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Home My WebLink About224-026Nolan 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: 2/4/2026 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20260204 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 223-34T 50283202060000 225059 12/31/2025 AK E-LINE Perf T41308 BRU 244-27 50283201850000 222038 1/2/2026 AK E-LINE Perf T41309 CLU 11RD 50133205590000 225013 1/2/2026 YELLOWJACKET SCBL T41310 CLU 11RD 50133205590000 225013 12/19/2025 YELLOWJACKET SCBL T41310 END 1-25A 50029217220100 197075 11/7/2025 HALLIBURTON COILFLAG T41311 END 1-25A 50029217220100 197075 12/26/2025 READ PressTempSurvey T41311 END 2-40 50029225270000 194152 12/18/2025 READ PressTempSurvey T41312 END 2-52 50029217500000 187092 12/24/2025 HALLIBURTON MFC40 T41313 END 2-56A 50029228630100 198058 1/1/2026 HALLIBURTON COILFLAG T41314 END 2-56A 50029228630100 198058 1/19/2026 READ CaliperSurvey T41314 KALOTSA 3 50133206610000 217028 1/14/2026 YELLOWJACKET PERF T41315 KALOTSA 3 50133206610000 217028 1/9/2026 YELLOWJACKET PERF T41315 KALOTSA 8 50133207050000 222003 12/18/2025 YELLOWJACKET PERF T41316 KBU 44-06 50133204980000 200179 12/22/2026 YELLOWJACKET CBL T41317 KBU 44-06 50133204980000 200179 11/12/2025 YELLOWJACKET PLUG T41317 KU 24-07RD 50133203520100 205099 1/6/2026 AK E-LINE CBL T41318 KU 24-07RD 50133203520100 205099 1/6/2026 AK E-LINE Plug/Cement T41318 KU 24-07RD 50133203520100 205099 1/1/2026 AK E-LINE Plug/Cement/TubingPunch T41318 MPI-36 50029236770000 220047 1/19/2026 READ CaliperSurvey T41319 MPI-36 50029236770000 220047 1/19/2026 READ LeakDetectLog T41319 NCIU A-19 50883201940000 224026 1/7/2025 AK E-LINE Perf T41320 NFU 42-35 50231200460000 214170 1/8/2026 YELLOWJACKET PERF T41321 NIK OI24-08 50029234570000 211130 1/19/2026 HALLIBURTON COILFLAG T41322 ODSN-04 50703206700000 213037 1/20/2026 HALLIBURTON LDL T41323 ODSN-22 50703207080000 215054 12/20/2025 READ LeakDetection T41324 PBU 15-11D 50029206530400 225112 1/18/2026 HALLIBURTON RBT-COILFLAG T41325 PBU 15-43 50029226760000 196083 12/21/2025 HALLIBURTON RBT T41326 PBU B-30B 50029215420200 225009 1/24/2026 HALLIBURTON RBT-COILFLAG T41327 PBU C-33B 50029223730200 225096 12/16/2025 HALLIBURTON RBT-COILFLAG T41328 NCIU A-19 50883201940000 224026 1/7/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.02.05 09:10:43 -09'00' 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: PBU D-26B 50029215300200 206098 12/20/2025 HALLIBURTON ISAT T41329 PBU D-26B 50029215300200 206098 12/19/2025 BAKER SPN T41329 PBU F-21A 50029219490100 225019 1/18/2026 HALLIBURTON RBT-COILFLAG T41330 PBU J-21A 50029217050100 225106 1/21/2026 HALLIBURTON RBT-COILFLAG T41331 PBU L-291 50029237790000 224002 12/26/2025 HALLIBURTON RBT T41332 PBU L-291 50029237790000 224002 12/9/2025 YELLOWJACKET RCBL T41332 PBU S-107A 50029220440200 225083 12/8/2025 HALLIBURTON RBT-COILFLAG T41333 PBU S-201A 50029229870100 219092 1/21/2026 HALLIBURTON WFL-TMD3D T41335 PBU S-24B 50029220440200 203163 12/22/2025 HALLIBURTON RBT T41334 PBU S-24B 50029230230100 203163 12/23/2025 HALLIBURTON WFL-TMD3D T41334 SRU 223-15 50133207410000 225123 1/29/2026 YELLOWJACKET GPT-PERF T41336 SRU 223-15 50133207410000 225123 1/20/2026 YELLOWJACKET SCBL T41336 SRU 233-10 50133207400000 225113 12/30/2026 AK E-LINE CBL T41337 SRU 233-10 50133207400000 225113 1/10/2026 YELLOWJACKET SCBL T41337 SRU 233-10 50133207400000 225113 1/6/2026 YELLOWJACKET SCBL T41337 SRU 34-28 50133101580000 163007 1/7/2026 YELLOWJACKET Gamma Ray T41338 SU 32-16 50133207380000 225095 1/17/2026 YELLOWJACKET GPT-PLUG-PERF T41339 SU 32-16 50133207380000 225095 11/22/2025 YELLOWJACKET SCBL T41339 SU 43-10 50133207390000 225107 12/10/2025 YELLOWJACKET SCBL T41340 TBU A-12RD 50883200320100 171029 1/2/2026 AK E-LINE StripGun T41341 TBU D-24A 50733202240100 174064 12/4/2025 AK E-LINE TubingPunch T41342 Please include current contact information if different from above. Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.02.05 09:11:00 -09'00' 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: 1/21/2026 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20260121 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 16RD 50133205540100 207125 12/3/2025 AK E-LINE PPROF T41253 BRU 211-35 50283201890000 223050 11/7/2025 AK E-LINE Perf T41254 BRU 213-26 50283201920000 223069 11/23/2025 AK E-LINE Perf T41255 BRU 213-26T 50283202040000 225038 11/4/2025 AK E-LINE Perf T41256 BRU 241-34S 50283201980000 224077 11/9/2025 AK E-LINE Perf T41257 BRU 241-34T 50283201810000 220052 11/6/2025 AK E-LINE Perf T41258 BRU 244-27 50283201850000 222038 12/13/2025 AK E-LINE Perf T41259 BRU 244-27 50283201850000 222038 12/19/2025 AK E-LINE StripGun T41259 GP ST 17586 9 50733204480000 193062 11/13/2025 AK E-LINE Perf T41260 IRU 241-01 50283201840000 221076 12/21/2025 AK E-LINE Perf T41261 IRU 241-01 50283201840000 221076 12/30/2025 AK E-LINE Perf T41261 IRU 241-01 50283201840000 221076 12/16/2025 AK E-LINE Plug T41261 IRU 241-01 50283201840000 221076 11/26/2025 AK E-LINE Plug/Perf T41261 KALOTSA 01 50133206570000 216132 11/19/2025 AK E-LINE Perf T41262 KBU 31-18 50133206490000 215024 11/8/2025 AK E-LINE Drift/PPROF T41263 KU 12-17 50133205770000 208089 11/14/2025 AK E-LINE StimGun T41264 LRU C-01RD 50283200610100 201168 11/27/2025 AK E-LINE RCT/Perf T41265 MPI 2-32 50029220840000 190119 12/10/2025 AK E-LINE LDL T41266 MPI 2-38 50029220900000 190129 12/5/2025 AK E-LINE LDL T41267 MPU H-16 50029232270000 204190 12/3/2025 AK E-LINE CBL T41268 MPU H-16 50029232270000 204190 11/19/2025 AK E-LINE TubingCut T41268 MPU I-14 50029232140000 204119 11/13/2025 AK E-LINE CBL T41269 NCIU A-06A 50883200260100 225071 11/28/2025 AK E-LINE Perf/Plug T41270 NCIU A-08 50883200280000 169063 12/2/2025 AK E-LINE GPT T41271 NCIU A-19 50883201940000 224026 12/16/2025 AK E-LINE GPT T41272 NCIU A-19 50883201940000 224026 12/12/2025 AK E-LINE GPT/Perf/Plug T41272 NCIU A-19 50883201940000 224026 12/17/2025 AK E-LINE Perf T41272 NCIU A-21A 50883201990100 225075 12/30/2025 AK E-LINE PPROF T41273 OP19-T1N 50029234910000 213068 11/19/2025 AK E-LINE TubingPunch T41274 T41272NCIU A-19 50883201940000 224026 12/16/2025 AK E-LINE GPT T41272NCIU A-19 50883201940000 224026 12/12/2025 AK E-LINE GPT/Perf/Plug NCIU A-19 50883201940000 224026 12/17/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.01.21 13:56:35 -09'00' 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: PCU D-10 50283202080000 225082 12/9/2025 AK E-LINE Perf T41275 SCU 322C-04 50133101040100 215217 12/4/2025 AK E-LINE TubingPunch T41276 SRU 222-33 50133207150000 223100 12/7/2025 AK E-LINE Plug T41277 SU 43-10 50133207390000 225107 11/26/2025 AK E-LINE CBL T41278 TBU A-12RD 50733200760100 171029 11/29/2025 AK E-LINE Perf T41279 TBU D-24A 50733202240100 174064 12/2/2025 AK E-LINE TubingPunch T41280 TBU D-24A 50733202240100 174064 11/21/2025 AK E-LINE TubingPunch T41280 TBU M-10 50733205880000 209154 11/15/2025 AK E-LINE Perf T41281 Please include current contact information if different from above. Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.01.21 13:56:51 -09'00' 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:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:20251222 1000 APPROVAL PTD 224-026 NCIU A-19 Sundry Request 325-745 reperf request Date:Monday, December 22, 2025 2:37:58 PM From: Rixse, Melvin G (OGC) Sent: Monday, December 22, 2025 10:44 AM To: 'Dan Marlowe' <dmarlowe@hilcorp.com> Cc: Eric Dickerman <Eric.Dickerman@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com> Subject: RE: PTD 224-026 NCIU A-19 Sundry Request 325-745 reperf request Dan, Reperf of existing open perf intervals is approved. 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: Dan Marlowe <dmarlowe@hilcorp.com> Sent: Monday, December 22, 2025 10:34 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Eric Dickerman <Eric.Dickerman@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com> Subject: PTD 224-026 NCIU A-19 Sundry Request 325-745 reperf request Importance: High Mel, Following up on our phone call. We have cleaned the well out with coil and unloaded it with nitrogen but are seeing lower than expected rates. Today we will run a GPT log to help evaluate the open intervals. Hilcorp requests approval for selective reperfs based on what the log tells us. Regards, Dan Marlowe Hilcorp Alaska, LLC Area Operations Manager – Cook Inlet Offshore Office 907-283-1329 Cell 907-398-9904 Email DMarlowe@hilcorp.com Hilcorp A Company Built on Energy 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 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 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. 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): 8,824 See schematic Casing Collapse Structural Conductor 230psi Surface 4,750psi Intermediate Production Liner 7,500psi 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: Eric Dickerman Contact Email:Eric.Dickerman@hilcorp.com Contact Phone:(907) 564-4061 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 N Cook Inlet Tertiary System Gas Same 6,690 8,135 6,008 251psi See schematic Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY 8,430psi Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Operations Manager STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 / ADL0037831 224-026 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20194-00-00 Hilcorp Alaska, LLC N Cook Inlet Unit A-19 Length Size Proposed Pools: L-80 TVD Burst 4,984 MD 1,630psi 6,870psi 384' 3,435' 384' 5,148' 30" 9-5/8" 384' 5,148' Perforation Depth MD (ft): 6,587 - 8,044 4-1/2" 4,498 - 5,918 Other: CO 68A 12/12/2025 8,824'3,878' 4-1/2" 6,690' LTP & Baker TE-5 4,946 (MD) 3,333 (TVD) & 505 (MD) 505 (TVD) No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2025.12.05 14:45:34 - 09'00' Dan Marlowe (1267) 325-745 By Grace Christianson at 7:56 am, Dec 08, 2025 * Service coil BOPE test to 3000 psi. 48 hour notice to AOGCC for opportunity to witness. * Wireline to dump bail 25' of cement above CIBP after setting the plug. * State to witness safety valve system performance test within 5 days of initial production. DSR-12/8/25A.Dewhurst 08DEC25 10-404 MGR09DEC25JLC 12/10/2025 12/10/25 NCIU A-19 Fill Clean Out, Bridge Plug, Add Perf Page 1 of 4 Well Name:NCIU A-19 API Number:50-883-20194-00-00 Current Status:Online Permit to Drill Number:224-026 Estimated Start Date:December 2025 Rig:Fox Coil Unit 9 Regulatory Contact:Juanita Lovett Estimated Duration:3 days First Call Engineer:Eric Dickerman Cell Number:307-250-4013 Second Call Engineer:Casey Morse Cell Number:603-205-3780 Current Bottom Hole Pressure:700 psi at 4,498 TVD. Nodal analysis from 9/22/24 flowing bottomhole pressure survey. MPSP:251 psi (Based on 0.1 psi/ft. gas gradient) Last Shut-in WHP:199 psi Min. ID:3.813 - 4-1/2 X nipple Max. Deviation:67 at 2,598 Pool:Tertiary Gas Pool, North Cook Inlet Field, no pool change during operation. Brief Well Summary: NCIU A-19 was drilled in August 2024 and completed in September 2024 in the Beluga formation. On 4/15/25, the well failed an SVS test with the subsurface safety valve failing to hold differential pressure. On 4/19/25 slickline brushed the subsurface safety valve and a subsequent in-house SVS test passed. However production failed to return to pre-SVS testing rates and then the production died of completely on 4/20/25. Slickline returned on 4/24/25 and worked through bridges at 1200 and 1750 before running into solid fill at 2100. A coiled tubing cleanout was successfully completed down to 7,935 on 4/30/25. The well was brought online post cleanout and again experienced fill problems in the tubing and flowline subsequently leading to the well getting shut in. Based on analog well performance and diagnostics, the intervals below the Beluga Gb are suspected to be the intervals producing solids.Recently NCIU A-06A, has successfully produced from intervals that were bypassed in NCIU A-19 because they were thought to be wet. Objective: Coiled tubing fill cleanout. Set a bridge plug to reduce fill potential.Add perforations. NCIU A-19 Fill Clean Out, Bridge Plug, Add Perf Page 2 of 4 Coiled Tubing: 1. MIRU Fox Energy offshore Coiled Tubing #9 and pressure control equipment on A-19, Leg #2. 2. Pressure test BOP and PCE to 250 psi low / 3,000 psi high. a. Provide AOGCC with 48 hr BOP test witness notification. 3. MU cleanout BHA. Dry tag top of fill, then begin cleaning out to tag at approximately 7,935. PUH 50 from tag and paint a flag on the pipe. a. Working fluid will be 6% KCl (8.6 ppg). b. Take returns to surface up the CT x tubing annulus. c. Add foam and nitrogen as necessary to carry solids to surface. 4. RIH with GR/CCL tools in a carrier and a drift nozzle. Log a correlation pass and flag pipe. 5. Set 4-1/2 bridge plug to shut off the Beluga Ka interval. Target bridge plug depth ±7,800. 6. RIH and blow well dry with nitrogen. 7. RDMO Coiled tubing unit. Eline: 8. MIRU Eline. 9. Pressure test PCE to 250 psi low / 3,000 psi high. 10. Perforate the following intervals. Sand Interval Perforation Top (MD) Perforation Bottom (MD) Perforation Interval Footage (ft.) Beluga_Gc 7371 7382 11 Beluga_Ha 7454 7467 13 Beluga_Hc 7483 7513 30 Beluga_Hd 7517 7523 6 Beluga_He 7543 7552 9 11. RDMO Eline, hand well over to production for flow test. CONTINGENCY Eline plug/patch: (if any zone makes unwanted solids or water) 12. RU Nitrogen to tubing and pressure test treating iron to 250 psi low / 3,000 psi high. 13. Pressure up on tubing to displace water back into formation. 14. MIRU Eline. 15. Pressure test PCE to 250 psi low / 3,000 psi high. 16. Set 4-1/2 CIBP or patch to shut off unwanted interval per Operations Engineer. 17. RDMO Eline and Nitrogen. Wireline to dump bail 25' of cement on top of CIBP. Target TOC ~7775' MD. - mgr Wireline to dump bail 25' of cement on top of CIBP. Target TOC ~7775' MD. - mgr NCIU A-19 Fill Clean Out, Bridge Plug, Add Perf Page 3 of 4 CONTINGENCY Coiled Tubing Cleanout: (if any zone brings in excessive fill and needs to be cleaned out) 18. MIRU Fox Offshore Coiled Tubing Unit #9 and pressure control equipment. 19. Pressure test BOP and PCE to 250 psi low / 3,000 psi high. a. Provide AOGCC with 48 hr witness notification for BOP test. 20. MU cleanout BHA. Dry tag top of fill, then begin cleaning out to target depth per Operations Engineer. b. Working fluid will be 6% KCl (8.6 ppg). c. Take returns to surface from the coiled tubing by 4-1/2 annulus. d. Add foam and nitrogen as necessary to carry solids to surface. 21. RIH and blow well dry with nitrogen. 22. RDMO CTU. Operations: COMPLETED 23. Perform SVS test within 5 days of bringing the well on production. a. Provide AOGCC with 48 hr witness notification. Attachments: 1. Correlation Log 2. Current Wellbore Schematic 3. Proposed Wellbore Schematic 4. CT BOP schematic (Fox Energy) 5. Standard nitrogen procedure NCIU A-19 Fill Clean Out, Bridge Plug, Add Perf Page 4 of 4 Correlation Log: _____________________________________________________________________________________ Updated By: JLL 05/05/25 SCHEMATIC North Cook Inlet Unit NCIU A-19 PTD: 224-026 API: 50-883-20194-00-00 Bel Oa - Bel QbL 1 2 3/4/5 PBTD = 8,135 / TVD = 6,008 TD = 8,824 / TVD = 6,690 Bel M Bel L Bel O Bel K Bel G Bel F Bel B Bel E Bel D Bel C Bel A RKB = 126.6' 30 12-1/4 hole 8-1/2 hole CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 30Conductor Driven to Set Depth - - Weld 29 Surf 384 9-5/8" Surf Csg 47 L-80 DWC/C 8.681 Surf 5,148 4-1/2" Prod Lnr 12.6 L-80 JFELion 3.958 4,946 8,824 4-1/2" Prod Tieback 12.6 L-80 DWC/C 3.958 Surf 4,984 JEWELRY DETAIL No.Depth (MD) Depth (TVD)Item 1 505 505' Baker TE-5 SSSV 2 1,023 1,018' ES Cementer 3 4,916 3,318' X nipple (GOT) 4 4,974 3,347' Seal Stem 5 4,946 3,333' Liner hanger / LTP Assembly 6 8,135' 6,008' CIBP (9/4/24) 6 8,365' 6,236' CIBP (9/2/24) OPEN HOLE / CEMENT DETAIL 9-5/8" TOC @ Surface Stg 1 332 bbls Stg 2 - 448 bbls 4-1/2 Est. TOC @ TOL (40% excess) L 237 bbls / T 37 bbls PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status Bel Au 6,587' 6,599' 4,498' 4,509' 12' 9/21/24 Open Bel Al 6,626' 6,638' 4,534' 4,546' 12' 9/21/24 Open Bel Ba 6,679' 6,683' 4,584' 4,588' 4' 9/21/24 Open Bel Bb 6,689' 6,699' 4,594' 4,603' 10' 9/21/24 Open Bel Bc 6,703' 6,709' 4,607' 4,613' 6' 9/21/24 Open Bel Bd 6,757' 6,767' 4,659' 4,669' 10' 9/21/24 Open Bel Ca 6,892' 6,896' 4,788' 4,792' 4' 9/21/24 Open Bel Cb 6,913' 6,917' 4,809' 4,812' 4' 9/21/24 Open Bel Cc 6,933' 6,939' 4,828' 4,834' 6' 9/21/24 Open Bel Da 7,007' 7,013' 4,899' 4,905' 6' 9/20/24 Open Bel Db 7,017' 7,021' 4,909' 4,913' 4' 9/20/24 Open Bel Dc 7,047' 7,053' 4,938' 4,943' 6' 9/20/24 Open Bel Ea 7,061' 7,067' 4,951' 4,957' 6' 9/20/24 Open Bel Eb 7,108' 7,116' 4,997' 5,004' 8' 9/20/24 Open Bel Ec 7,154' 7,158' 5,041' 5,041' 4' 9/20/24 Open Bel Ed 7,171' 7,175' 5,058' 5,062' 4' 9/18/24 Open Bel Ee 7,205' 7,210' 5,091' 5,096' 5' 9/18/24 Open Bel Fa 7,228' 7,232' 5,113' 5,117' 4' 09/15/24 Open Bel Fb 7,247' 7,253' 5,132' 5,138' 6' 09/15/24 Open Bel Fc 7,266' 7,270' 5,151' 5,154' 4' 09/15/24 Open Bel Fd 7,273' 7,280' 5,157' 5,164' 7' 09/15/24 Open Bel Fe 7,309' 7,313' 5,193' 5,197' 4' 09/13/24 Open Bel Ga 7,317' 7,323' 5,201' 5,206' 6' 09/13/24 Open Bel Gb 7,328' 7,332' 5,211' 5,215' 4' 09/13/24 Open Bel Ka 7,807' 7,817' 5,684' 5,694' 10' 09/05/24 Open Bel Kb 7,823' 7,835' 5,700' 5,711' 12' 09/05/24 Open Bel KcU 7,858' 7,864' 5,734' 5,740' 6' 09/06/24 Open Bel KcL 7,866' 7,876' 5,742' 5,752' 10' 09/06/24 Open Bel La 7,937' 7,947' 5,812' 5,822' 10' 09/04/24 Open Bel Lb 7,965' 7,971' 5,840' 5,846' 6' 08/30/24 Open Bel Lc 7,980' 7,990' 5,855' 5,865' 10' 08/30/24 Open Bel Ma 8,007' 8,010' 5,881' 5,884' 3' 08/30/24 Open Bel Mb 8,016' 8,022' 5,890' 5,896' 6' 09/06/24 Open Bel Mc 8,040' 8,044' 5,915' 5,918' 4' 09/06/24 Open Bel O 8,147' 8,153' 6,020' 6,026' 6' 09/04/24 Isolated Bel Qa 8,375' 8,381' 6,246' 6,252' 6' 09/02/24 Isolated Bel QbU 8,407' 8,413' 6,277' 6,283' 6' 09/02/24 Isolated Bel QbL 8,413' 8,433' 6,283' 6,303' 20' 09/02/24 Isolated GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 2,225 1,994' 3.833 GLM, 4.5" X 1.5'' FO-2 (BK)16 Dome 750 07/31/2024 2 4,852 3,288' 3.833 GLM, 4.5" X 1.5'' FO-2 (Gen 2 Mod) 24 Orifice 07/31/2024 FISH/OTHER DETAILS 7,988' 9/18/24 - Tag fish (Btm of BRT, guns & roller bogey) 8,029' 9/16/24 - Tag fish (Btm of BRT, guns & roller bogey) 6,819' GCBD with RA tag in collar 7,816' GCBD with RA tag in collar _____________________________________________________________________________________ Updated By: EPD 06/10/25 PROPOSED North Cook Inlet Unit NCIU A-19 PTD: 224-026 API: 50-883-20194-00-00 Bel Oa - Bel QbL 6 7 8 1 2 3/4/5 Bel H PBTD = 8,135 / TVD = 6,008 TD = 8,824 / TVD = 6,690 Bel M Bel L Bel O Bel K Bel G Bel F Bel B Bel E Bel D Bel C Bel A RKB = 126.6' 30 12-1/4 hole 8-1/2 hole CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 30Conductor Driven to Set Depth - - Weld 29 Surf 384 9-5/8" Surf Csg 47 L-80 DWC/C 8.681 Surf 5,148 4-1/2" Prod Lnr 12.6 L-80 JFELion 3.958 4,946 8,824 4-1/2" Prod Tieback 12.6 L-80 DWC/C 3.958 Surf 4,984 JEWELRY DETAIL No. Depth (MD) Depth (TVD) Item 1 505 505' Baker TE-5 SSSV 2 1,023 1,018' ES Cementer 3 4,916 3,318' X nipple (GOT) 4 4,974 3,347' Seal Stem 5 4,946 3,333' Liner hanger / LTP Assembly 6 ± 7,800 ± 5,677 Bridge Plug 7 8,135' 6,008' CIBP (9/4/24) 8 8,365' 6,236' CIBP (9/2/24) OPEN HOLE / CEMENT DETAIL 9-5/8" TOC @ Surface Stg 1 332 bbls Stg 2 - 448 bbls 4-1/2 Est. TOC @ TOL (40% excess) L 237 bbls / T 37 bbls PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status Bel Au 6,587' 6,599' 4,498' 4,509' 12' 9/21/24 Open Bel Al 6,626' 6,638' 4,534' 4,546' 12' 9/21/24 Open Bel Ba 6,679' 6,683' 4,584' 4,588' 4' 9/21/24 Open Bel Bb 6,689' 6,699' 4,594' 4,603' 10' 9/21/24 Open Bel Bc 6,703' 6,709' 4,607' 4,613' 6' 9/21/24 Open Bel Bd 6,757' 6,767' 4,659' 4,669' 10' 9/21/24 Open Bel Ca 6,892' 6,896' 4,788' 4,792' 4' 9/21/24 Open Bel Cb 6,913' 6,917' 4,809' 4,812' 4' 9/21/24 Open Bel Cc 6,933' 6,939' 4,828' 4,834' 6' 9/21/24 Open Bel Da 7,007' 7,013' 4,899' 4,905' 6' 9/20/24 Open Bel Db 7,017' 7,021' 4,909' 4,913' 4' 9/20/24 Open Bel Dc 7,047' 7,053' 4,938' 4,943' 6' 9/20/24 Open Bel Ea 7,061' 7,067' 4,951' 4,957' 6' 9/20/24 Open Bel Eb 7,108' 7,116' 4,997' 5,004' 8' 9/20/24 Open Bel Ec 7,154' 7,158' 5,041' 5,041' 4' 9/20/24 Open Bel Ed 7,171' 7,175' 5,058' 5,062' 4' 9/18/24 Open Bel Ee 7,205' 7,210' 5,091' 5,096' 5' 9/18/24 Open Bel Fa 7,228' 7,232' 5,113' 5,117' 4' 09/15/24 Open Bel Fb 7,247' 7,253' 5,132' 5,138' 6' 09/15/24 Open Bel Fc 7,266' 7,270' 5,151' 5,154' 4' 09/15/24 Open Bel Fd 7,273' 7,280' 5,157' 5,164' 7' 09/15/24 Open Bel Fe 7,309' 7,313' 5,193' 5,197' 4' 09/13/24 Open Bel Ga 7,317' 7,323' 5,201' 5,206' 6' 09/13/24 Open Bel Gb 7,328' 7,332' 5,211' 5,215' 4' 09/13/24 Open Bel Gc 7,371 7,382 5,254 5,264 11 TBD Open Bel Ha 7,454 7,467 5,335 5,348 13 TBD Open Bel Hc 7,483 7,513 5,364 5,394 30 TBD Open Bel Hd 7,517 7,523 5,398 5,403 6 TBD Open Bel He 7,543 7,552 5,423 5,432 9 TBD Open Bel Ka 7,807' 7,817' 5,684' 5,694' 10' 09/05/24 Isolated Bel Kb 7,823' 7,835' 5,700' 5,711' 12' 09/05/24 Isolated Bel KcU 7,858' 7,864' 5,734' 5,740' 6' 09/06/24 Isolated Bel KcL 7,866' 7,876' 5,742' 5,752' 10' 09/06/24 Isolated Bel La 7,937' 7,947' 5,812' 5,822' 10' 09/04/24 Isolated Bel Lb 7,965' 7,971' 5,840' 5,846' 6' 08/30/24 Isolated Bel Lc 7,980' 7,990' 5,855' 5,865' 10' 08/30/24 Isolated Bel Ma 8,007' 8,010' 5,881' 5,884' 3' 08/30/24 Isolated Bel Mb 8,016' 8,022' 5,890' 5,896' 6' 09/06/24 Isolated Bel Mc 8,040' 8,044' 5,915' 5,918' 4' 09/06/24 Isolated Bel O 8,147' 8,153' 6,020' 6,026' 6' 09/04/24 Isolated (9/4/24) Bel Qa 8,375' 8,381' 6,246' 6,252' 6' 09/02/24 Isolated (9/2/24) Bel QbU 8,407' 8,413' 6,277' 6,283' 6' 09/02/24 Isolated (9/2/24) Bel QbL 8,413' 8,433' 6,283' 6,303' 20' 09/02/24 Isolated (9/2/24) GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 2,225 1,994' 3.833 GLM, 4.5" X 1.5'' FO-2 (BK)16 Dome 750 07/31/2024 2 4,852 3,288' 3.833 GLM, 4.5" X 1.5'' FO-2 (Gen 2 Mod) 24 Orifice 07/31/2024 FISH/OTHER DETAILS 7,988' 9/18/24 - Tag fish (Btm of BRT, guns & roller bogey) 8,029' 9/16/24 - Tag fish (Btm of BRT, guns & roller bogey) 6,819' GCBD with RA tag in collar 7,816' GCBD with RA tag in collar STANDARD WELL PROCEDURE NITROGEN OPERATIONS 09/23/2016 FINAL v-offshore Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Facility Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review 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 Nitrogen Tank. 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 supplier 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 Tank. 