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Home My WebLink About224-1221 Gluyas, Gavin R (OGC) From:Lau, Jack J (OGC) Sent:Monday, February 24, 2025 3:35 PM To:David.Wages@hilcorp.com Subject:FW: 09-35B 2nd perf round (PTD: 224-122) Attachments:PBU 09-35B Approved 10-401 11-14-24.pdf; 09-35B Post Rig ExtADP #2 2-20-25.pdf; 09-35B Post-CTD ExtADP #2 2-20-25.docx; Voice Mail (45 seconds) David – You are approved for additional perforations in the zone and approved for a 2 week extension for the 10- 407. Thanks Jack From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Thursday, February 20, 2025 2:19 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Subject: FW: 09-35B 2nd perf round (PTD: 224-122) Forwarding on to you. Mel From: Brodie Wages <David.Wages@hilcorp.com> Sent: Thursday, February 20, 2025 12:35 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: 09-35B 2nd perf round (PTD: 224-122) Hello Mel, We would like to add additional perforations to 09-35B Initial perforations were shot on Feb 3, 2025. Initial POP attempt came in 2/8/2025 however, we have been unsuccessful getting the well to flow consistently measurable volumes. Per the word program and log attached, we would like to add additional perfs via service coil extended perforating under the existing PTD. Given those initial perf date of 2/3/2025, our due date for the 10-407 lands on 3/5/2025. We will make an eƯort to shoot this second round by March 5th but would like to ask for a 2 week extension at this time for the 10-407 submittal. David Wages CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 Hilcorp – OE – FS2 Cell: 713.380.9836 From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Thursday, February 20, 2025 8:35 AM To: Brodie Wages <David.Wages@hilcorp.com> Subject: [EXTERNAL] Additional Perfs on PTD? Brodie, Please send a quick note describing the perforations you want to add with PTD number. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 OƯice 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 11,089' - 11,319' 11,779' - 11,813'11,716' - 11,758' 11,940' - 12,072' (re-perf)11,830' - 11,930' (Re-perf) Post-CTD ExtADP #2 09-35b Revision 1 Well Name: 09-35b API Number: 50-029-21314-01 Current Status: PAL Operable Rig: Slickline/ Coil Estimated Start Date: March 2025 Sundry Number: 323-509 Regulatory Contact: Carrie Janowski Permit to Drill Number: 224-122 First Call Engineer: David Wages 713-380-9836 Second Call Engineer: Jerry Lau 907-360-6233 AFE Number: 241-00124.05.02 IOR: 200 Current Bottom Hole Pressure: 3322 psi @ 8,700’ TVD 7.2 PPGE | RE est. Max. Anticipated Surface Pressure: 2452 psi (Based on 0.1 psi/ft. gas gradient) Min ID: 3.725” @ XN nipple @ 9433’ Max Angle: 92 deg @ 10,725’ MD. 70 deg: 10,070’ Last tag: 10,005’ w/ slickline Well History Info 09-35b was successfully sidetracked Jan 2025. Initial perforates were shot post rig and attempted to be brought online. At most, the well made ~100 bopd with a surprisingly low volume of water. As a result, additional ADPs are requested and detailed below. Significant Well Events: Sidetracked in 1993 to current location 1/2003: Eline RST log Through 2005: passing MIT-OAs to 2500 psi 4/2006: MIT-T passed, still some IAxOA re-pressurization Some wellhead issues noted but the seals all passed tests immediately prior to the RWO 4/2006: eline jet cut tubing, RWO to install 7” tieback to address OA re-pressurization and install 4-1/2” tubing 5/2006: SL: Pull B&R, install GLVs, EL: Gyro survey and jewelry log Well online @ 600 bopd and 6000 water, died off in a year 5/2009: SBHPS 4/2014: GLRDFR 8/2014: RPM from 10,217’ – 9450’ (did not enter liner) and borax log which indicated questionable cement Perforate 2014 intervals 5/2015: Eline perf 8/2016: SL: GLRDFR, MIT-IA passed 6/2021: SL tag fill at 10,005’ (424’ open perfs) 9/2021: EL: PPROF, no flow below 9996’, most flow from 9666’ – 9710’ 9/2023: SL GLRDFR 2/2025: Post CTD initial perforations and POP Objective: The purpose of this program is to provide guidance for well integrity conformance and post rig perforating on service coil Post-CTD ExtADP #2 09-35b Revision 1 Procedure: Coiled Tubing Drift and Flag Notes: • Remote gas monitoring for H2S and LELs are required for Open Hole Deployment Operations • Due to the necessary open hole deployment of Extended Perforating jobs, 24-hour crew and WSS coverage is required. The well will be killed and monitored before making up the initial perf guns. 