSED Pretty Creek Unit Well: PCU-02A PTD: 224-110 API: 50-283-20022-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 94 / H-40 / Butt 19”Surf 339’ 13-3/8”Surface 61 / J-55 / Butt 12.515”Surf 2,032’ 9-5/8"Intermediate 47/43.5 P-100/N-80 8.861”Surf 2,070’ (TOW) 4-1/2”Prod Casing 12.6 / L-80 / GBCD 3.883”1,867’5,188’ 4-1/2”Tieback 12.6 / L-80 / GBCD 3.883”Surf 1,867’ OPEN HOLE / CEMENT DETAIL 20”TOC @ Surface 600 sx 13-3/8”TOC @ Surface 675 sx (Stg 2 + Top Job) Stg 1 660 sx 9-5/8"Est. TOC @ 1,500’ 1020 sx Stg 2 / 1110 sx Stg 1 4-1/2”TOC @ ±1,850’ L – 255 bbls / T – 36.5 bbls JEWELRY DETAIL No.Depth Item 1 ±1,850’Liner Top Packer 2 ±1,867’Baker 7” x 9.6” SLZXP (HRD-E) Liner top hanger/Packer PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Ft Date Status ST X3 ±3,482'±3,487'±3,300'±3,304'±5 Proposed TBD ST A1 ±3,567'±3,575'±3,369'±3,375'±8 Proposed TBD ST A3 ±3,641'±3,658'±3,428'±3,442'±17 Proposed TBD ST A5 ±3,754'±3,762'±3,518'±3,525'±8 Proposed TBD ST A5 ±3,772'±3,796'±3,533'±3,552'±24 Proposed TBD ST B1 ±3,819'±3,832'±3,570'±3,580'±13 Proposed TBD ST B2 ±3,853'±3,858'±3,597'±3,601'±5 Proposed TBD ST C1 ±3,989'±4,002'±3,704'±3,715'±13 Proposed TBD ST C1 ±4,014'±4,030'±3,724'±3,737'±16 Proposed TBD ST C2 ±4,061'±4,069'±3,761'±3,768'±8 Proposed TBD ST C5 ±4,139'±4,154'±3,823'±3,835'±15 Proposed TBD Beluga D3 ±4,251'±4,259'±3,913'±3,919'±8 Proposed TBD NOTES 8.5” Ghost hole from 2714’ to 6000’ Short Joints (~10ft)3,351’, 3610’ (w/ RA Tag), 3912’ (w/ RA Tag), 4337’ (w/ RA Tag) STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 1 McLellan, Bryan J (OGC) From:McLellan, Bryan J (OGC) Sent:Monday, September 30, 2024 4:21 PM To:Chad Helgeson Subject:RE: [EXTERNAL] PCU-02A (PTD 224-110) CBL Chad, Hilcorp has approval to perform the CT cleanout as described in the Sundry application submitted on 9/20/24. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Monday, September 30, 2024 4:05 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] PCU-02A (PTD 224-110) CBL Not yet. We are running it tonight. I should have it tomorrow morning. From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, September 30, 2024 4:03 PM To: Chad Helgeson <chelgeson@hilcorp.com> Subject: [EXTERNAL] PCU-02A (PTD 224-110) CBL Chad, Do you have the CBL log for this well yet? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 2 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. 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:Pretty Creek Unit, Undefined Gas Pool, PCU-02A Hilcorp Alaska, LLC Permit to Drill Number: 224-110 UHYLVHG Surface Location: 1608' FNL, 2128' FEL, Sec 33, T14N, R9W, SM, AK Bottomhole Location: 65' FSL, 1593' FEL, Sec 33, T14N, R9W, SM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. 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, Jessie L. Chmielowski Commissioner DATED this 18th day of September 2024. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.09.18 08:28:59 -08'00' 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 5,128' TVD: 4,623' 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): 100.5' 15. Distance to Nearest Well Open Surface: x-342548 y-2654865 Zone-.4 82' to Same Pool: 5540' to PCU-04 16. Deviated wells:Kickoff depth: 2,750 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 37 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 8-1/2" 4-1/2" 12.6# L-80 GBCD 3,278' 1,850' 1,850' 5,128' 4,623' Tieback 4-1/2" 12.6# L-80 GBCD 1,850' Surface Surface 1,850' 1,850' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD 339' 2,032' 8,550' 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: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: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng PCU-02A Pretty Creek Unit Undefined Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. Plugged 8,550'9-5/8" Total Depth MD (ft):Total Depth TVD (ft): 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL REVISED 20 AAC 25.005 1809 677' FNL, 1817' FEL, Sec 33, T14N, R9W, SM, AK 65' FNL, 1593' FEL, Sec 33, T14N, R9W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 1608' FNL, 2128' FEL, Sec 33, T14N, R9W, SM, AK ADL 390780 18. Casing Program:Top - Setting Depth - BottomSpecifications 2271 GL / BF Elevation above MSL (ft): Plugs (measured): (including stage data) L - 1084 ft3 / T - 205 ft3 Tieback Assy. 2,990'2,990' Effect. Depth MD (ft):Effect. Depth TVD (ft): 12,025'12,025' LengthCasing ±2,990' Size Plugged Conductor/Structural 20"339' Authorized Title: Authorized Signature: Authorized Name: Production Liner 8,550' Intermediate 600 sx 339' 2,032'13-3/8"1335 sx Drilling Manager Monty Myers 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):Perforation Depth MD (ft): 2,032' 2130 sx 9/3/2024 5345' to nearest unit boundary Sean Mclaughlin sean.mclaughlin@hilcorp.com 907-223-6784 840 Cement Volume MD s N ype of W L l R L 1b S Class: os N s No s N o D s s sD 84 o well is p G S S 20 S S S s Nos No S G y E S s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) Drilling Manager 09/17/24 Monty M Myers By Grace Christianson at 1:29 pm, Sep 17, 2024 SFD 9/17/2024BJM 9/17/24 50-283-20022-01-00224-110 BOP test to 2500 psi Verbal approval granted to proceed 9/17/24 - bjm *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.09.18 08:29:12 -08'00'09/18/24 0/24 RBDMS JSB 091924 PC-02A Drilling Program Pretty Creek Unit Sean McLaughlin August 28, 2024 September 17, 2024 -bjm Contents 1. Well Summary.....................................................................................................................................2 2. Management of Change Information................................................................................................3 3. Tubular Program................................................................................................................................4 4. Drill Pipe Information........................................................................................................................4 5. Internal Reporting Requirements.....................................................................................................5 6. Current Wellbore Schematic (Planned post RWO).........................................................................6 7. Planned Wellbore Schematic.............................................................................................................7 8. Drilling Summary...............................................................................................................................8 9. Mandatory Regulatory Compliance / Notifications.........................................................................9 10. R/U and Preparatory Work.............................................................................................................10 11. BOP N/U and Test.............................................................................................................................11 12. Set Whipstock / Mill Window..........................................................................................................12 13. Drill 8-1/2” Hole Section...................................................................................................................14 14. Run 4-1/2” Production Liner...........................................................................................................15 15. Cement 4-1/2” Production Liner.....................................................................................................17 16. Wellbore Clean Up & Displacement...............................................................................................20 17. 4-1/2” Liner Tieback Polish Run.....................................................................................................21 18. Run Completion Assembly...............................................................................................................21 19. BOP Schematic..................................................................................................................................22 20. Wellhead Schematic..........................................................................................................................23 21. Anticipated Drilling Hazards...........................................................................................................24 22. FIT Procedure...................................................................................................................................25 23. Choke Manifold Schematic..............................................................................................................26 24. Casing Design Information ..............................................................................................................27 25. 