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): 8,824 See schematic Casing Collapse Structural Conductor 230psi Surface 4,750psi Intermediate Production Liner 7,500psi 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: Eric Dickerman Contact Email:Eric.Dickerman@hilcorp.com Contact Phone:(907) 564-4061 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: CTCO, N2 CO 68A 6/24/2025 8,824'3,878' 4-1/2" 6,690' LTP & Baker TE-5 4,946 (MD) 3,333 (TVD) & 505 (MD) 505 (TVD) Perforation Depth MD (ft): 6,587 - 8,044 4-1/2" 4,498 - 5,918 30" 9-5/8" 384' 5,148' MD 1,630psi 6,870psi 384' 3,435' 384' 5,148' Length Size Proposed Pools: L-80 TVD Burst 4,984 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 / ADL0037831 224-026 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20194-00-00 Hilcorp Alaska, LLC N Cook Inlet Unit A-19 AOGCC USE ONLY 8,430psi Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Operations Manager Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY N Cook Inlet Tertiary System Gas Same 6,690 8,135 6,008 251psi See schematic No 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 11:30 am, Jun 10, 2025 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2025.06.10 10:27:47 - 08'00' Dan Marlowe (1267) 325-354 DSR-6/18/25A.Dewhurst 16JUN25 BOPE test to 3000 psi. 48 hour notice to AOGCC. 10-404 MGR30JUNE2025JLC 7/1/2025 Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.07.01 14:37:09 -08'00'07/01/25 RBDMS JSB 070225 NCIU A-19 Fill Clean Out and Bridge Plug Page 1 of 2 Well Name:NCIU A-19 API Number:50-883-20194-00-00 Current Status:Shut in Permit to Drill Number:224-026 Estimated Start Date:6/24/2025 Rig:Fox Coil Unit 9 Regulatory Contact:Juanita Lovett Estimated Duration:3 days First Call Engineer:Eric Dickerman Cell Number:307-250-4013 Second Call Engineer:Casey Morse Cell Number:603-205-3780 Current Bottom Hole Pressure:700 psi at 4,498’ TVD. Nodal analysis from 9/22/24 flowing bottomhole pressure survey. MPSP:251 psi (Based on 0.1 psi/ft. gas gradient) Last Shut-in WHP:199 psi Min. ID:3.813’’ - 4-1/2” X nipple Max. Deviation:67϶ at 2,598’ Pool:Tertiary Gas Pool, North Cook Inlet Field, no pool change during operation. Brief Well Summary: NCIU A-19 was drilled in August 2024 and completed in September 2024 in the Beluga formation. On 4/15/25, the well failed an SVS test with the subsurface safety valve failing to hold differential pressure. On 4/19/25 slickline brushed the subsurface safety valve and a subsequent in-house SVS test passed. However production failed to return to pre-SVS testing rates and then the production died of completely on 4/20/25. Slickline returned on 4/24/25 and worked through bridges at 1200’ and 1750’ before running into solid fill at 2100’. A coiled tubing cleanout was successfully completed down to 7,935’ on 4/30/25. The well was brought online post cleanout and again experienced fill problems in the tubing and flowline subsequently leading to the well getting shut in. Based on analog well performance and diagnostics, the intervals below the Beluga Gb are suspected to be the intervals producing solids. There is currently a construction project to add conductor slots for future drill wells in progress on the Tyonek platform. This construction project limits resources to perform wellwork. Currently there is estimated to be a window from 6/23/25 to 6/30/25 where wellwork can be performed, otherwise the project is estimated to be completed the first week of August 2025. Objective: Coiled tubing fill cleanout. Set a bridge plug to reduce fill potential. NCIU A-19 Fill Clean Out and Bridge Plug Page 2 of 2 Coiled Tubing: 1. MIRU Fox Energy offshore Coiled Tubing #9 and pressure control equipment on A-19, Leg #2. 2. Pressure test BOP and PCE to 250 psi low / 3,000 psi high. a. Provide AOGCC with 48 hr BOP test witness notification. 3. MU cleanout BHA. Dry tag top of fill, then begin cleaning out to tag at approximately 7,935’. PUH 50’ from tag and paint a flag on the pipe. a. Working fluid will be 6% KCl (8.6 ppg). b. Take returns to surface up the CT x tubing annulus. c. Add foam and nitrogen as necessary to carry solids to surface. 4. RIH with GR/CCL tools in a carrier and a drift nozzle. Log a correlation pass and flag pipe. 5. Set 4-1/2” bridge plug to shut off the Beluga Ka interval. Target bridge plug depth ±7,800’. 6. RIH and blow well dry with nitrogen. 7. RDMO Coiled tubing unit. Operations: 8. Perform SVS test within 5 days of bringing the well on production. a. Provide AOGCC with 48 hr witness notification. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. CT BOP schematic (Fox Energy) 4. Standard nitrogen procedure _____________________________________________________________________________________ Updated By: JLL 05/05/25 SCHEMATIC North Cook Inlet Unit NCIU A-19 PTD: 224-026 API: 50-883-20194-00-00 Bel Oa - Bel QbL 1 2 3/4/5 PBTD = 8,135’ / TVD = 6,008’ TD = 8,824’ / TVD = 6,690’ Bel M Bel L Bel O Bel K Bel G Bel F Bel B Bel E Bel D Bel C Bel A RKB = 126.6' 30” 12-1/4” hole 8-1/2” hole CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 30”Conductor – Driven to Set Depth - - Weld 29” Surf 384’ 9-5/8" Surf Csg 47 L-80 DWC/C 8.681” Surf 5,148’ 4-1/2" Prod Lnr 12.6 L-80 JFELion 3.958” 4,946’ 8,824’ 4-1/2" Prod Tieback 12.6 L-80 DWC/C 3.958” Surf 4,984’ JEWELRY DETAIL No.Depth (MD) Depth (TVD)Item 1 505’ 505' Baker TE-5 SSSV 2 1,023’ 1,018' ES Cementer 3 4,916’ 3,318' X nipple (GOT) 4 4,974’ 3,347' Seal Stem 5 4,946’ 3,333' Liner hanger / LTP Assembly 6 8,135' 6,008' CIBP (9/4/24) 6 8,365' 6,236' CIBP (9/2/24) OPEN HOLE / CEMENT DETAIL 9-5/8" TOC @ Surface Stg 1 –332 bbls Stg 2 -448 bbls 4-1/2” Est. TOC @ TOL (40% excess) L – 237 bbls / T – 37 bbls PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status Bel Au 6,587' 6,599' 4,498' 4,509' 12' 9/21/24 Open Bel Al 6,626' 6,638' 4,534' 4,546' 12' 9/21/24 Open Bel Ba 6,679' 6,683' 4,584' 4,588' 4' 9/21/24 Open Bel Bb 6,689' 6,699' 4,594' 4,603' 10' 9/21/24 Open Bel Bc 6,703' 6,709' 4,607' 4,613' 6' 9/21/24 Open Bel Bd 6,757' 6,767' 4,659' 4,669' 10' 9/21/24 Open Bel Ca 6,892' 6,896' 4,788' 4,792' 4' 9/21/24 Open Bel Cb 6,913' 6,917' 4,809' 4,812' 4' 9/21/24 Open Bel Cc 6,933' 6,939' 4,828' 4,834' 6' 9/21/24 Open Bel Da 7,007' 7,013' 4,899' 4,905' 6' 9/20/24 Open Bel Db 7,017' 7,021' 4,909' 4,913' 4' 9/20/24 Open Bel Dc 7,047' 7,053' 4,938' 4,943' 6' 9/20/24 Open Bel Ea 7,061' 7,067' 4,951' 4,957' 6' 9/20/24 Open Bel Eb 7,108' 7,116' 4,997' 5,004' 8' 9/20/24 Open Bel Ec 7,154' 7,158' 5,041' 5,041' 4' 9/20/24 Open Bel Ed 7,171' 7,175' 5,058' 5,062' 4' 9/18/24 Open Bel Ee 7,205' 7,210' 5,091' 5,096' 5' 9/18/24 Open Bel Fa 7,228' 7,232' 5,113' 5,117' 4' 09/15/24 Open Bel Fb 7,247' 7,253' 5,132' 5,138' 6' 09/15/24 Open Bel Fc 7,266' 7,270' 5,151' 5,154' 4' 09/15/24 Open Bel Fd 7,273' 7,280' 5,157' 5,164' 7' 09/15/24 Open Bel Fe 7,309' 7,313' 5,193' 5,197' 4' 09/13/24 Open Bel Ga 7,317' 7,323' 5,201' 5,206' 6' 09/13/24 Open Bel Gb 7,328' 7,332' 5,211' 5,215' 4' 09/13/24 Open Bel Ka 7,807' 7,817' 5,684' 5,694' 10' 09/05/24 Open Bel Kb 7,823' 7,835' 5,700' 5,711' 12' 09/05/24 Open Bel KcU 7,858' 7,864' 5,734' 5,740' 6' 09/06/24 Open Bel KcL 7,866' 7,876' 5,742' 5,752' 10' 09/06/24 Open Bel La 7,937' 7,947' 5,812' 5,822' 10' 09/04/24 Open Bel Lb 7,965' 7,971' 5,840' 5,846' 6' 08/30/24 Open Bel Lc 7,980' 7,990' 5,855' 5,865' 10' 08/30/24 Open Bel Ma 8,007' 8,010' 5,881' 5,884' 3' 08/30/24 Open Bel Mb 8,016' 8,022' 5,890' 5,896' 6' 09/06/24 Open Bel Mc 8,040' 8,044' 5,915' 5,918' 4' 09/06/24 Open Bel O 8,147' 8,153' 6,020' 6,026' 6' 09/04/24 Isolated Bel Qa 8,375' 8,381' 6,246' 6,252' 6' 09/02/24 Isolated Bel QbU 8,407' 8,413' 6,277' 6,283' 6' 09/02/24 Isolated Bel QbL 8,413' 8,433' 6,283' 6,303' 20' 09/02/24 Isolated GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 2,225’ 1,994' 3.833 GLM, 4.5" X 1.5'' FO-2 (BK)16 Dome 750 07/31/2024 2 4,852’ 3,288' 3.833 GLM, 4.5" X 1.5'' FO-2 (Gen 2 Mod) 24 Orifice 07/31/2024 FISH/OTHER DETAILS 7,988' 9/18/24 - Tag fish (Btm of BRT, guns & roller bogey) 8,029' 9/16/24 - Tag fish (Btm of BRT, guns & roller bogey) 6,819' GCBD with RA tag in collar 7,816' GCBD with RA tag in collar _____________________________________________________________________________________ Updated By: EPD 06/10/25 PROPOSED North Cook Inlet Unit NCIU A-19 PTD: 224-026 API: 50-883-20194-00-00 Bel Oa - Bel QbL 6 7 8 1 2 3/4/5 PBTD = 8,135’ / TVD = 6,008’ TD = 8,824’ / TVD = 6,690’ Bel M Bel L Bel O Bel K Bel G Bel F Bel B Bel E Bel D Bel C Bel A RKB = 126.6' 30” 12-1/4” hole 8-1/2” hole CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 30”Conductor – Driven to Set Depth - - Weld 29” Surf 384’ 9-5/8" Surf Csg 47 L-80 DWC/C 8.681” Surf 5,148’ 4-1/2" Prod Lnr 12.6 L-80 JFELion 3.958” 4,946’ 8,824’ 4-1/2" Prod Tieback 12.6 L-80 DWC/C 3.958” Surf 4,984’ JEWELRY DETAIL No.Depth (MD) Depth (TVD)Item 1 505’ 505' Baker TE-5 SSSV 2 1,023’ 1,018' ES Cementer 3 4,916’ 3,318' X nipple (GOT) 4 4,974’ 3,347' Seal Stem 5 4,946’ 3,333' Liner hanger / LTP Assembly 6 ± 7,800’ ± 5,677’ Bridge Plug 7 8,135' 6,008' CIBP (9/4/24) 8 8,365' 6,236' CIBP (9/2/24) OPEN HOLE / CEMENT DETAIL 9-5/8" TOC @ Surface Stg 1 –332 bbls Stg 2 -448 bbls 4-1/2” Est. TOC @ TOL (40% excess) L – 237 bbls / T – 37 bbls PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status Bel Au 6,587' 6,599' 4,498' 4,509' 12' 9/21/24 Open Bel Al 6,626' 6,638' 4,534' 4,546' 12' 9/21/24 Open Bel Ba 6,679' 6,683' 4,584' 4,588' 4' 9/21/24 Open Bel Bb 6,689' 6,699' 4,594' 4,603' 10' 9/21/24 Open Bel Bc 6,703' 6,709' 4,607' 4,613' 6' 9/21/24 Open Bel Bd 6,757' 6,767' 4,659' 4,669' 10' 9/21/24 Open Bel Ca 6,892' 6,896' 4,788' 4,792' 4' 9/21/24 Open Bel Cb 6,913' 6,917' 4,809' 4,812' 4' 9/21/24 Open Bel Cc 6,933' 6,939' 4,828' 4,834' 6' 9/21/24 Open Bel Da 7,007' 7,013' 4,899' 4,905' 6' 9/20/24 Open Bel Db 7,017' 7,021' 4,909' 4,913' 4' 9/20/24 Open Bel Dc 7,047' 7,053' 4,938' 4,943' 6' 9/20/24 Open Bel Ea 7,061' 7,067' 4,951' 4,957' 6' 9/20/24 Open Bel Eb 7,108' 7,116' 4,997' 5,004' 8' 9/20/24 Open Bel Ec 7,154' 7,158' 5,041' 5,041' 4' 9/20/24 Open Bel Ed 7,171' 7,175' 5,058' 5,062' 4' 9/18/24 Open Bel Ee 7,205' 7,210' 5,091' 5,096' 5' 9/18/24 Open Bel Fa 7,228' 7,232' 5,113' 5,117' 4' 09/15/24 Open Bel Fb 7,247' 7,253' 5,132' 5,138' 6' 09/15/24 Open Bel Fc 7,266' 7,270' 5,151' 5,154' 4' 09/15/24 Open Bel Fd 7,273' 7,280' 5,157' 5,164' 7' 09/15/24 Open Bel Fe 7,309' 7,313' 5,193' 5,197' 4' 09/13/24 Open Bel Ga 7,317' 7,323' 5,201' 5,206' 6' 09/13/24 Open Bel Gb 7,328' 7,332' 5,211' 5,215' 4' 09/13/24 Open Bel Ka 7,807' 7,817' 5,684' 5,694' 10' 09/05/24 Isolated Bel Kb 7,823' 7,835' 5,700' 5,711' 12' 09/05/24 Isolated Bel KcU 7,858' 7,864' 5,734' 5,740' 6' 09/06/24 Isolated Bel KcL 7,866' 7,876' 5,742' 5,752' 10' 09/06/24 Isolated Bel La 7,937' 7,947' 5,812' 5,822' 10' 09/04/24 Isolated Bel Lb 7,965' 7,971' 5,840' 5,846' 6' 08/30/24 Isolated Bel Lc 7,980' 7,990' 5,855' 5,865' 10' 08/30/24 Isolated Bel Ma 8,007' 8,010' 5,881' 5,884' 3' 08/30/24 Isolated Bel Mb 8,016' 8,022' 5,890' 5,896' 6' 09/06/24 Isolated Bel Mc 8,040' 8,044' 5,915' 5,918' 4' 09/06/24 Isolated Bel O 8,147' 8,153' 6,020' 6,026' 6' 09/04/24 Isolated (9/4/24) Bel Qa 8,375' 8,381' 6,246' 6,252' 6' 09/02/24 Isolated (9/2/24) Bel QbU 8,407' 8,413' 6,277' 6,283' 6' 09/02/24 Isolated (9/2/24) Bel QbL 8,413' 8,433' 6,283' 6,303' 20' 09/02/24 Isolated (9/2/24) GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 2,225’ 1,994' 3.833 GLM, 4.5" X 1.5'' FO-2 (BK)16 Dome 750 07/31/2024 2 4,852’ 3,288' 3.833 GLM, 4.5" X 1.5'' FO-2 (Gen 2 Mod) 24 Orifice 07/31/2024 FISH/OTHER DETAILS 7,988' 9/18/24 - Tag fish (Btm of BRT, guns & roller bogey) 8,029' 9/16/24 - Tag fish (Btm of BRT, guns & roller bogey) 6,819' GCBD with RA tag in collar 7,816' GCBD with RA tag in collar KLU A-1 Well Head Rig Up 1 1 1 1 4 1/16" 15K Lubricator - 10 ft 100" Gooseneck HR680 Injector Head 4 1/16" 10K Flow Cross, 2" 1502 10k Flanged Valves 4 1/16" 15K Lubricator - 10 ft API Flange Adapter 10K to 5K for riser/wellhead Hydraulic Stripper 4 1/6" 15K API Bowen CB56 15K 4 1/16" 10K Combi BOPs Blind/Shear Ram Pipe/Slip Ram 4 1/16" 10K bottom flange 4 1/16" 5K flanged Riser - 10 ft if necessary STANDARD WELL PROCEDURE NITROGEN OPERATIONS 09/23/2016 FINAL v-offshore Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Facility Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review 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 Nitrogen Tank. 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 supplier 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 Tank. 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): 8,824 See schematic Casing Collapse Structural Conductor 230psi Surface 4,750psi Intermediate Production 7,500psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Eric Dickerman Contact Email:Eric.Dickerman@hilcorp.com Contact Phone:(907) 564-4061 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: CTCO CO 68A 4/27/2025 4-1/2" LTP & Baker TE-5 4,946 (MD) 3,333 (TVD) & 505 (MD) 505 (TVD) 8,824' Perforation Depth MD (ft): 6,587 - 8,044 3,878' 4,498 - 5,918 6,690'4-1/2" 30" 9-5/8" 384' 5,148' MD 1,630psi 6,870psi 384' 3,435' 384' 5,148' Length Size Proposed Pools: L-80 TVD Burst 4,984 8,430psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 / ADL0037831 224-026 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20194-00-00 Hilcorp Alaska, LLC N Cook Inlet Unit A-19 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Operations Manager Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY N Cook Inlet Tertiary System Gas Same 6,690 8,135 6,008 251psi See schematic No 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 3:36 pm, Apr 25, 2025 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2025.04.25 15:16:27 - 08'00' Dan Marlowe (1267) 325-261 SFD 4/28/2025 Mel Rixse - Senior Petroleum Engineer MGR25APR2025 Alaska LLC Standard Operating Procedure for Nitrogen Operations to be appended to this procedure before well site operations commence. YES 10-404 DSR-4/29/25 * Hilcorp 25-April-2025 * BOPE test to 3000 psi. 48 hour notice for AOGCC to witness. *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.30 14:57:25 -08'00'04/30/25 RBDMS JSB 050125 NCIU A-19 Fill Clean Out Page 1 of 2 Well Name:NCIU A-19 API Number:50-833-20194-00-00 Current Status:Shut in Permit to Drill Number:224-026 Estimated Start Date:4/27/25 Rig:Fox Coil Unit 9 Regulatory Contact:Juanita Lovett Estimated Duration:2 days First Call Engineer:Eric Dickerman Cell Number:307-250-4013 Second Call Engineer:Casey Morse Cell Number:603-205-3780 Current Bottom Hole Pressure:700 psi at 4,498’ TVD. Nodal analysis from 9/22/24 flowing bottomhole pressure survey. Max. Anticipated Surface Pressure:251 psi (Based on 0.1 psi/ft. gas gradient) Last Shut-in WHP:199 psi Min. ID:3.813’’ - 4-1/2” X nipple Max. Deviation:67϶ at 2,598’ Pool:Tertiary Gas Pool, North Cook Inlet Field, no pool change during operation. Brief Well Summary: NCIU A-19 was drilled in August 2024 and completed in September 2024 in the Beluga formation. On 4/15/25, the well failed an SVS test with the subsurface safety valve failing to hold differential pressure. On 4/19/25 slickline brushed the subsurface safety valve and a subsequent in-house SVS test passed. However production failed to return to pre-SVS testing rates and then the production died of completely on 4/20/25. Slickline returned on 4/24/25 and worked through bridges at 1200’ and 1750’ before running into solid fill at 2100’. Multiple bailing attempts showed minimal progress, leading to this procedure for a coiled tubing cleanout. Tyonek platform is currently in progress on the leg expansion project to add more conductor slots for future drilling targets. To prevent excessive delays on the construction project the goal is to complete the coiled tubing cleanout and demobilize the coil equipment off the platform by 4/29/25. Objective: Coiled tubing fill cleanout. NCIU A-19 Fill Clean Out Page 2 of 2 Coiled Tubing Procedure: 1. MIRU Fox Energy offshore Coiled Tubing #9 and pressure control equipment. 2. Pressure test BOP and PCE to 250 psi low / 3,000 psi high. a. Provide AOGCC with 48 hr BOP test witness notification. 3. MU cleanout BHA. Dry tag top of fill, then begin cleaning out to fish at 7,988’. a. Working fluid will be 6% KCl (8.6ppg). b. Take returns to surface up the CT x tubing annulus. c. Add foam and nitrogen as necessary to carry solids to surface. 4. RIH and blow well dry with nitrogen. 5. RDMO CT. Attachments: 1. Wellbore Schematic 2. CT BOP schematic (Fox Energy) 3. Standard nitrogen procedure Hilcorp Alaska, LLC Standard Operating Procedure for Nitrogen operations to be attached to this sundry before commencing operations. - MGR 3.Standard nitrogen procedure _____________________________________________________________________________________ Updated By: JLL 09/24/24 SCHEMATIC North Cook Inlet Unit NCIU A-19 PTD: 224-026 API: 50-883-20194-00-00 Bel Oa - Bel QbL 1 2 3/4/5 PBTD = 8,135’ / TVD = 6,008’ TD = 8,824’ / TVD = 6,690’ Bel M Bel L Bel O Bel K Bel G Bel F Bel B Bel E Bel D Bel C Bel A RKB = 126.6' 30” 12-1/4” hole 8-1/2” hole CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 30”Conductor – Driven to Set Depth - - Weld 29” Surf 384’ 9-5/8" Surf Csg 47 L-80 DWC/C 8.681” Surf 5,148’ 4-1/2" Prod Lnr 12.6 L-80 JFELion 3.958” 4,946’ 8,824’ 4-1/2" Prod Tieback 12.6 L-80 DWC/C 3.958” Surf 4,984’ JEWELRY DETAIL No.Depth (MD) Depth (TVD)Item 1 505’ 505' Baker TE-5 SSSV 2 1,023’ 1,018' ES Cementer 3 4,916’ 3,318' X nipple (GOT) 4 4,974’ 3,347' Seal Stem 5 4,946’ 3,333' Liner hanger / LTP Assembly 6 8,135' 6,008' CIBP (9/4/24) 6 8,365' 6,236' CIBP (9/2/24) OPEN HOLE / CEMENT DETAIL 9-5/8" TOC @ Surface Stg 1 –332 bbls Stg 2 -448 bbls 4-1/2” Est. TOC @ TOL (40% excess) L – 237 bbls / T – 37 bbls PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status Bel Au 6,587' 6,599' 4,498' 4,509' 12' 9/21/24 Open Bel Al 6,626' 6,638' 4,534' 4,546' 12' 9/21/24 Open Bel Ba 6,679' 6,683' 4,584' 4,588' 4' 9/21/24 Open Bel Bb 6,689' 6,699' 4,594' 4,603' 10' 9/21/24 Open Bel Bc 6,703' 6,709' 4,607' 4,613' 6' 9/21/24 Open Bel Bd 6,757' 6,767' 4,659' 4,669' 10' 9/21/24 Open Bel Ca 6,892' 6,896' 4,788' 4,792' 4' 9/21/24 Open Bel Cb 6,913' 6,917' 4,809' 4,812' 4' 9/21/24 Open Bel Cc 6,933' 6,939' 4,828' 4,834' 6' 9/21/24 Open Bel Da 7,007' 7,013' 4,899' 4,905' 6' 9/20/24 Open Bel Db 7,017' 7,021' 4,909' 4,913' 4' 9/20/24 Open Bel Dc 7,047' 7,053' 4,938' 4,943' 6' 9/20/24 Open Bel Ea 7,061' 7,067' 4,951' 4,957' 6' 9/20/24 Open Bel Eb 7,108' 7,116' 4,997' 5,004' 8' 9/20/24 Open Bel Ec 7,154' 7,158' 5,041' 5,041' 4' 9/20/24 Open Bel Ed 7,171' 7,175' 5,058' 5,062' 4' 9/18/24 Open Bel Ee 7,205' 7,210' 5,091' 5,096' 5' 9/18/24 Open Bel Fa 7,228' 7,232' 5,113' 5,117' 4' 09/15/24 Open Bel Fb 7,247' 7,253' 5,132' 5,138' 6' 09/15/24 Open Bel Fc 7,266' 7,270' 5,151' 5,154' 4' 09/15/24 Open Bel Fd 7,273' 7,280' 5,157' 5,164' 7' 09/15/24 Open Bel Fe 7,309' 7,313' 5,193' 5,197' 4' 09/13/24 Open Bel Ga 7,317' 7,323' 5,201' 5,206' 6' 09/13/24 Open Bel Gb 7,328' 7,332' 5,211' 5,215' 4' 09/13/24 Open Bel Ka 7,807' 7,817' 5,684' 5,694' 10' 09/05/24 Open Bel Kb 7,823' 7,835' 5,700' 5,711' 12' 09/05/24 Open Bel KcU 7,858' 7,864' 5,734' 5,740' 6' 09/06/24 Open Bel KcL 7,866' 7,876' 5,742' 5,752' 10' 09/06/24 Open Bel La 7,937' 7,947' 5,812' 5,822' 10' 09/04/24 Open Bel Lb 7,965' 7,971' 5,840' 5,846' 6' 08/30/24 Open Bel Lc 7,980' 7,990' 5,855' 5,865' 10' 08/30/24 Open Bel Ma 8,007' 8,010' 5,881' 5,884' 3' 08/30/24 Open Bel Mb 8,016' 8,022' 5,890' 5,896' 6' 09/06/24 Open Bel Mc 8,040' 8,044' 5,915' 5,918' 4' 09/06/24 Open Bel O 8,147' 8,153' 6,020' 6,026' 6' 09/04/24 Isolated Bel Qa 8,375' 8,381' 6,246' 6,252' 6' 09/02/24 Isolated Bel QbU 8,407' 8,413' 6,277' 6,283' 6' 09/02/24 Isolated Bel QbL 8,413' 8,433' 6,283' 6,303' 20' 09/02/24 Isolated GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 2,225’ 1,994' 3.833 GLM, 4.5" X 1.5'' FO-2 (BK)16 Dome 750 07/31/2024 2 4,852’ 3,288' 3.833 GLM, 4.5" X 1.5'' FO-2 (Gen 2 Mod) 24 Orifice 07/31/2024 FISH/OTHER DETAILS 7,988' 9/18/24 - Tag fish (Btm of BRT, guns & roller bogey) 8,029' 9/16/24 - Tag fish (Btm of BRT, guns & roller bogey) 6,819' GCBD with RA tag in collar 7,816' GCBD with RA tag in collar KLU A-1 Well Head Rig Up 1 1 1 1 4 1/16" 15K Lubricator - 10 ft 100" Gooseneck HR680 Injector Head 4 1/16" 10K Flow Cross, 2" 1502 10k Flanged Valves 4 1/16" 15K Lubricator - 10 ft API Flange Adapter 10K to 5K for riser/wellhead Hydraulic Stripper 4 1/6" 15K API Bowen CB56 15K 4 1/16" 10K Combi BOPs Blind/Shear Ram Pipe/Slip Ram 4 1/16" 10K bottom flange 4 1/16" 5K flanged Riser - 10 ft if necessary KLU A-1 Well Head Rig Up 1 1 1 1 4 1/16" 15K Lubricator - 10 ft 100" Gooseneck HR680 Injector Head 4 1/16" 10K Flow Cross, 2" 1502 10k Flanged Valves 4 1/16" 15K Lubricator - 10 ft API Flange Adapter 10K to 5K for riser/wellhead Hydraulic Stripper 4 1/6" 15K API Bowen CB56 15K 4 1/16" 10K Combi BOPs Blind/Shear Ram Pipe/Slip Ram 4 1/16" 10K bottom flange 4 1/16" 5K flanged Riser - 10 ft if necessary 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:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:20250425 1710 Verbal Approval 10-403 N Cook Inlet Unit A-19 PTD: 224-026 - Application for Sundry Approval Date:Friday, April 25, 2025 8:10:32 PM Attachments:Hilcorp_NCIU_ A-19_Verbal Approval - Nitrogen Cleanout - Rush.pdf From: Rixse, Melvin G (OGC) Sent: Friday, April 25, 2025 5:10 PM To: Eric Dickerman <Eric.Dickerman@hilcorp.com> Cc: Dan Marlowe <dmarlowe@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com> Subject: Verbal Approval 10-403 N Cook Inlet Unit A-19 PTD: 224-026 - Application for Sundry Approval Eric, Please assure the Hilcorp N2 SOP attached to this approved sundry at the well site before commencing operations. 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: Eric Dickerman <Eric.Dickerman@hilcorp.com> Sent: Friday, April 25, 2025 3:25 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Dan Marlowe <dmarlowe@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com> Subject: FW: 10-403 N Cook Inlet Unit A-19 PTD: 224-026 - Application for Sundry Approval Mel, As discussed on the phone, please see the attached sundry request for a coiled tubing fill clean out on NCIU A-19 (PTD 224-026) that was submitted this afternoon. We are requesting verbal approval to begin the coil operation this weekend. We plan to mobilize the coiled tubing unit and support equipment to the platform tomorrow, and have submitted a BOP test witness request for Sunday. The reason behind the rush is that we found fill at 2100’ with slickline yesterday, and a major stage in the construction project to add slots for future drill wells is kicking off on Tuesday 4/29. I appreciate your time, and am cognizant of the stress that these short notice requests add. Please let me know if you have any questions. Thank you, Eric Dickerman Hilcorp – CIO Ops Engineer Cell: 307-250-4013 From: Juanita Lovett <jlovett@hilcorp.com> Sent: Friday, April 25, 2025 3:19 PM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Eric Dickerman <Eric.Dickerman@hilcorp.com> Subject: 10-403 N Cook Inlet Unit A-19 PTD: 224-026 - Application for Sundry Approval For processing. Thank you, Juanita L Lovett Sr. Operations/Regulatory Tech Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 | Anchorage | AK | 99503 (907) 777-8332 | jlovett@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 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 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. 