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Home My WebLink About225-021Nolan 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: 5/29/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250529 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 19RD 50133205790100 219188 5/10/2025 AK E-LINE GPT/CIBP/Perf HVB 13A 50231200320100 224160 3/16/2025 YELLOWJACKET SCBL IRU 241-01 50283201840000 221076 5/7/2025 AK E-LINE Plug/Perf KBU 22-06Y 50133206500000 215044 5/6/2025 AK E-LINE Perf KBU 22-06Y 50133206500000 215044 5/7/2025 AK E-LINE Perf KBU 24-06RD 50133204990100 206013 4/8/2025 YELLOWJACKET GPT-PLUG MPI 1-61 50029225200000 194142 5/10/2025 AK E-LINE Perf MPU E-42 50029236350000 219082 5/3/2025 AK E-LINE Patch MPU S-55 50029238130000 225006 5/13/2025 AK E-LINE CBL OP16-03 50029234420000 211017 4/25/2025 READ LeakDetect PAXTON 13 50133207330000 225021 4/29/2025 YELLOWJACKET SCBL PBU 01-12B 50029202690200 223090 4/8/2025 HALLIBURTON RBT PBU D-08B 50029203720200 225007 3/22/2025 BAKER MRPM PBU H-17B (REVISION)50029208620100 197152 4/10/2025 HALLIBURTON RBT-COILFLAG PBU J-25B 50029217410200 224134 3/10/2025 BAKER MRPM PBU K-19C (REVISION)50029225310300 224004 3/27/2025 BAKER MRPM PBU K-19C 50029225310300 224004 3/27/2025 HALLIBURTON RBT SRU 241-33B 50133206960000 221053 3/12/2025 YELLOWJACKET PERF Revision Explanation: Both wells had wrong side stack well name and API#/PTD on previous upload H-17b was marked as H-17A and K-19C was marked as K-19B. Well name now reflets correct sidetrack and has correct SPI# and PTD. T40489 T40490 T40491 T40492 T40492 T40493 T40494 T40495 T40496 T40497 T40498 T40499 T40500 T40501 T40502 T40503 T40503 T40504 PAXTON 13 50133207330000 225021 4/29/2025 YELLOWJACKET SCBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.05.29 14:33:01 -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: 05/15/2025 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: PAXTON 13 PTD: 225-021 API: 50-133-20733-00-00 FINAL LWD FORMATION EVALUATION LOGS (03/29/2025 to 04/17/2025) DGR PCG, ADR, EWR-4, ALD, CTN (2” & 5” MD/TVD Color Logs) Final Definitive Directional Survey SFTP Transfer – Main Folders: FINAL LWD Subfolders: Please include current contact information if different from above. 225-021 T40426 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.05.16 08:17:42 -08'00' 1 Gluyas, Gavin R (OGC) From:McLellan, Bryan J (OGC) Sent:Friday, May 2, 2025 12:09 PM To:Scott Warner Cc:Noel Nocas Subject:RE: [EXTERNAL] RE: Paxton 13 AOGCC 10-403 325-258 PTD 225-021 Approved 05-01-25 Scott, Your plan below is approved for this sundry. I’m looking forward to continuing this discussion and coming to an agreement on how to deal with this common situation. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Scott Warner <Scott.Warner@hilcorp.com> Sent: Friday, May 2, 2025 11:45 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Noel Nocas <Noel.Nocas@hilcorp.com> Subject: RE: [EXTERNAL] RE: Paxton 13 AOGCC 10-403 325-258 PTD 225-021 Approved 05-01-25 Bryan, Hilcorp would like more Ɵme to formulate a response to this maƩer. Due to the Ɵme sensiƟvity of the Paxton 13 perforaƟons beginning, we are requesƟng that we will set a plug every 500’ MD that has open perforaƟons below with 10’ of cement on top. 10’ of cement is sufficient for a ~8500 psi pressure differenƟal. Thank you, ScoƩ Warner Kenai – OperaƟons Engineer Office: (907) 564-4506 Cell: (907) 830-8863 To help protect your priv acy, Microsoft Office prevented automatic download of this picture from the Internet. 2 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, May 1, 2025 4:32 PM To: Scott Warner <Scott.Warner@hilcorp.com> Cc: Noel Nocas <Noel.Nocas@hilcorp.com>; Stefan Reed <Stefan.Reed@hilcorp.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: [EXTERNAL] RE: Paxton 13 AOGCC 10-403 325-258 PTD 225-021 Approved 05-01-25 Scott, It’s not my intention that you place cement on top of 20 plugs. I’m glad you initiated a conversation about this. The sundry covers perfs over approximately 3500’ TVD interval. The AOGCC wouldn’t accept a P&A with 3500’ TVD of perfs open and elastomers are not suƯicient for P&A purposes, especially since you are not pressure testing any of them. It’s much easier to place cement now than to go back later and drill out multiple plugs. What’s a reasonable frequency to install cement plugs opportunistically through this interval? It’s hard for me to specify since we don’t know where plugs might be set. The easy thing for me to say is just put cement on a plug whenever you set one, but I’d be interested in your suggestion for a more practical approach. We don’t want to end up with a P&A application where Hilcorp wants to put a single cement plug above the top of a 3500+ TVD interval. In that case you would probably need to drill out some plugs to get cement deeper. I’m open to suggestions on a reasonable cement plug frequency that has a basis in the geology and fluid distribution. I’m interested in ultimately getting an agreement about P&A strategy added into the pool rules, especially where the pools cover a huge TVD range. But I’m sure we can come to terms on this well in the mean time. I’ve copied our geologists here and I think input from Hilcorp’s geologists would be beneficial. I’m looking forward to more discussion on the topic. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Scott Warner <Scott.Warner@hilcorp.com> Sent: Thursday, May 1, 2025 4:07 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Noel Nocas <Noel.Nocas@hilcorp.com>; Stefan Reed <Stefan.Reed@hilcorp.com> Subject: FW: Paxton 13 AOGCC 10-403 325-258 PTD 225-021 Approved 05-01-25 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 3 Bryan, Thank you for the quick approval. I would like to discuss the 25’ of cement on every plug if intervals allow. This could have us seƫng up to 20 plugs with cement on top of each one. 15 of those plugs are within a ~2300’ TVD secƟon which in the past has been allowed. Why does a CIBP that is rated to 10,000 psi differenƟal not count as an acceptable plugging method? That will sƟll confine all hydrocarbons and freshwater to their respecƟve indigenous strata and prevent them from migraƟng into other strata or to surface. Due to how we are consistently tesƟng sands in Kenai that have potenƟal to be plugged back can there be a certain TVD interval that cement will be required like we have done in the past? I hope we find gas in this well and it is not an issue but we may need up to 20 plugs with cement on top if every interval we test comes back wet/nonproducƟve. Entry into and out of a well is arguably the highest risk acƟvity we do due to working at heights with both toolstring handling, personnel on manliŌs, crane operaƟons, etc. Dump bailing 25’ of cement in 3-1/2” adds 2-3 addiƟonal runs and 4-6 addiƟonal Ɵmes crews have to pop on and off the well which subjects them to these risks. Well Name Zone Top MD Bottom MD Top TVD Bottom TVD Footage 25' of cement required if plug is set Paxton 13 T-3 5112 5120 3878 3886 8 yes Paxton 13 T-3 5147 5153 3912 3918 6 yes Paxton 13 T-3 5190 5204 3953 3966 14 Paxton 13 T-5 5229 5237 3990 3998 8 87' between intervals yes Paxton 13 T-5B 5324 5339 4081 4096 15 Paxton 13 T-5B 5340 5346 4097 4103 6 Paxton 13 T-6 5349 5420 4105 4174 71 60' between intervals yes Paxton 13 T-6 5480 5489 4232 4241 9 Paxton 13 T-7 5516 5522 4267 4273 6 Paxton 13 T-7 5534 5540 4284 4290 6 Paxton 13 T-7 5546 5562 4296 4311 16 Paxton 13 T-8 5579 5589 4328 4338 10 Paxton 13 T-8 5591 5604 4339 4351 13 Paxton 13 T-8 5605 5613 4353 4361 8 153' between intervals yes Paxton 13 T-10A 5766 5776 4510 4520 10 Paxton 13 T-10A 5791 5803 4535 4547 12 Paxton 13 T-10B 5815 5823 4558 4566 8 Paxton 13 T-10B 5826 5845 4569 4588 19 Paxton 13 T-10B 5858 5866 4601 4609 8 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. 