8-1/2” Hole Section MASP...............................................................................................................27 26. Plot (NAD 27) (Governmental Sections).........................................................................................29 Page 2 August 28, 2024 PC-02A Drilling Program APD 224-110 1. Well Summary New Well PCU-02A Drilling Rig Rig 147 Pad Pretty Creek Pad Directional plan wp09 Old Well Designation PC-02 Planned Completion Type 4-1/2” 12.6# Liner, 4-1/2” Tie back Target Reservoir(s)Sterling/Beluga Kick off point 2070’ MD / 2070’ Planned Well TD, MD / TVD 5128’ MD / 4623’ TVD PBTD, MD 55048’ MD MASP 1809 psi AFE Number AFE Days 21 days AFE Drilling Amount Work String(s)4-1/2” 16.6# S-135 CDS-40 RKB – AMSL 100.5’ MSL to ML 82.0’ 5048' MD per Ryan Ciolkosz Page 3 August 28, 2024 PC-02A Drilling Program APD 224-110 2. Management of Change Information Date: Subject: Changes to Approved Permit to Drill File #: PCU-02A Drilling Program Significant modifications to Drilling Program for PTD will be documented and approved below. Changes to an approved PTD will be communicated and approved by the AOGCC prior to continuing forward with work. Sec Page Date Procedure Change Approval: Drilling Manager Date Prepared: Engineer Date Page 4 August 28, 2024 PC-02A Drilling Program APD 224-110 3. Tubular Program Hole Section OD (in)ID (in)Drift (in) Conn OD (in) Wt (#/ft)Grade Conn Burst (psi) Collap se (psi) Tension (k-lbs) 8-1/2”4-1/2”3.958”3.833”5.0”12.6#L-80 GBCD 8430 7500 288 ** Minimum of 100’ overlap required between casing strings 4. 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 Page 5 August 28, 2024 PC-02A Drilling Program APD 224-110 5. Internal Reporting Requirements 1. Fill out daily drilling report and cost report. x Report covers operations from 6am to 6am x Ensure time entry adds up to 24 hours total. x Capture any out-of-scope work as NPT. This helps later when aggregating end of well reports. 2. Afternoon Updates x Submit a short operations update every day to kenaiciodrilling@hilcorp.com 3. EHS Incident Reporting x Notify EHS field coordinator. i. 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!!!! 1. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753 2. Leonard Dickerson: O: (907) 777-8317 C: (907) 252-7855 ii. Spills: x Notify Drlg Manager i. Monty M Myers: O: 907-777-8431 C: 907-538-1168 x Submit Hilcorp Incident report to contacts above within 24 hrs 4. Casing Tally x Send final “As-Run” Casing tally to sean.mclaughlin@hilcorp.com and cdinger@hilcorp.com 5. Casing and Cmt report x Send casing and cement report for each string of casing to sean.mclaughlin@hilcorp.com and cdinger@hilcorp.com Page 6 August 28, 2024 PC-02A Drilling Program APD 224-110 6. Wellbore Schematic (Planned post RWO) Page 7 August 28, 2024 PC-02A Drilling Program APD 224-110 7. Planned Wellbore Schematic Page 8 August 28, 2024 PC-02A Drilling Program APD 224-110 8. Drilling Summary PCU-02A is a 5128’ MD / 4623’ TVD development gas sidetrack drilled from Pretty Creek Pad. The base plan is a northern step out well to the Sterling/Beluga formation. The well will be completed with a 4-1/2” tie-back completion. Drilling operations is expected to commence approximately September 2024. General sequence of operations pertaining to this drilling operation: Pre-Rig Scope: Test Casing, Decomplete, Plug PC-02 Rig Work 1. Rig 147 will MIRU over PC-02 2. NU BOPE and test to 2500 psi. (MASP 1809psi) 3. Set 9-5/8” whipstock at 2065’ and 20R. Swap well to 9.2 ppg mud. x Gyro required for WS set 4. Mill window with 20’ of new formation. 5. Perform FIT to 13.0 ppg EMW 6. MU 8-1/2” bit with 6-3/4” tools (Triple Combo MAD pass) 7. Drill 8-1/2” production hole to 5128 MD, performing short trips as needed x Consider picking up LWD tools and MAD pass after TD of interval 8. RIH w/ 4-1/2” liner. Set liner and cement. Circ wellbore clean. 9. Perform Clean out run to polish bore, LDDP 10. Perform liner lap test to 2500 psi. 11. Run 4-1/2” tie back completion. 12. Land hanger and test.MIT-T to 2500 psi, MIT-IA to 2500 psi 13. ND BOPE, NU tree and test void Reservoir Evaluation Plan: 1. Geolog mud logging 2. Production Hole: Triple Combo LWD (consider MAD pass after drilling) 3. SLB Coal logging Page 9 August 28, 2024 PC-02A Drilling Program APD 224-110 9. Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that 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. Ensure to provide AOGCC 48 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/2500 psi & subsequent tests of the BOP equipment will be to 250/2500 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. o The highest reservoir pressure expected is 2271 psi in the Beluga F sand (4616' TVD). MASP is 1809 psi with 0.1psi/ft gas in the wellbore. o A casing test to 2500 is planned as part of the prerig work x Rated Working Pressure (RWP) the BOPE and wellhead must meet or exceed:3000 psi. x If the BOP is used to shut in on the well in a well control situation,ALL BOP components utilized for well control must be tested prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: None Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 8-1/2” x 11” x 5M Annular BOP x 11” x 5M Double Ram o Blind ram in btm cavity x Mud cross x 11” x 5M Single Ram x 3-1/8” 5M Choke Line x 2-1/16” x 5M Kill line x 3-1/8” x 2-1/16” 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/2500 (Annular 2500 psi) Subsequent Tests: 250/2500 (Annular 2500 psi) x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). Page 10 August 28, 2024 PC-02A Drilling Program APD 224-110 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 48 hours notice prior to full BOPE test. x Any other notifications required in APD conditions of approval. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / (C): 907-250-9193 / Email:bryan.mclellan@alaska.gov Melvin Rixse / Petroleum Engineer / (O): 907-793-1231 / Email:melvin.rixse@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) 10. R/U and Preparatory Work 1. Proposed rig orientation Page 11 August 28, 2024 PC-02A Drilling Program APD 224-110 2. 8-1/2” hole section mud program summary: Weighting material to be used for the hole section will be barite, 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. Ensure fluids are topped off and adequate lost circulation material is on location in anticipation of losses in hole section. System Type:9.2 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 2050’- 5128’9.0 – 10.0 40-53 15-25 15-25 8.5-9.5 11.0 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) 11. BOP N/U and Test 1. N/D Tree and adapter (BPV installed as part of pre-rig work), Install blanking plug 2. N/U to 11” 5M tubing spool 3. N/U 11” x 5M BOP as follows: Page 12 August 28, 2024 PC-02A Drilling Program APD 224-110 x BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram /11” x 5M mud cross/11” x 5M single ram x Double ram should be dressed with 2-7/8” x 5” variable bore rams in top cavity, blind ram in btm cavity. x Single ram should be dressed with 2-7/8” x 5” variable bore rams x N/U bell nipple, install flowline. x Install (2) manual valves & a check 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. x 11” 5M adapter required 4. Run BOPE test plug. 5. Test BOPE. x Test BOP to 250/2500 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. x Ensure to leave “A” section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. Confirm the correct valves are opened. x Test VBRs on a 4-1/2” a test joint (2500 psi test) x Test Annular on 4-1/2” test joint (2500 psi) x Ensure gas monitors are calibrated and tested in conjunction w/ BOPE. 6. Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section. 7. Pull test plug. 12. Set Whipstock / Mill Window Operation Steps: 1. Set wear bushing in wellhead. Ensure ID of wear bushing > 8-1/2”. 2. Make up the WIS Mechanical set Whipstock and RU to run GYRO 3. TIH with DP to the whipstock setting depth. Exercise caution when RIH / setting slips with whipstock assembly ¾Fill the drill pipe a minimum of every 20 stands on the trip in the hole with the whipstock assembly. ¾Avoid sudden starts and stops while running the whipstock. ¾Recommend running in the hole at a maximum of 90-120 seconds per stand taking care not to spud or catch the slips. Ensure running string is stationary prior to insertion of the slips and that slips are removed slowly when releasing the work string to RIH. These precautions are required to avoid any weakening of the whipstock shear mechanisms and / or to avoid part / preset on the packer. Page 13 August 28, 2024 PC-02A Drilling Program APD 224-110 4. Run GYRO to obtain tray face. Orient whipstock as directed by the directional driller. The directional plan specifies 20 deg ROHS. 5. Set the top of the whipstock at ~2,065’ MD x 9-5/8” CIBP set at 2134’ x 9-5/8” Collars at 2060’and 2102’ x Ref log: PCU-02 SCH CBL 09-JUN-1969 (TOC behind 9-5/8” ~1500’) 6. Mill window plus 20’-50’ of new hole (DO NOT EXCEED 50’ OF NEW HOLE BEFORE RUNNING THE PLANNED FIT/LOT). ¾Use ditch magnets to collect the metal shavings. Clean regularly. ¾Ensure any personnel working around metal shavings wear proper PPE, including goggles, face shield and Kevlar gloves. ¾Work the upper mill through the window to confirm the window milling is complete and circulate well clean (circulate a minimum of 1-1/2 bottoms up). Pump a high-vis super sweep to remove metal shavings and make every effort to remove all of the super sweep pill from the mud system as it is circulated to surface. 