The URL can be used to link to this page

Home My WebLink About224-002Nolan 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: 2/4/2026 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20260204 Well API # PTD # Log Date Log Company Log Type AOGCC E-Set# BRU 223-34T 50283202060000 225059 12/31/2025 AK E-LINE Perf T41308 BRU 244-27 50283201850000 222038 1/2/2026 AK E-LINE Perf T41309 CLU 11RD 50133205590000 225013 1/2/2026 YELLOWJACKET SCBL T41310 CLU 11RD 50133205590000 225013 12/19/2025 YELLOWJACKET SCBL T41310 END 1-25A 50029217220100 197075 11/7/2025 HALLIBURTON COILFLAG T41311 END 1-25A 50029217220100 197075 12/26/2025 READ PressTempSurvey T41311 END 2-40 50029225270000 194152 12/18/2025 READ PressTempSurvey T41312 END 2-52 50029217500000 187092 12/24/2025 HALLIBURTON MFC40 T41313 END 2-56A 50029228630100 198058 1/1/2026 HALLIBURTON COILFLAG T41314 END 2-56A 50029228630100 198058 1/19/2026 READ CaliperSurvey T41314 KALOTSA 3 50133206610000 217028 1/14/2026 YELLOWJACKET PERF T41315 KALOTSA 3 50133206610000 217028 1/9/2026 YELLOWJACKET PERF T41315 KALOTSA 8 50133207050000 222003 12/18/2025 YELLOWJACKET PERF T41316 KBU 44-06 50133204980000 200179 12/22/2026 YELLOWJACKET CBL T41317 KBU 44-06 50133204980000 200179 11/12/2025 YELLOWJACKET PLUG T41317 KU 24-07RD 50133203520100 205099 1/6/2026 AK E-LINE CBL T41318 KU 24-07RD 50133203520100 205099 1/6/2026 AK E-LINE Plug/Cement T41318 KU 24-07RD 50133203520100 205099 1/1/2026 AK E-LINE Plug/Cement/TubingPunch T41318 MPI-36 50029236770000 220047 1/19/2026 READ CaliperSurvey T41319 MPI-36 50029236770000 220047 1/19/2026 READ LeakDetectLog T41319 NCIU A-19 50883201940000 224026 1/7/2025 AK E-LINE Perf T41320 NFU 42-35 50231200460000 214170 1/8/2026 YELLOWJACKET PERF T41321 NIK OI24-08 50029234570000 211130 1/19/2026 HALLIBURTON COILFLAG T41322 ODSN-04 50703206700000 213037 1/20/2026 HALLIBURTON LDL T41323 ODSN-22 50703207080000 215054 12/20/2025 READ LeakDetection T41324 PBU 15-11D 50029206530400 225112 1/18/2026 HALLIBURTON RBT-COILFLAG T41325 PBU 15-43 50029226760000 196083 12/21/2025 HALLIBURTON RBT T41326 PBU B-30B 50029215420200 225009 1/24/2026 HALLIBURTON RBT-COILFLAG T41327 PBU C-33B 50029223730200 225096 12/16/2025 HALLIBURTON RBT-COILFLAG T41328 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.02.05 09:10:43 -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: PBU D-26B 50029215300200 206098 12/20/2025 HALLIBURTON ISAT T41329 PBU D-26B 50029215300200 206098 12/19/2025 BAKER SPN T41329 PBU F-21A 50029219490100 225019 1/18/2026 HALLIBURTON RBT-COILFLAG T41330 PBU J-21A 50029217050100 225106 1/21/2026 HALLIBURTON RBT-COILFLAG T41331 PBU L-291 50029237790000 224002 12/26/2025 HALLIBURTON RBT T41332 PBU L-291 50029237790000 224002 12/9/2025 YELLOWJACKET RCBL T41332 PBU S-107A 50029220440200 225083 12/8/2025 HALLIBURTON RBT-COILFLAG T41333 PBU S-201A 50029229870100 219092 1/21/2026 HALLIBURTON WFL-TMD3D T41335 PBU S-24B 50029220440200 203163 12/22/2025 HALLIBURTON RBT T41334 PBU S-24B 50029230230100 203163 12/23/2025 HALLIBURTON WFL-TMD3D T41334 SRU 223-15 50133207410000 225123 1/29/2026 YELLOWJACKET GPT-PERF T41336 SRU 223-15 50133207410000 225123 1/20/2026 YELLOWJACKET SCBL T41336 SRU 233-10 50133207400000 225113 12/30/2026 AK E-LINE CBL T41337 SRU 233-10 50133207400000 225113 1/10/2026 YELLOWJACKET SCBL T41337 SRU 233-10 50133207400000 225113 1/6/2026 YELLOWJACKET SCBL T41337 SRU 34-28 50133101580000 163007 1/7/2026 YELLOWJACKET Gamma Ray T41338 SU 32-16 50133207380000 225095 1/17/2026 YELLOWJACKET GPT-PLUG-PERF T41339 SU 32-16 50133207380000 225095 11/22/2025 YELLOWJACKET SCBL T41339 SU 43-10 50133207390000 225107 12/10/2025 YELLOWJACKET SCBL T41340 TBU A-12RD 50883200320100 171029 1/2/2026 AK E-LINE StripGun T41341 TBU D-24A 50733202240100 174064 12/4/2025 AK E-LINE TubingPunch T41342 Please include current contact information if different from above. T41332PBU L-291 50029237790000 224002 12/26/2025 HALLIBURTON RBT PBU L-291 50029237790000 224002 12/9/2025 YELLOWJACKET RCBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.02.05 09:11:00 -09'00' 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. From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: [EXTERNAL] RE: PBU L-291 (PTD #224-002) Liner Lap Length and Production Packer Set Depth Date:Tuesday, February 3, 2026 12:19:03 PM Attachments:image001.png From: Tyson Shriver <tyson.shriver@hilcorp.com> Sent: Friday, December 5, 2025 5:02 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Subject: RE: [EXTERNAL] RE: PBU L-291 (PTD #224-002) Liner Lap Length and Production Packer Set Depth Jack, I forgot to include that the proposed liner top packer set depth will be ~13,149’ MD (>100’ liner lap). This will position the tubing production packer at ~13,090’ MD, 146’ MD above top of SB pool (NA sand). Thank you, Tyson Shriver Hilcorp Alaska PBU GC-2 OE (L&V) o: 907-564-4542 c: 406-690-6385 From: Tyson Shriver Sent: Friday, December 5, 2025 4:50 PM To: 'Lau, Jack J (OGC)' <jack.lau@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Subject: RE: [EXTERNAL] RE: PBU L-291 (PTD #224-002) Liner Lap Length and Production Packer Set Depth Jack, Appreciate the quick response. I have had further discussions regarding these options with our operations team and equipment vendors. Setting the liner top packer inside the 7” shoe track is not recommended since there is no guarantee that the pipe walls are clean from previous cementing and drill out operations. This could ultimately lead to a compromised set / seal of the liner top packer and would require stacking a seal system with a second packer. In that scenario the tubing production packer would be set above the SB pool ultimately leading to an AA request. Understanding these operational risks and potential outcomes, Hilcorp is going to pursue Option 1 and apply for an AA. The AA request will include diagnostics to confirm injected fluids are confined to the approved SB oil pool injection interval. Thank you, Tyson Shriver Hilcorp Alaska PBU GC-2 OE (L&V) o: 907-564-4542 c: 406-690-6385 From: Lau, Jack J (OGC) <jack.lau@alaska.gov> Sent: Friday, December 5, 2025 4:09 PM To: Tyson Shriver <tyson.shriver@hilcorp.com>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Subject: [EXTERNAL] RE: PBU L-291 (PTD #224-002) Liner Lap Length and Production Packer Set Depth Tyson – Option 2 is our preference with the packer set below the confining zone and in the SB oil pool (as per conditions of approval) as that allows full monitoring of the IA to the SB. Additionally it does not require an AA. This option would require a variance for the liner lap, which can be granted with a pressure test to 50% of the casing burst pressure (lowest rated). Option 1 would require an AA for the high set packer with potential waterflow/oxygen activation log to ensure no flow behind pipe. Jack From: Tyson Shriver <tyson.shriver@hilcorp.com> Sent: Friday, December 5, 2025 2:28 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Subject: PBU L-291 (PTD #224-002) Liner Lap Length and Production Packer Set Depth Jack / Chris, The I-Rig just TD’d injection well PBU L-291 (PTD #224-002). There is a very small window in the 7” intermediate casing to set completion components to fulfil AOGCC regulations and PTD COAs. Per 20 AAC 25.030(d)(6) the 4-1/2” injection liner must overlap a minimum of 100’ with the 7” intermediate casing and L-291 PTD COA stipulates the tubing packer must be placed within the Schrader Bluff oil pool. Below is a log snippet showing the top of the pool (NA sand) and the 7” casing shoe, ~116’ MD separation. Based on a minimum 100’ liner lap and completion jewelry lengths, the production packer would be set above the SB pool. Hilcorp sees two options forward: 1. Obtain 100’ minimum liner lap and set the production packer above the top of pool. Hilcorp would apply for an AA to operate the well with a high set packer in this case. 2. Shorten the liner lap distance to ~60’ so the production packer can be set below 13,236’. This assumes liner can be run to TD. Based on offset wells, the liner run could be difficult and may not reach bottom. If this were the case, Hilcorp would apply for an AA to operate the well with a high set packer, same as Option 1. Do note that the injection liner will be cemented and the well will be a produced water only injector. Please let me know AOGCC’s preferred path forward. Thank you, Tyson Shriver Hilcorp Alaska PBU GC-2 OE (L&V) o: 907-564-4542 c: 406-690-6385 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 herebynotified 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 deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. Noresponsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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 herebynotified 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 deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. Noresponsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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: 01/02/2026 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL: Well: PBU L-291 PTD: 224-002 API: 50-029-23779-00-00 FINAL LWD FORMATION EVALUATION + GEOSTEERING (11/03/2025 to 12/05/2025) x ROP, AGR, ABG BaseStar and iCruise Gamma Ray, EWR-M5,StrataStar Resistivity x Pressure While Drilling (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Survey x Geosteering and EOW Report SFTP Transfer – Main Folders: LWD Subfolders: Geosteering Subfolders:g Please include current contact information if different from above. 