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Home My WebLink About225-030David Douglas Hilcorp North Slope, 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: Hilcorp North Slope, LLC Date: 07/02/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: PBU 18-27F PTD: 225-030 API: 50-029-22321-06-00 FINAL LWD FORMATION EVALUATION LOGS (06/07/2025 to 06/12/2025) Multiple Propagation Resistivity & Gamma Ray (2” & 5” MD/TVD Color Logs) Pressure While Drilling (PWD) Final Definitive Directional Surveys SFTP Transfer - Data Main Folders: SFTP Transfer - Data Sub-Folders: Please include current contact information if different from above. 225-030 T40631 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.07.03 08:03:50 -08'00' June 18, 2025 By Grace Christianson at 10:43 am, Jun 10, 2025 Digitally signed by Torin Roschinger (4662) DN: cn=Torin Roschinger (4662) Date: 2025.06.09 17:10:53 - 08'00' Torin Roschinger (4662) 325-351 A.Dewhurst 10JUN25JJL 6/10/25 10-407 Perforating gun or patch assembly not to exceed 500'. Reestablish pressure containment prior to perforating and running patch. Perform and document well control drill on each shift using attached standing orders. Ensure well is dead before breaking containment *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.06.16 13:49:04 -08'00'06/16/25 RBDMS JSB 061825 Ext liner top packer 18-27F PTD: 225-030 Well Name:18-27F API Number: 50-029-22321-06 Current Status:New drill - Producer Rig:CTU Estimated Start Date:6/18/25 Estimated Duration:2days Reg.Approval Req’std?10-403 Date Reg. Approval Rec’vd:Check status Regulatory Contact:Carrie Janowski (907) 564-5179 First Call Engineer:David Bjork (907) 564-4672 (907) 440-0331 Expected Rates Post Work ~2 MSCFD, 1000 BOPD and 1000BWPD Current Bottom Hole Pressure:3350 psi @ 8,800’ TVD 7.4 PPGE (offset producer 18-14C BHP) Max. Anticipated Surface Pressure:2470psi (Based on 0.1 psi/ft. gas gradient) Last SI WHP:new drill Min ID:2.37” 3-1/4” x 2-7/8” crossover @ ~9,929’ MD Max Angle:91 Deg @ 10,337’ MD, 70 Deg at ~9,700’ MD Brief Well Summary: 18-27F is a new drill currently being drilled by CDR2. Unfortunately DS 18 lacks gas lift, we commonly use metered in-situ gas lift from either the Sag or Put River formations. While calipering the wellbore before running the whipstock (after pulling a scab liner over existing Put River perfs) a gap in the completion continuity was found. The original packer tailpipe was not stung into the 4-1/2” liner top. Therefore a short liner top packer assembly is no longer practical. The 93’ vintage completion tail above the gap is also severely pitted and eroded. We are requesting approval to deploy an extended liner top assembly, to place the liner top packer in ‘clean’ pipe and allow access to the Put River perfs (if needed) before installing the liner top packer assembly. Note: Put River is the top of the pool in DS 18. Objective:Install extended liner top packer assembly with sliding sleeve for metered in-situ lift if necessary. 8,585ft to 8,760ft (175ft) Procedure Pop perforated well to portable testers for cleanup post rig. If the well flows and is competitive send to facility. Or If the well flows but has an uncompetitive GOR, assume Put River perfs are open and flowing. Proceed to sundried work below. Or If the well will not flow, e-line perforate the Put River section from 8,710 to 8,750ft and repeat. Coiled Tubing 1. MU drift BHA with GR/CCL in 2.25” carrier, drift to 8,800ft. Note: LTP assembly at 8,760ft 2. Correlate with attached log information. a. Correct flag and send to OE for confirmation. Coil – Extended Patch Deployment Notes: x Remote gas monitoring for H2S and LELs are required for Open Hole Deployment Operations x Due to the necessary open hole deployment of Extended Patch job, 24-hour crew and WSS coverage is required. Ext liner top packer 18-27F PTD: 225-030 The well will be killed and monitored before making up the patch. This is generally done during the drift/logging run. This will provide guidance as to whether the well will be killed by bullheading or circulating bottoms up throughout the job. If pressure is seen, it will either be killed by bullheading while POOH or circulating bottoms up. 1. After MU MHA and pull testing the CTC, tag-up on the CT stripper to ensure BHA cannot pull through the brass upon POOH with running tools, ensure adequate lubricator length to cover the running tools. 