7. Pull starter mill into casing above top of whipstock, flow check the well for 10 minutes and conduct a FIT to 13.0 ppg. ¾**Assuming the kick zone is at TD, a FIT of 12.0 ppg EMW gives a Kick Tolerance volume of 50 bbls with 10.0 ppg mud weight. ¾Monitor OA during FIT and report and change in pressure. 8. POOH and LD milling assembly ¾Once out of the hole, inspect mill gauge and record. ¾Flow check well for 10 minutes to confirm no flow: ¾Before pulling off bottom. ¾Before pulling the BHA through the BOPE. 9. Flush the stack/lines to remove metal debris that may have settled out in these areas. Ensure BOP equipment is operable. FIT was 13.3 ppg. -bjm Page 14 August 28, 2024 PC-02A Drilling Program APD 224-110 13. Drill 8-1/2” Hole Section 1. P/U 6-3/4” Sperry Sun motor drilling assy w/ GR only x Triple combo tools (DEN, POR, RES) will be run after TD. 2. Ensure BHA Components have been inspected previously. 3. Drift & caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 4. Ensure TF offset is measured accurately and entered correctly into the MWD software. 5. Have DD run hydraulics models to ensure optimum TFA. Plan to pump at 400-500 gpm. 6. Production section will be drilled with a motor. Must keep up with 5 deg/100 DLS in the build section of the wellbore. 7. TIH to window. Shallow test MWD on trip in. 8. Circulate well with 9.2 ppg mud to warm up mud until good 9.2 ppg in and out. 9. Drill 8-1/2” hole to 5128’ MD using motor assembly. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled.A significant coal (50’ TVD) is expected ~3264’ TVD. x Keep swab and surge pressures low when tripping. x Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. 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. x Minimize backreaming when working tight hole x Planned weight up to 10.0 ppg prior to drilling into the Beluga D5 at 3953’ TVD Triple combo tools (DEN, POR, RES) will be run after TD Page 15 August 28, 2024 PC-02A Drilling Program APD 224-110 10. At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement calculations. CBU. 11. TOH with drilling assembly, handle BHA as appropriate. PU Tripple Combo Logging tools and MAD pass per Geo Team. 12. POOH LDDP and BHA 13. Confirm 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 4-1/2” test joint. 14. Run 4-1/2” Production Liner 1. R/U Parker 4-1/2” liner running equipment. x Ensure DP crossover on rig floor and M/U to FOSV. x R/U fill up line to fill liner while running. x Ensure all liner has been drifted and tally verified 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. 2. P/U shoe joint, visually verify no debris inside joint. 3. Continue M/U & thread locking shoe track assy consisting of: Planned MWs Formation Top TVD max PPG Planned MW Sterling X2/X3 3264 8.8 9.20 Sterling B3 3702 8.8 9.20 Sterling C1 3734 8.8 9.20 Sterling C2 3786 8.8 9.20 Sterling C4 3837 8.8 9.20 Sterling C5 3873 8.8 9.20 Beluga D5 3953 9.4 10.00 Beluga D6 3979 9.5 10.00 Beluga E 4016 9.5 10.00 TD in Beluga F 4616 9.5 10.00 Page 16 August 28, 2024 PC-02A Drilling Program APD 224-110 x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). Centralizer 10’ from the bottom with stop ring x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x Landing collar pup bucked up. No centralizer x Centralizers will be run on 4-1/2” liner every joint. x Ensure proper operation of float shoe & FC. 4. Continue running 4-1/2” production liner to TD x Short joint and RA tag run every 1000’. x Fill liner while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Utilize a collar clamp until weight is sufficient to keep slips set properly. 5.Ensure to run enough liner to provide at least 100’ overlap inside casing. Ensure setting sleeve will not be set in a connection. Page 17 August 28, 2024 PC-02A Drilling Program APD 224-110 6. Before picking up Baker ZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 7. M/U Baker ZXP liner top packer. Fill liner tieback sleeve with “XANPLEX”, ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 8. RIH one stand and circulate a minimum of one liner volume. Note weight of liner. 9. RIH w/ liner on DP no faster than 1 min / stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 10. M/U top drive and fill pipe while lowering string every 10 stands. 11. Set slowly in and pull slowly out of slips. 12. Circulate 1-1/2 drill pipe and liner volume at the 9-5/8” window prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure. 13. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 14. Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill casing. 15. P/U the cmt stand and tag bottom with the liner shoe. P/U 2’ off bottom. Note slack-off and pick-up weights. Record rotating torque values at 10, 20, & 30 rpm. 16. Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting pressure. Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling fluid by adding water and thinners. 17. Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. 15. Cement 4-1/2” Production Liner 1. Hold a pre-job safety meeting over the upcoming cmt operations. 2. Attempt to reciprocate the casing during cmt operations until hole gets sticky. 3. Pump 5 bbls 12.5 ppg spacer. 4. Test surface cmt lines to 4500 psi. 5. Pump remaining 12.5 ppg spacer. Page 18 August 28, 2024 PC-02A Drilling Program APD 224-110 6. Mix and pump cement per below recipe and volume below with xx lbs/bbl of loss circulation fiber. Please independently verify cement volume with actual inputs. Ensure cmt is pumped at designed weight. Job is designed to pump 40% OH excess but if wellbore conditions dictate otherwise decrease or increase excess volumes. Cement volume is designed to bring cement to TOL. 7. Displacement fluid will be CLEAN drilling mud. Please independently verify with actual inputs. Slurry Information: Production Liner Cement Volumes Surface Casing OD 9.625 Suface Casing ID 8.681 Hole Size 8.5 in Casing OD 4.5 in Casing ID 3.958 in DP OD 4.5 in DP x Casing Annular Capacity 0.05354 bbl/ft Liner x Casing Annular Capacity 0.05354 bbl/ft Liner x OH Annular Capacity 0.05051 bbl/ft Casing Capacity 0.01522 bbl/ft OH Excess 40% Lead Cement Liner x OH 182.32 bbls Liner x Casing 10.71 bbls Total Lead 193.03 bbls Tail Cement Casing x OH 35.36 bbls Shoetrack 1.22 bbls Total Tail 36.58 bbls Total Job 229.60 bbls Cement Slurry Design: Lead Slurry (4628’ MD to 1850’ MD)Tail Slurry (5128’ to 4628’ 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 Page 19 August 28, 2024 PC-02A Drilling Program APD 224-110 Mixed Fluid 14.469 gal/sk 5.507 gal/sk Additives Code Description Code Description Type I/II Cement Class A Type I/II Cement Class A Halad-344 Fluid Loss Halad-344 Fluid Loss HR-5 Retarder HR-5 Retarder D-Air 5000 Anti Foam CFR-3 Dispersant Econolite Light-weight add.FDP-C1446-21 Slurry Conditioner SA-1015 Suspension Agent BridgeMaker II Lost Circulation 8. Drop DP dart and displace with KWF. 9. Pump cement at max rate of 5 bbl/min. Reduce pump rate to 3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re-zeroed at this point 10. If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. Reduce pump rate as required to avoid packoff. 11. Bump the plug. Do not overdisplace by more than 2 bbls. 12. Pressure up to 4200 psi to release the running tool (HRD-E) from the liner 13. Bleed pressure to zero to check float equipment. 14. P/U, verify setting tool is released. 15. Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 16. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 17. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re-tag the liner top, and circulate the well clean. 18. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. Page 20 August 28, 2024 PC-02A Drilling Program APD 224-110 19. POOH, LDDP. Backup release from liner running tool: 20. If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 21. NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down to the setting tool. 22. After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. Ensure to report the following on Wellview: 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 liner 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 Note: Send Csg & cmt report + “As-Run” liner tally to sean.mclaughlin@hilcorp.com 16. Wellbore Clean Up & Displacement 1. No cleanout planned. Service coil will cleanout, displace mud, and blow down well with N2 prior to perforating. Page 21 August 28, 2024 PC-02A Drilling Program APD 224-110 2. Test liner lap to 2500 psi after cement has reached 500 psi compressive strength. 10 min operational assurance test. 17. 4-1/2” Liner Tieback Polish Run 1. PU liner tieback polish mill assy per BOT rep and RIH on drillpipe. 2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per BOT procedure. 3. POOH, and LDDP and polish mill. 18. Run Completion Assembly 1. Run 4-1/2” tubing completion assembly to above the liner top x Tubing will be 4-1/2” L-80 12.6# GBCD x No GLM, CIM, or SSSV required 2. Swap the well over to CI Water 3. Space out and land seal bore in tie back sleeve. RILDs. 4.Test IA to 2500 psi and tubing to 2500 psi. Charted 30 min. 5. Install BPV in wellhead. 6. ND BOPE, NU tree, test void 7. Rig Down Page 22 August 28, 2024 PC-02A Drilling Program APD 224-110 19. BOP Schematic Page 23 August 28, 2024 PC-02A Drilling Program APD 224-110 20. Wellhead Schematic Page 24 August 28, 2024 PC-02A Drilling Program APD 224-110 21. Anticipated Drilling Hazards 8-1/2” 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. Anti Collision: None Page 25 August 28, 2024 PC-02A Drilling Program APD 224-110 22. 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 plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. Add casing pressure test data to graph if recent and available. 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 26 August 28, 2024 PC-02A Drilling Program APD 224-110 23. Choke Manifold Schematic Page 27 August 28, 2024 PC-02A Drilling Program APD 224-110 24. Casing Design Information 25. 8-1/2” Hole Section MASP Page 28 August 28, 2024 PC-02A Drilling Program APD 224-110 Page 29 August 28, 2024 PC-02A Drilling Program APD 224-110 26. Plot (NAD 27) (Governmental Sections) !"" #$% &' ( )* % +,,-*'., )* 1500 1750 2000 2250 2500 2750 3000 3250 3500 3750 4000 4250 4500 4750 5000 5250True Vertical Depth (500 usft/in)0 250 500 750 1000 1250 1500 1750 2000 2250 2500 2750 3000 3250 3500 Vertical Section at 14.90° (500 usft/in) 1500 2000 2 5 0 0 3000350040004500500055006000PCU-02A PB1 1500 2000 2 5 0 0 3000350040004275PCU-02A 1500 2000 2500 3000 3500 4000 4500 5000 PRETTY CK UNIT 2 13-3/8" x 17-1/2" 4 1/2" 1500 2000 2 5 0 0 300035004000450050005128PCU-2A wp09 Tie-on to survey 4275.42 'MD Start Dir 2º/100' : 4287.45' MD, 3942.97'TVD Total Depth : 5128' MD, 4622.98' TVD Beluga D5 Beluga D6Beluga E TD in Beluga F Hilcorp Alaska, LLC Calculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: Rig: PRETTY CK UNIT 2 Ground Level: 82.00 +N/-S +E/-W Northing Easting Latittude Longitude0.00 0.00 2654865.58 342548.83 61° 15' 48.747 N 150° 53' 40.034 W SURVEY PROGRAM Date: 2024-05-20T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 64.50 2036.50 PRETTY CK UNIT 1 (PRETTY CK UNIT 2)3_INC-Only2070.00 2380.00 Gyro-GC_Drop (Pretty CK Unit 2A PB1) 3_Gyro-GC_Drop 2466.09 4275.42 MWD+AX+Sag (2) (Pretty CK Unit 2A) 3_MWD+AX+Sag 4275.42 5128.00 PCU-2A wp09 (Pretty CK Unit 2A) 3_MWD+AX+Sag FORMATION TOP DETAILS TVDPath MDPath Formation 3264.50 3436.58 Sterling X2/X3 - 50' TVD gross coal 3701.50 3984.44 Sterling B3 3734.50 4026.16 Sterling C1 3786.50 4091.83 Sterling C2 3836.50 4154.76 Sterling C4 3873.50 4201.10 Sterling C5 3952.50 4299.24 Beluga D5 3979.50 4332.61 Beluga D6 4015.50 4377.11 Beluga E 4300.50 4729.39 TD in Beluga F REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Rig: PRETTY CK UNIT 2, True North Vertical (TVD) Reference:PCU 2A @ 100.50usft Measured Depth Reference:PCU 2A @ 100.50usft Calculation Method:Minimum Curvature Project:Beluga River North Site:Pretty CK Unit 2 Pad Well:Rig: PRETTY CK UNIT 2 Wellbore:Pretty CK Unit 2A Design:PCU-2A wp09 CASING DETAILS TVD MD Name Size 4622.98 5128.00 4 1/2" 4-1/2 SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 4275.42 36.24 20.03 3933.25 1071.91 361.39 0.00 0.00 1128.79 Tie-on to survey 4275.42 'MD 2 4287.45 36.00 20.00 3942.97 1078.58 363.82 2.00 -175.80 1135.86 Start Dir 2º/100' : 4287.45' MD, 3942.97'TVD 3 5128.00 36.00 20.00 4622.98 1542.84 532.80 0.00 0.00 1627.96 Total Depth : 5128' MD, 4622.98' TVD -250 -125 0 125 250 375 500 625 750 875 1000 1125 1250 1375 1500 1625 1750 1875 South(-)/North(+) (250 usft/in)-125 0 125 250 375 500 625 750 875 1000 1125 1250 1375 1500 1625 West(-)/East(+) (250 usft/in) PCU-02A PB1 PCU-02A PRETTY CK UNIT 2 26" x 30" 13-3/8" x 17-1/2" 4 1/2" 250500750100012501500175020002250 2500 2750 3000 3250 3500 3750 4000 4250 4500 4623 PCU-2A wp09 Tie-on to survey 4275.42 'MD Start Dir 2º/100' : 4287.45' MD, 3942.97'TVD Total Depth : 5128' MD, 4622.98' TVD CASING DETAILS TVD MD Name Size 4622.98 5128.00 4 1/2" 4-1/2 Project: Beluga River North Site: Pretty CK Unit 2 Pad Well: Rig: PRETTY CK UNIT 2 Wellbore: Pretty CK Unit 2A Plan: PCU-2A wp09 WELL DETAILS: Rig: PRETTY CK UNIT 2 Ground Level: 82.00 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2654865.58 342548.83 61° 15' 48.747 N 150° 53' 40.034 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Rig: PRETTY CK UNIT 2, True NorthVertical (TVD) Reference:PCU 2A @ 100.50usft Measured Depth Reference:PCU 2A @ 100.50usft Calculation Method:Minimum Curvature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original wellbore was P&A'd. -bjm 0.001.002.003.004.00Separation Factor4300 4400 4500 4600 4700 4800 4900 5000 5100 5200 5300 5400 5500 5600 5700 5800 5900 6000 6100 6200Measured Depth (200 usft/in)No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:Rig: PRETTY CK UNIT 2 NAD 1927 (NADCON CONUS)Alaska Zone 04Ground Level: 82.00+N/-S +E/-W Northing Easting Latittude Longitude0.000.002654865.58 342548.83 61° 15' 48.747 N 150° 53' 40.034 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Rig: PRETTY CK UNIT 2, True NorthVertical (TVD) Reference:PCU 2A @ 100.50usftMeasured Depth Reference:PCU 2A @ 100.50usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2024-05-20T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool64.50 2036.50 PRETTY CK UNIT 1 (PRETTY CK UNIT 2)3_INC-Only2070.00 2380.00 Gyro-GC_Drop (Pretty CK Unit 2A PB1) 3_Gyro-GC_Drop2466.09 4275.42 MWD+AX+Sag (2) (Pretty CK Unit 2A) 3_MWD+AX+Sag4275.42 5128.00 PCU-2A wp09 (Pretty CK Unit 2A) 3_MWD+AX+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)4300 4400 4500 4600 4700 4800 4900 5000 5100 5200 5300 5400 5500 5600 5700 5800 5900 6000 6100 6200Measured Depth (200 usft/in)MD + Stations, interval: 25.004275.42 To 5128.00Project: Beluga River NorthSite: Pretty CK Unit 2 PadWell: Rig: PRETTY CK UNIT 2Wellbore: Pretty CK Unit 2APlan: PCU-2A wp09Ladder / S.F. Plots2 of 2CASING DETAILSTVD MD Name Size4622.98 5128.00 4 1/2" 4-1/2 1 McLellan, Bryan J (OGC) From:McLellan, Bryan J (OGC) Sent:Tuesday, September 17, 2024 5:15 PM To:Ryan Ciolkosz Cc:Sean McLaughlin; John Perl; Monty Myers; Cody Dinger; Davies, Stephen F (OGC); Roby, David S (OGC) Subject:RE: PCU-02A Sidetrack PTD Revision (PTD# 224-110) Ryan, As discussed on the phone, Hilcorp has verbal approval to proceed with the revised PTD plan as submitted today. Required BOP test pressure is 2500 psi. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Ryan Ciolkosz <Ryan.Ciolkosz@hilcorp.com> Sent: Tuesday, September 17, 2024 10:30 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; John Perl <John.Perl@hilcorp.com>; Monty Myers <mmyers@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com> Subject: PCU-02A Sidetrack PTD Revision (PTD# 224-110) Brian, As discussed on the phone, while MAD passing the PCU-02A well bore the rig inadvertently sidetracked at roughly 2750’ (based on near bit inclination) and drilled to 4316’ before there was a noticeable change in parameters (ROP/WOB etc.). Based on the logs and options available at this point, we would like to continue drilling the new hole to the original target formation. Attached is an updated well plan (09) with new TD. The liner/cement and tubing program will be the same as the originally permitted well with slight variations due to the change in TD measured depth. The rig will be ready to go back to drilling in the next few hours and would like to request an expedited approval over email if possible. Let me know if you have any questions. You don't often get email from ryan.ciolkosz@hilcorp.com. Learn why this is important 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 Thanks, Ryan Ciolkosz | Drilling Engineer C: 907.244.4357 | O: 907.564.4413 3800 Centerpoint Dr. Suite 1400 | Anchorage, Alaska 99503 44.4357 | O: 907.564.4413 H 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. Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. 224-110 PCU 02A (REVISED) PRETTY CREEK, UNDEFINED GASPRETTY CREEK WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:PRETTY CK UNIT 02AInitial Class/TypeDEV / 1-GASGeoArea820Unit11620On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2241100PRETTY CREEK, UNDEFINED GAS - 580500NA1 Permit fee attachedYes Entire Well lies within ADL0390780.2 Lease number appropriateYes3 Unique well name and numberNo PRETTY CREEK, UNDEFINED GAS - 580500 - governed by Statewide Regs4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For NA15 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)NA Sidetrack18 Conductor string providedNA Sidetrack19 Surface casing protects all known USDWsNA Sidetrack20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitYes25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedNA27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 1809 psi, BOP rated to 5000 psi (BOP test to 2500 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 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: not expected; mitigation discussed; see p. 26.35 Permit can be issued w/o hydrogen sulfide measuresYes Expected pressure range is 0.442 to 0.492 psi/ft (8.5 to 9.5 ppg EMW). Operator's planned mud program36 Data presented on potential overpressure zonesNA appears sufficient to control anticipated pressures and maintain wellbore stability.37 Seismic analysis of shallow gas zonesNA Lost circulation and coal seams are potential hazards. Mitigation discussed on pages 11, 14, and 24.38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate9/17/2024ApprBJMDate9/17/2024ApprSFDDate9/17/2024AdministrationEngineeringGeologyGeologic Commissioner:GC:Date:Engineering Commissioner:JLCDatePublic CommissionerDateNOTE: Predecessor well PCU 2 (API 50-283-20022-90-00, PTD 179-009) is the same well as Theodore River 1 (50-283-20022-00-00, PTD 169-015). Revised PTD required: While MAD-pass logging the original PCU-02A well bore the rig inadvertently sidetracked at roughly 2750’ and drilled to 4316’ before there was a noticeable change in drilling parameters. Operator elected to drill on to near the original target location. BHL will be >500' from that originally permitted, requiring a revised PTD application.JLC 9/18/2024 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: Pretty Creek Unit, Undefined Gas Pool, PCU-02A Hilcorp Alaska, LLC Permit to Drill Number: 224-110 Surface Location: 1608' FNL, 2128' FEL, Sec 33, T14N, R9W, SM, AK Bottomhole Location: 1149' FSL, 1389' FEL, Sec 28, T14N, R9W, SM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. 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, Jessie L. Chmielowski Commissioner DATED this 21st day of August 2024. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.21 11:47:33 -08'00' 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 6,000' TVD: 4,615' 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): 100.5' 15. Distance to Nearest Well Open Surface: x-342548 y- 2654865 Zone-.4 82' to Same Pool: 5540' to PCU-04 16. Deviated wells:Kickoff depth: 2,050 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 55 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 8-1/2" 4-1/2" 12.6# L-80 GBCD 4,150' 1,850' 1,850' 6,000' 4,615' Tieback 4-1/2" 12.6# L-80 GBCD 1,850' Surface Surface 1,850' 1,850' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD 339' 2,032' 8,550' 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: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: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 9/3/2024 4130' to nearest unit boundary Sean Mclaughlin sean.mclaughlin@hilcorp.com 907-223-6784 840 Cement Volume MD 600 sx 339' 2,032'13-3/8"1335 sx Drilling Manager Monty Myers 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):Perforation Depth MD (ft): 2,032' 2130 sx Plugged Conductor/Structural 20"339' Authorized Title: Authorized Signature: Authorized Name: Production Liner 8,550' Intermediate 12,025'12,025' LengthCasing ±2,990' Size Plugs (measured): (including stage data) L - 1430 ft3 / T - 205 ft3 Tieback Assy. 2,990'2,990' Effect. Depth MD (ft):Effect. Depth TVD (ft): 18. Casing Program:Top - Setting Depth - BottomSpecifications 2271 GL / BF Elevation above MSL (ft): Total Depth MD (ft):Total Depth TVD (ft): 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1809 116' FNL, 1730' FEL, Sec 33, T14N, R9W, SM, AK 1149' FSL, 1389' FEL, Sec 28, T14N, R9W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 1608' FNL, 2128' FEL, Sec 33, T14N, R9W, SM, AK ADL 390780 PCU-02A Pretty Creek Unit Undefined Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. Plugged 8,550'9-5/8" s N ype of W L l R L 1b S Class: os N s No s N o D s s sD 84 o well is p G S S 20 S S S s No s No S G y E S s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) Drilling Manager 08/07/24 Monty M Myers By Grace Christianson at 10:36 am, Aug 07, 2024 224-110 BJM 8/20/24 DSR-8/12/24SFD 8/20/2024 Submit FIT/LOT results within 48 hrs of performing test. 50-283-20022-01-00 BOP test to 2500 psi *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.21 11:47:49 -08'00' 08/21/24 08/21/24 RBDMS JSB 082224 PC-02A Drilling Program Pretty Creek Unit Sean McLaughlin PTD August 02, 2024 Contents 1. Well Summary.....................................................................................................................................2 2. Management of Change Information................................................................................................3 3. Tubular Program................................................................................................................................4 4. Drill Pipe Information........................................................................................................................4 5. Internal Reporting Requirements.....................................................................................................5 6. Current Wellbore Schematic (Planned post RWO).........................................................................6 7. Planned Wellbore Schematic.............................................................................................................7 8. Drilling Summary...............................................................................................................................8 9. Mandatory Regulatory Compliance / Notifications.........................................................................9 10. R/U and Preparatory Work.............................................................................................................10 11. BOP N/U and Test.............................................................................................................................11 12. Set Whipstock / Mill Window..........................................................................................................12 13. Drill 8-1/2” Hole Section...................................................................................................................14 14. Run 4-1/2” Production Liner...........................................................................................................15 15. Cement 4-1/2” Production Liner.....................................................................................................17 16. Wellbore Clean Up & Displacement...............................................................................................20 17. 4-1/2” Liner Tieback Polish Run.....................................................................................................21 18. Run Completion Assembly...............................................................................................................21 19. BOP Schematic..................................................................................................................................22 20. Wellhead Schematic..........................................................................................................................23 21. Anticipated Drilling Hazards...........................................................................................................24 22. FIT Procedure...................................................................................................................................25 23. Choke Manifold Schematic..............................................................................................................26 24. Casing Design Information ..............................................................................................................27 25. 