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Home My WebLink About221-010CAUTION: 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: NOT OPERABLE: MPI-07 (PTD# 2210100) - Shut In for AOGCC MIT-IA Date:Thursday, May 30, 2024 11:07:10 AM From: Ryan Thompson <Ryan.Thompson@hilcorp.com> Sent: Thursday, May 30, 2024 11:00 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Taylor Wellman <twellman@hilcorp.com> Subject: NOT OPERABLE: MPI-07 (PTD# 2210100) - Shut In for AOGCC MIT-IA Mr. Wallace – PWI well MPI-07 (PTD# 2210100) is currently shut in and will not be brought online for its scheduled 2 year MIT-IA (AA 10B.019) due this month. The well will now be classified as NOT OPERABLE and will remain shut in. A witnessed MIT-IA will be scheduled once the well is returned to injection. Please respond with any comments or concerns. Thank you, Ryan Thompson Milne / Islands Well Integrity Engineer 907-564-5005 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently 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. MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Wednesday, June 15, 2022 SUBJECT:Mechanical Integrity Tests TO: FROM:Brian Bixby P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC I-07A MILNE PT UNIT I-07A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 06/15/2022 I-07A 50-029-22602-01-00 221-010-0 W SPT 3670 2210100 1500 842 847 847 847 211 213 211 211 OTHER P Brian Bixby 5/23/2022 MITIA to 2500 psi as per AA application (known TxIA communicstion). 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:MILNE PT UNIT I-07A Inspection Date: Tubing OA Packer Depth 677 2761 2628 2609IA 45 Min 60 Min Rel Insp Num: Insp Num:mitBDB220524130847 BBL Pumped:0.7 BBL Returned:0.7 Wednesday, June 15, 2022 Page 1 of 1 9 9 9 9 9 9 9 9 9 9MITIA AA application James B. Regg Digitally signed by James B. Regg Date: 2022.06.15 12:26:09 -08'00' 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: UNDER EVALUATION: Produced Water Injector MPI-07A (PTD# 221-010) Date:Wednesday, May 25, 2022 9:30:11 AM Attachments:image001.png image002.png From: Jerimiah Galloway <Jerimiah.Galloway@hilcorp.com> Sent: Thursday, May 19, 2022 4:27 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: RE: UNDER EVALUATION: Produced Water Injector MPI-07A (PTD# 221-010) Chris, If you got a strange call this morning, my cell phone was messed up and apologies. I just wanted to touch base with you on this one. We have a leak detect log complete and are awaiting the interpretation now. The last piece to this one is to have a witnessed MIT-IA. It doesn’t look like we have an inspector available to witness until Monday. Are we ok to leave this one online until after the MIT-IA? I’ll give you a call in the morning if you have any questions. Jerimiah Jerimiah Galloway MPU/Islands Well Integrity Engineer Email: jerimiah.galloway@hilcorp.com O: (907)564-5005 C: (828)553-2537 From: Jerimiah Galloway Sent: Monday, May 9, 2022 10:56 AM To: 'Wallace, Chris D (DOA)' <chris.wallace@alaska.gov> Cc: Regg, James B (CED) <jim.regg@alaska.gov>; David Haakinson <dhaakinson@hilcorp.com> Subject: RE: UNDER EVALUATION: Produced Water Injector MPI-07A (PTD# 221-010) Chris, Per our conversation, Hilcorp is requesting a 10 day extension to the Under Evaluation period for Produced Water Injector MPI-07A (PTD# 221-010). 1. PPOT-T: Passed with no signs of communication through the wellhead. 2. MIT-IA: Passed to 2500 psi 3. Leak Detect Log: Scheduled 4. AOGCC Witnessed MIT-IA: To be scheduled after logging. Please respond if there are questions or concerns. Jerimiah Jerimiah Galloway MPU/Islands Well Integrity Engineer Email: jerimiah.galloway@hilcorp.com O: (907)564-5005 C: (828)553-2537 From: Jerimiah Galloway Sent: Tuesday, April 12, 2022 1:41 PM To: 'Wallace, Chris D (DOA)' <chris.wallace@alaska.gov> Cc: Regg, James B (CED) <jim.regg@alaska.gov>; David Haakinson <dhaakinson@hilcorp.com> Subject: UNDER EVALUATION: Produced Water Injector MPI-07A (PTD# 221-010) Mr. Wallace, Produced Water Injector MPI-07A (PTD# 221-010) inner annulus pressure rose to 840 psi and was bled to 340 psi. During a monitor period, the inner annulus pressure subsequently rose to 820 psi indicating potential TxIA communication. The well is now classified UNDER EVALUATION and is on 28 day clock for evaluation. Plan Forward: 1. PPPOT-T 2. MIT-IA 3. Engineer to evaluate further diagnostics and repair Please respond with any questions. Jerimiah Jerimiah Galloway MPU/Islands Well Integrity Engineer Email: jerimiah.galloway@hilcorp.com O: (907)564-5005 C: (828)553-2537 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 thismessage in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender'sphone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect itssystems 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. Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 05/23/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU I-07A (PTD 221-010) LEAK 05/17/2022 Please include current contact information if different from above. PTD:221-010 T36647 Kayla Junke Digitally signed by Kayla Junke Date: 2022.05.25 09:55:46 -08'00' 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: UNDER EVALUATION: Produced Water Injector MPI-07A (PTD# 221-010) Date:Wednesday, May 11, 2022 8:26:04 AM Attachments:image001.png image002.png From: Jerimiah Galloway <Jerimiah.Galloway@hilcorp.com> Sent: Monday, May 9, 2022 10:56 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; David Haakinson <dhaakinson@hilcorp.com> Subject: RE: UNDER EVALUATION: Produced Water Injector MPI-07A (PTD# 221-010) Chris, Per our conversation, Hilcorp is requesting a 10 day extension to the Under Evaluation period for Produced Water Injector MPI-07A (PTD# 221-010). 1. PPOT-T: Passed with no signs of communication through the wellhead. 2. MIT-IA: Passed to 2500 psi 3. Leak Detect Log: Scheduled 4. AOGCC Witnessed MIT-IA: To be scheduled after logging. Please respond if there are questions or concerns. Jerimiah Jerimiah Galloway MPU/Islands Well Integrity Engineer Email: jerimiah.galloway@hilcorp.com O: (907)564-5005 C: (828)553-2537 From: Jerimiah Galloway Sent: Tuesday, April 12, 2022 1:41 PM To: 'Wallace, Chris D (DOA)' <chris.wallace@alaska.gov> Cc: Regg, James B (CED) <jim.regg@alaska.gov>; David Haakinson <dhaakinson@hilcorp.com> Subject: UNDER EVALUATION: Produced Water Injector MPI-07A (PTD# 221-010) Mr. Wallace, Produced Water Injector MPI-07A (PTD# 221-010) inner annulus pressure rose to 840 psi and was bled to 340 psi. During a monitor period, the inner annulus pressure subsequently rose to 820 psi indicating potential TxIA communication. The well is now classified UNDER EVALUATION and is on 28 day clock for evaluation. Plan Forward: 1. PPPOT-T 2. MIT-IA 3. Engineer to evaluate further diagnostics and repair Please respond with any questions. Jerimiah Jerimiah Galloway MPU/Islands Well Integrity Engineer Email: jerimiah.galloway@hilcorp.com O: (907)564-5005 C: (828)553-2537 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 thismessage in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender'sphone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect itssystems 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:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: UNDER EVALUATION: Produced Water Injector MPI-07A (PTD# 221-010) Date:Friday, April 15, 2022 3:12:41 PM Attachments:image001.png image002.png From: Jerimiah Galloway <Jerimiah.Galloway@hilcorp.com> Sent: Tuesday, April 12, 2022 1:41 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; David Haakinson <dhaakinson@hilcorp.com> Subject: UNDER EVALUATION: Produced Water Injector MPI-07A (PTD# 221-010) Mr. Wallace, Produced Water Injector MPI-07A (PTD# 221-010) inner annulus pressure rose to 840 psi and was bled to 340 psi. During a monitor period, the inner annulus pressure subsequently rose to 820 psi indicating potential TxIA communication. The well is now classified UNDER EVALUATION and is on 28 day clock for evaluation. Plan Forward: 1. PPPOT-T 2. MIT-IA 3. Engineer to evaluate further diagnostics and repair Please respond with any questions. Jerimiah Jerimiah Galloway MPU/Islands Well Integrity Engineer Email: jerimiah.galloway@hilcorp.com O: (907)564-5005 C: (828)553-2537 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 thismessage in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender'sphone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect itssystems 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. Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 12/30/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU I-07A (PTD 221-010) IPROF 12/07/2021 Please include current contact information if different from above. Received By: 01/03/2022 37' (6HW By Abby Bell at 9:46 am, Jan 03, 2022 DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-029-22602-01-00Well Name/No.MILNE PT UNIT I-07ACompletion Status1WINJCompletion Date5/8/2021Permit to Drill2210100OperatorHilcorp Alaska, LLCMD7797TVD7089Current Status1WINJ8/16/2021UICYesWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:I-07APB1: ROP, DGR, ABG, ADR MD & TVD...I-07A: ROP, DGR, ABG, ADR, ALD, CTN MD & TVD, Cem EvalNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF4/1/20212500 7798 Electronic Data Set, Filename: MPU I-07A LWD Final.las34872EDDigital DataDF4/1/2021 Electronic File: MPU I-07A LWD Final MD.cgm34872EDDigital DataDF4/1/2021 Electronic File: MPU I-07A LWD Final TVD.cgm34872EDDigital DataDF4/1/2021 Electronic File: MPU I-07A Surveys.xlsx34872EDDigital DataDF4/1/2021 Electronic File: MPU I-07A_Definitive Survey Report.pdf34872EDDigital DataDF4/1/2021 Electronic File: MPU I-07A_DSR.txt34872EDDigital DataDF4/1/2021 Electronic File: MPU I-07A_GIS.txt34872EDDigital DataDF4/1/2021 Electronic File: MPU I-07A_Plan.pdf34872EDDigital DataDF4/1/2021 Electronic File: MPU I-07A_VSec.pdf34872EDDigital DataDF4/1/2021 Electronic File: MPU I-07A LWD Final MD.emf34872EDDigital DataDF4/1/2021 Electronic File: MPU I-07A LWD Final TVD.emf34872EDDigital DataDF4/1/2021 Electronic File: MPU I-07A LWD Final MD.pdf34872EDDigital DataDF4/1/2021 Electronic File: MPU I-07A LWD Final TVD.pdf34872EDDigital DataDF4/1/2021 Electronic File: MPU I-07A LWD Final MD.tif34872EDDigital DataDF4/1/2021 Electronic File: MPU I-07A LWD Final TVD.tif34872EDDigital Data0 0 2210100 MILNE PT UNIT I-07A LOG HEADERS34872LogLog Header ScansDF4/1/20212500 4178 Electronic Data Set, Filename: MPU I-07A PB1 LWD Final.las34873EDDigital DataDF4/1/2021 Electronic File: MPU I-07A PB1 LWD Final MD.cgm34873EDDigital DataMonday, August 16, 2021AOGCC Page 1 of 4MPU I-07A LWD Final.lasMPU I-07A PB1 LWD Final.las DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-029-22602-01-00Well Name/No.MILNE PT UNIT I-07ACompletion Status1WINJCompletion Date5/8/2021Permit to Drill2210100OperatorHilcorp Alaska, LLCMD7797TVD7089Current Status1WINJ8/16/2021UICYesDF4/1/2021 Electronic File: MPU I-07A PB1 LWD Final TVD.cgm34873EDDigital DataDF4/1/2021 Electronic File: MPU I-07APB1_Definitive Survey Report.pdf34873EDDigital DataDF4/1/2021 Electronic File: MPU I-07APB1_DSR.txt34873EDDigital DataDF4/1/2021 Electronic File: MPU I-07APB1_GIS.txt34873EDDigital DataDF4/1/2021 Electronic File: MPU I-07APB1_Plan.pdf34873EDDigital DataDF4/1/2021 Electronic File: MPU I-07APB1_VSec.pdf34873EDDigital DataDF4/1/2021 Electronic File: MPU I-07A PB1 LWD Final MD.emf34873EDDigital DataDF4/1/2021 Electronic File: MPU I-07A PB1 LWD Final TVD.emf34873EDDigital DataDF4/1/2021 Electronic File: MPU I-07A PB1 LWD Final MD.pdf34873EDDigital DataDF4/1/2021 Electronic File: MPU I-07A PB1 LWD Final TVD.pdf34873EDDigital DataDF4/1/2021 Electronic File: MPU I-07A PB1 LWD Final MD.tif34873EDDigital DataDF4/1/2021 Electronic File: MPU I-07A PB1 LWD Final TVD.tif34873EDDigital Data0 0 2210100 MILNE PT UNIT I-07A LOG HEADERS34873LogLog Header ScansDF5/28/20212415 2099 Electronic Data Set, Filename: MPU I-07A_CBL_SET_CIBP_FINAL_25MAR2021.las35167EDDigital DataDF5/28/2021 Electronic File: MPU I-07A_CBL_SET_CIBP_FINAL_25MAR2021.pdf35167EDDigital Data0 0 2210100 MILNE PT UNIT I-07A LOG HEADERS35167LogLog Header ScansDF7/22/20213801 4222 Electronic Data Set, Filename: Hilcorp_MPU_I-07A_GR-CCL-PERF_ConCu_R01_L003Up_HSD_UPCT.las35403EDDigital DataDF7/22/20213964 4206 Electronic Data Set, Filename: Hilcorp_MPU_I-07A_GR-CCL-PERF_ConCu_R01_L007Up_HSD_UPCT.las35403EDDigital DataDF7/22/20213934 4177 Electronic Data Set, Filename: Hilcorp_MPU_I-07A_GR-CCL-PERF_ConCu_R01_L012Up_HSD_UPCT.las35403EDDigital DataMonday, August 16, 2021AOGCC Page 2 of 4 DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-029-22602-01-00Well Name/No.MILNE PT UNIT I-07ACompletion Status1WINJCompletion Date5/8/2021Permit to Drill2210100OperatorHilcorp Alaska, LLCMD7797TVD7089Current Status1WINJ8/16/2021UICYesWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalDF7/22/20213756 4064 Electronic Data Set, Filename: Hilcorp_MPU_I-07A_GR-CCL-PERF_ConCu_R01_L017Up_HSD_UPCT.las35403EDDigital DataDF7/22/20213832 4081 Electronic Data Set, Filename: Hilcorp_MPU_I-07A_GR-CCL-PERF_ConCu_R01_L021Up_HSD_UPCT.las35403EDDigital DataDF7/22/20213708 4022 Electronic Data Set, Filename: Hilcorp_MPU_I-07A_GR-CCL-PERF_ConCu_R01_L025Up_HSD_UPCT.las35403EDDigital DataDF7/22/20213720 4006 Electronic Data Set, Filename: Hilcorp_MPU_I-07A_GR-CCL-PERF_ConCu_R01_L030Up_HSD_UPCT.las35403EDDigital DataDF7/22/2021 Electronic File: Hilcorp_MPU_I-07A_GR-CCL-PERF_8-MAY-2021.Pdf35403EDDigital DataDF7/22/2021 Electronic File: Hilcorp_MPU_I-07A_GR-CCL-PERF_ConCu_R01_L003Up_HSD_UPCT.dlis35403EDDigital DataDF7/22/2021 Electronic File: Hilcorp_MPU_I-07A_GR-CCL-PERF_ConCu_R01_L007Up_HSD_UPCT.dlis35403EDDigital DataDF7/22/2021 Electronic File: Hilcorp_MPU_I-07A_GR-CCL-PERF_ConCu_R01_L012Up_HSD_UPCT.dlis35403EDDigital DataDF7/22/2021 Electronic File: Hilcorp_MPU_I-07A_GR-CCL-PERF_ConCu_R01_L017Up_HSD_UPCT.dlis35403EDDigital DataDF7/22/2021 Electronic File: Hilcorp_MPU_I-07A_GR-CCL-PERF_ConCu_R01_L021Up_HSD_UPCT.dlis35403EDDigital DataDF7/22/2021 Electronic File: Hilcorp_MPU_I-07A_GR-CCL-PERF_ConCu_R01_L025Up_HSD_UPCT.dlis35403EDDigital DataDF7/22/2021 Electronic File: Hilcorp_MPU_I-07A_GR-CCL-PERF_ConCu_R01_L030Up_HSD_UPCT.dlis35403EDDigital Data0 0 2210100 MILNE PT UNIT I-07A LOG HEADERS35403LogLog Header Scans4/5/20213914 393411774Core Chips4/5/20213910 4169 This set from PB1. Both sets in same box.11775Core ChipsConventional CoreMonday, August 16, 2021AOGCC Page 3 of 4 DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-029-22602-01-00Well Name/No.MILNE PT UNIT I-07ACompletion Status1WINJCompletion Date5/8/2021Permit to Drill2210100OperatorHilcorp Alaska, LLCMD7797TVD7089Current Status1WINJ8/16/2021UICYesINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Compliance Reviewed By:Date:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:5/8/2021Release Date:2/2/2021Core ChipsRoutine Core AnalysisCore PhotosCore DescriptionSpecial Core AnalysisMonday, August 16, 2021AOGCC Page 4 of 4See 10-407 packet**per David Douglas' email of 9/9/21, no core photos or RCA was completedon this core.M. Guhl8/16/2021 1 Guhl, Meredith D (CED) From:David Douglas <David.Douglas@hilcorp.com> Sent:Monday, August 9, 2021 4:04 PM To:Guhl, Meredith D (CED) Subject:MPU I-07A, PTD 221-010, Core analyses? - None Available Attachments:MPU I-07A + PB1 AOGCC Core Chip Transmittal from CoreLab 04052021.pdf Hello Meredith, No photos were taken and no RCA (porosity, perm, etc.) was done on this core. CoreLabs did collect chips every foot and delivered those to the AOGCC. Please see the signed transmittal (attached) from you. Lithologic Descriptions were provided in the 10‐407. Please let me know if you have any questions or further requests. David Douglas Sr. Geotechnician | Hilcorp Alaska, LLC O: (907) 777-8337 | C: (907) 887-6339 3800 Centerpoint Drive, Suite 1400 | Anchorage, AK 99503 david.douglas@hilcorp.com From: Guhl, Meredith D (CED) <meredith.guhl@alaska.gov> Sent: Friday, August 6, 2021 8:27 AM To: David Douglas <David.Douglas@hilcorp.com> Subject: [EXTERNAL] MPU I‐07A, PTD 221‐010, Core analyses? Hi David, Is there an ETA for core analyses from MPU I‐07A, PTD 221‐010, API 50‐029‐22602‐01‐00? We are approaching 90 days since well completion, but I know that core analyses generally take a little longer. Please advise. Thanks, Meredith Meredith Guhl (she/her) Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793‐1235 CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Meredith Guhl at 907‐793‐1235 or meredith.guhl@alaska.gov. 2 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-5245 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt and return one copy of this transmittal. Received By: Date: Hilcorp North Slope, LLC Date: 07/22/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL FTP Folder Contents: Log Print Files and LAS Data Files: Well API # PTD # Log Date Log Type MPU C-04 500292080100 182-126 2/27/2021 Wipestock MPU I-07A 500292260201 221-010 5/8/2021 Perf Record MPU L-06 500292200300 190-010 5/18/2021 Wipestock MPU S-21 500292306500 202-009 6/3/2021 Perf Record MPU F-116 500292365000 219-133 1/25/2020 Perf Record MPU I-19 500292321800 204-135 4/10/2020 CCL Please include current contact information if different from above. eceived By: 07/22/2021 37' (6HW By Abby Bell at 3:14 pm, Jul 22, 2021 1 Guhl, Meredith D (CED) From:Nathan Sperry <Nathan.Sperry@hilcorp.com> Sent:Tuesday, July 6, 2021 9:41 AM To:Rixse, Melvin G (CED) Cc:Joseph Lastufka Subject:RE: [EXTERNAL] PTD 221-010, MPU I-07A, 10-407- first stage cement - TOC Attachments:[EXTERNAL] FW: PTD 221-010 Hilcorp Well I-07A - Operational Update Mel, No, this is not accurate. We pumped stage 1 across the Kuparuk and stage 2 across the Schrader Bluff. Per our conversations during the operation, we did not run the CBL across the Kuparuk cement job. We ran the CBL across the Schrader Bluff cement job. We needed 24.7 bbls of cement to obtain TOC 500’ above the Kuparuk A sands which includes 30% excess. I’m calculating that by pumping 35 bbls and including 30% excess, TOC should be ~6795’ MD. We did not see any losses prior to cementing or during the cement job. Also, FYI in case this is relevant for your notes, the Kuparuk was 100% wet. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC O: 907‐777‐8450 C: 907‐301‐8996 From: Rixse, Melvin G (CED) [mailto:melvin.rixse@alaska.gov] Sent: Thursday, July 1, 2021 11:35 AM To: Nathan Sperry <Nathan.Sperry@hilcorp.com> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: [EXTERNAL] PTD 221‐010, MPU I‐07A, 10‐407‐ first stage cement ‐ TOC Nathan, I have not seen the CBL, but for full returns TOC on first stage should be closer to 6604’ MD rather than 7,221’MD. Did the CBL really pick TOC at 7,221’ when you had full returns for the entire 35 bbl cement volume? 2 The linked image cannot be displayed. The file may have been moved, renamed, or deleted. Verify that the link points to the correct file and location. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907‐793‐1231 Office 907‐223‐3605 Cell CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907‐793‐1231 ) or (Melvin.Rixse@alaska.gov). The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. MEMORANDUM TO: Jim Regg �- P.I.Supervisor FROM: Guy Cook Petroleum Inspector NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Tuesday, June 8, 2021 SUBJECT: Mechanical Integrity Tests Mkorp Alaska, LLC 1-07A MILNE PT UNIT 1-07A Src: Inspector Reviewed By: P.I. SupryJB'i7-- Comm Well Name MILNE PT UNIT 1-07A API Well Number 50-029-22602-01-00 Inspector Name: Guy Cook Permit Number: 221-010-0 Inspection Date: 6/1/2021 IOsp Num: mitGDC210601120619 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well I-07A Type Inj w • TVD 3670 Tubing 757 • 756 PTD 2210100 Type Test SPT' Test psi 1500 IA 141 181 x 1706 1686 BBL Pumped: 1 0.7 BBL Returned: 0.7 CIA 216 - 219 _ 217 - 216 - Interval IMTAL , PIF P Notes: Initial MIT -IA per Sundry 321-148. ,. Tuesday, June 8, 2021 Page 1 of I 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): GL: 30.45' BF: Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 (ft MSL) 22.Logs Obtained: 23. BOTTOM 20" H-40 112' 9-5/8" L-80 2,507' 7" L-80 7,081' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, TUBING RECORD 3,862'3-1/2" 9.3# L-80 SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): Stg 1 L - 170 sx / T - 95 sx 24" Surface 2,522' 550 sx PF 'E', 250 sx 'G', 140 sx PF 'E' 250 sx Arctic Set (Approx.) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 5/8/2021 2339' FSL, 3906' FEL, Sec. 33, T13N, R10E, UM, AK 1000' FNL, 2109' FEL, Sec. 33, T13N, R10E, UM, AK 221-010 / 321-148 & 321-203 Milne Point Field, Schrader Bluff Oil Pool 60.55' 4,243' / 4,116' HOLE SIZE AMOUNT PULLED 50-029-22602-01-00 MPU I-07A 551465 6009453 2450' FNL, 1775' FWL, Sec. 33, T13N,R10E, UM, AK CEMENTING RECORD 6009946 SETTING DEPTH TVD 6011407 BOTTOM TOP 8-1/2" Surface 12-1/4"Surface CASING WT. PER FT.GRADE 551861 553243 TOP SETTING DEPTH MD Surface Per 20 AAC 25.283 (i)(2) attach electronic information 26# Surface DEPTH SET (MD) 3,761' / 3,670' PACKER SET (MD/TVD) 91.1# 40# 112' Surface 7,788' Gas-Oil Ratio:Choke Size: 4,243' Set CIBP Water-Bbl: PRODUCTION TEST Not on Injection Date of Test: Flow Tubing Oil-Bbl: suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary N/A ***Please see attached Schematic for details*** I-07APB1: ROP, DGR, ABG, ADR MD & TVD I-07A: ROP, DGR, ABG, ADR, ALD, CTN MD & TVD, Cement Evaluation Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl: Water-Bbl: 3/21/2021 3/9/2021 ADL 025906 83-085 1800' (Approx.) 2,522' / 2,507'N/A None 7,797' / 7,089' Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment By Meredith Guhl at 9:09 am, Jun 01, 2021 GSFD 6/24/2021 DSR-6/1/21 Completion Date 5/8/2021 HEW MGR01JULY2021 DLB 06/22/2021 RBDMS HEW 6/7/2021 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD Top of Productive Interval 3877' 3780' 3399' 3333' 3877' 3780' 3907' 3809' 3940' 3840' 3958' 3857' 4009' 3905' 4047' 3940' 4111' 3998' SB OBa 4111' 3998' 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Joe Lastufka Contact Email:joseph.lastufka@hilcorp.com Authorized Contact Phone: 777-8400 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: FORMATION TESTS Permafrost - Top This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. LOT / FIT Data Sheet, Drilling and Completion Reports, Post-Rig Work Summary, Definitive Directional Surveys, Csg and Cmt Report, Wellbore Schematic, Core Descriptions and Inventory Signature w/Date: If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. Authorized Name: Monty Myers Authorized Title: Drilling Manager Schrader Bluff NE Schrader Bluff NF Permafrost - Base 29. GEOLOGIC MARKERS (List all formations and markers encountered): Schrader Bluff OBa Formation at total depth: Schrader Bluff NB Yes No Well tested? Yes No 28. CORE DATA If yes, list intervals and formations tested, briefly summarizing test results. Attach separate pages to this form, if needed, and submit detailed test information, including reports, per 20 AAC 25.071. NAME Schrader Bluff OA Schrader Bluff NC Ungnu LA3 Schrader Bluff NA The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. INSTRUCTIONS Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. TPI (Top of Producing Interval). Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment, whichever occurs first. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment I-07APB1: #1 3910'-3919' SB NB top 3914MD, 3810TVD Oil saturated sandstone / #2 4058'-4118' SB OA top 4059MD, 3941TVD Base 4088MD, 3967TVD Oil saturated sandtone / #3 4118'-4170' SB OBa top 4126MD, 4001TVD Base 4149MD, 4019TVD Oil saturated sandstone I-07A: #1 3913'-3934' SB NB Base 3927MD, 3838TVD Oil saturated sandstone 5.30.2021Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2021.05.30 07:41:16 -08'00' Monty M Myers _____________________________________________________________________________________ Revised By: JNL 5/27/2021 SCHEMATIC Milne Point Unit Well: MPU I-07A Last Completed: 3/27/2021 PTD: 221-010 JEWELRY DETAIL No Depth Item 1 3,678’ Zenith G6 Gauge 400 Bar 150C, 2 Press 2 Temp 2 3,761’ SLB MRP Packer 3 3,819’ “Brace” XN Nipple Assy, 2.813” Bottom No-Go 4 3,830’ 3-1/2” Mule Shoe – Bottom @ 3,862’ 54,243’CIBP TD = 7,797’(MD) / TD =7,089’(TVD) 20” Orig. KB Elev.: 60.55’/ GL Elev.: 34.5’ 7” 9-5/8” CIBP @4,243’ TOC @ 3,550’ MD PBTD = 4,243’(MD)/ PBTD =4,116’(TVD) ES Cementer @ 1,616’ 5 TOC @7,441’ ELM 3/25/2021 1 2 3 4 ES Cementer @ 4,275’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1 / H-40 / N/A - Surface 115' 9-5/8” Surface 40 / L-80 / BTC 8.679 Surface 2,522’ 7" Production 26 / L-80 / TXP 6.151 Surface 7,788’ TUBING DETAIL 3-1/2” Tubing 9.3# / L-80 / EUE 2.992 Surface 3,862’ GENERAL WELL INFO API: 50-029-22602-01-00 A Sidetrack Completed: 3/27/2021 TREE & WELLHEAD Tree 2-9/16” – 5M WKM Wellhead 11” 5M FMC w/ 11” x 2-7/8” tbg. Hanger, 2.5” ‘H’ BPV profile and 8rd EUE threads top and bottom OPEN HOLE / CEMENT DETAIL 24" 250 sx Arctic Set I 12-1/4” 550 sx PF E & 250 sx Class ‘G’, 140 sx PF E 8-1/2”Stg 1 – 170 sx Class ‘G’ Stg 2 - 95 sx Class ‘G” WELL INCLINATION DETAIL Max Hole Angle = 41 deg @ 4,933’ Hole Angle through perforations = 28 deg WINDOW DETAIL Top of Window – 2522’ (TVD 2507’) Bottom of Window – 2539’ Inclination 10 deg PERFORATION DETAIL SB Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status NA 3878’ 3898’ 3781’ 3800’ 20 5/8/2021 Open NB 3908’ 3928’ 3810’ 3829’ 20 5/8/2021 Open NC 3940’ 3945’ 3945’ 3840’ 5 5/8/2021 Open NE 3958’ 3993’ 3857’ 3890’ 35 5/8/2021 Open OA 4047’ 4077’ 3940’ 3967’ 30 5/7/2021 Open OBa 4112’ 4132’ 3999’ 4017’ 20 5/7/2021 Open TOWS 2522' MD 2680' MD, Surface casing shoe PB1 TD 4,178' MD / 4,049' TVD KOP 3,657' MD / 3,572' TVD Date 3/16/2021 MPU I-07A OH Sidetrack Summary PTD: 221-010 / API: 50-029-22602-70-00 CASING AND LEAK-OFF FRACTURE TESTS Well Name:MPU I-07A Date:3/8/2021 Csg Size/Wt/Grade: Supervisor:Barber /Montague Csg Setting Depth:2,539 2,523 TVD Mud Weight:9.2 ppg LOT / FIT Press =367 psi LOT / FIT =12.00 ppg Hole Depth =2562 md Fluid Pumped=0.4 Bbls Volume Back =0.4 bbls Estimated Pump Output:0.062 Barrels/Stroke LOT / FIT DATA CASING TEST DATA Enter Strokes Enter Pressure Enter Strokes Enter Pressure Here Here Here Here ->00 ->00 ->230 ->4250 ->4105 ->8520 ->6240 ->12 770 ->8370 ->16 1040 -> ->20 1330 -> ->24 1605 -> ->28 1880 -> ->32 2155 -> ->36 2420 -> ->40 2700 -> ->44 2970 -> ->46 3110 -> -> Enter Holding Enter Holding Enter Holding Time Here Pressure Here Time Here Pressure Here ->0370 ->03110 ->1362 ->53105 ->2360 ->10 3102 ->3357 ->15 3099 ->4354 ->20 3097 ->5352 ->25 3096 ->6350 ->30 3095 ->7347 -> ->8345 -> ->9344 -> ->10 341 -> -> -> -> -> -> -> 9.625 40# L-80 0 2 4 6 8 0 4 8 12 16 20 24 28 32 36 40 44 46 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 3100 3200 3300 3400 3500 3600 3700 3800 3900 4000 0 1020304050Pressure (psi)Strokes (# of) LOT / FIT DATA CASING TEST DATA 370362360357354352350347345344341 3110 3105 3102 3099 3097 3096 3095 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 3100 3200 3300 3400 3500 3600 3700 3800 3900 4000 0 5 10 15 20 25 30Pressure (psi)Time (Minutes) LOT / FIT DATA CASING TEST DATA Activity Date Ops Summary 3/8/2021 Displace well @ 2515' MD from seawater to 9.2 Baradril mud overboarding returns. 