2. Bullhead 1.2x wellbore volume ~160 bbls 1% KCL/SW down tubing. Max tubing pressure 2500 psi. (This step can be performed any time prior to open-hole deployment of the patch. Timing of the well kill is at the discretion of the WSS.) a. Wellbore volume to top perf (Put river)= 133 bbls b. 4-1/2” tubing/liner – 8,760’ X .0152 bpf = 133 bbls 3. At surface, prepare for deployment of patch. 4. Confirm well is dead. Bleed any pressure off to return tank. Kill well w/ KWF, 8.4 ppg 1% KCl or 8.5 ppg as needed. Maintain hole fill taking returns to tank until lubricator connection is re-established. Fluids man-watch must be performed while deploying patch to ensure the well remains killed and there is no excess flow. 5.*Perform drill by picking up safety joint with TIW valve and space out before MU patch. Review standing orders with crew prior to breaking lubricator connection and commencing makeup of patch. Once the safety joint and TIW valve have been spaced out, keep the safety joint/TIW valve readily accessible near the working platform for quick deployment if necessary. c.At the beginning of each job, the crossover/safety joint must be physically MU to the patch one time to confirm the threads are compatible. 6.Break lubricator connection at QTS and begin makeup of patch per schedule below. Constantly monitor fluid rates pumped in and fluid returns out of the well. Fluids man-watch must be performed while deploying patch to ensure the well remains killed and there is no excess flow. Patch assembly Patch Interval (tie-in depths) Patch Length Weight of Gun (lbs) Run #1 8,585’–8,760’175’ ~1,120 lbs (6.4 ppf) 7. RIH with PTSA, 2-7/8” sliding sleeve (closed), 2-7/8” chrome spacer pipe and liner top packer assembly with hydraulic setting tool. 8. Stab into liner top and set patch. 9. Pooh with running tools into lubricator, close in and bleed off. Break down running tools. End of sundried work. 10. RIH with drift nozzle and swap wellbore to diesel from 8,500ft to surface. 11. RDMO CTU. 12. Turn well over to Operations POP. Ext liner top packer 18-27F PTD: 225-030 Attachments: Wellbore Schematic, Proposed Schematic, Caliper Log, BOPE and rig-up diagram, Sundry Change Form Current Proposed Drilling Schematic Ext liner top packer 18-27F PTD: 225-030 Proposed Post Rig Wellbore Schematic 8,585ft –8,760ft Liner top packer assembly with In-situ lift provision Ext liner top packer 18-27F PTD: 225-030 Caliper Log Ext liner top packer 18-27F PTD: 225-030 BOP Schematic Ext liner top packer 18-27F PTD: 225-030 Ext liner top packer 18-27F PTD: 225-030 Ext liner top packer 18-27F PTD: 225-030 Changes to Approved Sundry Procedure Date: Subject: Sundry #: Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the “first call” engineer. AOGCC written approval of the change is required before implementing the change. Step Page Date Procedure Change HAK Prepared By (Initials) HAK Approved By (Initials) AOGCC Written Approval Received (Person and Date) Approval: Operations Manager Date Prepared: Operations Engineer Date 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: Prudhoe Bay Unit Field, Prudhoe Oil, PBU 18-27F Hilcorp Alaska, LLC Permit to Drill Number: 225-030 Surface Location: 893' FNL, 236' FEL, Sec. 24, T11N, R14E, UM, AK Bottomhole Location: 1730' FSL, 2125' FEL, Sec. 13, T11N, R14E, UM, 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 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 25th day of April 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.25 16:58:25 -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: 11779' TVD:8685' 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): 53.35' 15. Distance to Nearest Well Open Surface: x-691522 y- 5960969 Zone- 4 15.7' to Same Pool: 200' 16. Deviated wells: Kickoff depth: 9550 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 