224-002 T41235 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.01.05 08:31:59 -09'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: PBU L-291 (PTD #224-002) Liner Lap Length and Production Packer Set Depth Date:Friday, December 5, 2025 4:16:29 PM Attachments:image001.png From: Lau, Jack J (OGC) <jack.lau@alaska.gov> Sent: Friday, December 5, 2025 4:09 PM To: Tyson Shriver <tyson.shriver@hilcorp.com>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Subject: RE: PBU L-291 (PTD #224-002) Liner Lap Length and Production Packer Set Depth Tyson – Option 2 is our preference with the packer set below the confining zone and in the SB oil pool (as per conditions of approval) as that allows full monitoring of the IA to the SB. Additionally it does not require an AA. This option would require a variance for the liner lap, which can be granted with a pressure test to 50% of the casing burst pressure (lowest rated). Option 1 would require an AA for the high set packer with potential waterflow/oxygen activation log to ensure no flow behind pipe. Jack From: Tyson Shriver <tyson.shriver@hilcorp.com> Sent: Friday, December 5, 2025 2:28 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Subject: PBU L-291 (PTD #224-002) Liner Lap Length and Production Packer Set Depth Jack / Chris, The I-Rig just TD’d injection well PBU L-291 (PTD #224-002). There is a very small window in the 7” intermediate casing to set completion components to fulfil AOGCC regulations and PTD COAs. Per 20 AAC 25.030(d)(6) the 4-1/2” injection liner must overlap a minimum of 100’ with the 7” intermediate casing and L-291 PTD COA stipulates the tubing packer must be placed within the Schrader Bluff oil pool. Below is a log snippet showing the top of the pool (NA sand) and the 7” casing shoe, ~116’ MD separation. Based on a minimum 100’ liner lap and completion jewelry lengths, the production packer would be set above the SB pool. Hilcorp sees two options forward: 1. Obtain 100’ minimum liner lap and set the production packer above the top of pool. Hilcorp would apply for an AA to operate the well with a high set packer in this case. 2. Shorten the liner lap distance to ~60’ so the production packer can be set below 13,236’. This assumes liner can be run to TD. Based on offset wells, the liner run could be difficult and may not reach bottom. If this were the case, Hilcorp would apply for an AA to operate the well with a high set packer, same as Option 1. Do note that the injection liner will be cemented and the well will be a produced water only injector. Please let me know AOGCC’s preferred path forward. Thank you, Tyson Shriver Hilcorp Alaska PBU GC-2 OE (L&V) o: 907-564-4542 c: 406-690-6385 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 herebynotified 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 deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. Noresponsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Lau, Jack J (OGC) To:AOGCC Records (CED sponsored) Subject:FW: PBU L-291 (PTD: 224-002) Surface Casing Test and FIT Date:Tuesday, November 18, 2025 12:15:06 PM Attachments:PBU L-291 9.625 Csg test-FIT.pdf From: Joseph Engel <jengel@hilcorp.com> Sent: Monday, November 17, 2025 3:14 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: PBU L-291 (PTD: 224-002) Surface Casing Test and FIT Jack – Attached is the 9-5/8” surface casing test and FIT for L-291. Past emails cover the initial surface cement job. The top job went well, tagging TOC at 694’, and pumping 293bbls of cement with cement to surface. Witnessed by Austin McLeod. Thank you for your time. Joe Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC Office: 907.777.8395 | Cell: 805.235.6265 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Lau, Jack J (OGC) To:Joseph Engel Cc:Joseph Lastufka Subject:RE: PBU L-291 (PTD: 224-002) Update - Surface Remedial Top Job Date:Wednesday, November 12, 2025 3:29:18 PM Good afternoon Joe, The surface casing top job procedure outlined in your email is approved with the following conditions: RU and RIH in the conductor x surface casing annulus with 1” workstring to tag TOC – AOGCC Witnessed Pump top job taking returns to the cellar through 4” outlet valves, pumping enough cement to get cement to surface – AOGCC Witnessed If you cannot definitively identify the primary cement top what is your proposed plan? Email will suffice thus a 10-403 will not be required. Thanks for the detailed update. Jack From: Joseph Engel <jengel@hilcorp.com> Sent: Wednesday, November 12, 2025 3:07 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: PBU L-291 (PTD: 224-002) Update - Surface Remedial Top Job Jack – Thanks for the phone call earlier. Below is the summary of the surface casing run and cement job and our proposed top job plan forward. Casing Run: Surface casing run went ok. Casing was ran to 900’, where washing and reaming operations had to be established to make forward progress Due to the high inclination of this tangent section, we had to continue washing a reaming casing to TD A total of 25bbls were lost during the casing run. 1st Stage Cement Job: C&C mud prior to cement job, staging up to 6bpm with full returns Pumped 200bbls of 12# lead and 82bbl of 15.8 tail Pumped 743 bbls of displacement, experienced a packoff that resulted in partial losses Total losses of 220 bbls during entire cement job C&C waiting on cement: Opened stage tool, stage pumps up to 5 bpm, no spacer or cement returned to surface 120bph loss rate at 5bpm 30 bph loss rate at 3 bpm Full returns at 2 bpm Total losses during circulation 140 bbls. 2nd Stage Cement Job: Pumped 720 bbl of 11# Arctic Cem Lead and 56bbls of 15.8# tail Full returns until 70bbls of cement were outside the stage tool, then partial returns to no returns for the rest of the job Based upon gain/loss during 2nd stage job, there are 168bbls of cement between the stage tool and surface No cement to surface, however polyflake and red dye (additives in our spacer pumped ahead of cement) were seen at surface Estimated TOC: Based upon the spacer seen at surface, estimated TOC could be ~ 500’ MD Based upon the 168bbl in gauge hole, TOC could be ~ 250’ MD (gauge hole volume from stage tool to surface is ~180bbl) Losses occurring after packoff tell us that no cement to surface is a result of losses to formation and not due to inadequate volume of cement pumped Plan Forward: Wait on 2nd stage lead cement to build sufficient compressive strength and generate heat Notify AOGCC for opportunity to witness tag of TOC with workstring as per AOGCC Industry guidance bulletin 13-001 RU Eline to conduct a temperature survey to try and identify TOC (temp logs have been historically inconclusive) – est log time at 18:00 hrs tonight (11/12) Due to hole inclination, will only be able to get temp log to a max depth of ~ 1800 ‘ (inc is ~ 70* and 1900’ MD) RU and RIH in the conductor x surface casing annulus with 1” workstring to tag TOC Pump top job taking returns to the cellar through 4” outlet valves, pumping enough cement to get cement to surface Please let me know if you have any questions and respond with your approval. Thank you for your time. Joe Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC Office: 907.777.8395 | Cell: 805.235.6265 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 herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. By Grace Christianson at 11:42 am, Oct 20, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.10.20 07:19:17 - 08'00' Sean McLaughlin (4311) 325-651 A.Dewhurst 23OCT25 DSR-10/30/25 10-407 J.Lau 11/03/25 Conditions of Approval documented on approved PTD 224-002 remain valid. 11/03/25 Well: PBU L-291 Change to Approved Program PTD: 224-002 API: 50-029-23779-00-00 Well Name: PBU L-291 Permit to Drill: 224-002 API Number: 50-029-23779-00-00 Estimated Start Date: Regulatory Contact: Joseph Lastufka 907-777-8400 (O) jo4472@hilcorp.com Drilling Engineer: Joseph Engel 907-777-8395 (O) jengel@hilcorp.com Operations Engineer Tyson Shriver 907-564-4542 (O) tyson.shriver@hilcorp.com Brief Well Summary: PBU L-291 is a prior permitted grassroots Schrader Bluff injector. Due to extend production information needed to confirm fault block development strategies, the drilling of L-291 was delayed. Based upon the production/injection strategy of the fault block, Hilcorp would like to change the lower completion design of PBU L-291. Objective: Hilcorp would like to change the lower completion design from a 4-1/2 slotted liner to a 4-1/2 cemented sliding sleeve completion to allow for better injection conformance. Post rig work would also now include a coil tubing unit rig up to shift sleeves open and contingency acid job to break down cement behind sliding sleeves, if needed. All other aspects of the well design and well program will remain the same. Well: PBU L-291 Change to Approved Program PTD: 224-002 API: 50-029-23779-00-00 Operational Change: The following will replace section 18 in the approved PTD 18.0 Run 4-1/2 Sliding Sleeve Liner 18.1 Well control preparedness: In the event of an influx of formation fluids while running the 4-1/2 liner, the following well control response procedure will be followed: TIW with 4-1/2 crossover installed on bottom, TIW valve in open position on top TIW with 4 DP crossover installed on bottom, TIW valve in open position on top TIW shall be fully M/U and available prior to running the first joint of 4-1/2 liner and after picking up liner hanger Slack off with 4-1/2 or 4 across the BOP, shut in ram or annular. Close TIW. Proceed with well kill operations. 18.2 R/U liner running equipment. Ensure all casing has been drifted on the deck prior to running. Be sure to count the total # of joints on the deck before running. Keep hole covered while R/U casing tools. Record ODs, IDs, lengths, S/Ns of all components w/ vendor & model info. 18.3 Run 4-1/2 injection liner Use API Modified or other appropriate thread compound. Confirm pipe dope with TRS. Dope pin end only w/ paint brush. Wipe off excess. Thread compound can plug the screens Utilize a collar clamp until weight is sufficient to keep slips set properly. Use lift nubbins and stabbing guides for the liner run. Install jewelry as per the Running Order (From Completion Engineer post TD). o ~13 NCS Sleeves, 1 sleeve every ~450MD Centralization: 1 per joint, solid body centralizers Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm Liner Torque ftlbs OD PPF Connection Minimum Optimum Maximum Yield Torque 4-1/2 12.6 Hydril 563 3200 3800 5600 11900 18.4 Ensure hanger/pkr will not be set in a 7 connection. Tentative liner set depth, ~13,500 MD AOGCC regulations require a minimum 100 overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8 connection. 