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 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. 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 guns. 2. Pull tie in log from PBTD to liner top 3. Bullhead 1.2x wellbore volume ~225 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 perf guns. Timing of the well kill is at the discretion of the WSS.) a. Wellbore volume to LTP (9400’) = 143 bbls b. LTP to PBTD = ~17 bbls 4. At surface, prepare for deployment of TCP guns. 5. 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 perf guns to ensure the well remains killed and there is no excess flow. *Perform drill by picking up safety joint with TIW valve and space out before MU guns. Review standing orders 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. a. At the beginning of each job, the crossover/safety joint must be physically MU to the perf guns one time to confirm the threads are compatible. 6. Break lubricator connection at QTS and begin makeup of TCP guns per schedule below. Constantly monitor fluid rates pumped in and fluid returns out of the well. Fluids man-watch must be performed while deploying perf guns to ensure the well remains killed and there is no excess flow. Perf Schedule Use 2” MaxForce 070 charges 6 SPF Perf Interval Perf Length Gun Length Weight of Gun (lbs) Comment 11,089’ – 11,319’ 230’ 230’ 1283 11,716’ – 11,758’ 42’ 356’ 234 11,779’ – 11,813’ 34’ 190 11,830’ – 11,930’ 100’ 558 Re-Perf 11,940’ – 12,072’ 132’ 737 Re-Perf 7. RIH with perf gun and lightly tag CIBP for depth control (as needed). Pickup and perforate interval per Perf Schedule above. Post-CTD ExtADP #2 09-35b Revision 1 a. Note any tubing pressure change in WSR. 8. After perforating, PUH to top of liner or into tubing 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. 9. Pump pipe displacement while POOH. Stop at surface to reconfirm well is dead. Kill well if necessary. 10. Review well control steps and Standing Orders with crew prior to breaking lubricator connection and commencing breakdown of TCP gun string. 11. Ensure safety joint and TIW valve assembly are on-hand before breaking off lubricator to LD gun BHA. 12. RDMO CTU. 13. Turn well over to Operations POP. Well Testing- New Well POP 1. MIRU Well Test Unit a. Work with pad op to determine flowline to use if the tie in is not complete 2. POP well per SLBU program below 3. Once well is on stable production, obtain a 12 hour piggyback well test a. Retest as needed to confirm pad separator rates Post-CTD ExtADP #2 09-35b Revision 1 Current WBD: Post-CTD ExtADP #2 09-35b Revision 1 Proposed Schematic: Post-CTD ExtADP #2 09-35b Revision 1 Perf-Tie in: Post-CTD ExtADP #2 09-35b Revision 1 Tie-In ScreenShots: Gun Run #2 Gun Run #1 Post-CTD ExtADP #2 09-35b Revision 1 BOP Schematic Post-CTD ExtADP #2 09-35b Revision 1 Post-CTD ExtADP #2 09-35b Revision 1 Post-CTD ExtADP #2 09-35b Revision 1 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 Post-CTD ExtADP #2 09-35b Revision 1 Slow Bean-Up (SLBU) Procedure for Wells that received ~500’+ of new perforations Notes: - The objective of this procedure is to outline rough guidelines for making choke & drawdown changes to extended add-perf (ExtADP) wells to limit the rate of drawdown, which minimizes shock to the reservoir and minimizes sand-face failure (sand production) and completion damage. This should be considered general and not rigid rules. - This procedure should be followed any time an existing or new well receives an Ext ADP intervention or post drill where more than 500’ of perfs have been added. - Each well has different flow characteristics and as such may result in varying times to reach FOC and/or optimal choke setting. - GL should be shut-off anytime a well is shut-in. This prevents from displacing gas into the formation and thus can lead to applying a large amount of drawdown over a short time interval when re-POP’ing that can result in high amounts of sand production. 