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224-011
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: 6/18/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250618 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# AN 07RD2 50733200120200 195113 6/1/2025 AK E-LINE LDL AN 24RD 50733202850100 207170 6/1/2025 AK E-LINE LDL BRU 221-24 50283202020000 225027 5/29/2025 AK E-LINE CBL KALOTSA 10 50133207320000 224147 5/21/2025 AK E-LINE Perf KALOTSA 2 50133206590000 216155 5/25/2025 AK E-LINE Perf PAXTON 11 50133207040000 221114 5/27/2025 AK E-LINE Perf PAXTON 11 50133207040000 221114 5/26/2025 AK E-LINE Perf PBU 06-12C 50029204560300 225022 5/17/2025 HALLIBURTON RBT-COILFLAG PBU 15-32C 50029224620300 217104 5/27/2025 HALLIBURTON RBT PBU D-01B 50029200540200 224155 5/18/2025 BAKER MRPM PBU D-01B 50029200540200 224155 5/18/2025 HALLIBURTON RBT-COILFLAG PBU H-18A 50029208800100 224011 5/14/2025 BAKER MRPM PBU H-18A 50029208800100 224011 5/14/2025 HALLIBURTON RBT-COILFLAG PBU L-109 50029230460000 201201 5/24/2025 HALLIBURTON IPROF PBU L-115 50029230350000 201140 5/19/2025 HALLIBURTON IPROF PBU L-117 50029230390000 201167 5/30/2025 HALLIBURTON IPROF PBU N-07B 50029201370200 223122 6/7/2025 HALLIBURTON RBT PBU S-100A 50029229620100 224083 5/26/2025 HALLIBURTON PPROF-LDL PBU Z-34 50029234690000 212061 5/17/2025 HALLIBURTON IPROF-LDL Please include current contact information if different from above. T40566 T40567 T40568 T40569 T40570 T40571 T40571 T40572 T40573 T40574 T40574 T40575 T40575 T40576 T40577 T40578 T40579 T40580 T40581 PBU H-18A 50029208800100 224011 5/14/2025 BAKER MRPM PBU H-18A 50029208800100 224011 5/14/2025 HALLIBURTON RBT-COILFLAG Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.06.18 12:03:53 -08'00' David 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: 06/03/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: PBU H-18A PTD: 224-011 API: 50-029-20880-01-00 FINAL LWD FORMATION EVALUATION LOGS (04/28/2025 to 05/07/2025) 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. 224-011 T40524 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.06.04 08:06:33 -08'00' 325-063 By Gavin Gluyas at 12:22 pm, Feb 07, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.02.07 12:05:17 - 09'00' Sean McLaughlin (4311) JJL 2/24/25 10-407 *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. *Window milling on service coil not approved on 10-403, refer to sidetrack PTD for approval. A.Dewhurst 20FEB25 DSR-2/18/25*&: 2/25/2025 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.02.25 13:57:37 -09'00' RBDMS JSB 022625 To: Alaska Oil & Gas Conservation Commission From: Trevor Hyatt Drilling Engineer Date: February 7, 2025 Re:H-18A SUNDRY Change to approved program – updated service coil window milling procedure This sundry (change to approved program) is to update the H-18A plan with the new service coil window milling procedure. Approval is requested for drilling a CTD sidetrack lateral from well H-18 with the Nabors CDR2 Coiled Tubing Drilling Rig. Proposed plan for H-18A Producer: See H-18 Sundry request for complete pre-rig details - Prior to drilling activities, screening will be conducted to drift, caliper for whipstock and MIT. E-line will set the 4-1/2" x 7" CTD whipstock. Service coil will cement squeeze the whipstock in place, mill XN-nipple and mill the 3.80' window. If unable to set the whipstock or mill the window, for scheduling reasons, the rig will perform that work. A coil tubing drilling sidetrack will be drilled with the Nabors CDR2 rig. The rig will move in, test BOPE and kill the well. If unable to set whipstock pre-rig, the rig will set the 4-1/2" x 7" whipstock. A single string 3.80" window + 10' of formation will be milled. The well