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Home My WebLink About224-097David 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: 11/05/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: NCIU B-01B PTD: 224-097 API: 50-883-20093-02-00 FINAL LWD FORMATION EVALUATION LOGS (09/08/2024 to 09/21/2024) x ROP, DGR, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Survey SFTP Transfer – Data Main Folders: Please include current contact information if different from above. 224-097 T39749 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.11.05 13:00:22 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 10/30/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20241030 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BRU 221-26 50283202010000 224098 10/20/2024 AK E-LINE Perf BRU 233-23T 50283202000000 224088 10/14/2024 AK E-LINE Perf BRU 241-23 50283201910000 223061 10/12/2024 AK E-LINE Perf GP-ST-18742-33 50733203060000 177032 10/9/2024 AK E-LINE LeakDetect/Packer IRU 11-06 50283201300000 208184 10/4/2024 AK E-LINE Plug/Perf MPU B-28 50029235660000 216027 10/4/2024 READ CaliperSurvey MPU F-13 50029225490000 195027 10/15/2024 READ CaliperSurvey MPU L-36 50029227940000 197148 10/17/2024 READ CaliperSurvey MRU G-01RD 50733200370100 191139 10/10/2024 AK E-LINE Hoist NCIU A-21 50883201990000 224086 10/8/2024 AK E-LINE CBL NCIU B-01B 50883200930200 224097 10/1/2024 AK E-LINE CBL NCIU B-01B 50883200930200 224097 10/11/2024 AK E-LINE Perf PBU 06-18B 50029207670200 223071 10/2/2024 HALLIBURTON RBT PBU 14-32B 50029209990200 224073 10/13/2024 HALLIBURTON RBT PBU C-18B 50029207850200 209071 10/2/2024 HALLIBURTON RBT PBU C-18B 50029207850200 209071 10/2/2024 HALLIBURTON WSTT PBU NK-26A 50029224400100 218009 10/14/2024 HALLIBURTON PPROF PCU 02A 50283200220100 224110 9/30/2024 AK E-LINE CBL PCU 02A 50283200220100 224110 10/4/2024 AK E-LINE Perf SDI 3-25B 50029221250200 203021 10/17/2024 AK E-LINE Patch Please include current contact information if different from above. T39726 T39727 T39728 T39732 T39733 T39734 T39735 T39736 T39737 T39738 T39739 T39739 T39740 T39741 T39742 T39742 T39743 T39744 T39744 T39745 NCIU B-01B 50883200930200 224097 10/1/2024 AK E-LINE CBL NCIU B-01B 50883200930200 224097 10/11/2024 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.11.01 13:27:33 -08'00' 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 2.Operator Name: 4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 9,010 N/A Casing Collapse Structural Conductor 1,500psi Surface 2,670psi Intermediate Production 8,850psi Liner 10,029psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Ryan Rupert Contact Email:Ryan.Rupert@hilcorp.com Contact Phone:(907) 777-8503 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng North Cook Inlet Unit Tertiary System Gas Same 6,764 8,924 6,679 2,736psi N/A Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY 15,638psi Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Operations Manager STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 224-097 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20093-02-00 Hilcorp Alaska, LLC N Cook Inlet Unit B-01B Length Size Proposed Pools: 407' 407' L-80 TVD Burst ѷ2,697 10,900psi MD 3,060psi 5,380psi 2,510' 2,700' 2,579' 2,790' 2,700'9-5/8" 407' 30" 20" 13-3/8" 2,579' 2,790' Perforation Depth MD (ft): ѷ6,200 -ѷ8,924 2,790' 4-1/2" ѷ4,505 -ѷ6,678 CO 68A Other: CT & N2 Operations 10/8/2024 9,010'6,346' 4-1/2" 6,764' LTP & Baker TE S-5 SSSV 2,664 (MD) 2,587 (TVD) &ѷ426 (MD ѷ426 (TVD) 2,790' No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 3:58 pm, Sep 24, 2024 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2024.09.24 15:14:03 - 08'00' Dan Marlowe (1267) BJM 10/3/24 SFD 9/25/2024 CT BOP test to 3000 psi. 10-407 DSR-9/27/24 X Yes for CTCO only 10/3/24 Bryan McLellan JLC 10/3/2024 Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.10.08 15:18:56 -08'00'10/08/24 RBDMS JSB 100924 Initial Completion Well: NCIU (Tyonek) B-01B Well Name:NCIU (Tyonek) B-01B API Number:50-883-20093-02-00 Current Status:New Sidetrack Gas Well Leg:Leg #1 (NW corner) Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:224-097 First Call Engineer:Ryan Rupert (907) 301-1736 (c) Second Call Engineer:Dan Marlowe (907) 398-9904 (c) Maximum Expected BHP:3,403 psi @ 6,678’ TVD 9.8ppg at Deepest planned perf Max. Potential Surface Pressure: 2736 psi Using 0.1 psi/ft Brief Well Summary Jackup Rig #151 finished drilling and is currently completing Tyonek well B-01B. The drilling rig is running tie- back tubing as of this writing and will be leaving the platform for the season soon. B-01B is a closed system currently and is not open to the formation. This procedure addresses the initial post-drill completion wellwork to get the well online. All planned perforations below are within the Tertiary System Gas Pool as defined by CO 68A. The goal of this project is to complete the well after the drilling rig leaves. Pertinent wellbore information: - TRSSSV to be installed -Live GLV’s will be installed when the tubing was run - 9/2224 o 4-1/2” production liner cemented with full returns, and cement circulated off ToL o 10min assurance PT to 3000psi PASSED. Confirmed the integrity of 9-5/8” casing, 4-1/2” LTP, 4- 1/2” Liner, and 4-1/2” liner floats/cement Coiled Tubing Procedure 1. MIRU Fox Energy offshore Coiled Tubing and pressure control equipment 2. PT lubricator to 250psi low / 3000psi high a. Multiple wells planned for CT intervention on this leg (#1) b. Hilcorp requests a weekly CT BOP test requirement while on this leg, instead of each well 3. MU cleanout BHA 4. RIH to PBTD and swap well over to water if needed 5. Obtain CBL (may be executed on EL. TBD) Submit CBL to AOOGCC 6. RIH and blow well dry with nitrogen a. Reverse circulate water out of wellbore (no perforations, passing MIT’s) b. Want to evacuate all IA fluid through live GLV’s as well 7. RDMO CT BOP test is required on this well. -bjm Initial Completion Well: NCIU (Tyonek) B-01B E-Line Perf procedure 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250psi low / 3000psi high 3. Ensure CBL approval from AOGCC before perforating 4. RIH and perforate Beluga gas sands from ±6,200’ - ±8,924’ MD (±4,505’ - ±6,678’ TVD) per RE/Geo a. All proposed perfs within Tertiary System Gas Pool b. Bottom pool is below PBTD c. Top pool is at top Sterling sands at 3477’ MD (3245’ TVD) d. Pressures: i. 9-5/8” window at 2700’ TVD: FIT at 14.1PPG ii. Worst case pressure could create a 13.6ppg at the top sundried perf (4505’ TVD) 5. RDMO EL CONTINGENCY plug/patch: (if any zone makes unwanted