18.5 Before picking up Baker Flex Lock liner hanger / ZXP packer assembly, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 18.6 M/U Baker Flex Lock liner hanger and ZXP liner top packer to liner. Confirm with OE 4-1/2 liner top for tubing packer setting depth Well: PBU L-291 Change to Approved Program PTD: 224-002 API: 50-029-23779-00-00 18.7 Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 18.8 RIH with liner on 4 DP no faster than 30 ft/min this is to prevent buckling the liner and drill string and weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. Ensure 4 DP/HWDP has been drifted, use HWDP as needed for running liner There is no inner string planned to be run, as opposed to previous wells. The DP should auto fill. Monitor FL and if filling is required due to losses/surging. 18.9 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 18.10 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. 18.11 If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 18.12 TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 18.13 Rig up to pump down the work string with the rig pumps. 18.14 Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed 1,600 psi while circulating. Confirm all pressures with Baker. 18.15 Prior to proceeding with cement job, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 18.16 Circulate and condition mud for cement job 18.17 RU Lines for cement job if not already done so 18.18 Pump 60 bbls of 11ppg tunes spacer 18.19 Mix and pump cement as per plan 18.20 Cement volume based on OH annular volume + open hole excess (40%). Job will consist of single slurry, TOC brought to the 7 casing shoe, ~ 13,650 MD Section Calculation Vol (bbl) Vol (ft3) Vol (sks) 6-1/8" OH x 4-1/2" (19,821 - 13,649)' x 0.0168 bpf x 1.3 = 134.8 756.2 7" CH x 4-1/2" (13649 - 13500) x .0175 bpf = 2.6 14.6 4-1/2" Shoetrack 120' x 0.0152 bpf = 1.8 10.1 Total Tail 139.2 780.9 604.4 *30% per Joe Engel - J. Lau Well: PBU L-291 Change to Approved Program PTD: 224-002 API: 50-029-23779-00-00 18.21 After pumping cement, drop dart and displace cement with mud out of mud pits. Displacement calculations are based upon 4 dp from surface to liner top (13500 MD) 4-1/2 from liner top to TD Displacement Calculation: (19821 13500 120) * .0152bpf (4-1/2 cap) + 13500 * .0103 bpf (4 dp cap) 94.2 + 139.1 = 233.3 bbl 18.22 Monitor returns and pump pressure closely while displacing, slow donw pumps when dart latches onto liner wiper plug and when plug lands 18.23 Land liner wiper plug and pressure up to 500 psi over bump pressure. Bleed pressure and check floats. If floats are not holding, shut in and hold 500 psi over bump pressure until cement builds compressive strength. Ensure to report the following on well report: Pre flush type, volume (bbls) & weight (ppg) Cement slurry type, lead or tail, volume & weight Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration Pump rate while displacing, weight & type of displacing fluid Note if casing is reciprocated or rotated during the job Calculated volume of displacement , actual displacement, whether plug bumped & bump pressure, do floats hold Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure Note time cement in place & calculated top of cement Send final As-Run casing tally & casing and cement report to jengel@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. 18.24 Continue pressuring up to 2,600 psi to set the Flex lock liner hanger. Hold for 5 minutes. Slack off 20K lbs on the Flex Lock liner hanger to ensure the HRDE setting tool is in compression for release from the liner hanger/packer. Continue pressuring up 4,000 psi to set the ZXP liner top packer and release the HRDE running tool. Tail Slurry System Type 1/2 Density 15 lb/gal Yield 1.292 ft3/sk Mixed Water 5.989 gal/sk Well: PBU L-291 Change to Approved Program PTD: 224-002 API: 50-029-23779-00-00 18.25 Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 RPM and set down 50K again. 18.26 PU with running tool above Liner top packer and circulate bottoms up to remove any excess cement from around the running tool. 18.27 Reengage liner running tool. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. 18.28 Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 18.29 PU pulling running tool free of the packer and displace with at max rate to wash the liner top. Pump sweeps as needed. 18.30 POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned, LD DP on the TOOH. Operations in section 19 are unchanged, the only addition will be to post rig operations for coil tubing to shift sleeves and contingency acid job to break down cement behind sleeves if necessary. Attachments Proposed Wellbore Schematic Cement Calculations Well: PBU L-291 Change to Approved Program PTD: 224-002 API: 50-029-23779-00-00 Proposed Wellbore Schematic Well: PBU L-291 Change to Approved Program PTD: 224-002 API: 50-029-23779-00-00 Cement Calculations 4-1/2 Liner Cement OH x CSG 6-1/8 OH x 4-1/2 Liner Basis Cement Vol CH volume (150 7 Liner Lap) + (OH volume x 30%) + 120 ft shoe track TOC 7 x 5 Liner Top, ~ 13500 MD Total Cement Volume Spacer 60 bbls of 11.0 ppg Tuned Spacer Cement 30% Open Hole Excess 15.0ppg: 139.2 bbls, 780.9 ft3, 604.4 sks HalCem Class G 1.292 cuft/sk BHST 75 - 85 deg F Displacement (19821 13500 120) * .0152bpf (4-1/2 capacity) + 13500 * .0103 bpf (4 dp capacity) 94.2 + 139.1 = 233.3 bbl Tail Slurry System Type 1/2 Density 15 lb/gal Yield 1.292 ft3/sk Mixed Water 5.989 gal/sk Section Calculation Vol (bbl) Vol (ft3) Vol (sks) 6-1/8" OH x 4-1/2" (19,821 - 13,649)' x 0.0168 bpf x 1.3 = 134.8 756.2 7" CH x 4-1/2" (13649 - 13500) x .0175 bpf = 2.6 14.6 4-1/2" Shoetrack 120' x 0.0152 bpf = 1.8 10.1 Total Tail 139.2 780.9 604.4 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, Schrader Bluff Oil Pool, PBU L-291 Hilcorp Alaska, LLC Permit to Drill Number: 224-002 Surface Location: 2271' FSL, 4140' FEL, Sec 34, T12N, R11E, UM, AK Bottomhole Location: 2490' FSL, 1633' FEL, Sec19, T12N, 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, Brett W. Huber, Sr. Chair, Commissioner DATED this day of March 2024. Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.03.08 09:29:18 -09'00' 8 Drilling Manager 01/08/24 Monty M Myers By Grace Christianson at 8:49 am, Jan 09, 2024 * BOPE test to 3000 psi. Annular to 2500 psi. * Casing tests and FIT digital data to AOGCC immediately upon performing FIT. * LWD gamma-ray and resistivity data to AOGCC promptly to confirm required location for TOC on 8-1/2" OH by 7" annulus. * 24 hour notice to AOGCC to witness MIT-IA to 3500 psi. * Variance to 20 AAC 25.412 (b) approved for tubing injection packer to be set greater than 200' from top of slotted liner. Tubing packer to be placed within the SB oil pool. MGR16JAN2024 50-029-23779-00-00 A.Dewhurst 05FEB24 Injection limited to water only. -A.Dewhurst 05FEB24 DSR-1/26/24 224-002 JLC 3/8/2024 Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr. Date: 2024.03.08 12:22:50 -09'00' 03/08/24 03/08/24 RBDMS JSB 031124 Well Name PTD API Status Top of Oil Pool (SB NB, MD) Top of Oil Pool (SB NB, TVD)Top of Cmt (MD) Top of Cmt (TVD) Zonal Isolation Comments L-292 223-025 50-029-23751-00 Producer 12,496' 4,072' 10,322' 3,568' Closed 7" Casing set @ 12,585' MD. Cemented in two stages. Stage 1: 90 bbls 15.8 ppg cement. Bumped plug. Lost 17 bbls during cement job. Calculated TOC w/losses and30% washout is 10,322' MD. NWE2-01 198-035 50-029-22866-00 Suspended 4,068' 4,021' 2,664' 2,664' Closed 9-5/8" casing set @ 9276' MD. Cemented in two stages. Stage 1: 90 bbls 15.8 ppg TOC est. @ 8,276' MD, good returns throughout cement job. Stage 2: Through ES cementer @ 7,418' MD 524 bbls 13.1 ppg. Bumped plug. TOC est. @ 2664' MD. PBU I-100PB1 205-010 50-029-23245-00 Abandoned Bore 7,253' 4,102' 2660' 2619' Closed 5-1/2" casing shoe set at 11,980' MD, TOL @ 9,300' MD, cemented in one stage with 157 bbls of 15.8 lead followed by 60 bbls 12.5 ppg tail. Full returns throughout cement job. Set ECP packer @ 9,300' MD. Ran 3.5" cementiing string and pumped 109 bbls 15.8 ppg Class G. POOH to 8,175' MD. Returned approx. 15 bbls cement to surface. Pumped 109 bbls Class G. POOH to 7,042' MD. Returned approx. 15 bbls cement to surface. Pumped 100 bbls 12.5 ppg cement. POOH to 4,956' MD. Returned approx. 15 bbls cement to surface. POOH to 3,426' MD. Pumped 98 bbls 15.7 ppg Class G cement. POOH to 2,087' MD. Returned approx. 10 bbls cement to surface. Washed/drilled cement from 1,964' MD to hard cement @ 2,325' MD. Drilled good cement to and KO from wellbore @ 2,660' MD. Area of Review PBU L-291i Prudhoe Bay West (PBU) L-291 Permit to Drill Application Version 1 1/2/2024 Table of Contents 1.0 Well Summary ........................................................................................................................... 2 2.0 Management of Change Information ........................................................................................ 3 3.0 Tubular Program:...................................................................................................................... 4 4.0 Drill Pipe Information: .............................................................................................................. 4 5.0 Internal Reporting Requirements ............................................................................................. 5 6.0 Planned Wellbore Schematic ..................................................................................................... 6 7.0 Drilling / Completion Summary ................................................................................................ 7 8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8 9.0 R/U and Preparatory Work ..................................................................................................... 11 10.0 N/U 13-5/8” 5M Diverter System ............................................................................................. 12 11.0 Drill 12-1/4” Hole Section ........................................................................................................ 14 12.0 Run 9-5/8” Surface Casing ...................................................................................................... 17 13.0 Cement 9-5/8” Surface Casing ................................................................................................. 23 14.0 ND Diverter, NU BOPE, & Test .............................................................................................. 28 15.0 Drill 8-1/2” Hole Section .......................................................................................................... 