91 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 4-1/4"3-1/2"x3-1/4"9.3#/6.6# 13Cr80 STL/TCII 3019' 8760' 8066' 11779' 8685' x2-7/8" 6.5# /Hyd 511 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): 13152 TVD 38 - 118 38 - 3497 36 - 8259 8110 - 8618 8011 - 8660 8020 - 8671 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: Trevor Hyatt Sean McLaughlin Contact Email:trevor.hyatt@hilcorp.com Drilling Manager Contact Phone:907-223-3087 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 May 15, 2025 25000' Liner 998 7" 398 cu ft Class G 8829 - 9827 8691 - 13187 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): Perforation Depth MD (ft): 3459 2000# Poleset 38 - 118 38 - 349713-3/8" 2706 cu ft CS III, 460 cu ft Class G Effect. Depth MD (ft): Effect. Depth TVD (ft): Authorized Title: Authorized Signature: 3-1/2" x 3-1/4" x 2-7/8" 36 - 9069 832 cu ft Class G 175 sx Class G Liner Liner 9033 1623 4496 Intermediate Authorized Name: 8710 - 13130 Conductor 20"80 13187 8671 LengthCasing None Cement Volume MDSize Plugs (measured): (including stage data) 145 sx Class G 13152 8672 2560 18. Casing Program: Top - Setting Depth - BottomSpecifications 3340 Total Depth MD (ft): Total Depth TVD (ft): 107205344 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 2460 187' FNL, 2469' FEL, Sec. 24, T11N, R14E, UM, AK 1730' FSL, 2125' FEL, Sec. 13, T11N, R14E, UM, AK 79-190 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 Hilcorp North Slope, LLC 893' FNL, 236' FEL, Sec. 24, T11N, R14E, UM, AK ADL 028307 PBU 18-27F PRUDHOE BAY PRUDHOE OIL Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. 8033 - 8672 2217 cu ft Class G 8678 - 103014-1/2" 9-5/8" oooo oo ooo ooo oo oo oo 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 Grace Christianson at 9:08 am, Apr 01, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.03.28 16:04:14 - 08'00' Sean McLaughlin (4311) *Variance as per 20 AAC 25.112(i): Approved for alternate abandonment plug placement on parent well contingent upon fully cemented liner on upcoming sidetrack. 50-029-22321-06-00 A.Dewhurst 24APR25 *AOGCC Witnessed BOP Test to 3500 psi, Annular 2500 psi minimum. *Post rig service coil perforating approved for max gun length of 500'. *Window milling approved on service coil *Variance to 20 AAC 25.036 (c)(2)(A)(iv) approved with documented well control drills performed by all crews deploying tubulars <2.375" OD without properly sized pipe rams. DSR-4/2/25JJL 4/8/25 225-030 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.25 16:58:38 -08'00' 04/25/25 04/25/25 RBDMS JSB 043025 To: Alaska Oil & Gas Conservation Commission From: Trevor Hyatt Drilling Engineer Date: March 28, 2025 Re:18-27F Permit to Drill Approval is requested for drilling a CTD sidetrack lateral from well 18-27E with the Nabors CDR2/CDR3 Coiled Tubing Drilling. Proposed plan for 18-27F Producer: See 18-27E Sundry request for complete pre-rig details - Prior to drilling activities, screening will be conducted to MIT. The existing 3-1/2" liner will be cut with E-line and verified it is free (and ready to be pulled by rig) with service coil. A coil tubing drilling sidetrack will be drilled with the Nabors CDR2 or CDR3 rig. The rig will move in, test BOPE and kill the well. The rig will latch up to the 3-1/2" pre-cut liner and pull out of hole. A whipstock drift will be performed followed by setting a 4-1/2" packer whipstock. A dual string 3.80" window + 10' of formation will be milled out of the 4-1/2" and 7" liners. The well will kick off drilling in the Ivishak Zone 2 and lands in Zone 1. The lateral will continue in Zone 1 to TD. The proposed sidetrack will be completed with a 3-1/2"x3-1/4"x2-7/8” 13Cr solid liner, cemented in place and selectively perforated post rig (will be perforated with rig if unable to post rig). This completion will not completely isolate and abandon the parent Prudhoe Pool perfs (sag perfs will remain open). The following describes the work planned. A wellbore schematic of the current well and proposed sidetrack is attached for reference. Pre-Rig Work: x Reference 18-27E Sundry submitted in concert with this request for full details. 