540 gpm, 665 psi. Establish parameters @ 2515' and wash down tagging top of whipstock @ 2522' MD. Mill 8.5" window in 9-5/8" casing (bi mill assy) T/ 2534' MD. 90 rpm, 2.6k tq, 445 gpm, 445 psi, 51% flow. 110k up, 109k dn. Drilled down to 2562' putting top mill @ window. Continue mill window with same parameters F/ 2534' to final depth 2562' MD. TOW @ 2522' md, BOW @ 2539' MD. Reamed thru window 3x, tripped thru with minimal pump rate and no rotary. Saw 3-4k tripping up. Reamed 1x time and repeated tripping with no issue (clean window). Rack back to 2510' MD. Flow check (static). B/D TDS and R/U test equipment. Perform 12 ppg FIT. 9.2 MW in/out. 2523' TVD (367 psi). .4 bbls pumped, .4 bbls bled back. 1/4 bpm rate. No break over w/ final psi 342 after 10 min hold. R/D test equipment and B/D same. Chart and record same. Pump 10 bbls dry job. POOH from 2510' to surface, racking back DP and HWDP. L/D 10 excess joints HWDP, and drill collars. L/D BHA milling assembly. Lower window mill 1/8" under-gauge, upper mill in gauge. Clean and clear rig floor. M/U NOV Ander-reamer on bullnose for gauge run. RIH and tag at 250', work down to 254', setting 16K down, observe 15K overpull. Pick up and attempt to work through putting 1/8 turn each time all the way around, set down 15K with 5-8K overpull. Unable to work through tight spot. POOH and L/D BHA M/U coring drift BHA. Pick up core barrel and break out XO, M/U to lower core barrel. M/U Bit, core barrel, XO. RIH, observe 5-7 drag from 242', set down at 248' with 15K down. Pick up and attempt to work through with 1/8-1/4 turns. Unable to work though. POOH. B/O bit. RIH with core barrel to drift centralizer on core barrel to 284', observe 8-12K drag with first centralizer going past 248', and 5-8K drag as second centralizer goes through. POOH, break lower centralizer off core barrel to be milled down. L/D core barrels Pick up working single, M/U 'Johnny Whacker' - stack washing tool. Blow down choke/kill lines into stack. Flush stack. L/D Johnny Whacker. P/U and M/U 8.5" RSS drilling assembly: NOV PDC bit, 7600 Geo-Pilot, ADR collar, PWD, DM, and TM collar. Daily Disposal to G&I 404 bbls, total = 668 bbls. Daily Water from L Pad lagoon 85 bbls, total =885 bbls. Daily Mud lost 0 bbls Total Lost = 0 bbls. Daily Metal 190 lb = Total 190 lb. 3/9/2021 Cont. to M/U BHA: Upload MWD. PT Geo-span and shallow pulse test - good. Blow down top drive. RIH with HWDP, Jars. Observes up to 10K drag as BHA passes through 248'. Pick up, drift (3.125") and single in the hole with drilling assembly from 459' to 2,493'. Calculated displacement. PUW 90K, SOW 88K. Hang blocks, cut and slip 69' of drilling line. Check drawworks brake gaps, calibrate block height. Monitor well on trip tank - static. Service rig: grease crown, blocks, top drive, draw works, handling equipment and wash pipe. Check oil in top drive and weld on TD cradle - good. Fill pipe and break in Geo-Pilot. Establish parameter. Wash down to 2662' observing 7-10K through window. Drill 8-1/2" hole from 2562' to 2762' (total 200', AROP =44fph) 500 gpm, 1260 psi, 80-120 rpms, 2.5-7.5Kft- lbs, WOB 2-20K, max gas 258U ECD 9.5 ppg with 9.1 ppg mud. PUW 109K, SOW 102K, ROT 110K. Adjust parameters through slow ROP from 2758' to 2778'. Drill 8-1/2" hole from 2762' to 2994' (total 232', AROP =39fph) 550 gpm, 1520 psi, 80-120 rpms, 3-5Kft-lbs, WOB 2-20K, max gas 257U ECD 9.5 ppg with 9.1 ppg mud. PUW 115K, SOW 100K, ROT 110K. Pump bit balling sweep with nut plug and condt at 2874'. Drill 8-1/2" hole from 2994' to 3382' (total 388', AROP =65fph) 550 gpm, 1625 psi, 85 rpms, 4.5Kft-lbs, WOB 5-20K, max gas 357U ECD 9.69 ppg with 9.0 ppg mud. PUW 122K, SOW 103K, ROT 113K. Pump bit balling sweep with nut plug and condet at 3255'. Daily Disposal to G&I 171 bbls, total = 839 bbls Daily Water from L Pad lagoon 170 bbls, total =1055 bbls. Daily Mud lost 0 bbls Total = 0 bbls. Daily Metal 110 lb = Total 300 lb. Distance to WP8: 24.36', 7.23' Low, 23.26' Right. 3/10/2021 Drill 8-1/2" hole from 3382' to 3890' (total 508', AROP =85fph) 550 gpm, 1690 psi, 90 rpms, 6.7Kft-lbs, WOB 5-20K, max gas 1884U ECD 9.89 ppg with 9.0 ppg mud. PUW 130K, SOW 107K, ROT 125K. Displace on the fly to 9.0 ppg coring fluid at 3,700', treat coring fluid to ensure API FL<5.0. Slow ROP to max 50 fph, and flow 420 gpm, 945 psi at 3,823' to ensure correct formation correlation and prevent washing out hole as per coring procedure. Drill 8-1/2" hole from 3890' to 3910', coring point (total 30', AROP =30fph) 420 gpm, 1005 psi, 80 rpms, 5.6Kft-lbs, WOB 5-10K, max gas 59U ECD 9.55 ppg with 9.0 ppg mud. PUW 138K, SOW 109K, ROT 125K. At coring point, ensure cuttings clear of BHA and BROOH 2 stands to 3825'. Pump 30 bbls high viscosity sweep (10% increase, on time) and circulate 2 x bottoms up, 420 gpm, 1005 psi, 80 rpms, 5.6K ft-lbs. Monitor well, static. BROOH from 3825' to 2494' at 15-25 fpm as hole dictates. 500 gpm, 1200 psi, 60-80 rpms, 3Kft-lbs, max gas 258U, ECD 9.5 ppg with 9.0 ppg mud. PUW 103K, SOW 98K, ROTW 101K. Pull Jars and BHA through window with no rotary, just pumps 5-14K drag. Pump high vis sweep (25% increase, on time) and circulate hole clean at 500 gpm, 1200 psi 60 rpms 2.5Kft-lbs. Monitor well, static. Pump dry job. Rig service, perform derrick inspection, grease crown, blocks, top drive, iron roughneck. Replace worn U-bolt in link tilt arm. POOH racking back DP and HWDP from 2494' to 100'. Observe 10-20 drag through buckled casing at 248'. L/D BHA: download MWD, break out and check float subs. L/D TM, DM and float subs. Break off bit and rack back ADR with Geo-Pilot. Bit grade 2-2-BT-A-X-I-CT-BHA Clean and clear rig floor of BHA components. P/U and stage all coring tools and equipment on rig floor and pipe shed. M/U BHA: Core bit, milled down stabilizer, core barrel. Break off rock strong. M/U inner core barrel, ball sub to rock strong. Space out inner string. P/U and M/U 2 jnts drill collars. RIH from derrick with 6 jnts HWDP, jars, 5 jnts HWDP to 477'. Tag up on buckled casing at 250' with 14K. Pick up and work through with 7-8K drag as bit goes through and 10-15K drag with stabilizer. Pick up, drift and single in the hole with coring BHA on 5" drill pipe from 477' to 2,511'. Calculated displacement, fill pipe at 1200'. PUW 89K, SOW 92K. Fill pipe, circulate string volume at 250 gpm, 130 psi. Establish parameters PUW 109K, SOW 108K, ROT 108 K. TQ at 40rpms, 2.5Kft-lbs. Blow down top drive. RIH on elevators from 2511' to 3210', observe 6-12K drag as bit goes through window. PUW 123K, SOW 107K, calculated displacement observed. Daily Disposal to G&I 1161 bbls, total = 2000 bbls. Daily Water from L Pad lagoon 300 bbls, total =1355 bbls. Daily Mud lost 0 bbls Total = 0 bbls. Daily Metal 300 lb = Total 330 lb. Distance to WP8: 5.37', 1.71' Low, 5.09' Right. Well Name: Field: County/State: MP I-07A Milne Point Hilcorp Energy Company Composite Report , Alaska 50-029-22602-01-00API #: 3/11/2021 RIH on elevators from 3,210' to 3,846'. No issues. PUW 125K, SOW 115K. Calculated displacement observed. Circulate bottoms up at 400 gpm, 390 psi, 50 rpms, 4.5Kft-lbs. Max gas 405U. PUW 134K, SOW 112K, ROT 117K. Drop coring diverter ball. Wash down and tag bottom at 3910' with 5K. Core as per US Coring rep from 3,910' to 3,934' 220 gpm, 240 psi, 50 rpms, 5Kft-lbs, WOB 2-13K, Max Gas 68U. Observe core barrel jam at 3,934'. Drop activation ball. CBU at 400 gpm, 455 psi, max gas 1,299U. PUW 134K, SOW 112K, ROTW 117K. Monitor well, static. POOH on elevators from 3,934' to 2,420' following CoreLab trip schedule. PUW 108K, SOW 110K. Observe 5-10K drag through window. Cont. to POOH on elevators from 2,420' to 40' following CoreLab trip schedule. L/D 2 joints of drill collars. Observe 10-15K drag through buckled casing at ~250' Break off rock strong. Pull inner core tube out of core barrel, drill relieve holes to allow mud to drain. Bring up core cradle and secure inner core tube. L/d to pipe shed. M/U Rock strong. Pick up and break core bit. L/D core assembly ~9' of core recovered. Remaining core cut fell out the bottom of the barrel as indicated by oil sheen on upper part of core barrel. M/U BHA: 8.5" bit to Geopilot/ADR. M/U DM, TM, (2) float subs. RIH with 1 stand of HWDP and attempt to circulate to warm up MWD. Unable to circulate due to ice plug in Kelly hose. Service rig: grease crown, blocks, top drive, iron roughneck. Attempt to locate ice plug. Break off Kelly hose, ice plug at the gooseneck of the top drive in kelly hose. Thaw out ice plug. Upload MWD. RIH with 1 stand HWDP. PT kelly hose - good. Shallow pulse test MWD. Blow down top drive. RIH with (6) HWDP, Jars, (5) HWDP to 459'. Observe up to 15K drag going through buckled casing at 250'. RIH with RSS drilling assembly from 459' to 2494', picking up 10 joints of drill pipe. Fill pipe. PUW 111K, SOW 110K. Daily Disposal to G&I 0 bbls, total = 2000 bbls. Daily Water from L Pad lagoon 80 bbls, total =1435 bbls. Daily Mud lost 0 bbls Total = 0 bbls. Daily Metal 0 lb = Total 330 lb. 3/12/2021 Cont. to RIH with 8.5" RSS drilling assembly from 2,494' to 3,829', no issues. Observe 5-10K drag through window. PUW 133K, SOW 114K. Calculated displacement. Fill pipe, wash down from 3,829' to 3,840'. MADD pass at 50 fph from 3,840' to 3,934' at 450 gpm, 1075 psi, 60 rpms, 4.5Kft-lbs, ECD 9.51 ppg. max gas 259U. Set down 15K at 3,863', pick up and work through with no issues. Cont. Drilling 8.5" hole from 3,934' to 4,000' control drill at 50 fph max to determine coring point. 550 gpm, 1550 psi, 100 rpm, 5Kft-lbs. WOB 2-4K. ECD 9.65 ppg. max gas 549U. Cont. Drilling 8.5" hole from 4,000' to 4,058', coring point control drill at 50 fph max to determine coring point. 375 gpm, 810 psi, 60 rpm, 5.2Kft-lbs. WOB 4-10K. ECD 9.69 ppg. max gas 178U. PUW 144K, SOW 115K, ROTW 131K. BROOH 3 stands to 3890' to prevent washout. Pump high vis sweep (25% increase, on time) and circulate hole clean 500 gpm, 1395 psi, 75 rpms, 4.5Kft-lbs. Max gas 202U, ECD 9.69 ppg. PUW 128K, SOW 109K, ROT 155K. Monitor well, static. Blow down top drive. POOH on elevators from 3890' to 2494', observe 7-14K drag pulling through window. Calc displacement observed. PUW 109K, SOW 105K. CBU 1.5X at 550 gpm, 1485 psi, 80 rpms, 3.5Kft-lbs. ECD 9.63 ppg. Max gas 50U. PUW 109K, SOW 105K, ROT 104K. Monitor well, static. Pump dry job, blow down top drive. POOH from 2,494' to 86'. Observe 15K drag while pulling BHA through buckled casing at 250'. Calculated hole fill. Plug in and download MWD. Remove old pulser form TM and install new pulser. M/U float subs to TM and L/D. L/D DM, ADR, Geopilot and PDC bit. Bit grade 2-3-CT-A-X-I-BT-BHA M/U Coring BHA: Coring bit, stabilizer, (2) core barrels. Break off Rock strong. P/U and M/U inner core bbls (2). Spacer out as per US Coring. M/U rock strong, float sub. Pick up 1 jnt drill collars. RIH with 1 joint DC, (6) HWDP, Jars, (5) HWDP. Observe 10-15K drag with bit and stabilizers through buckled pipe at 250'. Cont. to RIH with coring BHA from 531' to 2502', filling pipe every 1000'. PUW 114K, SOW 112K. Fill pipe and circulate drill string volume. Obtain parameters 200 gpm, 120 pis, 50 rpms, 3.2Kft-lbs. PUW 114K, SOW 112K, ROTW 114K. Continue to RIH with coring assembly from 2502' to 4058'. Observe 5-10K drag through window. Wash down from 4028', tag fill at 4040', wash and ream from 4040' to 4058' 400 gpm, 400 psi, 40 rpms, 6.3Kft-lbs. PUW 145K, SOW 117K, ROTW 130K. Daily Disposal to G&I 57 bbls, total = 2057 bbls. Daily Water from L Pad lagoon 80 bbls, total =1515 bbls. Daily Mud lost 0 bbls Total = 0 bbls. Daily Metal 0 lb = Total 330 lb. Distance to WP 2.47', 0.89' L, 2.31' R. 3/13/2021 CBU @ 400 gpm/400 psi 40 rpm, 5Kft-lbs, reciprocating pipe. Drop coring activation ball. Core Drill from 4058’ to 4118’ w/2-4 WOB, 50 RPM, 250 GPM, 300 psi, 5- 6K Tq. @ 4118’ barrel full. Drop FCS Ball and chase on seat @ 100 gpm/120 psi. Ball on seat see 150 psi increase in pump PSI (270 psi) Increase flow rate to 200 GPM for total pump pressure of 790 psi. See sleeve collapse See sleeve collapse with 200 psi pressure loss. Pump OOH 1 stand to 4055’ @ 300 GPM/650 psi. Prior to POOH CBU @ 300 GPM/650 psi 40 rpm, 4-5k Tq. Blow down TD. POOH on elevators as per coring trip schedule from 4055' to 2439'. Observe 10-15k drag pulling stabs through window. POOH on elevators f/2439' to surface as per coring procedure trip schedule racking back DP, HWDP/Jars, and 1 std of 6.5" Spiral DC's, stop for 30 minutes at 280'. Observed 10-20k drag through buckled casing at 250'. Calculated hole fill. Break off rock strong and hook up inner core barrel. Drill relief holes in barrel while pulling to allow mud to drain. Bring up core cradle and secure to barrel. L/D both sections of inner core. 60' of core recovered. Change out activation sub on rock strong. Core bit grade 2-2-CT-X-I-PN-BHA M/U coring BHA. M/U inner core bbl 2 x and space out as per US Coring rep. M/U rock strong and float sub. Pick up and change out coring bit. RIH with (2) drill collars, (6) HWDP, jars, (5) HWDP, 20' DP pup joint to space out DP on full stand while coring. Observe 5-15K drag through buckled casing. Cont. to RIH on elevators with 5" drill pipe from 527' to 1,480'. PUW 81K, SOW 86K. Calculated displacement observed. Cont. to RIH on elevators with 5" drill pipe from 1480' to 2497', fill pipe every 1000'. PUW 115K, SOW 112K. Fill pipe, circulate drill string volume, 200 gpm, 125 psi. Blow down top drive. Service rig: Grease crown, top drive. Check fluid levels Daylight savings time. Cont. to RIH on elevators from 2497' to 4087'. Wash down and tag fill at 4,105'. Wash and ream to 4,118' at 400 gpm, 460 psi, 40 rpms, 5Kft-lbs. PUW 145K, SOW 119K, ROT 134K. Observe 5-12K as bit and stabilizers pass through window. CBU at 300 gpm, 260 psi, 30 rpms, 5K ft-lbs, reciprocating pipe. Drop activation ball. Daily Disposal to G&I 57 bbls, total = 2114 bbls. Daily Water from L Pad lagoon 70 bbls, total =1585 bbls. Daily Mud lost 0 bbls Total = 0 bbls. Daily Metal 0 lb = Total 330 lb. 3/14/2021 Finish CBU from 4118' @ 300 gpm/260 psi. Drop coring flow diverter ball. Core Drill from 4118’ to 4178’ w/2-8 WOB, 50 RPM, 250 GPM, 300 psi, 5-6K Tq. @ 4178’ barrel full. Drop FCS Ball and chase on seat @ 100 gpm/115 psi. Ball on seat see 90 psi increase in pump PSI (205 psi) Increase flow rate to 200 GPM for total pump pressure of 515 psi. See sleeve collapse with 150 psi pressure loss. Pump OOH and rack back 1 std to 4115'. CBU from 4115' @ 300 GPM/650 psi. POOH on elevators from 4115’ to surface as per coring trip schedule, racking back HWDP, jars, L/D 2 joints drill collars. Observe 5-10K drag as BHA comes through window, 10-15K drag as BHA at buckled casing. Calculated hole fill observed. Break off rock strong, hook up inner core barrel. Drill relief holes in barrel while pulling. Bring up core cradle and L/D inner barrels. L/D rock strong, float sub and outer core barrels. 51.67' of core recovered. Monitor well, static. BOLDS drain stack. Attempt to pull wear ring, pulling tight. Rinse and suck out around wear ring. Pull wear ring. Johnny whack stack. Sim Ops, Change our choke HCR valve. M/U test joint. Set test plug. Flood stack and purge air. Continue to change out choke HCR valve. Shell test BOPE - good. Test BOPE's on 5" test joint 250/4000 psi. AOGCC right to witness waived by Jeff Jones. F/P on choke manifold #14, grease, function and retest. Daily Disposal to G&I 0 bbls, total = 2114 bbls. Daily Water from L Pad lagoon 80 bbls, total =1655 bbls. Daily Mud lost 0 bbls Total = 0 bbls. Daily Metal 0 lb = Total 330 lb. 3/15/2021 Cont. to test BOPE's 250/4000 psi 5" test joint. AOGCC right to witness waived by Jeff Jones. Accumulator drawdown test: starting pressure 2950 psi, final 1500 psi. First 200psi recharge 23 seconds, full recovery 86 seconds. 6 N2 bottles at 2330 psi average. Test gas alarms, flow paddle, G/L alarms. Pull test plug and install wear ring. Break down test joint and valve assembly. Blow down lines. Pull riser and replace air boot. Rig up 3.5" running equipment, power tongs, slips, elevators RIH picking up cement stinger: 3.5" 8rnd to 712'. M/U XO and first stand of dill pipe. Circulate drill string volume. Swap elevators and rig down equipment. RIH on elevators from 712' to 2175'. PUW 82K, SOW 79K. Move HWDP from ODS to DS Cont to RIh from 2175' to 4,083'. PUW 126K, SOW 117K. CBU at window 300 gpm, 285 psi. No issues going through window. Wash down from 4,083' to 4176', tag bottom with 2K, 2' of fill. Circulate surface to surface volume at 550 gpm, 650 psi. L/D single off top of stand 55. BD top drive. Rig up for cement. M/U pump in sub, TIW and 5' pup joint. Hook up cement line and 1502 components to pump in sub. Pump balanced cement plug: PT lines to 1000/4000. Pump 22.5 bbls 10 ppg spacer at 2.8 bpm, 220 psi. 46 bbls 15.8 ppg class G cement at 3.5 bpm, 620 psi. 8.2 bbls 10 ppg spacer at 3.5 bpm, 208 psi. rig displaced with 49.6 bbls 9.4 ppg Baradril -N 6 bpm, 165 psi. CIP at 18:00 POOH from 4175' to 3280' at 25 fpm. PUW 112K, SOW 107K Establish circulation, drop drill pipe wiper ball. Circulate hole clean S-S x 1.5 at 415 gpm, 320 psi. Trace spacer observed at surface. Cont to POOH from 3280' to 712'. Move HWDP from DS to ODS. Pumped 7 bbls dry job at window. Calculated hole fill observed. Rig up Weatherford power tongs, C/O elevators. POOH laying down 3-1/2" EUE 8rd. Calc. hole fill observed. Break off mule shoe and retrieve wiper ball. R/D power tongs, pipe handling equipment. Clean and clear rig floor. Rig up to drift run 7" shoe and ES cementer. C/O pipe handling equipment. P/U and M/U shoe joint to ES cementer. RIH to 331', observe 2-3K as shoe passes buckled pipe, 10K as lower 8-1/4 OD solid body centralizer passes ~10' up from shoe (3K for other 3 centralizers), 10-15K as 8.3" OD ES cementer passes through buckled casing. POOH, observe 10K over as ES cementer pulls through buckled casing. C/O pipe handling equipment. L/D ES cementer and shoe joint. M/U BHA, 8-1/2" bit, Geopilot, ADR, ILS, DGR, PWD, DM, TM, (2) float collars. Plug in and upload. RIH 1 stand of HWDP and shallow pulse test - good. Cont. RIH with total 6 jnts HWDP, jars, 5 jnts HWDP to 459'. Observe 4K drag as bit passes through buckled casing and 18K drag as stabilizers pass. Daily Disposal to G&I 97 bbls, total = 2211 bbls. Daily Water from L Pad lagoon 165 bbls, total =1830 bbls. Daily Mud lost 0 bbls Total = 0 bbls. Daily Metal 0 lb = Total 330 lb. 3/16/2021 RIH with 8.5" RSS drilling assembly from 459' to 2430'. PUW 114K, SOW 110K. Fill pipe and break in Geo-Pilot. WOC to harden, Perform EAM's on top drive, open J box, grease crown. rig up Beyond return line to flow line. Pump through beyond lines and PT 250/1300 psi - good. Clean out rig floor drains. Remove misc XO's from rig floor. RIH on elevators from 2430' to 3240'. Observe 5-15K drag tripping through window. At 3240' set down 15K x2. PUW 115K, SOW 113K. Est. Circ., wash ream from 3240’ to 3250’ with 3-10K WOB.See weight fall off @3250’. Wash down from 3250’ set down 15k x3 @ 3608’. Drill cement from 3608’ to 3610’ with 10-15k WOB. @ 3610’ see Wt fall off. Wash down to from 3250 to 3657’. Set down 15K x3. CBU. Retag with 15K @ 3657’. TOC at 3657' Sidetrack off cement plug from 3657' to 3698' with 400 gpm, 900 psi, 80 rpms, 3.2Kft-lbs. At 3698' ABI shows 0.9° separation from old hole. max WOB 4K. Cont. Drilling 8.5" hole from 3698' to 3913', core depth. 550 gpm, 1480 psi, 70-110 rpms, 5.6Kft-lbs, WOB 3-15K, ECD 9.83 ppg, Max gas 2039U. Slow ROP to 50 fph and reduce flow to 420 gpm, 940 psi at 3826' for correlation and to prevent washout near core depth. PUW 141K, SOW 113K, ROT 128K BROOH to 3827'. Pump high vis sweep (10 bbls late, 10% increase) and circulate hole clean at 420 gpm, 910 psi, 80 rpms, 4Kft-lbs, reciprocating pipe. PUW 138K, SOW 113K. Monitor well, static. BROOH from 3765' to 3701', pump out to 3638', across sidetrack depth. Shut down pumps and RIH to 3699', no issues. Establish circulate to obtain ABI and ensure in new hole. Blow down top drive. POOH on elevators from 3699' to 2494', PUW 118K, SOW 109K. Observe 5-12K drag while BHA across window. Pump sweep (no incerase, on time) and circulate casing clean, 500 gpm, 1200 psi. Monitor well, static. Pump dry job. Blow down top drive. POOH on elevators from 2494' to 86'. Observe 10-20K drag as BHA goes through buckled casing. Daily Disposal to G&I 451 bbls, total = 2662 bbls. Daily Water from L Pad lagoon 130 bbls, total =1960 bbls. Daily Mud lost 0 bbls Total = 0 bbls. Daily Metal 0 lb = Total 330 lb. Distance to WP: 8.21', 8.18'L, 0.67'R. 3/17/2021 Continue to work BHA. Down Load tools. L/D TM & DM collars. Rack back Geo-Pilot and ADR. Bit Grade 1-1-NO-A-X-I-NO-BHA Clean and clear Rig Floor. Stage coring tools on rig floor. M/U coring BHA #4 with 30’ inner core barrel to 477’. See 10-15k as Bit and stabs pass through buckled casing @ 250’ M/U coring BHA #4 with 30’ inner core barrel. M/U 2 jts of Spiral DC's and RIH with 6 stds HWDP to 477’. See 10-15k as Bit and stabs pass through buckled casing @ 250’ TIH on elevators from 477’ to 2511’ (TOW 2522'). P/U 115k, SO 112K. Fill pipe and blow down TD every 1000'. TIH & wash last stand down tagging fill at 3902’ wash ream to 3910’ @ 400 gpm, 400 psi P/U 141K, SO 131K, Rot 121K. Space out with 5’ pup jt and P/U Single. Wash down and tag bottom at 3913’. PUH 20’ and CBU@ 400 gpm/380 psi. Drop coring diverter ball and chase @ 150 gpm/125 psi. See ball seat with 140 psi. Core Drill from 3913’ to 3935’ (22’) w/4-6 WOB, 50 RPM, 160 GPM, 145 psi, 7-8K Tq. @ 3935’ see slowing ROP, loss in Tq, 20 psi increase in pump psi. Drop FCS Ball and chase on seat @ 100 gpm/107 psi. Ball on seat see 80 psi increase in pump PSI (187 psi) Increase flow rate to 260 GPM for total pump pressure of 515 psi before Seeing sleeve closure with 260 psi pressure loss. Pump OOH to 3910’ @ 260 gpm/900 psi. L/D 5’ pup jt and single. Blow down top drive. Monitor well, static. PJSM POOH on elevators from 3910’ as per coring trip schedule. Racked back 5" D.P., 5" HWDP and Jars. L/D 2 jnts 6.5" spiral collars. Stopped for 30 min at 280' MD to allow for gas evolution. Observed 5-12K drag pulling coring BHA through window and 10-15K drag at 250' MD. PJSM Break off rock strong and P/U core barrel drilling holes to evacuate fluid from barrel as per Corelab rep onsite. P/U core cradle and secure core barrel as per Corelab rep onsite. L/D to pipe shed using tugger. Break off core bit Grade 2-3-CT-N- X-I-CT-TD. Recovered 21.25' core sample. PJSM P/U M/U RSS BHA 12. P/U GeoPilot and ADR F/ derrick. M/U RR 8.5" SK616MJ1D Bit (6X12) TFA 0.6627, Cont M/U & scribe 6 3/4" DGR, 6 3/4" PWD, 6 3/4" DM, 6 3/4" ADR, 6 3/4" ALD, 6 3/4" CTN, 6 3/4" TM & 2 ea Float Subs ( non ported plunger) to 116.29'. P/U and down load as per MWD. MWD load Nuclear sources. Perform shallow hole test 400 gpm 650 psi. Static loss 10 bbls in 6 hours. Daily Disposal to G&I 40 bbls, total = 2702 bbls. Daily Water from L Pad lagoon 80 bbls, total =2040 bbls. Daily Mud lost 0 bbls Total = 0 bbls. Daily Metal 0 lb = Total 330 lb. Distance to WP: 8.21', 8.18'L, 0.67'R. 3/18/2021 RIH with Drilling BHA from 116' to 2454' MD, See 10-20K drag through buckled pipe at 250'. Fill pipe and perform pulse test, blow down Top Drive. PJSM, Install TIW valve, space out and hang blocks, cut 11 wraps, spool on new line and Tq Deadman Anchor. Inspect brakes and calibrate blocks. Perform PM on Top Drive, Grease Top Drive and check fluid levels, grease crown, perform derrick inspection. PJSM, Pull flow riser, P/U stand of DP from Derrick and install MPD Bearing. RIH with 2518'. PJSM, Check MPD Lines/Bearing for leaks and establish clean hole parameters, GPM 400, SPP 833, RPM 60 Tq 4K, PUW 108K, SOW 92K, Rot 100K, Clean ECD 9.98. TIH on elevators f/2518' to 3859' PUW 138K, SOW 105K, 5-15K drag thru window. Wash down from 3859' to 3936'. Tag bottom on depth. Performing MADD Pass @ 100 fph from 3900' to 3936'. GPM 400, SPP 1040, RPM 80 Tq 5-6K, PUW 138K, SOW 102K, Rot 120K, Clean ECD 9.98. PJSM Drill 8.5" Production Hole F/ 3,936' to 4,683' MD ( 4,498' TVD) Total 747’ (AROP 83’) 550 GPM/ MPD 542, 1,770 PSI, 120 RPM, TRQ on 6.8K, TRQ off 5-7K, WOB 10- 20K. P/U 152K, SLK 108K, ROT 119K. Max Gas 1178U. ECD 10.27. MPD 100% open. Back ream full stand. PJSM Cont Drill 8.5" Production Hole F/ 4,683' to 5,352' MD ( 5,015' TVD) Total 669’ (AROP 112’) 550 GPM/ MPD 536, 1,940 PSI, 120 RPM, TRQ on 7K, TRQ off 6K, WOB 5-15K. P/U 155K, SLK 108K, ROT 124K. Max Gas 183U. ECD 10.65. MPD 100% open. Back ream full stand. Distance to WP5: 1.86', 1.07' High, 1.53' Left Daily Disposal to G&I 285 bbls, total = 2987 bbls. Daily Water from L Pad lagoon 160 bbls, total =2200 bbls. Daily Mud lost 12 bbls Total = 12 bbls. Daily Metal 0 lb = Total 330 lb. 3/19/2021 PJSM Cont Drill 8.5" Production Hole F/ 5,352' to 5,830' MD (5,377' TVD) Total 478’ (AROP 79.7’) 525 GPM/ MPD 513, 1,950 PSI, 120 RPM, TRQ on 7-8K, TRQ off 7K, WOB 8-15K. P/U 170K, SLK 116K, ROT 126K. Max Gas 130U. ECD 10.61. MPD 100% open. Back ream full stand. Cont Drill 8.5" Production Hole F/ 5,830' to 6,210' MD (5,667' TVD) Total 380’ (AROP 63.4’) 525 GPM/ MPD 512, 2,070 PSI, 120 RPM, TRQ on 11K, TRQ off 11.5K, WOB 14K. P/U 179K, SLK 114K, ROT 142K. Max Gas 93U. ECD 10.81. MPD 100% open. Back ream full stand. Cont Drill 8.5" Production Hole F/ 6,210' to 6,654' MD ( 6,029' TVD) Total 444’ (AROP 74’) 525 GPM/ MPD 507, 2,285 PSI, 120 RPM, TRQ on 12.5K, TRQ off 13K, WOB 15K. P/U 185K, SLK 116K, ROT 148K. Max Gas 442U. ECD 11.02. MPD 100% open. Back ream full stand. Dump 340 bbls and dilute H2O 50 bph to attempt reduce MW down F 9.55ppg.. At ~6,460' MD encountered No Diff high trq and slight packing off for ~2'. BU gas 446u pushed away ~48 bbls.. No issue since. Cont Drill 8.5" Production Hole F/ 6,654' to 6,876' MD (6,230' TVD) Total 222’ (AROP 74’) 525 GPM/ MPD 507, 2,250 PSI, 120 RPM, TRQ on 12-13K, TRQ off 11-12K, WOB 10-18K. P/U 197K, SLK 116K, ROT 148K. Max Gas 181U. ECD 11.07. MPD 100% open. Back ream full stand. Was only able to drop mud weight to 9.5 ppg W/ dump & dilute. Decision was made to pump sweep and add black product spike fluid for HRZ and perform wiper trip. PJSM Break stand and set single in mouse hole. Rot & Rec F/ 6,876' to 6,813' MD. 525 GPM/ MPD 507, 2,050 PSI, 120 RPM, TRQ 13K. Build and pump HiVis Nut Plug Sweep and add black product spike fluid. Sweep back on time W/ no increase of cuttings. Distance to WP5: 11.32', 11.01' Low, 2.62' Left Daily Disposal to G&I 746 bbls, total = 3733 bbls. Daily Water from L Pad lagoon 720 bbls, total =2920 bbls. Daily Mud lost 48 bbls Total = 60 bbls. Daily Metal 0 lb = Total 330 lb. 3/20/2021 Cont Circ adding in black product spike fluid. 