8-1/2” Hole Section MASP...............................................................................................................28 26. Plot (NAD 27) (Governmental Sections).........................................................................................29 Page 2 August 02, 2024 PC-02A Drilling Program APD xxx-xxx 1. Well Summary New Well PCU-02A Drilling Rig Rig 147 Pad Pretty Creek Pad Directional plan wp08 Old Well Designation PC-02 Planned Completion Type 4-1/2” 12.6# Liner, 4-1/2” Tie back Target Reservoir(s)Sterling/Beluga Kick off point 2050’ MD / 2050’ Planned Well TD, MD / TVD 6000’ MD / 4616’ TVD PBTD, MD 5900’ MD MASP 1809 psi AFE Number AFE Days 21 days AFE Drilling Amount Work String(s)4-1/2” 16.6# S-135 CDS-40 RKB – AMSL 100.5’ MSL to ML 82.0’ Page 3 August 02, 2024 PC-02A Drilling Program APD xxx-xxx 2. Management of Change Information Date: Subject: Changes to Approved Permit to Drill File #: PCU-02A Drilling Program Significant modifications to Drilling Program for PTD will be documented and approved below. Changes to an approved PTD will be communicated and approved by the AOGCC prior to continuing forward with work. Sec Page Date Procedure Change Approval: Drilling Manager Date Prepared: Engineer Date Page 4 August 02, 2024 PC-02A Drilling Program APD xxx-xxx 3. Tubular Program Hole Section OD (in)ID (in)Drift (in) Conn OD (in) Wt (#/ft)Grade Conn Burst (psi) Collap se (psi) Tension (k-lbs) 8-1/2”4-1/2”3.958”3.833”5.0”12.6#L-80 GBCD 8430 7500 288 ** Minimum of 100’ overlap required between casing strings 4. 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 Page 5 August 02, 2024 PC-02A Drilling Program APD xxx-xxx 5. Internal Reporting Requirements 1. Fill out daily drilling report and cost report. x Report covers operations from 6am to 6am x Ensure time entry adds up to 24 hours total. x Capture any out-of-scope work as NPT. This helps later when aggregating end of well reports. 2. Afternoon Updates x Submit a short operations update every day to kenaiciodrilling@hilcorp.com 3. EHS Incident Reporting x Notify EHS field coordinator. i. 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!!!! 1. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753 2. Leonard Dickerson: O: (907) 777-8317 C: (907) 252-7855 ii. Spills: x Notify Drlg Manager i. Monty M Myers: O: 907-777-8431 C: 907-538-1168 x Submit Hilcorp Incident report to contacts above within 24 hrs 4. Casing Tally x Send final “As-Run” Casing tally to sean.mclaughlin@hilcorp.com and cdinger@hilcorp.com 5. Casing and Cmt report x Send casing and cement report for each string of casing to sean.mclaughlin@hilcorp.com and cdinger@hilcorp.com Page 6 August 02, 2024 PC-02A Drilling Program APD xxx-xxx 6. Current Wellbore Schematic (Planned post RWO) Page 7 August 02, 2024 PC-02A Drilling Program APD xxx-xxx 7. Planned Wellbore Schematic Page 8 August 02, 2024 PC-02A Drilling Program APD xxx-xxx 8. Drilling Summary PCU-02A is a 6000’ MD / 4616’ TVD development gas sidetrack drilled from Pretty Creek Pad. The base plan is a northern step out well to the Sterling/Beluga formation. The well will be completed with a 4-1/2” tie-back completion. Drilling operations is expected to commence approximately September 2024. General sequence of operations pertaining to this drilling operation: Pre-Rig Scope: Test Casing, Decomplete, Plug PC-02 Rig Work 1. Rig 147 will MIRU over PC-02 2. NU BOPE and test to 2500 psi. (MASP 1809psi) 3. Set 9-5/8” whipstock at 2050’ and 20R. Swap well to 9.2 ppg mud. x Gyro required for WS set 4. Mill window with 20’ of new formation. 5. Perform FIT to 13.0 ppg EMW 6. MU 8-1/2” bit with 6-3/4” tools (Triple Combo MAD pass) 7. Drill 8-1/2” production hole to 6000 MD, performing short trips as needed x Consider picking up LWD tools and MAD pass after TD of interval 8. RIH w/ 4-1/2” liner. Set liner and cement. Circ wellbore clean. 9. Perform Clean out run to polish bore, LDDP 10. Perform liner lap test to 2500 psi. 11. Run 4-1/2” tie back completion. 12. Land hanger and test.MIT-T to 2500 psi, MIT-IA to 2500 psi 13. ND BOPE, NU tree and test void Reservoir Evaluation Plan: 1. Mud logging 2. Production Hole: Triple Combo LWD (consider MAD pass after drilling) Page 9 August 02, 2024 PC-02A Drilling Program APD xxx-xxx 9. Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that 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. Ensure to provide AOGCC 48 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/2500 psi & subsequent tests of the BOP equipment will be to 250/2500 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. o The highest reservoir pressure expected is 2271 psi in the Beluga F sand (4616' TVD). MASP is 1809 psi with 0.1psi/ft gas in the wellbore. o A casing test to 2500 is planned as part of the prerig work x Rated Working Pressure (RWP) the BOPE and wellhead must meet or exceed:3000 psi. x If the BOP is used to shut in on the well in a well control situation,ALL BOP components utilized for well control must be tested prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: None Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 8-1/2” x 11” x 5M Annular BOP x 11” x 5M Double Ram o Blind ram in btm cavity x Mud cross x 11” x 5M Single Ram x 3-1/8” 5M Choke Line x 2-1/16” x 5M Kill line x 3-1/8” x 2-1/16” 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/2500 (Annular 2500 psi) Subsequent Tests: 250/2500 (Annular 2500 psi) x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). Page 10 August 02, 2024 PC-02A Drilling Program APD xxx-xxx 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 48 hours notice prior to full BOPE test. x Any other notifications required in APD conditions of approval. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / (C): 907-250-9193 / Email:bryan.mclellan@alaska.gov Melvin Rixse / Petroleum Engineer / (O): 907-793-1231 / Email:melvin.rixse@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) 10. R/U and Preparatory Work 1. Proposed rig orientation Page 11 August 02, 2024 PC-02A Drilling Program APD xxx-xxx 2. 8-1/2” hole section mud program summary: Weighting material to be used for the hole section will be barite, 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. Ensure fluids are topped off and adequate lost circulation material is on location in anticipation of losses in hole section. System Type:9.2 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 2050’- 6000’9.0 – 10.0 40-53 15-25 15-25 8.5-9.5 11.0 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) 11. BOP N/U and Test 1. N/D Tree and adapter (BPV installed as part of pre-rig work), Install blanking plug 2. N/U to 11” 5M tubing spool 3. N/U 11” x 5M BOP as follows: Page 12 August 02, 2024 PC-02A Drilling Program APD xxx-xxx x BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram /11” x 5M mud cross/11” x 5M single ram x Double ram should be dressed with 2-7/8” x 5” variable bore rams in top cavity, blind ram in btm cavity. x Single ram should be dressed with 2-7/8” x 5” variable bore rams x N/U bell nipple, install flowline. x Install (2) manual valves & a check 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. x 11” 5M adapter required 4. Run BOPE test plug. 5. Test BOPE. x Test BOP to 250/2500 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. x Ensure to leave “A” section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. Confirm the correct valves are opened. x Test VBRs on a 4-1/2” a test joint (2500 psi test) x Test Annular on 4-1/2” test joint (2500 psi) x Ensure gas monitors are calibrated and tested in conjunction w/ BOPE. 6. Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section. 7. Pull test plug. 12. Set Whipstock / Mill Window Operation Steps: 1. Set wear bushing in wellhead. Ensure ID of wear bushing > 8-1/2”. 2. Make up the WIS Mechanical set Whipstock and RU to run GYRO 3. TIH with DP to the whipstock setting depth. Exercise caution when RIH / setting slips with whipstock assembly ¾Fill the drill pipe a minimum of every 20 stands on the trip in the hole with the whipstock assembly. ¾Avoid sudden starts and stops while running the whipstock. ¾Recommend running in the hole at a maximum of 90-120 seconds per stand taking care not to spud or catch the slips. Ensure running string is stationary prior to insertion of the slips and that slips are removed slowly when releasing the work string to RIH. These precautions are required to avoid any weakening of the whipstock shear mechanisms and / or to avoid part / preset on the packer. Page 13 August 02, 2024 PC-02A Drilling Program APD xxx-xxx 4. Run GYRO to obtain tray face. Orient whipstock as directed by the directional driller. The directional plan specifies 20 deg ROHS. 5. Set the top of the whipstock at ~2,050’ MD (confirm depth after RWO) x 9-5/8” Collars at 2025’ and 2060’ x Ref log: PCU-02 SCH CBL 09-JUN-1969 (TOC behind 9-5/8” ~1500’) x 9-5/8” CIBP w/ 25’ cmt (planned TOC – 2700’) 6. Mill window plus 20’-50’ of new hole (DO NOT EXCEED 50’ OF NEW HOLE BEFORE RUNNING THE PLANNED FIT/LOT). ¾Use ditch magnets to collect the metal shavings. Clean regularly. ¾Ensure any personnel working around metal shavings wear proper PPE, including goggles, face shield and Kevlar gloves. ¾Work the upper mill through the window to confirm the window milling is complete and circulate well clean (circulate a minimum of 1-1/2 bottoms up). Pump a high-vis super sweep to remove metal shavings and make every effort to remove all of the super sweep pill from the mud system as it is circulated to surface. 