will kick off drilling in the Sag/Shublik and land in Ivishak Zone 2. The lateral will continue in Zone 2 to TD. The proposed sidetrack will be completed with a 3-1/2" x 3-1/4" x 2-7/8” 13Cr solid liner, cemented in place and selectively perforated post rig (will be perferated with rig if unable to post rig). This completion will completely isolate and abandon the parent Ivishak perfs. The well will be perforated post rig as part of this PTD. The following describes the work planned. A wellbore schematic of the current well and proposed sidetrack is attached for reference. Pre-Rig Work: (Estimated to start in March 1st, 2024) x Reference H-18 Sundry submitted in concert with this request for full details. 1. E-Line : Set Whipstock 2. Coil : Squeeze cement through WS, Mill XN, mill window – see attached procedure 3. Valve Shop : Pre-CTD Tree Work 4. Operations : Remove wellhouse and level pad. Rig Work: (Estimated to start in May 2024) 1. MIRU and test BOPE 250 psi low and 3,500 psi high (MASP 2,506 psi). Give AOGCC 24hr notice prior to BOPE test. 2. Mill 3.80” Window (if not done pre-rig) 3. Drill build section: 4.25" OH, ~1045' (22 deg DLS planned). 4. Drill production lateral: 4.25" OH, ~1500' (12 deg DLS planned). Swap to KWF if necessary. 5. Run 3-1/2” x 3-1/4” x 2-7/8” 13Cr liner (swap to VBRs and test prior to running liner) 6. Pump primary cement job: 41 bbls, 15.3 ppg Class G, TOC at TOL*. 7. Freeze protect well to a min 2,200' TVD. 8. Close in tree, RDMO. Post Rig Work: 1. Valve Shop : Valve & tree work 2. Coil : RPM, ~100' of i-perfs – See perf procedure attached 3. Slickline : SBHPS, set LTP (if necessary). Set live GLVs. 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” (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 (9036' MD -8,546' TVD) Pumps On Pumps Off A Target BHP at Window (ppg)4,355 psi 4,355 psi 9.8 B Annular friction - ECD (psi/ft)542 psi 0 psi 0.09 C Mud Hydrostatic (ppg)3,822 psi 3,822 psi 8.6 B+C Mud + ECD Combined 4,364 psi 3,822 psi (no choke pressure) A-(B+C)Choke Pressure Required to Maintain -9 psi 533 psi Target BHP at window and deeper Operation Details: Reservoir Pressure: x The estimated reservoir pressure is expected to be 3,386 psi at 8,800 TVD. (7.4 ppg equivalent). x Maximum expected surface pressure with gas (0.10 psi/ft) to surface is 2,506 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: 8,700' MD – 9,021' MD (321' liner) x 3-1/4", 6.6#, 13Cr Solid: 9,021' MD – 9,231' MD (210' liner) x 2-7/8", 6.5#, 13Cr Solid: 9,231' MD – 11,581' MD (2,350' 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” pipe/slip rams (for drilling) to 2-3/8” x 3-1/2” VBR rams for 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 93°. Inclination at kick off point is 20°. x Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. x Distance to nearest property line – 24,723 ft x Distance to nearest well within pool – 862 ft Logging: x MWD directional and Gamma Ray will be run through the entire open hole section. x Real time bore pressure to aid in MPD and ECD management. Perforating: x 100' perforated post rig – See attached perf procedure x 2.5" 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 8,994’ MD. Anti-Collision Failures: x All well pass collision risk criteria Hazards: x H is not an H2S pad. H2S reading on H-18: 15 ppm on 10/05/2021. x Max H2S recorded on H Pad: 64 ppm. x 1 fault crossings expected. x Medium lost circulation risk. Trevor Hyatt CC: Well File Drilling Engineer (907-223-3087) Joseph Lastufka Pre-Rig – Service Coil – Window Milling The approved sundry and permit to drill will be posted in the Operations Cabin of the unit during the entire window milling operation. Notes for window milling: x Window milling with service CTU operations will fully comply with 20 AAC 25.286(d)(3), including the use of pressure control equipment, all BHAs fully lubricated and at no point will any BHA be open-hole deployed. Window Milling Procedure: 1. Kill well with 1% KCL if necessary. Well may already be killed from previous operations. 