525 GPM 1,900 PSI 120 RPM TRQ 11-13K. PJSM POOH on elevators F/ 6,876' to 6,132' MD started swabbing. P/U 190K SLK 165K @ 6,876' MD. Pulled 25K over at 6,460' MD wiped clean. PJSM BROOH F/ 6,132' to 4,685' MD. 525 GPM/ MPD 490 1,750 PSI 120 RPM TRQ 5- 12K P/U 169K SLK 104K ROT 110K. F/ 5,000' to 4,113' encountered Press & Trq spikes with slight packing off, slowed pulling speed and reduce pump rate. Lost 7 bbls. CBU F/ 4,113' to 4,050' MD at reaming parameters. Max Gas 104u. Attempt to pull on elevators encountered 25K overpull 2X. Cont BROOH. Cont BROOH F/ 4,050' to 3,778' MD. 525 GPM/ MPD 490 1,550 PSI 120 RPM TRQ 5-12K P/U 145K SLK 100K ROT 110K. Cont encountering Press & Trq spikes with slight packing off, slowing pulling speed and reduce pump rate. Reaming sections clean. CBU F/ 3,778' to 3,715' MD Max Gas 102u. POOH on elevators F/ 3,715' to 2,450' MD. Saw 10K drag intermittent. No over pull through window. P/U 140K SLK 100K. PJSM Service rig while circ 525/ MPD 495 GPM 1,400 PSI. Grease Blocks, Top Drive, Crown, Spinners. Electrician work on Iron Roughneck ghosting. Found loose wire in consol. PJSM TIH F/ 2,450' to 6,782' MD Fill pipe every 2,500'. P/U 183K SLK 125K. No issue TIH. PJSM Condition mud cutting WT back F/ 9.5 ppg to 9.15 ppg W/ 580 bbls 8.8 ppg black product spike fluid. 525/ MPD 484 GPM 1,650 PSI 120 RPM TRQ 10.5K P/U 183 SLK 125K ROT 150. Cont circ to smooth out wt. Max Gas 212u. PJSM Wash down F/ 6,782' to 6,876' MD Using MPD adjusting parameters to target 10.5 BHP. First attempt trop 400 PSI bled to 360 psi 5 min. Second attempt trap 344 PSI bled to 311 PSI 5 min. Discuss with town and adjust BHP to ~10.3 EMW. Hold 170-180 PSI dynamic/ 340 PSI static. PJSM Drill 8.5" Production Hole F/ 6,876' to 6,969' MD (6,137' TVD) Total 93’ (AROP 62’) 525 GPM/ MPD 507, 1,840 PSI, 120 RPM, TRQ on 10.5K, TRQ off 10K, WOB 18K. P/U 200K, SLK 115K, ROT 157K. Max Gas 123U. ECD 10.49. MPD 170-180 PSI dynamic/ 340 PSI static W/ 9.15 MW maintain 10.3 ppg BHP. Back ream full stand. PJSM Cont Drill 8.5" Production Hole F/ 6,876' to 7,333' MD (6,653 TVD) Total 457’ (AROP 76.2’) 525 GPM/ MPD 500, 2,050 PSI, 120 RPM, TRQ on 11-13K, TRQ off 10K, WOB 18-20K. P/U 207K, SLK 123K, ROT 164K. Max Gas 2,735U. ECD 10.49. MPD 120-140 PSI to maintain 10.5 ECD/ 320 PSI static W/ 9.2 MW maintain 10.2 ppg BHP. Static press bleeding down ~50 psi at 5 min. At 7,331’ MD (6,653’ TVD) encountered hard spot. Kuparuk D top at 6,636’ TVD. Working down to 30 K bit weight seeing press spikes and slight packing off. Gas spike 2,735u showing no gain, falling back to 100u quickly. Send Geo to home. Cont to attempt to work pass hard spot. Distance to WP5: 6.13', 6.02' Low, 1.14' Right Daily Disposal to G&I 972 bbls, total = 4705 bbls. Daily Water from L Pad lagoon 300 bbls, total =3220 bbls. Daily Mud lost 22 bbls Total = 82 bbls. Daily Metal 0 lb = Total 330 lb. 3/21/2021 Cont Drill 8.5" Production Hole F/ 7,333' to 7,542' MD (6,850' TVD) Total 209’ (AROP 34.8’) 525 GPM/ MPD 512, 2,070 PSI, 120-150 RPM, TRQ on 13-15K, TRQ off 12K, WOB 10-20K. P/U 218K, SLK 120K, ROT 168K. Max Gas 525U. ECD 10.49. MPD 80-120 PSI to maintain 10.5 ECD/ 320 PSI static W/ 9.3 MW Control drilling through shales @ 40 to 70 fph to mitigate excessive Tq swings. At 7481’ MD, (6725 TVD see Tq smooth out. Possibly transitioned into KUP B (Silts) formation. Added 2% lubes to mud system. PJSM Cont Drill 8.5" Production Hole F/ 7,542' to 7,662' MD (6,962' TVD) Total 120’ (AROP 80’) 525 GPM/ MPD 515, 2,090 PSI, 150 RPM, TRQ on 15-17K, TRQ off 15K, WOB 20K. P/U 218K, SLK 120K, ROT 168K. Max Gas 465U. ECD 10.46. MPD 0 PSI to maintain 10.5 ECD/ 320 PSI static W/ 9.3 MW Rot & Rec F/ 7,662' to 7,595' MD 250 GPM/ MPD 250 850 PSI 135 RPM TRQ 13K Max Gas 295U. MPD 200 PSI to maintain 10.4 ECD. Work on Shaker #1 replaced power cable due to broke. Cont Drill 8.5" Production Hole F/ 7,662' to TD 7,797' MD Called by Geo due to wet KU A2 sand (7,089' TVD) Total 135’ (AROP 54’) 525 GPM/ MPD 515, 2,090 PSI, 150 RPM, TRQ on 15-17K, TRQ off 15K, WOB 20K. P/U 222K, SLK 118K, ROT 169K. Max Gas 549U. ECD 10.39. MPD 0 PSI to maintain 10.5 ECD/ 320 PSI static W/ 9.3 MW Rot & Rec F/ 7,797' to 7,730' MD 525 GPM/ MPD 515, 2,090 PSI, 150 RPM, TRQ 13.5K. P/U 230K, SLK 120K, ROT 169K. Max Gas 428U. ECD 10.39 Pump 40 bbl HiVis sweep late 25 bbls W/ 10% increase at shakers. CBU 3X. Obtain final surveys. SPR's. Cont Rot & Rec F/ 7,797' to 7,730' MD while Beyond performs trip margin schedules W/ BHP 10.1, 10.2 & 10.3. 525 GPM/ MPD 515, 2,090 PSI, 150 RPM, TRQ 13.5K P/U 230K, SLK 120K, ROT 169K. Max Gas 200U. ECD 10.39 PJSM Blow down top drive. Isolate Pit 5. Use MP #1 through kill line at 1 bpm for MPD back Press. Hold 370 PSI static 10.4 BHP, Dynamic 340 PSI 10.1 BHP. POOH on elevators F/ 7,797' to 6,845' MD at 15 ft/min. P/U 230k SLK 120K. Lost 5 bbls for trip. Pulled clean. PJSM CBU Rot Rec F/ 6,840' to 6,782' MD 525 GPM/ MPD 515, 2,000 PSI, 100 RPM, TRQ 9-11K Max Gas 134U. ECD 10.39 W/ 125 PSI dynamic. Shut down holding 370 PSI static. Blow down top drive and line back up through kill line. MP #1 1 bpm establish MPD back Press. PJSM RIH W/ elevators F/ 6,840' to 7,743' MD. Hold 370 PSI static 10.4 BHP, Dynamic 280 PSI 10.1 BHP. Trip clean. Lost 4 bbls. Wash down F/ 7,743' to 7,797' MD at 3 bpm. Tagged up at 7,775' (22' F/ TD') setting down 20K. Cont washing down W/ 4-8K bit wt 525 GPM/ MPD 515, 2,150 PSI, 150 RPM, TRQ 12.-13.5K. Max Gas 682U. ECD 10.39. MPD holding 130 PSI dynamic. Seeing Press spikes while reaming. Weight up F/ 9.3 to 10.3 ppg in 0.3 ppg increments. Rot & Rec F/ 7,797' to 7,730' MD 525 GPM/ MPD 515, 2,000 PSI, 150 RPM, TRQ 11-13K Max Gas 35U. Reduced pump rate to 500 GPM/ MD 478 1,850 PSI first circ to 9.7 ppg stepping down MPD F/ 130 PSI to 70 PSI to maintain 10.5 ECD. Reduced pump rate to 350 GPM/MD 339 1,070 PSI 2nd circ to 10.0 ppg stepping down MPD F/ 100 PSI to full open maintain 10.55 ECD. Distance to WP5: 4.03', 0.96' Low, 3.91' Right Daily Disposal to G&I 285 bbls, total = 4990 bbls. Daily Water from L Pad lagoon 480 bbls, total =3700 bbls. Daily Mud lost 20 bbls Total = 102 bbls. Daily Metal 0 lb = Total 330 lb. 3/22/2021 Cont Weight up F/ 10.0 to 10.3 ppg in 0.3 ppg increments. Rot & Rec F/ 7,797' to 7,730' MD 300 GPM/ MPD 290, 850 PSI, 150 RPM, TRQ 11-13K Max Gas 35U. Reduced pump rate to 300 GPM/MD 290 850 PSI 3rd circ to 10.3 ppg MPD full open maintain 10.81 ECD. SPR W/ 10.3 MW Spot 55 bbl Liner running pill (12 ppb Black Product, 8 ppb SteelSeal, 4% NXS-Lube) Blow down. PJSM POOH on elevators F/ 7,797' to 6,845' MD 15 ft/min. 120 psi dynamic, static zero. 30 ft/min. F/ 6,845' to 5,448' MD Dynamic 140/0. 60 ft. min F/ 5,448' to 3,800' MD 110 psi / 0 F/ 3,800' to 2,450' 90 ft/min 100/0 following Beyond tripping schedule . P/U 219K SLK 134K off bottom. P/U 145k SLK 113K at 4,113' MD. Lost 10 bbls. 5-10 drag through shoe. CBU at 2,450' MD 375 GPM/ MPD 371 930 PSI 50 RPM TRQ 2.3K P/U 11K SLK 99K ROT 107K Max Gas 17u. Blow down top drive & GeoSpan. PJSM Remove RCD Bearing as per Beyond rep onsite. Install trip riser. Monitor well through Annulus, static. Role hole fill and check for leaks. PJSM Cont POOH racking back 5" D.P. F/2,450' to HWDP. P/U 111K SLK 99K. No losses. PJSM L/D 5" HWDP, Jars & FS. Remove Nuclear sources. Down load MWD. L/D remaining BHA components . Bit Grade 1-1-NO-A-X-I-NO-BHA Saw 15K overpull @ 334' MD and 10K drag W/ BHA through buckled 9 5/8" Csg. PJSM Shut down hole fill, drain stack BOLDS and remove wear ring. PJSM P/U Dummy run 7" Hanger and marking landing jnt as per NOS rep onsite. SIMOPS Load and process rerun 7" Csg. PJSM Install test plug. Shut Blind Rams. Bleed down Koomey. Remove VRB's and install 7" Upper solid body rams. SIMOPS Load and process rerun 7" Csg. PJSM P/U 7" test Jnt M/U head pin and M/U to test plug. Flood stack W/ H20. SIMOPS Load and process rerun 7" Csg. PJSM Test W/ 7" test jnt Annular 250/ 2500 PSI 5 min low/ 5 min high. Upper rams 250/ 4000 PSI 5 min low/ 5 min high on chart. SIMOPS Load and process rerun 7" Csg. PJSM Pull and L/D 7" test jnt. R/D test Equip. SIMOPS Load and process rerun 7" Csg. PJSM P/U Weatherford job box, air slips & Power Tongs. Remove 5" elevators and install Volant to top drive. Install 5'bail ext & 250T 7" elevators. R/U tong hydraulic lines. SIMOPS Load and process rerun 7" Csg. PJSM Cont R/U fill up line. Rearrange shoe track jnts. Clean 7" shoe track threads for Baker Loc. Install seal rings in rerun 7" Csg. Monitor well, static. PJSM P/U M/U Innovex ported shoe, 7" slick 161.57' (collars not Baker Loc pins Baker Loc) FC drop By Pass as per Halliburton rep onsite. Check floats, good. P/U BFA Shoe track 204.86'. (Baker Loc). Cont RIH W/ 7" 26# L-80 TXP/BTC F/ 204' to 1,406' MD. Filling every Jnt W/ fill up line. topping off every 10 jnts. TRQ TXP to 14,750 ft/lb. Best O Lfe 2000. Install 7" Centralizers as per tally. Observed 5-10K drag W/ shoe track going through buckled 9 5/8" Csg at 242' MD. Running speed 45 ft/min. P/U 78K SLK 76K. No losses. Daily Disposal to G&I 575 bbls, total = 5565 bbls. Daily Water from L Pad lagoon 80 bbls, total =3780 bbls. Daily Mud lost 14 bbls Total = 116 bbls. Daily Metal 0 lb = Total 330 lb. 3/23/2021 Cont RIH 7" 25# L-80 TXP/BTC Csg F/ 1,406' to 2,510' MD Run speed 45 ft/min. TRQ RXP 14,750 ft/lb. Fill every 5 jnts top off every 10 jnts. P/U 100K SLK 95K. No losses. PJSM CBU staging pumps up 1-5 bpm 165 PSI. Rot parameters 10 RPM TRQ 2.3K, 20 RPM TRQ 2.7K, 30 RPM TRQ 2.9K. no losses. Cont RIH 7" 25# L-80 TXP/BTC Csg F/ 2,510' to 4,176' MD M/U ES & Baker Loc as per Halliburton rep onsite. Install 7" Centralizers as per tally. Saw 5-10K drag shoe track at window. P/U 143K SLK 104K Lost 7 bbls. Run speed 45 ft/min. TRQ RXP 14,750 ft/lb. Fill every 5 jnts top off every 10 jnts. P/U 100K SLK 95K. Cont RIH 7" 25# L- 80 TXP/BTC Csg F/ 4,176' to 6,664' MD Run speed 45 ft/min. TRQ RXP 14,750 ft/lb. Fill every 5 jnts top off every 10 jnts. P/U 200K SLK 125K. CBU for HRZ top. Rot Rec F/ 6,664' to 6,610' MD stage pumps up F/ 1-5 bpm 480 PSI 20 RPM TRQ 9-12K RF 42%. Max Gas 625u. P/U 125K SLK 125K ROT 143K Cont RIH 7" 25# L-80 TXP/BTC Csg F/ 6,664' to 7,675' MD Run speed 25 ft/min. Wash down 2 jnts F/ 7,675' to 7,756' MD 2 bpm 340 PSI P/U 250K SLK 125K no losses. TRQ RXP 14,750 ft/lb. Fill every 5 jnts top off every 10 jnts. PJSM M/U 7" Hanger and landing joint as per NOS rep onsite. Est Circ at 3 bpm 400 PSI. Wash down 1-2 ft/min 10-15K down limiting press spike 100-200 PSI staging up to 5 bpm 700 PSI. P/U 250K SLK 125K. Landed Hanger on depth 7,787' MD. Max Gas 870u at BU. PJSM Cont Circ 5 bpm 775 PSI RF 42% no losses. Offload excess mud in pits for cement job. L/D Weatherford Power Tongs. Blow air through cement line. Stage swings and LoTrq for cement job. Shut down blow down and R/U cement lines on Volant. Break out and M/U landing jnt to ensure we can get out. Establish Circ at 5 bpm 800 PSI. No Losses. CBU 5X. PJSM Wet lines w/ 5 bbls H2O (HES) and P/T low kick out 1330/ 4162 high. Pump 1st stage cement job as follows: 51.5 bbls 11 ppg 4 bpm 700 psi. Un sting F/ Volant & drop bypass plug. Pump 35 bbls 15.8 ppg cmt 1.16 yld 3.5 bpm 816 PSI. Un sting F/ Volant & drop shutoff plug. Displace w/ 20 bbls H2O (HES) 5 bpm 790 PSI then turn over to rig. Rig disp w/ 271.2 bbls 9.5 ppg NaCl Brine 5 bpm ICP 795 PSI. Reduced rate at 20 bbls to 4 bpm 1,152 PSI and last 10 bbls 3 bpm FCP 1,600 PSI. Bump plug Press up to 2,100 PSI with 271.2 bbls actual / 270.6 bbls calculated. Held pressure for 5 minutes, check floats - good. CIP 01:00 hrs. Full returns throughout job. Pump at 2 bpm Press up to 3,400 psi ES cementer opened. PJSM Cont circulating displace 10.3 ppg Mud to 9.5 ppg Brine F/ ES at 4,275' MD 5 bpm ICP 565 PSI FCP 300 PSI. Shut down pumps and redress cup seal on Volant. Build and pump 30 bbl HiVis sweep. Returned on time W/ zero increase. No losses. SIMOPS prep pits for cement job. PJSM Wet lines w/ 5 bbls H2O (HES) Pump 2nd stage cement job as follows: Clean spacer 48 bbls 10 ppg 3 bpm 104 psi. Pump 25.5 bbls 14 ppg cmt 1.52 yld 3.2 bpm 320 PSI. Un sting F/ Volant & drop shutoff plug. Displace w/ 20 bbls H2O (HES) 5 bpm 323 PSI then turn over to rig. Rig disp w/ 141.2 bbls 9.5 ppg NaCl Brine 5 bpm ICP 160 PSI. Reduced rate at 14 bbls to 3 bpm FCP 360 PSI. Bump plug Press up to 1,620 PSI ES shifted closed with 141.2 bbls actual / 144.2 bbls calculated. CIP 05:20 hrs. Full returns throughout job. Bleed down Press. PJSM Unsting F/ landing joint. R/D cement lines and Volant. Daily Disposal to G&I 584 bbls, total = 6149 bbls. Daily Water from L Pad lagoon 0 bbls, total =3780 bbls. Daily Mud lost 7 bbls Total = 123 bbls. Daily Metal 0 lb = Total 330 lb. Activity Date Ops Summary 3/24/2021 P/U 5" HWDP and install 7" Pack Off as per NOS. RILDS. Test void 150/4000 psi 10 min.,C/O upper rams F/ 7" solid to 2 7/8" X 5 1/2" VBR's. C/U Saver Sub to HT-38.,Cont C/O Saver Sub. C/O leaking O Ring on valve block for Hyraulic elevators. Clean out Centrifuge bowls. Remove lower test plug, wear ring and X/O's F/ rig floor.,P/U 4" test jnt & set test plug. M/O X/O & head pin. Flood Stack W/ H2O. Perform shell test to 4,000 PSI. Test 2 7/8" X 5 1/2" upper & lower VBR's W/ 3.5" & 4" test jnt 250/ 4000 PSI 5/5 min, Annulus 250/2500 psi 5/5 min on chart. R/D test Equip.,Install Wear ring 9" ID 12" Ln 10.8" OD.,P/U M/U 6.125" RR Roller Cone Bit Hughes STX-1 (3X15) 0.5177 TFA & 4.75" Bit Sub. RIH W/ 20 jnts 4" HT38 HWDP & 4" 14# HT38 DP to 671' MD. Drift W/ 2.3 OD rabbit.,Service rig. Grease crown, blocks, top drive, FH-80 & spinners.,Cont RIH Clean out BHA W/ 4" D.P. F/ 671' to 4,245' MD. Fill pipe every 2,500'. P/U 108K SLK 90K. SIMOPS LRS Freeze Protect 9 5/8" X 7" Annulus bullhead 71 bbls.,Wash down F/ 4,246' to 4,263' MD 250 GPM 620 PSI Tag 8K. Wash/ Ream F/ 4,263' to 4,273' MD 250 GPM 620 PSI 80 RPM TRQ 3K ROT 103K saw green cement at BU. Drill down F/ 4,273' to 4,280' MD Max WOB 1-5K 500 ft/lb Trq spikes, seeing fine cement at shakers.,Cont drilling F/ 4,280' to 4,282' MD Started seeing fine rubber/ cement at surface. Adjusting parameters 200-250 gpm, 450-700 psi, 60-100 RPM, TRQ 2.4-3.1K, WOB 1-11K. P/U 104K SLK 79K ROT 95K. Initially seeing reactive TRQ 500-700 ft/lb fading to no reactive TRQ. No signs of packing off. Decision was made to pull the bit.,POOH racking back 4" D.P. F/ 4,282' to 609' MD. P/U 45K SLK 45K,Daily Disposal to G&I 1102 bbls, total = 7251 bbls. Daily Water from L Pad lagoon 70 bbls, total =3850 bbls. Mud lost Total = 123 bbls. 3/25/2021 Continue POOH F/ 609' to surface racking back 4" HWDP. B/O and L/D 6-1/8" milltooth (3,3,BT,A,E,2,WT,ROP).,Service rig. Grease crown, TDS and inspect derrick.,Clean and clear rig floor. Clean pits. Service handling equipment.,M/U new 6-1/8" Smith Milltooth bit. RIH w/ 10 stds 4" S-135 HWDP and continue RIH w/ HT38 4" DP to 4246' MD. 114k up, 94k dn, 104k rot.,Wash down from 4246' to tag depth 4282' MD. 200 gpm, 535 psi, 36% flow, 100 rpm, 3.3k tq. Work various parameters from 80-100 rpm, 1-8k WOB. Saw ~1k tq swings w/ 8k WOB. Drilled 1' before washing thru ES cementer clean without issue.,Circulate 1.5x btms up @ 200 gpm, 535 psi. Trip in F/ 4283' to 4497' clean.,POOH laying down 4" HT38 drill pipe F/ 4497' MD to surface. B/O and L/D bit (1,1 grade). Hole took proper displacement.,R/U Ak E-line equipment. RIH w/ Gamma, junk basket and 5.72" gauge ring to final tag depth of 7441.4' ELM. Fought intermittent obstructions F/ 4590' to btm. Tag witnessed by AOGCC rep Austin McLeod.,Flood surface Equip through Kill & Choke. Install Gauge on OA (9 5/8" X 7") IP 220 PSI. Perform Press test to 3,640 PSI 15 min 3,579 PSI 30 min 3,550 PSI on chart witnessed by AOGCC rep Austin McLeod. (Pass) Bump 3.4 bbl bled 3.4 bbl.,PJSM RIH W/ 2 3/4" Radial Sector Bond Log/ CCL. Free pipe pass 2,000'-2,500' ELM. RIH Repeat Pass 4,500-4,000' ELM 60 ft/min. Final Pass 4,500' to 2,522' ELM. At ~3,675' ELM cement top. Discuss W/ town. Carry on as per plan.,RIH CCl & 5.61” Big Boy Legacy CIBP (CCL: CIBP 9.7’) to 4,365’ ELM. (150 ft/min) Correlate up to 4,190’ ELM. RIH to 4,375’ P/U to set depth 4,243.3’ ELM. Set CIBP 820# dropped to 590# line weight. Surface line jump. Tag CIBP top at 4,253’ ELM. POOH L/D Eline.,PJSM R/U test CIBP to 3,500 PSI 10 min, good. R/D test Equip.,PJSM L/D 50 stands 5" D.P. using mouse hole to make room on rig floor for Tech Wire spool.,Daily Disposal to G&I 57 bbls, total = 7308 bbls. Daily Water from L Pad lagoon 0 bbls, total =3850 bbls. Mud lost Total = 123 bbls. 3/26/2021 L/D 67 stands of 5" DP out of derrick using mousehole.,Pull wear bushing. Clean and clear rig floor. Mob Casing and Centrilift equipment to floor. Stage 3.5" equipment in shed (142 total jts). R/U Weatherford double stack power tongs and 3.5" handling equipment.,M/U 3.5" EUE, 8rd, 9.3# Mule shoe (cut jt with full mule shoe). RIH w/ XN, packer, and gauge. Tie in Tech wire and test same (test good). RIH to 3862'. P/U M/U hanger, terminate tech wire. 3.2k tq on connections (optimum). RIH testing every 1000' PU 80K SO 76K 63 CC.,PJSM C/O 4" Bell Guide and die blocks for grabber box to 5" to make up to landing jnt.,PJSM Displace well W/ 130 bbl 9.5 ppg Inhibited NaCl Brine 6 bpm 400 PSI from Vac Truck. Shut down and land Hanger W/ 40K on Hanger.,PJSM RILDS. Remove and L/D landing jnt. NOS install BPV.,PJSM Johnny Whack Stack W/ H2O. Flush all surface Equip and blow down.,PJSM Lo/To Koomey and bleed off. Split RCD clamp and remove riser. Remove mouse hole. Start breaking bolts on Stack.,PJSM Cont N/D BOPE. Remove choke and kill lines. Install bridge cranes and remove chains F/ Stack. Break bolts F/ spacer spool & DSA. P/U and rack back Stack to pedestal. SIMOPS Load and process 5" D.P. in pipe shed. PM MP #1. Prep for rig move. Remove HT38 Saver Sub and replace W/ NC50.,PJSM NOS set RTC to BPV. Bring in and install tree adapter to well head. Bring in dry hole tree to cellar and N/U as per NOS Rep onsite.,Daily Disposal to G&I 451 bbls, total = 7759 bbls. Daily Water from L Pad lagoon 50 bbls, total =3900 bbls. Mud lost Total = 123 bbls. 3/27/2021 Cont M/U Tree. Centrilift test tech wire, good. NOS test void 500/ 5 min 5000/ 10 min. SIMOPS PM MP #1. Clean Pits. EAM Degasser. Hooch & heat tires.,R/U test Equip. Test Tree, Found leak F/ Master Valve. NOS serviced valve. Test 500/ 5 min 5000/ 10 min. R/D test Equip. Pull TWC,R/U LRS. LRS pump 84 bbl Diesel 7" X 3.5" IA taking returns back through 3.5" Tubing to cutting box, 2 bpm FCP 505 psi. Shut in R/D LRS. R/U "U" Tube manifold and let IA & tubing "U" Tube. SIMOPS C/O wash pipe.,Open Master valve, drop 1.3" ball 8' 9" OAL 5 ea 2" rollers, top roller missing. Press up to 4,171 psi saw shift at 1,400 psi. Held for 10 in 4,171-3,953 psi. Bleed to 3,500 psi hold for 30 min, good. Bleed tubing to 2,350 psi & Press up IA 7" X 3.5" to 3,500 psi for 30 min, good. All charted. Bleed off. R/D test Equip. SIMOPS C/O Wash Pipe. Bridal up. PM MP #2. Move Office Camp. Finish EAM Degasser.,PJSM Scope down Derrick. Blow down H2O. Disconnect inner connects. Prep rig floor & cellar for move. Release rig @ 18:00 hrs. Well Name: Field: County/State: MP I-07A Milne Point Hilcorp Energy Company Composite Report , Alaska 50-029-22602-01-00API #: 4,253’ ELM. f 7441.4' ELM. Well Name Rig API Number Well Permit Number Start Date End Date MP I-07A Eline 5-0029-22602-01-00 221-010 5/7/2021 5/8/2021 Arrive at wellsite, begin rigging up Eline. Rigged up, PT 250/2500psi, bleed off. Hot check, arm gun. RIH with GR-CCL-GUN (5ft PowerJet 2006, 2" OD, 6 SPF) , CCL to top shot: 3.3'. Fire gun, no change in pressure. 10# weight loss. CCL stop depth: 3936.7', zone: 3940-3945'. POOH. At surface, rig down shot gun, hot check tools, rig up/arm next gun. RIH with GR-CCL-GUN (20ft PowerJet 2006, 2" OD, 6 SPF) , CCL to top shot: 3.3'. Fire gun, slight change in pressure. 50# weight loss. CCL stop depth: 3904.7', zone: 3908-3928'. POOH. At surface, pressure gradually built to 80 psi. Rig down shot gun, hot check tools, rig up/arm next gun. RIH with GR-CCL-GUN (20ft PowerJet 2006, 2" OD, 6 SPF) , CCL to top shot: 3.3'. Fire gun, no change in pressure. 50# weight loss. CCL stop depth: 3874.7', zone: 3878-3898'. POOH. At surface, rig down shot gun, rig down lubricator and BOP, secure well. Rig down equipment, clean up and get equipment ready for mobilization back to Prudhoe. Depart wellsite. 5/8/2021 5/7/2021 Arrive at wellsite, begin spotting Eline equipment. Rigged up, PT 250/2500psi, bleed off. Rig up tools and hot check. Arm gun. RIH with GR-CCL-GUN (20ft PowerJet 2006, 2" OD, 6 SPF) , CCL to top shot: 3.3'. Tag at 4259'. Pull correlation pass. Fire gun, no change in pressure. 50# weight loss. CCL stop depth: 4108.7', zone: 4112 - 4132'. POOH. At surface, rig down shot gun, hot check tools, rig up/arm next gun. RIH with GR-CCL-GUN (30ft PowerJet 2006, 2" OD, 6 SPF) , CCL to top shot: 4.3'. Fire gun, no change in pressure. 50# weight loss. CCL stop depth: 4042.7', zone: 4047 - 4077'. POOH. At surface, rig down shot gun, hot check tools, rig up/arm next gun. RIH with GR-CCL-GUN (35ft PowerJet 2006, 2" OD, 6 SPF) , CCL to top shot: 9.3'. Fire gun, no change in pressure. 50# weight loss. CCL stop depth: 3948.7', zone: 3958 - 3993'. POOH. At surface, rig down shot gun, rig down lubricator and BOP, secure well. Clean up and depart site. Hilcorp Alaska, LLC Weekly Operations Summary TD Shoe Depth: PBTD: No. Jts. Returned RKB RKB to BHF RKB to THF Jts. 1 4 1 82 105 Yes X No Yes X No 7.1 Fluid Description: Liner hanger Info (Make/Model): Liner top Packer?: Yes X No Liner hanger test pressure:X Yes No Centralizer Placement: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp:X Yes No Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface? Yes X No Spacer returns?Yes X No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp:X Yes No Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface? Yes X No Spacer returns?Yes X No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: Cmt returned to surface: Calculated cement left in wellbore: OH volume Calculated: OH volume actual: Actual % Washout: 3/24/2021 3,408 Brine Type I-II 170 1.16 3 4,256.48 7" Csg 7 27.0 L-80 TCP/BTC Tenaris 4,225.09 4,256.48 31.39 4,277.50 4,274.80 Pup 7 26.0 L-80 TCP/BTC Tenaris 18.32 4,274.80 17.68 4,295.18 4,277.50 ES Cementer 7 5/8 TCP/BTC Halliburton 2.70 Pup 7 26.0 L-80 TCP/BTC Tenaris 7,582.96 7" Csg 7 26.0 L-80 TCP/BTC Tenaris 3,287.78 7,582.96 4,295.18 7,624.85 7,584.04 Baffle Adapter 7 5/8 TCP/BTC Halliburton 1.08 7,584.04 1.40 7,626.25 7,624.85 7" Csg 7 26.0 L-80 TCP/BTC Tenaris 40.81 Float Collar 7 5/8 TCP/BTC Innovex 7" CSG 7 26.0 L-80 TCP/BTC Tenaris 159.57 7,785.82 7,626.25 www.wellez.net WellEz Information Management LLC ver_04818br Ftg. Returned 240.00 Ftg. Cut Jt. Ftg. Balance No. Jts. Delivered 198 No. Jts. Run 192 6 Length Measurements W/O Threads Ftg. Delivered 7,920.00 Ftg. Run 7,787.00 26.05 RKB to CHF Type of Shoe:Ported Casing Crew:Weatherford 15.8 35 ES Closure OK Type I-II Type Clean Spacer 94.52 1.52 Stage Collar @ 48 Bump press 100 0 7,787.007,797.00 4,178.00 CEMENTING REPORT Csg Wt. On Slips:90,000 Baradril N 1:00 3/24/2021 7,221 4274.8 Bump press CBL Bump Plug? Y 9.5 6 141.2/144.2 271.2/270.6 2100 0 1FIRST STAGE11Clean Spacer 51.5 360 9.5 5 1620 10 14 25.5 3 100 1600 Bump Plug? Csg Wt. On Hook:250,000 Type Float Collar:Standard No. Hrs to Run:18.5 28.20 28.20 7 27.0 L-80 TCP/BTC Tenaris 28.9110 3/4 TCP/BTC 0.71 TCP/BTC Innovex 2.00 7,787.82 7,785.82 28.20 2.48 31.39 28.91 Setting Depths Component Size Wt. Grade THD Make Length Bottom Top Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.MP I-07A Date Run 23-Mar-21 CASING RECORD County State Alaska Supv.J Lott/ O Amend 7,624.85 Floats Held 30 60.5 060.5 Brine Rotate Csg Recip Csg Ft. Min. PPG10.3 Shoe @ 7787.82 FC @ Top of Liner SECOND STAGE1 5:20 CBL 32.5 60.5 RKB Casing (Or Liner) Detail Shoe Pup Hanger 7 5/8 6795' 7787.82 3,408 Volumetric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Chelsea Wright Digitally signed by Chelsea Wright Date: 2021.03.24 08:50:58 -08'00'Benjamin Hand Digitally signed by Benjamin Hand Date: 2021.03.24 10:08:56 -08'00' File No : 202006851 March 29, 2021 Core Box Core Box No No Remarks No No Remarks 1 1 3913.00 - 3916.00 62171944 1 2 3916.00 - 3919.00 62171948 1 3 3919.00 - 3922.00 62171947 1 4 3922.00 - 3925.00 62171946 1 5 3925.00 - 3928.00 62171945 1 6 3928.00 - 3931.00 62171949 1 7 3931.00 - 3934.00 62171938 1 8 3934.00 - 3934.25 62171939 Total 21.25 Depth Interval Depth Interval (ft) (ft) Hilcorp Alaska, LLC I-07A Mine Point Alaska Core Inventory Sand Mud vc cmfvfDepth (MD & -SSTVD)st cl Grav el gp Grainst. Packst.Boundst.Whackst.Mudst. Sorting Grainsize and Sedimentary Structures I-07A Core Description BI (0-6)Klinkenberg Permeability (md) Ambient Porosity (݊ Description Interpretation Net Confining Stress = 2500 psi 3,800' (-3,739') 3,820' (-3,759') 3,840' (-3,779') 3,860' (-3,799') 3,880' (-3,819') 3,900' (-3,839') 3,920' (-3,859') 3,940' (-3,879') 3,960' (-3,899') 3,980' (-3,919') 4,000' (-3,939') 4,020' (-3,959') 4,040' (-3,979') 4,060' (-3,999') 4,080' (-4,019') 4,100' (-4,039') 4,120' (-4,059') 4,140' (-4,079') 4,160' (-4,099') 4,180' (-4,119') 4,200' (-4,139') Sideritized nodule and/or cement Woody debris/wood Leaf Burrow Trace fossil Root trace Current ripple cross-laminations Wave ripple cross-laminations Climbing current ripple cross-laminations Combined ripple cross-laminations Lenticular bedding Hummocky cross-stratified Flaser bedding Trough cross-stratification Planar tabular cross-stratification Horizontal laminations Wavy/undulating laminations Soft-sediment deformation (convolute bed- ding) Coal clasts Lignite Interbeds/stringers of mud Coal parting or interbed Interbeds/stringers of ss Interbeds/stringers of siltstone Bentonite Clast (granule to pebble size) Sedimentary Structures Explanation deformed bands/ripples M Muscovite Core Plug Volcaniclastic Pebble Fracture 3929-3934 (St2-S1): Light gray, wavy beded, bioturbated siltstone inter- bedded with VFU, combined ripple-, wave ripple- laminated sandstone. Contains numerous interbeds of carbonaceous material as well. Abun- dant bioturbation with a moderate diversity throughout. Pl, Sk, Ar? 3926.1-3929 (S1): Sharp contact where bioturbation stops and higher energy traction transport structures are seen. Light gray, VFU, current ripple-, and combined ripple-laminated sandstone is interbedded with a FU, climbing ripple-laminated, and trough cross-stratified sandstone. Carbonaceous material has increased here. 3924.6-3926.1(NB Base): Dark brown, oil stained, MU, inclined, trough cross-stratified Ss interbedded with a light gray mudstone. Contains moderate amounts of carbonaceous material and coal partings. 