4 Paxton 13 T-115 5874 5880 4616 4622 6 361' between intervals yes Paxton 13 T-13 6241 6247 4974 4980 6 125' between intervals yes Paxton 13 T-14 6372 6378 5101 5107 6 91' between intervals yes Paxton 13 T-16 6469 6479 5194 5204 10 43' between intervals yes Paxton 13 T-17 6522 6542 5244 5263 20 Paxton 13 T-17 6544 6601 5265 5320 57 51' between intervals yes Paxton 13 T-18 6652 6658 5368 5374 6 Paxton 13 T-18 6673 6688 5388 5402 15 Paxton 13 T-18 6691 6704 5405 5417 13 Paxton 13 T-18 6727 6737 5440 5450 10 206' between intervals yes Paxton 13 T-37 6943 6966 5647 5669 23 Paxton 13 T-37 6977 6995 5679 5696 18 Paxton 13 T-37 7013 7033 5714 5733 20 605' between intervals yes Paxton 13 T-53 7638 7672 6315 6348 34 55' between intervals yes Paxton 13 T-55 7727 7733 6401 6407 6 167' between intervals yes Paxton 13 T-65 7900 7920 6568 6587 20 36' between intervals yes Paxton 13 T-67 7956 7966 6621 6631 10 175' between intervals yes Paxton 13 T-80 8141 8155 6800 6814 14 65' between intervals yes Paxton 13 T-83 8220 8234 6876 6890 14 124' between intervals yes Paxton 13 T-90 8358 8398 7011 7050 40 Paxton 13 T-90 8423 8451 7075 7102 28 82' between intervals yes Paxton 13 T-100 8533 8558 7182 7206 25 Paxton 13 T-100 8573 8598 7221 7245 25 Paxton 13 T-100 8601 8623 7248 7269 22 45' between intervals yes Paxton 13 T-115 8668 8684 7313 7329 16 Paxton 13 T-115 8687 8697 7332 7341 10 I will be out of town starƟng Friday at 1 PM and back Tuesday at ~4 PM. I will have very limited service and Stefan Reed will be covering for me in my absence. 5 Thanks, ScoƩ Warner Kenai – OperaƟons Engineer Office: (907) 564-4506 Cell: (907) 830-8863 To help protect your priv acy, Microsoft Office prevented automatic download of this picture from the Internet. From: Donna Ambruz <dambruz@hilcorp.com> Sent: Thursday, May 1, 2025 8:19 AM To: Scott Warner <Scott.Warner@hilcorp.com> Cc: Noel Nocas <Noel.Nocas@hilcorp.com> Subject: Paxton 13 AOGCC 10-403 325-258 PTD 225-021 Approved 05-01-25 FYI – Please distribute as necessary. Thank you. Donna Ambruz Operations/Regulatory Tech KEN Asset Team Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 907.777.8305 - Direct dambruz@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that 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. 6 While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Initial Completion, N2 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 8,940'N/A Casing Collapse Structural Conductor 1,410psi Surface 4,790psi Intermediate Production 10,540psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng scott.warner@hilcorp.com 907-564-4506 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Scott Warner, Operations Engineer AOGCC USE ONLY Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 Private FEE, ADL 384372 225-021 50-133-20733-00-00 Hilcorp Alaska, LLC Proposed Pools: 9.2# / L-80 TVD Burst 2,414' 10,160psi 1,992' Size 120' 2,575' MD See Attached Schematic 2,980psi 6,890psi 120'120' 2,575' April 28, 2025 Tieback 3-1/2" 8,939' Perforation Depth MD (ft): 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Ninillchik Paxton 13CO 701C Same 7,578'3-1/2" ~2493psi 6,558' N/A Length LTP; SSSV 2,381' MD/ 1,906' TVD; 148' MD/TVD 7,578'8,872'7,512' Ninilchik Unit Beluga-Tyonek Gas 16" 7-5/8" See Attached Schematic m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 1:13 pm, Apr 25, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.04.25 11:17:47 - 08'00' Noel Nocas (4361) 325-258 DSR-4/29/25SFD 4/28/2025 RUSH SFD Perforate Dump bail 25 ft of cement on top of any plug set, unless there is not enough room between the plug and the next set of shallower perfs BOP test to 3500 psi. Submit CBL to AOGCC and obtain approval before perforating. BJM 4/30/25 10-407 X *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.05.01 07:58:36 -08'00'05/01/25 RBDMS JSB 050125 Well Prognosis Well Name: Paxton 13 API Number: 50-133-20733-00-00 Current Status: New Drill Well Permit to Drill Number: 225-021 Regulatory Contact: Donna Ambruz (907) 777-8305 First Call Engineer: Scott Warner (907) 564-4506 (O) (907) 830-8863 (C) Second Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Maximum Expected BHP: 3226 psi @ 7332’ TVD (Based on 0.44 psi/ft gradient) Max. Potential Surface Pressure:2493 psi (Based on 0.1 psi/ft gas gradient to surface) Applicable Frac Gradient: .754 psi/ft using 14.5 ppg EMW FIT at the 7-5/8” surface casing shoe Shallowest Allowable Perf TVD: MPSP/(0.754-0.1) = 2493 psi / 0.654 = 3811’ TVD Top of Applicable Gas Pool: 1609’ MD/1480’ TVD (Beluga-Tyonek) Well Status: New Drill Initial Completion Brief Well Summary Paxton 13 is a new drill, grassroots well targeting the Tyonek and Beluga sands. This objective of this sundry is to clean out the liner with coil tubing/nitrogen and perforate the T-3 through T-115. Wellbore Conditions: - Max Inclination – 64.72° at 2,701’ MD - Max DLS °/100’ – 5.93° at 1,272’ MD - SSSV @ 148’ MD w/ 2.992” ID - Liner is full of ~9.1 ppg 6% KCl mud - Tubing and IA are displaced to 8.4 ppg CIW - T & IA were pressure tested to 3000 psi - Min ID- 2.992” 3-1/2” tubing/liner Pre-Sundry Eline Work: 1. Review all approved COAs 2. MIRU E-line and pressure control equipment 3. Log well with CBL tool in 3-1/2” liner a. Send results to AOGCC to review prior to perforating 4. RDMO E-line Pre-Sundry Coil Cleanout Procedure: 1. MIRU Coil Tubing and pressure control equipment 2. PT BOPE to 250 psi low / 3,500 psi high a. Provide AOGCC 24hr notice for BOP test 3. RIH & clean out wellbore to ~8,864’ MD (~8’ above landing collar), displace liner to 8.4 ppg water 4. Reverse out wellbore with nitrogen, trap ~2400 psi on wellbore a. ~77 bbls total wellbore volume 5. RDMO Coil Tubing Add Perf SUNDRIED WORK 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250 psi low / 3,500 psi high 3. Ops bleed N2 from well as directed by OE/RE for desired perforating pressure by zone (typically targeting 20% underbalance) 4. RIH and perforate per RE/Geo and test sands within the interval below, from the bottom up: perforate the T-3 through T-115 Well Prognosis Below are proposed targeted sands in order of testing (bottom/up), but additional sand may be added depending on results of these perfs, between the proposed top and bottom perfs Sand Top MD Btm MD Top TVD Btm TVD Interval T-3 ±5,112' ±5,120' ±3,878' ±3,886' ±8' T-3 ±5,147' ±5,153' ±3,912' ±3,918' ±6' T-3 ±5,190' ±5,204' ±3,953' ±3,966' ±14' T-5 ±5,229' ±5,237' ±3,990' ±3,998' ±8' T-5B ±5,324' ±5,339' ±4,081' ±4,096' ±15' T-5B ±5,340' ±5,346' ±4,097' ±4,103' ±6' T-6 ±5,349' ±5,420' ±4,105' ±4,174' ±71' T-6 ±5,480' ±5,489' ±4,232' ±4,241' ±9' T-7 ±5,516' ±5,522' ±4,267' ±4,273' ±6' T-7 ±5,534' ±5,540' ±4,284' ±4,290' ±6' T-7 ±5,546' ±5,562' ±4,296' ±4,311' ±16' T-8 ±5,579' ±5,589' ±4,328' ±4,338' ±10' T-8 ±5,591' ±5,604' ±4,339' ±4,351' ±13' T-8 ±5,605' ±5,613' ±4,353' ±4,361' ±8' T-10A ±5,766' ±5,776' ±4,510' ±4,520' ±10' T-10A ±5,791' ±5,803' ±4,535' ±4,547' ±12' T-10B ±5,815' ±5,823' ±4,558' ±4,566' ±8' T-10B ±5,826' ±5,845' ±4,569' ±4,588' ±19' T-10B ±5,858' ±5,866' ±4,601' ±4,609' ±8' T-115 ±5,874' ±5,880' ±4,616' ±4,622' ±6' T-13 ±6,241' ±6,247' ±4,974' ±4,980' ±6' T-14 ±6,372' ±6,378' ±5,101' ±5,107' ±6' T-16 ±6,469' ±6,479' ±5,194' ±5,204' ±10' T-17 ±6,522' ±6,542' ±5,244' ±5,263' ±20' T-17 ±6,544' ±6,601' ±5,265' ±5,320' ±57' T-18 ±6,652' ±6,658' ±5,368' ±5,374' ±6' T-18 ±6,673' ±6,688' ±5,388' ±5,402' ±15' T-18 ±6,691' ±6,704' ±5,405' ±5,417' ±13' T-18 ±6,727' ±6,737' ±5,440' ±5,450' ±10' T-37 ±6,943' ±6,966' ±5,647' ±5,669' ±23' T-37 ±6,977' ±6,995' ±5,679' ±5,696' ±18' T-37 ±7,013' ±7,033' ±5,714' ±5,733' ±20' T-53 ±7,638' ±7,672' ±6,315' ±6,348' ±34' T-55 ±7,727' ±7,733' ±6,401' ±6,407' ±6' Well Prognosis T-65 ±7,900' ±7,920' ±6,568' ±6,587' ±20' T-67 ±7,956' ±7,966' ±6,621' ±6,631' ±10' T-80 ±8,141' ±8,155' ±6,800' ±6,814' ±14' T-83 ±8,220' ±8,234' ±6,876' ±6,890' ±14' T-90 ±8,358' ±8,398' ±7,011' ±7,050' ±40' T-90 ±8,423' ±8,451' ±7,075' ±7,102' ±28' T-100 ±8,533' ±8,558' ±7,182' ±7,206' ±25' T-100 ±8,573' ±8,598' ±7,221' ±7,245' ±25' T-100 ±8,601' ±8,623' ±7,248' ±7,269' ±22' T-115 ±8,668' ±8,684' ±7,313' ±7,329' ±16' T-115 ±8,687' ±8,697' ±7,332' ±7,341' ±10' a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations i. Pending well production, all perf intervals may not be completed ii.Note: Note: A CIBP may be used instead of WRP if it is determined that no cement is needed for operational purposes. iii. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations 5. RDMO 6. Turn well over to production & flow test well 7. Test SVS as necessary once well has reached stable flow rates a. Notify state 24 hrs prior to testing within 5 days of stable production Coil Procedure (Contingency) 1. MIRU Coil Tubing, PT BOPE to 250 psi low / 3,500 psi high a. Provide AOGCC 24 hr notice for BOP test 2. PU wash nozzle and/or motor and mill, RIH and cleanout well to below perfs or proposed plug depth 3. PU CT jet nozzle and RIH, unload fluid from wellbore with nitrogen Attachments: 1. Current Schematic 2. Proposed Schematic 3. Coil Tubing BOP Schematic 4. Standard Well Procedure – N2 Operations Dump bail 25 ft of cement on top of any plug set, unless there is not enough room between the plug and the next set of shallower perfs. -bjm Updated by DMA 04-24-25 CURRENT SCHEMATIC Ninilchik Unit Paxton 13 PTD: 225-021 API: 50-133-20733-00-00 PBTD = 8,872’ / TVD = 7,512’ TD = 8,940’ / TVD = 7,578’ RKB to GL = 18’ OPEN HOLE / CEMENT DETAIL 7-5/8" Est. TOC @ Surface. 60 bbl 10.5 ppg spacer, 152 bbl 12 ppg lead followed by 37 bbls 15.8 ppg tail cement. 3-1/2” Est. TOC @ ~3205’ . (63 bbls lost) 40 bbl 10.5 ppg spacer followed by 270 bbl 12 ppg lead cement and 24 bbl 15.3 ppg tail cement. CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120’ 7-5/8" Surf Csg 29.7 L-80 GBCD 6.875” Surf 2,575’ 3-1/2" Prod Lnr 9.2 L-80 Wedge 563 2.992” 2,381’ 8,939’ 3-1/2" Prod Tieback 9.2 L-80 EUE 2.992” Surf 2,414’ 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 148’ 2.992 3.50 SSSV 2 2,381’ 5.25” 5.630” Liner hanger / LTP Assembly 3 2,404’ 3.958” 5.630” Seal Stem 6-3/4” hole 2/3 1 Updated by SRW 04-22-25 PROPOSED SCHEMATIC Ninilchik Unit Paxton 13 PTD: 225-021 API: 50-133-20733-00-00 PBTD = 8,872’ / TVD = 7,512’ TD = 8,940’ / TVD = 7,578’ RKB to GL = 18’ OPEN HOLE / CEMENT DETAIL 7-5/8" Est. TOC @ Surface. 60 bbl 10.5 ppg spacer, 152 bbl 12 ppg lead followed by 37 bbls 15.8 ppg tail cement. 3-1/2” Est. TOC @ ~3205’ . (63 bbls lost) 40 bbl 10.5 ppg spacer followed by 270 bbl 12 ppg lead cement and 24 bbl 15.3 ppg tail cement. CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120’ 7-5/8" Surf Csg 29.7 L-80 GBCD 6.875” Surf 2,575’ 3-1/2" Prod Lnr 9.2 L-80 Wedge 563 2.992” 2,381’ 8,939’ 3-1/2" Prod Tieback 9.2 L-80 EUE 2.992” Surf 2,414’ 16” 7-5/8” 9-7/8” hole 3-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 148’ 2.992 3.50 SSSV 2 2,381’ 5.25” 5.630” Liner hanger / LTP Assembly 3 2,404’ 3.958” 5.630” Seal Stem 6-3/4” hole 2/3 1 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status T-3 ±5,112' ±5,120' ±3,878' ±3,886' ±8' Proposed TBD T-3 ±5,147' ±5,153' ±3,912' ±3,918' ±6' Proposed TBD T-3 ±5,190' ±5,204' ±3,953' ±3,966' ±14' Proposed TBD T-5 ±5,229' ±5,237' ±3,990' ±3,998' ±8' Proposed TBD T-5B ±5,324' ±5,339' ±4,081' ±4,096' ±15' Proposed TBD T-5B ±5,340' ±5,346' ±4,097' ±4,103' ±6' Proposed TBD T-6 ±5,349' ±5,420' ±4,105' ±4,174' ±71' Proposed TBD T-6 ±5,480' ±5,489' ±4,232' ±4,241' ±9' Proposed TBD T-7 ±5,516' ±5,522' ±4,267' ±4,273' ±6' Proposed TBD T-7 ±5,534' ±5,540' ±4,284' ±4,290' ±6' Proposed TBD T-7 ±5,546' ±5,562' ±4,296' ±4,311' ±16' Proposed TBD T-8 ±5,579' ±5,589' ±4,328' ±4,338' ±10' Proposed TBD T-8 ±5,591' ±5,604' ±4,339' ±4,351' ±13' Proposed TBD T-8 ±5,605' ±5,613' ±4,353' ±4,361' ±8' Proposed TBD T-10A ±5,766' ±5,776' ±4,510' ±4,520' ±10' Proposed TBD T-10A ±5,791' ±5,803' ±4,535' ±4,547' ±12' Proposed TBD T-10B ±5,815' ±5,823' ±4,558' ±4,566' ±8' Proposed TBD T-10B ±5,826' ±5,845' ±4,569' ±4,588' ±19' Proposed TBD T-10B ±5,858' ±5,866' ±4,601' ±4,609' ±8' Proposed TBD T-115 ±5,874' ±5,880' ±4,616' ±4,622' ±6' Proposed TBD T-13 ±6,241' ±6,247' ±4,974' ±4,980' ±6' Proposed TBD T-14 ±6,372' ±6,378' ±5,101' ±5,107' ±6' Proposed TBD T-16 ±6,469' ±6,479' ±5,194' ±5,204' ±10' Proposed TBD T-17 ±6,522' ±6,542' ±5,244' ±5,263' ±20' Proposed TBD T-17 ±6,544' ±6,601' ±5,265' ±5,320' ±57' Proposed TBD T-18 ±6,652' ±6,658' ±5,368' ±5,374' ±6' Proposed TBD T-18 ±6,673' ±6,688' ±5,388' ±5,402' ±15' Proposed TBD T-18 ±6,691' ±6,704' ±5,405' ±5,417' ±13' Proposed TBD T-18 ±6,727' ±6,737' ±5,440' ±5,450' ±10' Proposed TBD T-37 ±6,943' ±6,966' ±5,647' ±5,669' ±23' Proposed TBD T-37 ±6,977' ±6,995' ±5,679' ±5,696' ±18' Proposed TBD T-37 ±7,013' ±7,033' ±5,714' ±5,733' ±20' Proposed TBD T-53 ±7,638' ±7,672' ±6,315' ±6,348' ±34' Proposed TBD T-55 ±7,727' ±7,733' ±6,401' ±6,407' ±6' Proposed TBD PERFORATION DETAIL Cont’d on Pg. 2 Updated by SRW 04-22-25 PROPOSED SCHEMATIC Ninilchik Unit Paxton 13 PTD: 225-021 API: 50-133-20733-00-00 PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status T-65 ±7,900' ±7,920' ±6,568' ±6,587' ±20' Proposed TBD T-67 ±7,956' ±7,966' ±6,621' ±6,631' ±10' Proposed TBD T-80 ±8,141' ±8,155' ±6,800' ±6,814' ±14' Proposed TBD T-83 ±8,220' ±8,234' ±6,876' ±6,890' ±14' Proposed TBD T-90 ±8,358' ±8,398' ±7,011' ±7,050' ±40' Proposed TBD T-90 ±8,423' ±8,451' ±7,075' ±7,102' ±28' Proposed TBD T-100 ±8,533' ±8,558' ±7,182' ±7,206' ±25' Proposed TBD T-100 ±8,573' ±8,598' ±7,221' ±7,245' ±25' Proposed TBD T-100 ±8,601' ±8,623' ±7,248' ±7,269' ±22' Proposed TBD T-115 ±8,668' ±8,684' ±7,313' ±7,329' ±16' Proposed TBD T-115 ±8,687' ±8,697' ±7,332' ±7,341' ±10' Proposed TBD PERFORATION DETAIL Cont’d from Pg. 1 STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. CAUTION: 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:Joshua Riley - (C) To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC) Subject:MIT Paxton 13 Hilcorp 169 Date:Sunday, April 20, 2025 8:13:59 AM Attachments:Paxton 13 MIT tubing and IA 4-20-25.xlsx Here is our MIT for Paxton 13 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. Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2250210 Type Inj N Tubing 3099 3073 3046 Type Test P Packer TVD 1914 BBL Pump 0.8 IA 35 35 35 Interval O Test psi 3000 BBL Return 0.8 OA 0 0 0 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2250210 Type Inj N Tubing 80 60 60 Type Test P Packer TVD 1914 BBL Pump 1.0 IA 3075 3055 3055 Interval O Test psi 3000 BBL Return 1.0 OA 0 0 0 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes:Post Completion Testing Notes: Notes: Hilcorp Alaska LLC Ninilchik Paxton Waived by Jim Regg Josh Riley 04/20/25 Notes:Post Completion Testing Notes: Notes: Notes: Paxton 13 Paxton 13 Form 10-426 (Revised 01/2017)2025-0420_MITP_Ninilchik_Paxton-13 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________NINILCHIK UNIT PAXTON 13 JBR 05/14/2025 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 TJ 3-1/2" & 4-1/2" Accumulator bottle precharge avg. 1036 psi 15 bottles. Had a late start they had trouble pulling wear ring when I arrived and then set test plug took 3 hrs. Test Results TEST DATA Rig Rep:Shawn TrickOperator:Hilcorp Alaska, LLC Operator Rep:J. Riley / J. Richardson Rig Owner/Rig No.:Hilcorp 169 PTD#:2250210 DATE:4/15/2025 Type Operation:DRILL Annular: 250/3000Type Test:BIWKLY Valves: 250/3000 Rams: 250/3000 Test Pressures:Inspection No:bopKPS250416085037 Inspector Kam StJohn Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 3 MASP: 2634 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 1 P Inside BOP 1 P FSV Misc 0 NA 15 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 11"P #1 Rams 1 2-7/8" x 5"P #2 Rams 1 Blinds P #3 Rams 1 2-7/8" x 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&2-1/16 P Kill Line