1. E-Line : Cut 3-1/2" coil at 9,610' MD 2. Fullbore : MIT-IA and/or MIT-T to 2,500 psi 3. Slickline : Bait deployment sleeve for service coil 4. Coil : Latch liner and pick up, verify liner free. Set down and release. 5. Valve Shop : Pre-CTD Tree Work 6. Operations : Remove wellhouse and level pad. Rig Work: (Estimated to start May 2025) 1. MIRU and test BOPE 250 psi low and 3,500 psi high (MASP 2,460 psi). Give AOGCC 24hr notice prior to BOPE test (install VBRs for pulling liner) 2. Pull 3-1/2" pre-cut liner from 9,610' MD and lay down 3. Drift for whipstock (swap to 3” pressure deployment rams and test) 4. Set 4-1/2" Packer Whipstock at 9,550’ MD at 180 degrees ROHS 5. Mill 3.80” Window 6. Drill build section: 4.25" OH, ~379' (28 deg DLS planned). 7. Drill production lateral: 4.25" OH, ~1850' (12 deg DLS planned). Swap to KWF for liner. 8. Run 3-1/2” x 3-1/4” x 2-7/8” 13Cr solid liner (swap to VBRs and test prior to running liner) 9. Pump primary cement job: 32 bbls, 15.3 ppg Class G, 1.24 (ft3/sk), TOC at TOL. 10. Only if not able to do with service coil extended perf post rig – Perforate Liner 11. Freeze protect well to a min 2,200' TVD. 12. Close in tree, RDMO. Post Rig Work: 1. Valve Shop : Valve & tree work 2. Slickline : Set LTP* (if necessary). Set live GLVs. 3. Service Coil : Perforate (~1250’) - see extended perf procedure attached. 4. Testing : Portable test separator flowback. Managed Pressure Drilling: Managed pressure drilling techniques will be employed on this well. The intent is to provide constant bottom hole pressure by using minimum 8.4 ppg drilling fluid in combination with annular friction losses and applied surface pressure. Constant BHP will be utilized to reduce pressure fluctuations to help with hole stability. Applying annular friction and choke pressure also allow use of lighter drilling fluid and minimizes fluid losses and/or fracturing at the end of the long well bores. A MPD choke for regulating surface pressure and is independent of the WC choke. Deployment of the BHA under trapped wellhead pressure will be necessary. Pressure deployment of the BHA will be accomplished utilizing 3”/3-1/8” (big hole) & 2-3/8” (slim hole) pipe/slip rams (see attached BOP configurations). The annular preventer will act as a secondary containment during deployment and not as a stripper. Operating parameters and fluid densities will be adjusted based on real-time bottom hole pressure measurements while drilling and shale behavior. The following scenario is expected: MPD Pressure at the Planned Window (9550' MD -8,511' TVD) Pumps On Pumps Oī A Target BHP at Window (ppg)4,337 psi 4,337 psi 9.8 B ŶŶƵůĂƌĨƌŝĐƟŽŶ-;ƉƐŝͬŌͿ 573 psi 0 psi 0.09 C DƵĚ,ǇĚƌŽƐƚĂƟĐ;ƉƉŐͿ 3,806 psi 3,806 psi 8.6 B+C Mud + ECD Combined 4,379 psi 3,806 psi (no choke pressure) A-(B+C)Choke Pressure Required to Maintain 0 psi 531 psi Target BHP at window and deeper Operation Details: Reservoir Pressure: x The estimated reservoir pressure is expected to be 3,340 psi at 8,800 TVD. (7.3 ppg equivalent). x Maximum expected surface pressure with gas (0.10 psi/ft) to surface is 2,460 psi (from estimated reservoir pressure). Mud Program: x Drilling: Minimum MW of 8.4 ppg KCL with viscosifier for drilling. Managed pressure used to maintain constant BHP. Disposal: x All Class l & II non-hazardous and RCRA-exempt drilling and completion fluids will go to GNI at DS 4. x Fluids >1% hydrocarbons or flammables must go to GNI. x Fluids >15% solids by volume must go to GNI. x Fluids with solids that will not pass through 1/4” screen must go to GNI. x Fluids with PH >11 must go to GNI. Hole Size: x 4.25" hole for the entirety of the production hole section. Liner Program: x 3-1/2", 9.3#, 13Cr/Solid: 8,760' MD – 9,540' MD (780' liner) x 3-1/4", 6.6#, 13Cr/Solid: 9,540' MD – 9,929' MD (389' liner) x 2-7/8", 6.5#, 13Cr/Solid: 9,929' MD – 11,779' MD (1,850' liner) x The primary barrier for this operation: Kill Weight Fluid to provide overbalance as necessary. x A X-over shall be made up to a safety joint including a TIW valve for all tubulars ran in hole. Well Control: x BOP diagram is attached. MPD and pressure deployment is planned. x Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 3,500 psi. x The annular preventer will be tested to 250 psi and 2,500 psi. x 1.5 wellbore volumes of KWF will be on location at all times during drilling operations. x Solid 2-7/8” Liner Running Ram Change: Change out 3”/3-1/8” pipe/slip rams (for drilling) to 2-3/8” x 3- 1/2” VBR rams for liner pulling and liner run. Test VBR rams to 250 psi and 3,500 psi. x A X-over shall be made up to a 2 3/8" safety joint including a TIW valve for all tubulars ran in hole. x 2 3/8" safety joint will be utilized while running solid or slotted liner. The desire is to keep the same standing orders for the entire liner run and not change shut in techniques from well to well (run safety joint with pre-installed TIW valve). When closing on a 2 3/8" safety joint, 2 sets of pipe/slip rams will be available, above and below the flow cross providing better well control option. Directional: x Directional plan attached. Maximum planned hole angle is 91°. Inclination at kick off point is 63°. x Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. x Distance to nearest property line – 25000 x Distance to nearest well within pool – 200 ft Logging: x MWD directional, Gamma Ray and Resistivity will be run through the entire open hole section. x Real time bore pressure to aid in MPD and ECD management. Perforating: x 1250' perforated post rig – See attached extended perforating procedure. x 2" Perf Guns at 6 spf x If post rig extended perforating with service coil is not an option, the well will be perforated with the rig or post rig under this PTD. x The well will be perforated between the CTD whipstock and TD of the newly drilled CTD well, completely in the Prudhoe Pool. x Formations: Top of Prudhoe Pool MD in the parent is 8,670’ MD Anti-Collision Failures: x Anti-Collision Summary – All wells Pass for WP01 Hazards: x DS 18 is an H2S pad. The last H2S reading on 18-27E: 20 ppm on 6/1/2022. x Max H2S recorded on DS18: 450 ppm (18-01A in 2013). x 1 fault crossings expected. x Medium lost circulation risk. Trevor Hyatt CC: Well File Drilling Engineer Joseph Lastufka (907-223-3087) Post-Rig Service Coil Perforating Procedure: Coiled Tubing Notes: x Due to the necessary open hole deployment of Extended Perforating jobs, 24-hour crew and WSS coverage is required. x Note: The well will be killed and monitored before making up the initial perfs guns. This will provide guidance as to whether the well will be killed by bullheading or circulating bottoms up throughout the job. If pressure is seen immediately after perforating, it will either be killed by bullheading while POOH or circulating bottoms up through the same port that opened to shear the firing head. Coil Tubing 1. MIRU Coiled Tubing Unit and spot ancillary equipment. 2. MU nozzle drift BHA (include SCMT and/or RPM log as needed). 3. RIH to PBTD. a. Displace well with weighted brine while RIH (minimum 8.4 ppg to be overbalanced). 4. POOH (and RPM log if needed) and lay down BHA. 5. After MU MHA and pull testing the CTC, tag-up on the CT stripper to ensure BHA cannot pull through the brass upon POOH with guns. 6. There will be no perforations to bullhead kill the well. Well will already be loaded w/ weighted brine or KCl per previous steps. Re-load well at WSS discretion. 7. At surface, prepare for deployment of TCP guns. 8.Confirm well is dead. Bleed any pressure off to return tank. Kill well w/ KWF, weighted brine as needed (minimum 8.4 ppg). Maintain continuous hole fill taking returns to tank until lubricator connection is reestablished. Fluids man-watch must be performed while deploying perf guns to ensure the well remains killed and there is no excess flow. 9.Pickup safety joint and TIW valve and space out before MU guns.Review well control steps with crew prior to breaking lubricator connection and commencing makeup of TCP gun string. Once the safety joint and TIW valve have been spaced out, keep the safety joint/TIW valve readily accessible near the working platform for quick deployment if necessary. 