solids or water) 1. RU nitrogen to tubing and PT lines to 3000psi (or higher if needed) 2. Pressure up on tubing and displace water back into formation 3. MIRU E-line and pressure control equipment 4. PT lubricator to 250psi low / 3000psi high 5. Set 4-1/2” isolation plug or patch per OE 6. RDMO Nitrogen and EL CONTINGENCY CT Cleanout: (if any zone brings in excessive fill and needs to be cleaned out) 1. MIRU Coiled Tubing and pressure control equipment 2. PT lubricator to 250psi low / 3000psi high 3. MU FCO BHA 4. RIH and cleanout to PBTD or as deep as practical a. Working fluid will be water (8.33ppg or greater) b. Take returns to surface up the CT x tubing annulus c. Add foam and nitrogen as necessary to carry solids to surface d. Can use GL to assist with hole cleaning 5. Once cleanout is completed, blow well down with nitrogen 6. RDMO CT Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. CT BOP Drawing (Fox energy) 4. Nitrogen procedure Worst case pressure could create a 13.6ppg at the top sundried perf (4505’ TVD) CBL received by AOGCC. The below perf intervals are approved. -bjm Updated By: JLL 9/23/24 SCHEMATIC North Cook Inlet Unit Tyonek Platform Well: NCI B-01B PTD: 224-097 API: 50-883-20093-02-00 Completed: Future PBTD: 8,924’ TD: 9,010’ 30” RKB: MSL = 126.6’ 3 4/5/6 2 9-5/8” 4-1/2” 9-5/8” Window @ 2,790’ MD 20” 13-3/8” 2-3/8" 1 Casing &Tubing Detail SIZE WT GRADE CONN MIN ID TOP BTM (MD) 30” 547 Welded 29.000 Surf 407’ 20” 133 K-55 Dni- Quip 19.730 Surf 2,579’ 13-3/8” 72 L-80 BTC 12.415 Surf 2,790’TOW 9-5/8” 53.5 P-110 BTC 8.535 Surf 2,790 TOW 4-1/2” 12.6 L-80 GBCD 3.958 2,664’ 9,010’ 4-1/2” 12.6 L-80 TC II 3.958 Surf ±2,697’ Jewelry Detail No.Depth MD Depth TVD Item 1 ±426’ ±426 Baker TE S-5 SSSV (Draft Tally) 2 2,664’ 2,587' Liner hanger / LTP Assembly (Tag Depth) 3 ±2,673’ ±2,595' X Nipple (Draft Tally) 4 ±2,697’ ±2,617' Seal Assembly (Draft Tally) GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 ±2,033’ ±2,007' 3.833"GLM, 4.5" X 1.5'' FO-2 " (Draft Tally)16 Dome 750 2 ±2,619’ ±2,547' 3.833"GLM, 4.5" X 1.5'' FO-2 " (Draft Tally)24 Orifice OTHER DETAILS 6,987 RA Tag 7,998 RA Tag OPEN HOLE / CEMENT DETAIL 20"24” Hole: Pumped 1690sxs of 12ppg lead followed by 700sxs of 15.8ppg tail cement.Saw cement to surface. 13-3/8"18-1/2” hole: 115bbls of 12ppg lead cement returned to surface.9/4/97 cement log acquired 9-5/8” Scab Liner 9-5/8” scab liner stung into 9-5/8” liner at 3,591’ MD in parentbore. Cemented on 4/12/23 down 2-3/8” A-string taking returns up 13-3/8” x 9-5/8” OA. Cement circ’d up into OA from 3500’ to 2,230’ MD.ToC in 9-5/8” x 13-3/8” OA at 2230’ MD (4/24/23 CBL) 4-1/2"8-1/2" hole: Pumped 413 bbls (977 sx) of 12 ppg lead cement followed by 37 bbls (180s sx) of 15.3 ppg cement, circulated 125 bbls of cement off liner top. Cuttings Disposal Tubing (2 strings) Dual 2-3/8” clamped to outside 13-3/8” A String:Cement to Surface B String:Cement to 255’ (~80’ below mudline). Will need cement top off for final P&A 4.7 N-80 CS Hydril 1.995” Surf 2,790' Updated By: JLL 9/23/24 PROPOSED North Cook Inlet Unit Tyonek Platform Well: NCI B-01B PTD: 224-097 API: 50-883-20093-02-00 Completed: Future PBTD: 8,924’ TD: 9,010’ 30” RKB: MSL = 126.6’ 3 4/5/6 2 9-5/8” 4-1/2” 9-5/8” Window @ 2,790’ MD Beluga Gas Sands 20” 13-3/8” 2-3/8" 1 Casing &Tubing Detail SIZE WT GRADE CONN MIN ID TOP BTM (MD) 30” 547 Welded 29.000 Surf 407’ 20” 133 K-55 Dni- Quip 19.730 Surf 2,579’ 13-3/8” 72 L-80 BTC 12.415 Surf 2,790’TOW 9-5/8” 53.5 P-110 BTC 8.535 Surf 2,790 TOW 4-1/2” 12.6 L-80 GBCD 3.958 2,664’ 9,010’ 4-1/2” 12.6 L-80 TC II 3.958 Surf ±2,697’ Jewelry Detail No.Depth MD Depth TVD Item 1 ±426’ ±426 Baker TE S-5 SSSV (Draft Tally) 2 2,664’ 2,587' Liner hanger / LTP Assembly (Tag Depth) 3 ±2,673’ ±2,595' X Nipple (Draft Tally) 4 ±2,697’ ±2,617' Seal Assembly (Draft Tally) GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 ±2,033’ ±2,007' 3.833"GLM, 4.5" X 1.5'' FO-2 " (Draft Tally)16 Dome 750 2 ±2,619’ ±2,547' 3.833"GLM, 4.5" X 1.5'' FO-2 " (Draft Tally)24 Orifice OTHER DETAILS 6,987 RA Tag 7,998 RA Tag OPEN HOLE / CEMENT DETAIL 20"24” Hole: Pumped 1690sxs of 12ppg lead followed by 700sxs of 15.8ppg tail cement.Saw cement to surface. 13-3/8"18-1/2” hole: 115bbls of 12ppg lead cement returned to surface.9/4/97 cement log acquired 9-5/8” Scab Liner 9-5/8” scab liner stung into 9-5/8” liner at 3,591’ MD in parentbore. Cemented on 4/12/23 down 2-3/8” A-string taking returns up 13-3/8” x 9-5/8” OA. Cement circ’d up into OA from 3500’ to 2,230’ MD.ToC in 9-5/8” x 13-3/8” OA at 2230’ MD (4/24/23 CBL) 4-1/2"8-1/2" hole: Pumped 413 bbls (977 sx) of 12 ppg lead cement followed by 37 bbls (180s sx) of 15.3 ppg cement, circulated 125 bbls of cement off liner top. Cuttings Disposal Tubing (2 strings) Dual 2-3/8” clamped to outside 13-3/8” A String:Cement to Surface B String:Cement to 255’ (~80’ below mudline). Will need cement top off for final P&A 4.7 N-80 CS Hydril 1.995” Surf 2,790' PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status BEL ±6,200’ ±8,924’ ±4,505’ ±6,678’ ±2,724' Future Proposed KLU A-1 Well Head Rig Up 1 1 1 1 4 1/16" 15K Lubricator - 10 ft 100" Gooseneck HR680 Injector Head 4 1/16" 10K Flow Cross, 2" 1502 10k Flanged Valves 4 1/16" 15K Lubricator - 10 ft API Flange Adapter 10K to 5K for riser/wellhead Hydraulic Stripper 4 1/6" 15K API Bowen CB56 15K 4 1/16" 10K Combi BOPs Blind/Shear Ram Pipe/Slip Ram 4 1/16" 10K bottom flange 4 1/16" 5K flanged Riser - 10 ft if necessary STANDARD WELL PROCEDURE NITROGEN OPERATIONS 09/23/2016 FINAL v-offshore Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Facility Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Nitrogen Tank. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure supplier has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Tank. 1 McLellan, Bryan J (OGC) From:McLellan, Bryan J (OGC) Sent:Thursday, October 3, 2024 9:36 AM To:Ryan Rupert Cc:Juanita Lovett; Dan Marlowe Subject:RE: NCIU B-01B cement log Hilcorp has conditional verbal approval to begin the CT work on this well as described in the sundry submitted on 9/24/24. Conditions of approval: CT BOP test to 3000 psi required. Provide notification for AOGCC opportunity to witness. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Thursday, October 3, 2024 9:05 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Ryan Rupert <Ryan.Rupert@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com> Subject: NCIU B-01B cement log Bryan- Please see attached for NCIU B-01b cement log associated with the pending completion sundry. With your approval, if like to begin the CT work on this well tomorrow, Friday 10/4. Let me know if that is permissable. Ryan Rupert 907-301-1736 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Monty Myers Cc:Regg, James B (OGC); Sean McLaughlin Subject:RE: PTD 224-097 - NCIU B-01B FIT Date:Friday, September 13, 2024 2:33:00 PM Monty, Hilcorp has approval to continue drilling production hole based on the FIT data providing sufficient kick tolerance. Regards Bryan Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Monty Myers <mmyers@hilcorp.com> Sent: Friday, September 13, 2024 7:23 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: PTD 224-097 - NCIU B-01B FIT Good morning gents. Attached are the FIT result for NCIU B-01B. We achieved a 14.15 ppge FIT test at the window (2700’ TVD) with a mud weight of 8.8 ppg. We pumped 1.6 bbls of fluid and applied 751 psi. We needed to achieve a 13.8 ppge FIT as per the PTD. Please let me know if you have any questions. We will be ready to begin drilling production hole this afternoon. Monty M Myers Drilling Manager 907.538.1168 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Monty M. Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: North Cook Inlet, Tertiary System Gas Pool, NCIU B-01B Hilcorp Alaska, LLC Permit to Drill Number: 224-097 Surface Location: 1257' FNL, 979' FWL, Sec 6, T11N, R9W, SM, AK Bottomhole Location: 530' FNL, 2128' FWL, Sec 7, T11N, R9W, SM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski Commissioner DATED this 15th day of August 2024. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.15 11:36:28 -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: 8,976' TVD: 6,732' 4a. Location of Well (Governmental Section):7. Property Designation: Surface: Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 126.6 15. Distance to Nearest Well Open Surface: x-331998 y- 2586723 Zone-4 N/A to Same Pool: 1471' to NCIU A-15 16. Deviated wells:Kickoff depth: 2,790 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 64 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 8-1/2" 4-1/2" 12.6# L-80 GBCD 6,386' 2,590' 2,501' 8,976' 6,732' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): N/A TVD 407' 2511' 3515' 8841' 12896' Hydraulic Fracture planned?Yes No 20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng NCIU B-01B North Cook Inlet Unit Tertiary System Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. N/A Plugged 115 bbls 10377'9-5/8" 13-3/8" 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 2760 2439' FNL, 1159' FWL, Sec 6, T11N, R9W, SM, AK 530' FNL, 2128' FWL, Sec 7, T11N, R9W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 1257' FNL, 979' FWL, Sec 6, T11N, R9W, SM, AK ADL 17589 18. Casing Program:Top - Setting Depth - BottomSpecifications 3433 GL / BF Elevation above MSL (ft): Plugs (measured): (including stage data) L - 2315 ft3 / T - 207 ft3 3450'3266' Effect. Depth MD (ft):Effect. Depth TVD (ft): 16720'12943' LengthCasing 3450' Size N/A Plugged Conductor/Structural 30"407' Authorized Title: Authorized Signature: 5" Authorized Name: Production Liner 3760' 10377' 6576 Intermediate 407' 2579'20"2390 sx Drilling Manager Monty Myers 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft):Perforation Depth MD (ft): 2579' 3760' 966 bbls 8/15/2024 5575' to nearest unit boundary Sean Mclaughlin sean.mclaughlin@hilcorp.com 907-223-6784 16650' 5002 Cement Volume MD s N ype of W L l R L 1b S Class: os N s No s N o D s s sD 84 o well is p G S S 20 S S S s No s No S G y E S s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) Drilling Manager 07/15/24 Monty M Myers By Grace Christianson at 8:29 am, Jul 15, 2024 224-097 DSR-7/15/24 50-883-20093-01-00 Submit FIT/LOT data and obtain approval before drilling production hole Final Wellbore Diagram in 10-407 must show the annular injection strings, with top of cement at 255' in the B-string for awareness during final P&A. SFD 7/16/2024 BOP test to 3000 psi. Annular test to 2500 psi. See attached conditions of waiver for drilling dynamically overbalanced w/ MPD BJM 8/14/24*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.15 11:36:14 -08'00' 08/15/24 08/15/24 MDG 8/15/2024 02 RBDMS JSB 081924 NCIU B-01B (PTD 224-097) Conditions of approval and Waiver to 20 AAC 25.033(b)(1)(A) The following are conditions of ÍŕŕŘĺŽÍīϙťĺϙŪŜôϙÍϙîŘĖīīĖĲČϙƲŪĖîϙťēÍťϙîĺôŜϙĲĺťϙēÍŽôϙŜŪƯĖèĖôĲťϙîôĲŜĖťƅϙ to overbalance the pressure of the uncased portion of the formations penetrated in the 8-3/4” hole section of this well, which requires a waiver to 20 AAC 25.033(b)(1)(A). This waiver is conditional on the following: 1. ϙaÍĲÍČôîϙŘôŜŜŪŘôϙ"ŘĖīīĖĲČϙϼa"ϽϙŜƅŜťôıϙĖŜϙťĺϙæôϙŪŜôîϙťĺϙÍŕŕīƅϙťēôϙŜŪŘċÍèôϙŕŘôŜŜŪŘôϙ required to keep the open hole formations in an overbalanced state whenever the drilling ƲŪĖîϙîôĲŜĖťƅϙĖŜϙĖĲŜŪƯĖèĖôĲťϙťĺϙıÍĖĲťÍĖĲϙĺŽôŘæÍīÍĲèôϙťĺϙťēôϙĺŕôĲϙēĺīôϙċĺŘıÍťĖĺĲŜϟ 2. ēôϙ>Iϯ[iϙŕŘôŜŜŪŘôϙĖŜϙŜŪƯĖèĖôĲťϙťĺϙıÍĖĲťÍĖĲϙѳ20 bbls kick tolerance with a 0.2 ppg kick ĖĲťôĲŜĖťƅϙÍæĺŽôϙťēôϙēĖČēôŜťϙÍĲťĖèĖŕÍťôîϙŘôŜôŘŽĺĖŘϙŕŘôŜŜŪŘôϟϙϙēĖŜϙŕŘĺŽĖîôŜϙŜĺıôϙŘĺĺıϙċĺŘϙ ôŘŘĺŘϙĖĲϙa"ϙèēĺħôϙŜƅŜťôıϙċÍĖīŪŘôϙĺŘϙēŪıÍĲϙôŘŘĺŘŜϙÍŜŜĺèĖÍťôîϙſĖťēϙħĖèħϙŕŘôŽôĲťĖĺĲϙÍĲîϙſôīīϙ control response. This is a reduced requirement from the previous 3 MPD wells drilled with ťēĖŜϙŘĖČϙĖĲϙťēĖŜϙèÍıŕÍĖČĲϠϙŘôèĺČĲĖƏĖĲČϙťēôϙĖĲèŘôÍŜôîϙċÍıĖīĖÍŘĖťƅϙÍĲîϙŕŘÍèťĖèôϙſĖťēϙa"ϙ ŜƅŜťôıŜϙÍĲîϙťēôϙīĺſϙīĖħôīĖēĺĺîϙĺċϙôĲèĺŪĲťôŘĖĲČϙŕŘôŜŜŪŘôŜϙôƄèôôding highest prognosed pressureϟϙϙXĖèħϙťĺīôŘÍĲèôϙťĺϙæôϙŽôŘĖƱôîϙŪŜĖĲČϙÍèťŪÍīϙ>Iϯ[iϙîÍťÍϙîôŘĖŽôîϙċŘĺıϙťēôϙťôŜťϙ ŕôŘċĺŘıôîϙÍċťôŘϙîŘĖīīĖĲČϙĺŪťϙťēôϙŕŘôŽĖĺŪŜīƅϙŜôťϙèÍŜĖĲČϙŜēĺôϙĺċϙťēĖŜϙſôīīϟϙϙϙi@ϙŽôŘĖƱèÍťĖĺĲϙ ĺċϙŜŪƯĖèĖôĲťϙ>Iϯ[iϙŘôŜŪīťŜϙŘôŗŪĖŘôîϙæôċĺŘôϙîŘĖīīĖĲČϙŕŘĺîŪèťĖĺĲϙēĺīô. 3. īīϙĖĲƲŪƄôŜϙťĺϙæôϙcirculated out per conventional well kill protocols, with closed BOP and ŜīĺſϙŕŪıŕϙŘÍťôϟϙϙa"ϙŜƅŜťôıϙſĖīīϙĲĺťϙæôϙŪŜôîϙċĺŘϙèĖŘèŪīÍťĖĲČϙĺŪťϙĖĲƲŪƄôŜϠϙſēôťēôŘϙťēôϙĖĲƲŪƄϙ occurred while drilling, while making a connection or while tripping, or while conducting ÍĲƅϙĺťēôŘϙĺŕôŘÍťĖĺĲ. 