Valves 1 2-1/16"P Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P1635 200 PSI Attained P20 Full Pressure Attained P92 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P4@ 2500 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 P14 #1 Rams P5 #2 Rams P4 #3 Rams P5 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P1 9 9 9999 9 9 9 9 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 Sean McLaughlin Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Ninilchik Unit, Beluga/Tyonek Gas Pool, NINU Paxton 13 Hilcorp Alaska, LLC Permit to Drill Number: 225-021 Surface Location: 861' FNL, 3104' FEL, Sec 13, T1S, R14W, SM, AK Bottomhole Location: 2368' FNL, 1440' FWL, Sec 12, T1S, R14W, SM, AK Dear Mr. McLaughlin: 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 AOGCCreserves 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 AOGCCspecifically 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 AOGCCorder, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski Commissioner DATED this 1th day of March 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.03.13 09:52:42 -08'00' 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 8,900' TVD: 7,525' 4a. Location of Well (Governmental Section):7. Property Designation: Surface: Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 166.7 15. Distance to Nearest Well Open Surface: x-206221 y-2230504 Zone-4 148.7 to Same Pool: 200' to Pax 1 16. Deviated wells:Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 62 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Conductor 16" 84# X-56 Weld 120' Surface Surface 120' 120' 9-7/8" 7-5/8" 29.7# L-80 GBCD 2,591' Surface Surface 2,591' 2,000' 6-3/4" 3-1/2" 9.2# L-80 Hyd 563 6,509' 2,391' 1,906' 8,900' 7,525' Tieback 3-1/2" 9.2# L-80 EUE 2,391' Surface Surface 2,391' 1,906' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned?Yes No 20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number: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 3/21/2025 5007' to nearest unit boundary Sean Mclaughlin sean.mclaughlin@hilcorp.com 907-223-6784 Tieback Assy. 3508 Cement Volume MD Drilling Manager Sean Mclaughlin 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft):Perforation Depth MD (ft): Conductor/Structural Authorized Title: Authorized Signature: Authorized Name: Production Liner Intermediate LengthCasing Size Plugs (measured): (including stage data) Driven L - 850 ft3 / T - 208 ft3 Effect. Depth MD (ft):Effect. Depth TVD (ft): 18. Casing Program:Top - Setting Depth - BottomSpecifications 3387 GL / BF Elevation above MSL (ft): Total Depth MD (ft):Total Depth TVD (ft): 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 L - 1516 ft3 / T - 131 ft3 2634 468' FSL, 1892' FWL, Sec 12, T1S, R14W, SM, AK 2368' FNL, 1440' FWL, Sec 12, T1S, R14W, SM, AK LOCI 04-007 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 861' FNL, 3104' FEL, Sec 13, T1S, R14W, SM, AK Private FEE, ADL 384372 Paxton 13 Ninilchik Unit Beluga/Tyonek Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. s N ype of W L l R L Class: os N s No s N o D s s sD 84 o well is G S S 20 AA S S S s Nos No S G y 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) By Gavin Gluyas at 10:55 am, Feb 27, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.02.27 10:33:26 - 09'00' Sean McLaughlin (4311) Submit FIT/LOT results within 48 hrs of performing test. A.Dewhurst 11MAR25 BOP test to 3000 psi, annular test to 2500 psi. 225-021 DSR-2/28/25 NINU BJM 3/12/25 50-133-20733-00-00 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.03.13 09:52:58 -08'00' 03/13/25 03/13/25 RBDMS JSB 031825 Paxton 13 PTD Program Ninilchik Field February 25, 2025 PAXTON 13 Drilling Procedure Contents 1.0 Well Summary................................................................................................................................2 2.0 Management of Change Information...........................................................................................3 3.0 Tubular Program:..........................................................................................................................4 4.0 Drill Pipe Information:..................................................................................................................4 5.0 Internal Reporting Requirements................................................................................................5 6.0 Planned Wellbore Schematic........................................................................................................6 7.0 Drilling / Completion Summary...................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications....................................................................8 9.0 R/U and Preparatory Work........................................................................................................10 10.0 N/U 21-1/4” 2M Diverter.............................................................................................................11 11.0 Drill 9-7/8” Hole Section..............................................................................................................12 12.0 Run 7-5/8” Surface Casing..........................................................................................................14 13.0 Cement 7-5/8” Surface Casing....................................................................................................16 14.0 BOP N/U and Test........................................................................................................................18 15.0 Drill 6-3/4” Hole Section..............................................................................................................19 16.0 Run 3-1/2” Production Liner......................................................................................................21 17.0 Cement 3-1/2” Production Liner................................................................................................25 18.0 3-1/2” Liner Tieback Polish Run................................................................................................28 19.0 3-1/2” Tieback Run, ND/NU, RDMO.........................................................................................29 20.0 Diverter Schematic ......................................................................................................................30 21.0 BOP Schematic.............................................................................................................................31 22.0 Wellhead Schematic.....................................................................................................................32 23.0 Anticipated Drilling Hazards......................................................................................................33 24.0 Hilcorp Rig 169 Layout...............................................................................................................35 25.0 FIT/LOT Procedure ....................................................................................................................36 26.0 Rig 169 Choke Manifold Schematic...........................................................................................37 27.0 Casing Design Information.........................................................................................................38 28.0 6-3/4” Hole Section MASP..........................................................................................................39 29.0 Spider Plot w/ 660’.......................................................................................................................40 30.0 Surface Plat As-Built...................................................................................................................41 Page 2 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 1.0 Well Summary Well PAXTON 13 Pad & Old Well Designation Paxton Pad – Grassroots Well Planned Completion Type 3-1/2” Production Liner w/Tieback (monobore) Target Reservoir(s)Tyonek / Lower Beluga Planned Well TD, MD / TVD 8900 MD / 7526’ TVD PBTD, MD / TVD 8800’ MD AFE Number AFE Drilling Days AFE Drilling Amount Maximum Anticipated Pressure (Surface)2634 psi Maximum Anticipated Pressure (Downhole/Reservoir)3387 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB 166.70’ Ground Elevation 148.70’ BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram Page 3 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 2.0 Management of Change Information Page 4 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 3.0 Tubular Program: Hole Section OD (in)ID (in)Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 16”15.01”14.822”-84 X-56 Weld 2980 1410 - Surface 9-7/8”7-5/8”6.875”6.750”8.500”29.7 L-80 GBCD 6890 4790 683 Prod 6-3/4”3-1/2”2.992”2.867”4.250”9.2 L-80 HYD-563 10160 10540 207 ** Liner must overlap surface casing by at least 100’. 