1. Open the choke to minimum choke position. Start GL at 1 MMSCFD and maintain this setting for 6 hours after the well is kicked off. Consider adjusting the choke if the WHT is <50F and/or WHP is >500 psi for a prolonged period (mitigate hydrate formation). • Expect WHP to initially drop when opening the choke until GL has time to build pressure and KO well. • If well is setup with continuous AF / EB / Meth injection at the wellhead, add as necessary to help reduce slugging until well stabilizes out. • If well is setup for continuous methanol injection, add methanol into the GL stream as necessary until well is warm and stable. • After the well kicks off, adjust gas lift rate at this time to get stable flow. Flow should be as stable as possible before opening up the choke. 2. After the 6 hour hold period, open choke 10 steps • Increase GL to target rate at the end of the 6 hour hold period. Adjust GL as necessary to achieve stable flow and limited slugging. Target 1500 TGLR. 3. Hold at this choke setting for 2 hours • If the stages are lengthened due to operational constraints that is fine. Bean-up should take a minimum of 10 hours to get to target. • After a bottoms up is seen, take a solids sample. If the shakeout sample shows a solid content >1% contact OE. o Will likely want to hold at choke setting for an additional bottoms up . o At the end of the hold period, grab another shakeout to confirm solids production has reduced to a manageable level before proceeding with any additional drawdown changes. • If solids sample <0.2%, open choke up 10 more steps • If possible, obtain a water salinity every choke adjustment. 4. Repeat the choke opening steps as described above to fully open well to flow. Discuss with OE if there are any flowing BHP limitations. 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: 02/21/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: PBU 09-35B PTD: 224-122 API: 50-029-21314-02-00 FINAL LWD FORMATION EVALUATION LOGS (01/19/2025 to 01/27/2025) 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. 224-122 T40150 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.02.21 14:42:00 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 2/16/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250216 Well API #PTD #Log Date Log Company Log Type AOGCC Eset # BRU 232-04 50283100230000 132037 1/18/2025 AK E-LINE Perf CLU 08 50133205340000 204005 2/13/2025 YELLOWJACKET SCBL CLU 10RD2 50133205530200 224135 1/2/2025 YELLOWJACKET SCBL CLU 10RD2 50133205530200 224135 12/13/2024 YELLOWJACKET SCBL CLU 7 50133205310000 203191 1/25/2025 YELLOWJACKET SCBL IRU 44-36 50283200890000 193022 1/21/2025 AK E-LINE Plug/Perf KALOTSA 10 50133207320000 224147 2/11/2025 YELLOWJACKET SCBL KALOTSA 9 50133207310000 224145 1/26/2025 YELLOWJACKET SCBL KBU 22-06Y 50133206500000 215044 1/11/2025 YELLOWJACKET SCBL KU 13-06A 50133207160000 223112 1/12/2025 YELLOWJACKET SCBL MRU M-25 50733203910000 187086 1/15/2024 AK E-LINE PPROF NCIU A-21 50883201990000 224086 1/6/2024 AK E-LINE Plug/Perf PBU 06-05A 50029202980100 224115 1/14/2025 HALLIBURTON RBT PBU 09-35B 50029213140200 224122 2/3/2025 HALLIBURTON RBT PBU B-12B 50029203320200 224133 1/20/2025 HALLIBURTON RBT PBU D-12 50029204430000 180015 12/19/2024 BAKER SPN PBU F-08B 50029201350200 212040 1/27/2025 HALLIBURTON RBT PBU NK-41A 50029227780100 197158 12/18/2024 YELLOWJACKET CBL PBU S-100A 50029229620100 224083 1/5/2025 HALLIBURTON RBT Revision Explanation: Annotations added to processed log. Please include current contact information if different from above. 162-037 T40080 T40081 T40082 T40082 T40083 T40084 T40085 T40086 T40087 T40088 T40089 T40090 T40091 T40092 T40093 T40094 T40095 T40096 T40097 PBU 09-35B 50029213140200 224122 2/3/2025 HALLIBURTON RBT Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.02.18 13:06:47 -09'00' Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Monty M. Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Prudhoe Bay Field, Prudhoe Oil Pool, PBU 09-35B Hilcorp Alaska, LLC Permit to Drill Number: 224-122 Surface Location: 1822' FSL, 1048' FEL, Sec 02, T10N, R15E, UM, AK Bottomhole Location: 2623' FSL, 2370' FEL, Sec 02, T10N, R15E, 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, Jessie L. Chmielowski Commissioner DATED this 14th day of November 2024. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.11.14 08:30:00 -09'00' 3-1/2"x3-1/4" Drilling Manager 09/06/24 Monty M Myers 5 By Grace Christianson at 8:39 am, Sep 09, 2024 DSR-9/11/24A.Dewhurst 28OCT24 50-029-21314-02-00 MGR16SEP2024 * BOPE test to 3500 psi. * Variance to 20 AAC 25.112(i) Alternate plug placement approved when liner is fully cemented and all drilling is below the PB Oil pool confining zones. * Approved for post rig service coil perforating. BHA length not to exceed 500' in length. * Waiver request to 20 AAC 25.036 (c)(2)(A)(iv) for running 2-7/8" production liner without pipe rams denied. * Waiver to 20 AAC 25.036 (c)(2)(A)(iv) if CS Hydril jointed pipe is required is approved for this well if well work completed by 3-31-2025. 224-122 WCB 11-13-2024 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.11.14 08:30:15 -09'00' 11/14/24 11/14/24 RBDMS JSB 111824 To: Alaska Oil & Gas Conservation Commission From: Trevor Hyatt Drilling Engineer Date: September 6, 2024 Re:09-35B Permit to Drill Approval is requested for drilling a CTD sidetrack lateral from well 09-35A with the Nabors CDR2 Coiled Tubing Drilling. Proposed plan for 09-35B Producer: See 09-35A Sundry request for complete pre-rig details - Prior to drilling activities, screening will be conducted to drift/caliper for whipstock 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 or 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 Ivishak Zone 4 and lands in Zone 2. The lateral will continue in Zone 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 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: Reference 09-35A Sundry submitted in concert with this request for full details. 1. Slickline : Dummy WS drift and Caliper 2.E-Line : Set 4-1/2"x7" Whipstock at 9,626’ MD at 150 degrees ROHS 3. Fullbore : MIT-IA and/or MIT-T to 3,000 psi (if needed) 4. Coil : Mill XN nipple (at 9,433' MD) and Window (if window not possible, mill with rig). Give AOGCC 24hr notice prior to BOPE test. Test BOPE to 3500 psi. MASP with gas (0.10 psi/ft) to surface is 2,420 psi. 5. Valve Shop : Pre-CTD Tree Work 6. Operations : Remove wellhouse and level pad. Rig Work: (Estimated to start in January 2025) 1. MIRU and test BOPE 250 psi low and 3,500 psi high (MASP 2,420 psi). Give AOGCC 24hr notice prior to BOPE test. 2. Mill 3.80” Window (top of window at 9,631' MD pinch point) - only if not done pre rig. 3. Drill build section: 4.25" OH, ~356' (35 deg DLS planned). 4. Drill production lateral: 4.25" OH, ~2,125' (12 deg DLS planned). 5. Run 3-1/2” x 3-1/4” x 2-7/8” 13Cr liner 6. Pump primary cement job: 36.7 bbls, 15.3 ppg Class G, 1.24 (ft 3/sk), 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) PTD 224-122 Pipe rams to fit required for running 2-7/8" liner. - mgr Sundry 323-509 Post Rig Work: 1. Valve Shop : Valve & tree work 2. Coil : CBL, ~1000' of perfs (see attached procedure) 3. Slickline : Set LTP (if necessary), GLRD if necessary 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 (9631' MD -8,692' TVD) Pumps On Pumps O A Target BHP at Window (ppg)4,429 psi 4,429 psi 9.8 B -578 psi 0 psi 0.06 C 3,887 psi 3,887 psi 8.6 B+C Mud + ECD Combined 4,465 psi 3,887 psi (no choke pressure) A-(B+C)Choke Pressure Required to Maintain 0 psi 542 psi Target BHP at window and deeper Operation Details: Reservoir Pressure: The estimated reservoir pressure is expected to be 3,300 psi at 8,800 TVD. (7.3 ppg equivalent). Maximum expected surface pressure with gas (0.10 psi/ft) to surface is 2,420 psi (from estimated reservoir pressure). Mud Program: Drilling: Minimum MW of 8.4 ppg KCL with viscosifier for drilling. Managed pressure used to maintain constant BHP. Disposal: All Class l & II non-hazardous and RCRA-exempt drilling and completion fluids will go to GNI at DS 4. Fluids >1% hydrocarbons or flammables must go to GNI. Fluids >15% solids by volume must go to GNI. Fluids with solids that will not pass through 1/4” screen must go to GNI. Fluids with PH >11 must go to GNI. Hole Size: 4.25 hole for the entirety of the production hole section. Liner Program: 3-1/2", 9.3#, 13Cr/Solid: 9,400' MD – 9,610' MD (210' liner) 3-1/4", 6.6#, 13Cr/Solid: 9,610' MD – 10,200' MD (590' liner) 2-7/8", 6.5#, 13Cr/Solid: 10,200' MD – 12,112' MD (1,912' liner) The primary barrier for this operation: Kill Weight Fluid to provide overbalance as necessary. A X-over shall be made up to a safety joint including a TIW valve for all tubulars ran in hole. Well Control: BOP diagram is attached. MPD and pressure deployment is planned. Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 3,500 psi. The annular preventer will be tested to 250 psi and 2,500 psi. 1.5 wellbore volumes of KWF will be on location at all times during drilling operations. 20 AAC 25.036 (c)(2)(A)(iv): Waiver Request o Blind/Shear rams will be utilized in place of pipe rams sized for CTD jointed pipe operations as a worst-case shut-in scenario (in place of 2-3/8”x3-1/2” VBRs for liner runs and 1” / 1-1/4” CS hydril pipe rams). o Blind/Shear rams are preferred over pipe rams in CTD jointed pipe operations, because liners and jointed pipe strings for CTD are only ~500-3500’ long and therefore are not suitable killstrings – having a circulation point of less than ~3500’ MD. The jointed pipe will also be pipe light and would be shut in below the flow cross. Thus, circulation would not be possible if shut in. There is not adequate room to add extra BOP rams for this well (see attached tree height diagram): o Current Well Tree height is 190.5”. o CDR2 max tree height, with six ram BOP, to fit over the well is 163”. o CDR3 max tree height, with six ram BOP, to fit over the well is 172”. o A six ram BOP stack (to accommodate two extra rams for CTD jointed pipe operations – 2-3/8”x3-1/2” VBRs for liner runs and 1” / 1-1/4” CS hydril pipe rams), is based off two triples. Mitigations: o The well will be full of KWF prior to running liner or jointed pipe operations. o The BHA will be circulated out of hole prior to laying down BHA for jointed pipe operations. o The well will be flow checked after laying in KWF, before laying down BHA and before making jointed pipe. o In addition, a X-over shall be made up to a 2 3/8" safety joint including a TIW valve for all tubulars ran in hole. o Primary shut-in standing orders will be to use a safety joint while running 2-3/8” or 3-1/2”x3-1/4”x2- 7/8” solid or slotted liner, 1” or 1-1/4” CS Hydril jointed pipe, and perf guns.The desire is to keep the same standing orders for all jointed pipe operations and not change shut in techniques in the middle of jointed pipe operations or from well to well (run safety joint with pre-installed TIW valve). When closing on a safety joint, 2 sets of pipe/slip rams will be available, above and below the flow cross providing better well control option. Directional: Directional plan attached. Maximum planned hole angle is 101°. Inclination at kick off point is 40°. Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. Distance to nearest property line – 13,584 ft Distance to nearest well within pool – 1,340 ft Logging: MWD directional, Gamma Ray and Resistivity will be run through the entire open hole section. Real time bore pressure to aid in MPD and ECD management. - Denied for liners, Approved for CS Hydril. mgr Perforating: 1000' perforated post rig – See attached extended perforating procedure. 2" Perf Guns at 6 spf 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. The well will be perforated between the CTD whipstock and TD of the newly drilled CTD well, completely in the Ivishak pool. Formations: Top of Ivishak is 9,578’ MD in the parent Anti-Collision Failures: Anti-Collision Summary – Fails 09-31 (at 9,240’ MD) and 09-31C (at 9,665’ MD) – 09-31D Sidetracked and abandoned at 3,505’ MD. Financial risk for plugback and sidetrack. Hazards: DS 09 is an H2S pad. The last H2S reading on 09-35A: 220 ppm on 05/04/2024. Max H2S recorded on 09-35A: 450 ppm on 02/05/2008. 2 fault crossings expected. High lost circulation risk. Trevor Hyatt CC: Well File Drilling Engineer Joseph Lastufka (907-223-3087) Post-Rig Service Coil Perforating Procedure: Coiled Tubing Notes: Due to the necessary open hole deployment of Extended Perforating jobs, 24-hour crew and WSS coverage is required. 