3913-3924.6 (NB): Dark brown, oil stained, MU sometimes grading to FU, well sorted, round- to sub-angular, inclined, trough cross-stratified sandstone with pebble conglomerates. Pebble conglomerates include clay-, silt-, and coal- clast. Carbonaceous material still seen in moderate amounts. Towards 3914.5 there is a small interbed of current- to com- bined- ripple laminated siltstone. Possible bioturbation at 3913-3915. Note: As the core drys and the oil volatilizes more sedimentary struc- tures and bioturbation is noted. Even after coming back 1 day later more structures and bioturbation can now be seen. When looking at the core from the OBa to OA to NB we see overall a progradational- to aggradational- trend in which we move from a more distal to a more proximal depositional environment. With this proximal transition we see coarser sediments, more erosional truncation, larger pebble sized clasts, more common traction transport in the upper part of the lower flow regime and can thus infer a increase in the sedimen- tation rate from our OBa sand to the NB sand. Fluvial Deltaic incising into lower shoreface Lower Shoreface Lower- to Mid- Shoreface by C. Brock Rust File No : 202006851 March 29, 2021 Core Box Core Box No No Remarks No No Remarks 1 1 3910.00 - 3913.00 62171940 3 1 4117.98 - 4121.00 62171957 1 2 3913.00 - 3916.00 62171941 3 2 4121.00 - 4124.00 62171958 1 3 3916.00 - 3919.00 62171942 3 3 4124.00 - 4127.00 62171959 3 4 4127.00 - 4130.00 62171960 Total 9 3 5 4130.00 - 4133.00 62171961 3 6 4133.00 - 4136.00 62171962 2 1 4058.00 - 4061.00 62171943 3 7 4136.00 - 4139.00 62171963 2 2 4061.00 - 4064.00 62171932 3 8 4139.00 - 4142.00 62171964 2 3 4064.00 - 4067.00 62171933 3 9 4142.00 - 4145.00 62171965 2 4 4067.00 - 4070.00 62171934 3 10 4145.00 - 4148.00 62171966 2 5 4070.00 - 4073.00 62171935 3 11 4148.00 - 4151.00 62171967 2 6 4073.00 - 4076.00 62171936 3 12 4151.00 - 4154.00 62171968 2 7 4076.00 - 4079.00 62171937 3 13 4154.00 - 4157.00 62171969 2 8 4079.00 - 4082.00 62171926 3 14 4157.00 - 4160.00 62171970 2 9 4082.00 - 4085.00 62171927 3 15 4160.00 - 4163.00 62171971 2 10 4085.00 - 4088.00 62171928 3 16 4163.00 - 4166.00 62171972 2 11 4088.00 - 4091.00 62171929 3 17 4166.00 - 4169.00 62171973 2 12 4091.00 - 4094.00 62171930 3 18 4169.00 - 4169.65 62171974 2 13 4094.00 - 4097.00 62171931 2 14 4097.00 - 4100.00 62171950 Total 51.67 2 15 4100.00 - 4103.00 62171951 2 16 4103.00 - 4106.00 62171952 2 17 4106.00 - 4109.00 62171953 2 18 4109.00 - 4112.00 62171954 2 19 4112.00 - 4115.00 62171955 2 20 4115.00 - 4117.98 62171956 Total 59.98 Depth Interval Depth Interval (ft) (ft) Hilcorp Alaska, LLC I-07A BP01 Mine Point Alaska Core Inventory Sand Mud vc cmfvfDepth (MD & -SSTVD)st cl Grav el gp Grainst. Packst.Boundst.Whackst.Mudst. Sorting Grainsize and Sedimentary Structures I-07A PB1 Core Description BI (0-6)KlinkenbergPermeability (md) AmbientPorosity (݊ Description Interpretation Net Confining Stress = 2500 psi 3,840'(-3,659') 3,860'(-3,679') 3,880'(-3,699') 3,900'(-3,719') 3,920'(-3,739') 3,940'(-3,759') 3,960'(-3,779') 3,980'(-3,799') 4,000'(-3,819') 4,020'(-3,839') 4,040'(-3,859') 4,060(-3,879') 4,080'(-3,899') 4,100'(-3,919') 4,120'(-3,939') 4,140'(-3,959') 4,160'(-3,979') 4149.3-4169.65(M1-St1-S1): Dark- to light- gray, lentincular laminated mudstone coarsening upwards to siltstone with interbeds of VFL wave ripple cross-laminated ss. Common Ph and Pl. Where sand is present it is oil stained. 4145.2-4149.3 (OBa Base/S2-M1): Oil stained-brown, FU, wave ripple, hummocky-swaley, and amalgamated swaley cross-stratified ss with interbeds of bioturbated mudstone with a sharp basal contact. Biotur- bation common in both ss and mudstone with moderate diveristy and high abundance. Ph, Ch (mustone), and Pl. Core GR does not pick up true base of OBa sand. Offshore Marine transition to lower shoreface Lower Shore- face- storm influ- ence. End of progradational parasequence 4136.7-4145.2: (S3) Buff- to Oil-brown, FU, cross-bedded sandstone. Interbeds of bioturbated mudstone have decreased significantly. Low abundance but moderate diversity of ichnofossils. Possible Arenico- lites? and Ph. 4133.8-4136.7(M1-St1): Light gray bioturbated mudstone grading to gray bioturbated siltstone. Ichnofossils found in low diversity high abundance. Minor flooding surface. 4129.8-4133.8 (OBa Top/S4): Buff brown- to oil stained- brown, VFU-FL, structureless Ss with abundant, low diversity bioturbation. Minor mud- stone interbeds. Wave ripple laminated- and cross-stratified Ss return above 4130. 4087.6-4125.4 (M1-St1-S1): An overall coarsening upward succession from dark- to light- gray bioturbated mudstone to wavy bedded silt- sone, and VFL, wave ripple laminated Ss. Low diversity, moderate bio- turbation. 4125.4 marks a basinward shift, possible MFS. Lower shoreface- mid shoreface. End of a progra- dation parase- quence Offshore Marine transition to lower shoreface 4059.2-4087.6 (OA/S3-S4-M1): Dark brown, oil stained, VFU-FL, convo- luted-, current- ripple laminated, wave- ripple laminated- and hum- mocky-swaley cross stratified sandstone overlying concultuted to bio- turbated mudstone. Occurs in pulses of events. Often contains sharp erosive bases with pebble sized clasts. Minor bioturbation. Pl and bivalve shell fragments. 4125.4-4129.8: Buff brown, FU, wave ripple- laminated and cross-strati- fied Ss with interbedded silstone. Moderate bioturbation Storm influenced lower- to mid-shoreface Bi Sk 3913.9-3919(NB/S5): Dark brown, heavily oil stained, MU grading to FU, cross-stratified sandstone with pebble sized, silt- and clay- clasts with sharp basal contacts interbedded with VFU, wave ripple- laminated sandstone, bioturbated mudstone, and wave affected siltstone. Pebble clasts exhibit a slight imbriction at 3916. Fluvial Deltaic incising into lower shoreface When looking at the core from the OBa to OA to NB we see overall a progradational- to aggradational- trend in which we move from a more distal to more proximal depositional environment. With this proximal transition we see coarser sediments, more erosional truncation, larger pebble sized clasts, traction transport in the upper part of the lower flow regime and can thus infer a increase in the sedimentation rate from our OBa sand to the NB sand. 3910-3913.9 (M1-S1): Light gray, wavy bedded, bioturbated mudstone and siltstone. Moderate bioturbation in which casts have been infilled with VFU sandstone and exhibit oil staining. Note: As the core drys and the oil volatilizes more sedimentary struc- tures and bioturbation is noted. Even after coming back 1 day later more structures and bioturbation can now be seen. Sideritized nodule and/or cement Woody debris/wood Leaf Burrow Trace fossil Root trace Current ripple cross-laminations Wave ripple cross-laminations Climbing current ripple cross-laminations Combined ripple cross-laminations Lenticular bedding Hummocky cross-stratified Flaser bedding Trough cross-stratification Planar tabular cross-stratification Horizontal laminations Wavy/undulating laminations Soft-sediment deformation (convolute bedding) Coal clasts Lignite Interbeds/stringers of mud Coal parting or interbed Interbeds/stringers of ss Interbeds/stringers of siltstone Bentonite Clast (granule to pebble size) Sedimentary Structures Explanation deformed bands/ripples M Muscovite Core Plug Volcaniclastic Pebble Fracture by C. Brock Rust David Douglas Hilcorp Alaska, LLC 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 or fax to 907 777-8510. Received By: Date: Date: 05/28/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU I-07A (PTD 221-010) Radial Cement Bond Log – Set 5.61” CIBP (03/25/2021) SFTP Data Transfer Files: Please include current contact information if different from above. PTD: 2210100 E-Set: 35167 06/01/2021 1.Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 7,444'4,235' Casing Collapse Conductor N/A Surface 3,090psi Production 5,410psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Chad Helgeson Contact Name:Ian Toomey Operations Manager Contact Email:itoomey@hilcorp.com Contact Phone: 777-8520 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng COMMISSION USE ONLY Authorized Name: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025906 220-010 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 MILNE POINT / SCHRADER BLUFF OIL 50-029-22602-01-00 Hilcorp Alaska LLC Length Size 7,305' 6,885' 6,766' C.O. 477.05 PRESENT WELL CONDITION SUMMARY 852 TVD Burst 3,862' MD N/A 7,020' 2,522' 7,788' Tubing Size: Tubing Grade: 4,236' MILNE PT UNIT I-07A 112'112' Tubing MD (ft): 80'20" 9-5/8" 7" 2,522' 7,788' 5,750psi 7,240psi 2,522' 3-1/2" Perforation Depth MD (ft): See Schematic 9.2# / L-80 / 8rd EUESee Schematic Perforation Depth TVD (ft): SLB MRP and N/A Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. 4,243' MD/ 4,116' TVD and N/A Authorized Signature: 4/30/2021 ory Statu Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 4:35 pm, Apr 19, 2021 321-203 Chad Helgeson (1517) 2021.04.19 16:08:04 - 08'00' MGR22APR21 221-010 DLB DLB 04/19/2021 7797' DLB X 7,788' 10-407 (perforation operations to be included in I-07A completion report) DSR-4/20/21Comm pq 4/23/21 dts 4/22/2021 RBDMS HEW 4/23/2021 Perf SB Sands Well: MPU I-07A Date: 04-19-21 Well Name:MPU I-07A API Number:50-029-22602-01-00 Current Status:Unperforated Well Pad:I-Pad Estimated Start Date:April 30th, 2021 Rig:E-Line Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Tom Fouts Permit to Drill Number:220-010 First Call Engineer:Ian Toomey (907) 777-8520 (O) (907) 903-3987 (M) Second Call Engineer:David Haakinson (907) 777-8343 (O) (307) 660-4999 (M) AFE Number:Job Type:Perforate SB Sands Current Bottom Hole Pressure:Not perforated Maximum Expected BHP:1,254 psi @ 4,017’ TVD EMW 6.0 ppg (Estimated from in nearby producers) MPSP:852 psi Gas Column Gradient (0.1 psi/ft) Max Inclination above CIBP:28°at 4,234’ MD Max Dogleg:5.8°/100ft at 4,043’ MD Tree:Cameron 3-1/8” 5M Wellhead:FMC, 11” 5M, Gen 5 Tubing Hanger Lift threads:3-1/2” TC-II top & bottom BPV Profile:3” CIW Type H Brief Well Summary: MPU I-07A was sidetracked for obtaining Schrader Bluff sand cores. After coring we continued to drill to the Kuparuk and found the sand wet. 7” casing was run and cemented with a two-stage cement job to abandon the Kuparuk and isolate the Schrader Bluff. The stage tool was drill out and E-line tagged the TOC at 7,441’ ELM. The 7” casing was successfully PT to 3,500 psi. A CBL was run and confirm adequate TOC for the Schrader Bluff sands. Notes Regarding Wellbore Condition x The 7” casing passed an MIT to 3,500 psi on 3/25/2021. x CIBP set at 4,243’ MD. x Minimum ID = 2.75” at 3,820’ MD (XN nipple) Objective: x Perforate the Schrader Bluff OBA, OA, ND, NC, NB & NA sands. Procedure: 1. MIRU E-line unit. 2. PT PCE to 250/2,500 psi. 3. PU and MU GR/CCL with 2-1/2” 6 SPF, 60° phasing perforating guns. 4. RIH and correlate guns on depth using GR/CCL/CBL log dated 3/25/2021. Contact OE Ian Toomey at 907-903-3987 and Geologist prior to perforating for tie in approval. 221-010 Perf SB Sands Well: MPU I-07A Date: 04-19-21 5. Perforate the following intervals. SB Sand Bottom Top Length OBA ±4,132' ±4,112' ±30' OA ±4,077' ±4,047' ±30' ND ±3,993' ±3,858' ±35' NC ±3,945' ±3,940' ±5' NB ±3,928' ±3,908' ±20' NA ±3,898' ±3,878' ±20' 6. POOH and LD perforating guns. Note: a. Condition of spent guns including any damage or un-fired charges. b. Well conditions pre/post perforating (Pressure changes, fluid level if identified when RIH, etc.) 7. RDMO E-line Unit Attachments: 1. As-built Schematic 2. Proposed Schematic _____________________________________________________________________________________ Revised By: TDF 4/16/2021 SCHEMATIC Milne Point Unit Well: MPU I-07A Last Completed: 3/28/2021 PTD: 221-010 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1 / H-40 / N/A - Surface 115' 9-5/8” Surface 40 / L-80 / BTC 8.835 Surface 2,522’ 7" Production 26 / L-80 / TXP 6.276 Surface 7,788’ TUBING DETAIL 3-1/2” Tubing 9.2 / L-80 / 8rd EUE 2.992 Surface 3,862’ GENERAL WELL INFO API: 50-029-22602-01-00 Sidetracked & Completed by Innovation 3-28-2021 TREE & WELLHEAD Tree 2-9/16” – 5M WKM Wellhead 11” 5M FMC w/ 11” x 2-7/8” tbg. Hanger, 2.5” ‘H’ BPV profile and 8rd EUE threads top and bottom. OPEN HOLE / CEMENT DETAIL 24" 250 sx Arctic Set I 12-1/4” 550 sx PF E & 250 sx Class ‘G’, 140 sx PF E 8-1/2”Stg 1 – 170 sx Class ‘G’ Stg 2 - 95 sx Class ‘G” WELL INCLINATION DETAIL Max Hole Angle = 41° @ 4,933’ JEWELRY DETAIL No Depth Item 1 3,678’ Zenith G6 Gauge 400 Bar 150C, 2 Press 2 Temp 2 3,761’ SLB MRP Packer 3 3,819’ “Brace” XN Nipple Assy, 2.813” Bottom No-Go 4 3,830’ 3-1/2” Mule Shoe –Bottom @ 3,862’ 54,243’CIBP TD =7,797’(MD) / TD =7,089’(TVD) 20” Orig. KB Elev.: 60.55’/ GL Elev.: 34.5’ 7” 9-5/8” TOC @ 3,550’ MD PBTD =4,260’(MD) / PBTD =4,130’(TVD) ES Cementer @ 1,616’ TOC @ 7,441’ELM 3/25/2021 1 2 3 5ES Cementer @ 4,275’ 4 NOTE 9-5/8” Casing Tight Spot @ 248’ MD _____________________________________________________________________________________ Revised By: TDF 4/16/2021 PROPOSED Milne Point Unit Well: MPU I-07A Last Completed: 3/28/2021 PTD: 221-010 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1 / H-40 / N/A - Surface 115' 9-5/8” Surface 40 / L-80 / BTC 8.835 Surface 2,522’ 7" Production 26 / L-80 / TXP 6.276 Surface 7,788’ TUBING DETAIL 3-1/2” Tubing 9.2 / L-80 / 8rd EUE 2.992 Surface 3,862’ TREE & WELLHEAD Tree 2-9/16” – 5M WKM Wellhead 11” 5M FMC w/ 11” x 2-7/8” tbg. Hanger, 2.5” ‘H’ BPV profile and 8rd EUE threads top and bottom. OPEN HOLE / CEMENT DETAIL 24" 250 sx Arctic Set I 12-1/4” 550 sx PF E & 250 sx Class ‘G’, 140 sx PF E 8-1/2”Stg 1 – 170 sx Class ‘G’ Stg 2 - 95 sx Class ‘G” WELL INCLINATION DETAIL Max Hole Angle = 41° @ 4,933’ JEWELRY DETAIL No Depth Item 1 3,678’ Zenith G6 Gauge 400 Bar 150C, 2 Press 2 Temp 2 3,761’ SLB MRP Packer 3 3,819’ “Brace” XN Nipple Assy, 2.813” Bottom No-Go 4 3,831’ 3-1/2” Mule Shoe –Bottom @ 3,862’ 54,243’CIBP PERFORATION DETAIL SB Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status NA ±3,878’ ±3,898’ ±3,781’ ±3,800’ ±20’ Future Proposed NB ±3,908’ ±3,928’ ±3,810’ ±3,829’ ±20’ Future Proposed NC ±3,940’ ±3,945’ ±3,840’ ±3,845’ ±5’ Future Proposed ND ±3,958’ ±3,993’ ±3,857’ ±3,890’ ±35’ Future Proposed OA ±4,047’ ±4,077’ ±3,940’ ±3,967’ ±30’ Future Proposed OBA ±4,112’ ±4,132’ ±3,999’ ±4,017’ ±20’ Future Proposed GENERAL WELL INFO API: 50-029-22602-01-00 Sidetracked & Completed by Innovation 3-28-2021 TD =7,797’(MD) / TD =7,089’(TVD) 20” Orig. KB Elev.: 60.55’/ GL Elev.: 34.5’ 7” 9-5/8” TOC @ 3,550’ MD PBTD =4,260’(MD) / PBTD =4,130’(TVD) ES Cementer @ 1,616’ 1 2 3 5ES Cementer @ 4,275’ 4 TOC @ 7,441’ELM 3/25/2021 NOTE 9-5/8” Casing Tight Spot @ 248’ MD A�A � External Chain of CustodyRecord Core Lab RESERM 0"MIZAnoM 5C)-0 2-q - Z ao 0 'z- 0 ECoc#: 8436 Date: 5 Apr 2021 50 " C) 2 2 Cho Zr �- Via(-- vi 0 6316 Windfern Road Houston, TX 77040 Phone: 1-713-328-2673 Fax: Contact: Daniel Burch Phone: +1 713 328 2471 EMail: Daniel. Burch@corelab.com "Please check the Notes at the bottom for important information, Client: HILCORP ALASKA LLC 3800 Centerpoint Drive Anchorage AK United States 99503 Contact: Phone: Job( 202006851) has 144 Samples Well: 1-07A Client Ref# Depthl (ft) 1AK 2AK 3AK 4AK 5AK 6AK 7AK 8AK 9AK 10AK 11AK 12AK 13AK 14AK 15AK 16AK 17AK 18AK 19AK 20AK 21AK 22AK Well: 1-07A BP01 Client Ref# 1AK 2AK 3AK 3913.60 3914.05 3915.15 3915.90 3917.45 3918.00 3919.15 3920.05 3921.10 3922.10 3923.00 3924.10 3925.50 3926.60 3927.10 3928.00 3929.10 3930.10 3931.00 3932.10 3933.10 3934.15 Consignee: Alaska Oil and Gas Conservation Commission 333 W. 7Th Ave Anchorage, AK 99501 Contact: Meredith GUA\k Phone: 907-793-1235 Depth2(ft) Length Sample Type CHUNK CHUNK CHUNK CHUNK CHUNK CHUNK CHUNK CHUNK CHUNK CHUNK CHUNK CHUNK CHUNK CHUNK CHUNK CHUNK CHUNK CHUNK CHUNK CHUNK CHUNK CHUNK Total: Sample:22 Depthl (ft) Depth2(ft) Length Sample Type 391.0 CHUNK 3911.10 CHUNK ` 3912.10 CHUNK Page 1 of 4 4AK 3913.00 CHUNK 5AK 3914.10 CHUNK 6AK 3915.85 CHUNK 7AK 3916.00 CHUNK 8AK 3917.10 CHUNK 9AK 3918.05 CHUNK 1 OAK 3919.00 CHUNK 11AK 4058.00 CHUNK 12AK 4059.05 CHUNK 13AK 4060.45 CHUNK 14AK 4061.00 CHUNK 15AK 4062.65 CHUNK 16AK 4063.50 CHUNK 17AK 4064.00 CHUNK 18AK 4065.05 CHUNK 19AK 4066.10 CHUNK 20AK 4067.00 CHUNK 21AK 4068.10 CHUNK 22AK 4069.10 CHUNK 23AK 4070.00 CHUNK 24AK 4071.05 CHUNK 25AK 4072.05 CHUNK 26AK 4073.00 CHUNK 27AK 4074.00 CHUNK 28AK 4075.00 CHUNK 29AK 4076.00 CHUNK 30AK 4077.25 CHUNK 31AK 4078.15 CHUNK 32AK 4079.00 CHUNK 33AK 4080.05 CHUNK 34AK 4081.25 CHUNK 35AK 4082.00 CHUNK 36AK 4083.20 CHUNK 37AK 4084.10 CHUNK 38AK 4085.00 CHUNK 39AK 4086.50 CHUNK 40AK 4087.10 CHUNK 41AK 4088.00 CHUNK 42AK 4089.10 CHUNK 43AK 4090.10 CHUNK 44AK 4091.00 CHUNK 45AK 4092.10 CHUNK 46AK 4093.10 CHUNK 47AK 4094.00 CHUNK 48AK 4095.10 CHUNK 49AK 4096.10 CHUNK 50AK 4097.00 CHUNK 51AK 4098.10 CHUNK 52AK 4099.10 CHUNK 53AK 4100.00 CHUNK 54AK 4101.10 CHUNK 55AK 4102.10 CHUNK 56AK 4103.00 CHUNK 57AK 4104.10 CHUNK 58AK 4105.10 CHUNK 59AK 4106.00 CHUNK Page 2 of 4 60AK 4107.10 CHUNK 61AK 4108.10 CHUNK 62AK 4109.00 CHUNK 63AK 4110.10 CHUNK 64AK 4111.10 CHUNK 65AK 4112.00 CHUNK 66AK 4113.10 CHUNK 67AK 4114.10 CHUNK 68AK 4115.00 CHUNK 69AK 4116.10 CHUNK 70AK 4117.10 CHUNK 71AK 4118.00 CHUNK 72AK 4119.10 CHUNK 73AK 4120.10 CHUNK 74AK 4121.00 CHUNK 75AK 4122.10 CHUNK 76AK 4123.10 CHUNK 77AK 4124.00 CHUNK 78AK 4125.45 CHUNK 79AK 4126.45 CHUNK 80AK 4127.40 CHUNK 81AK 4128.00 CHUNK 82AK 4129.10 CHUNK 83AK 4130.50 CHUNK 84AK 4131.00 CHUNK 85AK 4132.05 CHUNK 86AK 4133.15 CHUNK 87AK 4134.10 CHUNK 88AK 4135.10 CHUNK 89AK 4136.00 CHUNK 90AK 4137.00 CHUNK 91AK 4138.40 CHUNK 92AK 4139.10 CHUNK 93AK 4140.10 CHUNK 94AK 4141.20 CHUNK 95AK 4142.15 CHUNK 96AK 4143.35 CHUNK 97AK 4144.15 CHUNK 98AK 4145.70 CHUNK 99AK 4146.10 CHUNK 100AK 4147.20 CHUNK 101AK 4148.00 CHUNK 102AK 4149.10 CHUNK 103AK 4150.10 CHUNK 104AK 4151.00 CHUNK 105AK 4152.10 CHUNK 106AK 4153.10 CHUNK 107AK 4154.00 CHUNK 108AK 4155.10 CHUNK 109AK 4156.10 CHUNK 11 OAK 4157.00 CHUNK 111AK 4158.10 CHUNK 112AK 4159.10 CHUNK 113AK 4160.00 CHUNK 114AK 4161.10 CHUNK 115AK 4162.10 CHUNK Page 3 of 4 116AK 4163.00 CHUNK 117AK 4164.10 CHUNK 118AK 4165.10 CHUNK 119AK 4166.00 CHUNK 120AK 4167.10 CHUNK 121AK 4168.10 CHUNK 122AK 4169.00 CHUNK Total: Sample:122 Prepared By : Daniel Burch Please sign, date, & return copy to Core Lab via e-mail, fax, or mail. Date : 5 Apr 2021 Total Samples : 144; Total Boxes : 0; Total Pallets : 0 Received �� % Date: / liD I ZI Notes : chip samples 1 per foot for the state Page 4 of 4 1 Guhl, Meredith D (CED) From:Nathan Sperry <Nathan.Sperry@hilcorp.com> Sent:Friday, March 26, 2021 11:31 AM To:Rixse, Melvin G (CED) Subject:RE: [EXTERNAL] RE: PTD 221-010 I-07A - CBL Results Top of NB at 3,908’ MD Proposed packer set depth at 3,750’ MD. Thanks, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC O: 907‐777‐8450 C: 907‐301‐8996 From: Rixse, Melvin G (CED) [mailto:melvin.rixse@alaska.gov] Sent: Friday, March 26, 2021 8:57 AM To: Nathan Sperry <Nathan.Sperry@hilcorp.com> Subject: [EXTERNAL] RE: PTD 221‐010 I‐07A ‐ CBL Results Nathan, What is Hilcorp calling the base of the SB? What will be your lower most perf? Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907‐793‐1231 Office 907‐223‐3605 Cell CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907‐793‐1231 ) or (Melvin.Rixse@alaska.gov). From: Nathan Sperry <Nathan.Sperry@hilcorp.com> Sent: Friday, March 26, 2021 8:49 AM To: Rixse, Melvin G (CED) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: PTD 221‐010 I‐07A ‐ CBL Results Good morning Mel, The CBL revealed TOC at 3,550’ MD / 3,472’ TVD, which is 358’ MD and 337’ TVD above the Schrader NB. 2 The job was executed as planned. We pumped 30% excess to account for washout. We did not want to pump more cement due to a couple of risks, namely bringing cement into the surface shoe, breaking down the Colville, and breaking down the Schrader. We saw ~400 psi increase in pressure during the final displacement. The base of cement is right at the ES cementer, so it does not appear that the cement ‘slumped’ downhole. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC O: 907‐777‐8450 C: 907‐301‐8996 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. 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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. MEMORANDUM TO: JJiim Regg Supervisor ' eq 4(-zf�a?✓� FROM: Austin McLeod Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission DATE: March 25, 2021 SUBJECT: Well Bore Plug & Abandonment Milne Point Unit 1-07A ' Hilcorp North Slope LLC PTD 2210100 Section: 33 Township: 13N Range: 10E Meridian: Umiat - Drilling Rig: Innovation Rig Elevation: 27 ft Total Depth: 7,797 ft MD Lease No.: ADL 025906 ' Operator Rep: Shane Barber Suspend: P&A: X Casing/Tubing Data (depths are MD): Casing Removal: Conductor: 20" O.D. Shoe@ 115 - Feet Csg Cut@ NA Feet Surface: 9-5/8" - O.D. Shoe@ 2522 Feet Csg Cut@ NA Feet Intermediate: NA O.D. Shoe@ NA Feet Csg Cut@ NA Feet Production: 7 O.D. Shoe@ 7787 Feet Csg Cut@ NA Feet Liner: NA O.D. Shoe@ NA Feet Csg Cut@ NA Feet Tubing: NA O.D. Tail@ NA Feet Tbg Cut@ NA Feet Plugging Data: Test Data: Type Plug Founded on Depth Btm Depth( op MW Above Verified Fullbore Bottom 7,797 ft MD . 7,441 ft WLM 9.5 ppg Wireline tag Initial 15 min 30 min 45 min Result Tubing NA NA NA IA 3640 3579 3550 P ✓ OA 220 220 220 Initial 15 min 30 min 45 min Result Remarks: I traveled to location to witness the E-line tag of the plug (rubber) and pressure test of the same to isolate the Kuparuk A sand formation (top at 7,721 ft MD). A 5.72-inch gauge ring assembly weighing one hundred fifty pounds was used for the tag. They tagged at 7441 ft WLM. "Expected" tag was the plug (rubber) in the Baffle in the shoe track assembly at 7,583 ft MD. This put the tag 5.4 barrels high. Due to setting down on cement "wash up" above the Baffle I had no way of proving/tagging actual cement (cement below). They then completed a passing 7-inch casing/baffle plug test to 3500 psi. True Vertical Depth of the well is 7,089 ft. Inclination at 7,441 ft MD-20 degrees. Schrader formation up hole will be logged. ✓ Attachments: none rev. 11-28-18 2021-0325_Plug_Verification_MPU_I-07A_am 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ________________ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception? Yes No 9. Property Designation (Lease Number): 10. Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 7797'None Casing Collapse Structural Conductor Surface 3090 Intermediate Production 5410 Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. W ell Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Nathan Sperry Nathan.Sperry@hilcorp.com 777-8450 7089' 7797' 7089' None Length Size COMMISSION USE ONLY Tubing Grade: Tubing MD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 025906 221-010 3800 Centerpoint Drive, Suite 1400, Acnhorage, AK 99503 C.O. 477.05 50-029-22602-01-00 Hilcorp Alaska, LLC Milne Point Field, Schrader Bluff Oil Pool MPU I-07A PRESENT WELL CONDITION SUMMARY TVD Burst 7240 MD 5750 115' 2507' 115' 2522' 20" 9-5/8" 80' 2522' 7787' Perforation Depth MD (ft): None 7787' Perforation Depth TVD (ft): Tubing Size: 7081'7" 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: March 25, 2021 None None Authorized Title: Drilling Manager Authorized Name: Monty Myers ory Statu Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. 3.25.2021 By Samantha Carlisle at 4:07 pm, Mar 25, 2021 321-148 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2021.03.25 16:00:54 -08'00' Monty M Myers X DLB 03/25/2021 2367 10-407 ( to be submitted for entire completion after peforating) BOPE pressure test to 4000 psi. Annular to 2500 psi. 24 hour notice to AOGCC to witness initial MIT-IA. AOGCC to witness MIT-IA to 1500 psi within 7 days of POI. Separate sundry for perforating. MGR26MAR21 26-March-2021 Mel Rixse - Sr. Petroleum Engineer Milne Point Unit (MPU) I-07A Drilling Program Version 2 March 25, 2021 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 Casing Inspection ....................................................................................................................... 4 6.0 Internal Reporting Requirements ............................................................................................. 5 7.0 Wellbore Schematics .................................................................................................................. 6 8.0 Drilling / Completion Summary .............................................................................................. 10 9.0 Mandatory Regulatory Compliance / Notifications ................................................................ 11 10.0 R/U and Test BOPE ................................................................................................................. 13 11.0 Pull 2-7/8” Tubing .................................................................................................................... 14 12.0 Cut and Pull 7” Casing, Cleanout, Set CIBP .......................................................................... 15 13.0 Mill 8-1/2” Window and Kick Off ........................................................................................... 17 14.0 Production Hole Section Summary ......................................................................................... 20 15.0 Drill 8-1/2” Production Hole Section ....................................................................................... 21 16.0 Run 7” Casing .......................................................................................................................... 26 17.0 Cement 7” Casing .................................................................................................................... 31 18.0 Cleanout Run ........................................................................................................................... 35 19.0 E-line: Tag PBTD, CBL/GR/CCL, CIBP ................................................................................ 35 20.0 Perforate .................................................................................................................................. 35 21.0 Run 3-1/2” Injection String ..................................................................................................... 36 22.0 Post Rig .................................................................................................................................... 37 23.0 Innovation BOP Schematic ...................................................................................................... 38 24.0 Wellhead Schematic ................................................................................................................. 39 25.0 Days Vs Depth .......................................................................................................................... 40 26.0 Formation Tops & Information............................................................................................... 41 27.0 Anticipated Drilling Hazards .................................................................................................. 44 28.0 Innovation Layout.................................................................................................................... 46 29.0 FIT Procedure .......................................................................................................................... 47 30.0 Innovation Choke Manifold Schematic ................................................................................... 48 31.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 49 32.