29 16.0 Run & Cement 7” Intermediate Casing .................................................................................. 32 17.0 Drill 6-1/8” Hole Section .......................................................................................................... 37 18.0 Run 4-1/2” Slotted Injection Liner .......................................................................................... 42 19.0 Run Upper Completion/ Post Rig Work ................................................................................. 46 20.0 Innovation Rig Diverter Schematic ......................................................................................... 49 21.0 Innovation Rig BOP Schematic ............................................................................................... 50 22.0 Wellhead Schematic ................................................................................................................. 51 23.0 Days Vs Depth .......................................................................................................................... 52 24.0 Formation Tops & Information............................................................................................... 53 25.0 Anticipated Drilling Hazards .................................................................................................. 55 26.0 Innovation Rig Layout ............................................................................................................. 61 27.0 FIT Procedure .......................................................................................................................... 62 28.0 Innovation Rig Choke Manifold Schematic ............................................................................ 63 29.0 Casing Design ........................................................................................................................... 64 30.0 MASP ....................................................................................................................................... 65 31.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 67 32.0 Surface Plat (As-Built) (NAD 27) ............................................................................................ 68 Page 2 Prudhoe Bay West L-291 SB Injector Drilling Procedure 1.0 Well Summary Well PBU L-291 Pad Prudhoe Bay L Pad Planned Completion Type 4-1/2” Injection Target Reservoir(s) Schrader Bluff NB Sand Planned Well TD, MD / TVD 19,820’ MD / 3,997’ TVD PBTD, MD / TVD 19,810’ MD / 3,997’ TVD Surface Location (Governmental) 2271' FSL, 4140' FEL, Sec 34, T12N, R11E, UM, AK Surface Location (NAD 27) X= 582,778, Y= 5,977,987 Top of Productive Horizon (Governmental)1667' FNL, 2016' FWL, Sec 29, T12N, R11E, UM, AK TPH Location (NAD 27) X=573,009, Y=5,984,507 BHL (Governmental) 2490' FSL, 1633' FWL, Sec 19, T12N, R11E, UM, AK BHL (NAD 27) X= 567,744, Y= 5,988,615 AFE Drilling Days 36 AFE Completion Days 3 Maximum Anticipated Surface Pressure (intermediate) 1381 psi Maximum Anticipated Surface Pressure (production) 1381 psi Maximum Anticipated Pressure (Downhole/Reservoir) 1788 psi Work String 5” 19.5# S-135 NC 50 Innovation KB Elevation above MSL: 26.5 ft +47.4ft =73.9ft GL Elevation above MSL: 47.4 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Prudhoe Bay West L-291 SB Injector Drilling Procedure 2.0 Management of Change Information Page 4 Prudhoe Bay West L-291 SB Injector Drilling Procedure 3.0 Tubular Program: Hole Section OD (in)ID (in) Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 20” 19.25”---X-52Weld 12-1/4”9-5/8” 8.835”8.750”10.625”40 L-80 BTC 5,750 3,090 916 9-5/8” 8.681”8.525”10.625”47 L-80 BTC 6,870 4,750 1,086 8-1/2” 7” 6.276 6.151 7.875 26 L-80 BTC 7240 5410 604 6-1/8” 4-1/2” 3.958 3.833 5.2 12.6 L-80 H563 8,430 7,500 288 Tubing 4-1/2” 3.958 3.833 5 12.6 L-80 JFE BEAR 8,430 7,500 288 4.0 Drill Pipe Information: Hole Section OD (in) ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn M/U (Min) M/U (Max) Tension (k-lbs) Surface & Intermediate 5”4.276”3.25” 6.625”19.5 S-135 DS50 36,100 43,100 560klb 5”4.276”3.25” 6.625”19.5 S-135 NC50 30,730 34,136 560klb Production 4”3.34 2.688 4.875 14 S-135 XT-39 17,700 21,200 553klb 4”3.34 2.688 4.875 14# S-135 HT-38 12,200 17,700 649klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Prudhoe Bay West L-291 SB Injector Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. Report covers operations from 6am to 6am Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry. Ensure time entry adds up to 24 hours total. Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates Submit a short operations update each work day to mmyers@hilcorp, nathan.sperry@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.3 Intranet Home Page Morning Update Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting Health and Safety: Notify EHS field coordinator. Environmental: Drilling Environmental Coordinator Notify Drilling Manager & Drilling Engineer on all incidents Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally Send final “As-Run” Casing tally to mmyers@hilcorp,com jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.6 Casing and Cement report Send casing and cement report for each string of casing to mmyers@hilcorp.com jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.7 Hilcorp Contact List: Title Name Work Phone Email Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com Completion Engineer Aras Worthington 907.440.7692 aras.worthington@hilcorp.com Geologist Kevin Eastham 907.777.8316 keastham@hilcorp.com Reservoir Engineer Natalie Brent 907.564.4313 nbrent@hilcorp.com EHS Manager Laura Green 907.777.8314 lagreen@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com Page 6 Prudhoe Bay West L-291 SB Injector Drilling Procedure 6.0 Planned Wellbore Schematic Page 7 Prudhoe Bay West L-291 SB Injector Drilling Procedure 7.0 Drilling / Completion Summary PBU L-291 is a grassroots injector planned to be drilled in the Schrader Bluff NB sands. L-291 is part of a multi-well program targeting the Schrader Bluff sand on PBU L-pad The directional plan is 12-1/4” surface hole and 9-5/8” surface casing set below the SV1. 8-1/2” intermediate hole will be drilled into the top of the Schrader Bluff NB sand, with 7” casing ran and cemented. A 6-1/8” lateral section will be drilled. A 4-1/2” slotted liner will be run in the open hole section, followed by 4-1/2” injection tubing. This well will not be pre-produced prior to being on injection. The Innovation Rig will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately February 27, 2024, pending rig schedule. Surface casing will be run to 6,915’ MD / 2,680’ TVD and cemented to surface via a two stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will then be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to one of two locations: Primary: Prudhoe G&I on Pad 4 Secondary: the Milne Point “B” pad G&I facility General sequence of operations: 1. MIRU Innovation Rig to well site 2. N/U & Test 13-5/8” Diverter and 16” diverter line 3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing 4. N/D diverter, N/U wellhead, NU 13-5/8” 5M BOP & Test 5. Drill 8-1/2” to section TD, Run and cement 7” casing 6. Drill 6-1/8” lateral to well TD 7. Run 4-1/2” liner 8. Run Upper Completion 9. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Surface & Intermediate hole: No mud logging. Remote geologist. LWD: GR + Res 2. Production Hole: No mud logging. Remote geologist. LWD: GR + ADR (For geo-steering) p This well will not be pre-produced prior to being on injection. Page 8 Prudhoe Bay West L-291 SB Injector Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that all drilling and completion operations comply with all applicable AOGCC regulations. Operations stated in this PTD application may be altered based on sound engineering judgement as wellbore conditions require, but no AOGCC regulations will be varied from without prior approval from the AOGCC. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. BOPs shall be tested at (2) week intervals during the drilling and completion of PBU L-291. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore, AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements”. o Ensure the diverter vent line is at least 75’ away from potential ignition sources Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test pressure must show stabilizing pressure and may not decline more than 10 percent within 30 minutes. The results of this test and any subsequent tests of the casing must be recorded as required by 20 AAC 25.070(1)”. Page 9 Prudhoe Bay West L-291 SB Injector Drilling Procedure AOGCC Regulation Variance Requests: Hilcorp would like to request a variance from 20 AAC 25.412.(b) which states: “A well used for injection must be equipped with tubing and a packer, or with other equipment that isolates pressure to the injection interval, unless the commission approves the operator's use of alternate means to ensure that injection of fluid is limited to the injection zone. The minimum burst pressure of the tubing must exceed the maximum surface injection pressure by at least 25 percent. The packer must be placed within 200 feet measured depth above the top of the perforations, unless the commission approves a different placement depth as the commission considers appropriate given the thickness and depth of the confining zone.” In order to effectively produce this fault block, the current wellplan has the intermediate casing shoe landing at the NB production interval at 87 degrees inclination. The production packer is planned to be set ~ 190’ MD above the liner top packer, ~ 440’ MD above the 7” casing shoe to allow for spacing of the x nipple beneath it at a pump downable depth at 77* inclination. The intermediate casing shoe is planned at ~13,649’ MD / 4147’ TVD which means the planned packer depth is ~440’ MD away. From a TVD standpoint, the production tubing packer is ~52’ TVD from the intermediate casing shoe. With the intermediate casing set in the Schrader Bluff sand, and the injection packer set inside the intermediate casing, injection fluids will be confined to the Schrader bluff sands. Page 10 Prudhoe Bay West L-291 SB Injector Drilling Procedure Summary of Innovation BOP Equipment & Test Requirements Hole Section Equipment Test Pressure (psi) 12-1/4”13-5/8” 5M CTI Annular BOP w/ 16” diverter line Function Test Only 8-1/2” & 6-1/8” 13-5/8” x 5M Control Technology Inc Annular BOP 13-5/8” x 5M Control Technology Inc Double Gate o Blind ram in btm cavity Mud cross w/ 3” x 5M side outlets 13-5/8” x 5M Control Technology Single ram 3-1/8” x 5M Choke Line 3-1/8” x 5M Kill line 3-1/8” x 5M Choke manifold Standpipe, floor valves, etc Initial Test: 250/3,000 Subsequent Tests: 250/3,000 Primary closing unit: Control Technology Inc. (CTI), 6 station, 3,000 psi, 220 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: Well control event (BOPs utilized to shut in the well to control influx of formation fluids). 