4.0 Drill Pipe Information: Hole Section OD (in)ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 5 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellView. 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. 5.2 Afternoon Updates x Submit a short operations update each day to kenaiciodrilling@hilcorp.com 5.3 Morning Update x Submit a short operations update each morning by 7am in NDE – Drilling Comments 5.4 EHS Incident Reporting x Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don’t wait until an emergency to have to call around and figure it out!!!! a. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753 b. Leonard Dickerson: O: (907) 777-8317 C: (907) 252-7855 2. Spills: x Notify Drlg Manager 1. Sean McLaughlin: C: 907-223-6784 x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to Sean.McLaughlin@hilcorp.com,andcdinger@hilcorp.com 5.6 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 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 6.0 Planned Wellbore Schematic Page 7 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 7.0 Drilling / Completion Summary PAXTON 13 is an S-shaped directional grassroots development well to be drilled from Paxton Pad. Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the Tyonek and Lower Beluga sands. The base plan is an S-shaped directional wellbore with a kickoff point at ~500’ MD. Maximum hole angle will be ~62 deg. and TD of the well will be 8900’ TMD/ 7526’ TVD, ending with 15 deg inclination. Drilling operations are expected to commence approximately March, 2025. The Hilcorp Rig # 169 will be used to drill the wellbore then run casing and cement. Surface casing will be run to 2591’ MD / 2000’ TVD and cemented to surface to ensure protection of any shallow freshwater resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed, a cement evaluation log (CBL/VDL or temperature log for example)maybe runto determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All waste & mud generated during drilling and completion operations will be hauled to the Beluga Waste Cells.The contingency plan will be tohaul cuttingsto theKenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. General sequence of operations: 1. MOB Hilcorp Rig # 169 to wellsite 2. N/U diverter and test. 3. Drill 9-7/8” hole to 2591’ MD. Run and cmt 7-5/8” surface casing. **GYRO required for first 1000’** 4. Test casing to 3500 psi. Perform 14.5# FIT 5. ND diverter, N/U & test 11” x 5M BOP to 3000 psi 6. Drill 6-3/4” hole section to 8900’ MD. 7. Run and cmt 3-1/2” production liner. 8. Displace well to inhibited completion fluid. 9. POOH and LDDP. 10. RIH and land 3-1/2” tieback string in liner top. 11. Test IA to 3000; Test tubing to 3000 psi 12. N/D BOP, N/U temp abandonment cap, RDMO. Reservoir Evaluation Plan: Surface hole: Triple Combo Production Hole: Triple Combo Page 8 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling of PAXTON 13. Ensure to provide AOGCC 48 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/10 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements” x Ensure AOGCC approved drilling permits are posted on the rig floor and in Co Man office. x Review all conditions of approval of the AOGCC 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. Page 9 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 9-7/8”x 21-1/4” x 2M Hydril MSP diverter Function Test Only 6-3/4” x 11” x 5M Annular BOP x 11” x 5M Double Ram o Blind ram in btm cavity x Mud cross x 11” x 5M Single Ram x 3-1/8” 5M Choke Line x 2-1/16” x 5M Kill line x 3-1/8” x 2-1/16” 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3000 (Annular 2500 psi) Subsequent Tests: 250/3000 (Annular 2500 psi) x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to testing BOPs. x Any other notifications required in APD. Additional requirements may be stipulated on APD and Sundry. Page 10 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 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 / Email:bryan.mclellan@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:victoria.loepp@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) 9.0 R/U and Preparatory Work 9.1 Set 16” conductor at +/-120’ below ground level. 9.2 Dig out and set impermeable cellar. 9.3 Install landing ring on conductor. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of rig. 9.6 R/U Hilcorp Rig # 169, spot service company shacks, spot & R/U company man & toolpusher offices. 9.7 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.8 Mix mud for 9-7/8” hole section. 9.9 Install 5-1/2” liners in mud pumps. x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes with 5-1/2” liners. Page 11 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 10.0 N/U 21-1/4” 2M Diverter 10.1 N/U 21-1/4” Hydril MSP 2M diverter System. x N/U 16-3/4” 3M x 21-1/4” 2M DSA (Hilcorp) on 16-3/4” 3M wellhead. x N/U 21-1/4” diverter “T”. x Knife gate, 16” diverter line. x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). 10.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. x NOTE:Ensure closing time on diverter annular is in line with API RP 64: 2..1.1.Annular element ID 20” or smaller: Less than 30 seconds 2..1.2.Annular element ID greater than 20”: Less than 45 seconds 10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the vent line tip. “Warning Zone” must include: x A prohibition on vehicle parking. x A prohibition on ignition sources or running equipment. x A prohibition on staged equipment or materials. x Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set wear bushing in wellhead. 10.5 Estimated Diverter line orientation on Paxton Pad: Page 12 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 11.0 Drill 9-7/8” Hole Section 11.1 P/U 9-7/8” directional drilling assy: x GYRO required to ensure standoff from offset wells x Triple Combo LWD tools required (DEN, POR, RES) x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Workstring will be 4.5” 16.6# S-135 CDS40 11.2 4-1/2” Workstring & HWDP will come from Hilcorp. 11.3 Begin drilling out from 16” conductor at reduced flow rates to avoid broaching the conductor. 11.4 Drill 9-7/8” hole section to 2591’ MD/ 2000’ TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate. x Utilize Inlet experience to drill through coal seams efficiently. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ or every couple days unless hole conditions dictate otherwise. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. x TD the hole section in a good shale x Take MWD surveys every stand drilled (60’ intervals). 