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 2.0" 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 Well Date Quick Test Sub to Otis Top of 7" Otis Distances from top of riser Excluding quick-test sub Top of Annular C L Annular Bottom Annular CL Blind/Shears CL 2.0" Pipe / Slips B3 B4 B1 B2 Kill Line Choke Line CL 2-3/8" Pipe / Slip CL 2.0" Pipe / Slips TV1 TV2 T1 T2 Flow Tee Master Master LDS IA OA LDS Ground Level 3" LP hose open ended to Flowline CDR3-AC BOP Schematic CDR3 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 CDR2 or CDR3 BOP and Well Tree Height Hydril 7 1/16" Annular Blind/Shear 2" or 2-3/8" Pipe/Slips 2 3/8" Pipe/Slips 2 3/8" Pipe/Slips 7-1/16" 5k Mud Cross 2" or 2-3/8" Pipe/Slips 2-3/8" or 3.0" Pipe / Slip Blind/Shear 2" or 2-3/8" Pipe/Slips 2-3/8" or 3.0" Pipe / Slip 2" or 2-3/8" Pipe/Slips 1" or 1-1/4" Pipe/Slips 2-3/8" x3-1/2" VBRs CDR2 Maximum Tree Height with 6 ram BOP: 163" Current Well Tree Height: 190.5" CDR3 Maximum Tree Height with 6 ram BOP: 172" Rig Floor Cellar Top/Ground Level Top of Tree (top swab flange) Well: 09-35B 6 ram BOP height based off two triples. 1 Christianson, Grace K (OGC) From:Trevor Hyatt <trevor.hyatt@hilcorp.com> Sent:Tuesday, November 5, 2024 4:40 PM To:Boman, Wade C (OGC) Cc:Rixse, Melvin G (OGC); Ryan Ciolkosz; Joseph Lastufka Subject:RE: [EXTERNAL] 09-35B anti-collision question Categories:CDR2-3 Wade, That well is sidetracked at 3,505’ MD to the new 09-31D. All the close approaches are down past 9,000’ MD (09-31 depths). The new 09-31D completion is out of range for the AC scan. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 Trevor Hyatt Hilcorp Alaska, LLC Drilling Engineer Trevor.Hyatt@hilcorp.com Cell: 907-223-3087 From: Boman, Wade C (OGC) <wade.boman@alaska.gov> Sent: Thursday, October 31, 2024 1:55 PM To: Trevor Hyatt <trevor.hyatt@hilcorp.com> 3 Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: [EXTERNAL] 09-35B anti-collision question Trevor, on the PBU 09-35B PTD, in the anti-collision section, the following is mentioned: I see in our database that 09-31 and 09-31C are P&A’d. However, I’m seeing 09-31D’s current class and status being “Service” and “Gas injection, single completion,” respectively. Could you please clarify the current status of 09-31D? 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 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 1 Christianson, Grace K (OGC) From:Boman, Wade C (OGC) Sent:Thursday, October 31, 2024 1:55 PM To:Trevor Hyatt Cc:Rixse, Melvin G (OGC) Subject:09-35B anti-collision question Trevor, on the PBU 09-35B PTD, in the anti-collision section, the following is mentioned: I see in our database that 09-31 and 09-31C are P&A’d. However, I’m seeing 09-31D’s current class and status being “Service” and “Gas injection, single completion,” respectively. Could you please clarify the current status of 09-31D? 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 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. PBU 09-35B PRUDHOE OILPRUDHOE BAY 224-122 WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UNIT 09-35BInitial Class/TypeDEV / PENDGeoArea890Unit11650On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2241220PRUDHOE BAY, PRUDHOE OIL - 640150NA1Permit fee attachedYesADL0283272Lease 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 has adequate tankage and good trucking support.24Adequate tankage or reserve pitYesSundry 324-50925If a re-drill, has a 10-403 for abandonment been approvedYesAnti-collision failures are deep in the reservoir.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 7.3 ppg28Drilling 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 psi30BOPE 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 shutdownYesPrudhoe's 09 drillsite is an H2S pad, with max reading of 450 ppm . Monitoring will be conducted.33Is presence of H2S gas probableNAThis is a development well.34Mechanical condition of wells within AOR verified (For service well only)NoDS 09 wells are H2S-bearing. H2S measures are required. Max H2S recorded on 09-35A: 450 ppm on 02/05/200835Permit can be issued w/o hydrogen sulfide measuresYesExpected reservoir pressure is 7.3 ppg EMW.MPD to be employed.36Data presented on potential overpressure zonesNATwo fault crossings anticipated.37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprADDDate10/28/2024ApprWCBDate11/13/2024ApprADDDate10/28/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 11/14/2024