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): 8,824 See schematic Casing Collapse Structural Conductor 230psi Surface 4,750psi Intermediate Production 7,500psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Eric Dickerman Contact Email:Eric.Dickerman@hilcorp.com Contact Phone:(907) 564-4061 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: CTCO CO 68A 4/27/2025 4-1/2" LTP & Baker TE-5 4,946 (MD) 3,333 (TVD) & 505 (MD) 505 (TVD) 8,824' Perforation Depth MD (ft): 6,587 - 8,044 3,878' 4,498 - 5,918 6,690'4-1/2" 30" 9-5/8" 384' 5,148' MD 1,630psi 6,870psi 384' 3,435' 384' 5,148' Length Size Proposed Pools: L-80 TVD Burst 4,984 8,430psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 / ADL0037831 224-026 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20194-00-00 Hilcorp Alaska, LLC N Cook Inlet Unit A-19 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Operations Manager Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY N Cook Inlet Tertiary System Gas Same 6,690 8,135 6,008 251psi See schematic No 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 3:36 pm, Apr 25, 2025 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2025.04.25 15:16:27 - 08'00' Dan Marlowe (1267) 325-261 Mel Rixse - Senior Petroleum Engineer MGR25APR2025 Alaska LLC Standard Operating Procedure for Nitrogen Operations to be appended to this procedure before well site operations commence. YES 10-404 * Hilcorp 25-April-2025 * BOPE test to 3000 psi. 48 hour notice for AOGCC to witness. NCIU A-19 Fill Clean Out Page 1 of 2 Well Name:NCIU A-19 API Number:50-833-20194-00-00 Current Status:Shut in Permit to Drill Number:224-026 Estimated Start Date:4/27/25 Rig:Fox Coil Unit 9 Regulatory Contact:Juanita Lovett Estimated Duration:2 days First Call Engineer:Eric Dickerman Cell Number:307-250-4013 Second Call Engineer:Casey Morse Cell Number:603-205-3780 Current Bottom Hole Pressure:700 psi at 4,498’ TVD. Nodal analysis from 9/22/24 flowing bottomhole pressure survey. Max. Anticipated Surface Pressure:251 psi (Based on 0.1 psi/ft. gas gradient) Last Shut-in WHP:199 psi Min. ID:3.813’’ - 4-1/2” X nipple Max. Deviation:67϶ at 2,598’ Pool:Tertiary Gas Pool, North Cook Inlet Field, no pool change during operation. Brief Well Summary: NCIU A-19 was drilled in August 2024 and completed in September 2024 in the Beluga formation. On 4/15/25, the well failed an SVS test with the subsurface safety valve failing to hold differential pressure. On 4/19/25 slickline brushed the subsurface safety valve and a subsequent in-house SVS test passed. However production failed to return to pre-SVS testing rates and then the production died of completely on 4/20/25. Slickline returned on 4/24/25 and worked through bridges at 1200’ and 1750’ before running into solid fill at 2100’. Multiple bailing attempts showed minimal progress, leading to this procedure for a coiled tubing cleanout. Tyonek platform is currently in progress on the leg expansion project to add more conductor slots for future drilling targets. To prevent excessive delays on the construction project the goal is to complete the coiled tubing cleanout and demobilize the coil equipment off the platform by 4/29/25. Objective: Coiled tubing fill cleanout. NCIU A-19 Fill Clean Out Page 2 of 2 Coiled Tubing Procedure: 1. MIRU Fox Energy offshore Coiled Tubing #9 and pressure control equipment. 2. Pressure test BOP and PCE to 250 psi low / 3,000 psi high. a. Provide AOGCC with 48 hr BOP test witness notification. 3. MU cleanout BHA. Dry tag top of fill, then begin cleaning out to fish at 7,988’. a. Working fluid will be 6% KCl (8.6ppg). b. Take returns to surface up the CT x tubing annulus. c. Add foam and nitrogen as necessary to carry solids to surface. 4. RIH and blow well dry with nitrogen. 5. RDMO CT. Attachments: 1. Wellbore Schematic 2. CT BOP schematic (Fox Energy) 3. Standard nitrogen procedure Hilcorp Alaska, LLC Standard Operating Procedure for Nitrogen operations to be attached to this sundry before commencing operations. - MGR 3.Standard nitrogen procedure _____________________________________________________________________________________ Updated By: JLL 09/24/24 SCHEMATIC North Cook Inlet Unit NCIU A-19 PTD: 224-026 API: 50-883-20194-00-00 Bel Oa - Bel QbL 1 2 3/4/5 PBTD = 8,135’ / TVD = 6,008’ TD = 8,824’ / TVD = 6,690’ Bel M Bel L Bel O Bel K Bel G Bel F Bel B Bel E Bel D Bel C Bel A RKB = 126.6' 30” 12-1/4” hole 8-1/2” hole CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 30”Conductor – Driven to Set Depth - - Weld 29” Surf 384’ 9-5/8" Surf Csg 47 L-80 DWC/C 8.681” Surf 5,148’ 4-1/2" Prod Lnr 12.6 L-80 JFELion 3.958” 4,946’ 8,824’ 4-1/2" Prod Tieback 12.6 L-80 DWC/C 3.958” Surf 4,984’ JEWELRY DETAIL No.Depth (MD) Depth (TVD)Item 1 505’ 505' Baker TE-5 SSSV 2 1,023’ 1,018' ES Cementer 3 4,916’ 3,318' X nipple (GOT) 4 4,974’ 3,347' Seal Stem 5 4,946’ 3,333' Liner hanger / LTP Assembly 6 8,135' 6,008' CIBP (9/4/24) 6 8,365' 6,236' CIBP (9/2/24) OPEN HOLE / CEMENT DETAIL 9-5/8" TOC @ Surface Stg 1 –332 bbls Stg 2 -448 bbls 4-1/2” Est. TOC @ TOL (40% excess) L – 237 bbls / T – 37 bbls PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status Bel Au 6,587' 6,599' 4,498' 4,509' 12' 9/21/24 Open Bel Al 6,626' 6,638' 4,534' 4,546' 12' 9/21/24 Open Bel Ba 6,679' 6,683' 4,584' 4,588' 4' 9/21/24 Open Bel Bb 6,689' 6,699' 4,594' 4,603' 10' 9/21/24 Open Bel Bc 6,703' 6,709' 4,607' 4,613' 6' 9/21/24 Open Bel Bd 6,757' 6,767' 4,659' 4,669' 10' 9/21/24 Open Bel Ca 6,892' 6,896' 4,788' 4,792' 4' 9/21/24 Open Bel Cb 6,913' 6,917' 4,809' 4,812' 4' 9/21/24 Open Bel Cc 6,933' 6,939' 4,828' 4,834' 6' 9/21/24 Open Bel Da 7,007' 7,013' 4,899' 4,905' 6' 9/20/24 Open Bel Db 7,017' 7,021' 4,909' 4,913' 4' 9/20/24 Open Bel Dc 7,047' 7,053' 4,938' 4,943' 6' 9/20/24 Open Bel Ea 7,061' 7,067' 4,951' 4,957' 6' 9/20/24 Open Bel Eb 7,108' 7,116' 4,997' 5,004' 8' 9/20/24 Open Bel Ec 7,154' 7,158' 5,041' 5,041' 4' 9/20/24 Open Bel Ed 7,171' 7,175' 5,058' 5,062' 4' 9/18/24 Open Bel Ee 7,205' 7,210' 5,091' 5,096' 5' 9/18/24 Open Bel Fa 7,228' 7,232' 5,113' 5,117' 4' 09/15/24 Open Bel Fb 7,247' 7,253' 5,132' 5,138' 6' 09/15/24 Open Bel Fc 7,266' 7,270' 5,151' 5,154' 4' 09/15/24 Open Bel Fd 7,273' 7,280' 5,157' 5,164' 7' 09/15/24 Open Bel Fe 7,309' 7,313' 5,193' 5,197' 4' 09/13/24 Open Bel Ga 7,317' 7,323' 5,201' 5,206' 6' 09/13/24 Open Bel Gb 7,328' 7,332' 5,211' 5,215' 4' 09/13/24 Open Bel Ka 7,807' 7,817' 5,684' 5,694' 10' 09/05/24 Open Bel Kb 7,823' 7,835' 5,700' 5,711' 12' 09/05/24 Open Bel KcU 7,858' 7,864' 5,734' 5,740' 6' 09/06/24 Open Bel KcL 7,866' 7,876' 5,742' 5,752' 10' 09/06/24 Open Bel La 7,937' 7,947' 5,812' 5,822' 10' 09/04/24 Open Bel Lb 7,965' 7,971' 5,840' 5,846' 6' 08/30/24 Open Bel Lc 7,980' 7,990' 5,855' 5,865' 10' 08/30/24 Open Bel Ma 8,007' 8,010' 5,881' 5,884' 3' 08/30/24 Open Bel Mb 8,016' 8,022' 5,890' 5,896' 6' 09/06/24 Open Bel Mc 8,040' 8,044' 5,915' 5,918' 4' 09/06/24 Open Bel O 8,147' 8,153' 6,020' 6,026' 6' 09/04/24 Isolated Bel Qa 8,375' 8,381' 6,246' 6,252' 6' 09/02/24 Isolated Bel QbU 8,407' 8,413' 6,277' 6,283' 6' 09/02/24 Isolated Bel QbL 8,413' 8,433' 6,283' 6,303' 20' 09/02/24 Isolated GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 2,225’ 1,994' 3.833 GLM, 4.5" X 1.5'' FO-2 (BK)16 Dome 750 07/31/2024 2 4,852’ 3,288' 3.833 GLM, 4.5" X 1.5'' FO-2 (Gen 2 Mod) 24 Orifice 07/31/2024 FISH/OTHER DETAILS 7,988' 9/18/24 - Tag fish (Btm of BRT, guns & roller bogey) 8,029' 9/16/24 - Tag fish (Btm of BRT, guns & roller bogey) 6,819' GCBD with RA tag in collar 7,816' GCBD with RA tag in collar KLU A-1 Well Head Rig Up 1 1 1 1 4 1/16" 15K Lubricator - 10 ft 100" Gooseneck HR680 Injector Head 4 1/16" 10K Flow Cross, 2" 1502 10k Flanged Valves 4 1/16" 15K Lubricator - 10 ft API Flange Adapter 10K to 5K for riser/wellhead Hydraulic Stripper 4 1/6" 15K API Bowen CB56 15K 4 1/16" 10K Combi BOPs Blind/Shear Ram Pipe/Slip Ram 4 1/16" 10K bottom flange 4 1/16" 5K flanged Riser - 10 ft if necessary KLU A-1 Well Head Rig Up 1 1 1 1 4 1/16" 15K Lubricator - 10 ft 100" Gooseneck HR680 Injector Head 4 1/16" 10K Flow Cross, 2" 1502 10k Flanged Valves 4 1/16" 15K Lubricator - 10 ft API Flange Adapter 10K to 5K for riser/wellhead Hydraulic Stripper 4 1/6" 15K API Bowen CB56 15K 4 1/16" 10K Combi BOPs Blind/Shear Ram Pipe/Slip Ram 4 1/16" 10K bottom flange 4 1/16" 5K flanged Riser - 10 ft if necessary 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: 9/27/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240927 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 14B 50133205390200 222057 8/14/2024 YELLOWJACKET GPT-PERF BCU 19RD 50133205790100 219188 8/18/2024 YELLOWJACKET PERF BRU 214-13 50283201870000 222117 9/13/2024 AK E-LINE Perf BRU 221-26 50283202010000 224098 9/9/2024 AK E-LINE CBL BRU 222-26 50283201950000 224035 8/20/2024 AK E-LINE Perf BRU 233-23T 50283202000000 224088 9/14/2024 AK E-LINE CBL END 1-61 50029225200000 194142 9/11/2024 READ CaliperSurvey KBU 32-06 50133206580000 216137 8/6/2024 YELLOWJACKET PERF MPU B-24 50029226420000 196009 9/9/2024 READ CaliperSurvey MPU L-03 50029219990000 190007 9/18/2024 READ CaliperSurvey MPU R-103 50029237990000 224114 9/16/2024 AK E-LINE TubingCut MPU R-103 50029237990000 224114 9/19/2024 AK E-LINE TubingCut MRU M-02 50733203890000 187061 9/17/2024 AK E-LINE Plug NCIU A-19 50883201940000 224026 9/20/2024 AK E-LINE Perf NCIU A-19 50883201940000 224026 9/13/2024 AK E-LINE Perf NCIU A-19 50883201940000 224026 9/15/2024 AK E-LINE Perf NCIU A-19 50883201940000 224026 8/18/2024 AK E-LINE CBL NCIU A-20 50883201960000 224065 9/11/2024 AK E-LINE PPROF NCIU A-20 50883201960000 224065 8/26/2024 READ MemoryRadialCementBondLog PBU 09-27A 50029212910100 215206 9/13/2024 AK E-LINE CBL/TubingPunch PBU 09-34A 50029213290100 193201 12/31/2023 YELLOWJACKET PL PBU 13-24B 50029207390200 224087 8/21/2024 YELLOWJACKET CBL-PERF PBU 13-24B 50029207390200 224087 8/23/2024 YELLOWJACKET CBL PBU 13-26 50029207460000 182074 8/13/2024 YELLOWJACKET CCL PBU NK-26A 50029224400100 218009 7/20/2024 YELLOWJACKET PPROF Please include current contact information if different from above. T39593 T39594 T39595 T39596 T39597 T39598 T39599 T39600 T39601 T39602 T39603 T39603 T39604 T39605 T39605 T39605 T39605 T39606 T39606 T39607 T39608 T39609 T39609 T39610 T39611 NCIU A-19 50883201940000 224026 9/20/2024 AK E-LINE Perf NCIU A-19 50883201940000 224026 9/13/2024 AK E-LINE Perf NCIU A-19 50883201940000 224026 9/15/2024 AK E-LINE Perf NCIU A-19 50883201940000 224026 8/18/2024 AK E-LINE CBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.09.27 14:47:28 -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: 9/12/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240912 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 19RD 50133205790100 219188 7/22/2024 BAKER RPM Blossom 1 50133206480000 215015 8/31/2024 READ Coilflag Blossom 1 50133206480000 215015 9/2/2024 READ MemoryRadialCementBondLog KBY 43-07Y 50133206250000 214019 9/9/2024 AK E-LINE Perf NCIU A-19 50883201940000 224026 8/29/2024 AK E-LINE Perf NCIU A-19 50883201940000 224026 9/4/2024 AK E-LINE Plug/Perf NCIU A-20 50883201960000 224065 8/29/2024 AK E-LINE Perf NCIU A-20 50883201960000 224065 9/3/2024 AK E-LINE Plug/Perf PBU N-21A (REVISED) 50029213420100 196196 3/28/2024 BAKER SPN PBU N-02 50029200830000 170055 7/25/2024 BAKER SPN PBU S-104 50029229880000 200196 7/7/2024 BAKER SPN PBU Z-68 50029234930000 213093 7/6/2024 BAKER SPN Pearl 11 50133207120000 223032 6/24/2024 BAKER SPN Revision explanation: OmniView .las file was the same as the carbo/oxygen .las file, omniview file has been replaced with the correct file and data. Please include current contact information if different from above. T39545 T39546 T39546 T39547 T39548 T39548 T39549 T39549 T39550 T39551 T39552 T39553 T39554 NCIU A-19 50883201940000 224026 8/29/2024 AK E-LINE Perf NCIU A-19 50883201940000 224026 9/4/2024 AK E-LINE Plug/Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.09.12 12:52:42 -08'00' David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 08/20/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: NCIU A-19 PTD: 224-026 API: 50-883-20194-00-00 FINAL LWD FORMATION EVALUATION LOGS (05/29/2024 to 07/23/2024) x ROP, DGR, EWR-P4, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Survey SFTP Transfer – Data Main Folders: Please include current contact information if different from above. 224-026 T39466 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.08.21 08:12:27 -08'00' 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 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): 8,824 N/A Casing Collapse Structural Conductor 230psi Surface 4,750psi Intermediate Production 7,500psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Ryan Rupert Contact Email:Ryan.Rupert@hilcorp.com Contact Phone:(907) 777-8503 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 / N2 Ops / Initial Completion CO 68A 8/14/2024 4-1/2" LTP & Baker TE-5 4,946 (MD) 3,333 (TVD) & 505 (MD) 505 (TVD) 8,824' Perforation Depth MD (ft): ѷ6,561 -ѷ8,550 3,878' ѷ4,474 -ѷ6,419 6,690'4-1/2" 30" 9-5/8" 384' 5,148' MD 1,630psi 6,870psi 384' 3,435' 384' 5,148' Length Size Proposed Pools: L-80 TVD Burst 4,984 8,430psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 / ADL0037831 224-026 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20194-00-00 Hilcorp Alaska, LLC N Cook Inlet Unit A-19 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Operations Manager Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY N Cook Inlet None Tertiary System Gas 6,690 8,779 6,646 2,629psi N/A No 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 3:54 pm, Aug 05, 2024 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2024.08.05 14:10:34 - 08'00' Dan Marlowe (1267) A.Dewhurst 12AUG24BJM 8/12/24 Submit CBL and obtain approval before perforating. 10-407 CT BOP test to 3000 psi. X DSR-8/12/24 Perforate New Pool *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.12 16:41:02 -08'00'08/12/24 RBDMS JSB 081324 Initial Completion Well: NCIU (Tyonek) A-19 Well Name:NCIU (Tyonek) A-19 API Number:50-883-20194-00-00 Current Status:New drill gas well Leg:Leg #2 (SW corner) Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:224-026 First Call Engineer:Ryan Rupert (907) 301-1736 (c) Second Call Engineer:Dan Marlowe (907) 398-9904 (c) Maximum Expected BHP:3,271 psi @ 6,419’ TVD 9.8ppg at Deepest planned perf Max. Potential Surface Pressure: 2629 psi Using 0.1 psi/ft Brief Well Summary Jackup Rig #151 finished drilling and completing Tyonek well A-19 on 8/1/24. The drilling rig is currently skidding to leg #1 for additional drilling. We should be able to access A-19 and A-20 new drills for post-drill work shortly. The well is a closed system currently and is not open to the formation. This procedure addresses the initial post- drill completion wellwork to get the well online. All planned perforations below are within the Tertiary System Gas Pool as defined by CO 68A. The goal of this project is to complete the well Pertinent wellbore information: - TRSSSV installed -Live GLV’s were already installed when the tubing was run - 8/1/24 o CMIT-TxIA to 3000psi PASSED o MIT-T to 3000psi PASSED (also confirmed liner integrity. No TTP was set) Coiled Tubing Procedure 1. MIRU Fox Energy offshore Coiled Tubing and pressure control equipment 2. PT lubricator to 250psi low / 3000psi high a. Multiple wells planned for CT intervention on this leg (#2) b. Hilcorp requests a weekly CT BOP test requirement while on this leg, instead of each well 3. MU cleanout BHA 4. RIH to PBTD and swap well over to water if needed 5. Obtain CBL (may be executed on EL. TBD) Submit CBL to AOOGCC 6. RIH and blow well dry with nitrogen a. Reverse circulate water out of wellbore (no perforations, passing MIT’s) b. Want to evacuate all IA fluid through live GLV’s as well 7. RDMO CT Initial Completion Well: NCIU (Tyonek) A-19 E-Line Perf procedure 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250psi low / 3000psi high 3. Ensure CBL approval from AOGCC before perforating 4. RIH and perforate Beluga gas sands from ±6,561’ - ±8,550’ MD (±4,474’ - ±6,419’ TVD) per RE/Geo a. All proposed perfs within Tertiary System Gas Pool b. Bottom pool is below PBTD c. Top pool is at top Sterling sands (Far above top BEL-A at 6,561’ MD / 4474’ TVD) d. Pressures: i. 9-5/8” at 3435’ TVD: LOT at 13.7PPG ii. Worst case pressure could create a 13.3ppg at the top sundried perf (4474’ TVD) 5. RDMO EL CONTINGENCY plug/patch: (if any zone makes unwanted solids or water) 1. RU nitrogen to tubing and PT lines to 3000psi (or higher if needed) 2. Pressure up on tubing and displace water back into formation 3. MIRU E-line and pressure control equipment 4. PT lubricator to 250psi low / 3000psi high 5. Set 4-1/2” plug or patch per OE 6. RDMO Nitrogen and EL CONTINGENCY CT Cleanout: (if any zone brings in excessive fill and needs to be cleaned out) 1. MIRU Coiled Tubing and pressure control equipment 2. PT lubricator to 250psi low / 3000psi high 3. MU FCO BHA 4. RIH and cleanout to PBTD or as deep as practical a. Working fluid will be water (8.33ppg or greater) b. Take returns to surface up the CT x tubing annulus c. Add foam and nitrogen as necessary to carry solids to surface d. Can use GL to assist with hole cleaning 5. Once cleanout is completed, blow well down with nitrogen 6. RDMO CT Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. CT BOP Drawing (Fox energy) 4. Nitrogen procedure Updated by CJD 8-5-2024 Current SCHEMATIC North Cook Inlet Unit NCIU A-19 PTD: 224-026 API: 50-883-20194-00-00 PBTD = 8,779’ / TVD = 6,646’ TD = 8,824’ / TVD = 6,690’ RKB = 126.6’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 30”Conductor – Driven to Set Depth - - Weld 29” Surf 384’ 9-5/8" Surf Csg 47 L-80 DWC/C 8.681” Surf 5,148’ 4-1/2" Prod Lnr 12.6 L-80 JFELion 3.958” 4,946’ 8,824’ 4-1/2" Prod Tieback 12.6 L-80 DWC/C 3.958” Surf 4,984’ 130” 12-1/4” hole 4-1/2” JEWELRY DETAIL No. Depth Item 1 505’SSSV 2 1,023’ ES Cementer 3 2,225’ GLM 4.5” x 1.5” FO-2” 4 4,852’ GLM 4.5” x 1.5” FO-2” 5 4,916’ X nipple 6 4,974’ Seal Stem 7 4,946’ Liner hanger / LTP Assembly OPEN HOLE / CEMENT DETAIL 9-5/8" TOC @ Surface Stg 1 – 332 bbls Stg 2 - 448 bbls 4-1/2” Est. TOC @ TOL (40% excess) L – 237 bbls / T – 37 bbls 8-1/2” hole 2 4 5/6/7 3 6 _____________________________________________________________________________________ Updated By: JLL 08/05/24 PROPOSED North Cook Inlet Unit NCIU A-19 PTD: 224-026 API: 50-883-20194-00-00 1 2 3/4/5 PBTD = 8,779’ / TVD = 6,646’ TD = 8,824’ / TVD = 6,690’ RKB = 126.6' 30” 12-1/4” hole 8-1/2” hole CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 30”Conductor – Driven to Set Depth - - Weld 29” Surf 384’ 9-5/8" Surf Csg 47 L-80 DWC/C 8.681” Surf 5,148’ 4-1/2" Prod Lnr 12.6 L-80 JFELion 3.958” 4,946’ 8,824’ 4-1/2" Prod Tieback 12.6 L-80 DWC/C 3.958” Surf 4,984’ JEWELRY DETAIL No.Depth (MD) Depth (TVD)Item 1 505’ 505' Baker TE-5 SSSV 2 1,023’ 1,018' ES Cementer 3 4,916’ 3,318' X nipple (GOT) 4 4,974’ 3,347' Seal Stem 5 4,946’ 3,333' Liner hanger / LTP Assembly OPEN HOLE / CEMENT DETAIL 9-5/8" TOC @ Surface Stg 1 – 332 bbls Stg 2 - 448 bbls 4-1/2” Est. TOC @ TOL (40% excess) L – 237 bbls / T – 37 bbls PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status Beluga Gas Sands ±6,561' ±8,550' ±4,474' ±6,419' ±1,989' Future Proposed GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 2,225’ 1,994' 3.833 GLM, 4.5" X 1.5'' FO-2 (BK)16 Dome 750 07/31/2024 2 4,852’ 3,288' 3.833 GLM, 4.5" X 1.5'' FO-2 (Gen 2 Mod)24 Orifice 07/31/2024 KLU A-1 Well Head Rig Up 1 1 1 1 4 1/16" 15K Lubricator - 10 ft 100" Gooseneck HR680 Injector Head 4 1/16" 10K Flow Cross, 2" 1502 10k Flanged Valves 4 1/16" 15K Lubricator - 10 ft API Flange Adapter 10K to 5K for riser/wellhead Hydraulic Stripper 4 1/6" 15K API Bowen CB56 15K 4 1/16" 10K Combi BOPs Blind/Shear Ram Pipe/Slip Ram 4 1/16" 10K bottom flange 4 1/16" 5K flanged Riser - 10 ft if necessary STANDARD WELL PROCEDURE NITROGEN OPERATIONS 09/23/2016 FINAL v-offshore Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Facility Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review 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 Nitrogen Tank. 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 supplier 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 Tank. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 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:Sean McLaughlin To:McLellan, Bryan J (OGC) Subject:Re: [EXTERNAL] NCIU A-19 (PTD 224-026) MPD sundry Date:Wednesday, July 3, 2024 4:00:30 PM Attachments:cid6663013F-8AB9-464F-80B5-065BFF5B587E.pdf On Jul 3, 2024, at 9:41 AM, McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> wrote: Sean, I’m reviewing the MPD sundry application for A-19. A couple requests: 1. The sundry mentioned attached MPD equipment layout diagrams, but they were not attached. Please send piping and instrumentation diagram and indicate where the flow paddle is located in the flow stream of the returned fluids? Also include the BOP+MPD stackup configuration. 2. Please send over the daily reports for NCIU A-20 from when you drilled out the surface casing shoe until today? FYI, I’ll be out of office starting tomorrow through Sunday, so I’m hoping to complete my review today. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 <image001.jpg> 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 theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. MANUAL GATE VALVE ACTUATED BALL VALVE GLOBE VALVE BUTTERFLY VALVE CHECK VALVE NEEDLE VALVE BALL VALVE PRESSURE RELIEF VALVE MANUAL CHOKE VALVE ACTUATED CHOKE VALVE PLUG VALVE PRESSURE GAUGE MANUAL GAUGE VALVE & FITTINGS LEGEND CREATED BY: G. HOUNG DATE: APPROVED BY: R. JACOBO DATE: CLIENT: HILCORP ALASKA WELL: GENERIC P&ID GENERIC GENERIC PFD_BEST_2024_Rev0 RIG: FILENAME: DIAGRAM INFORMATIONNOTES / OBSERVATIONS x THIS IS A STANDARD GENERIC P&ID FOR ILLUSTRATIONS PURPOSES ONLY. x PIPE SPECIFICATIONS, INCLUDING CONNECTION TYPE AND SCHEDULES SHALL BE INCLUDED IN A JOB SPECIFIC P&ID x ALL VALVES SHALL BE TAGGED IN A JOB SPECIFIC P&ID Mud Pump 2 MUD PUMP GV3 GV4 GV1 GV2 BV3 MPD MANIFOLD BUILDING PRVPRV CORIOLIS FLOW METER CK-01CK-01 CK-02CK-02 RIG FLOOR LEVEL CEMENT LINE TO MPD CHOKE BLEED OFF TO FLOWLINEHIGH PRESSUREBLEED OFFLOW PRESSURE BLEED OFFCEMENT LINE BOP STACK BOP STACK LT4 LT3LT2 Rig Floor To Shakers RIG MANIFOLD BUILDING MGS LINECHOKE LINE VENT LINE MUD OUTLET WELL HEAD Pump lines to MPD Choke Mud Pump 1 Injection Pump KNIFE VALVE PP Pneumatic Valve PP PP PP PPPPPP PP PT2 PPPPPPPP PP PPPP PPPPP PPP P PT2 PPPP P PP PPDUMP LINE PT1 BV2 MPD PT STANDPIPESTANDPIPE MANIFOLD P AV P AVCV1CV1 GV5 BV1 PT2PT3 LT5 LT1 BD GV6 TO TRIP TANK RETURN LINE Flow Indicator To Platform Shakers STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________N COOK INLET UNIT A-19 JBR 08/28/2024 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:0 4-1/2" & 5" joints. Test Results TEST DATA Rig Rep:Mitchell/BoydOperator:Hilcorp Alaska, LLC Operator Rep:Hauck/LaFleur Rig Owner/Rig No.:Hilcorp 151 PTD#:2240260 DATE:7/11/2024 Type Operation:DRILL Annular: 250/3000Type Test:INIT Valves: 250/3000 Rams: 250/3000 Test Pressures:Inspection No:bopSAM240716185452 Inspector Austin McLeod Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 7 MASP: 2758 Sundry No: Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 2 P Inside BOP 1 P FSV Misc 0 NA 13 PNo. Valves 1 PManual Chokes 2 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13-5/8"P #1 Rams 1 2-7/8"x5-1/2"P #2 Rams 1 Blinds P #3 Rams 1 5"P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3-1/8"P HCR Valves 2 3-1/8"P Kill Line Valves 3 3-1/16"&3-1/P Check Valve 0 NA BOP Misc 0 NA System Pressure P3100 Pressure After Closure P1700 200 PSI Attained P22 Full Pressure Attained P131 Blind Switch Covers:PAll stations Bottle precharge P Nitgn Btls# &psi (avg)P16@2200 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P12 #1 Rams P10 #2 Rams P10 #3 Rams P10 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P1 9 9 9 9 9999 9 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): 5157'None Casing Collapse Structural Conductor 230 Surface 4760 Intermediate Production Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone:907-223-6784 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 3396'2758 None Monty Myers Drilling Manager Sean McLaughlin sean.mclaughlin@hilcorp.com 7/8/2024 N/A None Perforation Depth MD (ft): N/A N/A 30" 9-5/8" ~384' 5147' ~384' ~3450' ~384' ~5557' N/A TVD Burst N/A MD 1630 6870 Length Size Proposed Pools: North Cook Inlet Tertiary System Gas Pool 3439'5060' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 37831 & 17589 224-026 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20194-00-00 NCIU A-19 Hilcorp Alaska, LLC AOGCC USE ONLY Tubing Grade:Tubing MD (ft): N/A Perforation Depth TVD (ft): Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY 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 Drilling Manager 07/03/24 Monty M Myers 324-386 By Grace Christianson at 8:09 am, Jul 03, 2024 SFD 7/3/2024 See attached conditions of approval for waiver. 10-407 BJM 7/3/24&':IRU-/& Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.07.05 13:37:29 -08'00'07/05/24 RBDMS JSB 070924 NCIU A-19 (PTD 224-026) Sundry #324-386 and Waiver to 20 AAC 25.033(b)(1)(A) conditions of approval ēĖŜϙŜŪĲîŘƅϙŜôŘŽôŜϙÍŜϙÍĲϙÍŕŕŘĺŽÍīϙťĺϙŪŜôϙÍϙîŘĖīīĖĲČϙƲŪĖîϙťēÍťϙîĺôŜϙĲĺťϙēÍŽôϙŜŪƯĖèĖôĲťϙîôĲŜĖťƅϙťĺϙ overbalance the pressure of the uncased portion of the formations penetrated in the 8-3/4” hole section of this well, which requires a waiver to 20 AAC 25.033(b)(1)(A). This waiver is conditional on the following: 1. A Managed Pressure Drilling (MPD) system is to be used to apply the surface pressure required to keep the open hole formations in an overbalanced state whenever the drilling ƲŪĖîϙîôĲŜĖťƅϙĖŜϙĖĲŜŪƯĖèĖôĲťϙťĺϙıÍĖĲťÍĖĲϙĺŽôŘæÍīÍĲèôϙťĺϙťēôϙĺŕôĲϙēĺīôϙċĺŘıÍťĖĺĲŜϟ 2. ēôϙ>Iϯ[iϙŕŘôŜŜŪŘôϙĖŜϙŜŪƯĖèĖôĲťϙťĺϙıÍĖĲťÍĖĲϙѳ30 bbls kick tolerance with a 0.5 ppg kick intensity above the highest anticipated reservoir pressure. This is a relatively high kick tolerance which provides some room for error in MPD choke system failure or human errors associated with kick prevention anîϙſôīīϙèĺĲťŘĺīϙŘôŜŕĺĲŜôϟϙϙXĖèħϙťĺīôŘÍĲèôϙťĺϙæôϙŽôŘĖƱôîϙ using actual FIT/LOT data derived from the test performed after drilling out the previously set casing shoe of this well. i@ϙŽôŘĖƱèÍťĖĺĲϙĺċϙŜŪƯĖèĖôĲťϙ>Iϯ[iϙŘôŜŪīťŜϙŘôŗŪĖŘôîϙ æôċĺŘôϙſÍĖŽôŘϙſĖīīϙæôϙÍŕŕŘĺŽôîϟ 3. īīϙĖĲƲŪƄôŜϙťĺϙæôϙcirculated out per conventional well kill protocols, with closed BOP and ŜīĺſϙŕŪıŕϙŘÍťôϟϙϙa"ϙŜƅŜťôıϙſĖīīϙĲĺťϙæôϙŪŜôîϙċĺŘϙèĖŘèŪīÍťĖĲČϙĺŪťϙĖĲƲŪƄôŜϠϙſēôťēôŘϙťēôϙĖĲƲŪƄϙ occurred while drilling, while making a connection or while tripping, or while conducting any other operation. 4. ôťŪŘĲϙƲĺſϙŜťŘôÍıϙťĺϙæôϙŘĺŪťôîϙťēŘĺŪČēϙťēôϙƲĺſīĖĲôϙÍĲîϙƲĺſϙŕÍîîīôϙîĺſĲŜťŘôÍıϙĺċϙťēôϙ a"ϙèēĺħôϙÍĲîϙĺŘôĺīĖŜϙƲĺſϙıôťôŘϙŜĺϙťēôϙîŘĖīīôŘϙèÍĲϙĺæŜôŘŽôϙèēÍĲČôŜϙťĺϙŘôťŪŘĲϙƲĺſϙŘÍťôϙ independent of the MPD system. 5. Kick while drilling or while tripping drills required with each tour every other day while using ťēôϙa"ϙŜƅŜťôıϙæôČĖĲĲĖĲČϙťēôϙƱŘŜťϙîÍƅϙa"ϙĖŜϙŪŜôîϟϙ 6. TēôϙċĺīīĺſĖĲČϙÍîîĖťĖĺĲÍīϙîŘĖīīŜϙŜēÍīīϙæôϙèĺĲîŪèťôîϙſĖťēϙôÍèēϙťĺŪŘϙĖĲϙťēôϙƱŘŜťϙîÍƅϙťēôϙa"ϙ system is used. a. Loss of MPD choke pressure while making connection. This drill will assume that the loss of choke pressure results in a kick due to being underbalanced. b. >ÍĖīŪŘôϙĺċϙťēôϙîŘĖīīŜťŘĖĲČϙƲĺÍťϙŘôŜŪīťĖĲČϙĖĲϙÍϙƲĺſϙŪŕϙťēôϙîŘĖīīϙŜťŘĖĲČϙîŪôϙťĺϙæôĖĲČϙ underbalanced to the reservoir and because of U-ťŪæôϙôƯôèťϙſĖťēϙMPD pressure on the choke. An additional consideration for this waiver approval is the relatively low uncertainty for the ıÍƄĖıŪıϙŘôŜôŘŽĺĖŘϙŕŘôŜŜŪŘôŜϙĖĲϙťēĖŜϙēĺīôϙŜôèťĖĺĲϙîŪôϙťĺϙťēôϙıŪīťĖŕīôϙŕôĲôťŘÍťĖĺĲŜϙæôīĺſϙťēôϙ Tyonek Platform. Reservoir pressures are well understood and thus the risk of a kick intensity of ѳ͏ϟ͔ϙŕŕČϙÍæĺŽôϙıÍƄϙÍĲťĖèĖŕÍťôîϙŘôŜôŘŽĺĖŘϙŕŘôŜŜŪŘôϙĖŜϙīĺſϟ Well Prognosis Well:NCIU A-19 Date: 7/2/24 Well Name:NCIU A-19 API Number:50-883-20194-00-00 Current Status:Surface Hole Complete Estimated Start Date:7/8/24 Rig:Spartan 151 Reg. Approval Req’d?403 Date Reg. Approval Rec’vd:TBD Regulatory Contact:Cody Dinger 777-8389 Permit to Drill Number:224-026 First Call Engineer:Sean McLaughlin (907)-223-6784 (M) Second Call Engineer AFE Number: A-19 Waiver request to 20 AAC 25.033(b)(1)(A) Description: A combination of hydrostatic pressure and choke pressure will be used to provide overbalance while drilling. The technique is called Managed Pressure Drilling. A-19 is the second well planned to drill with MPD and a waiver. The MPD system will be used to apply surface pressure to keep the open hole formation in an overbalanced state. All influxes to be circulated out per conventional well kill protocols. MPD equipment: ͐ϟ a"ϙ"ŪÍīϙēĺħô o a"ϙĺĲťŘĺīϙĺĲŜĺīô o ĺŘĖĺīĖŜϙċīĺſıôťôŘ ͑ϟ a"ϙôıĺťôϙĺĲťŘĺīϙÍĲôī ͒ϟ "ϙĺîƅ ͓ϟ "ϙôÍŘĖĲČϙÍŜŜôıæīƅϙſĖťēϙŜôÍīĖĲČϙôīôıôĲťŜ ͔ϟ «ÍŘĖĺŪŜϙŕĖŕĖĲČϙÍĲîϙĖŜĺīÍťĖĺĲϙŽÍīŽôŜ MPD layout: Attached Planned Overbalance while drilling: 0.5 ppg Maximum expected choke pressure (static fluid column): 9.1 ppg MW, 9.8 ppg reservoir pressure at 6727’ TVD (TD), 10.3 ppg bottom hole pressure: 420 psi Influx management:. Rig crew to monitor flow and pit levels per standard operations. Rig crew to shut in per standard operations (no change to standing orders). Influx will be managed conventionally. Rig crew training: MPD awareness only. Additional driller responsibility to notify the MPD technician of a change in pump rate. This is a courtesy notification as the system will automatically trap pressure when the pump is shut down. On the job training, as the first 3000’ will be drilled with overbalanced fluid and MPD will only be used to keep constant BHP. Weekly kick while drilling drills while using the MPD system. Attachments 1.Actual Schematic 2.Proposed Schematic Influx will be managed conventionally Not attached. Requested diagram and stack up. Kick while drilling or while tripping drills required with each tour every other day while using the MPD system beginning the first day MPD is used. The following additional drills shall be conducted with each tour in the first day the MPD system is used. 1. Loss of MPD choke pressure while making connection. This drill will assume that the loss of choke pressure results in a kick due to being underbalanced. 2. Failure of the drillstring float resulting in a flow up the drill string due to being underbalanced and because of U-tube effect with pressure on the choke. -bjm All influxes to be circulated out per conventional well kill protocols. Updated by CJD 7-2-2024 Current SCHEMATIC North Cook Inlet Unit NCIU A-19 PTD:224-026 API: 50-883-20194-00-00 PBTD = 5060’ / TVD = ~3396’ TD = 5157’ / TVD = 3439’ RKB = 126.6’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 30”Conductor – Driven to Set Depth - - Weld 29” Surf 384’ 9-5/8"Surf Csg 47 L-80 DWC/C 8.681”Surf 5,148’ 30” 12-1/4” hole JEWELRY DETAIL No.Depth Item 1 1,023’ES Cementer OPEN HOLE / CEMENT DETAIL 9-5/8"TOC @ Surface Stg 1 – 332 bbls Stg 2 - 448 bbls 1 6 TOC @ Surface Stg 1 Updated by CJD 7-2-2024 Proposed SCHEMATIC North Cook Inlet Unit NCIU A-19 PTD:224-026 API: 50-883-XXXXX-00-00 PBTD = 8750’ / TVD = 6,654’ TD = 8824’ / TVD = 6,727’ RKB = 126.6’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 30”Conductor – Driven to Set Depth - - Weld 29” Surf 384’ 9-5/8"Surf Csg 47 L-80 DWC/C 8.681”Surf 5,148’ 4-1/2"Prod Lnr 12.6 L-80 JFELion 3.958”4,948’8,824’ 4-1/2"Prod Tieback 12.6 L-80 TBD 3.958”Surf 4,948’ 130” 12-1/4” hole 4-1/2” JEWELRY DETAIL No.Depth Item 1 ±459’SSSV 2 ±1,006’ES Cementer 3 ±2,360’GLM with Dummy 1-1/2” valve 4 ±4,573’GLM with Dummy 5 ±4,626’X nipple 3.813” Profile 6 ±4,948’Seal Stem 7 ±4,948’Liner hanger / LTP Assembly OPEN HOLE / CEMENT DETAIL 9-5/8"TOC @ Surface Stg 1 – 332 bbls Stg 2 - 448 bbls 4-1/2”Est. TOC @ TOL (40% excess) L – 236 bbls / T – 37 bbls 8-1/2” hole 2 4 5/6/7 3 6 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Sean McLaughlin To:McLellan, Bryan J (OGC) Subject:RE: [EXTERNAL] RE: ***Please Expedite***NCIU A-20 (PTD #224-065) 10-403 Sundry Request Date:Wednesday, July 3, 2024 10:26:32 AM Attachments:image003.png Yes, The rig up, equipment, procedures, and plan will be the same on A-19 and A-21 as it is on the current well, A-20. sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, July 3, 2024 9:54 AM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: FW: [EXTERNAL] RE: ***Please Expedite***NCIU A-20 (PTD #224-065) 10-403 Sundry Request Sean, I assume this information is applicable to NCIU A-19 and NCIU A-21. I plan to attach it to the sundries as reference. Let me know if anything has changed. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Thursday, June 20, 2024 10:54 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] RE: ***Please Expedite***NCIU A-20 (PTD #224-065) 10-403 Sundry Request Bryan, CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. If the mud pump is stopped the MPD choke will automatically be maintaining a set pressure. The MPD choke will automatically trap pressure in the event of a pump shut down. The choke pressure will be set to maintain a constant BHP. The driller doesn’t need to step the pump down or consult with the MPD supervisor. Per the AOGCC concerns the revised procedures keep the systems independent. The driller can shut down pumps and shut in at will. The MPD chokes will prevent a sudden drop in surface pressure if the pumps are stopped suddenly. For reference, the proposed MPD kit is a more advanced system than in use on the CTD rigs. In those operations when the pump speed is changed the choke is manually changed. If the pump stops suddenly then the well will flow until the choke is shut in. Both crews drilled to these standing orders yesterday. There was no confusion in responsibilities. sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, June 20, 2024 10:15 AM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] RE: ***Please Expedite***NCIU A-20 (PTD #224-065) 10-403 Sundry Request Sean, For kick while drilling, can you describe what will be happening with the MPD choke during the period between stopping the pump (Highlighted in yellow in the standing orders below) and upper pipe ram sealing around the drill pipe. Does the MPD choke system automatically trap pressure when pumps go down? If so, how is the pressure level determined? Does the driller need to step the pump rate down slowly to allow the MPD choke to adjust pressures, or will the driller just turn the pumps off immediately, like a switch? If the latter, the sudden drop in surface pressure resulting from pumps going off will result in a period of increased flow until the pipe rams seal around the drill pipe. Even with the simplified approach for MPD, there are still some subtle differences when using underbalanced fluids. These differences need to be clear so there is no confusion in the heat of the moment. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Thursday, June 20, 2024 9:27 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] RE: ***Please Expedite***NCIU A-20 (PTD #224-065) 10-403 Sundry Request Bryan, Here is the additional information you requested: Kick while drilling: If flow is observed the well will be shut in per standing orders (attached). The pumps will be shut down and the upper pipe rams closed. The kick will be handled through conventional well control equipment. This action can happen independent of MPD operations. The MPD annular will be in use and the well is being drilled on a choke so MPD may shut in to arrest flow prior to the well control equipment being activated. Kick while making a connection: : If flow is observed the well will be shut in per standing orders (attached). The well can be shut in independently from MPD operations as back pressure is being applied above the well control equipment. The upper pipe rams can be shut in at will. Again, the MPD annular will be in use and the well is on a choke so MPD may shut in 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. to arrest flow prior to the well control equipment being activated. Please reach out with any further questions. The intent of this revised plan was to ease the AOGCC’s concerns and make well control operations conventional. All the focus will be on holding back pressure on the well to stay in an overbalance state. This is very similar to CTD operations and a common MPD technique. sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, June 19, 2024 5:19 PM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: [EXTERNAL] RE: ***Please Expedite***NCIU A-20 (PTD #224-065) 10-403 Sundry Request The sundry application is not going to be approved. There’s insufficient information to support the waiver. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Wednesday, June 19, 2024 3:55 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: ***Please Expedite***NCIU A-20 (PTD #224-065) 10-403 Sundry Request Bryan, What is the status of the A-20 Change to Approved program? sean From: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Sent: Monday, June 17, 2024 3:30 PM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: McLellan, Bryan J (CED <bryan.mclellan@alaska.gov>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: ***Please Expedite***NCIU A-20 (PTD #224-065) 10-403 Sundry Request Hello, Please expedite. Please see attached electronic distribution for NCIU A-20 (PTD #224-065). Please let me know if you have any questions. Thanks! Thanks, Joe Lastufka Sr. Drilling Technologist Hilcorp North Slope, LLC Office: (907)777-8400, Cell:(907)227-8496 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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. MANUAL GATE VALVEACTUATED BALL VALVEGLOBE VALVEBUTTERFLY VALVECHECK VALVENEEDLE VALVEBALL VALVEPRESSURE RELIEF VALVEMANUAL CHOKE VALVEACTUATED CHOKE VALVEPLUG VALVEPRESSURE GAUGEMANUAL GAUGEVALVE & FITTINGS LEGENDCREATED BY: G. HOUNG DATE:APPROVED BY: R. JACOBODATE:CLIENT: HILCORP ALASKAWELL: GENERIC P&IDGENERICGENERIC PFD_BEST_2024_Rev0RIG:FILENAME:DIAGRAM INFORMATIONNOTES / OBSERVATIONSxTHIS IS A STANDARD GENERIC P&ID FOR ILLUSTRATIONS PURPOSES ONLY.xPIPE SPECIFICATIONS, INCLUDING CONNECTION TYPE AND SCHEDULES SHALL BE INCLUDED IN A JOB SPECIFIC P&IDxALL VALVES SHALL BE TAGGED IN A JOB SPECIFIC P&IDDƵĚWƵŵƉϮMUD PUMP'sϯ'sϰ'sϭ'sϮsϯMPD MANIFOLD BUILDINGWZsCORIOLIS FLOW METER<ͲϬϭ<ͲϬϮZ/'&>KKZ>s>DEd>/EdKDW,K<>K&&dK&>Kt>/E,/',WZ^^hZ>K&&>KtWZ^^hZ>K&&DEd>/EBOPSTACK>dϰ>dϯ>dϮZŝŐ&ůŽŽƌdŽ^ŚĂŬĞƌƐRIG MANIFOLD BUILDINGD'^>/E,K<>/EsEd>/EDhKhd>dt>>,WƵŵƉůŝŶĞƐƚŽDWŚŽŬĞDƵĚWƵŵƉϭ/ŶũĞĐƚŝŽŶWƵŵƉKNIFE VALVEWPneumatic ValveWWWWWWWWdϮW W WWW WWW W hDW>/EWdϭsϮDWWd^dEW/WSTANDPIPE MANIFOLDWssϭ'sϱsϭWdϮWdϯ>dϱ>dϭ'sϲdKdZ/WdE<ZdhZE>/E 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: North Cook Inlet, Tertiary System Gas Pool, NCIU A-19 Hilcorp Alaska, LLC Permit to Drill Number: 224-026 Surface Location: 2404' FNL, 2357' FEL, Sec 1, T11N, R10W, SM, AK Bottomhole Location: 2558' FSL, 1945' FWL, Sec 1, T11N, R10W, 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, Brett W. Huber, Sr. Chair, Commissioner DATED this day of May 2024. Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.05.09 14:08:42 -08'00' WK 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: 8,824' TVD: 6,727' 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): 126.6 15. Distance to Nearest Well Open Surface: x-332034 y- 2586671 Zone-4 N/A to Same Pool:1445' to NCIU A-19A 16. Deviated wells:Kickoff depth: 400 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 60 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 8-1/2" 4-1/2" 12.6# L-80 GBCD 3,892' 4,932' 3,350' 8,824' 6,727' Tieback 4-1/2" 12.6# L-80 Hyd 533 4,932' Surface Surface 4,932' 3,350' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD 384' 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 NCIU A-19 North Cook Inlet Unit Tertiary System Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. 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 L - 1326 ft3 / T - 207 ft3 2758 2404' FNL, 2357' FEL, Sec 1, T11N, R10W, SM, AK 2558' FSL, 1945' FWL, Sec 1, T11N, R10W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 1309' FNL, 1016' FWL, Sec 6, T11N, R9W, SM, AK ADL 17589 / ADL 37831 8328 18. Casing Program:Top - Setting Depth - BottomSpecifications 3431 12-1/4"9-5/8"47# L-80 DWC/C MDSize Plugs (measured): (including stage data) St 1 L - 1592 ft3 / T - 253 ft3 St 2 L - 1572 ft3 / T - 313 ft35,132'Surface Surface 5,132'3,450' Effect. Depth MD (ft):Effect. Depth TVD (ft): Conductor/Structural 30"~384 Authorized Title: Authorized Signature: Authorized Name: Production Liner Intermediate LengthCasing Cement Volume Driven 384' Drilling Manager Monty Myers 5/9/2024 4585' to nearest unit boundary Sean Mclaughlin sean.mclaughlin@hilcorp.com 907-223-6784 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): Perforation Depth MD (ft): Tieback Assy. 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 04/30/24 Monty M Myers By Grace Christianson at 8:55 am, Apr 30, 2024 Requires redaction 50-833-20194-00-00 A.Dewhurst 30APR24BJM 8May24 DSR-4/30/24 See attached conditions of approval 224-026 Diverter waiver request not approved; diverter required. *&: Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr. Date: 2024.05.09 14:09:27 -08'00' JLC 5/9/2024 883 MDG 5/10/2024 NCIU A-19 (PTD 224-ϬϮϲͿWĞƌŵŝƚƚŽƌŝůůŽŶĚŝƟŽŶƐŽĨƉƉƌŽǀĂů 1.&ŝƌƐƚKWƚĞƐƚŝŶϮϬϮϰĚƌŝůůŝŶŐĐĂŵƉĂŝŐŶƚŽϱϬϬϬƉƐŝ͘&ŝƌƐƚĂŶŶƵůĂƌƚĞƐƚƚŽϮϱϬϬƉƐŝ͕ƐƵďƐĞƋƵĞŶƚ KWƚĞƐƚƐƚŽϯϬϬϬƉƐŝ͕ƐƵďƐĞƋƵĞŶƚĂŶŶƵůĂƌƚĞƐƚƚŽϮϱϬϬƉƐŝ͘ 2. 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Well Summary.....................................................................................................................................2 2. Management of Change Information................................................................................................3 3. Tubular Program................................................................................................................................4 4. Drill Pipe Information........................................................................................................................4 5. Internal Reporting Requirements.....................................................................................................5 6. Planned Wellbore Schematic.............................................................................................................6 7. Drilling Summary...............................................................................................................................7 8. Mandatory Regulatory Compliance / Notifications.........................................................................8 9. R/U and Preparatory Work.............................................................................................................11 10. Drill 12-1/4” Hole Section.................................................................................................................12 11. Run 9-5/8” Surface Casing ...............................................................................................................14 12. Cement 9-5/8” Surface Casing .........................................................................................................18 13. ND/NU, Test casing, secure well......................................................................................................23 14. Preparatory Work and Mud Program............................................................................................23 15. BOP N/U and Test.............................................................................................................................25 16. Drill 8-1/2” Hole Section...................................................................................................................25 17. Run 4-1/2” Production Liner ...........................................................................................................27 18. Cement 4-1/2” Production Liner .....................................................................................................29 19. Wellbore Clean Up & Displacement...............................................................................................32 20. Run Completion Assembly...............................................................................................................32 21. BOP Schematic..................................................................................................................................33 22. Wellhead Schematic..........................................................................................................................34 23. Anticipated Drilling Hazards...........................................................................................................35 24. Jack up position ................................................................................................................................36 25. FIT Procedure...................................................................................................................................37 26. Choke Manifold Schematic..............................................................................................................38 27. Casing Design Information ..............................................................................................................40 28. 