11.5 9-7/8” hole mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. System Type:8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Page 13 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 120-2591’8.8 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0 System Formulation: Aquagel + FW spud mud Product Concentration FRESH WATER SODA ASH AQUAGEL CAUSTIC SODA BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT ALDACIDE G X-TEND II 0.905 bbl 0.5 ppb 12-15 ppb 0.1 ppb (9 pH) as needed as required for weight if required for <12 FL 0.1 ppb 0.02 ppb 11.6 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16” conductor shoe. 11.7 TOH with the drilling assy, handle BHA as appropriate. Page 14 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 12.0 Run 7-5/8” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Parker 7-5/8” casing running equipment. x Ensure 7-5/8” Casing x CDS 40 XO on rig floor and M/U to FOSV. x R/U fill-up line to fill casing while running. x Ensure all casing has been drifted on the location prior to running. x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ float shoe bucked on (thread locked). x (1) Joint with coupling thread locked. x (1) Joint with float collar bucked on pin end & thread locked. x Install (2) centralizers on shoe joint over a stop collar. 10’ from each end. x Install (1) centralizer, mid tube on thread locked joint and on FC joint. x Ensure proper operation of float equipment. 12.5 Continue running 7-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the event a top out job is needed. x Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 15 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.7 Slow in and out of slips. 12.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. Page 16 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 12.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 12.11 After circulating, lower string and land hanger in wellhead again. 13.0 Cement 7-5/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface. x Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. 13.2 Document efficiency of all possible displacement pumps prior to cement job 13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.4 Pump 5 bbls spacer. Test surface cmt lines. 13.5 Pump remaining spacer. 13.6 Drop bottom plug. Mix and pump cmt per below recipe. 13.7 Cement volume based on annular volume + 75% lead and tail open hole excess. Job will consist of lead & tail, TOC brought to surface. Estimated Total Cement Volume: Page 17 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat and continue with the cement job. 13.9 After pumping cement, drop top plug and displace cement with spud mud. 13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.11 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.12 Do not overdisplace by more than 1 shoe track volume. Total volume in shoe track is 3.6 bbls. x Be prepared for cement returns to surface. If cmt returns are not observed to surface, be prepared to run a temp log between 12 – 18 hours after CIP. 13.13 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 Verified cement calcs. -bjm Page 18 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 13.14 R/D cement equipment. Flush out wellhead with FW. 13.15 Back out and L/D landing joint. Flush out wellhead with FW. 13.16 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. 13.17 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 x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and sean.mclaughlin@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 14.0 BOP N/U and Test 14.1 ND Diverter line and diverter 14.2 N/U wellhead assy. Ensure to orient wellhead so that tree will line up with flowline later. Test Packoff to 3000 psi. 14.3 N/U 11” x 5M BOP as follows: x BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram /11” x 5M mud cross/11” x 5M single ram Page 19 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx x Double ram should be dressed with 2-7/8” x 5” variable bore rams in top cavity, blind ram in btm cavity. x Single ram should be dressed with 2-7/8” x 5” variable bore rams x N/U bell nipple, install flowline. x Install (2) manual valves & a check valve on kill side of mud cross. x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 14.4 Land out test plug (if not installed previously). x Test BOP to 250/3000 psi for 5/10 min. x Test VBR’s with 3-1/2” and 4-1/2” test joints x Test annular to 250/2500 psi for 10/10 min with a 3-1/2” test joint x Ensure to leave side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.6 Mix 9.0 ppg 6% KCL PHPA mud system. 14.7 Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section. 15.0 Drill 6-3/4” Hole Section 15.1 Pull test plug, run and set wear bushing 15.2 Ensure BHA components have been inspected previously. 15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 15.4 TIH and conduct shallow hole test of MWD to confirm all LWD functioning properly. 15.5 Ensure TF offset is measured accurately and entered correctly into the MWD software. 15.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. 15.7 Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 15.8 6-3/4” hole section mud program summary: Page 20 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx Weighting material to be used for the hole section will be barite, salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. Ensure fluids are topped off and adequate lost circulation material is on location in anticipation of losses in hole section. System Type:9.0 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 2591’- 8900’8.8 – 9.5 40-53 15-25 15-25 8.5-9.5 11.0 System Formulation:6% KCL EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for a 9.0 – 9.5 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 15.9 TIH w/ 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. x Triple Combo LWD tools required (DEN, POR, RES) 15.10 R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst.7-5/8” L-80 burst is 6880 psi / 2 = 3440 psi. 15.11 Drill out shoe track and 20’ of new formation. 15.12 CBU and condition mud for FIT. Page 21 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 15.13 Conduct FIT to 14.5 ppg EMW. x A 14.0 FIT with 8.7 ppg reservoir pressure and 9.5 ppg MW would equate to a 18 bbl KTV. 15.14 Drill 6-3/4” hole section to 8900’ MD / 7526’ TVD x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 400 - 500 gpm. Ensure shaker screens are set up to handle this flowrate. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ unless hole conditions dictate otherwise. x Trip back to the 7-5/8” shoe about ½ way through the hole section x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed necessary. 15.15 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8” shoe. 15.16 TOH with the drilling assy, standing back drill pipe. 15.17 LD BHA 15.18 RIH to TD, pump sweep, CBU and condition mud for casing run. 15.19 POOH LDDP and BHA 15.20 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 3-1/2” test joint. 16.0 Run 3-1/2” Production Liner 16.1. R/U Parker 3-1/2” casing running equipment. x Ensure 3-1/2” HYD 563 x CDS 40 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill casing while running. x Ensure all casing has been drifted prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.2. P/U shoe joint, visually verify no debris inside joint. 16.3. Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). Page 22 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx x (1) Joint with YJOC landing collar bucked on pin end & threadlocked. x Solid body centralizers will be pre-installed on shoe joint an FC joint. x Leave centralizers free floating so that they can slide up and down the joint. x Ensure proper operation of float shoe and float collar. x Utilize a collar clamp until weight is sufficient to keep slips set properly 16.4. Continue running 3-1/2” production liner x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install solid body centralizers on every joint to the 7-5/8” shoe. Leave the centralizers free floating. 16.5. Continue running 3-1/2” production liner Page 23 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx Page 24 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 16.6. Run in hole w/ 3-1/2” liner to the 7-5/8” casing shoe. 16.7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole dictates. 