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Home My WebLink About224-132By Grace Christianson at 11:39 am, Jan 22, 2025 325-024 Digitally signed by Ryan Ciolkosz (10728) DN: cn=Ryan Ciolkosz (10728) Reason: Signing For Sean Mclaughlin Date: 2025.01.22 10:25:19 -09'00' Ryan Ciolkosz (10728) Window milling with service coil is approved to be done under PTD 224-132. Variance as per 20 AAC 25.112(i): Approved for alternate abandonment plug placement on parent well with fully cemented liner on upcoming sidetrack. SFD 1/24/2025 10-407 JJL 1/27/25 X DSR-1/31/25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.02.03 08:47:52 -09'00' 02/03/25 RBDMS JSB 020425 To: Alaska Oil & Gas Conservation Commission From: Ryan Ciolkosz Drilling Engineer Date: January 21, 2025 Re:D-21A Permit to Drill Approval is requested for drilling a CTD sidetrack lateral from well D-21 with the Nabors CDR2/CDR3 Coiled Tubing Drilling. Proposed plan for D-21A Producer: See D-21 Sundry request for complete pre-rig details - Prior to drilling activities, screening will be conducted to drift for whipstock, caliper, and MIT. E-line or coil will mill the XN-nipple. E-line will set a 4-1/2"x7" whipstock. Coil will mill window pre-rig. 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/CDR3 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"x7" whipstock. A single string 3.80" window + 10' of formation will be milled. The well will kick off drilling in the Shublik and land in Ivishak Zone 2. The lateral will continue in Zone 4, 3 and 2 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 completely isolate and abandon the parent Ivishak perfs. 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 D-21 Sundry submitted in concert with this request for full details. 1. Slickline : DMY GLVs, MIT, Drift, Caliper 2. E-Line : Set Whipstock 3. Fullbore : MIT-IA or MIT-T 4. Coil : Mill XN nipple and Window (if window not possible, mill with rig) 5. Valve Shop : Pre-CTD Tree Work 6. Operations : Remove wellhouse and level pad. Rig Work: (Estimated to start in December 2024) 1. MIRU and test BOPE 250 psi low and 3,500 psi high (MASP 2,433 psi). Give AOGCC 24hr notice prior to BOPE test. 2. Mill 3.80” Window. 3. Drill build section: 4.25" OH, ~870' (18 deg DLS planned). 4. Drill production lateral: 4.25" OH, ~1435' (12 deg DLS planned). Swap to KWF for liner. 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: 47 bbls, 15.3 ppg Class G, TOC at TOL*. 7. Only if not able to do with service coil extended perf post rig – Perforate Liner 8. Freeze protect well to a min 2,200' TVD. 9. Close in tree, RDMO. * Approved alternate plug placement per 20 AAC 25.112(i) Post Rig Work: 1. Valve Shop : Valve & tree work 2. Slickline : SBHPS, set LTP* (if necessary), set Live GLV's, 3. Service Coil : Post rig perforate (~20’) and RPM. ,p yppg(p This completion will completely isolate and abandon the parent Ivishak perfs. 4. Well Testers : Well Test 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 (9965' MD -8,497' TVD) Pumps On Pumps Oī A Target BHP at Window (ppg)4,330 psi 4,330 psi 9.8 B ŶŶƵůĂƌĨƌŝĐƟŽŶ- ECD ;ƉƐŝͬŌͿ 598 psi 0 psi 0.09 C DƵĚ,ǇĚƌŽƐƚĂƟĐ;ƉƉŐͿ 3,800 psi 3,800 psi 8.6 B+C Mud + ECD Combined 4,398 psi 3,800 psi (no choke pressure) A-(B+C)Choke Pressure Required to Maintain -68 psi 530 psi Target BHP at window and deeper Operation Details: Reservoir Pressure: x The estimated reservoir pressure is expected to be 3,313 psi at 8,800 TVD. (7.2 ppg equivalent). x Maximum expected surface pressure with gas (0.10 psi/ft) to surface is 2,433 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: 7,700' MD – 10,540' MD (2,840' liner) x 3-1/4", 6.6#, 13Cr Solid: 10,540' MD – 10,750' MD (210' liner) x 2-7/8", 6.5#, 13Cr Solid: 10,750' MD – 12,855' MD (2,105' 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 