4. ôťŪŘĲϙƲĺſϙŜťŘôÍıϙťĺϙæôϙŘĺŪťôîϙťēŘĺŪČēϙťēôϙƲĺſīĖĲôϙÍĲîϙƲĺſϙŕÍîîīôϙîĺſĲŜťŘôÍıϙĺċϙťēôϙ a"ϙèēĺħôϙÍĲîϙĺŘôĺīĖŜϙƲĺſϙıôťôŘϙŜĺϙťēôϙîŘĖīīôŘϙèÍĲϙĺæŜôŘŽôϙèēÍĲČôŜϙťĺϙŘôťŪŘĲϙƲĺſϙŘÍťôϙ ĖĲîôŕôĲîôĲťϙĺċϙťēôϙa"ϙŜƅŜťôıϟ 5. Kick while drilling or while tripping drills required ťſĖèôϙſôôħīƅϙwith each tour while using ťēôϙa"ϙŜƅŜťôıϙæôČĖĲĲĖĲČϙťēôϙƱŘŜťϙîÍƅϙa"ϙĖŜϙŪŜôîϟϙ ēĖŜϙċŘôŗŪôĲèƅϙĖŜϙŘôîŪèôîϙċŘĺıϙťēôϙ ŘôŗŪĖŘôîϙċŘôŗŪôĲèƅϙĺĲϙŕŘĖĺŘϙſôīīŜϙæôèÍŪŜôϙťēĖŜϙĖŜϙťēôϙ͓th MPD well on this rig in this drilling èÍıŕÍĖČĲϙÍĲîϙťēôϙèŘôſŜϙÍŘôϙæôèĺıĖĲČϙıĺŘôϙċÍıĖīĖÍŘϙſĖťēϙťēôϙa"ϙŜƅŜťôıϟ 6. TēôϙċĺīīĺſĖĲČϙÍîîĖťĖĺĲÍīϙîŘĖīīŜϙŜēÍīīϙæôϙèĺĲîŪèťôîϙſĖťēϙôÍèēϙťĺŪŘϙĖĲϙťēôϙƱŘŜťϙîÍƅϙťēôϙa"ϙ ŜƅŜťôıϙĖŜϙŪŜôîϟϙ a. Loss of MPD choke pressure while making connection. This drill will assume that the loss of choke pressure results in a kick due to being underbalanced. b. >ÍĖīŪŘôϙĺċϙťēôϙîŘĖīīŜťŘĖĲČϙƲĺÍťϙŘôŜŪīťĖĲČϙĖĲϙÍϙƲĺſϙŪŕϙťēôϙîŘĖīīϙŜťŘĖĲČϙîŪôϙťĺϙæôĖĲČϙ underbalanced to the reservoir and because of U-ťŪæôϙôƯôèťϙſĖťēϙMPD pressure on the choke. ĲϙÍîîĖťĖĺĲÍīϙèĺĲŜĖîôŘÍťĖĺĲϙċĺŘϙťēĖŜϙÍŕŕŘĺŽÍīϙĖŜϙťēôϙŘôīÍťĖŽôīƅϙīĺſϙŪĲèôŘťÍĖĲťƅϙċĺŘϙťēôϙıÍƄĖıŪıϙ ŘôŜôŘŽĺĖŘϙŕŘôŜŜŪŘôŜϙĖĲϙťēĖŜϙēĺīôϙŜôèťĖĺĲϙîŪôϙťĺϙťēôϙıŪīťĖŕīôϙŕôĲôťŘÍťĖĺĲŜϙæôīĺſϙťēôϙƅĺĲôħϙīÍťċĺŘıϟϙϙ Reservoir pressures are well understood and thus the risk ĺċϙÍϙħĖèħϙĖĲťôĲŜĖťƅϙĺċϙѳ͏ϟ͔ϙŕŕČϙÍæĺŽôϙıÍƄϙ anticipated reservoir pressure is low. B-01B Drilling Program Tyonek Sean McLaughlin PTD June 28, 2024 Contents 1. Well Summary.....................................................................................................................................2 2. Management of Change Information................................................................................................3 3. Tubular Program................................................................................................................................4 4. Drill Pipe Information........................................................................................................................4 5. Internal Reporting Requirements.....................................................................................................5 6. Current Wellbore Schematic.............................................................................................................6 7. Planned Wellbore Schematic.............................................................................................................7 8. Drilling Summary...............................................................................................................................8 9. Mandatory Regulatory Compliance / Notifications.........................................................................8 10. R/U and Preparatory Work.............................................................................................................11 11. BOP N/U and Test.............................................................................................................................12 12. Set Whipstock / Mill Window..........................................................................................................13 13. Drill 8-1/2” Hole Section...................................................................................................................14 14. Run 4-1/2” Production Liner ...........................................................................................................15 15. Cement 4-1/2” Production Liner .....................................................................................................17 16. Wellbore Clean Up & Displacement...............................................................................................20 17. Run Completion Assembly...............................................................................................................20 18. BOP Schematic..................................................................................................................................22 19. Wellhead Schematic..........................................................................................................................23 20. Anticipated Drilling Hazards...........................................................................................................24 21. FIT Procedure...................................................................................................................................26 22. Choke Manifold Schematic..............................................................................................................27 23. Casing Design Information ..............................................................................................................29 24. 8-1/2” Hole Section MASP ...............................................................................................................30 25. Plot (NAD 27) (Governmental Sections).........................................................................................31 26. Slot Diagram......................................................................................................................................32 Page 2 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx 1. Well Summary New Well NCI B-01B Drilling Rig Rig 151 Leg & Slot Leg 1 / Slot 4 Directional plan wp02 Old Well Designation B-01A - Sidetrack Planned Completion Type 4-1/2”12.6# Liner, 4-1/2” Tubing GL Comp Target Reservoir(s)Beluga A-U Kick off point 2790’ MD / 2700’ Planned Well TD, MD / TVD 8976’MD / 6732’TVD PBTD, MD 8876’MD MASP 2760 psi AFE Number AFE Days AFE Drilling Amount Work String(s)5” 19.5# S135 NC50 RKB –AMSL 126.6’ MSL to ML 74.10’ NAD 83 Page 3 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx 2. Management of Change Information Date: June 26, 2024 Subject: Changes to Approved Permit to Drill File #: NCI B-01B Drilling Program Significant modifications to Drilling Program for PTD will be documented and approved below. Changes to an approved PTD will be communicated and approved by the AOGCC prior to continuing forward with work. Sec Page Date Procedure Change Approval: Drilling Manager Date Prepared: Engineer Date Page 4 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx 3. Tubular Program Hole Section OD (in)ID (in)Drift (in) Conn OD (in) Wt (#/ft)Grade Conn Burst (psi) Collap se (psi) Tension (k-lbs) 8-1/2”4-1/2”3.958”3.833”5.0”12.6#L-80 GBCD 8430 7500 288 ** Minimum of 100’ overlap required between casing strings 4. Drill Pipe Information Hole Section OD (in)ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 5”4.276 3.25 6.625 19.5 S-135 NC50 15,638 10,029 560k Page 5 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx 5. Internal Reporting Requirements 1. Fill out daily drilling report and cost report. x Report covers operations from 6am to 6am x Ensure time entry adds up to 24 hours total. x Capture any out-of-scope work as NPT. This helps later when aggregating end of well reports. 