16.8. Obtain slack off weight, PU weight, rotating weight and torque of the casing. 16.9. Circulate 2X bottoms up at shoe, ease casing thru shoe. 16.10. Continue to RIH w/ casing no faster than 1 jt./minute. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.11. Set casing slowly in and out of slips. 16.12. PU 3-1/2” X 7-5/8” YJOC liner hanger/LTP assembly. RIH 1 stand and circulate one liner volume to clear string. Obtain slack off weight, PU weight, rotating weight and torque parameters of the liner. 16.13. Continue running in hole at slow speeds to avoid surging well. Target 20 ft/min and adjust slower as hole conditions dictate. 16.14. Swedge up and wash last stand to bottom. P/U 5’ off bottom. Note slack-off and pick-up weights. 16.15. Stage pump rates up slowly to circulating rate.Circ and condition mud with liner on bottom. Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the shakers are clean. Reduce the low end rheology of the drilling fluid by adding water and thinners. 16.16. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 25 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 17.0 Cement 3-1/2” Production Liner 17.1. Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. x Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. x Document efficiency of all possible displacement pumps prior to cement job. 17.2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky 17.3. Pump 5 bbls spacer. 17.4. Test surface cmt lines to 4500 psi. 17.5. Pump remaining spacer. 17.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed weight. Job is designed to pump 40% OH excess. Estimated Total Cement Volume: Page 26 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 17.7. Drop drillpipe dart and displace with drilling mud. If hole conditions allow – continue rotating and reciprocating liner throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 17.8. Displace cement at max rate of 5 bbl/min. Reduce pump rate to 2-3 bpm prior to DP dart/LWP entering into liner. 17.9. 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. 17.10. Bump the plug and pressure up to up as required by YJOC procedure to set the liner hanger (ensure pressure is above nominal setting pressure, but below pusher tool activation pressure). Hold pressure for 3-5 minutes. 17.11. Slack off total liner weight plus 30k to confirm hanger is set. 17.12. Do not overdisplace by more than 1 shoe track. Shoe track volume is 0.7 bbls. Verified cement calcs. -bjm Page 27 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 17.13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in compression. 17.14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool from the liner. 17.15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 17.16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight 17.17. Pressure up drill pipe to 500 psi and pick up to remove the bushing from the liner. 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). 17.18. 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. 17.19. 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. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 17.20. RD cementers and flush equipment. POOH, LDDP and running tool. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. 17.21. WOC minimum of 12 hours, test casing to 3000 psi and chart for 30 minutes. 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 x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement Page 28 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and sesan.mclaughlin@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 18.0 3-1/2” Liner Tieback Polish Run 18.1. PU liner tieback polish mill assy and RIH on drillpipe. 18.2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle. 18.3. POOH, and LDDP and polish mill. 18.4. If not completed, test 3-1/2” casing to 3000 psi and chart for 30 minutes Page 29 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 19.0 3-1/2” Tieback Run, ND/NU, RDMO 19.1 PU 3-1/2” tieback assembly and RIH with 3-1/2” 9.2# L-80 EUE. Ensure any jewelry is picked up per tally. x Run SSSV to ~150’ MD x No CIM, or GLM required. 19.2 No-go tieback seal assembly in liner PBR and mark pipe. PU pup joint(s) if necessary to space out tieback seals in PBR. 19.3 Circulate inhibited completion fluid. 19.4 PU hanger and terminate control line through hanger. Land string in hanger bowl. Note distance of seals from no-go. 19.5 Install packoff and test hanger void. 19.6 Test 3-1/2” liner and tieback to 3000 psi and chart for 30 minutes.24 hr notice required. 19.7 Test 7-5/8” x 3-1/2” annulus to 3000 psi and chart for 30 minutes.24 hr notice required. 19.8 Install BPV in wellhead 19.9 N/D BOPE 19.10 N/U dry-hole tree and test 19.11 RDMO Hilcorp Rig #169 Page 30 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 20.0 Diverter Schematic Page 31 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 21.0 BOP Schematic Page 32 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 22.0 Wellhead Schematic Page 33 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 23.0 Anticipated Drilling Hazards 9-7/8” Hole Section: Lost Circulation: Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Maintain YP between 25 – 45 to optimize hole cleaning and control ECD. Wellbore stability: Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity. Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP of ~50 - ~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200’ of drilling to reduce the likelihood of washing out the conductor shoe. To help ensure good cement to surface after running the casing, condition the mud to a YP of 25 – 30 prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be achieved. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. Page 34 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 6-3/4” Hole Section: Lost Circulation: Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Given the volume of losses experienced in 241-34T in 2020 and BRU 244-27 and BRU 222-34 in 2022, ensure all LCM inventory is fully stocked before drilling out surface casing. Hole Cleaning: Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP between 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. H2S: H2S is not present in this hole section. No abnormal temperatures are present in this hole section. Page 35 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 24.0 Hilcorp Rig 169 Layout Page 36 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 25.0 FIT/LOT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 37 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 26.0 Rig 169 Choke Manifold Schematic Page 38 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 27.0 Casing Design Information Page 39 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 28.0 6-3/4” Hole Section MASP Page 40 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 29.0 Spider Plot w/ 660’ Page 41 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx 30.0 Surface Plat As-Built Page 42 Rev 0.0 February 25, 2025 PAXTON 13 Drilling Procedure PTD xxx-xx !"