24 hours notice prior to spud. 24 hours notice prior to testing BOPs. 24 hours notice prior to casing running & cement operations. Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 11 Prudhoe Bay West L-291 SB Injector Drilling Procedure 9.0 R/U and Preparatory Work 9.1 L-291 will utilize a 20” conductor on L-pad. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Ensure PTD, COAs, and drilling program are posted in the rig office and on the rig floor. 9.3 Install landing ring. 9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each. 9.5 Level pad and ensure enough room for layout of rig footprint and R/U. 9.6 Rig mat footprint of rig. 9.7 MIRU Innovation. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers WILL NOT be used on either hole section. 9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80 F). Cold mud temps are necessary to mitigate hydrate breakout 9.10 Ensure 5” liners in mud pumps. White Star Quattro 1,300 HP mud pumps are rated at 4,097 psi, 381 gpm @ 140 spm @ 96.5% volumetric efficiency. Page 12 Prudhoe Bay West L-291 SB Injector Drilling Procedure 10.0 N/U 13-5/8” 5M Diverter System 10.1 N/U 13-5/8” CTI BOP stack in diverter configuration (Diverter Schematic attached to program). N/U 20” x 13-5/8” DSA N/U 13 5/8”, 5M diverter “T”. NU Knife gate & 16” diverter line. Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). Diverter line must be 75 ft from nearest ignition source Place drip berm at the end of diverter line. Utilized extensions if needed. 10.2 Notify AOGCC with 24 hour notice to witness. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. Ensure that the annular closes in less than 30 seconds (API Standard 64 3rd edition March 2018 section 12.6.2 for packing element ID less than or equal to 20”) 10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the vent line tip. “Warning Zone” must include: A prohibition on vehicle parking A prohibition on ignition sources or running equipment A prohibition on staged equipment or materials Restriction of traffic to essential foot or vehicle traffic only. Page 13 Prudhoe Bay West L-291 SB Injector Drilling Procedure 10.4 Rig & Diverter Orientation: May change on location Page 14 Prudhoe Bay West L-291 SB Injector Drilling Procedure 11.0 Drill 12-1/4” Hole Section 11.1 P/U 12-1/4” directional drilling assembly: Ensure BHA components have been inspected previously. Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. Ensure TF offset is measured accurately and entered correctly into the MWD software. Consider running a UBHO sub for wireline gyro.GWD will be the primary gyro tool. Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Drill string will be 5” 19.5# S-135. Run a solid float in the surface hole section. 11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor. Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 11.3 Drill 12-1/4” hole section to section TD below the SV1 sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100. Hold a safety meeting with rig crews to discuss: Conductor broaching ops and mitigation procedures. Well control procedures and rig evacuation Flow rates, hole cleaning, mud cooling, etc. Pump sweeps and maintain mud rheology to ensure effective hole cleaning. Keep mud as cool as possible to keep from washing out permafrost. Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. There have been ‘directional dead zones’ noted in PBW. Directional plan has a build up in DLS from 2 – 4, to allow gradual build. If possible get ahead of build rates while still meeting tangent hold target. Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen Slow in/out of slips and while tripping to keep swab and surge pressures low Ensure shakers are functioning properly. Check for holes in screens on connections. Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off. Adjust MW and viscosity as necessary to maintain hole stability,ensure MW is at a 9.5 at base of perm and at TD. Perform gyro surveys until clean MWD surveys are seen. Take MWD surveys every stand drilled. Gas hydrates have been seen at L-Pad Page 15 Prudhoe Bay West L-291 SB Injector Drilling Procedure Take MWD and GWD surveys every stand until magnetic interference cleans up. After MWD surveys show clean magnetics, only take MWD surveys. Surface Hole AC: There are no wells with a clearance factor of <1.0 11.4 12-1/4” hole mud program summary: Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.5+ ppg. MW for free gas and hydrates based upon offset wells Depth Interval MW (ppg) Surface –Base Permafrost 8.9+ Base Permafrost - TD 9.5+ (For Hydrates/Free Gas based on offset wells) PVT System: PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action. Casing Running:Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type:8.8 – 9.8 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Page 16 Prudhoe Bay West L-291 SB Injector Drilling Procedure Surface 8.8 –9.8 75-175 20 - 40 25-45 <10 8.5 –9.0 70 F System Formulation: Gel + FW spud mud Product Concentration Fresh Water soda Ash AQUAGEL caustic soda BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT ALDACIDE G 0.905 bbl 0.5 ppb 15 - 20 ppb 0.1 ppb (8.5 – 9.0 pH) as needed as required for 8.8 – 9.2 ppg if required for <10 FL 0.1 ppb 11.5 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem sweeps and drop viscosity. Observe well for flow. 11.6 RIH to bottom, proceed to BROOH to HWDP Pump at full drill rate (400-600 gpm), and maximize rotation. Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions Monitor well for any signs of packing off or losses. Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.7 TOOH and LD BHA 11.8 No wireline logging program planned. Page 17 Prudhoe Bay West L-291 SB Injector Drilling Procedure 12.0 Run 9-5/8” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Weatherford 9-5/8” casing running equipment (CRT & Tongs) Ensure 9-5/8” BTC x NC50 XO on rig floor and M/U to FOSV. Use BOL 2000 thread compound. Dope pin end only w/ paint brush. R/U of CRT if hole conditions require. R/U a fill up tool to fill casing while running if the CRT is not used. Ensure all casing has been drifted to 8.75” on the location prior to running. Top 2,500’ of casing 47# drift 8.525” Actual depth to be dependent upon base of permafrost and stage tool Be sure to count the total # of joints on the location before running. Keep hole covered while R/U casing tools. Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking 120’ shoe track assembly consisting of: 9-5/8” Float Shoe 1 joint – 9-5/8” , 2 Centralizers 10’ from each end w/ stop rings 1 joint –9-5/8” , 1 Centralizer mid joint w/ stop ring 9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’ 1 joint – 9-5/8” , 1 Centralizer mid joint with stop ring 9-5/8” HES Baffle Adaptor Ensure bypass baffle is coreclty installed on top of float collar Ensure proper operation of float equipment while picking up. Ensure to record S/N’s of all float equipment and stage tool components. Page 18 Prudhoe Bay West L-291 SB Injector Drilling Procedure 12.5 Float Equipment and Stage tool equipment drawings Page 19 Prudhoe Bay West L-291 SB Injector Drilling Procedure 12.6 Continue running 9-5/8” surface casing Fill casing while running using fill up line on rig floor. Use BOL 2000 thread compound. Dope pin end only w/ paint brush. Centralization: Bowspring Centralizers only 1 centralizer every joint to ~ 1000’ MD from shoe 1 centralizer every 2 joints to ~ 1,000’ above shoe Utilize a collar clamp until weight is sufficient to keep slips set properly. Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 9-5/8” 47# L-80 BTC Make-Up Torques: Casing OD Minimum Optimum Maximum 9-5/8”Make Up to Triangle 9-5/8” 40# L-80 BTC Make-Up Torques: Casing OD Minimum Optimum Maximum 9-5/8”Make Up to Triangle Page 20 Prudhoe Bay West L-291 SB Injector Drilling Procedure Page 21 Prudhoe Bay West L-291 SB Injector Drilling Procedure Page 22 Prudhoe Bay West L-291 SB Injector Drilling Procedure 12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below the permafrost (~ 2,500’ MD, actual depth based upon base of permafrost) Install centralizers over couplings on 5 joints below and 5 joints above stage tool. Do not place tongs on ES cementer, this can cause damaged to the tool. Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi. 12.8 Continue running 9-5/8” surface casing Centralizers: 1 centralizer every 3rd joint to 200’ from surface Fill casing while running using fill up line on rig floor. Use BOL 2000 thread compound. Dope pin end only w/ paint brush. Centralization: o 1 centralizer every 2 joints to base of conductor 12.9 Centralizers 1/jt for 5 joints above and below stage tool. Confirm stage tool depth compatibility with cancellation plug, inclination sensitive 12.10 The last 2,500’ of 9-5/8” will be 47#, from 2,500’ to Surface Actual length of 47# may change due to depth of permafrost as drilled Ensure drifted to 8.525” 12.11 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. Slow in and out of slips. 12.12 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.13 Lower casing to setting depth. Confirm measurements. 12.14 Have slips staged in cellar, along with necessary equipment for the operation. 12.15 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 23 Prudhoe Bay West L-291 SB Injector Drilling Procedure 13.0 Cement 9-5/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses Review test reports and ensure pump times are acceptable. Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 13.5 Fill surface cement lines with water and pressure test. 13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached. 