10. Break lubricator connection at QTS and begin makeup of TCP guns and blanks per schedule below.Max BHA length per PTD is 500ft. Fluids man-watch must be performed while deploying perf guns to ensure the well remains killed and there is no excess flow. a. Perforation details i.Perf Interval:The well will be perforated between the CTD whipstock and TD of the newly drilled CTD well, completely in the Prudhoe pool. ii.Perf Length:500’ iii.Gun Length:500’ iv.Weight of Guns (lbs):2300lbs (4.6ppf) 11. MU lubricator and RIH with perf gun and tie-in to coil flag correlation. Pickup and perforate perforation intervals (TBD). POOH. a. Note any tubing pressure change in WSR. 12. After perforating, PUH to top of liner or into tubing tail to ensure debris doesn’t fall in on the guns and stick the BHA.Confirm well is dead and re-kill if necessary before pulling to surface. 13. Pump pipe displacement while POOH.Stop at surface to reconfirm well dead and hole full. 14. Review well control steps with crew prior to breaking lubricator connection and commencing breakdown of TCP gun string. Standing orders flow chart included with this sundry request. Ensure safety joint and TIW valve assembly are on-hand before breaking off lubricator to LD gun BHA. 15. Freeze protect well to 2,000’ TVD. 16. RDMO CTU. Coiled Tubing BOPs Standing Orders for Open Hole Well Control during Perf Gun Deployment Equipment Layout Diagram 800120016002000240028003200South(-)/North(+) (800 usft/in)-3600 -3200 -2800 -2400 -2000 -1600 -1200 -800 West(-)/East(+) (800 usft/in)5600 60 0 0 6400 6800 72 00 7600 800084008800L2-2189 6 3L2-2 1 A8630L2-21B871018-23A18-35840018-26 C wp07 18-268400870918-31A8400870518-31PB18400869418-311 8 -2 6B 600064006800720076008000840018-26PB1840018-26C5200522818-11BPB118-18APB118-1852005600600018-11BPB2870518-27EPB118-27EPB218-27E18-27A840018-2740004400480018-10D wp0252005600600018-11C CTD Concept Lateral868518-27F wp01Top of Window - 9550'MDEnd 28 dls - 9929'MDTD - 11779'MD85008550860086508700True Vertical Depth (100 usft/in)-600 -400 -200 0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 3200 Vertical Section at 30.00° (400 usft/in)18-2718-27F wp01Top of Window - 9550'MDEnd 28 dls - 9929'MDTD - 11779'MDSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect1 9550.00 63.96 294.80 8511.56 1008.65 -2881.91 0.00 0.00 -567.442 9570.00 62.16 294.80 8520.62 1016.13 -2898.09 9.00 -180.00 -569.053 9630.00 45.36 294.80 8555.96 1036.35 -2941.86 28.00 -180.00 -573.424 9814.62 81.00 338.27 8641.13 1156.89 -3042.13 28.00 60.00 -519.175 9928.62 81.00 10.59 8658.96 1267.47 -3052.90 28.00 90.00 -428.796 10108.62 81.00 32.46 8687.12 1431.85 -2988.06 12.00 90.00 -254.017 10188.34 90.00 35.72 8693.37 1497.59 -2943.55 12.00 20.00 -174.838 10309.00 91.12 50.16 8692.18 1585.68 -2861.57 12.00 85.50 -57.559 10509.00 91.23 74.16 8688.01 1678.38 -2686.05 12.00 89.50 110.4910 10669.00 91.00 54.96 8684.87 1746.77 -2542.26 12.00 -90.50 241.6111 10829.00 90.28 35.77 8683.06 1858.65 -2428.94 12.00 -92.00 395.1612 10999.00 90.27 56.17 8682.24 1976.17 -2307.36 12.00 90.00 557.7313 11279.00 89.95 22.57 8681.70 2189.53 -2132.27 12.00 -90.50 830.0514 11419.00 89.51 39.37 8682.37 2309.14 -2060.48 12.00 91.50 969.5315 11599.00 89.55 17.77 8683.86 2466.28 -1974.91 12.00 -90.00 1148.4016 11779.00 89.58 39.37 8685.25 2623.42 -1889.34 12.00 90.00 1327.28Project: Prudhoe BaySite: 18Well: 18-27Wellbore: 18-27FPlan: 18-27F wp01WELLBORE DETAILSParent Wellbore:18-27Top of Window: 9550.0018-27F wp01Depth From Depth To Survey/Plan Tool951.91 9550.00 18-27 Srvy MWD (18-27) 3_MWD9550.00 11779.00 18-27F wp01 (18-27F) 3_MWDWELL DETAILSNorthing: 5960969.34Easting: 691522.34Lattitude: 70° 17' 52.5352 NLongitude: 148° 26' 56.0303 W18-27F wp01SECTION DETAILSHilcorp Alaska, LLCSURVEY PROGRAMNAD 1927 (NADCON CONUS)US State Plane 1927 (Exact solution)Alaska Zone 04PROJECT DETAILSREFERENCE INFORMATIONCoordinate(N/E) Reference: Well 18-27, True NorthVertical (TVD) Reference: KB @ 53.70usft (18-27E New RKB)Measured Depth Reference: KB @ 53.70usft (18-27E New RKB)Section (VS) Reference: Slot - (0.00N, 0.00E)Calculation Method: Minimum CurvatureREFERENCE INFORMATION !!" # $% & " ' % ! 