114°. Inclination at kick off point is 31°. x Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. x Distance to nearest property line – 24,772 ft x Distance to nearest well within pool – 850 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 Estimated 20'' perforated post rig – See attached extended perforating procedure. x 2.0" 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. x Formations: Top of Ivishak Pool: 10,504’ MD in the parent Anti-Collision Failures: x No Anti-collision failures with D-21A WP 03 Hazards: x DS/Pad is not an H2S pad. The last H2S reading on D-21: 22 ppm on 09/01/2024. x Max H2S recorded on DS/Pad: 34 ppm.. x No fault crossings expected. x Low lost circulation risk. Ryan Ciolkosz CC: Well File Drilling Engineer Joseph Lastufka (907-244-4357) 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 Ivishak 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 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 Field, Prudhoe Oil Pool, PBU D-21A Hilcorp Alaska, LLC Permit to Drill Number: 224-132 Surface Location: 1660’ FNL, 1692’ FEL, Sec 23, T11N, R13E, UM, AK Bottomhole Location: 1730' FNL, 2368' FWL, Sec 25, 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 AOGCCreserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCCspecifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCCorder, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski Commissioner DATED this 1th day of December2024. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.12.18 08:19:31 -09'00' 3-1/2"x3-1/4" 10605, 10630, 10934, 10950 Rig Asset Manager 10/15/24 Monty M Myers By Grace Christianson at 1:36 pm, Oct 15, 2024 *BOPE test to 3500 psi. 24-hr notice to AOGCC. *Variance to 20 AAC 25.112(i). Approved for alternate abandonment plug placement on parent well with fully cemented liner on upcoming sidetrack. *Approved for post rig perforating with service coil. Length of BHA not to exceed 500-ft per run. *Parent well D-21 to remain as a development oil well until completion of D-21A drilling ops and isolation of existing perforations with liner cement job, at which time D-21 will be considered abandoned. *The service coil milling step will require a 10-403 Change of Approved Program to this PTD. A.Dewhurst 28OCT24 50-029-20788-01-00224-132 WCB 12-17-2024 DSR-10/23/24*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.12.18 08:19:46 -09'00' 12/18/24 12/18/24 RBDMS JSB 121924 To: Alaska Oil & Gas Conservation Commission From: Ryan Ciolkosz Drilling Engineer Date: October 14, 2024 Re:D-21A Permit to Drill Approval is requested for drilling a CTD sidetrack lateral from well D-21 with the Nabors CDR2/CDR3 Coiled Tubing Drilling. Proposed plan for D-21A Producer: See D-21 Sundry request for complete pre-rig details - Prior to drilling activities, screening will be conducted to drift for whipstock, caliper, and MIT. E-line or coil will mill the XN-nipple. E-line will set a 4-1/2"x7" whipstock. Coil will mill window pre-rig. 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/CDR3 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"x7" whipstock. A single string 3.80" window + 10' of formation will be milled. The well will kick off drilling in the Shublik and land in Ivishak Zone 2. The lateral will continue in Zone 4, 3 and 2 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 completely isolate and abandon the parent Prudhoe Pool perfs. 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 D-21 Sundry submitted in concert with this request for full details. 1. Slickline : DMY GLVs, MIT, Drift, Caliper 2. E-Line : Set Whipstock 3. Fullbore : MIT-IA or MIT-T 4. Coil : Mill XN nipple and Window (if window not possible, mill with rig) 5. Valve Shop : Pre-CTD Tree Work 6. Operations : Remove wellhouse and level pad. Rig Work: (Estimated to start in December 2024) 1. MIRU and test BOPE 250 psi low and 3,500 psi high (MASP 2,433 psi). Give AOGCC 24hr notice prior to BOPE test. 2. Mill 3.80” Window. 