2. Afternoon Updates x Submit a short operations update every day to mmyers@hilcorp.com, cdinger@hilcorp.com, sean.mclaughlin@hilcorp.com 3. EHS Incident Reporting x Notify EHS field coordinator. i. Garrett St. Clair: C: (907) 252-7780 x Spills: i. Adrian Kersten: C: 907-564-4820 ii. Monty Myers: O: 907-777-8431 C: 907-538-1168 iii. Sean Mclaughlin x Report ALL spills to the water within 15 minutes. x Submit Hilcorp Incident report to contacts above within 24 hrs 4. Casing Tally x Send final “As-Run” Casing tally to sean.mclaughlin@hilcorp.com and cdinger@hilcorp.com 5. Casing and Cmt report x Send casing and cement report for each string of casing to sean.mclaughlin@hilcorp.com and cdinger@hilcorp.com Page 6 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx 6. Current Wellbore Schematic Page 7 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx 7. Planned Wellbore Schematic Final Diagram must show the injection strings, with top of cement at 255' in the B-string for awareness during final P&A. -bjm Page 8 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx 8. Drilling Summary B-01B is an 8976’ MD / 6732’ TVD development gas sidetrack drilled from leg 1 slot #4 off the Tyonek platform. The base plan is an infill wellbore to the Beluga U. The well will be completed with a 4-1/2”gas lift tie-back completion. Drilling operations is expected to commence approximately August 2024. General sequence of operations pertaining to this drilling operation: Rig Work 1. Rig 151 will MIRU over B-01A 2. NU BOPE and test to 3000 psi. (MASP 2760psi) 3. Set 9-5/8” whipstock at 2790’and 30R. Swap well to 8.8 ppg LSND mud. 4.Mill window with 20’ of new formation. 5. Perform FIT to 13.8 ppg EMW 6. MU 8-1/2” bit with 6-3/4” tools (Triple Combo LWD) 7. Drill 8-1/2” production hole to 8976 MD, performing short trips as needed x MPD equipment to be used as primary well control barrier x NOV Agitator tool to be used to reduce stick slip if necessary 8. Swap well over to KWF. POOH w/ directional tools. 9. RIH w/ 4-1/2” liner. Set liner and cement. Circ wellbore clean. 10. Perform Clean out run to polish bore, LDDP 11. Perform liner lap test to 3000 psi. 12. Run 4-1/2”gas lift completion. 13. Land hanger and test.MIT-T to 3000 psi, MIT-IA to 3000 psi 14. ND BOPE, NU tree and test void Reservoir Evaluation Plan: 1. Surface hole: GR + Res LWD 2. Production Hole: Triple Combo LWD 9. Mandatory Regulatory Compliance / Notifications Page 9 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx Regulatory Compliance Ensure that drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling. Ensure to provide AOGCC 48 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. o The highest reservoir pressure expected is 3433 psi in the Beluga U sand (6732' TVD). MASP is 2760 psi with 0.1psi/ft gas in the wellbore. o A casing test to 3000 is planned as part of the prerig work x Rated Working Pressure (RWP) the BOPE and wellhead must meet or exceed: 3000 psi. x If the BOP is used to shut in on the well in a well control situation, ALL BOP components utilized for well control must be tested prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: x 20 AAC 25.033(b)(1)(A) variance request:Managed Pressure Drilling equipment and technique will be used for primary well control in place of drilling mud while drilling the 8-1/2” production hole. Kill weight fluid will be used for primary well control during surface hole and running liner. o B-01B is the fourth well planned to drill with MPD and a waiver. o The MPD system will be used to apply surface pressure to keep the open hole formation in an overbalanced state. o All influxes to be circulated out per conventional well kill protocols. Benefits of using MPD with hydrostatically underbalanced mud weight: o Ability to utilize lighter mud weight and compensate for ECD difference through SBP (Surface Back Pressure) to stay above PP/wellbore stability o Improve ROP and minimize differential sticking o Ability to increase or reduce EMW downhole by adjusting SBP, without going through the process of displacing to new mud weight. o More effective downhole pressure control when comes to high pressure or abnormal pressure regimes. Page 10 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx o Coriolis flowmeter is able to measure small flowrates difference (up to +/- 0.10% of flow rate accuracy for liquid, technical specs sheet as per attached) thus able to identify influx or losses before it's picked up by the conventional PVT system. o Applying constant SBP can help to minimize ballooning and swabbing. o Holding SBP during connections help to minimize pressure cycling in the sensitive formation o With RCD and MPD Choke manifold in place, the drilling system is going to be closed loop all the time where MPD chokes will be opening and closing automatically depending on flowrates down the string to apply desired target SBP. o While ensuring SBP is applied constantly (except during the cases of losses), any flow is diverted away from the rig floor. Equipment and Generic Flow path: o Major Equipment includes: 1. MPD Choke Manifold Building (With MPD Choke Manifold) o MPD Control Console (inside MPD Choke Manifold Building) o Coriolis flowmeter spool (inside MPD Choke Manifold Building) 2. MPD Remote Control Panel 3. RCD Body 4. RCD Bearing assembly with sealing elements (installed into RCD Body) 5.Various piping (4” and 2”) and hoses (4” and 2”) 6. Isolation valves o Proposed flow path diagram is as follows: Contingency: Page 11 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx o There will be sufficient weighting material on location to bring the drilling mud up to KWF weight. Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 8-1/2” x 13-5/8” Shaffer 5M annular x 13-5/8” 5M Shaffer SL Double gate x Blind ram in bottom cavity x Mud cross x 13-5/8” 5M Shaffer SL single gate x 3-1/16” 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: Masco 7 station, 15 bottle, 3000 psi closing unit with two air pumps, a triplex electric driven pump Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 48 hours notice prior to full BOPE test. x Any other notifications required in APD conditions of approval. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / (C): 907-250-9193 / Email: bryan.mclellan@alaska.gov Melvin Rixse / Petroleum Engineer / (O): 907-793-1231 / Email: melvin.rixse@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) 10. R/U and Preparatory Work 1. Mix 8.8 ppg WBM mud for 8-1/2” hole section. 