8-1/2” Hole Section MASP ...............................................................................................................41 29. Plot (NAD 27) (Governmental Sections).........................................................................................43 30. Slot Diagram......................................................................................................................................44 31. Directional Program (wp02) - Attached separately......................................................................45 32. Tyonek Shallow Gas Hazard Analysis - Attached separately.......................................................45 Page 2 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 1. Well Summary Well NCI A-19 Drilling Rig Rig 151 Leg & Slot Leg 2 / Slot 2 Directional plan wp02 Pad & Old Well Designation NA - Grassroots Planned Completion Type 4-1/2”12.6# Liner, 4-1/2” Tubing GL Comp Target Reservoir(s)Beluga A-U Kick off point NA Planned Well TD, MD / TVD 8824’MD / 6727’TVD PBTD, MD 8724’MD AFE Number AFE Days AFE Drilling Amount Work String(s)5” 19.5# S135 NC50 RKB –AMSL 126.6’ MSL to ML 74.10’ Page 3 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 2. Management of Change Information Date: March 27, 2024 Subject: Changes to Approved Permit to Drill File #: NCI A-19 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 April 29, 2024 NCI A-19 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) Conductor (previously installed) 30”Assume 29”--Assume 158#X-56 Weld 1630 230 12-1/4”9.625”8.681”8.525”10.625”47 L-80 DWC/C 6870 4750 1086 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 5”4.276 3.25 6.625 19.5 S-135 NC50 15,638 10,029 560k optional 4-1/2”3.826 2.6875”5.25”16.6 S-135 DS40 16,176 10,959 468k Page 5 April 29, 2024 NCI A-19 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 mmyers@hilcorp.com, cdinger@hilcorp.com, sean.mclaughlin@hilcorp.com 3. EHS Incident Reporting x Notify EHS field coordinator. i. Garrett St. Clair: C: (907) 252-7780 x Spills: i. Adrian Kersten: C: 907-564-4820 ii. Monty Myers: O: 907-777-8431 C: 907-538-1168 iii. Sean Mclaughlin x Report ALL spills to the water within 15 minutes. 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 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 6. Planned Wellbore Schematic Page 7 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 7. Drilling Summary A-19 is an 8824’ MD / 6727’ TVD development gas well drilled from leg 2 slot #2 off the Tyonek platform. The base plan is an infill wellbore to the Beluga U. The well will be completed with a 4-1/2”gas lift tie-back completion. Drilling operations are expected to commence approximately May 2023. General sequence of operations pertaining to this drilling operation: Pre-Rig Work: x Set plug in A-15 X NIP at 5809’, bleed well (no fluid required on top of plug, perform negative test) x No Gyro required, use 2008 eline gyro (run to 1900’) Rig Work 1. Rig 151 will MIRU over leg 2, slot 2 x Diverter waiver requested 2. MU 12-1/4” bit with 8” drilling tools (GR/RES) 3. Drill 12-1/4” hole to 5132’ MD. Run and cmt 9-5/8” casing (2 stages). x Gyro Required due to close approach 4. N/D riser and N/U casing head 5. Test casing to 3500 psi. Secure well with BPV and dryhole tree 6.Secure well and skid Rig to A-20 Stop operations for batch drilling. Move Rig to A-20 to drill surface and production hole. Then back to A-19 to drill the production hole. 7. Move rig to A-19 8. N/U and test 13-5/8” x 5M BOP to 3000 psi, Rig up MPD equipment 9. MU 8-1/2” bit with 6-3/4” tools (Triple Combo, GeoTap to be picked up during a short trip) 10. Mill shoe track with 20’ of new formation. 11. Perform FIT to 14.8 ppg EMW 12. Drill 8-1/2” production hole to 8824 MD, performing short trips as needed x MPD equipment to be used as primary well control barrier x NOV Agitator tool to be used to reduce stick slip if necessary x RFT with GeoTap per Asset team 13. Swap well over to KWF. POOH w/ directional tools. 14. RIH w/ 4-1/2” liner. Set liner and cement. Circ wellbore clean. 15. Perform Clean out run to polish bore, LDDP 16. Perform liner lap test to 2000 psi. 17. Run 4-1/2”gas lift completion. Bleed pressure off inner annulus, perform negative test. -bjm Page 8 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 18. Land hanger and test.MIT-T to 3000 psi, MIT-IA to 3000 psi 19. ND BOPE, NU tree and test void Reservoir Evaluation Plan: 1. Surface hole: GR + Res LWD 2. Production Hole: Triple Combo LWD + GeoTap RFT 8. 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 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 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 3431 psi in the Beluga U sand (6727' TVD). MASP is 2758 psi with 0.1psi/ft gas in the wellbore. 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. x Notice of Batch Drilling: A-19 and A-20 will be batch drilled. Conductors previously installed. Both surface holes will be drilled without diverter, casing run, and fully cemented. Then each production hole section will be drilled. AOGCC Regulation Waiver and Variance Requests: First test in 2024 summer drilling campaign to 5000 psi, rated working pressure of BOPs. First annular test to 2500 psi -bjm Page 9 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx x 20 AAC 25.035(h)(2) - Diverter waiver Request:The request is to not use a diverter for drilling surface hole on the Tyonek Platform. From analysis, and drilling experience of existing wells on the Tyonek Platform, Hilcorp does not anticipate any significant gas at depths between surface and the Sterling X. The Tyonek Platform is isolated geographically and is the furthest North Platform in the inlet. There are 22 penetrations from the Tyonek Platform that validate shallow geologic structure and risk. Mudlogs from surface are available for four wells (A-10A, A-13, B-01, and B-03). Five grassroots wells have been drilled since 2009, all with surface casing shoe depths of 3202’ -3498’ TVD (above the Sterling X). The Sterling sands below the casing shoe are depleted, low pressure sands. No accumulation of significant hydrocarbons exist above the Sterling X sands. Due to the nature of platform drilling, surface holes are closely grouped with little geographical differences. A shallow geologic hazard analysis will be attached separately. x 20 AAC 25.033 Variance Request:Managed Pressure Drilling equipment and technique will be used for primary well control in place of drilling mud while drilling the 8-1/2” production hole. Kill weight fluid will be used for primary well control during surface hole and running liner. Benefits of using MPD with hydrostatically underbalanced mud weight: o Ability to utilize lighter mud weight and compensate for ECD difference through SBP (Surface Back Pressure) to stay above PP/wellbore stability o Improve ROP and minimize differential sticking o Ability to increase or reduce EMW downhole by adjusting SBP, without going through the process of displacing to new mud weight. o More effective downhole pressure control when comes to high pressure or abnormal pressure regimes. o Coriolis flowmeter is able to measure small flowrates difference (up to +/- 0.10% of flow rate accuracy for liquid, technical specs sheet as per attached) thus able to identify influx or losses before it's picked up by the conventional PVT system. o Applying constant SBP can help to minimize ballooning and swabbing. o Holding SBP during connections help to minimize pressure cycling in the sensitive formation o With RCD and MPD Choke manifold in place, the drilling system is going to be closed loop all the time where MPD chokes will be opening and closing automatically depending on flowrates down the string to apply desired target SBP. o While ensuring SBP is applied constantly (except during the cases of losses), any flow is diverted away from the rig floor. Equipment and Generic Flow path: o Major Equipment includes: 1. MPD Choke Manifold Building (With MPD Choke Manifold) o MPD Control Console (inside MPD Choke Manifold Building) o Coriolis flowmeter spool (inside MPD Choke Manifold Building) 2. MPD Remote Control Panel 3. RCD Body Waiver not recommended. Review of the offset well NCIU A-10A (PTD 203-075) mudlog indicates significant gas at less than 2,000’ TVD. -A.Dewhurst 30APR24 This variance request is not approved as of the date of permit approval, but is still under review. This permit is approved for MPD operations with mud density sufficient to overbalance the highest anticipated reservoir pressure 9.8 ppg without surface pressure applied. - bjm Page 10 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 4. RCD Bearing assembly with sealing elements (installed into RCD Body) 5.Various piping (4” and 2”) and hoses (4” and 2”) 6. Isolation valves o A general flow path diagram is as follows. An actual flow path diagram will be created during rig up and prior to drilling with MPD. Contingency: o There will be sufficient weighting material on location to bring the drilling mud up to KWF weight. Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 12-1/4 x 21-1/4” Riser N/A 8-1/2” x 13-5/8” Shaffer 5M annular x 13-5/8” 5M Shaffer SL Double gate x Blind ram in bottom cavity Initial Test: 250/3000 (Annular 2500 psi) Page 11 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx x Mud cross x 13-5/8” 5M Shaffer SL single gate x 3-1/16” 5M Choke Manifold x Standpipe, floor valves, etc Subsequent Tests: 250/3000 (Annular 2500 psi) x Primary closing unit: Masco 7 station, 15 bottle, 3000 psi closing unit with two air pumps, a triplex electric driven pump 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) 9. R/U and Preparatory Work 1. N/U 21-1/4” 2M riser to 30” starting head 2. Mix WBM mud for 12-1/4” hole section. 3. Set test plug in wellhead prior to N/U riser to ensure nothing can fall into the wellbore if it is accidentally dropped. 4. Install 7” liners in mud pumps. Plan to pump at 1000 gpm to clean the 30”conductor. 7” liners will deliver 575 gpm @ 98% eff @ 3623 psi. Page 12 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 10. Drill 12-1/4” Hole Section 1. N/U 21-1/4” Riser. 2. 12-1/4” hole mud program summary: x Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 9.2ppg. x 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, and Toolpusher office. System Type: 8.9 –9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 327’ – 5132’8.9 – 9.5 80-120 20 - 40 35 - 55 <10 8.5 – 9.5 System Formulation: Aquagel / FW spud mud Product Concentration Fresh Water soda Ash AQUAGEL BARAZAN D+ PAC-L /DEXTRID LT BARACARB 5/25/50 STEELSEAL 50/100/400 BAROFIBRE BAROID 41 0.905 bbl 0.5 ppb 15 -25ppb as needed if required for <10 API FL 5 ppb total 5 ppb total 4.0 ppb as required for weight 8.8 –9.2 ppg Rig up and function test diverter. -bjm Page 13 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx caustic soda ALDACIDE G 0.1 ppb (8.5 –9.5 pH) 0.1 ppb AQUAGEL and BARAZAN D+ should be used to maintain rheology. Begin system with a 55 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 - 20 ppb total) BARACARBs/BAROFIBRE/STEELSEALs should be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. While drilling, monitor the torque and drag to determine if liquid lubricant is required. If so, approval from town will be required prior to additions of lubricants. Additions of CON DET PRE- MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating high-clay content sections. Maintain the pH in the 8.5 –9.5 range with caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action. Mix a ~50 bbl LCM pill prior to drilling out of the conductor, to be available for immediate use if losses are seen drilling the Surface hole. The pill formulation will be the 50 ppb pill from the LCM tree. Mix the recommended LCM material in thinned back base mud. Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). Sweep Formulations: 20 barrels mud, add 1.0 ppb BARAZAN D. Additions of CON DET PREMIX are recommended when penetrating high-clay content sections to reduce the incidence of bit balling and shaker blinding. At TD, a Walnut “flag” (20 bbl pill with 15 ppb of Wallnut M) could be pumped to gauge hole washout - to help calculate the required cement volume. The cement will then be pumped and drilling mud will be used to bump the plug. Pretreat this chase mud with 1 ppb Bicarb and 0.5 ppb citric acid. 3. MU 12-1/4” milltooth bit with 8” Drilling o UBHO required for gyro work o GR/RES can be picked up after gyro work is complete o Ensure BHA components have been inspected previously. o Drift and caliper all components before M/U. o Pump at 1000 gpm to clean the hole effectively. 4. TIH to top of fill in the 30” conductor. Fill was tagged at 327’during prerig magnet run.. 5.Displace hole to spud mud and begin drilling out cmt plug at 350’ to 400’. This plug will be approx. 50 –100 ft thick. Page 14 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 6. Drill 12-1/4” hole section until clear of AC hazard. x A-15 tubing plug set as part of the pre rig work x Frequent Gyro survey required to reduce AC risk x There is a close approach with A-15. o A-15- Producer, Top perforation in the Beluga at 4870’ TVD 2.2’ cen-cen distance at 460’, Tubing plug to be set in X NIP, confirm no flow test. x GR/RES only for surface hole. x Rationale for casing shoe depth is ~40’ TVD above CI sands and ~40’ TVD below disposal zone. Same surface casing plan as A-14, A-15, A-16 drilled by Conoco in 2009. x Pump at 900 - 1000 gpm. 900 gpm equates to an annular velocity of 170 fpm in the openhole, and 27 fpm in the 30” casing which is poor for effective hole cleaning. Short trips and sweep will be required. Ensure shaker screens are set up to handle this flowrate. x Circulate hole clean and pump sweep before dropping rate to prevent fall back and sticking. Maximize drill string RPMs, Pump sweeps and 6rpm rheology (target 10) to ensure effective hole cleaning. x Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team. Work through coal seams once drilled. x Keep swab and surge pressures low when tripping. x Pull wiper trips as often as necessary. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Take MWD surveys every stand drilled. 11. Run 9-5/8” Surface Casing 1. R/U and pull wear bushing. 2. R/U PESI (Volant) 9-5/8” casing running equipment x Ensure 9-5/8” TXP x NC50 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Plan to rig up Volant CRT if available x R/U a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted to 8-1/2” on the location prior to running. x Note that 47# drift is 8.525” x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 3. P/U shoe joint, visually verify no debris inside joint. 4. Continue M/U & thread locking 120’ shoe track assembly consisting of: 9-5/8” Float Shoe 1 joint –9-5/8” TXP, 1 Centralizer 10’ from bottom w/ stop ring ~40’ TVD below disposal zone. Page 15 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 1 joint –9-5/8” TXP, NO Centralizer 9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’ 1 joint –9-5/8” TXP, 1 Free floating centralizer 9-5/8” HES Baffle Adaptor x Ensure bypass baffle is correctly installed on top of float collar. x Ensure proper operation of float equipment while picking up. x Ensure to record S/N’s of all float equipment and stage tool components. This end up. Bypass Baffle Page 16 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 5. Float equipment and Stage tool equipment drawings: Page 17 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 6. Continue running 9-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: x 1 centralizer every joint to 5 joints below the ES Cementer x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. x Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 7. Install the Halliburton Type H ES-II Stage tool so that it is positioned at ~600’ MD below the conductor. x Install free floating centralizers on 5 joints below and 5 joints above stage tool. x Do not place tongs on ES cementer, this can cause damage to the tool. x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi. Page 18 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 8. Continue running 9-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: No centralizers in the conductor. 9. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 10. Slow in and out of slips. 11. P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 12. Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. Conventional circulation is not permissible once casing hanger is landed. 13. P/U and R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 14. After circulating, lower string and land hanger in wellhead again. Cement returns will be out the 2 x 4” side outlets. Ensure hose is in place to take returns and dump into the inlet over the side of the platform. 12. Cement 9-5/8” Surface Casing 1. Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amount of water for mix fluid is heated and available in the water tanks. x Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses x Review test reports and ensure pump times are acceptable. Page 19 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 2. Document efficiency of all possible displacement pumps prior to cement job. 3. Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 4. R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 5. Fill surface cement lines with water and pressure test. 6. Pump remaining 60 bbls 10.5 ppg tuned spacer. 7. Drop bottom plug (flexible bypass plug) –HEC rep to witness. Mix and pump cement per below calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached. 8. Cement volume based on annular volume + 40% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. Estimated 1st Stage Total Cement Volume: Cement Slurry Design (1st Stage Cement Job): Lead Slurry Tail Slurry System EconoCem HalCem Density 12.0 lb/gal 15.3 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk verified cement calcs. -bjm Page 20 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 9. Attempt to reciprocate casing during first stage cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation, land hanger, and continue with the cement job. 10. After pumping cement, drop top plug (shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 11. Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug must be bumped. 12. Land hanger. 13. Displacement calculation is in the Stage 1 Table above. 73 bbls of tuned spacer to be left on top of stage tool so that the first fluid through the ES cementer is tuned spacer to minimize the risk of flash setting cement 14. Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. 15. If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 1 shoe track volume, ±6 bbls before consulting with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 16. Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 17. Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. Page 21 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 18. Be prepared for cement returns to surface. Cement return to be taken overboard. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. Second Stage Surface Cement Job: 19. Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Hold pre-job safety meeting. 20. HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 21. Fill surface lines with water and pressure test. 22. 73 bbls of Spacer is already in the casing string. 23. Mix and pump cmt per below recipe for the 2nd stage. 24. Cement volume based on annular volume + 40% open hole excess. Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated 2nd Stage Total Cement Volume: cement will continue to be pumped until clean spacer is observed at surface. 100% OH excess used in table below. -bjm + 40% open hole excess Page Page 22 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx Cement Slurry Design (2nd stage cement job): 25. Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 26. After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 27. Displacement volume is in the Stage 2 table above. 28. Monitor returns closely while displacing cement. Adjust pump rate if necessary. Cement return will be taken from 2 x 4” outlets and sent overboard. 29. Land closing plug on stage collar and pressure up to 1000 –1500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. 30.Close 4” valves on wellhead side outlet and monitor pressure build up. 31. R/D cement equipment. Flush out wellhead with FW. 32. Back out and L/D landing joint. Flush out wellhead with FW. 33. M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 34. Lay down landing joint and pack-off running tool. 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 casing is reciprocated or rotated during the job x Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure Lead Slurry Tail Slurry System EconoCem HalCem Density 12.0 lb/gal 15.3 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk Page 23 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to sean.mclaughlin@hilcorp.com and cody.dinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. 13. ND/NU, Test casing, secure well 1. N/D the Riser 2.N/U 11” 5M multi-bowl wellhead assy. Install 9-5/8” packoff P-seals. Test to 3000 psi. 3. Test casing to 3500 psi. 30 min charted. 4.Secure well with hanger, BPV, and dryhole tree then and slide rig to A-20 14. Preparatory Work and Mud Program 1. Move to A-19 and rig up for Managed Pressure Drilling operations. 2. Mix 9.0 WBM mud for 8-1/2” hole section. 3. 6” liners installed in mud pump #1 and pump #2. (PZ-10’s) x Gardner Denver PZ-10’s Pumps are rated at 4932 psi (98%) with 6” liners and can deliver 422 gpm at 115 spm. x Pump range for drilling will be 400-500 gpm. This can be achieved with one or both pumps. Mix 9.0 WBM Page 24 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 4. 8-1/2” Production hole mud program summary: x Primary weighting material to be used for the hole section will be barite to minimize solids. Ensure enough barite is on location to weight up the active system 1ppg above highest anticipated KWF in the event of a well control situation. x 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, and Toolpusher office. x MPD will be used to add pressure to the hydrostatic mud column to provide primary well control. o PWD will be used to monitor the annular pressure and adjust surface pressure based on ECD. x KWF or a spike pill will be required when swapping out a BHA or running liner. System Type: LNSD WBM Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 5132’-TD 8.8-10.1 40-53 6-15 13-24 8.5-9.5 11.0 System Formulation: 2% KCL/BDF-976/GEM GP Product Concentration Water KCl Caustic BARAZAN D+ DEXTRID LT PAC L BDF-976 GEM GP BARACARB 5/25/50 STEELSEAL 50/100/400 BAROFIBRE BAROTROL PLUS SOLTEX BAROID 41 ALDACIDE-G 0.905 bbl 7 ppb 0.2 ppb (9 pH) 1.0 ppb (as required 18 YP) 1-2 ppb 1 ppb 4 ppb 1.0% by volume 5 ppb (1.7 ppb of each) 5 ppb (1.7 ppb of each) 1.7 ppb 4.0 ppb 2 –4 ppb as needed 0.1 ppb 5. Program mud weights are generated by reviewing data from producing & shut in offset wells, estimated BHP’s from formations capable of producing fluids or gas and formations which could require mud weights for hole stabilization. 