2. MU and RIH with window milling assembly – Window mill followed by string reamer. NOTE: Confirm milling BHA configuration prior to job execution due to variations in different service provider’s window milling BHAs. 3. RIH & TAG whipstock pinch point, calculate distance till string reamer is out of the window, paint coil flag and note in WSR. 4. Mill window per vendor procedure. – Make note of any WHP changes while milling window in the WSR. 5. Make multiple reciprocating passes through the kickoff point to dress liner exit and eliminate all burs. Perform gel sweeps as necessary to keep window clean. Maximum approved distance to reciprocate beyond the window is 15 ft to ensure confidence the window is prepared for the sidetrack.DO NOT RECIPROCATE DEEPER than 15 ft. 6. Confirm exited liner & string reamer dressed entire window with coil flag and note bottom of window and total milled depth in WSR. 7. FP well to 2,500’ TVD with 60/40 MeOH while POOH. 8. Once on surface inspect BHA, measure OD of mill and string reamer & document in WSR. 9. RDMO 10. Communicate to Operations to tag wing valve “Do Not POP”. Pre-Rig – Service Coil – Window Milling – BOP Diagram 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 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"or 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 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Monty M. Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov Re: Prudhoe Bay Field, Prudhoe Oil Pool, PBU H-18A Hilcorp Alaska, LLC Permit to Drill Number: 224-011 Surface Location: 700' FNL, 1735' FEL, Sec 21, T11N, R13E, UM, AK Bottomhole Location: 1599' FSL, 347' FEL, Secl6, T11N, R13E, UM, 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, Digitally signed by Brett W. Huber, Brett W. Huber, Sr. Sr. Date: 2024.05.01 11:08:30-08'00' Brett W. Huber, Sr. Chair, Commissioner DATED this 01 day of May 2024. 3-1/2"x3-1/4" Drilling Manager 02/13/24 Monty M Myers By Kayla Junke at 4:08 pm, Feb 14, 2024 224-011 DSR-2/14/24A.Dewhurst 01MAR24 50-029-20880-01-00 * BOPE test to 3500 psi. * Variance to 20 AAC 25.112(i) for alternate plug placement with fully cemented line. * Post rig perf gun length not to exceed 500' MD. MGR08MAR2024*&:JLC 5/1/2024 Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr. Date: 2024.05.01 11:00:18 -08'00'05/01/24 05/01/24 RBDMS JSB 050124 To: Alaska Oil & Gas Conservation Commission From: Ryan Ciolkosz Drilling Engineer Date: February 13, 2024 Re:H-18A Permit to Drill Approval is requested for drilling a CTD sidetrack lateral from well H-18 with the Nabors CDR2 Coiled Tubing Drilling Rig. Proposed plan for H-18A Producer: See H-18 Sundry request for complete pre-rig details - Prior to drilling activities, screening will be conducted to drift, caliper for whipstock and MIT. E-line will set the 4-1/2" x 7" CTD whipstock. Service coil will cement squeeze the whipstock in place, mill XN-nipple and mill the 3.80' window. If unable to set the whipstock or milling the window, for scheduling reasons, the rig will perform that work. A coil tubing drilling sidetrack will be drilled with the Nabors CDR2 rig. The rig will move in, test BOPE and kill the well. If unable to set whipstock pre-rig, the rig will set the 4-1/2" x 7" whipstock. A single string 3.80" window + 10' of formation will be milled. The well will kick off drilling in the Sag/Shublik and land in Ivishak Zone 2. The lateral will