##$ % &"' -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250True Vertical Depth (1500 usft/in)-1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 Vertical Section at 348.72° (1500 usft/in) Paxton 13 Tgt1 Paxton 13 wp08 TD 7-5/8" x 9-7/8" 3-1/2" x 6-3/4" 500 1 0 0 0 150020002500300035004 00 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 8 9 0 0 Paxton #13 wp08 Start Dir 2º/100' : 300' MD, 300'TVD Start Dir 4º/100' : 500' MD, 499.84'TVD End Dir : 2017.44' MD, 1730.53' TVD Start Dir 3º/100' : 3088.45' MD, 2233.34'TVD End Dir : 4655.11' MD, 3425.34' TVD Total Depth : 8900' MD, 7525.58' TVD BEL 10 BEL 53 BEL 82 BEL 134 T 5 T 16 T 65 T 83 T 90 T 142 Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: Paxton #13 148.70+N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2230504.24 206221.70 60° 5' 44.7591 N 151° 36' 34.5095 W SURVEY PROGRAM Date: 2025-02-19T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.00 1000.00 Paxton #13 wp08 (Paxton #13) 3_Gyro-GC_Drop+Sag 1000.00 2591.00 Paxton #13 wp08 (Paxton #13) 3_MWD+IFR1+MS+Sag 2591.00 8900.00 Paxton #13 wp08 (Paxton #13) 3_MWD+IFR1+MS+Sag REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Paxton #13, True North Vertical (TVD) Reference: RKB Permit @ 166.70usft (HEC 169) Measured Depth Reference:RKB Permit @ 166.70usft (HEC 169) Calculation Method:Minimum Curvature Project:Ninilchik Unit Site:Paxton Well:Paxton #13 Wellbore:Paxton #13 Design:Paxton #13 wp08 CASING DETAILS TVD TVDSS MD Size Name 2000.00 1833.30 2591.42 7-5/8 7-5/8" x 9-7/8" 7525.58 7358.88 8900.00 3-1/2 3-1/2" x 6-3/4" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 18.00 0.00 0.00 18.00 0.00 0.00 0.00 0.00 0.00 2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 2º/100' : 300' MD, 300'TVD 3 500.00 4.00 280.00 499.84 1.21 -6.87 2.00 280.00 2.53 Start Dir 4º/100' : 500' MD, 499.84'TVD 4 1767.44 52.00 349.50 1594.55 535.21 -150.94 4.00 72.53 554.39 5 2017.44 62.00 349.50 1730.53 741.10 -189.10 4.00 0.00 763.77 End Dir : 2017.44' MD, 1730.53' TVD 6 3088.45 62.00 349.50 2233.34 1670.91 -361.43 0.00 0.00 1709.33 Start Dir 3º/100' : 3088.45' MD, 2233.34'TVD 7 4655.11 15.00 349.50 3425.34 2603.19 -534.21 3.00 180.00 2657.40 End Dir : 4655.11' MD, 3425.34' TVD 8 8900.00 15.00 349.50 7525.58 3683.45 -734.43 0.00 0.00 3755.96 Total Depth : 8900' MD, 7525.58' TVD FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 1500.37 1333.67 1623.45 BEL 10 2157.79 1991.09 2927.52 BEL 53 2750.31 2583.61 3896.67 BEL 82 3538.78 3372.08 4772.56 BEL 134 3957.99 3791.29 5206.56 T 5 5132.60 4965.90 6422.60 T 16 6537.02 6370.32 7876.56 T 65 6839.82 6673.12 8190.05 T 83 7009.37 6842.67 8365.58 T 90 -225 0 225 450 675 900 1125 1350 1575 1800 2025 2250 2475 2700 2925 3150 3375 3600 3825 4050 South(-)/North(+) (450 usft/in)-1125 -900 -675 -450 -225 0 225 450 675 900 1125 1350 1575 1800 West(-)/East(+) (450 usft/in) Paxton 13 wp08 TD Paxton 13 Tgt1 7-5/8" x 9-7/8" 3-1/2" x 6-3/4" 250500750 1 0 0 0 1 2 5 0 1 5 0 0 1 7 5 0 2 0 0 0 2 2 5 0 2 5 0 0 2 7 5 0 3 0 0 0 3 2 5 0 3 5 00 3 7 50 4 0 00 4 2 5 0 4 5 0 0 4 7 5 0 5 0 0 0 5 2 50 5 5 00 5 7 50 6 0 00 6 2 5 0 6 5 00 6 7 5 0 7 0 00 7 2 50 7 5 0 07526 P a x t o n #1 3 w p 0 8 Start Dir 2º/100' : 300' MD, 300'TVD Start Dir 4º/100' : 500' MD, 499.84'TVD End Dir : 2017.44' MD, 1730.53' TVD Start Dir 3º/100' : 3088.45' MD, 2233.34'TVD End Dir : 4655.11' MD, 3425.34' TVD Total Depth : 8900' MD, 7525.58' TVD CASING DETAILS TVD TVDSS MD Size Name 2000.00 1833.30 2591.42 7-5/8 7-5/8" x 9-7/8" 7525.58 7358.88 8900.00 3-1/2 3-1/2" x 6-3/4" Project: Ninilchik Unit Site: Paxton Well: Paxton #13 Wellbore: Paxton #13 Plan: Paxton #13 wp08 WELL DETAILS: Paxton #13 148.70 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2230504.24 206221.70 60° 5' 44.7591 N 151° 36' 34.5095 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Paxton #13, True North Vertical (TVD) Reference:RKB Permit @ 166.70usft (HEC 169) Measured Depth Reference:RKB Permit @ 166.70usft (HEC 169) Calculation Method:Minimum Curvature ( $ ) # $ * + ,-. + / / 0$ 1& ! 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(,.&- ".&+%(,-%&/ ) 01-) 01-) 01- ".&" .(2&* -&-- .%&(( &..".(2&*/ ) 01-) 01-) 01- ".&% .%& -&-2 .%+&. &.%.%&/ ) - '. ? - '. ,@ ,? "+& ",& 01"2+ 265 )/6 ! 7 ",& ,%-"& 01"2+ 2689!"!8 ! 7 ,%-"& +,-& 01"2+ 2689!"!8 ! 7 : 3 45)& 3 ;& / 3 3 $ & / < $#= $) >& 7 ;; & 3 378:3:/3 4 3 :& 0.00 1.00 2.00 3.00 4.00 Separation Factor0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500 Measured Depth (1000 usft/in) Paxton #1Paxton #9 No-Go Zone - Stop Drilling Collision Avoidance Required Collision Risk Procedures Req. NOERRORS WELL DETAILS:Paxton #13 NAD 1927 (NADCON CONUS)Alaska Zone 04 148.70 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2230504.24 206221.70 60° 5' 44.7591 N 151° 36' 34.5095 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Paxton #13, True North Vertical (TVD) Reference: RKB Permit @ 166.70usft (HEC 169) Measured Depth Reference:RKB Permit @ 166.70usft (HEC 169) Calculation Method:Minimum Curvature SURVEY PROGRAM Date: 2025-02-19T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.00 1000.00 Paxton #13 wp08 (Paxton #13) 3_Gyro-GC_Drop+Sag 1000.00 2591.00 Paxton #13 wp08 (Paxton #13) 3_MWD+IFR1+MS+Sag 2591.00 8900.00 Paxton #13 wp08 (Paxton #13) 3_MWD+IFR1+MS+Sag 0.00 30.00 60.00 90.00 120.00 150.00 180.00 Centre to Centre Separation (60.00 usft/in)0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500 Measured Depth (1000 usft/in) Paxton #5 Paxton #12 Paxton #1 Paxton #8 Paxton #9 Paxton #11 Paxton #10 Paxton #7 Paxton #6 Paxton #6 PB1 GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference 18.00 To 8900.00 Project: Ninilchik Unit Site: Paxton Well: Paxton #13 Wellbore: Paxton #13 Plan: Paxton #13 wp08 Ladder / S.F. Plots CASING DETAILS TVD MD Name Size 2000.00 2591.42 7-5/8" x 9-7/8" 7-5/8 7525.58 8900.00 3-1/2" x 6-3/4" 3-1/2 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. 225-021 BELUGA-TYONEK GAS NINU Paxton 13 NINILCHIK WELL PERMIT CHECKLIST Company Hilcorp Alaska, LLC Well Name:NINILCHIK UNIT PAXTON 13 Initial Class/Type DEV / PEND GeoArea 820 Unit 51432 On/Off Shore On Program DEVField & Pool Well bore seg Annular DisposalPTD#:2250210 NINILCHIK, BELUGA-TYONEK GAS - 562503 NA1 Permit fee attached Yes Private Fee and ADL3843722 Lease number appropriate Yes3 Unique well name and number Yes4 Well located in a defined pool Yes5 Well located proper distance from drilling unit boundary NA6 Well located proper distance from other wells Yes7 Sufficient acreage available in drilling unit Yes8 If deviated, is wellbore plat included Yes9 Operator only affected party Yes10 Operator has appropriate bond in force Yes11 Permit can be issued without conservation order Yes12 Permit can be issued without administrative approval Yes13 Can permit be approved before 15-day wait NA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For NA15 All wells within 1/4 mile area of review identified (For service well only) NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only) NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D) Yes18 Conductor string provided Yes19 Surface casing protects all known USDWs Yes20 CMT vol adequate to circulate on conductor & surf csg Yes21 CMT vol adequate to tie-in long string to surf csg Yes22 CMT will cover all known productive horizons Yes23 Casing designs adequate for C, T, B & permafrost Yes24 Adequate tankage or reserve pit NA25 If a re-drill, has a 10-403 for abandonment been approved Yes26 Adequate wellbore separation proposed Yes27 If diverter required, does it meet regulations Yes28 Drilling fluid program schematic & equip list adequate Yes29 BOPEs, do they meet regulation Yes MPSP =2634 psi, BOP rated to 5k psi (BOP test to 3000 psi)30 BOPE press rating appropriate; test to (put psig in comments) Yes31 Choke manifold complies w/API RP-53 (May 84) Yes32 Work will occur without operation shutdown No33 Is presence of H2S gas probable NA34 Mechanical condition of wells within AOR verified (For service well only) Yes H2S is not anticipated based on nearby wells.35 Permit can be issued w/o hydrogen sulfide measures Yes Anticipating normal pressure gradients (min 8.08 ppg EMW)36 Data presented on potential overpressure zones NA37 Seismic analysis of shallow gas zones NA38 Seabed condition survey (if off-shore) NA39 Contact name/phone for weekly progress reports [exploratory only] Appr ADD Date 3/11/2025 Appr BJM Date 3/11/2025 Appr ADD Date 3/11/2025 Administration Engineering Geology Geologic Commissioner:Date:Engineering Commissioner:Date Public Commissioner Date *&:JLC 3/13/2025