7. Pull starter mill into casing above top of whipstock, flow check the well for 10 minutes and conduct a FIT to 13.0 ppg. ¾**Assuming the kick zone is at TD, a FIT of 12.0 ppg EMW gives a Kick Tolerance volume of 50 bbls with 10.0 ppg mud weight. ¾Monitor OA during FIT and report and change in pressure. 8. POOH and LD milling assembly ¾Once out of the hole, inspect mill gauge and record. ¾Flow check well for 10 minutes to confirm no flow: ¾Before pulling off bottom. ¾Before pulling the BHA through the BOPE. 9. Flush the stack/lines to remove metal debris that may have settled out in these areas. Ensure BOP equipment is operable. Page 14 August 02, 2024 PC-02A Drilling Program APD xxx-xxx 13. Drill 8-1/2” Hole Section 1. P/U 6-3/4” Sperry Sun motor drilling assy w/ GR only x Triple combo tools (DEN, POR, RES) will be run after TD. 2. Ensure BHA Components have been inspected previously. 3. Drift & caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 4. Ensure TF offset is measured accurately and entered correctly into the MWD software. 5. Have DD run hydraulics models to ensure optimum TFA. Plan to pump at 400-500 gpm. 6. Production section will be drilled with a motor. Must keep up with 5 deg/100 DLS in the build section of the wellbore. 7. TIH to window. Shallow test MWD on trip in. 8. Circulate well with 9.2 ppg mud to warm up mud until good 9.2 ppg in and out. 9. Drill 8-1/2” hole to 6000’ MD using motor assembly. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled.A significant coal (50’ TVD) is expected ~3264’ TVD. x Keep swab and surge pressures low when tripping. x Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. 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. x Minimize backreaming when working tight hole x Planned weight up to 10.0 ppg prior to drilling into the Beluga D5 at 3953’ TVD Page 15 August 02, 2024 PC-02A Drilling Program APD xxx-xxx 10. At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement calculations. CBU. 11. TOH with drilling assembly, handle BHA as appropriate. PU Tripple Combo Logging tools and MAD pass per Geo Team. 12. POOH LDDP and BHA 13. Confirm 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 4-1/2” test joint. 14. Run 4-1/2” Production Liner 1. R/U Parker 4-1/2” liner running equipment. x Ensure DP crossover on rig floor and M/U to FOSV. x R/U fill up line to fill liner while running. x Ensure all liner has been drifted and tally verified 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. 2. P/U shoe joint, visually verify no debris inside joint. 3. Continue M/U & thread locking shoe track assy consisting of: Planned MWs Formation Top TVD max PPG Planned MW Sterling X2/X3 3264 8.8 9.20 Sterling B3 3702 8.8 9.20 Sterling C1 3734 8.8 9.20 Sterling C2 3786 8.8 9.20 Sterling C4 3837 8.8 9.20 Sterling C5 3873 8.8 9.20 Beluga D5 3953 9.4 10.00 Beluga D6 3979 9.5 10.00 Beluga E 4016 9.5 10.00 TD in Beluga F 4616 9.5 10.00 Page 16 August 02, 2024 PC-02A Drilling Program APD xxx-xxx x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). Centralizer 10’ from the bottom with stop ring x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x Landing collar pup bucked up. No centralizer x Centralizers will be run on 4-1/2” liner every joint. x Ensure proper operation of float shoe & FC. 4. Continue running 4-1/2” production liner to TD x Short joint and RA tag run every 1000’. x Fill liner while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Utilize a collar clamp until weight is sufficient to keep slips set properly. 5.Ensure to run enough liner to provide at least 100’ overlap inside casing. Ensure setting sleeve will not be set in a connection. Page 17 August 02, 2024 PC-02A Drilling Program APD xxx-xxx 6. Before picking up Baker ZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 7. M/U Baker ZXP liner top packer. Fill liner tieback sleeve with “XANPLEX”, ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 8. RIH one stand and circulate a minimum of one liner volume. Note weight of liner. 9. RIH w/ liner on DP no faster than 1 min / stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 10. M/U top drive and fill pipe while lowering string every 10 stands. 11. Set slowly in and pull slowly out of slips. 12. Circulate 1-1/2 drill pipe and liner volume at the 9-5/8” window prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure. 13. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 14. Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill casing. 15. P/U the cmt stand and tag bottom with the liner shoe. P/U 2’ off bottom. Note slack-off and pick-up weights. Record rotating torque values at 10, 20, & 30 rpm. 16. Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting pressure. Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling fluid by adding water and thinners. 17. Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. 15. Cement 4-1/2” Production Liner 1. Hold a pre-job safety meeting over the upcoming cmt operations. 2. Attempt to reciprocate the casing during cmt operations until hole gets sticky. 3. Pump 5 bbls 12.5 ppg spacer. 4. Test surface cmt lines to 4500 psi. 5. Pump remaining 12.5 ppg spacer. Page 18 August 02, 2024 PC-02A Drilling Program APD xxx-xxx 6. Mix and pump cement per below recipe and volume below with xx lbs/bbl of loss circulation fiber. Please independently verify cement volume with actual inputs. Ensure cmt is pumped at designed weight. Job is designed to pump 40% OH excess but if wellbore conditions dictate otherwise decrease or increase excess volumes. Cement volume is designed to bring cement to TOL. 7. Displacement fluid will be CLEAN drilling mud. Please independently verify with actual inputs. Slurry Information: Cement Slurry Design: Lead Slurry (5500’ MD to 1850’ MD)Tail Slurry (6000’ to 5500’ 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 Verified cement calcs. -bjm Page 19 August 02, 2024 PC-02A Drilling Program APD xxx-xxx Additives Code Description Code Description Type I/II Cement Class A Type I/II Cement Class A Halad-344 Fluid Loss Halad-344 Fluid Loss HR-5 Retarder HR-5 Retarder D-Air 5000 Anti Foam CFR-3 Dispersant Econolite Light-weight add.FDP-C1446-21 Slurry Conditioner SA-1015 Suspension Agent BridgeMaker II Lost Circulation 8. Drop DP dart and displace with KWF. 9. Pump cement at max rate of 5 bbl/min. Reduce pump rate to 3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re-zeroed at this point 10. If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. Reduce pump rate as required to avoid packoff. 11. Bump the plug. Do not overdisplace by more than 2 bbls. 12. Pressure up to 4200 psi to release the running tool (HRD-E) from the liner 13. Bleed pressure to zero to check float equipment. 14. P/U, verify setting tool is released. 15. Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 16. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 17. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re-tag the liner top, and circulate the well clean. 18. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 19. POOH, LDDP. Page 20 August 02, 2024 PC-02A Drilling Program APD xxx-xxx Backup release from liner running tool: 20. If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 21. NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down to the setting tool. 22. After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. Ensure to report the following on Wellview: 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 liner 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 Note: Send Csg & cmt report + “As-Run” liner tally to sean.mclaughlin@hilcorp.com 16. Wellbore Clean Up & Displacement 1. No cleanout planned. Service coil will cleanout, displace mud, and blow down well with N2 prior to perforating. 2. Test liner lap to 2500 psi after cement has reached 500 psi compressive strength. 10 min operational assurance test. Page 21 August 02, 2024 PC-02A Drilling Program APD xxx-xxx 17. 