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 50 Page 2 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 1.0 Well Summary Well MPU I-07A Pad Milne Point “I” Pad Planned Completion Type Injection Tubing Target Reservoir(s) Schrader Bluff Wellplan 5 Planned Well TD, MD / TVD 7,869’ MD / 7,161’ TVD PBTD, MD / TVD ±7,789 MD / 7,084’ TVD Surface Location (Governmental) 2339' FSL, 1374' FWL, Sec 33, T13N, R10E, UM, AK Surface Location (NAD 27 –Zone 4) X=551,464.8 Y=6,009,453.3 Top of Productive Horizon (Governmental) 1119' FNL, 2226' FEL, Sec 33, T13N, R10E, UM, AK TPH Location (NAD 27) X=553,126.7, Y=6,011,286.0 BHL (Governmental) 977' FNL, 2093' FEL, Sec 33, T13N, R10E, UM, AK BHL (NAD 27) X=553,258.9 Y=6,011,428.9 AFE Pre-Drill Days 4 Days AFE Drilling Days 11 Days AFE Completion Days 5 Days Maximum Anticipated Pressure (Surface) 1,525 psi Maximum Anticipated Pressure (Downhole/Reservoir) 3,071 psi (8.4 ppg EMW) Work String 5” 19.5# S-135 NC-50, DS-50 KB Elevation above MSL: 26.5 ft + 34.5 ft = 61.0 ft GL Elevation above MSL: 34.5 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 2.0 Management of Change Information Page 4 Version 2 March 2021 Milne Point Unit I-07A 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) 8-1/2” 7” 6.276 6.151 7.656 26 L-80 HYD TXP 7240 5410 604 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) 8-1/2” 5” 4.276”3.25” 6.625”19.5 S-135 NC50 31,032 34,136 560klb *Tension Rating Based on Premium Pipe 5.0 Casing Inspection All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 6.0 Internal Reporting Requirements 6.1 Fill out daily drilling report and cost report on Wellez. x Report covers operations from 6am to 6am x 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 tab. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. x Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 6.2 Afternoon Updates x Submit a short operations update each work day to mmyers@hilcorp.com, pmazzolini@hilcorp.com ,nathan.sperry@hilcorp.com,jengel@hilcorp.com and joseph.lastufka@hilcorp.com 6.3 Intranet Home Page Morning Update x 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. 6.4 EHS Incident Reporting x Health and safety: Notify EHS field coordinator. x Environmental: Drilling Environmental coordinator x Notify Drlg Manager & Drlg Engineer x Submit Hilcorp Incident report to contacts above within 24 hrs 6.5 Casing Tally x Send final “As-Run” Casing tally to nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 6.6 Casing and Cement report x Send casing and cement report for each string of casing to nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 6.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com Drilling Engineer Nate Sperry 907-777-8450 907.301.8996 nathan.sperry@hilcorp.com Completion Engineer Ian Toomey 907.777.8434 907.903.3987 itoomey@hilcorp.com Geologist (Schrader) Rebecca Emerson 907.777.8491 907.590.0648 Rebecca.emerson@hilcorp.com Res. Engineer (Schrader) Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com Geologist (Kuparuk) Radu Girbacea 907.777.8324 907.230.9490 rgirbacea@hilcorp.com Res. Engineer (Kuparuk) Daniel Taylor 907.777.8319 907.947.8051 dtaylor@hilcorp.com Drlg Environmental Coord Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com Safety Manager Carl Jones 907.777.8327 907.382.4336 cajones@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 907.227.8496 Joseph.Lastufka@hilcorp.com Page 6 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 7.0 Wellbore Schematics Parent Abandonment Page 7 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure Parent Abandonment w/ Whipstock Page 8 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure I-07A Pre-completion Schematic Page 9 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure Completion Proposed TOC from CBL 3,550' MD BOC from CBL 4,275' MD TOC Eline Tag 7,441' ELMD Top of Kup A Sands 7,721' MD Page 10 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 8.0 Drilling / Completion Summary MPU I-07A is a sidetrack producing well targeting the Schrader Bluff, located on Milne Point ‘I-Pad’. The primary objective of the well is to core (conventional) the Schrader Bluff sands (NB, OA, OBa). After coring the Schrader Bluff in 8-1/2” hole, we will continue drilling to the Kuparuk. The well will be completed with 7” casing. The directional plan is a single string slant well with the kick off point at ~2,560’ MD. Maximum hole angle is ~47 degrees. Drilling operations are expected to commence approximately February 15th, 2021, pending rig schedule. Production casing will be 7” 26# L-80 cemented casing run to 7,869’ MD / 7,161’ TVD. The well will be perforated post-rig. Innovation will leave the well with the casing cemented and a 3-1/2” completion string installed with a 7” CIBP installed 100’ below the base of the Schrader OBa sand. A separate sundry will be submitted for post-rig completion operations on I-07A. All waste & mud generated during drilling operations will be hauled to the Milne Point G&I facility located on “B” pad. General sequence of operations: 1. MIRU Innovation 2. N/U 13-5/8” x 5M BOPE and test 3. Pull 2-7/8” kill string 4. Cut and pull 7” casing. 5. Cleanout run. Set CIBP. 6. Set 9-5/8” WS and mill 8-1/2” window 7. Drill 8-1/2” hole to first coring point 8. Core Schrader sands, drilling 8-1/2” hole between coring points. 9. Drill 8-1/2” hole to base Kuparuk 10. Run and cement 7” production casing. 11. Perform cleanout run on 4” DP to drill up the ES cementer. 12. RU e-line. Tag PBTD. Run GR/CCL/CBL. Pressure test 7”. Run 7” CIBP. 13. Run Upper Completion 14. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Production hole prior to coring (Schrader): No mud logging. LWD: GR/Res/NB GR 2. Production hole after coring (Kuparuk): No mud logging. LWD: Triple combo 3. Mud loggers will not be used on this well. Page 11 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 9.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOP’s shall be tested at 1 week intervals prior to initiating window milling and 2 week intervals during the drilling and completion of MPU I-07A thereafter. Provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/4000 psi & subsequent tests of the BOP equipment will be to 250/4000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation, notify AOGCC and 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. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements”. x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. x 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)”. AOGCC Regulation Variance Requests: x There are no variance requests at this time. Page 12 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure Summary of Innovation BOP Equipment & Test Requirements Hole Section Equipment Test Pressure (psi) 12-1/4”x 13-5/8” 5M CTI Annular BOP w/ 16” diverter line Function Test Only 8-1/2” x 13-5/8” x 5M Control Technology Inc Annular BOP x 13-5/8” x 5M Control Technology Inc Double Gate o Blind ram in btm cavity x Mud cross w/ 3” x 5M side outlets x 13-5/8” x 5M Control Technology Single ram x 3-1/8” x 5M Choke Line x 3-1/8” x 5M Kill line x 3-1/8” x 5M Choke manifold x 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: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Guy Schwartz / Petroleum Engineer / (O): 907-793-1226 / (C): 907-301-4533 / Email:guy.schwartz@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 13 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 10.0 R/U and Test BOPE All work prior to milling the window will be on the PRE AFE. 10.1 Reservoir abandonment was completed pre-rig via a separate Sundry. 10.2 Ensure Sundry, PTD, and drilling program are posted in the rig office and on the rig floor. 10.3 Level pad and ensure enough room for layout of rig footprint and R/U. 10.4 Ensure rig mats cover entire footprint of rig. 10.5 MIRU Innovation. Ensure rig is centered over the wellhead to prevent any wear to BOPE or wellhead. 10.6 N/U 13-5/8” x 5M BOP as follows: x 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 x Double gate ram should be dressed with 2-7/8” x 5” VBRs in top cavity,blind ram in bottom cavity. x Single ram can be dressed with 7” FBRs x N/U bell nipple, install flowline. x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 10.7 Test BOP to 250/4000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. x Install test dart in BPV. x Test upper VBR’s with 2-7/8” and 5” test joints x Test lower VBR’s with 4-1/2” and 7” test joints x Confirm test pressures with PTD x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 10.8 R/D BOP test equipment. Pull test dart and BPV. From PTD Irrellevant to this sundry Page 14 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 11.0 Pull 2-7/8” Tubing 11.1 PU landing joint or spear and recover the tubing hanger. 11.2 Back out lock down screws. 11.3 Pull tubing hanger with landing joint/XO to the floor. Have appropriate protectors ready. 11.4 The tubing is expected to be in good condition since it was just installed by ASR as a kill string. 11.5 Note and record PU weight required to pull the tubing from cut. 11.6 The expected weight of the string in a vertical hole filled with seawater is 15,500 lbs (assumes 2,750’ of tubing). 11.7 Circulate at least 1.5x BU after pulling the hanger to the floor. If desired, circulate a soap sweep surface-to-surface to clean the tubing. Swap well to 9.5ppg brine per Baroid. 11.8 Pull and lay down the tubing. From PTD Irrellevant to this sundry Page 15 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 12.0 Cut and Pull 7” Casing, Cleanout, Set CIBP Important Notes: The Nabors 22E RKB was 28.5’ on the 7” run. There is a 2’ shift to our Innovation measurement of 26.5’ RKB. Ensure fishing rep and company man review parent tallies and agree on cut depth. The 7” casing was installed w/ a mandrel hanger and a packoff on 10/6/95 (see drilling report in PARENT WELL folder on the O-drive). Talk to the wellhead hands about pulling the 7” packoff and hanger and any potential contingencies we need to have lined up. We may need to steam the wellhead to get the packoff free. 7” was cemented on 10/7/1995. Centralizers were installed 2/jt on jts 1-16 and then 1/jt on 77-106 and 117 and 118. The second stage cement job was performed with 32.8 bbls of 15.8ppg G. No losses were noted. Estimated TOC based on GAUGE hole is 2,783’ MD (they were able to inject the FP fluid 12 hrs after cement was in place). They achieved a 12.5ppg FIT on the parent surface casing shoe. Operational Steps: 12.1 Ensure 7” x 9-5/8” annulus is bled to zero. Bleed each tour. 12.2 RU e-line. PU jet cutter for 7” casing per AK e-line. 12.3 RIH and cut the 7” in the 9-5/8” shoetrack. 12.4 Perform flowcheck. POOH to surface. 12.5 Rig up to circulate seawater down the 7” and out the annulus to displace the freeze protect and annulus fluids. Perform flowcheck and weight up using KCl/NaCl if necessary. Note: Schrader PP is subnormal in the area. 12.6 Pull packoff. PU landing joint or spear and recover the casing hanger. 12.7 Back out lock down screws. 12.8 Pull hanger with landing joint/XO to the floor. 12.9 Note and record PU weight required to pull the casing from cut. 12.10 The expected weight of the string in a vertical hole filled with seawater is ~59klbs (assumes ~2,600’ cut depth). Irrelevant to sundry Page 16 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 12.11 If necessary, circulate at least 1.5x BU at maximum rate after pulling the hanger to the floor. If desired, circulate a soap sweep surface-to-surface to clean the casing and annulus (pump fluid train per Baroid recommendation to clean the wellbore). 12.12 Pull and lay down the casing from the cut. 12.13 Run wear ring. 12.14 RIH with clean-out assembly on 5” pipe and clean-out the well to the top of the casing stub. 12.15 When on bottom circulate at max rate at least 1X BU or until returns are clean. Pump high vis sweep if necessary. Displace to 8.6ppg Baradrill-N fluid. Note: Displacement can also take place after setting the whipstock prior to milling. 12.16 POOH with clean-out assembly. 12.17 MU 9-5/8” CIBP. RIH and set CIBP per tally just above the float collar (base of joint #3). Pressure test CIBP x 9-5/8” envelope to 2900 psi for 30 charted minutes (2,900 psi is ~50% of the 9-5/8” 40# internal yield pressure). x The TrackmasterElite whipstock is 30’ long. Set CIBP near the bottom of the joint so that we can set the WS in the joint to avoid milling a collar. 12.18 POOH. Irrelevant to Sundry Page 17 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 13.0 Mill 8-1/2” Window and Kick Off Note: All following operations will be covered under the PTD for I-07A 13.1 Whipstock Set Depth Information: x Planned TOW: ~2,560’ MD x Whipstock is the Wellbore Integrity Solutions Trackmaster Elite x Whipstock is a mechanical set system. After tagging the CIBP, WS can be pulled uphole but will set when slacked off. x Verify shear bolt strength with WIS rep. 13.2 MU 8-1/2” mill/whipstock assembly as per fishing rep’s tally x Ensure magnets are in trough, under shakers, and flow area to capture metal shavings circulated 13.3 Install MWD. Rack back mill assembly. 13.4 Verify offset between MWD and whipstock tray, witnessed by Drilling Supervisor, MWD/DD and fishing rep. Document and record offset in well file. 13.5 Slowly run in the hole as per fishing rep. Run extremely slow through the BOP & wear bushing to prevent damaging the shear bolt. 13.6 Run in hole at 1 ½ to 2 minutes per double, or as per fishing rep. Ensure work string is stationary prior to setting the slips, and removed slowly as well. These precautions are to avoid weakening the shear bolt and prematurely setting the anchor. 13.7 Stop at least 30-45’ above planned set depth and obtain survey with MWD. 13.8 Milling fluid will be 8.6 ppg Baradrill-N. x If re-using fluid from I-28, a fluid density between 8.6ppg and 9.5ppg is acceptable. 13.9 With the bottom of the whipstock 30 – 45’ above the set depth, work torque out of string, measure and record P/U and S/O weights. Obtain good survey to orient whipstock face. 13.10 Orient whipstock to desired direction by turning DP in ¼ round increments. P/U and S/O on DP to work all torque out after oriented. Target orientation is 60q ROHS. Slack off and trip the anchor system on the CIBP per fishing rep. Irrelevant to sundry Page 18 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 13.11 Whipstock Orientation Diagram: Desired orientation of the whipstock face is 60R. Acceptable range is between 30R and 60R Hole Angle at window interval (2,560’ MD) is ~11°, Azimuth 40°. 13.12 Once whipstock is in desired orientation, set WS per fishing rep. 13.13 P/U 5-7K maximum overpull to verify anchor is set. The window mill can then be sheared off by slacking off weight on the whipstock shear bolt. 13.14 P/U 5-10’ above top of whipstock. 13.15 CBU and confirm consistent MW in/out x Ensure Mud properties are sufficient for transporting metal cuttings x Visc: 40-60, YP: 18-20 13.16 Record P/U, S/O weights, and free rotation. Slack off to top of whipstock and with light weight and low torque. Mill window as per fishing rep. Utilize 4 ditch magnets on the surface to catch metal cuttings. Pump high visc sweeps as necessary. 13.17 If possible, install catch trays in shaker underflow chute to help catch metal cuttings. 13.18 Clean catch trays and ditch magnets frequently while milling window. 13.19 Mill window until the uppermost mill has passed across the entire tray. Dress and polish window as needed. 13.20 With upper mill at the end of the tray, this will drill ~ 20’ of new hole. 13.21 After window is milled and before POOH, shut down pumps and work milling assembly through window watching for drag. Dress and polish window as needed. After reaming, shut off pumps and rotary (if hole conditions allow) and pass through window checking for drag. 13.22 Circulate bottoms up until even MW in/out and hole is clean of metal shavings. Reduce mud properties for drilling. 60R 30R Irrelevant to sundry Page 19 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 13.23 Pull back into 9-5/8” casing and perform FIT t/ 12.0 ppg EMW. Chart Test. x Note: If a 12.0ppg is not achieved on the first attempt, try again. If second attempt falls short as well, contact drilling engineer. 13.24 POOH & LD milling BHA. Gauge mills for wear. 13.25 PU stack washer and wash BOPE stack. Function all rams to clear any potential milling debris. Irrelevant to sundry Page 20 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 14.0 Production Hole Section Summary This is a single section 8-1/2” hole kicked off from cemented pipe. We will drill 8-1/2” hole to the Schrader Bluff sands and then core the NB, OBA, and OA stands. After coring, we will make up an underreaming assembly with triple combo and drill to TD in the Kuparuk. The Kuparuk pore pressure is expected to be 8.4 ppg EMW. Maintaining CBHP will be critical for maintaining HRZ and Kalubik stability. Note: Managed Pressure Drilling will be used in this hole section. Prior to drilling, verify all rig crew member are familiar with operation. If needed, install RCD bearing element and perform practice connections to familiarize crews with its operations. Irrelevant to sundry Page 21 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 15.0 Drill 8-1/2” Production Hole Section Scope: x The plan is to drill 8-1/2” hole using the GeoPilot assembly to the coring intervals using GR/Res and Near-Bit GR. x We will core the Schrader Bluff per US Coring. o Coring Rep Contact Info: Chris Fletcher, Christopher.Fletcher@us-coring.com, 832-517- 5540 x After coring, we will PU an 8-1/2” RSS/UnderReaming assembly utilizing the NOV AnderReamer and drill to TD in the Kuparuk using a triple combo. x Proposed top coring depths are NB 3,910’ MD, OA 4,030’ MD, Oba 4,135’ MD. 15.1 PU 8-1/2” GeoPilot RSS assembly. x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Workstring will be 5” DP. 15.2 8-1/2” hole section mud program summary: x 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. x 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. x 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. x Run the centrifuge continuously while drilling the production hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x 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. Irrelevant to sundry Page 22 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure System Type:8.6 – 9.5 ppg Baradrill-N drilling fluid Properties: Section Density Plastic Viscosity Yield Point Total Solids MBT HPHT Production 8.6-9.5 15-25 20-25 <10%<7 <11.0 System Formulation: Baradrill-N 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 15.3 Ensure even MW in and out. Note: MPD is NOT needed prior to or during coring. MPD will be install after coring. 15.4 Drill 8-1/2” hole section with GeoPilot assembly to the first coring point (Schrader NB) per Schrader Geologist. x Control drill the final 100’ at 50 fph. 15.5 Backream 1 stand to get separation from the coring point (to minimize washout right above the coring point – this will help with coring BHA stabilization). After pulling one stand, CBU minimum 2X (or longer if necessary) to clean the hole. 15.6 As necessary, either dilute or swap to clean mud prior to coring.Ensure mud PH < 10 and API FL < 5.The core won’t see the fluid very long as the flow will be diverted down the core barrel annulus and out the bit but it is important to limit core swelling (using low fluid loss) so that the core doesn’t swell and jam in the barrel. 15.7 Backream to the window. POOH. 15.8 MU 8-1/2” coring BHA per US Coring rep. RIH per rep and core interval 1 per US Coring Rep. 15.9 POOH. MU RSS assembly and TIH. 15.10 MADpass as necessary. Drill to coring point #2 (Schrader Oba) per Schrader Geologist. x Control drill final 50’ at 50 fph. Irrelevant to sundry Page 23 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 15.11 Backream 1 stand to get separation from the coring point. After backreaming 1 stand, CBU 1X (or longer if necessary) to clean the hole. 15.12 Backream to the window. POOH. 15.13 MU 8-1/2” coring BHA per US Coring rep. RIH per rep and core interval 2. 15.14 POOH. MU RSS assembly. TIH and MADpass as necessary. 15.15 Drill to coring point #3 (Schrader OA) per Schrader Geologist. x Control drill the final 50’ at 50 fph. 15.16 Backream 1 stand to get separation from the coring point. After backreaming 1 stand, CBU 1X (or longer if necessary) to clean the hole. 15.17 Backream to the window. POOH. 15.18 MU 8-1/2” coring BHA per US Coring rep. RIH per rep and core interval 3. 15.19 POOH. MU 8-1/2” RSS assembly w/ NOV AnderReamer. TIH. Mud system for drilling the remainder of the well will be LSND with 3% KCl. 15.20 RIH to window. Install MPD. RIH to current TD and activate NOV AnderReamer (NOV rep will be remote). 15.21 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer. x Flow Rate: 525-620 gpm (Target 200 ft/min AV) x RPM: 120 – for hole cleaning x RPM:Do NOT rotate >60 RPM off bottom. The risk is backing off the BHA below the AnderReamer. x WOB as needed x Target ECD and CBHP: 11.0 EMW +/- 5% (target this at the top of the HRZ) x Utilize MPD to maintain CBHP (constant bottom hole pressure) on connections, following annular pressure ramp schedule x This will reduce the pumps on/ pumps off pressure cycles on shales x Slow ramp pumps on/off on each connection x Smooth connections are more important that connection time x Monitor connections for losses, adjust as necessary x Take MWD surveys every stand drilled. x Kuparuk PP estimate is 8.4 ppg. Good drilling and tripping practices are vital for avoidance of differential sticking and HRZ/Kalubik stability. x Watch for fluid losses while drilling through Kuparuk. x Ensure black products are in the mud per Baroid prior to drilling into the HRZ. 15.22 Kuparuk production hole section mud program summary: Irrelevant to sundry Page 24 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure x Density: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. x 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. x Inhibition: 3% KCl will be used for handling clay cuttings. Watch MBT levels, dilute as necessary to maintain. Increase KCl % if needed x Run the centrifuge continuously while drilling the production hole, this will help with solids removal and minimize sand content and LGS to maintain fluid properties and quality of the mud system. x PVT will be used throughout the drilling phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type:9.5 – 10.8 ppg 3% KCl Inhibited LSND WBM Properties: Section Density (ppg) Plastic Viscosity Yield Point LGS MBT HPHT pH Intermediate 9.5 –10.5 15-25 15-20 <6%<20 <11.0 9-10 15.23 At TD, circulate a minimum of 2X BU x Drop the closing ball and close the AnderReamer per the NOV rep. x Circulate at full drill rate while rotating at 120 rpm’s x Only if necessary (if hole conditions dictate), perform short trip to 9-5/8” window following the pressure schedule to maintain CBHP at the base of the Kalubik. x We can slowly rack back a couple of stands while performing the BU circulations. x Attempt to pull through the Kalubik on elevators to the window. Only initiate backreaming if necessary. x Circulate a minimum of 1.5X BU at the window prior to TIH on elevators. 15.24 If backreaming is necessary: x Circulate at max rate while maintaining drilling ECD’s x Perform CBHP connections x Rotate at maximum rpm that can be sustained. x Limit pulling speed to 5 – 10 min/std (slip to slip time, not including connections). x If backreaming operations are commenced, continue backreaming to the window and circ at least a b/u once at the window. Irrelevant to sundry Page 25 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 15.25 At TD, circulate at least 2X BU. Observe well for flow, weight up to 10.3 ppg prior to TOOH. Include a casing running pill in the open hole to the top of the HRZ/Kalubik. Perform flow check prior to TOOH. x 12ppb black product, graphite, 2% lube 15.26 TOOH with the drilling assembly to 9-5/8” window while offsetting swab with MPD x Follow tripping schedule, matching string speed and annular pressure x Rack back DP while TOOH, Do not lay down drill pipe. This is to minimize open hole time before casing is on bottom. 15.27 CBU at 9-5/8” window 15.28 Pull RCD bearing element with bit at the window. Perform flowcheck. 15.29 Continue TOOH to HWDP/ BHA. 15.30 L/D 8-1/2” BHA 15.31 No additional logs are planned for the 8-1/2” hole section. Irrelevant to sundry Page 26 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 16.0 Run 7” Casing 16.1 Ensure rams have been tested on 7” test joint prior to running casing. 16.2 Ensure emergency slips are ready to go and staged where appropriate. 16.3 Ensure wear bushing is pulled from wellhead. 16.4 R/U 7” casing running equipment. x Ensure 7” TXP crossover is on rig floor and M/U to FOSV. x Ensure all casing has been drifted prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.5 Continue MU & thread locking 80’ shoe track assembly consisting of: 7” Float Shoe 4 joints –7” TXP, 2 Centralizers 10’ from each end w/ stop rings 7” Float Collar with Stage Cementer Bypass Baffle ‘Top Hat’ 1 joint – 7” TXP, 1 Centralizer mid joint with stop ring 7” HES Baffle Adaptor x Ensure bypass baffle is correctly installed on top of float collar. x Ensure proper operation of float equipment while picking up. x Ensure to record SN’s of all float equipment and stage tool components. This end up. Bypass Baffle Irrelevant to sundry Page 27 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 16.6 Float equipment and stage tool equipment drawings: Irrelevant to sundry Page 28 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 16.7 Run 7” casing per tally. x Install 7” ES cementer at least 100’ below base of Schrader OBa Sand x Dope pin end only w/ paint brush. x Utilize a collar clamp until weight is sufficient to keep slips set properly. x CENTRALIZERS: Run one 7” x 8-1/4” hydroform centralizer per joint across the cemented intervals. Centralize the ES cementer with 1 centralizer per joint for 5 joints below and 5 joints above the ES cementer. x MU shoetrack and check floats. 7” 26ppf L-80 TXP Torque OD Minimum/Maximum Optimum Operating Torque 7” 13,280 / 16,230 ft-lbs 14,750 ft-lbs 20,000 ft-lbs Circulating Strategy Stage pumps in ½ to 1 bpm increments. Allow pressures to stabilize prior to increasing to the next flowrate. Watch for packoffs, especially after the shoe is below the Kalubik. Depth Interval Strategy MU casing to window Fill as needed At window Circulate 1X BU (or until mud is conditioned) Window to HRZ Circulate 1 jt down for 5 minutes every 10 joints By the top HRZ Circulate down consecutive joints to achieve 1X BU by the top of the HRZ (having a BU within a couple hundred feet from the top is fine – does not need to occur right at the top). From THRZ to TD Fill pipe. Do not circulate unless necessary to wash down. Irrelevant to sundry Page 29 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure Page 30 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 16.5 RIH casing. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.6 Obtain up and down weights of the casing before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 16.7 RIH to TD as per running schedule. Monitor run for losses. Irrelevant to sundry Page 31 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 17.0 Cement 7” Casing 17.1 Circulate and condition mud for cement job. x Break circulation slowly and stage up rate with reciprocation. x Circulate minimum 1.5X BU to condition hole and mud for cement job. 17.2 Hold pre job safety meeting over upcoming casing cementing operations. Make room in pits for volume gained during cement job. Ensure adequate displacement volume is available. x Discuss pumps for displacement x Positions and expectations of all personnel involved in cement operations, have one hand in the pits specifically for strapping pits and recording volume returned. 17.3 The 7” casing cement job will be a two stage cement job. 17.4 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. 17.5 Fill surface cement lines with water and pressure test. 17.6 Pump 40 bbls 11.0 ppg tuned spacer. 17.7 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. Irrelevant to sundry Page 32 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 17.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of one slurry brought to at least 500’ MD above the Kuparuk A sands. Estimated 1st Stage Total Cement Volume: Cement Slurry Design (1st Stage Cement Job): 17.9 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 continue with the cement job. 17.10 After pumping cement, drop top plug (Shutoff plug) and displace cement with mud out of mud pits. x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 17.11 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. 17.12 Displacement calculation: (7797’-204’) x 0.0383 bpf = 291 bbls 17.13 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. 17.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume before consulting with Drilling Engineer. 17.15 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. Tail Slurry Density 15.8 lb/gal Yield 1.16 ft3/sk Mixed Water 4.98 gal/sk Irrelevant to sundry Page 33 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 17.16 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. 17.17 Increase pressure to 3,300 psi to open circulating ports in stage collar. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Second Stage Surface Cement Job: 17.18 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. 17.19 After Stage 1 tail cement reaches 50 psi compressive strength, swap circulating fluid to 9.5ppg KCl/NaCl. 17.20 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 17.21 Fill surface lines with water and pressure test. 17.22 Pump 50 bbls 10.0 ppg tuned spacer. 17.23 Mix and pump cement per below recipe for the 2 nd stage. 17.24 Cement volume based on annular volume + open hole excess (30%). Job will consist of tail, TOC brought 500’ above Schrader Bluff. Estimated 2nd Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): 13.9 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 17.25 After pumping cement, drop ES Cementer closing plug and displace cement with 9.5ppg brine. Tail Slurry System G Density 14.0 lb/gal Yield 1.52 ft3/sk Mixed Water 7.74 gal/sk Irrelevant to sundry Page 34 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 17.26 Displacement calculation: 4,165’ x 0.0383 bpf = 159.5 bbls mud 17.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. 17.28 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. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job 17.29 R/D cementing equipment. If cement was displaced with brine, set test plug and flush out wellhead and stack with FW. Pull the test plug. 17.30 Install packoff. Test void to 250/4000 psi for 10 min. 17.31 After Stage 2 cement has developed 100 psi compressive strength, freeze protect 9-5/8” x 7” annulus. Send final “As-Run” casing tally & casing and cement report to nathan.sperry@hilcorp.com, itoomey@hilcorp.com,and joseph.lastufka@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Irrelevant to sundry Page 35 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 18.0 Cleanout Run Swap to completion AFE. 18.1 Swap handling equipment to 4” DP. Ensure appropriate XO’s, safety joint, and TIW are staged in case of a well control event. Ensure rams have been tested on 4” DP. 18.2 PU cleanout assembly on 4” DP (milltooth bit). 18.3 TIH with cleanout assembly to stage tool. Drill out stage tool. Ensure even 9.5ppg brine in and out. 18.4 POOH racking back DP. 19.0 E-line: Tag PBTD, CBL/GR/CCL, CIBP NOTIFY AOGCC FOR OPPORTUNITY TO WITNESS PBTD TAG AND 7” PRESSURE TEST 19.1 RU E-line per vendor. Confirm RU with Ops Engineer. 19.2 PU and MU drift assembly. RIH and tag PBTD. POOH. x MU CBL/GR/CCL tool string. RIH below base of ES cementer and log CBL across Schrader Bluff x Ensure Stage 2 TOC logged at least 500’ above Schrader Bluff NB sand x Communicate CBL results to drilling engineer and ops engineer. 19.3 Perform 7” casing pressure test to 3500 psi high for 30 charted minutes. 19.4 PU 7” CIBP. RIH and set above the ES cementer but at least 100’ below the base of the Schrader OBa sand. Note: perforating will be performed post-rig per a separate 10-403. 20.0 Perforate 20.1 Pressure test the 7” casing to 4,000 psi for 30 minutes (charted) prior to perforating. 20.2 Ensure appropriate XO’s, safety joint, and TIW are staged in case of a well control event. 20.3 MU 3-3/8” 6 SPF 60 deg phasing perf guns per tally from ops engineer. 20.4 Crossover to 4” XT-39 S-135 drillpipe. 20.5 Single in the hole to PBTD. Lightly tag PBTD and correct depth (tie PBTD to GR/CCL and MWD logs per Ops Engineer and geologist). 20.6 Close the annular or rams. Perforate per Halliburton. 20.7 Pull above top shot. Stop and monitor for losses and CBU. 20.8 Flowcheck and POOH while keeping the hole full and laying down DP. Verify all shots have fired. Page 36 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 21.0 Run 3-1/2” Injection String 21.1 RU 3-1/2” handling equipment. x Ensure wear bushing is pulled. x Ensure 3-1/2” EUE 8rd x XT-39 crossover is on rig floor and M/U to FOSV. x Ensure all tubing has been drifted in the pipe shed prior to running. x Be sure to count the total # of joints in the pipe shed before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths and SN’s of all components with vendor & model info. x Monitor displacement from wellbore while RIH. 21.2 PU, MU and RIH with the following 3-1/2” completion. Verify running order with Ops Engineer. x WLEG Joint, 3-1/2”, 9.3#, L-80, EUE 8rd x Pup Joint, 3-1/2”, 9.3#, L-80, EUE 8rd x Nipple, 2.813” XN with RHC plug body installed x Pup Joint, 3-1/2”, 9.3#, L-80, EUE 8rd x 1 Joint, 3-1/2”, 9.3#, L-80, EUE 8rd x Pup Joint, 3-1/2”, 9.3#, L-80, EUE 8rd x Packer, 3-1/2” x 7” Retrievable (setting depth within 200’ of the top of the NB sand) x Pup Joint, 3-1/2”, 9.3#, L-80, EUE 8rd x 2 Joints, 3-1/2”, 9.3#, L-80, EUE 8rd x Pup Joint, 3-1/2”, 9.3#, L-80, EUE 8rd x Ported Pressure Gauge sub x Pup Joint, 3-1/2”, 9.3#, L-80, EUE 8rd x XXX Joints, 3-1/2”, 9.3#, L-80, EUE 8rd 21.3 PU and MU the tubing hanger with landing joint. 21.4 Land the tubing hanger and RILDS. Lay down the landing joint and install the BPV. 21.5 ND the BOP stack. Install the plug off tool. NU the tubing head adapter and tree. 21.6 PT the tubing hanger void to 250/5,000 psi. PT the tree to 500/5,000 psi. 21.7 Pull the plug off tool and BPV. 21.8 RU to reverse circulate. Reverse circulate the well to corrosion inhibited brine following by diesel freeze protect to ~2,500’ MD. 21.9 Drop the ball & rod. 21.10 Pressure up on the tubing to set the packer. PT the tubing to 3,500 psi for 30 minutes (charted). 21.11 Bleed the tubing pressure to 2,500 psi and PT the IA to 3,500 psi for 30 minutes (charted). Proposed packer set depth 3,750' MD Top of NB 3,908' MD 24 hour notice to AOGCC for opportunity to witness. Page 37 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 21.12 Bleed the tubing and IA pressure to 0 psi. 21.13 Secure the tree and cellar. 21.14 RDMO Innovation 21.15 Turn the well over to operations via handover form. 22.0 Post Rig 22.1 RU slickline 22.2 Pull the ball & rod. Pull the RHC plug body. 22.3 RD slickline. 22.4 RU LRS. 22.5 Freeze protect the tubing with diesel down to ~2,500’ MD. 22.6 RD LRS State to witness MIT-IA to 1500 psi within 7 days of initial injection. Page 38 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 23.0 Innovation BOP Schematic Typical Ram Configuration Page 39 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 24.0 Wellhead Schematic FMC Gen 5 Typical 2-7/8” Page 40 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 25.0 Days Vs Depth Page 41 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 26.0 Formation Tops & Information Page 42 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure MPU I Pad Data Sheet Page 43 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure Page 44 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 27.0 Anticipated Drilling Hazards Decomplete: Failed C&P: The tubing will be cut pre-rig. We will cut and pull the 7” from inside 9-5/8” cased hole to minimize the risk of failing to pull the 7”. Window Exit: Tracking Casing The KOP is cemented. The risk of tracking casing is low. Production Hole Sections: 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 with AV of 200 ft/min. Lost Circulation: Lost circulation has been seen in the Colville formation at EMW exceeding ~ 12.0 ppg. Monitor ECDs during production section to ensure ECDs stay below 12.0. 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. Wellbore Stability: This well will drill through historically trouble shales (HRZ and Kalubik). Maintain sufficient MW for stability and utilize MPD to maintain constant bottom hole pressure to mitigate on/off pressure cycles. Use MPD to offset swab effect while TOOH. Follow tripping in hole schedule to manage surge pressures on shales. The well will be underreamed to 9-7/8” as well. Anti-Collision: This well has no close approaches on the planned wellpath. Monitor MWD survey for magnetic interference while drilling ahead. Faulting: There are no known faults in the hole section. H2S: Treat every hole section as though it has the potential for H2S. H2S events have typically been minor from I-pad wells. The majority of pad sample data is less than 10 ppm. I-04A had one sample reading of 36. The next highest reading was 3 ppm on I-15. Page 45 Version 2 March 2021 Milne Point Unit I-07A 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 46 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 28.0 Innovation Layout Page 47 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 29.0 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. Page 48 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 30.0 Innovation Choke Manifold Schematic Page 49 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 31.0 Spider Plot (NAD 27) (Governmental Sections) Page 50 Version 2 March 2021 Milne Point Unit I-07A Drilling Procedure 32.0 Surface Plat (As Built) (NAD 27) y500'fromUnitBoundar33I-3,8263I-05-06I-09-3 ,7 7 5 -3 ,9 6 8 -3 ,9 0 5 I-15-3 ,7 7 6 -3 ,9 0 4 I-15L1-3,696-3,882-3,821I-17-3,696-3,881-3,821I-17L1-3,696-3,820I-17L2-14I-19I-19L1-3,705-3,909-3,842I-16-3 ,8 2 3 -3 ,9 8 9-3 ,9 3 8H-16-3 ,8 2 2 -3 ,9 3 8 H-16L1-3,764-3,949-3,889I-03-3,817-4,010-3,948I-04-3 ,7 2 3 -3 ,9 0 7 -3 ,8 4 8 I-07-3,772-3,968-3,904I-15PB1-3,695-3,881-3,820I-17L1PB1I-19PB1-3,823-3,989-3,939H-16PB1-3,821-4,016-3,955I-04PB1I-19PB2-3 ,8 2 3 -3 ,9 8 9 -3 ,9 3 8 H-16PB2-3 ,8 2 3 -3 ,9 8 9 -3 ,9 3 8 H-16PB3-3,752I-35-3,753I-36-3,714-3,911-3,835-3,857I-21-3,750-3,953-3,860I-20I-36PB1I-36PB23839-3,747I-37-3,720-3,785-3,881I-28-3,747-3,938-3,880I-07A-3,718-3,899I-27HILCORP ALASKA LLCMILNE POINT FIELDAOR MAPI-07A Multi-Zone InjectorFEET05001,000POSTED WELL DATAWell NumberFMTOPS - MP_SB_NB[RBE] (SS)FMTOPS - MP_SB_OBA[RBE] (SS)FMTOPS - MP_SB_OA[RBE] (SS)WELL SYMBOLSActive OilLocationShut In OilINJ Well (Water Flood)P&A OilAbandoned InjectorPlug BackInjector LocationProducer LocationREMARKSWell Sybols at top of Schrader Bluff Formation (top NASand)Black dash circle = 1320' radius from NB sand top in I-07ARed numbers = Schrader Bluff NB sand tops (SSTVD)Green numbers = Schrader Bluff OA sand tops(SSTVD)Blue numbers = Schrader Bluff OBa sand tops (SSTVD)March 23, 2021PETRA 3/23/2021 3:19:14 PM Area of Review MPU I-07AAPI WELL STATUSTop of NB/ OA / OB(MD)Top of NB/ OA / OB(TVD)CBL Top ofCement(MD)CBL Top ofCement(TVD)Schrader Bluff NB /OA / OB StatusZonal Isolation50-029-22602-00-00 MPU I-07NB / OA / OBAProducer (P&A)NB: 3935' 3911' 3100' 3077' P&A Closed50-029-23679-00-00 MPU I-20OBa Producer (NotCompleted)NB: 4066'OA: 4343'OBa: 4923'3810'3920'4013'Surface Surface OpenNot Completed (OpShutdown) - OBa lateral - it isacross a 60' fault and notexpected to see injectionsupport50-029-23681-00-00 MPU I-21 OBa WINJNB: 4451'OA: 4940'OBa: 5406'3774'3895'3971'Surface Surface OpenCased and Cemented aboveOBa - it is across a 60' faultand not expected to seeinjection support50-029-23692-00-00 MPU I-27OA Producer (NotCompleted)N/A N/AWill beCementedto SurfaceWill beCementedto SurfaceN/APlanned OA Producer - it isacross a 60' fault and notexpected to see injectionsupport50-029-23691-00-00 MPU I-28 OA WINJNB: 4284'OA: 4840'3781'3941'Surface Surface OpenCased and Cemented aboveOA section - it is across a 60'fault and not expected to seeinjection support50-029-23675-00-00 MPU I-35 NB WINJ NB: 4842' 3812' Surface Surface OpenCased and Cemented aboveNB section - it is across a 60'fault and not expected to seeinjection support50-029-22068-01-00 MPU I-04A NB ProducerNB: 4412'OA: 4556'OBa: 4624'3886'4017'4079'~2533' 2300' Open Open to Injection Support50-029-22068-70-00 MPU I-04PB1 PlugbackNB: 4438'OA: 4556'OBa: 4672'3890'4024'4085'~2533' 2300' N/A N/A 1 Guhl, Meredith D (CED) From:Rixse, Melvin G (CED) Sent:Sunday, March 14, 2021 3:08 PM To:Nathan Sperry Cc:Joseph Lastufka; Stephen F Davies (DOA) (steve.davies@alaska.gov); Boyer, David L (CED) Subject:RE: PTD 221-010 Hilcorp Well I-07A - PB and sidetrack Nathan, Hilcorp has AOGCC approval to plug back the I‐07A hole section just cored and sidetrack off a cement plug as you described below. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907‐793‐1231 Office 907‐223‐3605 Cell CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907‐793‐1231 ) or (Melvin.Rixse@alaska.gov). cc. Lastufka, David Boyer, Steve Davies From: Nathan Sperry <Nathan.Sperry@hilcorp.com> Sent: Sunday, March 14, 2021 12:32 PM To: Rixse, Melvin G (CED) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: PTD 221‐010 Hilcorp Well I‐07A ‐ PB and sidetrack Mel, Innovation is currently drilling I‐07A. We unsuccessfully cored the Schrader NB sand but successfully cored the OA and we are on the way out of the hole with an Oba core right now with indications during the job that it went as planned. We would like to plugback and sidetrack to try the NB core again. The top of the Schrader Bluff is 3,882’ MD / 3,781’ TVD. Our plan is to pump a 15.8ppg cement plug from 4,178’ MD TD with TOC brought to a minimum of 3,782’ MD (100’ above top of Schrader). We are tentatively planning to bring TOC another 100’ above the minimum and using the plug as a kickoff plug. By using the plug as a kickoff plug, we will ensure that we have a firm TOC at or above 3,782’ MD. Our hole size is 8.5”. The bottom of our window is at 2,539’ MD. Please let me know if you need additional information. Thank you, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC 2 O: 907‐777‐8450 C: 907‐301‐8996 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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: Milne Point Field, Kuparuk Oil Pool, MPU I-07A Hilcorp Alaska, LLC Permit to Drill Number: 221-010 Surface Location: 2339' FSL, 3906' FEL, Sec. 33, T13N, R10E, UM, AK Bottomhole Location: 977' FNL, 2093' FEL, Sec. 33, T13N, R10E, 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 well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. 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, Jeremy M. Price Chair DATED this ___ day of February, 2021. Sincerely, 2 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address: 6. Proposed Depth: 12. Field/Pool(s): MD: 7,869' TVD: 7,161' 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 61.0' 15. Distance to Nearest Well Open Surface: x-551465 y- 6009453 Zone-4 34.5' to Same Pool: 5205' 16. Deviated wells: Kickoff depth: 2560 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 40 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 8-1/2"x9-7/8"7" 26# L-80 HYD TXP 7,869' Surface Surface 7,869' 7,161' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): 4,235' TVD 112' 2,663' 7,287' 3,808' - 4,010 3,785' - 3,987' Hydraulic Fracture planned? Yes No 20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number: 50-029-22602-Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Sr Pet Eng Sr Pet Geo Sr Res Eng February 15, 2021 Authorized Name: Monty Myers Authorized Title: Drilling Manager Nathan Sperry nathan.sperry@hilcorp.com 18. Casing Program: Top - Setting Depth - BottomSpecifications 3071 MPU I-07A Milne Point Field Kuparuk Oil Pool 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp Alaska, LLC 2339' FSL, 3906' FEL, Sec. 33, T13N, R10E, UM, AK ADL 025906 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1525 1119' FNL, 2226' FEL, Sec. 33, T13N, R10E, UM, AK 977' FNL, 2093' FEL, Sec. 33, T13N, R10E, UM, AK 83-085 2560 4160' Cement Quantity, c.f. or sacks Cement Volume MDSize Plugs (measured): (including stage data) Effect. Depth TVD (ft): 4,236' Effect. Depth MD (ft): 4,212'7,444'7,305' LengthCasing 4,236' Total Depth MD (ft): Total Depth TVD (ft): Liner Intermediate 7,425'7" Surface Conductor/Structural 20"80' 2,680'2,680' 7,425' 9-5/8" Authorized Signature: 490 sx Class 'G'Production See cover letter for other requirements.01-00 Perforation Depth MD (ft): 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Commission Use Only Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): 550 sx PF 'E', 250 sx Class 'G' 250 sx Arctic Set 112' Stg 1 L - 248 sx Class 'G' Stg 2 - 85 sx Class 'G' Form 10-401 Revised 3/2020 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) 1.21.2021 By Samantha Carlisle at 10:15 am, Jan 22, 2021 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2021.01.21 14:41:17 -09'00' Monty M Myers DSR-1/22/21MGR01FEB2021SFD 1/25/2021 221-010 269sx 2367 psi State witnessed BOPE test to 4000 psi. Annular to 2500 psi. 01FEB2021 2/1/20 50-029-22602-01-00 2/2/21 Milne Point Unit (MPU) I-07A Drilling Program Version 1 January 18, 2021 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 Casing Inspection ....................................................................................................................... 4 6.0 Internal Reporting Requirements ............................................................................................. 5 7.0 Wellbore Schematics .................................................................................................................. 6 8.0 Drilling / Completion Summary ................................................................................................ 9 9.0 Mandatory Regulatory Compliance / Notifications ................................................................ 10 10.0 R/U and Test BOPE ................................................................................................................. 12 11.0 Pull 2-7/8” Tubing .................................................................................................................... 13 12.0 Cut and Pull 7” Casing, Cleanout, Set CIBP .......................................................................... 14 13.0 Mill 8-1/2” Window and Kick Off ........................................................................................... 16 14.0 Production Hole Section Summary ......................................................................................... 19 15.0 Drill 8-1/2” x 9-7/8” Production Hole Section ......................................................................... 20 16.0 Run 7” Casing .......................................................................................................................... 25 17.0 Cement 7” Casing .................................................................................................................... 30 18.0 Cleanout Run ........................................................................................................................... 34 19.0 E-line: CBL/GR/CCL .............................................................................................................. 34 20.0 Perforate .................................................................................................................................. 34 21.0 Run 4-1/2” Frac String ............................................................................................................ 35 22.0 Post Rig .................................................................................................................................... 36 23.0 Innovation BOP Schematic ...................................................................................................... 37 24.0 Wellhead Schematic ................................................................................................................. 38 25.0 Days Vs Depth .......................................................................................................................... 39 26.0 Formation Tops & Information............................................................................................... 40 27.0 Anticipated Drilling Hazards .................................................................................................. 43 28.0 Innovation Layout.................................................................................................................... 45 29.0 FIT Procedure .......................................................................................................................... 46 30.0 Innovation Choke Manifold Schematic ................................................................................... 47 31.0 Casing Design Information ...................................................................................................... 48 32.0 8-1/2” x 9-7/8” Hole Section MASP ......................................................................................... 49 33.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 50 34.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 51 Page 2 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 1.0 Well Summary Well MPU I-07A Pad Milne Point “I” Pad Planned Completion Type 7” Cemented Casing Target Reservoir(s) Kuparuk Wellplan 5 Planned Well TD, MD / TVD 7,869’ MD / 7,161’ TVD PBTD, MD / TVD ±7,789 MD / 7,084’ TVD Surface Location (Governmental) 2339' FSL, 1374' FWL, Sec 33, T13N, R10E, UM, AK Surface Location (NAD 27 –Zone 4) X=551,464.8 Y=6,009,453.3 Top of Productive Horizon (Governmental) 1119' FNL, 2226' FEL, Sec 33, T13N, R10E, UM, AK TPH Location (NAD 27) X=553,126.7, Y=6,011,286.0 BHL (Governmental) 977' FNL, 2093' FEL, Sec 33, T13N, R10E, UM, AK BHL (NAD 27) X=553,258.9 Y=6,011,428.9 AFE Pre-Drill Days 4 Days AFE Drilling Days 11 Days AFE Completion Days 5 Days Maximum Anticipated Pressure (Surface) 1,525 psi Maximum Anticipated Pressure (Downhole/Reservoir) 3,071 psi (8.4 ppg EMW) Work String 5” 19.5# S-135 NC-50, DS-50 KB Elevation above MSL: 26.5 ft + 34.5 ft = 61.0 ft GL Elevation above MSL: 34.5 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams 2367 psi. Page 3 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 2.0 Management of Change Information Page 4 Version 1 January 2021 Milne Point Unit I-07A 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) 8-1/2” x 9- 7/8”7” 6.276 6.151 7.656 26 L-80 HYD TXP 7240 5410 604 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) 8-1/2” x 9-7/8” 5” 4.276”3.25” 6.625”19.5 S-135 NC50 31,032 34,136 560klb *Tension Rating Based on Premium Pipe 5.0 Casing Inspection All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 6.0 Internal Reporting Requirements 6.1 Fill out daily drilling report and cost report on Wellez. x Report covers operations from 6am to 6am x 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 tab. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. x Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 6.2 Afternoon Updates x Submit a short operations update each work day to mmyers@hilcorp.com, pmazzolini@hilcorp.com ,nathan.sperry@hilcorp.com,jengel@hilcorp.com and joseph.lastufka@hilcorp.com 6.3 Intranet Home Page Morning Update x 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. 6.4 EHS Incident Reporting x Health and safety: Notify EHS field coordinator. x Environmental: Drilling Environmental coordinator x Notify Drlg Manager & Drlg Engineer x Submit Hilcorp Incident report to contacts above within 24 hrs 6.5 Casing Tally x Send final “As-Run” Casing tally to nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 6.6 Casing and Cement report x Send casing and cement report for each string of casing to nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 6.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com Drilling Engineer Nate Sperry 907-777-8450 907.301.8996 nathan.sperry@hilcorp.com Completion Engineer Ian Toomey 907.777.8434 907.903.3987 itoomey@hilcorp.com Geologist (Schrader) Rebecca Emerson 907.777.8491 907.590.0648 Rebecca.emerson@hilcorp.com Res. Engineer (Schrader) Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com Geologist (Kuparuk) Radu Girbacea 907.777.8324 907.230.9490 rgirbacea@hilcorp.com Res. Engineer (Kuparuk) Daniel Taylor 907.777.8319 907.947.8051 dtaylor@hilcorp.com Drlg Environmental Coord Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com Safety Manager Carl Jones 907.777.8327 907.382.4336 cajones@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 907.227.8496 Joseph.Lastufka@hilcorp.com Page 6 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 7.0 Wellbore Schematics Page 7 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure Page 8 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure I-07 Parent TOWS 2,560' MD Page 9 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 8.0 Drilling / Completion Summary MPU I-07A is a sidetrack producing well targeting the Kuparuk River Pool, located on Milne Point ‘I-Pad’. The primary objective of the well is to core (conventional) the Schrader Bluff sands (NB, OA, OBa). After coring the Schrader bluff in 8-1/2” hole, we will continue drilling to the Kuparuk. The well will be completed with 7” casing. The directional plan is a single string slant well with the kick off point at ~2,560’ MD. Maximum hole angle is ~47 degrees. Drilling operations are expected to commence approximately February 15th, 2021, pending rig schedule. Production casing will be 7” 26# L-80 cemented casing run to 7,869’ MD / 7,161’ TVD. The well will be perforated by Innovation using tubing conveyed perf guns. Innovation will leave the well with the casing cemented and a 4-1/2” completion string installed. A separate sundry will be submitted for P&A operations on I-07. All waste & mud generated during drilling operations will be hauled to the Milne Point G&I facility located on “B” pad. General sequence of operations: 1. MIRU Innovation 2. N/U 13-5/8” x 5M BOPE and test 3. Pull 2-7/8” kill string 4. Cut and pull 7” casing. 