13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. Estimated 1st Stage Cement Volume: Section Calculation Vol (bbl) Vol (ft3) Vol (sks) 12-1/4" OH x 9-5/8" Casing (6,915'-1,000'-2,500') x 0.0558 bpf x 1.3 247.6 1389.3 Total Lead 247.6 1389.3 591.2 12-1/4" OH x 9-5/8" Casing 1000' x 0.0558 bpf x 1.3 = 72.5 406.8 9-5/8" Shoetrack 120' x 0.0758 bpf = 9.1 51.0 Total Tail 81.6 457.8 394.7LeadTail Page 24 Prudhoe Bay West L-291 SB Injector Drilling Procedure Cement Slurry Design (1st Stage Cement Job) 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continu with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 bps (5” liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 2500’ x 0.0732 bpf + (6,915’-120’-2500’) x .0758 bpf = = 508.7 bbls 80 bbls of tuned spacer to be left behind stage tool for preventing of contamination of cement in the annulus 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling Engineer. Lead Slurry Tail Slurry System EconoCem HalCem Density 12.0 lb/gal 15.8 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mixed Water 13.92 gal/sk 4.95 gal/sk Page 25 Prudhoe Bay West L-291 SB Injector Drilling Procedure 13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 13.15 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. Ensure the free fall stage tool opening plug is available. This is the back-up option to open the stage tool if the plugs are not bumped. 13.16 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. Page 26 Prudhoe Bay West L-291 SB Injector Drilling Procedure Second Stage Surface Cement Job 13.17 Prepare for the 2 nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety meeting. Past wells have seen pressure increase while circulating through stage tool after reduced rate 13.18 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.19 Fill surface lines with water and pressure test. 13.20 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.21 Mix and pump cmt per below recipe for the 2 nd stage. 13.22 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. Cement will continue to be pumped until clean spacer is observed at surface. Estimated 2nd Stage Total Cement Volume: Cement Slurry Design (2nd Stage): 13.23 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.24 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.25 Displacement calculation: 2500’ x 0.0732 bpf = 183 bbls mud 13.26 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. Section Calculation Vol (bbl) Vol (ft3) Vol (sks) 20" Cond x 9-5/8" Casing 110' x 0.26 bpf 28.6 160.4 12-1/4" OH x 9-5/8" Casing (2000' - 110) x .0558 x 3 316.3 1774.3 Total Lead 344.9 1934.8 763.2 12-1/4" OH x 9-5/8" Casing (2500 - 2000') x .0558 bpf x 2 55.8 313.0 Total Tail 55.8 313.0 269.9LeadTail Lead Slurry Tail Slurry System Arctic Cem HalCem Density 11.0 lb/gal 15.8 lb/gal Yield 2.535 ft3/sk 1.16 ft3/sk Mixed Water 12.2 gal/sk 5.06 gal/sk Page 27 Prudhoe Bay West L-291 SB Injector Drilling Procedure 13.27 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. 13.28 Displacement calculation: 2500’ x .0732 = 183bbl 13.29 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips. 13.30 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump. Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on wellez: Pre flush type, volume (bbls) & weight (ppg) Cement slurry type, lead or tail, volume & weight Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid Note if casing is reciprocated or rotated during the job Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure Note if pre flush or cement returns at surface & volume Note time cement in place Note calculated top of cement Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 28 Prudhoe Bay West L-291 SB Injector Drilling Procedure 14.0 ND Diverter, NU BOPE, & Test 14.1 Give AOGCC 24hr notice of BOPE test, for test witness. 14.2 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool. 14.3 NU 13-5/8” x 5M BOP as follows: BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13- 5/8” x 5M mud cross / 13-5/8” x 5M single gate Double gate ram should be dressed with 4-1/2” x 7” VBRs in top cavity,blind ram in bottom cavity. Single ram can be dressed with 2-7/8” x 5-1/2” VBRs or 5” solid body rams NU bell nipple, install flowline. Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve. 14.4 RU MPD RCD and related equipment 14.5 Run 5” BOP test plug 14.6 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. Test with 5” test joint and test VBR’s with 4-1/2” and 5” test joints Confirm test pressures with PTD Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.7 RD BOP test equipment 14.8 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.9 Mix 9.5 ppg spud mud to be used in intermediate hole 14.10 Set wearbushing in wellhead. 14.11 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole section. 14.12 Ensure 5” liners in mud pumps. Page 29 Prudhoe Bay West L-291 SB Injector Drilling Procedure 15.0 Drill 8-1/2” Hole Section 15.1 P/U 8-1/2” directional drilling assembly: RSS will be ran. Ensure BHA components have been inspected previously. Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. Ensure TF offset is measured accurately and entered correctly into the MWD software. Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Drill string will be 5” 19.5# S-135. Run a solid float in the intermediate hole section. 15.2 Drill out 9-5/8” Stage tool 15.3 TIH to TOC above the shoetrack. Note depth TOC tagged on morning report. 15.4 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.5 Drill out shoe track and 20’ of new formation. 15.6 CBU and condition mud for FIT. 15.7 Conduct FIT to 11.5 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. 11.5 ppg provides >25 bbls based on 9.5ppg MW, 8.46 ppg PP (swab kick at 8.46 ppg BHP). Email digital data for casing test and FIT to AOGCC upon completion – Melvin.rixse@alaska.gov 15.8 Drill 8-1/2” hole section to section TD in the Schrader NB sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. Efforts should be made to minimize dog legs. Keep DLS < 6 deg / 100. Hold a safety meeting with rig crews to discuss: Well control procedures Flow rates, hole cleaning, etc. Pump sweeps and maintain mud rheology to ensure effective hole cleaning. Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen. Slow in/out of slips and while tripping to keep swab and surge pressures low. Ensure shakers are functioning properly. Check for holes in screens on connections. Page 30 Prudhoe Bay West L-291 SB Injector Drilling Procedure Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a ~9.5 by TD. Intermediate Hole AC: There are no wells with a CF < 1.0 15.9 8-1/2” hole mud program summary: Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at same ppg as surface TD MW and ensure we TD with 9.5+ ppg. Depth Interval MW (ppg) Surface shoe - TD 9.5+ PVT System: PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. Rheology: Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action. Casing Running:Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type:8.8 – 9.8 ppg 6% KCl LSND Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Page 31 Prudhoe Bay West L-291 SB Injector Drilling Procedure Intermediate 8.8 –9.8 75-175 20 - 40 25-45 <10 8.5 –9.0 70 F 15.10 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem sweeps and drop viscosity. 15.11 RIH to bottom, proceed to BROOH to surface casing shoe Pump at full drill rate and maximize rotation. Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions Monitor well for any signs of packing off or losses. Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 15.12 CBU at casing shoe 15.13 TOOH and LD BHA Send LWD/GR & Res to AOGCC to confirm required TOC in the 8-1/2” x 7” OH Annulus 15.14 No wireline logging program planned Page 32 Prudhoe Bay West L-291 SB Injector Drilling Procedure 16.0 Run & Cement 7” Intermediate Casing 16.1 R/U and pull wearbushing. 16.2 R/U 7” casing running equipment (CRT & Tongs) Ensure 7” BTC x NC50 XO on rig floor and M/U to FOSV. Use BOL 2000 thread compound. Dope pin end only w/ paint brush. R/U of CRT if hole conditions require. R/U a fill up tool to fill casing while running if the CRT is not used. Ensure all casing has been drifted. Be sure to count the total # of joints on the location before running. Keep hole covered while R/U casing tools. Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. Plan to land the 7” casing on a mandrel hanger. 16.3 P/U shoe joint, visually verify no debris inside joint. 16.4 Continue M/U & thread locking 120’ shoe track assembly consisting of: 7” Float Shoe 1 joint – 7”, 2 Centralizers 10’ from each end w/ stop rings 1 joint –7”, 1 Centralizer mid joint w/ stop ring 1 joint – 7”, 1 Centralizer mid joint with stop ring 7” Float Collar 16.5 Continue running 7” intermediate casing Fill casing while running using fill up line on rig floor. Use BOL 2000 thread compound. Dope pin end only w/ paint brush. Centralization: 1 centralizer every joint to ~ 500’ MD above Schrader Bluff Utilize a collar clamp until weight is sufficient to keep slips set properly. Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. 7” 29# L-80 BTC Make-Up Torques: Casing OD Minimum Optimum Maximum 7”Make Up to Triangle Page 33 Prudhoe Bay West L-291 SB Injector Drilling Procedure Page 34 Prudhoe Bay West L-291 SB Injector Drilling Procedure 16.6 Continue running 7” casing Fill casing while running using fill up line on rig floor. Use BOL 2000 thread compound. Dope pin end only w/ paint brush. 16.7 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.8 Slow in and out of slips. 16.9 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 16.10 Lower casing to setting depth. Confirm measurements. 16.11 Have emergency slips staged along with necessary equipment for the operation. 16.12 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. 16.13 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses Review test reports and ensure pump times are acceptable. Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 16.14 Document efficiency of all possible displacement pumps prior to cement job. 16.15 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 16.16 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 16.17 Fill surface lines with water and pressure test. 16.18 Pump 60 bbls 11 ppg tuned spacer. Page 35 Prudhoe Bay West L-291 SB Injector Drilling Procedure 16.19 Mix and pump cmt per below recipe. 