2. Install 7” liners in mud pumps. Plan to pump at 400-500 gpm. 7” liners will deliver 575 gpm @ 98% eff @ 3623 psi. Page 12 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx 11. BOP N/U and Test 1. N/D Tree and adapter (BPV installed as part of pre-rig work), Install blanking plug 2. N/U to 11” 5M tubing spool 3. N/U 13-5/8” x 5M BOP as follows (top down): x RCD for MPD (Beyond Energy) x 13-5/8” x 5M Shaffer annular BOP. x 13-5/8” 5M Shaffer Type SL Double ram. (2-7/8” X 5” VBR in top cavity, blind ram in btm cavity) x 13-5/8” mud cross x 13-5/8” 5M Shaffer Type SL single ram. (2-7/8” X 5” VBR) x N/U pitcher nipple, install flowline. x Install (2) manual valves on kill side of mud cross. Manual valve used as inside or “master valve”. x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. x 11” 5M adapter required 4. Run BOPE test plug. 5. Test BOPE. x Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. x Ensure to leave “A” section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. Confirm the correct valves are opened!!! x Test VBRs on a 4-1/2” and 5” test joints (3000 psi test) x Test Annular on 4-1/2” test joint (2500 psi) x Ensure gas monitors are calibrated and tested in conjunction w/ BOPE. 6. Pull test plug. Page 13 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx 12. Set Whipstock / Mill Window Operation Steps: 1. Set wear bushing in wellhead. Ensure ID of wear bushing > 8-1/2”. 2. Make up the WIS Mechanical set Whipstock. 3. TIH with DP to the whipstock setting depth. Exercise caution when RIH / setting slips with whipstock assembly ¾Fill the drill pipe a minimum of every 20 stands on the trip in the hole with the whipstock assembly. ¾Avoid sudden starts and stops while running the whipstock. ¾Recommend running in the hole at a maximum of 90-120 seconds per stand taking care not to spud or catch the slips. Ensure running string is stationary prior to insertion of the slips and that slips are removed slowly when releasing the work string to RIH. These precautions are required to avoid any weakening of the whipstock shear mechanisms and / or to avoid part / preset on the packer. 4. Orient whipstock as directed by the directional driller. The directional plan specifies 30 deg ROHS. 5. Set the top of the whipstock at ~2,790’ MD x 9-5/8” Collar at 2770’ and 2816’ x Ref log: NCIU B-1A CBL 24-APR-2023 x 9-5/8” CIBP w/ 25’ cmt (est TOC –3,450) 6. Mill window plus 20’-50’ of new hole (DO NOT EXCEED 50’ OF NEW HOLE BEFORE RUNNING THE PLANNED FIT/LOT). ¾Use ditch magnets to collect the metal shavings. Clean regularly. ¾Ensure any personnel working around metal shavings wear proper PPE, including goggles, face shield and Kevlar gloves. ¾Work the upper mill through the window to confirm the window milling is complete and circulate well clean (circulate a minimum of 1-1/2 bottoms up). Pump a high-vis super sweep to remove metal shavings and make every effort to remove all of the super sweep pill from the mud system as it is circulated to surface. 7. Pull starter mill into casing above top of whipstock, flow check the well for 10 minutes and conduct a FIT to 13.8 ppg. ¾**Assuming the kick zone is at TD, a FIT of 13.8 ppg EMW gives a Kick Tolerance volume of 34 bbls with 9.2 ppg mud weight. ¾The OA shoe is open. Monitor OA during FIT and report and change in pressure. Page 14 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx 8. POOH and LD milling assembly ¾Once out of the hole, inspect mill gauge and record. ¾Flow check well for 10 minutes to confirm no flow: ¾Before pulling off bottom. ¾Before pulling the BHA through the BOPE. 9. Flush the stack/lines to remove metal debris that may have settled out in these areas. Ensure BOP equipment is operable. 13. Drill 8-1/2” Hole Section 1. PU 9000’ of 5” NC50 Drill pipe for drilling 8-1/2” hole section 2. P/U 6-3/4” Sperry Sun motor drilling assy w/ triple combo (DEN, POR, RES). 3. Ensure BHA Components have been inspected previously. 4. Drift & caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 5. Ensure TF offset is measured accurately and entered correctly into the MWD software. 6. Have DD run hydraulics models to ensure optimum TFA. Plan to pump at 400-500 gpm. 7. Production section will be drilled with a motor. Must keep up with 3.5 deg/100 DLS in the build and drop sections of the wellbore. 8. TIH to window. Shallow test MWD on trip in. 9. TIH through window ensure Baker Hughes MWD service rep on rig floor during this operation. 10. Circulate well with 8.8 ppg LNSD to warm up mud until good 8.8 ppg in and out. 11. Drill 8-1/2” hole to 8976’ MD using motor assembly. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. x Keep swab and surge pressures low when tripping. x See attached mud program for hole cleaning and LCM strategies. Page 15 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx x Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. x Ensure mud engineer set up to perform HTHP fluid loss. x Maintain API fluid loss < 6. x Take MWD surveys every stand drilled. x Minimize backreaming when working tight hole x Adjust EMW with MPD as necessary to maintain overbalance. 12. At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement calculations. CBU, and swap well to KWF. KWF dependent on pressures observed while drilling. Flow check well for 10 minutes. 13. TOH with drilling assembly, handle BHA as appropriate. 14. Run 4-1/2” Production Liner 1. R/U Baker 4-1/2” liner running equipment. x Ensure 5” NC50 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill liner while running. x Ensure all liner has been drifted and tally verified prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 2. P/U shoe joint, visually verify no debris inside joint. 3. Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). Centralizer 10’ from the bottom with stop ring Anticipated Formations and Pressures: Formation Top TVD MD Est Pressure Oil/Gas/Wet PPG Grad Target EMW Top_Sterling_X 3492 3908 1,467 Gas 8.1 0.42 8.6 Top_Beluga_A 4523 6255 1,949 Gas 8.3 0.43 8.8 Top_Beluga_I 5522 7732 2,540 Gas 8.8 0.46 9.3 Top_Beluga_M 5901 8132 2,832 Gas 9.2 0.48 9.7 Beluga T/U - TD 6732 8976 3,433 Gas 9.8 0.51 10.3 Page 16 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x Landing collar pup bucked up. No centralizer x Centralizers will be run on 4-1/2” liner every joint to 6255’ and every other joint above that. x Ensure proper operation of float shoe & FC. 4. Continue running 4-1/2” production liner to TD x Short joint run every 1000’, RA Tag 1000’ and 2000’ from bottom. x Fill liner while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Utilize a collar clamp until weight is sufficient to keep slips set properly. 5.Ensure to run enough liner to provide at least 100’ overlap inside casing. Ensure setting sleeve will not be set in a connection. Page 17 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx 6. Before picking up Baker ZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 7.M/U Baker ZXP liner top packer. Fill liner tieback sleeve with “XANPLEX”, ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 8. RIH one stand and circulate a minimum of one liner volume. Note weight of liner. 