continue in Zone 2 to TD. The proposed sidetrack will be completed with a 3-1/2" x 3-1/4" x 2-7/8” 13Cr solid liner, cemented in place and selectively perforated post rig (will be perferated with rig if unable to post rig). This completion will completely isolate and abandon the parent Ivishak perfs. The well will be perforated post rig as part of this PTD. The following describes the work planned. A wellbore schematic of the current well and proposed sidetrack is attached for reference. Pre-Rig Work: (Estimated to start in March 1st, 2024) x Reference H-18 Sundry submitted in concert with this request for full details. 1. E-Line : Set Whipstock 2. Coil : Squeeze cement through WS, Mill XN, mill window 3. Valve Shop : Pre-CTD Tree Work 4. Operations : Remove wellhouse and level pad. Rig Work: (Estimated to start in May 2024) 1. MIRU and test BOPE 250 psi low and 3,500 psi high (MASP 2,506 psi). Give AOGCC 24hr notice prior to BOPE test. 2. Mill 3.80” Window if not done pre-rig 3. Drill build section: 4.25" OH, ~1045' (22 deg DLS planned). 4. Drill production lateral: 4.25" OH, ~1500' (12 deg DLS planned). Swap to KWF if necessary. 5. Run 3-1/2” x 3-1/4” x 2-7/8” 13Cr liner (swap to VBRs and test prior to running liner) 6. Pump primary cement job: 41 bbls, 15.3 ppg Class G, TOC at TOL*. 7. Freeze protect well to a min 2,200' TVD. 8. Close in tree, RDMO. * Approved alternate plug placement per 20 AAC 25.112(i) Post Rig Work: 1.Valve Shop : Valve & tree work 2.Coil : RPM, ~100' of i-perfs – See perf procedure attached 3. Slickline : SBHPS, set LTP (if necessary). Set live GLVs. PTD 224-011 Sundry 324-082 41 bbls, 15.3 ppg Class G, TOC at TOL* 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” (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 (9036' MD -8,546' TVD) Pumps On Pumps Off A Target BHP at Window (ppg)4,355 psi 4,355 psi 9.8 B Annular friction - ECD (psi/ft)542 psi 0 psi 0.09 C Mud Hydrostatic (ppg)3,822 psi 3,822 psi 8.6 B+C Mud + ECD Combined 4,364 psi 3,822 psi (no choke pressure) A-(B+C)Choke Pressure Required to Maintain -9 psi 533 psi Target BHP at window and deeper Operation Details: Reservoir Pressure: x The estimated reservoir pressure is expected to be 3,386 psi at 8,800 TVD. (7.4 ppg equivalent). x Maximum expected surface pressure with gas (0.10 psi/ft) to surface is 2,506 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: 8,700' MD – 9,021' MD (321' liner) x 3-1/4", 6.6#, 13Cr Solid: 9,021' MD – 9,231' MD (210' liner) x 2-7/8", 6.5#, 13Cr Solid: 9,231' MD – 11,581' MD (2,350' liner) r pressure is expected to be 3,386 psi at 8,800 TVD. (7.4 ppg equivalent). 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” pipe/slip rams (for drilling) to 2-3/8” x 3-1/2” VBR rams for 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 93°. Inclination at kick off point is 20°. x Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. x Distance to nearest property line – 24,723 ft x Distance to nearest well within pool – 862 ft Logging: x MWD directional and Gamma Ray will be run through the entire open hole section. x Real time bore pressure to aid in MPD and ECD management. Perforating: x 100' perforated post rig – See attached perf procedure x 2.5" 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 Ivishak pool. Anti-Collision Failures: x All well pass collision risk criteria Hazards: x H is not an H2S pad. H2S reading on H-18: 15 ppm on 10/05/2021. x Max H2S recorded on H Pad: 64 ppm. x 1 fault crossings expected. x Medium lost circulation risk. Ryan Ciolkosz CC: Well File Drilling Engineer (907-244-4357) Joseph Lastufka 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 Kuparuk 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 