5. Cleanout run. Set CIBP. 6. Set 9-5/8” WS and mill 8-1/2” window 7. Drill 8-1/2” hole to first coring point 8. Core Schrader sands, drilling 8-1/2” hole between coring points. 9. Drill 8-1/2” x 9-7/8” hole to base Kuparuk 10. Run and cement 7” production casing. 11. Perform cleanout run on 4” DP. 12. Run GR/CCL/CBL. 13. Perforate on 4” DP. 14. Run Upper Completion 15. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Production hole prior to coring (Schrader): No mud logging. LWD: GR/Res/NB GR 2. Production hole after coring (Kuparuk): No mud logging. LWD: Triple combo 3. Mud loggers will not be used on this well. Page 10 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 9.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOP’s shall be tested at 1 week intervals prior to initiating window milling and 2 week intervals during the drilling and completion of MPU I-07A thereafter. Provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/4000 psi & subsequent tests of the BOP equipment will be to 250/4000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation, notify AOGCC and 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. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements”. x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: x There are no variance requests at this time. Page 11 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 8-1/2” x 9-7/8” x 13-5/8” x 5M Hydril “GK” Annular BOP x 13-5/8” x 5M Hydril MPL Double Gate o Blind ram in btm cavity x Mud cross w/ 3” x 5M side outlets x 13-5/8” x 5M Hydril MPL Single ram x 3-1/8” x 5M Choke Line x 3-1/8” x 5M Kill line x 3-1/8” x 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/4000 Subsequent Tests: 250/4000 Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, 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: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Guy Schwartz / Petroleum Engineer / (O): 907-793-1226 / (C): 907-301-4533 / Email:guy.schwartz@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 12 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 10.0 R/U and Test BOPE All work prior to milling the window will be on the PRE AFE. 10.1 Reservoir abandonment was completed pre-rig via a separate Sundry. 10.2 Ensure Sundry, PTD, and drilling program are posted in the rig office and on the rig floor. 10.3 Level pad and ensure enough room for layout of rig footprint and R/U. 10.4 Ensure rig mats cover entire footprint of rig. 10.5 MIRU Innovation. Ensure rig is centered over the wellhead to prevent any wear to BOPE or wellhead. 10.6 N/U 13-5/8” x 5M BOP as follows: x 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 x Double gate ram should be dressed with 2-7/8” x 5” VBRs in top cavity,blind ram in bottom cavity. x Single ram can be dressed with 4-1/2” x 7” VBRs x N/U bell nipple, install flowline. x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 10.7 Test BOP to 250/4000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. x Install test dart in BPV. x Test upper VBR’s with 2-7/8” and 5” test joints x Test lower VBR’s with 4-1/2” and 7” test joints x Confirm test pressures with PTD x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 10.8 R/D BOP test equipment. Pull test dart and BPV. 24 hour notice to AOGCC Page 13 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 11.0 Pull 2-7/8” Tubing 11.1 PU landing joint or spear and recover the tubing hanger. 11.2 Back out lock down screws. 11.3 Pull tubing hanger with landing joint/XO to the floor. Have appropriate protectors ready. 11.4 The tubing is expected to be in good condition since it was just installed by ASR as a kill string. 11.5 Note and record PU weight required to pull the tubing from cut. 11.6 The expected weight of the string in a vertical hole filled with seawater is 15,500 lbs (assumes 2,750’ of tubing). 11.7 Circulate at least 1.5x BU after pulling the hanger to the floor. If desired, circulate a soap sweep surface-to-surface to clean the tubing. Swap well to 9.5ppg brine per Baroid. 11.8 Pull and lay down the tubing. Page 14 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 12.0 Cut and Pull 7” Casing, Cleanout, Set CIBP Important Notes: The Nabors 22E RKB was 28.5’ on the 7” run. There is a 2’ shift to our Innovation measurement of 26.5’ RKB. Ensure fishing rep and company man review parent tallies and agree on cut depth. The 7” casing was installed w/ a mandrel hanger and a packoff on 10/6/95 (see drilling report in PARENT WELL folder on the O-drive). Talk to the wellhead hands about pulling the 7” packoff and hanger and any potential contingencies we need to have lined up. We may need to steam the wellhead to get the packoff free. 7” was cemented on 10/7/1995. Centralizers were installed 2/jt on jts 1-16 and then 1/jt on 77-106 and 117 and 118. The second stage cement job was performed with 32.8 bbls of 15.8ppg G. No losses were noted. Estimated TOC based on GAUGE hole is 2,783’ MD (they were able to inject the FP fluid 12 hrs after cement was in place). They achieved a 12.5ppg FIT on the parent surface casing shoe. Operational Steps: 12.1 Ensure 7” x 9-5/8” annulus is bled to zero. Bleed each tour. 12.2 RU e-line. PU jet cutter for 7” casing per AK e-line. 12.3 RIH and cut the 7” in the 9-5/8” shoetrack. 12.4 Perform flowcheck. POOH to surface. 12.5 Rig up to circulate seawater down the 7” and out the annulus to displace the freeze protect and annulus fluids. Perform flowcheck and weight up using KCl/NaCl if necessary. Note: Schrader PP is subnormal in the area. 12.6 Pull packoff. PU landing joint or spear and recover the casing hanger. 12.7 Back out lock down screws. 12.8 Pull hanger with landing joint/XO to the floor. 12.9 Note and record PU weight required to pull the casing from cut. 12.10 The expected weight of the string in a vertical hole filled with seawater is ~59klbs (assumes ~2,600’ cut depth). Page 15 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 12.11 If necessary, circulate at least 1.5x BU at maximum rate after pulling the hanger to the floor. If desired, circulate a soap sweep surface-to-surface to clean the casing and annulus (pump fluid train per Baroid recommendation to clean the wellbore). 12.12 Pull and lay down the casing from the cut. 12.13 Run wear ring. 12.14 RIH with clean-out assembly on 5” pipe and clean-out the well to the top of the casing stub. 12.15 When on bottom circulate at max rate at least 1X BU or until returns are clean. Pump high vis sweep if necessary. Displace to 8.6ppg Baradrill-N fluid. Note: Displacement can also take place after setting the whipstock prior to milling. 12.16 POOH with clean-out assembly. 12.17 MU 9-5/8” CIBP on e-line. RIH and set CIBP per tally just above the float collar (base of joint #3) per AK e-line rep. Pressure test CIBP x 9-5/8” envelope to 2900 psi for 30 charted minutes (2,900 psi is ~50% of the 9-5/8” 40# internal yield pressure). x The TrackmasterElite whipstock is 30’ long. Set CIBP near the bottom of the joint so that we can set the WS in the joint to avoid milling a collar. 12.18 POOH. RD e-line. Page 16 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 13.0 Mill 8-1/2” Window and Kick Off Note: All following operations will be covered under the PTD for I-07A 13.1 Whipstock Set Depth Information: x Planned TOW: ~2,560’ MD x Whipstock is the Wellbore Integrity Solutions Trackmaster Elite x Whipstock is a mechanical set system. After tagging the CIBP, WS can be pulled uphole but will set when slacked off. x Verify shear bolt strength with WIS rep. 13.2 MU 8-1/2” mill/whipstock assembly as per fishing rep’s tally x Ensure magnets are in trough, under shakers, and flow area to capture metal shavings circulated 13.3 Install MWD. Rack back mill assembly. 13.4 Verify offset between MWD and whipstock tray, witnessed by Drilling Supervisor, MWD/DD and fishing rep. Document and record offset in well file. 13.5 Slowly run in the hole as per fishing rep. Run extremely slow through the BOP & wear bushing to prevent damaging the shear bolt. 13.6 Run in hole at 1 ½ to 2 minutes per double, or as per fishing rep. Ensure work string is stationary prior to setting the slips, and removed slowly as well. These precautions are to avoid weakening the shear bolt and prematurely setting the anchor. 13.7 Stop at least 30-45’ above planned set depth and obtain survey with MWD. 13.8 Milling fluid will be 8.6 ppg Baradrill-N. 13.9 With the bottom of the whipstock 30 – 45’ above the set depth, work torque out of string, measure and record P/U and S/O weights. Obtain good survey to orient whipstock face. 13.10 Orient whipstock to desired direction by turning DP in ¼ round increments. P/U and S/O on DP to work all torque out after oriented. Target orientation is 60q ROHS. Slack off and trip the anchor system on the CIBP per fishing rep. Page 17 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 13.11 Whipstock Orientation Diagram: Desired orientation of the whipstock face is 60R. Acceptable range is between 30R and 60R Hole Angle at window interval (2,560’ MD) is ~11°, Azimuth 40°. 13.12 Once whipstock is in desired orientation, set WS per fishing rep. 13.13 P/U 5-7K maximum overpull to verify anchor is set. The window mill can then be sheared off by slacking off weight on the whipstock shear bolt. 13.14 P/U 5-10’ above top of whipstock. 13.15 CBU and confirm 9.5 ppg MW in/out x Ensure Mud properties are sufficient for transporting metal cuttings x Visc: 40-60, YP: 18-20 13.16 Record P/U, S/O weights, and free rotation. Slack off to top of whipstock and with light weight and low torque. Mill window as per fishing rep. Utilize 4 ditch magnets on the surface to catch metal cuttings. Pump high visc sweeps as necessary. 13.17 If possible, install catch trays in shaker underflow chute to help catch metal cuttings. 13.18 Clean catch trays and ditch magnets frequently while milling window. 13.19 Mill window until the uppermost mill has passed across the entire tray. Dress and polish window as needed. 13.20 With upper mill at the end of the tray, this will drill ~ 20’ of new hole. 13.21 After window is milled and before POOH, shut down pumps and work milling assembly through window watching for drag. Dress and polish window as needed. After reaming, shut off pumps and rotary (if hole conditions allow) and pass through window checking for drag. 13.22 Circulate bottoms up until even MW in/out and hole is clean of metal shavings. Reduce mud properties for drilling. 60R 30R Page 18 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 13.23 Pull back into 9-5/8” casing and perform FIT t/ 12.0 ppg EMW. Chart Test. x Note: If a 12.0ppg is not achieved on the first attempt, try again. If second attempt falls short as well, contact drilling engineer. 13.24 POOH & LD milling BHA. Gauge mills for wear. 13.25 PU stack washer and wash BOPE stack. Function all rams to clear any potential milling debris. FIT data and earlier casing test data to AOGCC. Page 19 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 14.0 Production Hole Section Summary This is a single section 8-1/2” x 9-7/8” hole kicked off from cemented pipe. We will drill 8-1/2” hole to the Schrader Bluff sands and then core the NB, OBA, and OA stands. After coring, we will make up an underreaming assembly with triple combo and drill to TD in the Kuparuk. The Kuparuk pore pressure is expected to be 9.0 ppg EMW. Maintaining CBHP will be critical for maintaining HRZ and Kalubik stability. Note: Managed Pressure Drilling will be used in this hole section. Prior to drilling, verify all rig crew member are familiar with operation. If needed, install RCD bearing element and perform practice connections to familiarize crews with its operations. 8.4 ppg expected (9.0 a possibility). ,p Kuparuk pore pressure isgy expected to be 9.0 ppg EMW. Page 20 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 15.0 Drill 8-1/2” x 9-7/8” Production Hole Section Scope: x The plan is to drill 8-1/2” hole using the GeoPilot assembly to the coring intervals using GR/Res and Near-Bit GR. x We will core the Schrader Bluff per US Coring. o Coring Rep Contact Info: Chris Fletcher, Christopher.Fletcher@us-coring.com, 832-517- 5540 x After coring, we will PU an 8-1/2” x 9-7/8” RSS/UnderReaming assembly utilizing the NOV AnderReamer and drill to TD in the Kuparuk using a triple combo. x Proposed top coring depths are NB 3,910’ MD, OA 4,030’ MD, Oba 4,135’ MD. 15.1 PU 8-1/2” GeoPilot RSS assembly. x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Workstring will be 5” DP. 15.2 8-1/2” hole section mud program summary: x 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. x 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. x 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. x Run the centrifuge continuously while drilling the production hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x 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:8.6 – 9.5 ppg Baradrill-N drilling fluid Page 21 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure Properties: Section Density Plastic Viscosity Yield Point Total Solids MBT HPHT Production 8.6-9.5 15-25 20-25 <10% <7 <11.0 System Formulation: Baradrill-N 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 15.3 Ensure even MW in and out. Note: MPD is NOT needed prior to or during coring. MPD will be install after coring. 15.4 Drill 8-1/2” hole section with GeoPilot assembly to the first coring point (Schrader NB) per Schrader Geologist. x Control drill the final 100’ at 50 fph. 15.5 Backream 1 stand to get separation from the coring point (to minimize washout right above the coring point – this will help with coring BHA stabilization). After pulling one stand, CBU minimum 2X (or longer if necessary) to clean the hole. 15.6 As necessary, either dilute or swap to clean mud prior to coring.Ensure mud PH < 10 and API FL < 5.The core won’t see the fluid very long as the flow will be diverted down the core barrel annulus and out the bit but it is important to limit core swelling (using low fluid loss) so that the core doesn’t swell and jam in the barrel. 15.7 Backream to the window. POOH. 15.8 MU 8-1/2” coring BHA per US Coring rep. RIH per rep and core interval 1 per US Coring Rep. 15.9 POOH. MU RSS assembly and TIH. 15.10 MADpass as necessary. Drill to coring point #2 (Schrader Oba) per Schrader Geologist. x Control drill final 50’ at 50 fph. 15.11 Backream 1 stand to get separation from the coring point. After backreaming 1 stand, CBU 1X (or longer if necessary) to clean the hole. Page 22 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 15.12 Backream to the window. POOH. 15.13 MU 8-1/2” coring BHA per US Coring rep. RIH per rep and core interval 2. 15.14 POOH. MU RSS assembly. TIH and MADpass as necessary. 15.15 Drill to coring point #3 (Schrader OA) per Schrader Geologist. x Control drill the final 50’ at 50 fph. 15.16 Backream 1 stand to get separation from the coring point. After backreaming 1 stand, CBU 1X (or longer if necessary) to clean the hole. 15.17 Backream to the window. POOH. 15.18 MU 8-1/2” coring BHA per US Coring rep. RIH per rep and core interval 3. 15.19 POOH. MU 8-1/2” x 9-7/8” RSS assembly w/ NOV AnderReamer. TIH. Mud system for drilling the remainder of the well will be LSND with 3% KCl. 15.20 RIH to window. Install MPD. RIH to current TD and activate NOV AnderReamer (NOV rep will be remote). 15.21 Drill 8-1/2” x 9-7/8” hole section to section TD per Geologist and Drilling Engineer. x Flow Rate: 525-620 gpm (Target 200 ft/min AV) x RPM: 120 – for hole cleaning x RPM:Do NOT rotate >60 RPM off bottom. The risk is backing off the BHA below the AnderReamer. x WOB as needed x Target ECD and CBHP: 11.0 EMW +/- 5% (target this at the top of the HRZ) x Utilize MPD to maintain CBHP (constant bottom hole pressure) on connections, following annular pressure ramp schedule x This will reduce the pumps on/ pumps off pressure cycles on shales x Slow ramp pumps on/off on each connection x Smooth connections are more important that connection time x Monitor connections for losses, adjust as necessary x Take MWD surveys every stand drilled. x Kuparuk PP estimate is 8.4 ppg. Good drilling and tripping practices are vital for avoidance of differential sticking and HRZ/Kalubik stability. x Watch for fluid losses while drilling through Kuparuk. x Ensure black products are in the mud per Baroid prior to drilling into the HRZ. 15.22 Kuparuk production hole section mud program summary: Page 23 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure x Density: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. x 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. x Inhibition: 3% KCl will be used for handling clay cuttings. Watch MBT levels, dilute as necessary to maintain. Increase KCl % if needed x Run the centrifuge continuously while drilling the production hole, this will help with solids removal and minimize sand content and LGS to maintain fluid properties and quality of the mud system. x PVT will be used throughout the drilling phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type:9.5 – 10.8 ppg 3% KCl Inhibited LSND WBM Properties: Section Density (ppg) Plastic Viscosity Yield Point LGS MBT HPHT pH Intermediate 9.5 –10.5 15-25 15-20 <6% <20 <11.0 9-10 15.23 At TD, circulate a minimum of 2X BU x Drop the closing ball and close the AnderReamer per the NOV rep. x Circulate at full drill rate while rotating at 120 rpm’s x Only if necessary (if hole conditions dictate), perform short trip to 9-5/8” window following the pressure schedule to maintain CBHP at the base of the Kalubik. x We can slowly rack back a couple of stands while performing the BU circulations. x Attempt to pull through the Kalubik on elevators to the window. Only initiate backreaming if necessary. x Circulate a minimum of 1.5X BU at the window prior to TIH on elevators. 15.24 If backreaming is necessary: x Circulate at max rate while maintaining drilling ECD’s x Perform CBHP connections x Rotate at maximum rpm that can be sustained. x Limit pulling speed to 5 – 10 min/std (slip to slip time, not including connections). x If backreaming operations are commenced, continue backreaming to the window and circ at least a b/u once at the window. Page 24 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 15.25 At TD, circulate at least 2X BU. Observe well for flow, weight up to 10.3 ppg prior to TOOH. Include a casing running pill in the open hole to the top of the HRZ/Kalubik. Perform flow check prior to TOOH. x 12ppb black product, graphite, 2% lube 15.26 TOOH with the drilling assembly to 9-5/8” window while offsetting swab with MPD x Follow tripping schedule, matching string speed and annular pressure x Rack back DP while TOOH, Do not lay down drill pipe. This is to minimize open hole time before casing is on bottom. 15.27 CBU at 9-5/8” window 15.28 Pull RCD bearing element with bit at the window. Perform flowcheck. 15.29 Continue TOOH to HWDP/ BHA. 15.30 L/D 8-1/2” x 9-7/8” BHA 15.31 No additional logs are planned for the 8-1/2” x 9-7/8” hole section. Page 25 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 16.0 Run 7” Casing 16.1 Ensure rams have been tested on 7” test joint prior to running casing. 16.2 Ensure emergency slips are ready to go and staged where appropriate. 16.3 Ensure wear bushing is pulled from wellhead. 16.4 R/U 7” casing running equipment. x Ensure 7” TXP crossover is on rig floor and M/U to FOSV. x Ensure all casing has been drifted prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.5 Continue MU & thread locking 80’ shoe track assembly consisting of: 7” Float Shoe 1 joint –7” TXP, 2 Centralizers 10’ from each end w/ stop rings 7” Float Collar with Stage Cementer Bypass Baffle ‘Top Hat’ 1 joint – 7” TXP, 1 Centralizer mid joint with stop ring 7” HES Baffle Adaptor x Ensure bypass baffle is correctly installed on top of float collar. x Ensure proper operation of float equipment while picking up. x Ensure to record SN’s of all float equipment and stage tool components. This end up. Bypass Baffle Page 26 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 16.6 Float equipment and stage tool equipment drawings: Page 27 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 16.7 Run 7” casing per tally. x Install 7” ES cementer at the base of the Schrader Bluff x Dope pin end only w/ paint brush. x Utilize a collar clamp until weight is sufficient to keep slips set properly. x CENTRALIZERS: Run one 7” x 8-1/4” hydroform centralizer per joint across the cemented intervals. Centralize the ES cementer with 1 centralizer per joint for 5 joints below and 5 joints above the ES cementer. x MU shoetrack and check floats. 7” 26ppf L-80 TXP Torque OD Minimum/Maximum Optimum Operating Torque 7” 13,280 / 16,230 ft-lbs 14,750 ft-lbs 20,000 ft-lbs Circulating Strategy Stage pumps in ½ to 1 bpm increments. Allow pressures to stabilize prior to increasing to the next flowrate. Watch for packoffs, especially after the shoe is below the Kalubik. Depth Interval Strategy MU casing to window Fill as needed At window Circulate 1X BU (or until mud is conditioned) Window to HRZ Circulate 1 jt down for 5 minutes every 10 joints By the top HRZ Circulate down consecutive joints to achieve 1X BU by the top of the HRZ (having a BU within a couple hundred feet from the top is fine – does not need to occur right at the top). From THRZ to TD Fill pipe. Do not circulate unless necessary to wash down. Page 28 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure Page 29 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 16.5 RIH casing. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.6 Obtain up and down weights of the casing before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 16.7 RIH to TD as per running schedule. Monitor run for losses. Page 30 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 17.0 Cement 7” Casing 17.1 Circulate and condition mud for cement job. x Break circulation slowly and stage up rate with reciprocation. x Circulate minimum 1.5X BU to condition hole and mud for cement job. 17.2 Hold pre job safety meeting over upcoming casing cementing operations. Make room in pits for volume gained during cement job. Ensure adequate displacement volume is available. x Discuss pumps for displacement x Positions and expectations of all personnel involved in cement operations, have one hand in the pits specifically for strapping pits and recording volume returned. 17.3 The 7” casing cement job will be a two stage cement job. 17.4 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. 17.5 Fill surface cement lines with water and pressure test. 17.6 Pump 40 bbls 11.0 ppg tuned spacer. 17.7 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. Page 31 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 17.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of one slurry brought to 500’ MD above TKUP. Estimated 1st Stage Total Cement Volume: Cement Slurry Design (1st Stage Cement Job): 17.9 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 continue with the cement job. 17.10 After pumping cement, drop top plug (Shutoff plug) and displace cement with mud out of mud pits. x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 17.11 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. 17.12 Displacement calculation: (7869’-80’) x 0.0383 bpf = 298 bbls 17.13 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. 17.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume before consulting with Drilling Engineer. 17.15 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. Tail Slurry Density 15.8 lb/gal Yield 1.16 ft3/sk Mixed Water 4.98 gal/sk 55.7 312.2 269 sx (Target should be TOC 500' minimum above hydrocarbon bearing zone.) Page 32 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 17.16 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. 17.17 Increase pressure to 3,300 psi to open circulating ports in stage collar. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Second Stage Surface Cement Job: 17.18 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. 17.19 After Stage 1 tail cement reaches 50 psi compressive strength, swap circulating fluid to 9.5ppg KCl/NaCl. 17.20 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 17.21 Fill surface lines with water and pressure test. 17.22 Pump 50 bbls 10.0 ppg tuned spacer. 17.23 Mix and pump cement per below recipe for the 2 nd stage. 17.24 Cement volume based on annular volume + open hole excess (30%). Job will consist of tail, TOC brought 500’ above Schrader Bluff. Estimated 2nd Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): 13.9 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. Tail Slurry System G Density 14.0 lb/gal Yield 1.52 ft3/sk Mixed Water 7.74 gal/sk 85 sx Page 33 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 17.25 After pumping cement, drop ES Cementer closing plug and displace cement with 9.5ppg brine. 17.26 Displacement calculation: 4,165’ x 0.0383 bpf = 159.5 bbls mud 17.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. 17.28 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. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job 17.29 R/D cementing equipment. If cement was displaced with brine, set test plug and flush out wellhead and stack with FW. Pull the test plug. 17.30 Install packoff. Test void to 250/4000 psi for 10 min. 17.31 After Stage 2 cement has developed 100 psi compressive strength, freeze protect 9-5/8” x 7” annulus. Send final “As-Run” casing tally & casing and cement report to nathan.sperry@hilcorp.com, itoomey@hilcorp.com,and joseph.lastufka@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 34 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 18.0 Cleanout Run Swap to completion AFE. 18.1 Swap handling equipment to 4” DP. Ensure appropriate XO’s, safety joint, and TIW are staged in case of a well control event. 18.2 PU cleanout assembly on 4” DP (milltooth bit). 18.3 TIH with cleanout assembly to stage tool. Drill out stage tool. x Remind crews that we will have different density fluids above and below the stage tool. 18.4 TIH to TOC above the baffle adapter. Swap entire well to 10.3ppg brine (same density as static MW prior to cementing). 18.5 POOH racking back DP. 19.0 E-line: CBL/GR/CCL 19.1 RU E-line per vendor. Confirm RU with Ops Engineer. 19.2 PU and MU CBL/GR/CCL tool string. RIH, tag PBTD and POOH logging CBL/GR/CCL (use open hole MWD log for correlation). x Ensure Stage 1 TOC logged at least 500’ above TKUP and Stage 2 TOC at least 500’ above TSB. x Communicate CBL results to drilling engineer and ops engineer. 