9. RIH w/ liner on DP no faster than 1 min / stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 10. M/U top drive and fill pipe while lowering string every 10 stands. 11. Set slowly in and pull slowly out of slips. 12. Circulate 1-1/2 drill pipe and liner volume at 9-5/8” shoe prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure. 13. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 14. Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill casing. 15.P/U the cmt stand and tag bottom with the liner shoe. P/U 2’ off bottom. Note slack-off and pick-up weights. Record rotating torque values at 10, 20, & 30 rpm. 16. Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting pressure. Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling fluid by adding water and thinners. 17. Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. 15. Cement 4-1/2” Production Liner 1. Hold a pre-job safety meeting over the upcoming cmt operations. 2. Attempt to reciprocate the casing during cmt operations until hole gets sticky. 3. Pump 15 bbls 12.5 ppg spacer. 4. Test surface cmt lines to 4500 psi. 5. Pump remaining 10 bbls 12.5 ppg spacer. Page 18 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx 6. Mix and pump cement per below recipe and volume below with xx lbs/bbl of loss circulation fiber. Please independently verify cement volume with actual inputs. Ensure cmt is pumped at designed weight. Job is designed to pump 40% OH excess but if wellbore conditions dictate otherwise decrease or increase excess volumes. Cement volume is designed to bring cement to TOL. 7. Displacement fluid will be CLEAN drilling mud. Please independently verify with actual inputs. Slurry Information: 8. Drop DP dart and displace with KWF. Lead Slurry Tail Slurry System EconoCem HalCem Density 12.0 lb/gal 15.3 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk Verified cement calcs. -bjm Page 19 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx 9. Pump cement at max rate of 5 bbl/min. Reduce pump rate to 3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re-zeroed at this point 10. If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. Reduce pump rate as required to avoid packoff. 11. Bump the plug. Do not overdisplace by more than 2 bbls. 12. Pressure up to 4200 psi to release the running tool (HRD-E) from the liner 13. Bleed pressure to zero to check float equipment. 14. P/U, verify setting tool is released. 15. Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 16. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 17. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re-tag the liner top, and circulate the well clean. 18. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 19. POOH, LDDP. Backup release from liner running tool: 20. If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 21.NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down to the setting tool. 22. After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At Page 20 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. Ensure to report the following on Wellview: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if liner is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Note: Send Csg & cmt report + “As-Run” liner tally to sean.mclaughlin@hilcorp.com 16. Wellbore Clean Up & Displacement 1. No cleanout planned. Service coil will cleanout, displace mud, and blow down well with N2 prior to perforating. 2. Test liner lap to 3000 psi after cement has reached 500 psi compressive strength. 10 min operational assurance test. 17. Run Completion Assembly 1. Run 4-1/2” tubing completion assembly to above the liner top x Tubing will be 4-1/2” L-80 12.6# GBCD x Baker S-5 SSSV to be placed between 400’ and 450’ MD x Live GLM’s will be run at xxxx TVD (1 full joint between X-nip and bottom GLM pup) x Tripoint X NIP –just above the seal stem 2. Swap the well over to FIW Page 21 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx x Circulate a hi-vis pill followed by a soap train per Baroid x Circulate FIW until clean-up is satisfactory. x Leave FIW in the annulus. 3. Space out and land seal bore in tie back sleeve. RILDs. 4.Test IA to 3000 psi and tubing to 3000 psi. Charted 30 min. 5. Install BPV in wellhead. 6. ND BOPE, NU tree, test void 7. Rig Down Page 22 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx 18. BOP Schematic Page 23 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx 19. Wellhead Schematic Page 24 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx 20. Anticipated Drilling Hazards Lost Circulation: Drill depleted reservoir may cause loss circulation events (as seen in the 2021 program on A-03A and A-01A) x Maintain sufficient volumes while drill. x Maintain ability to take on FIW during drilling phase x If a LC event occurs pumping cement will be the likely remedy Ensure 500 lbs of medium/coarse fibrous material, 500 lbs SteelSeal (Angular, dual-composition carbon-based material), & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ viscofier as necessary. Sweep hole w/ 20 bbls flowzan as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain programmed mud specs. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. x Minimize swab and surge pressures x Minimize back reaming through coals when possible H2S: H2S is not present in this hole section. Anti Collision: Plan Fails AC with (P&A’d) COOK INLET ST 17589-1A @ 6279’MD, ~306’C-C, -286’ E-E, CF = 0.515. 17589-1A intersection point is ~4400’ TVD. At 10558 TVD is expected to be around a 9.2 ppg EMW. Loss circulation risk is minimal. Risk of intensity kick is minimal. Accept AC risk. Page 25 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx Page 26 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx 21. FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. Add casing pressure test data to graph if recent and available. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 27 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx 22. Choke Manifold Schematic Page 28 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx Page 29 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx 23. Casing Design Information Page 30 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx 24. 8-1/2” Hole Section MASP Page 31 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx 25. Plot (NAD 27) (Governmental Sections) Page 32 June 28, 2024 NCI B-01B Drilling Program APD xxx-xxx 26. Slot Diagram !" #$%% & $ & $! 