6. A guiding philosophy will be that it is less risky to weight up a lower weight mud than be overbalanced and have the challenge to mitigate lost circulation while drilling ahead. p MPD will be used to add pressure to the hydrostatic mud column to provide primary well control. Page 25 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 15. BOP N/U and Test 1. N/U 13-5/8” x 5M BOP as follows (top down): x Dual RCD (Beyond Energy) x 13-5/8” x 5M Shaffer annular BOP. x 13-5/8” 5M Shaffer Type SL Double ram. (2-7/8” X 5” VBR in top cavity, blind ram in btm cavity) x 13-5/8” mud cross x 13-5/8” 5M Shaffer Type SL single ram. (2-7/8” X 5” VBR) x N/U pitcher nipple, install flowline. x Install (2) manual valves on kill side of mud cross. Manual valve used as inside or “master valve”. x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. x 11” 5M adapter required 2. Run BOPE test plug. 3. Test BOPE. x Test BOP to 250/3000 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” and 5” test joints (3000 psi) x Test Annular on 4-1/2” test joint (2500 psi) x Ensure gas monitors are calibrated and tested in conjunction w/ BOPE. 4. Pull test plug. 16. Drill 8-1/2” Hole Section 1.M/U 8.5” Cleanout BHA (Milltooth Bit & 1.22°PDM) 2. TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool. 3. TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 4.Drill out shoe track and 20’ of new formation. 5. CBU and condition mud for FIT. Pump at least one high vis sweep at maximum rate to surface to clean up debris. 6. Conduct FIT to 14.8 ppg EMW. Chart test. Document incremental volume pumped (and subsequent pressure) and volume returned. x 14.8 ppg with 9.8 ppg BHP and 9.2ppg mud equates to an 66 bbl KTV Page 26 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 7. POOH & LD Cleanout BHA 8. Drift & caliper all MWD components before M/U. Visually verify no debris inside components that cannot be drifted. 9. Ensure TF offset is measured accurately and entered correctly into the MWD software. 10. Have DD run hydraulics models to ensure optimum TFA. Plan to pump at 400-500 gpm. 11. P/U 8-1/2” PDC bit and 6-3/4” Sperry Sun motor drilling assy w/ triple combo (DEN, POR, RES, GeoTAP). 12. Production section will be drilled with a motor. Must keep up with 4 deg/100 DLS in the build and drop sections of the wellbore. 13. TIH to window. Shallow test MWD on trip in. 14. Drill 8-1/2” hole to 8824’ MD using motor assembly. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. x Keep swab and surge pressures low when tripping. x See attached mud program for hole cleaning and LCM strategies. x Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. x Adjust ECD with MPD as necessary to maintain hole stability. x Ensure mud engineer set up to perform HTHP fluid loss. x Maintain API fluid loss < 6. x Take MWD surveys every stand drilled. x Minimize backreaming when working tight hole 15. At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement calculations. CBU, and swap well to KWF. KWF dependent on pressures observed while drilling. Flow check well for 10 minutes. 16. TOH with drilling assembly, handle BHA as appropriate. Page 27 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 17. Run 4-1/2” Production Liner 1. R/U Baker 4-1/2” liner running equipment. x Ensure 5” NC50 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: 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 to 6500’ and every other joint above that. x Ensure proper operation of float shoe & FC. 4. Continue running 4-1/2” production liner to TD x Short joint run every 1000’, RA Tag 1000’ and 2000’ from bottom. 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. Page 28 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 5.Ensure to run enough liner to provide at least 100’ overlap inside casing. Ensure setting sleeve will not be set in a connection. 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. Page 29 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 12. Circulate 1-1/2 drill pipe and liner volume at 9-5/8” shoe 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. 18. 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 15 bbls 12.5 ppg spacer. 4. Test surface cmt lines to 4500 psi. 5. Pump remaining 10 bbls 12.5 ppg spacer. 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. Page 30 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx Slurry Information: 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 Lead Slurry Tail Slurry System EconoCem HalCem Density 12.0 lb/gal 15.3 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk Verified cement calcs -bjm Page 31 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 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. 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. Page 32 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 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 19. 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 3000 psi after cement has reached 500 psi compressive strength. 10 min operational assurance test. 20. 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 SSSV to be placed at 500’ x CIM to be placed at 2000’ x GLM will be run (depths TBD) 2. Swap the well over to FIW x Circulate a hi-vis pill followed by a soap train per Baroid x Circulate FIW until clean-up is satisfactory. x Leave FIW in the annulus. Page 33 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 3. Space out and land seal bore in tie back sleeve. RILDs. 4.Test IA to 3000 psi and tubing to 3000 psi. Charted 30 min test per AOGCC 5. Install BPV in wellhead. 6. ND BOPE, NU tree, test void 7. Rig Down 21. BOP Schematic Page 34 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 22. Wellhead Schematic Page 35 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 23. Anticipated Drilling Hazards Lost Circulation: Drill depleted reservoir may cause loss circulation events (as seen in the 2021 program on A-03A and A-01A) x Maintain sufficient volumes while drill. x Maintain ability to take on FIW during drilling phase x If a LC event occurs pumping cement will be the likely remedy Ensure 500 lbs of medium/coarse fibrous material, 500 lbs SteelSeal (Angular, dual-composition carbon-based material), & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ viscofier as necessary. Sweep hole w/ 20 bbls flowzan as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain programmed mud specs. 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. x Minimize swab and surge pressures x Minimize back reaming through coals when possible H2S: H2S is not present in this hole section. Anti Collision: Drill out of conductor with mill tooth bit, gyro, monitor annuli in offset well. There is a close approach with A-15. A-15 will be resurveyed and plugged. Page 36 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 24. Jack up position Page 37 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 25. 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 38 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 26. Choke Manifold Schematic Page 39 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx Page 40 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 27. Casing Design Information Page 41 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 28. 8-1/2” Hole Section MASP Page 42 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx Page 43 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 29. Plot (NAD 27) (Governmental Sections) Page 44 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 30. Slot Diagram A-19 Page 45 April 29, 2024 NCI A-19 Drilling Program APD xxx-xxx 31. Directional Program (wp02) - Attached separately. 32. Tyonek Shallow Gas Hazard Analysis - Attached separately. !"" # ! # ! -500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 Tr u e V e r t i c a l D e p t h ( 1 0 0 0 u s f t / i n ) 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 Vertical Section at 252.00° (1000 usft/in) NCI A-19 wp02 Tgt1 Base Beluga A NCI A-19 wp02 Tgt2 Beluga M 9 5/8" x 12 1/4" 4 1/2" x 8 1/2" 50 0 1 0 0 0 1 5 0 0 2 0 0 0 2500 3000 3500 4000 4500 5000 5 5 0 0 6 0 0 0 6 5 0 0 7 0 0 0 7 5 0 0 8 0 0 0 8 5 0 0 8 8 2 4 NCIU A-19 wp02 Start Dir 2º/100' : 400' MD, 400'TVD Start Dir 2.5º/100' : 750' MD, 749.13'TVD End Dir : 2365.22' MD, 2066.81' TVD Start Dir 3º/100' : 5215.22' MD, 3491.81'TVD End Dir : 6881.88' MD, 4814.16' TVD Total Depth : 8824' MD, 6726.77' TVD Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: Plan: NCIU A-19 Water Depth: 101.00 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 2586671.01 332034.02 61° 4' 35.8029 N 150° 56' 54.8122 W SURVEY PROGRAM Date: 2024-03-05T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 52.53 1200.00 NCIU A-19 wp02 (NCIU A-19) 3_Gyro-CT_Csg 1200.00 5132.00 NCIU A-19 wp02 (NCIU A-19) 3_MWD+AX+Sag 5132.00 8824.00 NCIU A-19 wp02 (NCIU A-19) 3_MWD+AX+Sag REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: NCIU A-19 - Slot 2002, True North Vertical (TVD) Reference:Prelim @ 126.63usft (151) Measured Depth Reference:Prelim @ 126.63usft (151) Calculation Method:Minimum Curvature Project:North Cook Inlet Site:North Cook Inlet Unit Well:Plan: NCIU A-19 Wellbore:NCIU A-19 Design:NCIU A-19 wp02 CASING DETAILS TVD TVDSS MD Size Name 3450.00 3323.37 5131.59 9-5/8 9 5/8" x 12 1/4" 6726.77 6600.14 8824.00 4-1/2 4 1/2" x 8 1/2" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 52.53 0.00 0.00 52.53 0.00 0.00 0.00 0.00 0.00 2 400.00 0.00 0.00 400.00 0.00 0.00 0.00 0.00 0.00 Start Dir 2º/100' : 400' MD, 400'TVD 3 750.00 7.00 270.00 749.13 0.00 -21.35 2.00 270.00 20.31 Start Dir 2.5º/100' : 750' MD, 749.13'TVD 4 1000.00 12.24 248.71 995.60 -9.63 -61.32 2.50 -45.00 61.30 Start Dir 3.5º/100' : 1000' MD, 995.6'TVD 5 2365.22 60.00 252.00 2066.81 -259.51 -801.82 3.50 3.85 842.77 End Dir : 2365.22' MD, 2066.81' TVD 6 5215.22 60.00 252.00 3491.81 -1022.22 -3149.19 0.00 0.00 3310.94 Start Dir 3º/100' : 5215.22' MD, 3491.81'TVD 7 6881.88 10.00 252.00 4814.16 -1308.34 -4029.79 3.00 180.00 4236.85 End Dir : 6881.88' MD, 4814.16' TVD 8 8824.00 10.00 252.00 6726.77 -1412.56 -4350.53 0.00 0.00 4574.10 Total Depth : 8824' MD, 6726.77' TVD -2 4 7 5 -2 2 0 0 -1 9 2 5 -1 6 5 0 -1 3 7 5 -1 1 0 0 -8 2 5 -5 5 0 -2 7 5 0 27 5 55 0 82 5 11 0 0 13 7 5 South(-)/North(+) (550 usft/in) -4 6 7 5 - 4 4 0 0 - 4 1 2 5 - 3 8 5 0 - 3 5 7 5 - 3 3 0 0 - 3 0 2 5 - 2 7 5 0 - 2 4 7 5 - 2 2 0 0 - 1 9 2 5 - 1 6 5 0 - 1 3 7 5 - 1 1 0 0 - 8 2 5 - 5 5 0 - 2 7 5 0 2 7 5 5 5 0 We s t ( - ) / E a s t ( + ) ( 5 5 0 u s f t / i n ) NC I A - 1 9 w p 0 2 T g t 2 B e l u g a M NC I A - 1 9 w p 0 2 T g t 1 B a s e B e l u g a A 9 5 / 8 " x 1 2 1 / 4 " 4 1 / 2 " x 8 1 / 2 " 25 0 500 750100 0 1 2 5 0 1 5 0 0 1 7 5 0 2 0 0 0 2 2 5 0 2 5 0 0 2 7 5 0 3 0 0 0 3 2 5 0 3 5 0 0 3 7 5 0 4 0 0 0 4 2 5 0 4 5 0 0 4 7 5 0 5 0 0 0 5 2 5 0 5 5 0 0 5 7 5 0 6 0 0 0 6 2 5 0 6 5 0 0 6 7 2 7 N C I U A -1 9 w p 0 2 St a r t D i r 2 º / 1 0 0 ' : 4 0 0 ' M D , 4 0 0 ' T V D St a r t D i r 2 . 5 º / 1 0 0 ' : 7 5 0 ' M D , 7 4 9 . 1 3 ' T V D St a r t D i r 3 . 5 º / 1 0 0 ' : 1 0 0 0 ' M D , 9 9 5 . 6 ' T V D En d D i r : 2 3 6 5 . 2 2 ' M D , 2 0 6 6 . 8 1 ' T V D St a r t D i r 3 º / 1 0 0 ' : 5 2 1 5 . 2 2 ' M D , 3 4 9 1 . 8 1 ' T V D En d D i r : 6 8 8 1 . 8 8 ' M D , 4 8 1 4 . 1 6 ' T V D To t a l D e p t h : 8 8 2 4 ' M D , 6 7 2 6 . 7 7 ' T V D CA S I N G D E T A I L S TV D TV D S S M D Si z e N a m e 34 5 0 . 0 0 3 3 2 3 . 3 7 5 1 3 1 . 5 9 9 - 5 / 8 9 5 / 8 " x 1 2 1 / 4 " 67 2 6 . 7 7 6 6 0 0 . 1 4 8 8 2 4 . 0 0 4 - 1 / 2 4 1 / 2 " x 8 1 / 2 " Pr o j e c t : N o r t h C o o k I n l e t Si t e : N o r t h C o o k I n l e t U n i t We l l : P l a n : N C I U A - 1 9 We l l b o r e : N C I U A - 1 9 Pl a n : N C I U A - 1 9 w p 0 2 WE L L D E T A I L S : P l a n : N C I U A - 1 9 Wa t e r D e p t h : 1 0 1 . 0 0 +N / - S + E / - W No r t h i n g Ea s t i n g La t i t u d e Lo n g i t u d e 0. 0 0 0 . 0 0 25 8 6 6 7 1 . 0 1 3 3 2 0 3 4 . 0 2 6 1 ° 4 ' 3 5 . 8 0 2 9 N 1 5 0 ° 5 6 ' 5 4 . 8 1 2 2 W RE F E R E N C E I N F O R M A T I O N Co - o r d i n a t e ( N / E ) R e f e r e n c e : We l l P l a n : N C I U A - 1 9 - S l o t 2 0 0 2 , T r u e N o r t h Ve r t i c a l ( T V D ) R e f e r e n c e : Pr e l i m @ 1 2 6 . 6 3 u s f t ( 1 5 1 ) Me a s u r e d D e p t h R e f e r e n c e : Pr e l i m @ 1 2 6 . 6 3 u s f t ( 1 5 1 ) Ca l c u l a t i o n M e t h o d : Mi n i m u m C u r v a t u r e $ % & " ' ()* ' + +, -.& - /# ! 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" , & + - 0 & * '( ) * % * ' ( * % * * % " / & / + + & " " / & / - , + / & " / " & / + - + & ( * '( ) * / * ' ( * / * * / +. & % 0 0 - & % + , - & - 0 " - & , " - & / / / 0 - & % + ( * '( ) * / * ' ( * / * * / +. & / 0 % & , - & " - 0 0 & " / " + & - + " 0% & * '( ) * / * ' ( * / * * / .1 - & + . + 1 + 0 & 1 , - " & + , 1 - , & + , & . , 0 +1 + 0 & ( * '( ) * , * ' ( * , * * , -" & + 0 , % & - & + / 0 & . % % + & + - / ,% & ( * & ! " # $ " " # $ % / " / > " ' ( 89 - ' 9 ' , & . 4 , & . 89 - ' < - - 3 < & & -3 9 * 4 - (! 3 0 0 3 & 3 9 - ' 3 ) ' * + ' , ( - & . & ' (! " ! " # $ " " # $ " " # $ % 9 - ' ; - 9 / ( '( ) * , * ' ( * , * * , - & / 0 % & + + & % 0 " . & + & / - - 0 % & * '( ) * , * ' ( * , * * , "0 & 0 - % & " . " & % + - . - & , / " . & % + -% & ( * '( ) * + * ' ( * + * * + +0 & - , 0 & , - & 0 % . + - & . , " % & . - 0 0 & ( * '( ) * + * ' ( * + * * + +% & . " 0 % & , - & " - 0 . - & . , " . & - 0 . 0% & * '( ) * + * ' ( * + * * + .1 , / & - + 1 0 % & . 1 . . . & - + / 1 , , & + & , , . +1 0 % & ( * '( ) * - * ' ( * - * * - ,& 0 , % & % & / 0 & . / . & . + - ,% & ( * '( ) * - * ' ( * - * * - +& . 0 0 & % & , . + - & . % & % 0 - 0 & * '( ) * - * ' ( * - * * - +& % 0 % & % & " " 0 " 0 & . % & % - 0 % & ( * '( ) * - * ' ( ) * - * ' ( ) * - ,& 0 , % & % & , 0 & - - . & . + - ,% & ( * '( ) * - * ' ( ) * - * ' ( ) * - +& . 0 0 & % & , . - - & - + & % 0 - 0 & * '( ) * - * ' ( ) * - * ' ( ) * - +& % 0 % & % & " " 0 0 & - + & % - 0 % & ( * '( ) * - * ' ( ) * - " * ' ( ) * - " ,& 0 , % & % & / 0 & . / . & . + - ,% & ( * '( ) * - * ' ( ) * - " * ' ( ) * - " +& . 0 0 & % & , . + - & . % & % 0 - 0 & * '( ) * - * ' ( ) * - " * ' ( ) * - " / " & - " 1 + , % & " . & / " 1 + . / & % " " & - - . "1 + , % & ( * '( ) * " * ' ( ) * " * * " " & " 0 " & - % / & + , . - " & . . . & " " " 0 " & - % ( * '( ) * " * ' ( ) * " * * " " & " 0 % & / & + % 0 " 0 & . + . & 0 " 0 % & * '( ) * " * ' ( ) * " * * " " & % 0 % & , & 0 0 . - & . , . & / 0% & ( * '( ) * " * ' ( ) * " * * " " & " 0 " & - % / & + , . - 0 & . . . & " " " 0 " & - % ( * '( ) * " * ' ( ) * " * * " " & " 0 % & / & + % 0 " , & . , . & 0 " 0 % & * '( ) * " * ' ( ) * " * * " " & % 0 % & , & 0 0 0 & . , . & / 0% & ( * '( ) * " * ' ( ) * " * ' ( ) * " " & " 0 " & - % / & + , 0 " & - / . & " " " 0 " & - % ( * '( ) * " * ' ( ) * " * ' ( ) * " " & " 0 % & / & + % 0 % & " . & 0 " 0 % & * '( ) * " * ' ( ) * " * ' ( ) * " " & % 0 % & , & 0 0 % & . & / 0% & ( * '( ) * " " * ' ( * " " * * " " -& + , % & , & / " & / / 0 & 0 + + ,% & * '( ) * " " * ' ( * " " * * " " "" & / . 0 % & + & " . - / & / " . & . " 0 0% & ( * '( ) * " " * ' ( * " " * ' ( * " " -& + , % & , & / , 0 & - - 0 & 0 + + ,% & * '( ) * " " * ' ( * " " * ' ( * " " "" & / . 0 % & + & " 0 0 - & - 0 . & . " 0 0% & ( * '( ) * " * ' ( * " * * " %. & + / + . % & , 0 0 0 & 0 + . & , % & , - +. % & , 0 ( * '( ) * " * ' ( * " * * " %. & - . + % & 0 0 & . + . , & , - % & / " % +% & * '( ) * " * ' ( * " * * " %/ & , % - % & 0 / & 0 - " " & + . % & 0 . - % & ( * & ! " # $ " " # $ % / " / > " ' ( 89 - ' 9 ' , & . 4 , & . 89 - ' < - - 3 < & & -3 9 * 4 - (! 3 0 0 3 & 3 9 - ' 3 ) ' * + ' , ( - & . & ' (! " ! " # $ " " # $ " " # $ % 9 - ' ; - 9 / ( '( ) * " * ' ( * " * ' ( * " %. & + / + . % & , 0 0 0 & 0 + . 0 & . . % & , - +. % & , 0 ( * '( ) * " * ' ( * " * ' ( * " %. & - . + % & 0 0 & . + 0 + & 0 % & / " % +% & * '( ) * " * ' ( * " * ' ( * " %/ & , % - % & 0 / & 0 - & 0 / % & 0 . - % & ( * '( ) * " * ' ( * " * ' ( * " %. & + / + . % & , 0 0 0 & 0 + . 0 & . . % & , - +. % & , 0 ( * '( ) * " * ' ( * " * ' ( * " %. & - . + % & 0 0 & . + 0 + & 0 % & / " % +% & * '( ) * " * ' ( * " * ' ( * " %/ & , % - % & 0 / & 0 - & 0 / % & 0 . - % & ( * '( ) * " . * ' ( ) * " . * ' ( ) * " . // & - - + , & . % - & - + % & , - + & / - + + , & . ( * '( ) * " . * ' ( ) * " . * ' ( ) * " . /, & " + % & % - & . + 0 + & % + & % +% & * '( ) * " . * ' ( ) * " . * ' ( ) * " . 1 / % & % + 1 + 0 & 1 " & , , 1 , + - & - " / & . +1 + 0 & ( * '( ) * " . * ' ( ) * " . " * ' ( ) * " . " // & - - + , & . % - & - + % & , - + & / - + + , & . ( * '( ) * " . * ' ( ) * " . " * ' ( ) * " . " /, & " + % & % - & . + 0 + & % + & % +% & * '( ) * " . * ' ( ) * " . " * ' ( ) * " . " ," & . - % & / & % % - 0 / & - , + & " % . -% & ( * '( ) * " . * ' ( ) * " . * ' ( ) * " . // & - - + , & . % - & " . + % & , - + & % % + , & . ( * '( ) * " . * ' ( ) * " . * ' ( ) * " . /, & " + % & % - & , + 0 + & % + & . . , +% & * '( ) * " . * ' ( ) * " . * ' ( ) * " . ," & . - % & / & . - - 0 / & - , + & " -% & ( * '( ) * " . * ' ( ) * " . . * ' ( ) * " . . // & - - + , & . % - & - + % & , - + & / - + + , & . ( * '( ) * " . * ' ( ) * " . . * ' ( ) * " . . /, & " + % & % - & . + 0 + & % + & % +% & * '( ) * " . * ' ( ) * " . . * ' ( ) * " . . 1 / % & % + 1 + 0 & 1 " & , , 1 , + - & - " / & . +1 + 0 & ( * '( ) * " . * ' ( ) * " . 0 * ' ( ) * " . 0 // & - - + , & . % - & - + % & , - + & / - + + , & . ( * '( ) * " . * ' ( ) * " . 0 * ' ( ) * " . 0 /, & " + % & % - & . + 0 + & % + & % +% & * '( ) * " . * ' ( ) * " . 0 * ' ( ) * " . 0 1 / % & % + 1 + 0 & 1 " & , , 1 , + - & - " / & . +1 + 0 & ( * '( ) * " . * ' ( ) * " . % * ' ( ) * " . % // & - - + , & . % - & - + % & , - + & / - + + , & . ( * '( ) * " . * ' ( ) * " . % * ' ( ) * " . % /, & " + % & % - & . + 0 + & % + & % +% & * '( ) * " . * ' ( ) * " . % * ' ( ) * " . % 1 / % & % + 1 + 0 & 1 " & , , 1 , + - & - " / & . +1 + 0 & ( * '( ) * " . * ' ( ) * " . / * ' ( ) * " . / // & - - + , & . % - & - + % & , - + & / - + + , & . ( * '( ) * " . * ' ( ) * " . / * ' ( ) * " . / /, & " + % & % - & . + 0 + & % + & % +% & * '( ) * " . * ' ( ) * " . / * ' ( ) * " . / 1 / % & % + 1 + 0 & 1 " & , , 1 , + - & - " / & . +1 + 0 & ( * '( ) * " . * ' ( ) * " . , * ' ( ) * " . , // & - - + , & . % - & - + % & , - + & / - + + , & . ( * '( ) * " . * ' ( ) * " . , * ' ( ) * " . , /, & " + % & % - & . + 0 + & % + & % +% & * '( ) * " . * ' ( ) * " . , * ' ( ) * " . , 1 / % & % + 1 + 0 & 1 " & , , 1 , + - & - " / & . +1 + 0 & ( * & ! " # $ " " # $ % / " / > " ' ( 89 - ' 9 ' , & . 4 , & . 89 - ' < - - 3 < & & -3 9 * 4 - (! 3 0 0 3 & 3 9 - ' 3 ) ' * + ' , ( - & . & ' (! " ! " # $ " " # $ " " # $ % 9 - ' ; - 9 / ( '( ) * " 0 * ' ( ) * " 0 * ' ( ) * " 0 ,& % - , % & / & . / + & - 0 % & - / . ,% & ( * '( ) * " 0 * ' ( ) * " 0 * ' ( ) * " 0 +& " % . % & % & + + . " + & - " . & % + % . % & * '( ) * " 0 * ' ( ) * " 0 * ' ( ) * " 0 -& + % % & / & . + % " + & - . & + % % % & ( * '( ) * " % * ' ( ) * " % * ' ( ) * " % 3 $ 3 1 " 3 $ ) ) 3 3 2 $ 3 1 ' < " '( ) * " % * ' ( ) * " % * ' ( ) * " % 3 0 2 3 " 3 $ 2 1 0 3 $ 0 3 2 2 3 < < " '( ) * " / * ' ( ) * " / * ' ( ) * " / 0& 0 , % & & + / + & - 0 & - . / ,% & * '( ) * " / * ' ( ) * " / * ' ( ) * " / %& + % 0 & . & " % . - . & - & " / . 0 & ( * '( ) * " / * ' ( ) * " / " * ' ( ) * " / " 0& " + , & + - & 0 , " & + . & 0 0 . , & + - ( * '( ) * " / * ' ( ) * " / " * ' ( ) * " / " 0& 0 % . & & 0 . - . & - . & % . & * '( ) * " / * ' ( ) * " / " * ' ( ) * " / " %& 0 0 % & & / 0 0 . & - . " & - 0 / 0% & ( * '( ) * " / * ' ( ) * " / * ' ( ) * " / 0& 0 , % & & + / + & - 0 & - . / ,% & * '( ) * " / * ' ( ) * " / * ' ( ) * " / /& , 0 % & . & / 0 0 . & - & + / 0% & ( * '( ) * " , * ' ( * " , * ' ( * " , , & - " % & % . , & " % % & % . / & 0 " . % & % . ( * '( ) * " , * ' ( * " , * ' ( * " , ,. & , " % & , & " 0 " 0 - & , , 0 & - 0 . "% & * '( ) * " , * ' ( * " , * ' ( * " , "1 % , & , - / 1 % % & " 1 + & - / 1 . 0 & - - / & " / + /1 % % & ( * '( ) * " , * ' ( * " , " * ' ( * " , " , & - " % & % . , & " % % & % . / & 0 " . % & % . ( * '( ) * " , * ' ( * " , " * ' ( * " , " ,. & , " % & , & " 0 " 0 - & , , 0 & - 0 . "% & * '( ) * " , * ' ( * " , " * ' ( * " , " "1 % , & , - / 1 % % & " 1 + & - / 1 . 0 & - - / & " / + /1 % % & ( * '( ) * " + * ' ( ) * " + * ' ( ) * " + % & / % " 1 / & " " / & . " 1 % & - & , 0 - "1 / & " ( * '( ) * " + * ' ( ) * " + " * ' ( ) * " + " % & / % "1 / & " ", & " , "1 % & - . & 0 "1 / & " ( * 2 3 , . / & '( ) * " * ' ( * " * * " 0. & , + - % & + . / & . - & - / / & . / % +- % & + ( * '( ) * " * ' ( * " * * " 0. & + - & . / & + - % & + 0 / & . . % - & * '( ) * " * ' ( * " * * " 00 & 0 + - % & . , & . . - % % & , / & 0 -% & ( * '( ) * " * ' ( * " * * " 0. & , + - % & + . / & . - & - / / & . / % +- % & + ( * '( ) * " * ' ( * " * * " 0. & + - & . / & + - % & + 0 / & . . % - & * '( ) * " * ' ( * " * * " 00 & 0 + - % & . , & . . - % % & , / & 0 -% & ( * '( ) * * ' ( ) * * * /. & / / - / & / / % + & " - , & / " " & , " . /- / & / / ( * '( ) * * ' ( ) * * * /. & , . , % & % + & " , + & % + " " & . 0 , % & * '( ) * * ' ( ) * * * /, & , + % & / & - % + / & , - " & / 0 - + % & ( * '( ) * * ) ' 4 . * ) ' 4 . /. & / / - / & / / % + & " - , & / " " & , " . /- / & / / ( * & ! " # $ " " # $ % / " / > " ' ( 89 - ' 9 ' , & . 4 , & . 89 - ' < - - 3 < & & -3 9 * 4 - (! 3 0 0 3 & 3 9 - ' 3 ) ' * + ' , ( - & . & ' (! " ! " # $ " " # $ " " # $ % 9 - ' ; - 9 / ( '( ) * * ) ' 4 . * ) ' 4 . /. & , . , % & % + & " , + & % + " " & . . , % & * '( ) * * ) ' 4 . * ) ' 4 . /, & , + % & / & - % + / & , - " & / 0 - + % & ( * '( ) * . * ' ( * . * * . 0/ & . . " 1 , & . % & " 1 , & 0 + 0 & + - "1 , & ( * '( ) * . * ' ( * . " * * . " 0/ & . . " 1 , & . % & " 1 , & 0 + 0 & + - "1 , & ( * '( ) * . * ' ( ) * . * ' ( ) * . 0/ & . . " 1 , & . % & " 1 , & 0 + 0 & + - "1 , & * '( ) * . * ' ( ) * . * ' ( ) * . 0/ & % " " 1 % & . % & / " 1 0 & - " 0 & / "1 % & ( * ' ( ) * * ' ( * * ' ( * " -& , / 0 & % & / % 0 & & . , % 0 & * ' ( ) * * ' ( * * ' ( * " -& - , 0 % & % & / / 0 0 & - & . " 0 % & ( * ' ( ) * " * ' ( ) * " * ' ( * " " %. & - + / , / & % 0 + & % / / , % & , - & - / " /, / & % * ' ( ) * " * ' ( ) * " * ' ( * " " %% & 0 , % & 0 - & 0 - , & - - & / " . , % & ( * 5 ' ( ) * 0 * ' ( ) * 0 * ' ( ) * 0 " / & . + & / % % & / - + / & / % - & % " + + & / ( * 5 ' ( ) * 0 * ' ( ) * 0 * ' ( ) * 0 " / & . + + % & % % & / - + + & + - & . " + % & * 5 ' ( ) * 0 * ' ( ) * 0 * ' ( ) * 0 " /% & - - & % + & + - & + % - & % / - & ( * < , & . = , & . + ? + = % & % . " 1 & ' ( ) * " - . 6 7 * ( 6 ( 8 "1 & % 1 " . & ' ( ) * " - . 6 9 : ! ; ! 8 %1 " . & + 1 + 0 & ' ( ) * " - . 6 9 : ! ; ! 8 5 < 2 7 * & < = & ( < < $ & ( > $ # ? $ * @ & 8 = = & < < 8 9 5 < 5 ( < 2 < 5 & WE L L D E T A I L S : P l a n : N C I U A - 1 9 N A D 1 9 2 7 ( N A D C O N C O N U S ) A l a s k a Z o n e 0 4 Wa t e r D e p t h : 1 0 1 . 0 0 +N / - S +E / - W N o r t h i n g Ea s t i n g La t i t u d e Lo n g i t u d e 0. 0 0 0. 