16.20 Cement volume based on annular volume + open hole excess (40%). Job will consist of tail, TOC brought to 500’ above Ugnu LA (Note: TOC may be adjusted if formations are found to be wet or hydrocarbon bearing.) Prognosed Ugnu LA: 10,792’ MD, Planned TOC: 10,292’ MD The four previous 3 string SB wells on L pad in this fault block (L-292, 293, 294, 295) had approved TOC 500’ MD above the Ugnu LA, uppermost significant oil Estimated Total Cement Volume: Cement Slurry Design (2nd stage cement job): 16.21 After pumping cement, drop top plug and displace cement with mud out of mud pits. Displacement: (13,649-120’) * .0383 = 518.2bbl 16.22 Monitor returns closely while displacing cement. Adjust pump rate if necessary. 16.23 Land top plug and pressure up to 500 psi over bump pressure. Bleed pressure and check floats. If floats are not holding, shut in and hold 500 psi over bump pressure until cement builds compressive strength. Ensure to report the following on wellez: Pre flush type, volume (bbls) & weight (ppg) Cement slurry type, lead or tail, volume & weight Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid Note if casing is reciprocated or rotated during the job Section Calculation Vol (bbl) Vol (ft3) Vol (sks) 8.5" OH x 7" (13,649 - 10,292)' x 0.0226 bpf x 1.4 = 106.2 595.8 7" Shoetrack 120' x 0.0372 bpf = 4.5 25.2 Total Tail 110.7 621.0 535.4Tail Tail Slurry System HalCem Density 15.8 lb/gal Yield 1.16 ft3/sk Mixed Water 5.06 gal/sk Prognosed Ugnu LA: 10,792’ MD, Planned TOC: 10,292’ MDgg The four previous 3 string SB wells on L pad in this fault block ( Page 36 Prudhoe Bay West L-291 SB Injector Drilling Procedure Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure Note if pre flush or cement returns at surface & volume Note time cement in place Note calculated top of cement Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 37 Prudhoe Bay West L-291 SB Injector Drilling Procedure 17.0 Drill 6-1/8” Hole Section 17.1 MU 6-1/8” Cleanout BHA (Milltooth Bit & 1.22° PDM) 17.2 TIH w/ 6-1/8” cleanout BHA to float collar with 4” DP 17.3 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 17.4 Drill out shoe track and 20’ of new formation. 17.5 CBU and condition mud for FIT. 17.6 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. 12.0 ppg desired to cover shoe strength for expected ECD’s. A 9.9 ppg FIT is the minimum required to drill ahead 9.9 ppg provides >25 bbls based on 9.5ppg MW, 8.46ppg PP (swabbed kick at 9.5ppg BHP) Email digital data for casing test and FIT to AOGCC upon completion – Melvin.rixse@alaska.gov 17.7 POOH and LD cleanout BHA 17.8 PU 6-1/8” directional BHA. Ensure BHA components have been inspected previously. Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. Ensure TF offset is measured accurately and entered correctly into the MWD software. Ensure MWD is RU and operational. Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. Drill string will be 4” 14# S-135 Run a ported float in the production hole section. 17.9 6-1/8” hole section mud program summary: Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Page 38 Prudhoe Bay West L-291 SB Injector Drilling Procedure Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for sufficient hole cleaning Run the centrifuge continuously while drilling the production hole, this will help with solids removal. Dump and dilute as necessary to keep drilled solids to an absolute minimum. MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type:8.9 – 9.5 ppg Baradrill-N drilling fluid Properties: Interval Density PV YP LSYP Total Solids MBT HPHT Hardness Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100 System Formulation: Product Concentration Water KCL KOH N-VIS DEXTRID LT BARACARB 5 BARACARB 25 BARACARB 50 BARACOR 700 BARASCAV D X-CIDE 207 0.955 bbl 11 ppb 0.1 ppb 1.0 – 1.5 ppb 5 ppb 4 ppb 4 ppb 2 ppb 1.0 ppb 0.5 ppb 0.015 ppb 17.10 TIH with 6-1/8” directional assembly to bottom 17.11 Install MPD RCD 17.12 Displace wellbore to 9.2 ppg Baradrill-N drilling fluid Page 39 Prudhoe Bay West L-291 SB Injector Drilling Procedure Density may change based upon TD of intermediate hole section 17.13 Begin drilling 6-1/8” hole section, on-bottom staging technique: Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K. Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 17.14 Drill 6-1/8” hole section to section TD per Geologist and Drilling Engineer. Flow Rate: 150-250 GPM, target min. AV’s 200 ft/min, 385 GPM RPM: 120+ Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection Monitor Torque and Drag with pumps on every 5 stands Monitor ECD, pump pressure & hookload trends for hole cleaning indication Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. Use ADR to stay in section. Reservoir plan is to stay in NB sand. Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. Target ROP is as fast as we can clean the hole without having to backream connections Schrader Bluff NB Concretions: 4-6% Historically MPD will be utilized to monitor pressure build up on connections. 6-1/8” Lateral A/C: There are no wells with CF < 1.0 17.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons learned and best practices. Ensure the DD is referencing their procedure. Patience is key! Getting kicked off too quickly might have been the cause of failed liner runs on past wells. If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so we have a nice place to low side. Attempt to lowside in a fast drilling interval where the wellbore is headed up. Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working string back and forth. Trough for approximately 30 minutes. Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. Page 40 Prudhoe Bay West L-291 SB Injector Drilling Procedure 17.16 At TD, CBU at least 4 times at 200 ft/min AV and rotation (120+ RPM). Pump tandem sweeps if needed Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum 17.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter cake and calcium carbonate. Circulate the well clean. Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being removed, including an increase in the loss rate. 17.18 Displace 1.5 OH + liner volume with viscosified brine. Proposed brine blend (same as used on M-16, aiming for an 8 on the 6 RPM reading) - KCl: 7.1ppb for 2% NaCl: 60.9ppg for 9.4ppg Lotorq: 1.5% Lube 776: 1.5% Soda Ash: as needed for 9.5pH Busan 1060: 0.42ppb Flo-Vis Plus: 1.25ppb Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. Monitor the returned fluids carefully while displacing to brine. 17.19 BROOH with the drilling assembly to the 7” casing shoe Circulate at full drill rate (less if losses are seen, 350 GPM minimum). Rotate at maximum RPM that can be sustained. Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as dictated by hole conditions If backreaming operations are commenced, continue backreaming to the shoe 17.20 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while BROOH. 17.21 CBU minimum two times at 7” shoe and clean casing with high vis sweeps. 17.22 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary. Page 41 Prudhoe Bay West L-291 SB Injector Drilling Procedure Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise If necessary, increase MW at shoe for any higher than expected pressure seen 17.23 POOH and LD BHA. 17.24 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit diameter is sufficient for future ball drops. Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. Page 42 Prudhoe Bay West L-291 SB Injector Drilling Procedure 18.0 Run 4-1/2” Slotted Injection Liner 18.1 Well control preparedness: In the event of an influx of formation fluids while running the injection liner, the following well control response procedure will be followed: P/U & M/U the 4” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 4-1/2” liner. Slack off and with 4” DP across the BOP, shut in ram or annular on 4” DP. Close TIW. Proceed with well kill operations. 18.2 R/U 4-1/2” liner running equipment. Ensure 4-1/2” 12.6# W563 x HT38 crossover is on rig floor and M/U to FOSV. Ensure all casing has been drifted on the deck prior to running. Be sure to count the total # of joints on the deck before running. Keep hole covered while R/U casing tools. Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 18.3 Run 4-1/2” slotted injection liner Use Tenaris approved thread compound. Dope pin end only w/ paint brush. Wipe off excess. Utilize a collar clamp until weight is sufficient to keep slips set properly. Use lift nubbins and stabbing guides for the liner run. If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint outside of the surface shoe. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm See data sheets on the next page for MU torque for the 4-1/2” liner connection Page 43 Prudhoe Bay West L-291 SB Injector Drilling Procedure Page 44 Prudhoe Bay West L-291 SB Injector Drilling Procedure 18.4 Ensure to run enough liner to provide for setting the liner hanger at ~ 10,500 MD Confirm set depth with completion engineer. 18.5 Ensure hanger/pkr will not be set in a 7” connection. AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 7” connection. 18.6 Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 18.7 M/U Baker SLZXP liner top packer to 4-1/2” liner. 18.8 Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 18.9 RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. Ensure 4” DP/HWDP has been drifted 18.10 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 18.11 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. 18.12 If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 18.13 TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 18.14 Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed 1,600 psi while circulating. Pusher tool is set at 2,100 psi with 5% shear screws but it should be discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker 18.15 Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 18.16 Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 BPM). Slow pump before the ball seats. Do not allow ball to slam into ball seat. ~ 13,500' MD Page 45 Prudhoe Bay West L-291 SB Injector Drilling Procedure 18.17 Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the SLZXP liner hanger/packer to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi to release the HRDE running tool. 18.18 Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 RPM and set down 50K again. 