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"! >$ A 678 A A )$ >$ A A A > A A A >= " " " >" " "+ "+ >" " " " >= >= A A A >$ A A+ A+ > A A+ A+ > A A+ A+ > A 678 A A >$ + + > + + > >A > $ $+ $+ >$ $ $ $ > $ $+ $+ > $ $ $ >$ $ $ $ > 3+ 3+ > > '+ '+ >$ '+ '+ >$ ' ' >$ 3 3 > > > > $ + 8 $3&26'.'* $3 )$ >$ ' 7 ' ( 3 , 0 8 , 9 + ; &'< * C $= 7, 01 % 8 #=AD /, !$D $E $#$$$$ 5%% 3- 0 5%% 3 % 3- 0 !"#$% &' () * / , 01 2 % ' Well Date Quick Test Sub to Otis -1.1 ft Top of 7" Otis 0.0 ft Distances from top of riser Excluding quick-test sub Top of Annular 2.75 ft C L Annular 3.40 ft Bottom Annular 4.75 ft CL Blind/Shears 6.09 ft CL 2-3/8" Pipe / Slips 6.95 ft B3 B4 B1 B2 Kill Line Choke Line CL 3.0" Pipe / Slip 9.54 ft CL 2-3/8" Pipe / Slips 10.40 ft TV1 TV2 T1 T2 Flow Tee Master Master LDS IA OA LDS Ground Level 3" LP hose open ended to Flowline CDR2-AC BOP Schematic CDR2 Rig's Drip Pan Fill Line from HF2 Normally Disconnected 3" HP hose to Micromotion Hydril 7 1/16" Annular Blind/Shear 2-3/8" Pipe/Slips 2 3/8" Pipe/Slips 2 3/8" Pipe/Slips 7-1/16" 5k Mud Cross 2-3/8" Pipe/Slips 3-1/8" Pipe / Slip Well Date Quick Test Sub to Otis Top of 7" Otis Top of Annular C L Annular Bottom Annular CL Blind/Shears CL 2-3/8" Pipe / Slips B6 B5 B8 B7 Choke Line Kill Line CL 3" Pipe / Slip CL 2-3/8" Pipe / Slips TV1 TV2 T1 T2 Flow Tee Master Master LDS IA OA LDS Ground Level CDR3-AC BOP Schematic CDR3 Rig's Drip Pan Fill Line Normally Disconnected 2" HP hose to Micromotion Hydril 7 1/16" Annular Blind/Shear 2-3/8" Pipe/Slips 2 3/8" Pipe/Slips 2 3/8" Pipe/Slips 7-1/16" 5k Mud Cross 2-3/8" Pipe/Slips 3" Pipe / Slip neceeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeee 1 Dewhurst, Andrew D (OGC) From:Dewhurst, Andrew D (OGC) Sent:Thursday, 24 April, 2025 17:07 To:Christopher Clinkscales; Trevor Hyatt Cc:Lau, Jack J (OGC); Joseph Lastufka; Tanner Gansert; Michael Schoetz Subject:RE: [EXTERNAL] PBU 18-27F PTD (225-030): Question Chris, Thank you for clarifying this. I was not aware of the Northern Lobe; we will get the PTD to you shortly. Andy From: Christopher Clinkscales <Christopher.Clinkscales@hilcorp.com> Sent: Thursday, 24 April, 2025 16:38 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Trevor Hyatt <Trevor.Hyatt@hilcorp.com> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Tanner Gansert <Tanner.Gansert@hilcorp.com>; Michael Schoetz <mschoetz@hilcorp.com> Subject: RE: [EXTERNAL] PBU 18-27F PTD (225-030): Question Hi Andy, Please refer to #2 from the Pool DeƱnition (from the latest CO 341J). There it states that in the NGI-01 well that the interval starting at 9638 MD, which includes the Put River Formation (seen in the log below between the BHRZ and LCU picks), is included in the POP. You are correct that it is not referred to in Prudhoe Bay State 1, but it is referenced for NGI-01. CO 341J 2 Also, in earlier conservation orders (for example, CO 341G), the rule explicitly mentioned that the Put River of the Northern Lobe (as seen at DS-18) is part of the POP as well. From earlier CO 341G: 3 Thanks, Chris From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Thursday, April 24, 2025 3:12 PM To: Christopher Clinkscales <Christopher.Clinkscales@hilcorp.com>; Trevor Hyatt <Trevor.Hyatt@hilcorp.com> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: [EXTERNAL] PBU 18-27F PTD (225-030): Question Chris, Thanks for the info. Yes, the Prudhoe Oil Pool is deĮned from the one type-log at Prudhoe Bay St 1. You can see the details and the exact depths in ConservaƟon Order 341J. The Put River is not part of the pool. Although it isn’t very parƟcularly consequenƟal here, the exact pick of the Sag River (to deĮne the top of the pool) should be correla Ɵve to how it was picked in the order. Andy From: Christopher Clinkscales <Christopher.Clinkscales@hilcorp.com > Sent: Thursday, 24 April, 2025 13:32 To: Trevor Hyatt <Trevor.Hyatt@hilcorp.