1275 1700 2125 2550 2975 3400 3825 4250 4675 5100 5525 5950 6375 6800 7225 7650True Vertical Depth (850 usft/in)425 850 1275 1700 2125 2550 2975 3400 3825 4250 4675 5100 5525 5950 6375 Vertical Section at 165.80° (850 usft/in) NCIU B-01B wp03 TD 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 00 0 5 5 0 0 60 0 0 6 5 0 0 7 0 0 0 7 5 0 0 8 0 0 0 8 5 0 09 0 0 0 B-01A 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 00 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 09 0 0 0 B-01 4 1/2" x 8 1/2" 2 0 0 0 2 5 0 0 3 0 0 0 350040004500500055006000650070007 5 0 0 8 0 0 0 8 5 0 0 8 9 7 6 NCIU B-01B wp03 Start Dir 12º/100' : 2790' MD, 2700.21'TVD : 30° RT TF End Dir : 2807' MD, 2715.29' TVD Start Dir 3.5º/100' : 2907' MD, 2803.3'TVD Start Dir 1.5º/100' : 3935.24' MD, 3504.33'TVD End Dir : 4773.71' MD, 3873.38' TVD Start Dir 3º/100' : 6405.71' MD, 4588.8'TVD End Dir : 8205.71' MD, 5973.72' TVD Total Depth : 8975.69' MD, 6732' TVD Top_Sterling_X Top_Beluga_A Top_Beluga_I Top_Beluga_M Beluga T/U - TD 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: NCIU B-01 Water Depth: 101.00 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 2586723.04 331998.16 61° 4' 36.3101 N 150° 56' 55.5565 W SURVEY PROGRAM Date: 2024-06-14T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 194.63 2790.00 N COOK INLET UNIT B-01 (NCI B-01) 3_MWD 2790.00 3200.00 NCIU B-01B wp03 (NCIU B-01B) 3_MWD_Interp Azi+Sag 3200.00 8975.69 NCIU B-01B wp03 (NCIU B-01B) 3_MWD+AX+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 3492.00 3365.37 3907.59 Top_Sterling_X 4523.00 4396.37 6255.62 Top_Beluga_A 5522.00 5395.37 7731.86 Top_Beluga_I 5901.00 5774.37 8131.60 Top_Beluga_M 6731.99 6605.36 8975.68 Beluga T/U - TD REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well NCIU B-01, True North Vertical (TVD) Reference:NCIU B-01B @ 126.63usft Measured Depth Reference:NCIU B-01B @ 126.63usft Calculation Method: Minimum Curvature Project:North Cook Inlet Site:North Cook Inlet Unit Well:NCIU B-01 Wellbore:NCIU B-01B Design:NCIU B-01B wp03 CASING DETAILS TVD TVDSS MD Size Name 2700.21 2573.58 2790.00 9-5/8 9 5/8" KOP 6732.00 6605.37 8975.69 4-1/2 4 1/2" x 8 1/2" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 2790.00 26.58 166.48 2700.21 -522.63 94.48 0.00 0.00 529.83 Start Dir 12º/100' : 2790' MD, 2700.21'TVD : 30° RT TF 2 2807.00 28.35 168.69 2715.29 -530.28 96.16 12.00 30.00 537.67 End Dir : 2807' MD, 2715.29' TVD 3 2907.00 28.35 168.69 2803.30 -576.85 105.47 0.00 0.00 585.10 Start Dir 3.5º/100' : 2907' MD, 2803.3'TVD 4 3935.24 64.00 176.00 3504.33 -1301.19 188.35 3.50 11.23 1307.64 Start Dir 1.5º/100' : 3935.24' MD, 3504.33'TVD 5 4773.71 64.00 162.00 3873.38 -2038.40 331.65 1.50 -93.08 2057.48 End Dir : 4773.71' MD, 3873.38' TVD 6 6405.71 64.00 162.00 4588.80 -3433.44 784.92 0.00 0.00 3521.08 Start Dir 3º/100' : 6405.71' MD, 4588.8'TVD 7 8205.71 10.00 162.00 5973.72 -4425.98 1107.42 3.00 180.00 4562.41 End Dir : 8205.71' MD, 5973.72' TVD 8 8975.69 10.00 162.00 6732.00 -4553.14 1148.74 0.00 0.00 4695.82 NCIU B-01B wp03 TD Total Depth : 8975.69' MD, 6732' TVD -4950 -4675 -4400 -4125 -3850 -3575 -3300 -3025 -2750 -2475 -2200 -1925 -1650 -1375 -1100 -825 -550 -275 0 275 South(-)/North(+) (550 usft/in)-1375 -1100 -825 -550 -275 0 275 550 825 1100 1375 1650 1925 2200 2475 West(-)/East(+) (550 usft/in) NCIU B-01B wp03 TD B-01AB -0 1 4 1/2" x 8 1/2" 2 50 5 0 0 750100 0 1 2 5 0 150 0 175 0 20 0 0 2 2 5 0 2 5 0 0 2 75 0 3 0 0 0 32 5 0 35 0 0 3 7 5 0 4 0 0 0 4 2 5 0 4 5 0 0 4 7 5 0 5 0 0 0 5 2 5 0 5 5 0 0 5 7 5 0 6 0 0 0 6 2 5 0 6 5 0 0 6 7 3 2 N C I U B -0 1 B w p 0 3 Start Dir 12º/100' : 2790' MD, 2700.21'TVD : 30° RT TF End Dir : 2807' MD, 2715.29' TVD Start Dir 3.5º/100' : 2907' MD, 2803.3'TVD Start Dir 1.5º/100' : 3935.24' MD, 3504.33'TVD End Dir : 4773.71' MD, 3873.38' TVD Start Dir 3º/100' : 6405.71' MD, 4588.8'TVD End Dir : 8205.71' MD, 5973.72' TVD Total Depth : 8975.69' MD, 6732' TVD CASING DETAILS TVD TVDSS MD Size Name 2700.21 2573.58 2790.00 9-5/8 9 5/8" KOP 6732.00 6605.37 8975.69 4-1/2 4 1/2" x 8 1/2" Project: North Cook Inlet Site: North Cook Inlet Unit Well: NCIU B-01 Wellbore: NCIU B-01B Plan: NCIU B-01B wp03 WELL DETAILS: NCIU B-01 Water Depth: 101.00 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 2586723.04 331998.16 61° 4' 36.3101 N 150° 56' 55.5565 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well NCIU B-01, True North Vertical (TVD) Reference: NCIU B-01B @ 126.63usft Measured Depth Reference:NCIU B-01B @ 126.63usft Calculation Method:Minimum Curvature '" ( ) % " ! *" +,- *" ! . ./ 0)"! 1& ! !" ! #$%&%'!( -!2)' -/*+, - 1- *"#$%&%'!( & *" . +! 1 )( 3 -( '" 1 4 )(-( /$0123 !4 -/$01 -**4 56 . 7.( 77 ( ! !! 5 ( ! %! % 2! !! 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Plots Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. NCIU B-01B 224-097 TERTIARY GASNORTH COOK INLET WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:N COOK INLET UNIT B-01BInitial Class/TypeDEV / PENDGeoArea820Unit11450On/Off ShoreOffProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2240970NORTH COOK INLET, TERTIARY GAS - 564570NA1 Permit fee attachedYes Entire Well lies within ADL0017589.2 Lease number appropriateYes3 Unique well name and numberYes NORTH COOK INLET, TERTIARY GAS - 564570 - governed by CO 68A4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)NA Sidetrack18 Conductor string providedYes19 Surface casing protects all known USDWsNA20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitYes abandonment already completed25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedYes27 If diverter required, does it meet regulationsYes MPD used to maintain dynamic overbalance.28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 2760 psi, BOP rated to 5000 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 shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not expected in this well.35 Permit can be issued w/o hydrogen sulfide measuresYes Sterling slightly under-pressured (~ 8.1 ppg EMW). Beluga A to H normally pressured (~ 8.3 ppg).36 Data presented on potential overpressure zonesNA Beluga I to L over pressured (~ 8.85 ppg). Beluga M to T over pressured (~9.25 ppg). Beluga U37 Seismic analysis of shallow gas zonesNA over pressured (9.8 ppg). MPD will be utilized to maintain over balance.38 Seabed condition survey (if off-shore)NA Operator's planned MPD target EMW program appears adequate (see p.39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate7/16/2024ApprBJMDate8/14/2024ApprSFDDate7/16/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 8/15/2024