18.19 PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. 18.20 Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 18.21 PU pulling running tool free of the packer and displace with at max rate to wash the liner top. Pump sweeps as needed. 18.22 POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned, LD DP on the TOOH. Note: Once running tool is LD, swap to the completion AFE. Page 46 Prudhoe Bay West L-291 SB Injector Drilling Procedure 19.0 Run Upper Completion/ Post Rig Work 19.1 RU to run 4-1/2”, 12.6#, L-80 JFEBear tubing. Ensure wear bushing is pulled. Ensure 4-1/2”, L-80, 12.6#, JFEBear x NC50 crossover is on rig floor and M/U to FOSV. Ensure all tubing has been drifted in the pipe shed prior to running. Be sure to count the total # of joints in the pipe shed before running. Keep hole covered while RU casing tools. Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info. Monitor displacement from wellbore while RIH. 19.2 PU, MU and RH with the following 4-1/2” injection completion jewelry (tally to be provided by Operations Engineer): Tubing Jewelry to include: 1x X Nipple 1x X Nipple w/ sliding sleeve 1x Production Packer 1x X Nipple 1x WLEG, set as close to 7” x 4-1/2” liner xo as possible Page 47 Prudhoe Bay West L-291 SB Injector Drilling Procedure Page 48 Prudhoe Bay West L-291 SB Injector Drilling Procedure 19.3 PU and MU the 4-1/2” tubing hanger. 19.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with band/clamp summary. 19.5 Land the tubing hanger and RILDS. Lay down the landing joint. 19.6 Install 4” HP BPV. ND BOP. Install the plug off tool. 19.7 NU the tubing head adapter and NU the tree. 19.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi. 19.9 Pull the plug off tool and BPV. 19.10 Reverse circulate the well over to corrosion inhibited source water follow by 85 bbls of diesel freeze protect for both tubing and IA to 2,500’ MD. 19.11 Drop the ball & rod and complete loading tubing and hydraulically set the packer as per Halliburton’s setting procedure 19.12 Pressure up and test the tubing to 3500 psi for MIT-T with 1000 psi on the IA. Bleed off the tubing to 2000psi. Test the IA to 3500 psi for MIT-IA. Bleed off the tubing and observe DCK shear. Confirm circulation in both directions thru the sheared valve. Record and notate all pressure tests (30 minutes) on chart. i. AOGCC must be given 24hr notice for opportunity to witness this test ii. 10-426 form to be filled out and sent to AOGCC after completion, reviewed by completion engineer 19.13 Bleed both the IA and tubing to 0 psi. 19.14 Rig up jumper from IA to tubing to allow freeze protect to swap. 19.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 19.16 RDMO Innovation i. POST RIG WELL WORK 1. Slickline a. Pull ball and rod and RHC 2. Well Tie in 3. Put well on injection a. AOGCC witnessed MIT-IA once injection is stable i. 24 hour notice to AOGCC Page 49 Prudhoe Bay West L-291 SB Injector Drilling Procedure 20.0 Innovation Rig Diverter Schematic Page 50 Prudhoe Bay West L-291 SB Injector Drilling Procedure 21.0 Innovation Rig BOP Schematic Page 51 Prudhoe Bay West L-291 SB Injector Drilling Procedure 22.0 Wellhead Schematic Page 52 Prudhoe Bay West L-291 SB Injector Drilling Procedure 23.0 Days Vs Depth Page 53 Prudhoe Bay West L-291 SB Injector Drilling Procedure 24.0 Formation Tops & Information Reference Plan:COMMENTSSV5 Ice 2,0431,592.9-1519 701 8.46BPRF Water 2,7251,741.9-1668 766 8.46SV3 Gas Hydrates 3,8871,999.9-1926 880 8.46Gas Hydrates expected SV3, SV2, & SV1 sands: ~2875' - 5250' MDSV1 Gas Hydrates 5,8642,443.9-2370 1075 8.46SURF CSG PT 6,9152,679.9-2606 1179 8.46Ugnu 4A Heavy Oil 7,2662,758.9-2685 1214 8.46Possible Heavy Oil in Ugnu 4A: ~ 7400' - 7800' MDUG3 Water 8,4513,024.9-2951 1331 8.46Ugnu LA Heavy Oil 10,7933,550.9-3477 1562 8.46Possible Heavy Oil Lower Ugnu: ~11000' - 13200' MDUgnu MB Heavy Oil 11,7143,757.9-3684 1653 8.46FAULT 60' DTN THROW 12,250Likely repeat of Ugnu MBUgnu MD Heavy Oil 12,1953,865.9-3792 1701 8.46Ugnu MF Heavy Oil 12,5913,954.9-3881 1740 8.46NA Schrader Bluff 12,9394,032.9-3959 1774 8.46NB Top (Heel) Schrader Bluff Oil 13,0724,062.9-3989 1788 8.46NB (Toe) Schrader Bluff 19,8203,996.9-3923 1759 8.46= Reservoir Objectives= Possible Geo HazardsL-291 wp02ANTICIPATED FORMATION TOPS & GEOHAZARDSTOP NAMELITHOLOGYEXPECTEDFLUIDMD(FT)TVD(FT)TVDSS(FT)NORTHINGEASTINGEst.PressureGradient Page 54 Prudhoe Bay West L-291 SB Injector Drilling Procedure Page 55 Prudhoe Bay West L-291 SB Injector Drilling Procedure 25.0 Anticipated Drilling Hazards 12-1/4” Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPM’s when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Surface Hole AC: There are no wells with a clearance factor of <1.0 Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for H2S. PBU L-pad has a history of H2S on wells in all reservoirs. Page 56 Prudhoe Bay West L-291 SB Injector Drilling Procedure 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 57 Prudhoe Bay West L-291 SB Injector Drilling Procedure 8-1/2” Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: Crossing faults, known or unknown, can result in drilling into unstable formations that may impact future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared for accordingly. H2S: Treat every hole section as though it has the potential for H2S. PBU L-pad has a history of H2S on wells in all reservoirs. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 58 Prudhoe Bay West L-291 SB Injector Drilling Procedure Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen. Gas Cut Mud Gas cut mud as been seen on L pad, ensure sufficient MW is used during hole section. Ensure gas detectors are always functioning. Watch swab effect. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. Casing Running Casing running issue have been noted on L pad, gravels, stability wood chunks, etc. Watch casing run, and ensure to condition hole prior to running casing, ex: backream trouble intervals. 8-1/2” Section specific A/C: There are no wells with a clearance factor of <1.0 Page 59 Prudhoe Bay West L-291 SB Injector Drilling Procedure 6-1/8” Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: Crossing faults, known or unknown, can result in drilling into unstable formations that may impact future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared for accordingly. H2S: Treat every hole section as though it has the potential for H2S. PBU L-pad has a history of H2S on wells in all reservoirs. 4. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 5. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 6. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 60 Prudhoe Bay West L-291 SB Injector Drilling Procedure Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. 6-1/8” Lateral A/C: There are no wells with a CF <1.0 Page 61 Prudhoe Bay West L-291 SB Injector Drilling Procedure 26.0 Innovation Rig Layout Page 62 Prudhoe Bay West L-291 SB Injector Drilling Procedure 27.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 63 Prudhoe Bay West L-291 SB Injector Drilling Procedure 28.0 Innovation Rig Choke Manifold Schematic Page 64 Prudhoe Bay West L-291 SB Injector Drilling Procedure 29.0 Casing Design Page 65 Prudhoe Bay West L-291 SB Injector Drilling Procedure 30.0 MASP Page 66 Prudhoe Bay West L-291 SB Injector Drilling Procedure Page 67 Prudhoe Bay West L-291 SB Injector Drilling Procedure 31.0 Spider Plot (NAD 27) (Governmental Sections) Page 68 Prudhoe Bay West L-291 SB Injector Drilling Procedure 32.0 Surface Plat (As-Built) (NAD 27) 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. SCHRADER BLUFF OIL POOLPRUDHOE BAY X 224-002 PBU L-291 WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UN ORIN L-291Initial Class/TypeSER / PENDGeoArea890Unit11650On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2240020PRUDHOE BAY, SCHRADER BLUF OIL - 640135NA1 Permit fee attachedYes ADL028239, ADL047449, and ADL0474462 Lease number appropriateYes3 Unique well name and numberYes PRUDHOE BAY, SCHRADER BLUF OIL - 640135 - governed by 505C4 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 waitYes Governed by AIO 26B, issued May 4, 201014 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For sYes15 All wells within 1/4 mile area of review identified (For service well only)No16 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 20" 129.5# X-52 grouted to 107'18 Conductor string providedYes 3 string design. Fully cemented surface casing. Aquifer excemption.19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes Intermediate casing will have adequate cement to isolate hydrocarbon zones21 CMT vol adequate to tie-in long string to surf csgYes Intermediate casing will have adequate cement to isolate hydrocarbon zones22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes Innovation rig has adequate tankage and good trucking support.24 Adequate tankage or reserve pitNA Grassroots well.25 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan identifies no close approaches.26 Adequate wellbore separation proposedYes 16" diverter below BOPE/27 If diverter required, does it meet regulationsYes All fluids overbalanced to expected pore pressure.28 Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram stack tested to 3000 psi.29 BOPEs, do they meet regulationYes 13-5/8" , 5000 psi stack tested to 3000 psi.30 BOPE press rating appropriate; test to (put psig in comments)Yes Innovation has 2-9/16" piper ball valves, 1 manual and 1 remote hydraulic choke.31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownYes PBU L pad has H2S history. Monitoring will be required.33 Is presence of H2S gas probableYes34 Mechanical condition of wells within AOR verified (For service well only)No H2S measures required. L-Pad Orion development wells have recorded 16 to 80 ppm H2S.35 Permit can be issued w/o hydrogen sulfide measuresYes Normal pressure gradient expected (8.5 ppg or less). MPD will mitigate any abnormal pressures encountered36 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]ApprADDDate2/5/2024ApprMGRDate1/31/2024ApprADDDate2/2/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 3/8/2024