0 0 25 8 6 6 7 1 . 0 1 33 2 0 3 4 . 0 2 6 1 ° 4 ' 3 5 . 8 0 2 9 N 1 5 0 ° 5 6 ' 5 4 . 8 1 2 2 W RE F E R E N C E I N F O R M A T I O N Co - o r d i n a t e ( N / E ) R e f e r e n c e : We l l P l a n : N C I U A - 1 9 - S l o t 2 0 0 2 , T r u e N o r t h Ve r t i c a l ( T V D ) R e f e r e n c e : P r e l i m @ 1 2 6 . 6 3 u s f t ( 1 5 1 ) Me a s u r e d D e p t h R e f e r e n c e : Pr e l i m @ 1 2 6 . 6 3 u s f t ( 1 5 1 ) Ca l c u l a t i o n M e t h o d : Mi n i m u m C u r v a t u r e CA S I N G D E T A I L S TV D T V D S S M D S i z e N a m e 34 5 0 . 0 0 3 3 2 3 . 3 7 5 1 3 1 . 5 9 9 - 5 / 8 9 5 / 8 " x 1 2 1 / 4 " 67 2 6 . 7 7 6 6 0 0 . 1 4 8 8 2 4 . 0 0 4 - 1 / 2 4 1 / 2 " x 8 1 / 2 " SU R V E Y P R O G R A M Da t e : 2 0 2 4 - 0 3 - 0 5 T 0 0 : 0 0 : 0 0 V a l i d a t e d : Y e s V e r s i o n : De p t h F r o m D e p t h T o Su r v e y / P l a n To o l 52 . 5 3 1 2 0 0 . 0 0 N C I U A - 1 9 w p 0 2 ( N C I U A - 1 9 ) 3 _ G y r o - C T _ C s g 12 0 0 . 0 0 5 1 3 2 . 0 0 N C I U A - 1 9 w p 0 2 ( N C I U A - 1 9 ) 3 _ M W D + A X + S a g 51 3 2 . 0 0 8 8 2 4 . 0 0 N C I U A - 1 9 w p 0 2 ( N C I U A - 1 9 ) 3 _ M W D + A X + S a g 0. 0 0 10 . 0 0 20 . 0 0 30 . 0 0 40 . 0 0 50 . 0 0 60 . 0 0 70 . 0 0 80 . 0 0 90 . 0 0 10 0 . 0 0 Centre to Centre Separation (20.00 usft/in) 10 0 2 0 0 3 0 0 4 0 0 5 0 0 6 0 0 7 0 0 8 0 0 9 0 0 1 0 0 0 1 1 0 0 1 2 0 0 1 3 0 0 1 4 0 0 1 5 0 0 1 6 0 0 1 7 0 0 1 8 0 0 1 9 0 0 2 0 0 0 Me a s u r e d D e p t h ( 2 0 0 u s f t / i n ) NC I U A - 1 8 P B 1 NC I U A - 1 8 NC I U A - 1 8 A- 0 8 NC I U A - 1 0 B A- 1 0 A NC I A - 0 3 A A- 0 3 A- 0 5 NC I U A - 1 4 NC I U A - 1 6 NC I U A - 1 6 NC I U A - 1 5 NC I A - 2 1 w p 0 1 NC I A - 2 1 w p 0 1 A- 1 2 NC I A - 1 2 B NC I A - 1 2 B NC I A - 0 1 A A- 0 1 A- 1 1 NC I A - 1 1 A A- 0 6 B- 0 1 A A- 0 2 A- 0 7 NC I U A - 0 9 A A- 0 9 A- 0 4 NC I A - 0 4 A NC I A - 2 0 w p 0 1 NC I A - 1 7 NC I A - 1 7 NC I A - 1 7 P B 1 NC I U A - 1 3 GL O B A L F I L T E R A P P L I E D : A l l w e l l p a t h s w i t h i n 2 0 0 ' + 1 0 0 / 1 0 0 0 o f r e f e r e n c e 52 . 5 3 T o 8 8 2 4 . 0 0 Pr o j e c t : N o r t h C o o k I n l e t Si t e : N o r t h C o o k I n l e t U n i t We l l : P l a n : N C I U A - 1 9 We l l b o r e : N C I U A - 1 9 Pl a n : N C I U A - 1 9 w p 0 2 La d d e r / S . F . P l o t s 0. 0 0 0. 7 5 1. 5 0 2. 2 5 3. 0 0 Separation Factor 0 5 0 0 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 5 0 0 7 0 0 0 7 5 0 0 8 0 0 0 8 5 0 0 9 0 0 0 9 5 0 0 Me a s u r e d D e p t h ( 1 0 0 0 u s f t / i n ) NC I U A - 1 8 NC I U A - 1 0 B A- 1 0 NC I U A - 1 4 NC I U A - 1 6 NC I U A - 1 5 A- 1 1 NC I A - 1 1 A NC I U A - 0 9 A NC I U A - 0 9 P B 1 A- 0 9 NC I A - 2 0 w p 0 1 No - G o Z o n e - S t o p D r i l l i n g Co l l i s i o n A v o i d a n c e R e q u i r e d Co l l i s i o n R i s k P r o c e d u r e s R e q . NO E R R O R S WE L L D E T A I L S : P l a n : N C I U A - 1 9 N A D 1 9 2 7 ( N A D C O N C O N U S ) A l a s k a Z o n e 0 4 Wa t e r D e p t h : 1 0 1 . 0 0 +N / - S +E / - W N o r t h i n g Ea s t i n g La t i t u d e Lo n g i t u d e 0. 0 0 0. 0 0 25 8 6 6 7 1 . 0 1 33 2 0 3 4 . 0 2 6 1 ° 4 ' 3 5 . 8 0 2 9 N 1 5 0 ° 5 6 ' 5 4 . 8 1 2 2 W RE F E R E N C E I N F O R M A T I O N Co - o r d i n a t e ( N / E ) R e f e r e n c e : We l l P l a n : N C I U A - 1 9 - S l o t 2 0 0 2 , T r u e N o r t h Ve r t i c a l ( T V D ) R e f e r e n c e : P r e l i m @ 1 2 6 . 6 3 u s f t ( 1 5 1 ) Me a s u r e d D e p t h R e f e r e n c e : Pr e l i m @ 1 2 6 . 6 3 u s f t ( 1 5 1 ) Ca l c u l a t i o n M e t h o d : Mi n i m u m C u r v a t u r e CA S I N G D E T A I L S TV D T V D S S M D S i z e N a m e 34 5 0 . 0 0 3 3 2 3 . 3 7 5 1 3 1 . 5 9 9 - 5 / 8 9 5 / 8 " x 1 2 1 / 4 " 67 2 6 . 7 7 6 6 0 0 . 1 4 8 8 2 4 . 0 0 4 - 1 / 2 4 1 / 2 " x 8 1 / 2 " SU R V E Y P R O G R A M Da t e : 2 0 2 4 - 0 3 - 0 5 T 0 0 : 0 0 : 0 0 V a l i d a t e d : Y e s V e r s i o n : De p t h F r o m D e p t h T o Su r v e y / P l a n To o l 52 . 5 3 1 2 0 0 . 0 0 N C I U A - 1 9 w p 0 2 ( N C I U A - 1 9 ) 3 _ G y r o - C T _ C s g 12 0 0 . 0 0 5 1 3 2 . 0 0 N C I U A - 1 9 w p 0 2 ( N C I U A - 1 9 ) 3 _ M W D + A X + S a g 51 3 2 . 0 0 8 8 2 4 . 0 0 N C I U A - 1 9 w p 0 2 ( N C I U A - 1 9 ) 3 _ M W D + A X + S a g 0. 0 0 40 . 0 0 80 . 0 0 12 0 . 0 0 16 0 . 0 0 20 0 . 0 0 Centre to Centre Separation (80.00 usft/in) 50 0 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 5 0 0 7 0 0 0 7 5 0 0 8 0 0 0 8 5 0 0 9 0 0 0 9 5 0 0 Me a s u r e d D e p t h ( 1 0 0 0 u s f t / i n ) NC I U A - 1 8 P B 1 NC I U A - 1 8 P B 1 NC I U A - 1 8 P B 1 NC I U A - 1 8 NC I U A - 1 8 NC I U A - 1 8 A- 0 8 NC I U A - 1 0 B A- 1 0 A A- 1 0 NC I U B - 0 4 w p 0 1 NC I A - 0 3 A NC I A - 0 3 A A- 0 3 A- 0 3 A- 0 5 NC I U A - 1 4 NC I U A - 1 6 NC I U A - 1 6 NC I U A - 1 6 NC I U A - 1 5 NC I A - 2 1 w p 0 1 NC I A - 2 1 w p 0 1 B- 0 2 SU N F I S H 3 A- 1 2 NC I A - 1 2 A NC I A - 1 2 B NC I A - 1 2 B NC I A - 0 1 A A- 0 1 A- 1 1 NC I A - 1 1 A A- 0 6 B- 0 1 A B- 0 1 A- 0 2 A- 0 7 NC I U A - 0 9 A NC I U A - 0 9 A NC I U A - 0 9 P B 1 A- 0 9 A- 0 9 NC I U B - 0 3 A NC I U B - 0 3 A B- 0 3 P B 1 B- 0 3 B- 0 3 A- 0 4 NC I A - 0 4 A NC I A - 2 0 w p 0 1 NC I A - 2 0 w p 0 1 NC I A - 1 7 NC I A - 1 7 NC I A - 1 7 P B 1 NC I U A - 1 3 NC I U A - 1 3 GL O B A L F I L T E R A P P L I E D : A l l w e l l p a t h s w i t h i n 2 0 0 ' + 1 0 0 / 1 0 0 0 o f r e f e r e n c e 52 . 5 3 T o 8 8 2 4 . 0 0 Pr o j e c t : N o r t h C o o k I n l e t Si t e : N o r t h C o o k I n l e t U n i t We l l : P l a n : N C I U A - 1 9 We l l b o r e : N C I U A - 1 9 Pl a n : N C I U A - 1 9 w p 0 2 La d d e r / S . F . P l o t s 1 SHALLOW GEOLOGIC HAZARDS REPORT TO ACCOMPANY DIVERTER WAIVER FOR THE TYONEK DRILL WELL PROGRAM Matthew Petrowsky – Geologist, Hilcorp Alaska LLC Sean McLaughlin – Drilling Engineer, Hilcorp Alaska LLC Submitted to State of Alaska Oil and Gas Conservation Commission (“AOGCC”) 4/3/2024 CONTENTS 1. INTRODUCTION 2. TYONEK PLATFORM AREA 3. SEISMIC DATA EVALUATION IN AOI 4. MUDLOGS IN AOI 5. PREVIOUS DRILLING EXPERIENCE WITHIN AOI 6. SUMMARY 7. LIST OF FIGURES 1. INTRODUCTION 2 This geologic and engineering report is submitted by Hilcorp Alaska LLC in support of its application for diverter waiver when drilling from the Tyonek Platform (Figure 1). From an analysis and drilling experience of existing wells on the Tyonek Platform, Hilcorp does not anticipate any significant gas at depths between surface and the Sterling X. This report supports a waiver to drill surface hole without a diverter. The Tyonek Platform is isolated geographically and is the furthest North Platform in the inlet. 2. TYONEK PLATFORM Redacted 5/10/2024 M.Guhl 3 There are 22 penetrations from the Tyonek Platform that validate shallow geologic structure and risk. Mudlogs from surface are available for three wells (A-13, B-01, and B-03). Five grassroots wells have been drilled since 2009, all with surface casing shoe depths of 3202’ - 3498’ TVD. The surface casing shoe was set above the Sterling X sand. The Sterling sands below the casing shoe are depleted, low pressure sands. No commercial quantities of gas exist above the Sterling X sands. Due to the nature of platform drilling surface holes are closely grouped with little geographical differences 3. SEISMIC DATA IN AOI 4 Evaluation of the 3D seismic data across the North Cook Inlet Unit (NCIU) indicates that there are no high amplitude, gas-prospective Sterling sandstones (Class 3 amplitudes due to rock quality) that would pose a drilling hazard above the current top pool designation outlined in CO 68A. The depth of the top of Tertiary System Gas Pool fluctuates between approximately 3200’ – 3300’ TVD depending on the correlation with the North Cook Inlet A-15 well. In the AOI, the Sunfish_3D_2011transverses the prospect at various angles, providing a basis for evaluation (Figure 3). 5 6 4. SHALLOW MUDLOGS IN AOI Tyonek wells A-13, B-01, and B-03 each have surface hole mud log data. The gas chromatograph shows trace gas through the upper surface hole. Free gas exists near the top of the Sterling and is observed with the chromatograph. No abnormal pressure intervals are present. The absence of robust top seals in the vicinity undoubtedly prohibited significant entrapment of gas in the shallow section. 5. PREVIOUS DRILLING EXPERIENCE WITHIN AOI As mentioned above, there have been many penetrations in the area of interest. No abnormal pressured gas sands have been encountered. No cases of loss circulation have been encountered. Typical mud weights have been between 9.0 and 9.6 ppg. 6. SUMMARY In summary, based on the analysis of offset wells, mudlogs, seismic data, and drilling experience there is no evidence of trapped gas hazards at depths between surface and the Sterling X. This report is only intended for supporting a diverter waiver request when drilling from the Tyonek Platform. 7. CONFIDENTIAL LIST OF FIGURES x Figure 1: Index Map of Area x Figure 2: North Cook Inlet Beluga B Structure Map x Figure 3: 3D Seismic Cube with North Cook Inlet Beluga B Structure Map x Figure 4: Seismic Line: XLine 640 x Figure 5: Seismic Line: InLine 547 Waiver not recommended. Review of the offset well NCIU A-10A (PTD 203-075) mudlog indicates significant gas at less than 2,000’ TVD. -A.Dewhurst 30APR24 1 Di v e r t e r R e l e a s e L o w e r F l a m m a b l e L i m i t ( L F L ) M o d e l • P l u m e d e p i c t s m a x e x p e c t e d U F L ( r e d ) , L F L ( g r e e n ) a n d 5 0 % L F L ( b l u e ) o f r e l e a s e t o e x p e c t e d S E f r o m S E o r i e n t e d d i v e r t e r a t 1 0 m m s c f d . • A f f e c t e d r a d i i ' s s h o w p l u m e ’ s e x t e n t r e g a r d l e s s o f r e l e a s e d i r e c t i o n To p V i e w 2 Di s p e r s i o n P l u m e G e o m e t r y ( 5 0 % L F L ) Po t e n t i a l I g n i t i o n S o u r c e (H e a t e r E x h a u s t ) Po t e n t i a l I g n i t i o n S o u r c e (G e n e r a t o r E x h a u s t ) • C o n s e r v a t i v e m o d e l , a s s u m e s b o t h a r e l e a s e a n d w i n d d i r e c t i o n t o w a r d s N W i g n i t i o n s o u r c e s • S h o w s e x t e n t o f L F L m o d e l e d a t 5 0 % L F L ( . 0 2 5 b y v o l u m e f o r m e t h a n e ) i n b l u e , L F L i n g r e e n a n d U F L i n r e d 3 Di s p e r s i o n P l u m e G e o m e t r y ( 2 0 % L F L ) • A s s u m e s b o t h w i n d a n d r e l e a s e i n s a m e d i r e c t i o n • S h o w s e x t e n t o f o b s e r v a b l e L F L a s s h o w n b y a 2 0 % L F L ( a t y p i c a l a l a r m t h r e s h o l d ) i n b l u e , 5 0 % L F L i n g r e e n , L F L i n r e d a n d U F L i n p u r p l e 4 Ke y P o i n t s - As s u m p t i o n s : - 10 M M S C F D c o n s e r v a t i v e s t e a d y - s t a t e r e l e a s e r a t e f r o m 1 6 ” d i v e r t e r - 11 m p h ( 5 m / s ) w i n d a i d e d r e l e a s e i n s t a b l e a t m o s p h e r e - Pr i m a r i l y m e t h a n e g a s c o m p o s i t i o n - Co n s i d e r m u l t i p l e r e l e a s e & w i n d d i r e c t i o n s b u t e x p e c t e d r e l e a s e i s t o S E ( d i v e r t e r o r i e n t a t i o n ) - Re s u l t s / C o n c l u s i o n s : - 10 0 % L E L B o u n d a r y ~ 5 0 f t ( C l o s e s t i g n i t i o n s o u r c e ~ 5 5 f t , 2 9 f t b e l o w r e l e a s e p o i n t ) - Th e g a s i s b u o y a n t i n a t m o s p h e r e a n d m o d e l s d e m o n s t r a t e m i n i m a l s i n k i n g o f g a s t o e l e v a t i o n s lo w e r t h a n r e l e a s e p o i n t . E l e v a t i o n o f r e l e a s e p o i n t b e i n g h i g h e r t h a n t h e i g n i t i o n s o u r c e s i s a k e y mi t i g a t i n g f a c t o r . - Wi n d i s t y p i c a l l y f r o m N E o r S W . I g n i t i o n s o u r c e s a r e N W o f r e l e a s e p o i n t . - Wi n d d i r e c t i o n a n d a t m o s p h e r e s t a b i l i t y a f f e c t p l u m e g e o m e t r y b u t d i v e r t e r / r e l e a s e d i r e c t i o n i s th e p r i m a r y d r i v e r . - Ty p i c a l w i n d c o n d i t i o n s r e d u c e r i s k o f g a s r e a c h i n g i g n i t i o n s o u r c e s t o t h e N W . - No s c e n a r i o i d e n t i f i e d w h e r e L E L b o u n d a r y r e a c h e s a n i g n i t i o n s o u r c e - Re c o m m e n d t o m o n i t o r w i n d d i r e c t i o n d u r i n g a c t i v i t y a n d r e - a s s e s s i f w i n d s h i f t s f r o m S E CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Sean McLaughlin To:McLellan, Bryan J (OGC) Cc:Regg, James B (OGC); Dewhurst, Andrew D (OGC) Subject:RE: [EXTERNAL] NCIU A-19 Diverter Waiver Date:Wednesday, May 1, 2024 3:40:05 PM Bryan, The PSE has finished up with the modeling. When would you be free to review over Teams with the PSE? Regards, sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Friday, April 26, 2024 11:30 AM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Sandy Reynolds <sreynolds@hilcorp.com> Cc: jim.regg <jim.regg@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: RE: [EXTERNAL] NCIU A-19 Diverter Waiver Sean and Sandy, Thanks for discussing the issues with the diverter vent-line location relative to the ignition sources on the platform. Significant shallow gas has been encountered within the planned surface hole interval on at least one well drilled from the Tyonek platform. The starting point for any variance or waiver needs to acknowledge that shallow gas is present, and there is potential for the diverter to be used to divert gas away from the rig and platform. The risk reduction measures need to assume that there could be a significant quantity of gas discharging uncontrollably from the diverter vent line. If it is impossible to comply with the regulations that require 75’ between ignition source and diverter vent-line discharge per 20 AAC 25.035(c), I suggest a detailed analysis of the situation be performed by a process safety professional, with recommendations for risk reduction measures. I’m not sure what they might come up with, but things like a vapor-cloud dispersion model, location of gas detectors and protocols for shutting down the platform before a vapor cloud reaches the ignition sources are a few relevant examples. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Tuesday, April 23, 2024 1:18 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Sandy Reynolds <sreynolds@hilcorp.com> Subject: RE: [EXTERNAL] NCIU A-19 Diverter Waiver Bryan, 2pm tomorrow would work for the Sandy, the Platform Supervisor. Last year there was an open deck on leg two and we were able to extend the divert line to the States satisfaction. We had large area in which to perform work and the space is needed when working with 16” lines. With the rig being on leg two the cellar opening is such that only one stick of 16” diverter can be pointed out. A flange will not fit through the opening. The limitation is to avoid hanging people from a temporary manrider winch and using the platform crane to make up a flange 100’ above the water. In addition, the pipe extension would be unsupported. Assurances 50’ is sufficient: A good deal of work has been performed on the risk assessment and shallow hazard assessment. There is a low probability that a vapor cloud emanating from the vent line would occur, this is not an exploration well. There needs to be a source. Wind direction plays a significant part when drilling with a single diverter. Drilling will not occur if the wind direction will carry gas to an ignition source. There is more often wind than not. The ignition source was analyzed and discussed last year. The generators are in the bowels of the platform and the exhaust is run outside. The exhaust temperature is about 50% of methane auto ignition temperature. The rig is a significant baffle and tortuous path for gas to move in a straight line distance to the source. Dispersion or deflection would occur. Methane is lighter than air and the diverter is located about 15’ above the ignition source. Any methane is expected to remain above the ignition source. While drilling, a facility operator is present in the control room and can ESD the platform if required. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Regards, sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, April 23, 2024 12:07 PM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Cc: jim.regg <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] NCIU A-19 Diverter Waiver Sean, Thanks for offering to set up a meeting with the platform supervisor and facility engineer. I’m free after 2:00 pm tomorrow or Thursday or Friday before 1:00 pm. A couple of points for discussion: 1. What was the solution last year to getting the diverter outlet >75’ from the ignition sources? Why won’t that work this year? 2. What assurance can Hilcorp provide that 50’ is far enough between the diverter ventline outlet and ignition source to prevent ignition of a vapor cloud emanating from the ventline during a blowout? Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Monday, April 22, 2024 4:15 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] NCIU A-19 Diverter Waiver Bryan, CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. The vent line will extend about 10’ beyond the rig and platform. The rig will be at the edge of the platform and there is no egress around the rig. This is about the same point in space as it was last year. The diverter will be pointed out the back of the rig (South) and egress is out for the front (North). Please keep in mind that the rig has been skidded off its traditional substructure. The jack up is more than 100’ away and contains, the mud pits, pumps, fluids shack, power generation, and most of the people. The process safety equation is substantially different than a conventional rig up. I’d be happy to set up a meeting with Facility Engineer, Mark McKinley or Platform Supervisor, Sandy Reynolds to discuss. Two grass roots wells were drilled on diverter last year with a similar diverter location. Last year we kept close approach wells flowing. Because of the variance request we decided to shut in the close approach well, A-15. The proposed configuration has prompted no changes to the platform response for a divert event. Hilcorp has not conducted a HAZOP. We believe there is no shallow hazard. As such, I’m not sure there is a node to start a Hazop from. We conducted a risk conversation and that turned into the shallow hazard analysis that was submitted to the AOGCC. The result of the risk assessment was the original diverter variance request. Regards, sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, April 22, 2024 9:47 AM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Cc: jim.regg <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] NCIU A-19 Diverter Waiver Sean, We are evaluating the variance requests. A few questions 1. How far beyond the rig substructure are you planning to place the vent-line discharge and how far beyond the platform structure? 2. Does Hilcorp have an OIM and process safety engineer that can meet with us to discuss options for complying and risks of non-compliance? 3. Has Hilcorp performed a HAZOP to evaluate the risks? Thank you Bryan McLellan 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. Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Friday, April 19, 2024 11:10 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] NCIU A-19 Diverter Waiver Bryan, Thank you for the information ahead of the PTD so we can plan a different route. Please consider the following two variance requests for A-19: 1. 20 AAC 25.035 (c)(2)(C) the vent line must extend to a point at least 75 feet (i) away from a potential source of ignition a. Hilcorp proposes 50 foot between the generator exhaust and the vent line. The exhaust points west between legs 1 and 2 and the vent line points south. The rig is between the vent line and exhaust. A schematic is attached. b. Please also consider information supplied in the original diverter waiver request. Drilling experience shows there is not an intensity kick potential. Swabbing in surface hole is unlikely and drilling experience supports that. The are no reports of lost circulation. Drilling experience shows that surface hole flow is not likely or expected. 2. 20 AAC 25.035 (c)(2)(C) (ii) the vent line must extend to a point at least 75 feet beyond the drill rig substructure, or to a point within the reserve pit and at least 50 feet beyond the drill rig substructure; a. Please note that because we are drilling from a platform, we are unable to meet the requirement. While drilling on diverter the vent line will extend beyond the rig substructure and the platform structure. The rule was previously waived on Tyonek in 2009 during the drilling of A-14, A-15, and A-16. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. For reference, the threshold for a variance is drilling experience in the near vicinity: (h) Upon request of the operator, the commission will, in its discretion, approve a variance (1) from the BOPE requirements in (e) of this section if the variance provides at least an equally effective means of well control; and (2) from the diverter system requirements in (c) of this section if the variance provides at least equally effective means of diverting flow away from the drill rig or if drilling experience in the near vicinity indicates that a diverter system is not necessary. Regards, sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, April 18, 2024 3:54 PM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: [EXTERNAL] NCIU A-19 Diverter Waiver Sean, The diverter waiver request for this well will not be approved. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1 Dewhurst, Andrew D (OGC) From:Dewhurst, Andrew D (OGC) Sent:Tuesday, April 30, 2024 08:26 To:Matthew Petrowsky Subject:RE: [EXTERNAL] RE: NCIU A-19 Diverter Waiver Matt, Thanks for reaching out. Yes, when you are available give me a call at (907) 793-1254 and we can discuss what I suggest for a path forward. I have a couple meetings starting at 10am, but will call back if need be. Andy From: Matthew Petrowsky <mpetrowsky@hilcorp.com> Sent: Tuesday, April 30, 2024 08:19 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: Re: [EXTERNAL] RE: NCIU A-19 Diverter Waiver Good Morning Andy, Wanted to reach out per your request yesterday and touch base regarding the NCIU A-19 Diverter Waiver and ultimate Permit to Drill. I'm at a doctors appointment this morning with my son, but should be good to chat here in an hour or two. I'm also free later this afternoon if you wanted to meet in person. Let me know what you're thinking and we can go from there. Thanks. -Matt From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Monday, April 29, 2024 16:25 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Matthew Petrowsky <mpetrowsky@hilcorp.com>; Christopher Stone <Christopher.Stone@hilcorp.com > Cc: jim.regg <jim.regg@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: RE: [EXTERNAL] RE: NCIU A-19 Diverter Waiver Andy, Sounds good, Matt Petrowsky is the offshore geologist and will contact you. It might be good to hear from reservoir engineer Chris Stone as well. Thanks, sean From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Monday, April 29, 2024 3:22 PM You don't often get email from mpetrowsky@hilcorp.com. Learn why this is important 2 To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com > Cc: jim.regg <jim.regg@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: RE: [EXTERNAL] RE: NCIU A-19 Diverter Waiver Sean, Would you please have your geologist contact me to set up a meeting at the AOGCC to review both the M-26 data and information presented below. Thanks, Andy From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Monday, April 29, 2024 12:13 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: RE: [EXTERNAL] RE: NCIU A-19 Diverter Waiver Andy, The Steelhead blowout was from the SZ17 and SZ18. Those sands net 80’ and have a 24% porosity. They are commercial quality and have been the source of significant production. After a very brief search I see the Steelhead blowout zone was produced from M-03, M-09, M-13, M-16, and M-16RD. In 1992, the State of Alaska accepted Phillips Petroleum variance request to run conductor to 2706’. Information from Phillips states there is no indication of anomalies above 3000’ BML. That claim was underpinned by work previously done by Arco Alaska. The Hilcorp request is not new or outlandish. It is supported by multiple operators spanning decades. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 3 Below is the Lithology description from Sunfish #2. You have likely already read the lithology description on the A- 10A mudlog. It is not surprising or unexpected that there are few mudlogs to surface. Shallow hazards were derisked long ago. The lack of mudlog data speaks volumes regarding the shallow hazard risk. Most importantly, the A-10A mudlog was from a sidetrack. The gas spike you are concerned about contained C- 2. C-2 is not characteristic this shallow and is not present on the other mudlogs. The A-10 well history contains information about a remedial intermediate cement job. The most likely scenario is that poor annular cement allowed gas migration from deep in A-10. When the A-10A window was drilled this gas showed and then dissipated. The event was most likely mechanical in nature. This is supported by the non-occurrence on other wells. Regards, sean From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Monday, April 29, 2024 8:26 AM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com > Cc: jim.regg <jim.regg@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Davies, Stephen F (OGC) 4 <steve.davies@alaska.gov> Subject: [EXTERNAL] RE: NCIU A-19 Diverter Waiver Sean, The identification of “significant hydrocarbon” does not imply that it is overpressured or equates to a commercial quantity. The shallow gas that was the source of the Steelhead blowout was neither of the above. The presence of the shallow gas identified at NCIU A-10A is approximately 1,000’ from the proposed A-19 well path. I was only able to find 4 offset mudlogs that cover the interval represented by the proposed surface hole of A-19. The remaining (20+) wells that drilled through this depth without the quantitative gas measurements associated with a mudlogging unit do not prove that the shallow gas zone is absent; they do however provide evidence that the gas, if present, is not significantly overpressured. So, there is actually very little data to work with. Thus, there remains much uncertainty to the actual size/extent, thickness, and quality of the shallow gas sands below the platform. We will not prescribe the specific parameters that you have discussed below, but inclusion of the actual data at A-10A would improve the quality of the results. You might consider making 2 or 3 deterministic models that represent a low- medium-and high case event. Andy From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Friday, April 26, 2024 14:13 To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: Re: [EXTERNAL] NCIU A-19 Diverter Waiver Bryan, One more thing that we need guidance on. A-10A did not create a divert event when drilling with 8.7 ppg mud. How does that inform what a significant quantity of gas is? As you can imagine there is a lot of interest and discussion regarding significant quantities of hydrocarbons and shallow depths. Thanks, Sean On Apr 26, 2024, at 2:02 PM, Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> wrote: Bryan, Shallow gas was acknowledged in the very first response. There is free gas present and is not considered a hazard based on numerous factors previously submitted. This is a similar situation when seeing gas in stratigraphic test wells. I understand the State believes there is an overarching hazard based on the A-10A mud log. Prior to modeling, parameters need to be established. It is clear the State doesn’t accept our assumptions and therefore the State won’t accept the modeling. - Flow potential? What is a significant quantity? CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 5 - Flow profile (duration, and decline) is important for modeling. - Should we assume the discrete observation of A-10A (an occurrence at a specific depth)? - May we factor in that A-19 is pointed the opposite direction and more relevant logs based on proximity do not show the potential for significant quantities of gas? Shallow gas in the area has not been considered a hydrocarbon resource by HilCorp and previous operators. This is due to pressure and tank size (flow potential). I need State input to help determine what a significant quantity of gas is prior to modeling. Regards, Sean On Apr 26, 2024, at 11:30 AM, McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> wrote: Sean and Sandy, Thanks for discussing the issues with the diverter vent-line location relative to the ignition sources on the platform. Significant shallow gas has been encountered within the planned surface hole interval on at least one well drilled from the Tyonek platform. The starting point for any variance or waiver needs to acknowledge that shallow gas is present, and there is potential for the diverter to be used to divert gas away from the rig and platform. The risk reduction measures need to assume that there could be a significant quantity of gas discharging uncontrollably from the diverter vent line. If it is impossible to comply with the regulations that require 75’ between ignition source and diverter vent-line discharge per 20 AAC 25.035(c), I suggest a detailed analysis of the situation be performed by a process safety professional, with recommendations for risk reduction measures. I’m not sure what they might come up with, but things like a vapor-cloud dispersion model, location of gas detectors and protocols for shutting down the platform before a vapor cloud reaches the ignition sources are a few relevant examples. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 <image001.jpg> CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 6 From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Tuesday, April 23, 2024 1:18 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Sandy Reynolds <sreynolds@hilcorp.com> Subject: RE: [EXTERNAL] NCIU A-19 Diverter Waiver Bryan, 2pm tomorrow would work for the Sandy, the Platform Supervisor. Last year there was an open deck on leg two and we were able to extend the divert line to the States satisfaction. We had large area in which to perform work and the space is needed when working with 16” lines. With the rig being on leg two the cellar opening is such that only one stick of 16” diverter can be pointed out. A flange will not fit through the opening. The limitation is to avoid hanging people from a temporary manrider winch and using the platform crane to make up a flange 100’ above the water. In addition, the pipe extension would be unsupported. Assurances 50’ is sufficient: 1. A good deal of work has been performed on the risk assessment and shallow hazard assessment. There is a low probability that a vapor cloud emanating from the vent line would occur, this is not an exploration well. There needs to be a source. 2. Wind direction plays a significant part when drilling with a single diverter. Drilling will not occur if the wind direction will carry gas to an ignition source. There is more often wind than not. 3. The ignition source was analyzed and discussed last year. The generators are in the bowels of the platform and the exhaust is run outside. The exhaust temperature is about 50% of methane auto ignition temperature. 4. The rig is a significant baffle and tortuous path for gas to move in a straight line distance to the source. Dispersion or deflection would occur. 5. Methane is lighter than air and the diverter is located about 15’ above the ignition source. Any methane is expected to remain above the ignition source. 6. While drilling, a facility operator is present in the control room and can ESD the platform if required. Regards, sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, April 23, 2024 12:07 PM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com > Cc: jim.regg <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] NCIU A-19 Diverter Waiver CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 7 Sean, Thanks for offering to set up a meeting with the platform supervisor and facility engineer. I’m free after 2:00 pm tomorrow or Thursday or Friday before 1:00 pm. A couple of points for discussion: 1. What was the solution last year to getting the diverter outlet >75’ from the ignition sources? Why won’t that work this year? 2. What assurance can Hilcorp provide that 50’ is far enough between the diverter ventline outlet and ignition source to prevent ignition of a vapor cloud emanating from the ventline during a blowout? Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 <image001.jpg> From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Monday, April 22, 2024 4:15 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] NCIU A-19 Diverter Waiver Bryan, The vent line will extend about 10’ beyond the rig and platform. The rig will be at the edge of the platform and there is no egress around the rig. This is about the same point in space as it was last year. The diverter will be pointed out the back of the rig (South) and egress is out for the front (North). Please keep in mind that the rig has been skidded off its traditional substructure. The jack up is more than 100’ away and contains, the mud pits, pumps, fluids shack, power generation, and most of the people. The process safety equation is substantially different than a conventional rig up. I’d be happy to set up a meeting with Facility Engineer, Mark McKinley or Platform Supervisor, Sandy Reynolds to discuss. Two grass roots wells were drilled on diverter last year with a similar diverter location. Last year we kept close approach wells flowing. Because of the variance request we decided to shut in the close approach well, A-15. The proposed configuration has prompted no changes to the platform response for a divert event. Hilcorp has not conducted a HAZOP. We believe there is no shallow hazard. As such, I’m not sure there is a node to start a Hazop from. We conducted a risk conversation and that turned into the shallow hazard analysis that was submitted to the AOGCC. The result of the risk assessment was the original diverter variance request. Regards, sean 8 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, April 22, 2024 9:47 AM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com > Cc: jim.regg <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] NCIU A-19 Diverter Waiver Sean, We are evaluating the variance requests. A few questions 1. How far beyond the rig substructure are you planning to place the vent-line discharge and how far beyond the platform structure? 2. Does Hilcorp have an OIM and process safety engineer that can meet with us to discuss options for complying and risks of non-compliance? 3. Has Hilcorp performed a HAZOP to evaluate the risks? Thank you Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 <image001.jpg> From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Friday, April 19, 2024 11:10 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] NCIU A-19 Diverter Waiver Bryan, Thank you for the information ahead of the PTD so we can plan a different route. Please consider the following two variance requests for A-19: 1. 20 AAC 25.035 (c)(2)(C) the vent line must extend to a point at least 75 feet (i) away from a potential source of ignition 1. Hilcorp proposes 50 foot between the generator exhaust and the vent line. The exhaust points west between legs 1 and 2 and the vent line points south. The rig is between the vent line and exhaust. A schematic is attached. 2. Please also consider information supplied in the original diverter waiver request. Drilling experience shows there is not an intensity kick potential. Swabbing in surface hole is unlikely and drilling experience supports that. The are no reports of lost CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 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. 9 circulation. Drilling experience shows that surface hole flow is not likely or expected. 2. 20 AAC 25.035 (c)(2)(C) (ii) the vent line must extend to a point at least 75 feet beyond the drill rig substructure, or to a point within the reserve pit and at least 50 feet beyond the drill rig substructure; 1. Please note that because we are drilling from a platform, we are unable to meet the requirement. While drilling on diverter the vent line will extend beyond the rig substructure and the platform structure. The rule was previously waived on Tyonek in 2009 during the drilling of A-14, A-15, and A-16. For reference, the threshold for a variance is drilling experience in the near vicinity: (h) Upon request of the operator, the commission will, in its discretion, approve a variance (1) from the BOPE requirements in (e) of this section if the variance provides at least an equally effective means of well control; and (2) from the diverter system requirements in (c) of this section if the variance provides at least equally effective means of diverting flow away from the drill rig or if drilling experience in the near vicinity indicates that a diverter system is not necessary. Regards, sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, April 18, 2024 3:54 PM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com > Subject: [EXTERNAL] NCIU A-19 Diverter Waiver Sean, The diverter waiver request for this well will not be approved. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 <image001.jpg> The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 10 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Sean McLaughlin To:McLellan, Bryan J (OGC) Subject:RE: [EXTERNAL] NCIU A-19 PTD questions Date:Tuesday, April 23, 2024 1:53:35 PM Bryan, The IA very likely has gas. It can be bled down to <50psi after the well is secured. The current plan is to set a TTP in X-nip at 5809’ MD (below all GLM’s), so neither would have communication to the open reservoirs below the TTP. Regards, sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, April 23, 2024 11:59 AM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: RE: [EXTERNAL] NCIU A-19 PTD questions Sean, Is the annulus on A-15 full of lift gas and will it be bled off before the close approach drill-by? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Tuesday, April 23, 2024 11:44 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] NCIU A-19 PTD questions CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Bryan, The A-15 diagram is attached. The text should read 40% cement excess. I’ll remove that text in future programs and will just reference the excess listed in the calculations. The calculations are correct for 40% excess. Mud weight will be less than pore pressure equivalent. At this time, we expect the MPD equipment to be powered from the platform. The MPD system has a battery backup as well as an auxiliary air pump that will allow continued choke operation. The tertiary response is the nitrogen system that could add pressure to the chokes. Secondary well control systems are unchanged and independent. The addition of MPD will change the primary well control barrier. The communication and understanding of the barrier change is the biggest well control risk. Beyond will conduct training sessions with the rig crew that cover MPD operations and contingency situations. Roles and expectation will change. For example, the driller will be required to notify Beyond MPD operator in the event of a power loss. Regards, sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Friday, April 19, 2024 4:18 PM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: [EXTERNAL] NCIU A-19 PTD questions Sean, A few questions about the NCIU A-19 PTD. 1. Could you send a wellbore diagram for NCIU A-15, the close approach well? We don’t have anything current in our wellfiles. 2. Double check the cement volumes for the 4-1/2” liner. I calculate the volume you plan to pump is only 30% open hole excess, but in the text it says you are targeting 50% excess. 3. I’d like to understand how the MPD system will work. Are you planning to have mud weight less than pore pressure equivalent? If so, how will you keep the well in an overbalanced condition if the rig loses power? What else can go wrong wrt well control? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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 nogreater 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. 224-026 TERTIARY GAS NCIU A-19 NORTH COOK INLET W E L L P E R M I T C H E C K L I S T Co m p a n y Hi l c o r p A l a s k a , L L C We l l N a m e : N C O O K I N L E T U N I T A - 1 9 In i t i a l C l a s s / T y p e DE V / P E N D Ge o A r e a 82 0 Un i t 11 4 5 0 On / O f f S h o r e Of f Pr o g r a m DE V Fi e l d & P o o l We l l b o r e s e g An n u l a r D i s p o s a l PT D # : 22 4 0 2 6 0 NO R T H C O O K I N L E T , T E R T I A R Y G A S - 5 6 4 5 7 0 NA 1 P e r m i t f e e a t t a c h e d Ye s AD L 1 7 5 8 9 a n d AD L 3 7 8 3 1 2 L e a s e n u m b e r a p p r o p r i a t e Ye s 3 U n i q u e w e l l n a m e a n d n u m b e r Ye s N O R T H C O O K I N L E T , T E R T I A R Y G A S - 5 6 4 5 7 0 - g o v e r n e d b y 6 8 A 4 W e l l l o c a t e d i n a d e f i n e d p o o l Ye s 5 W e l l l o c a t e d p r o p e r d i s t a n c e f r o m d r i l l i n g u n i t b o u n d a r y NA 6 W e l l l o c a t e d p r o p e r d i s t a n c e f r o m o t h e r w e l l s Ye s 7 S u f f i c i e n t a c r e a g e a v a i l a b l e i n d r i l l i n g u n i t Ye s 8 I f d e v i a t e d , i s w e l l b o r e p l a t i n c l u d e d Ye s 9 O p e r a t o r o n l y a f f e c t e d p a r t y Ye s 10 O p e r a t o r h a s a p p r o p r i a t e b o n d i n f o r c e Ye s 11 P e r m i t c a n b e i s s u e d w i t h o u t c o n s e r v a t i o n o r d e r Ye s 12 P e r m i t c a n b e i s s u e d w i t h o u t a d m i n i s t r a t i v e a p p r o v a l Ye s 13 C a n p e r m i t b e a p p r o v e d b e f o r e 1 5 - d a y w a i t NA 14 W e l l l o c a t e d w i t h i n a r e a a n d s t r a t a a u t h o r i z e d b y I n j e c t i o n O r d e r # ( p u t I O # i n c o m m e n t s ) ( F o r s e r v NA 15 A l l w e l l s w i t h i n 1 / 4 m i l e a r e a o f r e v i e w i d e n t i f i e d ( F o r s e r v i c e w e l l o n l y ) NA 16 P r e - p r o d u c e d i n j e c t o r : d u r a t i o n o f p r e - p r o d u c t i o n l e s s t h a n 3 m o n t h s ( F o r s e r v i c e w e l l o n l y ) NA 17 N o n c o n v e n . g a s c o n f o r m s t o A S 3 1 . 0 5 . 0 3 0 ( j . 1 . A ) , ( j . 2 . A - D ) Ye s 18 C o n d u c t o r s t r i n g p r o v i d e d Ye s 19 S u r f a c e c a s i n g p r o t e c t s a l l k n o w n U S D W s Ye s 20 C M T v o l a d e q u a t e t o c i r c u l a t e o n c o n d u c t o r & s u r f c s g Ye s 21 C M T v o l a d e q u a t e t o t i e - i n l o n g s t r i n g t o s u r f c s g Ye s 22 C M T w i l l c o v e r a l l k n o w n p r o d u c t i v e h o r i z o n s Ye s 23 C a s i n g d e s i g n s a d e q u a t e f o r C , T , B & p e r m a f r o s t Ye s 24 A d e q u a t e t a n k a g e o r r e s e r v e p i t NA 25 I f a r e - d r i l l , h a s a 1 0 - 4 0 3 f o r a b a n d o n m e n t b e e n a p p r o v e d No W e l l N C I U A - 1 5 f a i l s c l o s e a p p r o a c h s u r v e y . A p l u g w i l l b e s e t i n t h e t u b i n g o f A - 1 5 . 26 A d e q u a t e w e l l b o r e s e p a r a t i o n p r o p o s e d No D i v e r t e r v e n t - l i n e < 7 5 ' f r o m i g n i t i o n s o u r c e a n d r i g s u b s t r u c t u r e . C o n d i t i o n a l a p p r o v a l r e c o m m e n d e d 27 I f d i v e r t e r r e q u i r e d , d o e s i t m e e t r e g u l a t i o n s Ye s 28 D r i l l i n g f l u i d p r o g r a m s c h e m a t i c & e q u i p l i s t a d e q u a t e Ye s 29 B O P E s , d o t h e y m e e t r e g u l a t i o n Ye s M P S P = 2 7 5 8 p s i , B O P r a t e d t o 5 k p s i ( B O P t e s t p r e s u r e 3 0 0 0 p s i ) 30 B O P E p r e s s r a t i n g a p p r o p r i a t e ; t e s t t o ( p u t p s i g i n c o m m e n t s ) Ye s 31 C h o k e m a n i f o l d c o m p l i e s w / A P I R P - 5 3 ( M a y 8 4 ) Ye s 32 W o r k w i l l o c c u r w i t h o u t o p e r a t i o n s h u t d o w n No 33 I s p r e s e n c e o f H 2 S g a s p r o b a b l e NA 34 M e c h a n i c a l c o n d i t i o n o f w e l l s w i t h i n A O R v e r i f i e d ( F o r s e r v i c e w e l l o n l y ) Ye s H 2 S n o t e x p e c t e d i n t h i s w e l l . 35 P e r m i t c a n b e i s s u e d w / o h y d r o g e n s u l f i d e m e a s u r e s Ye s B e l u g a A t o I e x p e c t e d t o b e n o r m a l l y p r e s s u r e d ( ~ 8 . 3 p p g ) ; i n c r e a s i n g t o 9 . 8 p p g E M W a t t a r g e t B e l u g a U 36 D a t a p r e s e n t e d o n p o t e n t i a l o v e r p r e s s u r e z o n e s Ye s P r o v i d e d a s j u s t i f i c a t i o n f o r d i v e r t e r w a i v e r 37 S e i s m i c a n a l y s i s o f s h a l l o w g a s z o n e s NA D r i l e d f r o m T y o n e k p l a t f o r m 38 S e a b e d c o n d i t i o n s u r v e y ( i f o f f - s h o r e ) NA 39 C o n t a c t n a m e / p h o n e f o r w e e k l y p r o g r e s s r e p o r t s [ e x p l o r a t o r y o n l y ] Ap p r AD D Da t e 4/ 3 0 / 2 0 2 4 Ap p r BJ M Da t e 5/ 8 / 2 0 2 4 Ap p r AD D Da t e 4/ 3 0 / 2 0 2 4 Ad m i n i s t r a t i o n En g i n e e r i n g Ge o l o g y Ge o l o g i c Co m m i s s i o n e r : Da t e : En g i n e e r i n g Co m m i s s i o n e r : Da t e Pu b l i c Co m m i s s i o n e r Da t e MP D t o b e e m p l o y e d i n 8 . 5 " p r o d u c t i o n h o l e *& : JL C 5 / 9 / 2 0 2 4