3. Drill build section: 4.25" OH, ~870' (18 deg DLS planned). 4. Drill production lateral: 4.25" OH, ~1435' (12 deg DLS planned). Swap to KWF for liner. 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: 47 bbls, 15.3 ppg Class G 1.24 yield, TOC at TOL*. 7. Only if not able to do with service coil extended perf post rig – Perforate Liner 8. Freeze protect well to a min 2,200' TVD. 9. Close in tree, RDMO. * Approved alternate plug placement per 20 AAC 25.112(i) Post Rig Work: 1. Valve Shop : Valve & tree work 2. Slickline : SBHPS, set LTP* (if necessary), set Live GLV's, 3. Service Coil : Post rig perforate (~20’) and RPM. 4. Well Testers : Well Test 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 (9965' MD -8,497' TVD) Pumps On Pumps Oī A Target BHP at Window (ppg)4,330 psi 4,330 psi 9.8 B ŶŶƵůĂƌĨƌŝĐƟŽŶ- ECD ;ƉƐŝͬŌͿ 598 psi 0 psi 0.09 C DƵĚ,ǇĚƌŽƐƚĂƟĐ;ƉƉŐͿ 3,800 psi 3,800 psi 8.6 B+C Mud + ECD Combined 4,398 psi 3,800 psi (no choke pressure) A-(B+C)Choke Pressure Required to Maintain -68 psi 530 psi Target BHP at window and deeper Operation Details: Reservoir Pressure: x The estimated reservoir pressure is expected to be 3,313 psi at 8,800 TVD. (7.2 ppg equivalent). x Maximum expected surface pressure with gas (0.10 psi/ft) to surface is 2,433 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: 7,700' MD – 10,540' MD (2,840' liner) x 3-1/4", 6.6#, 13Cr Solid: 10,540' MD – 10,750' MD (210' liner) x 2-7/8", 6.5#, 13Cr Solid: 10,750' MD – 12,855' MD (2,105' 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 114°. Inclination at kick off point is 31°. x Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. x Distance to nearest property line – 24,772 ft x Distance to nearest well within pool – 850 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 Estimated 20'' perforated post rig – See attached extended perforating procedure. x 2.0" 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: 10,504’ MD in the parent Anti-Collision Failures: x No Anti-collision failures with D-21A WP 03 Hazards: x DS/Pad is not an H2S pad. The last H2S reading on D-21: 22 ppm on 09/01/2024. x Max H2S recorded on DS/Pad: 34 ppm.. x No fault crossings expected. x Low lost circulation risk. Ryan Ciolkosz CC: Well File Drilling Engineer Joseph Lastufka (907-244-4357) 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 Ivishak 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 3.0" Pipe / Slip HF neceeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeee 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 neceeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeee $) $ $) $) $) $) $)$) $) $) $) $) $)$) $) $) $) !! ! !! !!! ! !!! !!!!!! !! !! ! !!! ! !! !!! !! !!!! !!! !!! !!!! !!! ! !!!!! !! !! !!!!! !! !!!!! !! !!!!! !!!! !!!! ! ! D $) Prudhoe Bay Unit ADL28285 ADL28286 A-06 D-05 D-09 D-09A D-12 D-14AD-14B D-16B D-20 D-20A D-21 D-22 D-22A D-22B D-23 D-31A Sec. 23 Sec. 26 Sec. 24 Sec. 25 U011N013E D PAD PLAN: D-21A_SHL PLAN: D-21A_TPH PLAN: D-21A_BHL Map Date: 4/24/2024 Prudhoe Bay Unit D-21A Well wp01 E0 725 1,450Feet Legend $)PLAN: D-21A_BHL !PLAN: D-21A_SHL D PLAN: D-21A_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\NS\Wells\TRS_Distance\mxds\2024\NorthSlope_PBU_D-21A_wp01.mxd -6000-5500-5000-4500-4000-3500-3000South(-)/North(+) (1000 usft/in)2500 3000 3500 4000 4500 5000 5500 6000 West(-)/East(+) (1000 usft/in)901 1 C-05 A 8640C-34B92329016D-23A6800720076008000840088009187D-2188009054D-09A7200760080008400880092009290D-09880 0 9 1 29A-2 5A 76008000840088009181A -258 8 0 0 907 7 C -0 5 8 8 0 0 8529D-21A wp01Top of Window - 10550'MDEnd 18dls - 