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 2.0" Pipe / Slips 6.95 ft B3 B4 B1 B2 Kill Line Choke Line CL 2-3/8" Pipe / Slip 9.54 ft CL 2.0" 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 3.0" Pipe / Slip HF nneceeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeee $) $) $) $) $) $) $) $) $) $) $) $) $) ! !!!! !!!! ! !!!! !!! ! !! ! ! !!!! !! ! !!!!!!! ! ! !! !!!! !! !!! !! !!!! !!! !! ! ! !! !! ! ! ! D $) Prudhoe Bay Unit ADL28284 H-02 H-08 H-13 H-14 H-14A H-16B H-18 H-19B H-20 H-29A H-35 H-35A Q-02A Sec. 21 Sec. 15 Sec. 22 Sec. 16 U011N013E H PAD PLAN: H-18A_SHL PLAN: H-18A_TPH PLAN: H-18A_BHL Map Date: 1/9/2024 Prudhoe Bay Unit H-18A Well wp03 E0 570 1,140Feet Legend H_18A_wp03 $)PLAN: H-18A_BHL !PLAN: H-18A_SHL D PLAN: H-18A_TPH $)Other Bottom Holes (BHL) Other Well Paths Pad Footprint Oil and Gas Unit Boundary CO - 341J AIO_3C Well located within PA - IPA Document Path: O:\AWS\GIS\Products\Alaska\KEN\Wells\TRS_Distance\mxd\2024\NorthSlope_PBU_H-18A_wp03.mxd 8500 8600 8700 8800 8900 9000True Vertical Depth (200 usft/in)-800-700-600-500-400-300-200-100010020030040050060070080090010001100Vertical Section at 320.00° (200 usft/in) H-18 H-18A wp03 Top of Window - 9036'MD End 22dls -10076'MD TD - 11581'MD LockUp with 500ft Agitator Drilling - 11581'MD 900 1200 1500 1800 2100 2400 2700 South(-)/North(+) (600 usft/in)90012001500180021002400270030003300West(-)/East(+) (600 usft/in) 5 2 0 0 5 6 0 0 6 0 0 0 6 4 0 0 6 8 0 0 7 2 0 0 7 6 0 0H- 1 9 3600 4000 4400 4800 5200 5600 6000 6400 6800 7200 7600 8000 84 0 0 H-408952 H-29A 6 0 0 0 6 4 0 0 680 07200760080008400880092009269H-188765H-14APB36000 6400 6800 720 0 7 6 0 0 8 0 0 0 8 4 0 0 8 8 0 0 H-1 4 9067H-14A72007600 8000 8400 88 00H-17A8800H- 1 7B wp0 4 640068007200H-178 8 0 0 9004H-14APB464 0 0 6 8 0 0 7 2 0 0 7 6 0 0 8 0 0 0 8 4008800H -1 4 B 8800H-14APB188008811H-14APB2 4 4 0 0 4 8 0 0 5 2 0 0 5 6 0 0 6 0 00 H-04PB188008928H-18A wp03 Top of Window - 9036'MD End 22dls -10076'MD TD - 11581'MD LockUp with 500ft Agitator Drilling - 11581'MD Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect 1 9036.00 19.65 89.78 8546.96 1155.92 2069.00 0.00 0.00 -444.44 2 9056.00 21.45 89.78 8565.68 1155.95 2076.02 9.00 0.00 -448.93 3 9126.00 36.85 89.78 8626.64 1156.08 2110.01 22.00 0.00 -470.69 4 9282.33 70.00 101.65 8718.70 1140.97 2232.53 22.00 20.00 -561.01 5 9362.33 70.00 120.38 8746.06 1114.13 2302.39 22.00 90.00 -626.47 6 9456.09 51.50 109.83 8791.77 1079.03 2375.71 22.00 -156.00 -700.49 7 9881.48 86.00 12.02 8983.72 1275.97 2637.46 22.00 -98.00 -717.88 8 9981.48 86.29 349.97 8990.53 1375.11 2639.18 22.00 -90.00 -643.04 9 10081.48 86.56 327.93 8996.84 1467.68 2603.56 22.00 -90.00 -549.23 10 10201.00 90.34 314.09 9000.08 1560.29 2528.57 12.00 -75.00 -430.08 11 10311.00 91.58 300.95 8998.23 1627.12 2441.53 12.00 -84.50 -322.94 12 10431.00 91.53 286.54 8994.95 1675.29 2332.02 12.00 -90.00 -215.64 13 10551.00 93.72 300.79 8989.43 1723.27 2222.51 12.00 81.00 -108.50 14 10701.00 93.53 318.82 8979.87 1818.71 2107.99 12.00 90.00 38.23 15 10941.00 93.10 289.98 8965.69 1952.64 1912.38 12.00 -90.00 266.55 16 11181.00 93.19 318.82 8952.23 2086.59 1716.75 12.00 89.00 494.92 17 11421.00 93.52 289.97 8937.87 2220.52 1521.16 12.00 -88.50 723.23 18 11581.00 93.65 309.21 8927.76 2299.00 1382.96 12.00 89.00 872.19 Project: Prudhoe Bay Site: H Well: H-18 Wellbore: PLAN: H-18A Plan: H-18A wp03 WELLBORE DETAILS Parent Wellbore:H-18Top of Window: 9036.00 H-18A wp03 Depth From Depth To Survey/Plan Tool 100.00 9036.00 H-18 Srvy 1 BOSS-GYRO (H-18) 3_Gyro-SR-GMS1 9036.00 11581.00 H-18A wp03 (PLAN: H-18A) 3_MWD WELL DETAILS Northing: 5960079.00Easting: 642841.00Lattitude: 70° 17' 54.4321 NLongitude: 148° 50' 35.4369 W H-18A wp03 SECTION DETAILS Hilcorp Alaska, LLC SURVEY PROGRAM NAD 1927 (NADCON CONUS) US State Plane 1927 (Exact solution) Alaska Zone 04 PROJECT DETAILS REFERENCE INFORMATION Coordinate(N/E) Reference: Well H-18, True North Vertical (TVD) Reference: H-18 @ 80.35usft (generic rig) Measured Depth Reference: H-18 @ 80.35usft (generic rig) Section (VS) Reference: Slot - (0.00N, 0.00E) Calculation Method: Minimum Curvature REFERENCE INFORMATION !""