4-1/2” Liner Tieback Polish Run 1. PU liner tieback polish mill assy per BOT rep and RIH on drillpipe. 2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per BOT procedure. 3. POOH, and LDDP and polish mill. 18. Run Completion Assembly 1. Run 4-1/2” tubing completion assembly to above the liner top x Tubing will be 4-1/2” L-80 12.6# GBCD x No GLM, CIM, or SSSV required 2. Swap the well over to CI Water 3. Space out and land seal bore in tie back sleeve. RILDs. 4.Test IA to 2500 psi and tubing to 2500 psi. Charted 30 min. 5. Install BPV in wellhead. 6. ND BOPE, NU tree, test void 7. Rig Down Page 22 August 02, 2024 PC-02A Drilling Program APD xxx-xxx 19. BOP Schematic Page 23 August 02, 2024 PC-02A Drilling Program APD xxx-xxx 20. Wellhead Schematic Page 24 August 02, 2024 PC-02A Drilling Program APD xxx-xxx 21. Anticipated Drilling Hazards 8-1/2” 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. Anti Collision: None Page 25 August 02, 2024 PC-02A Drilling Program APD xxx-xxx 22. 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 plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. Add casing pressure test data to graph if recent and available. 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 26 August 02, 2024 PC-02A Drilling Program APD xxx-xxx 23. Choke Manifold Schematic Page 27 August 02, 2024 PC-02A Drilling Program APD xxx-xxx 24. Casing Design Information Page 28 August 02, 2024 PC-02A Drilling Program APD xxx-xxx 25. 8-1/2” Hole Section MASP Page 29 August 02, 2024 PC-02A Drilling Program APD xxx-xxx 26. Plot (NAD 27) (Governmental Sections) !! " #$ % & '(()*$+( 82511001375165019252200247527503025330035753850412544004675True Vertical Depth (550 usft/in)-550 -275 0 275 550 825 1100 1375 1650 1925 2200 2475 2750 3025 3300 3575 3850 4125 4400 4675Vertical Section at 14.90° (550 usft/in)10001500200025003000350040004500PRETTY CK UNIT 213-3/8" x 17-1/2"9 5/8" KOP4-1/2" x 8-1/2"100015002000250030003500400045005000550060006000PCU-2A wp08KOP 12.3º/100' : 2050' MD, 2049.93'TVD : 20.33° RT TFEnd Dir : 2067' MD, 2066.92' TVDStart Dir 5º/100' : 2087' MD, 2086.9'TVDEnd Dir : 3130.87' MD, 2969.47' TVDTotal Depth : 6000' MD, 4615.14' TVDPossible FaultSterling X2/X3 - 50' TVD gross coalSterling B3Sterling C1Sterling C2Sterling C4Sterling C5Beluga D5Beluga D6Beluga EBeluga FHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: PRETTY CK UNIT 2Ground Level: 82.00+N/-S +E/-W Northing EastingLatitudeLongitude0.00 0.00 2654865.58 342548.83 61° 15' 48.7466 N 150° 53' 40.0335 WSURVEY PROGRAMDate: 2024-07-22T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool64.50 2050.00 PRETTY CK UNIT 1 (PRETTY CK UNIT 2) 3_INC-Only2050.00 2450.00 PCU-2A wp08 (PCU-2A) 3_MWD_Interp Azi+Sag2450.00 6000.00 PCU-2A wp08 (PCU-2A) 3_MWD+AX+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation3209.88 3109.38 3550.00 Possible Fault3264.00 3163.50 3644.36 Sterling X2/X3 - 50' TVD gross coal3702.00 3601.50 4407.99 Sterling B33734.00 3633.50 4463.78 Sterling C13786.00 3685.50 4554.44 Sterling C23837.00 3736.50 4643.36 Sterling C43873.00 3772.50 4706.12 Sterling C53953.00 3852.50 4845.60 Beluga D53979.00 3878.50 4890.93 Beluga D64016.00 3915.50 4955.43 Beluga E4615.14 4514.64 6000.00 Beluga FREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well PRETTY CK UNIT 2, True NorthVertical (TVD) Reference:RBK Permit @ 100.50usft (HEC 147)Measured Depth Reference:RBK Permit @ 100.50usft (HEC 147)Calculation Method: Minimum CurvatureProject:Beluga River NorthSite:Pretty CreekWell:PRETTY CK UNIT 2Wellbore:PCU-2ADesign:PCU-2A wp08CASING DETAILSTVD TVDSS MD Size Name2049.93 1949.43 2050.00 9-5/8 9 5/8" KOP4615.14 4514.64 6000.00 4-1/2 4-1/2" x 8-1/2"SECTION DETAILSSecMD Inc Azi TVD +N/-S +E/-W Dleg TFace VSectTargetAnnotation1 2050.00 0.75 360.00 2049.93 15.15 0.00 0.00 0.00 14.64 KOP 12.3º/100' : 2050' MD, 2049.93'TVD : 20.33° RT TF2 2067.00 2.81 15.01 2066.92 15.66 0.11 12.30 20.33 15.16 End Dir : 2067' MD, 2066.92' TVD3 2087.00 2.81 15.01 2086.90 16.61 0.36 0.00 0.00 16.14 Start Dir 5º/100' : 2087' MD, 2086.9'TVD4 3130.87 55.00 15.00 2969.47 487.27 126.48 5.00 -0.01 503.41 End Dir : 3130.87' MD, 2969.47' TVD5 6000.00 55.00 15.00 4615.14 2757.45 734.77 0.00 0.00 2853.66 Total Depth : 6000' MD, 4615.14' TVD 0 150 300 450 600 750 900 1050 1200 1350 1500 1650 1800 1950 2100 2250 2400 2550 2700 South(-)/North(+) (300 usft/in)-1200 -1050 -900 -750 -600 -450 -300 -150 0 150 300 450 600 750 900 West(-)/East(+) (300 usft/in) PRETTY CK UNIT 2 9 5/8" KOP 4-1/2" x 8-1/2" 250500750100012501500175020002250 2500 2750 3000 3250 3500 3750 4000 4250 4500 4615 PCU-2A wp08 KOP 12.3º/100' : 2050' MD, 2049.93'TVD : 20.33° RT TF End Dir : 2067' MD, 2066.92' TVD Start Dir 5º/100' : 2087' MD, 2086.9'TVD End Dir : 3130.87' MD, 2969.47' TVD Total Depth : 6000' MD, 4615.14' TVD CASING DETAILS TVD TVDSS MD Size Name 2049.93 1949.43 2050.00 9-5/8 9 5/8" KOP 4615.14 4514.64 6000.00 4-1/2 4-1/2" x 8-1/2" Project: Beluga River North Site: Pretty Creek Well: PRETTY CK UNIT 2 Wellbore: PCU-2A Plan: PCU-2A wp08 WELL DETAILS: PRETTY CK UNIT 2 Ground Level: 82.00 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 2654865.58 342548.83 61° 15' 48.7466 N 150° 53' 40.0335 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well PRETTY CK UNIT 2, True North Vertical (TVD) Reference: RBK Permit @ 100.50usft (HEC 147) Measured Depth Reference:RBK Permit @ 100.50usft (HEC 147) Calculation Method:Minimum Curvature , - & ! . 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eparation Factor2250 2500 2750 3000 3250 3500 3750 4000 4250 4500 4750 5000 5250 5500 5750 6000 6250 6500 6750Measured Depth (500 usft/in)PRETTY CK UNIT 2No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS: PRETTY CK UNIT 2 NAD 1927 (NADCON CONUS) Alaska Zone 04Ground Level: 82.00+N/-S+E/-W NorthingEastingLatitude Longitude0.000.002654865.58 342548.8361° 15' 48.7466 N150° 53' 40.0335 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well PRETTY CK UNIT 2, True NorthVertical (TVD) Reference: RBK Permit @ 100.50usft (HEC 147)Measured Depth Reference:RBK Permit @ 100.50usft (HEC 147)Calculation Method:Minimum CurvatureCASING DETAILSTVD TVDSS MD Size Name2049.93 1949.43 2050.00 9-5/8 9 5/8" KOP4615.14 4514.64 6000.00 4-1/2 4-1/2" x 8-1/2"SURVEY PROGRAMDate: 2024-07-22T00:00:00 Validated: Yes Version: Depth FromDepth ToSurvey/PlanTool64.50 2050.00 PRETTY CK UNIT 1 (PRETTY CK UNIT 2) 3_INC-Only2050.00 2450.00 PCU-2A wp08 (PCU-2A) 3_MWD_Interp Azi+Sag2450.00 6000.00 PCU-2A wp08 (PCU-2A) 3_MWD+AX+Sag0.0040.0080.00120.00160.00200.00Centre to Centre Separation (80.00 usft/in)2250 2500 2750 3000 3250 3500 3750 4000 4250 4500 4750 5000 5250 5500 5750 6000 6250 6500 6750Measured Depth (500 usft/in)PRETTY CK UNIT 2GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference2050.00 To 6000.00Project: Beluga River NorthSite: Pretty CreekWell: PRETTY CK UNIT 2Wellbore: PCU-2APlan: PCU-2A wp08Ladder/S.F. Plots Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. 224-110 PRETTY CREEK UNDEFINED GAS PCU 02A WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:PRETTY CK UNIT 02AInitial Class/TypeDEV / PENDGeoArea820Unit11620On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2241100PRETTY CREEK, UNDEFINED GAS - 580500NA1 Permit fee attachedYes Entire Well lies within ADL0390780.2 Lease number appropriateYes3 Unique well name and numberNo PRETTY CREEK, UNDEFINED GAS - 580500 - governed by Statewide Regs4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 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)NA Sidetrack18 Conductor string providedNA Sidetrack19 Surface casing protects all known USDWsNA Sidetrack20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitYes25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedNA27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 1809 psi, BOP rated to 5000 psi (BOP test to 2500 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 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: not expected; mitigation discussed; see p. 26.35 Permit can be issued w/o hydrogen sulfide measuresYes Expected pressure range is 0.442 to 0.492 psi/ft (8.5 to 9.5 ppg EMW). Operator's planned mud program36 Data presented on potential overpressure zonesNA appears sufficient to control anticipated pressures and maintain wellbore stability.37 Seismic analysis of shallow gas zonesNA Lost circulation and coal seams are potential hazards. Mitigation discussed on pages 11, 14, and 24.38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate8/20/2024ApprBJMDate8/20/2024ApprSFDDate8/20/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateNOTE: Predecessor well Pretty Creek Unit 2 (API 50-283-20022-90-00, PTD 179-009) is the same well as Theodore River 1 (50-283-20022-00-00, PTD 169-015).($8JLC 8/21/2024