11421'MDTD - 12855'MD8600880090009200True Vertical Depth (400 usft/in)1800 2000 2200 2400 2600 2800 3000 3200 3400 3600 3800 4000 4200 4400 4600 4800 5000 5200 5400 5600 Vertical Section at 190.00° (400 usft/in)D-21D-21A wp01Top of Window - 10550'MDEnd 18dls - 11421'MDTD - 12855'MDSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect1 10550.00 31.62 158.70 8497.49 -3553.07 4329.61 0.00 0.00 2747.262 10570.00 33.42 158.70 8514.35 -3563.08 4333.52 9.00 0.00 2756.453 10640.00 46.02 158.70 8568.08 -3604.68 4349.73 18.00 0.00 2794.594 10740.08 38.00 183.00 8642.88 -3669.53 4361.30 18.00 125.00 2856.455 10992.08 38.00 256.68 8841.46 -3780.61 4268.61 18.00 90.00 2981.946 11122.08 38.00 218.67 8943.90 -3822.63 4202.21 18.00 -90.00 3034.857 11420.50 90.00 202.67 9070.92 -4048.85 4078.09 18.00 -20.00 3279.198 11656.42 114.25 187.59 9021.46 -4268.81 4017.17 12.00 -30.00 3506.389 11777.00 114.25 171.72 8971.94 -4378.39 4017.83 12.00 -90.00 3614.1910 11957.00 114.25 195.41 8898.01 -4541.03 4007.69 12.00 90.00 3776.1111 12137.00 114.25 171.72 8824.08 -4703.66 3997.55 12.00 -90.00 3938.0412 12277.00 114.25 190.15 8766.58 -4830.74 3995.47 12.00 90.00 4063.5513 12497.00 114.25 161.20 8676.22 -5028.64 4010.45 12.00 -90.00 4255.8314 12657.00 114.25 182.25 8610.50 -5172.19 4031.33 12.00 90.00 4393.5815 12855.00 114.25 156.19 8529.18 -5348.01 4064.80 12.00 -90.00 4560.92Project: Prudhoe BaySite: DWell: D-21Wellbore: PLAN: D-21APlan: D-21A wp01WELLBORE DETAILSParent Wellbore:D-21Top of Window: 10550.00D-21A wp01Depth From Depth To Survey/Plan Tool100.00 10550.00 D-21 Srvy 1 BOSS-GYRO (D-21) 3_Gyro-SR-GMS110550.00 12855.00 D-21A wp01 (PLAN: D-21A) 3_MWDWELL DETAILSNorthing: 5959328.00Easting: 653462.00Lattitude: 70° 17' 44.9876 NLongitude: 148° 45' 26.3146 WD-21A wp01SECTION DETAILSHilcorp Alaska, LLCSURVEY PROGRAMNAD 1927 (NADCON CONUS)US State Plane 1927 (Exact solution)Alaska Zone 04PROJECT DETAILSREFERENCE INFORMATIONCoordinate(N/E) Reference: Well D-21, True NorthVertical (TVD) Reference: D-21 @ 71.52usft (Nabors 18E)Measured Depth Reference: D-21 @ 71.52usft (Nabors 18E)Section (VS) Reference: Slot - (0.00N, 0.00E)Calculation Method: Minimum CurvatureREFERENCE INFORMATION !" #$ % & ' $ ( )* ( + + !,$ ! -" !""# $%&'() *+,- . ./ ,!0! 1, - ($%&'() *+,- % " ( 2 1 - $' / !' & - 0 $'!'3 4%),5 - 4%) 663- 371,1 1, 8/9 ! # 3:2( 3:: ( 1 ' ! .! 2$ % ". 3. / ,. 1; ( ! 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"# $ %&' . ) /0 8 ! & 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. 224-132 PRUDHOE BAY PRUDHOE OIL PBU D-21A 1 Christianson, Grace K (OGC) From:Torin Roschinger <torin.roschinger@hilcorp.com> Sent:Friday, November 1, 2024 1:32 PM To:Boman, Wade C (OGC); Trevor Hyatt Cc:Rixse, Melvin G (OGC); Finn Oestgaard - (C) Subject:RE: [EXTERNAL] PBU D-21 service coil window milling Attachments:RE: [EXTERNAL] Preliminary - expectations for service coil window milling Good afternoon Wade, I would like to include what is in the attached email on all CTD PTD and sundrys moving forward. However, I want to make sure that I’ve received Mel’s blessing first prior to making these changes. If approved, we plan to submit all future PTD’s and sundry this way understanding that the AOGCC may not approve all of them. In addition, we would likely want to submit a few changes to existing PTD and sundrys to include them in the service coil milling hopper. Please advise how you would like us to move forward. Thank you, Torin From: Boman, Wade C (OGC) <wade.boman@alaska.gov> Sent: Friday, November 1, 2024 11:50 AM To: Trevor Hyatt <trevor.hyatt@hilcorp.com>; Torin Roschinger <torin.roschinger@hilcorp.com> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: [EXTERNAL] PBU D-21 service coil window milling Trevor and Torin, I’m looking at the PTD for PBU D-21, and the fourth