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: [EXTERNAL] PBU 18-27F PTD (225-030): Question Hi Andy, My understanding is at DS-18 the top of the Prudhoe Oil Pool is at the top of the Put River Formation because in the northern part of the drill site, the Put River rests unconformably on the Sag (separated by the LCU). Since there is a distinctive Put section here, I used its top for the pool reference. If that’s a mistake, please let me know and we can change to Top Sag. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN send ers. 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 If we need to shift, will probably adjust to 8980 MD (see top of resistivity bump and thin uppermost Sag). 5 Thanks, Chris From: Trevor Hyatt <Trevor.Hyatt@hilcorp.com> Sent: Thursday, April 24, 2025 1:21 PM To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Christopher Clinkscales <Christopher.Clinkscales@hilcorp.com> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: [EXTERNAL] PBU 18-27F PTD (225-030): Question Chris, Can you help Andrew on this question? Trevor Hyatt Hilcorp Alaska, LLC Drilling Engineer Trevor.Hyatt@hilcorp.com Cell: 907-223-3087 From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Wednesday, April 23, 2025 5:46 PM To: Trevor Hyatt <Trevor.Hyatt@hilcorp.com> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: [EXTERNAL] PBU 18-27F PTD (225-030): Question 6 Trevor, I’m compleƟng my review of the PBU 18-27F PTD and have one quesƟon: x Would you conĮrm the depth of the top of the Prudhoe Oil Pool? I see a Sag River top from the original parent (50-029-22321-00-00) at 8,988’ MD. Where does 8,670’ MD depth come from? Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas ConservaƟon Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. 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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. PRUDHOE OIL PBU 14-18C 225-040 PRUDHOE BAY WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UNIT 18-27FInitial Class/TypeDEV / PENDGeoArea890Unit11650On/Off ShoreOnProgramDEVWell bore segAnnular DisposalPTD#:2250300Field & Pool:PRUDHOE BAY, PRUDHOE OIL - 640150NA1Permit fee attachedYesADL0283072Lease number appropriateYes3Unique well name and numberYesPRUDHOE BAY, PRUDHOE OIL - 640150 - governed by CO 341J4Well located in a defined poolYes5Well located proper distance from drilling unit boundaryNA6Well located proper distance from other wellsYes7Sufficient acreage available in drilling unitYes8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceYes11Permit can be issued without conservation orderYes12Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitNA14Well located within area and strata authorized by Injection Order # (put IO# in comments) (For NA15All wells within 1/4 mile area of review identified (For service well only)NA16Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18Conductor string providedYes19Surface casing protects all known USDWsYes20CMT vol adequate to circulate on conductor & surf csgYes21CMT vol adequate to tie-in long string to surf csgYes22CMT will cover all known productive horizonsYes23Casing designs adequate for C, T, B & permafrostYes24Adequate tankage or reserve pitYesAlternative plug placement approved with fully cemented liner.25If a re-drill, has a 10-403 for abandonment been approvedYes26Adequate wellbore separation proposedNA27If diverter required, does it meet regulationsYes28Drilling fluid program schematic & equip list adequateYesVariance approved with well control drills29BOPEs, do they meet regulationYes5000 psi30BOPE press rating appropriate; test to (put psig in comments)Yes31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownYesDS 18 is an H2S pad. The last H2S reading on 18-27E: 20 ppm on 6/1/202233Is presence of H2S gas probableNA34Mechanical condition of wells within AOR verified (For service well only)NoDS 18 wells are H2S-bearing. H2S measures are required.35Permit can be issued w/o hydrogen sulfide measuresYesExpected reservoir pressure gradient is 7.3 ppg EMW. MPD to maintain an ECD of 9.8 ppg EMW.36Data presented on potential overpressure zonesNA37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprADDDate23-Apr-25ApprJJLDate08-Apr-25ApprADDDate23-Apr-25AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 4/25/2025