# $ % " & ' # ( " # ) *+, ) - - .# /$ !!" # $%&' ()**+ , 0 ,$& , -. / 0- /, ) # $%&' ()**+ & $ ) 1 0 / ( 1 ,( ' / 2 (,(2 345)-6 + . 345) .7 7 2+ 2 80-.0 0- 9$: " 2 *1( 2 ** ( ( " " 0 3 & $ 0 4 0 1 # .0 0 & ( ( ( ; %$ <$ ' 3'5 '54%4' =: &==%$5 $%$$ 5$; 5>&$%$'' : ;' > 3% $441 - - " 0 " 4 0 & $ 0 ( 546- 5&6 3 ( ( (1 ". 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"# #$ * & +# 6 ! / Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME:______________________________________ PTD:_____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD:__________________________POOL:____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in nogreater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. 224-011 PRUDHOE BAY X PRUDHOE OIL POOL PBU H-18A WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UNIT H-18AInitial Class/TypeDEV / PENDGeoArea890Unit11650On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2240110PRUDHOE BAY, PRUDHOE OIL - 640150NA1 Permit fee attachedYes ADL0282842 Lease number appropriateYes3 Unique well name and numberYes PRUDHOE BAY, PRUDHOE OIL - 640150 - governed by 341J4 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)Yes This well is a in zone CTD sidetrack from an existing wellbore with pressure integrity.18 Conductor string providedYes All drilling on this sidetrack will below existing surface casing shoe.19 Surface casing protects all known USDWsYes This well is a in zone CTD sidetrack from an existing wellbore with pressure integrity.20 CMT vol adequate to circulate on conductor & surf csgYes This well is a in zone CTD sidetrack from an existing wellbore with pressure integrity.21 CMT vol adequate to tie-in long string to surf csgYes Fully cemented production liner. Parent well isolates the reservoir.22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes CDR2 has adequate tankage and good trucking support.24 Adequate tankage or reserve pitYes Sundry 324-08225 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan identifies no close approaches with HSE risk26 Adequate wellbore separation proposedNA All drilling below the surface casing shoe. No diverter required.27 If diverter required, does it meet regulationsYes MPD but reservoir pressure below water gradient.28 Drilling fluid program schematic & equip list adequateYes CT Packoff, flow cross, annular, blind shear, CT pipe slips, flow cross, BHA pipe slips, CT pipe slips29 BOPEs, do they meet regulationYes 7-1/16" 5000 psi stack pressure tested to 3500 psi.30 BOPE press rating appropriate; test to (put psig in comments)Yes Flanged choke and kill lines between dual combi's w remote choke31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownYes PBU H pad has no high H2S events. Monitoring still required.33 Is presence of H2S gas probableNA This is a development well.34 Mechanical condition of wells within AOR verified (For service well only)No H-Pad wells are H2S-bearing. H2S measures are required. Max reading at H-pad: 64 ppm.35 Permit can be issued w/o hydrogen sulfide measuresYes Pore pressure anticipated to be 7.4 ppg EMW. MPD to be utilized for ECD of 9.8 ppg EMW.36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate3/1/2024ApprMGRDate3/8/2024ApprADDDate3/1/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateOne fault crossing expected with medium lost circulation risk.*&:JLC 5/1/2024