line of the pre-rig work section has service coil milling possibly milling the window: Are you wanting to officially include the template in the PTD as you did for PBU K-12C? I realize this process is a topic of current conversation and want to be clear on the plan for this sidetrack. Thanks. -Wade CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 2 WWade Boman Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave, Anchorage, AK 99501 wade.boman@alaska.gov office: 907-793-1238 cell: 907-687-4468 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1 Christianson, Grace K (OGC) From:Boman, Wade C (OGC) Sent:Friday, November 1, 2024 11:50 AM To:Trevor Hyatt; torin.roschinger@hilcorp.com Cc:Rixse, Melvin G (OGC) Subject:PBU D-21 service coil window milling Trevor and Torin, I’m looking at the PTD for PBU D-21, and the fourth line of the pre-rig work section has service coil milling possibly milling the window: Are you wanting to officially include the template in the PTD as you did for PBU K-12C? I realize this process is a topic of current conversation and want to be clear on the plan for this sidetrack. Thanks. -Wade Wade Boman Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave, Anchorage, AK 99501 wade.boman@alaska.gov office: 907-793-1238 cell: 907-687-4468 WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UNIT D-21AInitial Class/TypeDEV / PENDGeoArea890Unit11650On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2241320PRUDHOE BAY, PRUDHOE OIL - 640150NA1Permit fee attachedYesADL028285 and ADL0282862Lease 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) (ForNA15All 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)NAThis well is an in-zone CTD sidetrack from an existing wellbore with pressure integrity.18Conductor string providedNAAll drilling on this sidetrack will be below the existing SC shoe.19Surface casing protects all known USDWsNAThis well is an in-zone CTD sidetrack from an existing wellbore with pressure integrity.20CMT vol adequate to circulate on conductor & surf csgNAThis well is an in-zone CTD sidetrack from an existing wellbore with pressure integrity.21CMT vol adequate to tie-in long string to surf csgYesFully cemented production liner. Parent well isolates the wellbore.22CMT will cover all known productive horizonsYes23Casing designs adequate for C, T, B & permafrostYesCDR2 and CDR3 have adequate tankage and good trucking support.24Adequate tankage or reserve pitYesSundry 324-60025If a re-drill, has a 10-403 for abandonment been approvedYesNo wells with SF <1.26Adequate wellbore separation proposedNAAll drilling will be below the SC shoe.27If diverter required, does it meet regulationsYesMPD w/8.4ppg mud, and res press of 7.2 ppg equivalent28Drilling fluid program schematic & equip list adequateYesCT packoff, flow cross, annular, blind/shear, CT pipe slips, flow cross, BHA pipe slips, CT pipe slips29BOPEs, do they meet regulationYes7-1/16" 5000 psi stack, pressure tested to 3500 psi.30BOPE press rating appropriate; test to (put psig in comments)YesFlanged choke and kill lines between dual combis w/remote choke.31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownNoPrudhoe's D-Pad is not an H2S pad. The max recorded reading was 34 ppm.33Is presence of H2S gas probableNAThis is a development well.34Mechanical condition of wells within AOR verified (For service well only)NoD-Pad wells are H2S-bearing. H2S measures are required.35Permit can be issued w/o hydrogen sulfide measuresYesExpected reservoir pressure is 7.2 ppg EMW. MPD to be employed.36Data presented on potential overpressure zonesNANo fault crossings anticipated37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprADDDate10/28/2024ApprWCBDate11/1/2024ApprADDDate10/28/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 12/18/2024