20.0 Perforate 20.1 Pressure test the 7” casing to 4,000 psi for 30 minutes (charted) prior to perforating. 20.2 Ensure appropriate XO’s, safety joint, and TIW are staged in case of a well control event. 20.3 MU 3-3/8” 6 SPF 60 deg phasing perf guns per tally from ops engineer. 20.4 Crossover to 4” XT-39 S-135 drillpipe. 20.5 Single in the hole to PBTD. Lightly tag PBTD and correct depth (tie PBTD to GR/CCL and MWD logs per Ops Engineer and geologist). 20.6 Close the annular or rams. Perforate per Halliburton. 20.7 Pull above top shot. Stop and monitor for losses and CBU. 20.8 Flowcheck and POOH while keeping the hole full and laying down DP. Verify all shots have fired. CBL to AOGCC. Page 35 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 21.0 Run 4-1/2” Frac String 21.1 RU 4-1/2” handling equipment. x Ensure wear bushing is pulled. x Ensure 4-1/2”, L-80, 13.5#, Hydril 625 x XT-39 crossover is on rig floor and M/U to FOSV. x Ensure all tubing has been drifted in the pipe shed prior to running. x Be sure to count the total # of joints in the pipe shed before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info. x Monitor displacement from wellbore while RIH. 21.2 PU, MU and RIH with the following 4-1/2” completion. Verify running order with Ops Engineer. x WLEG x 1 Joint, 4-1/2”, 13.5#, L-80, Hydril 625 BxP x Pup Joint, 4-1/2”, 13.5#, L-80, Hydril 625 BxP x Nipple, 3.813” X with RHC plug body installed x Pup Joint, 4-1/2”, 13.5#, L-80, Hydril 625 BxP x 1 Joint, 4-1/2”, 13.5#, L-80, Hydril 625 BxP x Pup Joint, 4-1/2”, 13.5#, L-80, Hydril 625 BxP x Packer, 4-1/2” x 7” Retrievable x Pup Joint, 4-1/2”, 13.5#, L-80, Hydril 625 BxP x XXX Joints, 4-1/2”, 13.5#, L-80, Hydril 625 BxP 4-1/2”, 13.5#, L-80, Hydril 625 Troque 21.3 PU and MU the tubing hanger with landing joint. 21.4 Land the tubing hanger and RILDS. Lay down the landing joint and install the BPV. 21.5 ND the BOP stack. Install the plug off tool. NU the tubing head adapter and tree. 21.6 PT the tubing hanger void to 250/5,000 psi. PT the tree to 500/5,000 psi. 21.7 Pull the plug off tool and BPV. 21.8 RU to reverse circulate. Reverse circulate the well to corrosion inhibited brine following by diesel freeze protect to ~2,500’ MD. 21.9 Drop the ball & rod. 21.10 Pressure up on the tubing to set the packer. PT the tubing to 4,400 psi for 30 minutes (charted). 21.11 Bleed the tubing pressure to 2,500 psi and PT the IA to 4,000 psi for 30 minutes (charted). 21.12 Bleed the tubing and IA pressure to 0 psi. Tubing OD Minimum Optimum Maximum Operating Torque 4-1/2” 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs Page 36 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 21.13 Secure the tree and cellar. 21.14 RDMO Innovation 21.15 Turn the well over to operations via handover form. 22.0 Post Rig 22.1 RU slickline 22.2 Pull the ball & rod. Pull the RHC plug body. 22.3 RD slickline. 22.4 RU LRS. 22.5 Freeze protect the tubing with diesel down to ~2,500’ MD. 22.6 RD LRS Page 37 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 23.0 Innovation BOP Schematic Typical Ram Configuration Page 38 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 24.0 Wellhead Schematic FMC Gen 5 Typical 2-7/8” Page 39 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 25.0 Days Vs Depth Page 40 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 26.0 Formation Tops & Information Page 41 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure MPU I Pad Data Sheet Page 42 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure Page 43 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 27.0 Anticipated Drilling Hazards Decomplete: Failed C&P: The tubing will be cut pre-rig. We will cut and pull the 7” from inside 9-5/8” cased hole to minimize the risk of failing to pull the 7”. Window Exit: Tracking Casing The KOP is cemented. The risk of tracking casing is low. Production Hole Sections: 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 with AV of 200 ft/min. Lost Circulation: Lost circulation has been seen in the Colville formation at EMW exceeding ~ 12.0 ppg. Monitor ECDs during production section to ensure ECDs stay below 12.0. 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. Wellbore Stability: This well will drill through historically trouble shales (HRZ and Kalubik). Maintain sufficient MW for stability and utilize MPD to maintain constant bottom hole pressure to mitigate on/off pressure cycles. Use MPD to offset swab effect while TOOH. Follow tripping in hole schedule to manage surge pressures on shales. The well will be underreamed to 9-7/8” as well. Anti-Collision: This well has no close approaches on the planned wellpath. Monitor MWD survey for magnetic interference while drilling ahead. Faulting: There are no known faults in the hole section. H2S: Treat every hole section as though it has the potential for H2S. H2S events have typically been minor from I-pad wells. The majority of pad sample data is less than 10 ppm. I-04A had one sample reading of 36. The next highest reading was 3 ppm on I-15. Page 44 Version 1 January 2021 Milne Point Unit I-07A 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 45 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 28.0 Innovation Layout Page 46 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 29.0 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. Page 47 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 30.0 Innovation Choke Manifold Schematic Page 48 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 31.0 Casing Design Information Page 49 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 32.0 8-1/2” x 9-7/8” Hole Section MASP Page 50 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 33.0 Spider Plot (NAD 27) (Governmental Sections) Page 51 Version 1 January 2021 Milne Point Unit I-07A Drilling Procedure 34.0 Surface Plat (As Built) (NAD 27) 11 January, 2021 Plan: MPU I-07A wp05 Milne Point M Pt I Pad Plan: MPI-07 Plan: MPU I-07A Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Standard Proposal Report Well: Wellbore: Plan: MPI-07 Plan: MPU I-07A Survey Calculation Method:Minimum Curvature MPU I-07A Planned RKB @ 61.00usft Design:MPU I-07A wp05 Database:NORTH US + CANADA MD Reference:MPU I-07A Planned RKB @ 61.00usft North Reference: Well Plan: MPI-07 True Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Milne Point, ACT, MILNE POINT Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Site Position: From: Site Latitude: Longitude: Position Uncertainty: Northing: Easting: Grid Convergence: M Pt I Pad, TR-13-10 usft Map usft usft °0.39Slot Radius:"0 6,008,388.010 550,245.830 5.00 70° 26' 1.282 N 149° 35' 25.422 W Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: Plan: MPI-07, MPI-07 usft usft 0.00 0.00 6,009,453.309 551,464.818 34.50Wellhead Elevation:usft0.00 70° 26' 11.678 N 149° 34' 49.433 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) Plan: MPU I-07A Model NameMagnetics BGGM2020 3/15/2021 15.63 80.81 57,343.52630030 Phase:Version: Audit Notes: Design MPU I-07A wp05 PLAN Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:2,560.00 40.000.000.0026.50 Inclination (°) Azimuth (°) +E/-W (usft) Tool Face (°) +N/-S (usft) Measured Depth (usft) Vertical Depth (usft) Dogleg Rate (°/100usft) Build Rate (°/100usft) Turn Rate (°/100usft) Plan Sections TVD System usft 0.000.000.000.00104.45142.762,544.3031.3110.232,560.00 2,483.30 60.0053.256.0012.00106.32145.312,561.0040.7711.252,577.00 2,500.00 0.000.000.000.00108.87148.272,580.6240.7711.252,597.00 2,519.62 0.070.014.004.00156.76203.772,829.0440.8021.632,856.36 2,768.04 0.000.000.000.00384.58467.683,708.3540.8021.633,802.27 3,647.35 22.053.553.754.00408.64493.933,791.0044.0025.003,892.28 3,730.00 0.000.000.000.00580.00671.384,320.0044.0025.004,475.97 4,259.00 -0.90-0.104.004.00721.48819.024,639.6243.6440.224,856.52 4,578.62 0.000.000.000.001,369.421,498.595,749.9143.6440.226,310.62 5,688.91 -179.54-0.07-3.003.001,600.881,742.726,330.0043.1720.006,984.69 6,269.00 0.000.000.000.001,708.201,857.136,761.0043.1720.007,443.35 6,700.00 0.000.000.000.001,807.811,963.317,161.0043.1720.007,869.02 7,100.00 1/11/2021 11:29:25PM COMPASS 5000.15 Build 91E Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Standard Proposal Report Well: Wellbore: Plan: MPI-07 Plan: MPU I-07A Survey Calculation Method:Minimum Curvature MPU I-07A Planned RKB @ 61.00usft Design:MPU I-07A wp05 Database:NORTH US + CANADA MD Reference:MPU I-07A Planned RKB @ 61.00usft North Reference: Well Plan: MPI-07 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS -34.50 Vert Section 26.50 0.00 26.50 0.00 0.000.00 551,464.8186,009,453.309-34.50 0.000 0.00 109.00 0.00 109.00 0.00 0.000.00 551,464.8186,009,453.30948.00 0.000 0.00 20" 173.50 0.48 173.50 -0.26 -0.06193.56 551,464.7566,009,453.046112.50 0.744 -0.24 259.37 0.54 259.37 -0.73 0.24106.98 551,465.0626,009,452.580198.37 0.816 -0.41 349.54 0.70 349.53 -0.94 1.1999.33 551,466.0136,009,452.374288.53 0.199 0.04 441.61 0.71 441.59 -1.26 2.27113.72 551,467.0926,009,452.060380.59 0.192 0.49 531.75 0.78 531.73 -1.73 3.34113.45 551,468.1706,009,451.599470.73 0.078 0.82 713.90 0.95 713.86 -2.74 5.90110.07 551,470.7326,009,450.605652.86 0.097 1.69 805.60 0.87 805.54 -3.07 7.3095.20 551,472.1426,009,450.291744.54 0.271 2.34 896.38 0.21 896.32 -2.97 7.96349.82 551,472.7986,009,450.397835.32 1.044 2.84 987.24 0.24 987.18 -2.70 7.77303.35 551,472.6086,009,450.664926.18 0.198 2.93 1,081.05 0.40 1,080.99 -2.44 7.32297.49 551,472.1516,009,450.9201,019.99 0.174 2.83 1,175.54 0.47 1,175.48 -2.07 6.70303.47 551,471.5336,009,451.2821,114.48 0.088 2.72 1,271.34 0.51 1,271.27 -1.74 5.96285.76 551,470.7936,009,451.6091,210.27 0.163 2.50 1,366.91 0.55 1,366.84 -1.45 5.13292.47 551,469.9576,009,451.8941,305.84 0.077 2.19 1,461.83 0.45 1,461.76 -1.00 4.46316.94 551,469.2796,009,452.3361,400.76 0.246 2.09 1,557.30 3.57 1,557.16 1.89 5.6028.22 551,470.4096,009,455.2371,496.16 3.616 5.05 1,650.57 6.49 1,650.06 8.82 9.9233.93 551,474.6776,009,462.2001,589.06 3.173 13.14 1,746.32 7.50 1,745.10 18.29 16.7237.23 551,481.4126,009,471.7111,684.10 1.135 24.76 1,841.16 11.26 1,838.65 30.55 26.1337.67 551,490.7336,009,484.0371,777.65 3.965 40.20 1,934.06 12.36 1,929.59 45.44 37.9539.14 551,502.4486,009,499.0081,868.59 1.227 59.20 2,027.91 10.99 2,021.49 60.57 49.4134.91 551,513.8036,009,514.2121,960.49 1.720 78.16 2,127.70 11.08 2,119.44 76.26 60.3034.62 551,524.5846,009,529.9772,058.44 0.106 97.18 2,221.72 10.70 2,211.76 90.93 70.3234.03 551,534.4996,009,544.7122,150.76 0.421 114.85 2,318.47 10.77 2,306.82 105.84 80.4434.28 551,544.5136,009,559.6932,245.82 0.087 132.78 2,412.88 10.62 2,399.59 120.36 90.2433.80 551,554.2196,009,574.2772,338.59 0.185 150.21 2,506.16 10.30 2,491.32 134.59 99.4331.87 551,563.3056,009,588.5642,430.32 0.509 167.01 2,560.00 10.23 2,544.30 142.76 104.4531.31 551,568.2736,009,596.7682,483.30 0.232 176.50 KOP : Start Dir 12º/100' : 2560' MD, 2544.3'TVD : 60° RT TF 2,561.00 10.28 2,545.28 142.91 104.5531.91 551,568.3656,009,596.9212,484.28 11.987 176.67 9 5/8" TOW 2,577.00 11.25 2,561.00 145.31 106.3240.77 551,570.1236,009,599.3352,500.00 11.987 179.66 End Dir : 2577' MD, 2561' TVD 2,597.00 11.25 2,580.62 148.27 108.8740.77 551,572.6516,009,602.3082,519.62 0.000 183.56 Start Dir 4º/100' : 2597' MD, 2580.62'TVD 2,600.00 11.37 2,583.56 148.71 109.2540.77 551,573.0326,009,602.7562,522.56 4.000 184.15 2,700.00 15.37 2,680.83 166.22 124.3640.79 551,588.0146,009,620.3702,619.83 4.000 207.27 2,800.00 19.37 2,776.25 188.82 143.8640.80 551,607.3606,009,643.1042,715.25 4.000 237.12 2,856.36 21.63 2,829.03 203.77 156.7640.80 551,620.1526,009,658.1322,768.03 4.000 256.86 End Dir : 2856.36' MD, 2829.04' TVD 2,900.00 21.63 2,869.60 215.94 167.2740.80 551,630.5776,009,670.3792,808.60 0.000 272.94 3,000.00 21.63 2,962.56 243.84 191.3540.80 551,654.4676,009,698.4432,901.56 0.000 309.79 3,030.59 21.63 2,991.00 252.38 198.7240.80 551,661.7756,009,707.0282,930.00 0.000 321.07 UG_COAL1 1/11/2021 11:29:25PM COMPASS 5000.15 Build 91E Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Standard Proposal Report Well: Wellbore: Plan: MPI-07 Plan: MPU I-07A Survey Calculation Method:Minimum Curvature MPU I-07A Planned RKB @ 61.00usft Design:MPU I-07A wp05 Database:NORTH US + CANADA MD Reference:MPU I-07A Planned RKB @ 61.00usft North Reference: Well Plan: MPI-07 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 2,994.52 Vert Section 3,100.00 21.63 3,055.52 271.74 215.4440.80 551,678.3566,009,726.5062,994.52 0.000 346.65 3,200.00 21.63 3,148.48 299.64 239.5240.80 551,702.2466,009,754.5703,087.48 0.000 383.50 3,300.00 21.63 3,241.44 327.55 263.6140.80 551,726.1356,009,782.6343,180.44 0.000 420.36 3,385.59 21.63 3,321.00 351.42 284.2240.80 551,746.5816,009,806.6533,260.00 0.000 451.90 LA3 3,400.00 21.63 3,334.40 355.45 287.6940.80 551,750.0246,009,810.6983,273.40 0.000 457.21 3,500.00 21.63 3,427.36 383.35 311.7840.80 551,773.9146,009,838.7613,366.36 0.000 494.07 3,600.00 21.63 3,520.32 411.25 335.8640.80 551,797.8036,009,866.8253,459.32 0.000 530.92 3,616.87 21.63 3,536.00 415.96 339.9340.80 551,801.8336,009,871.5593,475.00 0.000 537.14 UGNU MB 3,700.00 21.63 3,613.28 439.15 359.9540.80 551,821.6926,009,894.8893,552.28 0.000 567.78 3,802.27 21.63 3,708.35 467.68 384.5840.80 551,846.1246,009,923.5893,647.35 0.000 605.47 Start Dir 4º/100' : 3802.27' MD, 3708.35'TVD 3,881.27 24.58 3,781.00 490.60 405.4443.65 551,866.8256,009,946.6463,720.00 4.000 636.43 SB_NA 3,892.28 25.00 3,791.00 493.93 408.6444.00 551,869.9996,009,949.9993,730.00 4.000 641.04 End Dir : 3892.28' MD, 3791' TVD 3,900.00 25.00 3,798.00 496.28 410.9144.00 551,872.2496,009,952.3623,737.00 0.001 644.30 3,908.83 25.00 3,806.00 498.96 413.5044.00 551,874.8246,009,955.0643,745.00 0.000 648.02 SB_NB 4,000.00 25.00 3,888.63 526.68 440.2644.00 551,901.3946,009,982.9613,827.63 0.000 686.45 4,035.72 25.00 3,921.00 537.54 450.7544.00 551,911.8046,009,993.8923,860.00 0.000 701.51 SB_OA 4,100.00 25.00 3,979.26 557.08 469.6244.00 551,930.5386,010,013.5613,918.26 0.000 728.61 4,135.02 25.00 4,011.00 567.73 479.9044.00 551,940.7466,010,024.2783,950.00 0.000 743.38 SB_OBA 4,162.61 25.00 4,036.00 576.11 488.0044.00 551,948.7856,010,032.7193,975.00 0.000 755.01 SB_OBA_base 4,200.00 25.00 4,069.89 587.48 498.9844.00 551,959.6826,010,044.1604,008.89 0.000 770.77 4,300.00 25.00 4,160.52 617.88 528.3444.00 551,988.8266,010,074.7604,099.52 0.000 812.93 4,400.00 25.00 4,251.15 648.28 557.6944.00 552,017.9706,010,105.3594,190.15 0.000 855.09 4,428.52 25.00 4,277.00 656.95 566.0744.00 552,026.2836,010,114.0874,216.00 0.000 867.12 Colville 4,475.97 25.00 4,320.00 671.38 580.0044.00 552,040.1116,010,128.6064,259.00 0.000 887.12 Start Dir 4º/100' : 4475.97' MD, 4320'TVD 4,500.00 25.96 4,341.69 678.81 587.1843.97 552,047.2386,010,136.0934,280.69 4.000 897.43 4,600.00 29.96 4,430.00 712.59 619.6843.84 552,079.5076,010,170.0904,369.00 4.000 944.20 4,700.00 33.96 4,514.83 750.79 656.3143.75 552,115.8656,010,208.5394,453.83 4.000 997.01 4,800.00 37.96 4,595.75 793.23 696.8843.67 552,156.1366,010,251.2534,534.75 4.000 1,055.59 4,856.52 40.22 4,639.62 819.02 721.4843.64 552,180.5556,010,277.2044,578.62 4.000 1,091.16 End Dir : 4856.52' MD, 4639.62' TVD 4,900.00 40.22 4,672.82 839.34 740.8543.64 552,199.7876,010,297.6554,611.82 0.000 1,119.18 5,000.00 40.22 4,749.17 886.07 785.4143.64 552,244.0196,010,344.6924,688.17 0.000 1,183.62 5,100.00 40.22 4,825.53 932.81 829.9743.64 552,288.2516,010,391.7304,764.53 0.000 1,248.07 5,200.00 40.22 4,901.88 979.54 874.5343.64 552,332.4836,010,438.7674,840.88 0.000 1,312.51 1/11/2021 11:29:25PM COMPASS 5000.15 Build 91E Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Standard Proposal Report Well: Wellbore: Plan: MPI-07 Plan: MPU I-07A Survey Calculation Method:Minimum Curvature MPU I-07A Planned RKB @ 61.00usft Design:MPU I-07A wp05 Database:NORTH US + CANADA MD Reference:MPU I-07A Planned RKB @ 61.00usft North Reference: Well Plan: MPI-07 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 4,917.24 Vert Section 5,300.00 40.22 4,978.24 1,026.28 919.0943.64 552,376.7156,010,485.8044,917.24 0.000 1,376.95 5,400.00 40.22 5,054.60 1,073.01 963.6543.64 552,420.9476,010,532.8414,993.60 0.000 1,441.40 5,500.00 40.22 5,130.95 1,119.75 1,008.2143.64 552,465.1796,010,579.8785,069.95 0.000 1,505.84 5,600.00 40.22 5,207.31 1,166.48 1,052.7743.64 552,509.4116,010,626.9155,146.31 0.000 1,570.28 5,700.00 40.22 5,283.66 1,213.22 1,097.3343.64 552,553.6436,010,673.9525,222.66 0.000 1,634.73 5,800.00 40.22 5,360.02 1,259.95 1,141.8943.64 552,597.8766,010,720.9895,299.02 0.000 1,699.17 5,900.00 40.22 5,436.38 1,306.69 1,186.4543.64 552,642.1086,010,768.0265,375.38 0.000 1,763.62 6,000.00 40.22 5,512.73 1,353.42 1,231.0143.64 552,686.3406,010,815.0635,451.73 0.000 1,828.06 6,100.00 40.22 5,589.09 1,400.16 1,275.5743.64 552,730.5726,010,862.1015,528.09 0.000 1,892.50 6,200.00 40.22 5,665.44 1,446.89 1,320.1343.64 552,774.8046,010,909.1385,604.44 0.000 1,956.95 6,300.00 40.22 5,741.80 1,493.63 1,364.6943.64 552,819.0366,010,956.1755,680.80 0.000 2,021.39 6,310.62 40.22 5,749.91 1,498.59 1,369.4243.64 552,823.7336,010,961.1705,688.91 0.000 2,028.24 Start Dir 3º/100' : 6310.62' MD, 5749.91'TVD 6,400.00 37.54 5,819.48 1,539.21 1,408.1243.60 552,862.1476,011,002.0455,758.48 3.000 2,084.22 6,500.00 34.54 5,900.33 1,581.82 1,448.6743.55 552,902.4016,011,044.9375,839.33 3.000 2,142.94 6,600.00 31.54 5,984.15 1,621.35 1,486.2243.50 552,939.6706,011,084.7165,923.15 3.000 2,197.35 6,700.00 28.54 6,070.71 1,657.67 1,520.6643.44 552,973.8536,011,121.2746,009.71 3.000 2,247.31 6,800.00 25.54 6,159.77 1,690.70 1,551.8943.36 553,004.8576,011,154.5116,098.77 3.000 2,292.69 6,900.00 22.54 6,251.08 1,720.33 1,579.8443.27 553,032.5956,011,184.3356,190.08 3.000 2,333.35 6,984.69 20.00 6,330.00 1,742.72 1,600.8843.17 553,053.4766,011,206.8636,269.00 3.000 2,364.02 End Dir : 6984.69' MD, 6330' TVD 6,996.40 20.00 6,341.00 1,745.64 1,603.6243.17 553,056.1956,011,209.8016,280.00 0.000 2,368.02 HRZ 7,000.00 20.00 6,344.39 1,746.54 1,604.4643.17 553,057.0326,011,210.7066,283.39 0.000 2,369.25 7,099.62 20.00 6,438.00 1,771.39 1,627.7743.17 553,080.1696,011,235.7146,377.00 0.000 2,403.27 KLB 7,100.00 20.00 6,438.36 1,771.48 1,627.8643.17 553,080.2576,011,235.8096,377.36 0.000 2,403.40 7,177.31 20.00 6,511.00 1,790.77 1,645.9543.17 553,098.2116,011,255.2156,450.00 0.000 2,429.80 KLGM 7,200.00 20.00 6,532.32 1,796.43 1,651.2643.17 553,103.4826,011,260.9126,471.32 0.000 2,437.55 7,300.00 20.00 6,626.29 1,821.37 1,674.6643.17 553,126.7076,011,286.0156,565.29 0.000 2,471.70 7,310.33 20.00 6,636.00 1,823.95 1,677.0843.17 553,129.1066,011,288.6086,575.00 0.000 2,475.23 KUP_D 7,400.00 20.00 6,720.26 1,846.31 1,698.0643.17 553,149.9326,011,311.1186,659.26 0.000 2,505.85 7,443.35 20.00 6,761.00 1,857.13 1,708.2043.17 553,160.0006,011,322.0006,700.00 0.000 2,520.65 7,500.00 20.00 6,814.23 1,871.26 1,721.4643.17 553,173.1576,011,336.2206,753.23 0.000 2,540.00 7,555.09 20.00 6,866.00 1,885.00 1,734.3543.17 553,185.9516,011,350.0506,805.00 0.000 2,558.81 LCU / KUP_B6 7,600.00 20.00 6,908.20 1,896.20 1,744.8643.17 553,196.3816,011,361.3236,847.20 0.000 2,574.15 7,700.00 20.00 7,002.17 1,921.15 1,768.2643.17 553,219.6066,011,386.4266,941.17 0.000 2,608.30 7,730.68 20.00 7,031.00 1,928.80 1,775.4443.17 553,226.7326,011,394.1286,970.00 0.000 2,618.78 KUP_A3 7,772.18 20.00 7,070.00 1,939.15 1,785.1543.17 553,236.3716,011,404.5467,009.00 0.000 2,632.95 KUP_A2 7,800.00 20.00 7,096.14 1,946.09 1,791.6643.17 553,242.8316,011,411.5297,035.14 0.000 2,642.45 1/11/2021 11:29:25PM COMPASS 5000.15 Build 91E Page 5 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Standard Proposal Report Well: Wellbore: Plan: MPI-07 Plan: MPU I-07A Survey Calculation Method:Minimum Curvature MPU I-07A Planned RKB @ 61.00usft Design:MPU I-07A wp05 Database:NORTH US + CANADA MD Reference:MPU I-07A Planned RKB @ 61.00usft North Reference: Well Plan: MPI-07 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 7,040.00 Vert Section 7,805.17 20.00 7,101.00 1,947.38 1,792.8743.17 553,244.0326,011,412.8277,040.00 0.000 2,644.22 KUP_A1 7,853.06 20.00 7,146.00 1,959.33 1,804.0743.17 553,255.1546,011,424.8497,085.00 0.000 2,660.57 KUP_A_BASE 7,869.02 20.00 7,161.00 1,963.31 1,807.8143.17 553,258.8616,011,428.8557,100.00 0.000 2,666.02 Total Depth : 7869.02' MD, 7161' TVD - 7" x 8 1/2" Target Name - hit/miss target - Shape TVD (usft) Northing (usft) Easting (usft) +N/-S (usft) +E/-W (usft) Tar gets Dip Angle (°) Dip Dir. (°) MPU I-07A wp01 tgt02 7,161.00 6,011,428.860 553,258.8601,963.31 1,807.810.00 0.00 - plan misses target center by 0.01usft at 7869.02usft MD (7161.00 TVD, 1963.31 N, 1807.81 E) - Point MPU I-07A wp05 cp1 3,791.00 6,009,950.000 551,870.000493.93 408.640.00 0.00 - plan hits target center - Point MPU I-07A wp01 tgt01 6,761.00 6,011,322.000 553,160.0001,857.13 1,708.200.00 0.00 - plan hits target center - Point Vertical Depth (usft) Measured Depth (usft) Casing Diameter (") Hole Diameter (")Name Casing Points 9 5/8" TOW2,545.282,561.00 9-5/8 12-1/4 7" x 8 1/2"7,161.007,869.02 78-1/2 1/11/2021 11:29:25PM COMPASS 5000.15 Build 91E Page 6 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Standard Proposal Report Well: Wellbore: Plan: MPI-07 Plan: MPU I-07A Survey Calculation Method:Minimum Curvature MPU I-07A Planned RKB @ 61.00usft Design:MPU I-07A wp05 Database:NORTH US + CANADA MD Reference:MPU I-07A Planned RKB @ 61.00usft North Reference: Well Plan: MPI-07 True Measured Depth (usft) Vertical Depth (usft) Dip Direction (°)Name Lithology Dip (°) Formations Vertical Depth SS 7,099.62 6,438.00 KLB 6,996.40 6,341.00 HRZ 4,135.02 4,011.00 SB_OBA 4,162.61 4,036.00 SB_OBA_base 3,908.83 3,806.00 SB_NB 3,881.27 3,781.00 SB_NA 7,310.33 6,636.00 KUP_D 7,177.31 6,511.00 KLGM 7,853.06 7,146.00 KUP_A_BASE 3,030.59 2,991.00 UG_COAL1 1,346.07 1,346.00 SV5 1,792.72 1,791.00 BPRF 2,200.58 2,191.00 SV0 3,616.87 3,536.00 UGNU MB 4,428.52 4,277.00 Colville 7,805.17 7,101.00 KUP_A1 4,035.72 3,921.00 SB_OA 7,772.18 7,070.00 KUP_A2 7,555.09 6,866.00 LCU / KUP_B6 7,730.68 7,031.00 KUP_A3 3,385.59 3,321.00 LA3 Measured Depth (usft) Vertical Depth (usft) +E/-W (usft) +N/-S (usft) Local Coordinates Comment Plan Annotations 2,560.00 2,544.30 142.76 104.45 KOP : Start Dir 12º/100' : 2560' MD, 2544.3'TVD : 60° RT TF 2,577.00 2,561.00 145.31 106.32 End Dir : 2577' MD, 2561' TVD 2,597.00 2,580.62 148.27 108.87 Start Dir 4º/100' : 2597' MD, 2580.62'TVD 2,856.36 2,829.03 203.77 156.76 End Dir : 2856.36' MD, 2829.04' TVD 3,802.27 3,708.35 467.68 384.58 Start Dir 4º/100' : 3802.27' MD, 3708.35'TVD 3,892.28 3,791.00 493.93 408.64 End Dir : 3892.28' MD, 3791' TVD 4,475.97 4,320.00 671.38 580.00 Start Dir 4º/100' : 4475.97' MD, 4320'TVD 4,856.52 4,639.62 819.02 721.48 End Dir : 4856.52' MD, 4639.62' TVD 6,310.62 5,749.91 1,498.59 1,369.42 Start Dir 3º/100' : 6310.62' MD, 5749.91'TVD 6,984.69 6,330.00 1,742.72 1,600.88 End Dir : 6984.69' MD, 6330' TVD 7,869.02 7,161.00 1,857.13 1,708.20 Total Depth : 7869.02' MD, 7161' TVD 1/11/2021 11:29:25PM COMPASS 5000.15 Build 91E Page 7 11 January, 2021Milne PointM Pt I PadPlan: MPI-07Plan: MPU I-07A5002922602MPU I-07A wp05Reference Design: M Pt I Pad - Plan: MPI-07 - Plan: MPU I-07A - MPU I-07A wp05Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Well Coordinates: 6,009,453.31 N, 551,464.82 E (70° 26' 11.68" N, 149° 34' 49.43" W)Datum Height: MPU I-07A Planned RKB @ 61.00usftScan Range: 2,560.00 to 7,869.02 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.15 Build: 91EScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftGLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of referenceScan Type:Scan Type:25.00 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPI-07 - MPU I-07A wp05Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 2,560.00 to 7,869.02 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt I Pad - Plan: MPI-07 - Plan: MPU I-07A - MPU I-07A wp05MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt I PadMPI-02 - MPI-02 - MPI-02 837.19 2,560.00 819.38 2,134.59 47.0142,560.00Clearance Factor Pass - MPI-03 - MPI-03 - MPI-03949.23 2,560.00 929.85 2,184.93 48.9652,560.00Clearance Factor Pass - MPI-04 - MPI-04 - MPI-04 723.62 2,560.00 704.16 2,327.69 37.1802,560.00Ellipse Separation Pass - MPI-04 - MPI-04 - MPI-04967.14 5,135.00 907.64 4,900.00 16.2535,135.00Clearance Factor Pass - MPI-04 - MPI-04A - MPI-04A723.62 2,560.00 704.35 2,327.69 37.5522,560.00Clearance Factor Pass - MPI-04 - MPI-04AL1 - MPI-04AL1723.62 2,560.00 704.16 2,327.69 37.1802,560.00Clearance Factor Pass - MPI-04 - MPI-04APB1 - MPI-04APB1723.62 2,560.00 704.16 2,327.69 37.1802,560.00Clearance Factor Pass - MPI-04 - MPI-04PB1 - MPI-04PB1723.62 2,560.00 704.05 2,327.69 36.9722,560.00Clearance Factor Pass - MPI-05 - MPI-05 - MPI-05621.78 2,560.00 604.77 2,255.54 36.5462,560.00Ellipse Separation Pass - MPI-05 - MPI-05 - MPI-05884.83 3,010.00 859.84 2,524.82 35.4073,010.00Clearance Factor Pass - MPI-06 - MPI-06 - MPI-06768.25 2,560.00 750.58 2,172.62 43.4912,560.00Clearance Factor Pass - MPI-08 - MPI-08 - MPI-08687.48 2,560.00 670.15 2,215.79 39.6622,560.00Clearance Factor Pass - MPI-09 - MPI-09 - MPI-09555.27 2,560.00 539.28 2,297.44 34.7172,560.00Clearance Factor Pass - MPI-10 - MPI-10 - MPI-10705.94 2,560.00 690.06 2,215.69 44.4672,560.00Clearance Factor Pass - MPI-10 - MPI-10 - MPI-10705.94 2,560.00 690.06 2,215.69 44.4672,560.00Centre Distance Pass - MPI-11 - MPI-11 - MPI-11960.41 2,560.00 945.23 2,024.18 63.2792,560.00Clearance Factor Pass - MPI-11 - MPI-11L1 - MPI-11L1960.41 2,560.00 945.23 2,024.18 63.2792,560.00Clearance Factor Pass - MPI-12 - MPI-12 - MPI-12750.26 2,560.00 732.71 2,133.53 42.7392,560.00Clearance Factor Pass - MPI-12 - MPI-12L1 - MPI-12L1750.26 2,560.00 732.71 2,133.53 42.7392,560.00Clearance Factor Pass - MPI-12 - MPI-12PB1 - MPI-12PB1750.26 2,560.00 732.71 2,133.53 42.7392,560.00Clearance Factor Pass - MPI-13 - MPI-13 - MPI-13968.36 2,560.00 953.13 2,022.13 63.5732,560.00Clearance Factor Pass - MPI-16 - MPI-16 - MPI-16753.06 2,560.00 734.92 2,267.34 41.5152,560.00Clearance Factor Pass - MPU I-35i - MPU I-35i - MPU I-35i 217.65 2,560.00 198.52 2,590.57 11.3742,560.00Clearance Factor Pass - MPU I-36 - MPU I-36 - MPU I-36643.94 2,560.00 631.49 2,334.11 51.7042,560.00Clearance Factor Pass - MPU I-36 - MPU I-36PB1 - MPU I-36PB1643.94 2,560.00 631.28 2,334.11 50.8322,560.00Clearance Factor Pass - MPU I-36 - MPU I-36PB2 - MPU I-36PB2643.94 2,560.00 631.28 2,334.11 50.8402,560.00Clearance Factor Pass - MPU I-37i - MPU I-37i - MPU I-37i705.05 2,560.00 692.58 2,159.46 56.5762,560.00Clearance Factor Pass - MPU I-37i - MPU I-37PB1 - MPU I-37PB1705.05 2,560.00 692.37 2,159.46 55.6232,560.00Clearance Factor Pass - 11 January, 2021-23:37COMPASSPage 2 of 6 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPI-07 - MPU I-07A wp05Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 2,560.00 to 7,869.02 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt I Pad - Plan: MPI-07 - Plan: MPU I-07A - MPU I-07A wp05MeasuredDepth(usft)Summary Based on MinimumSeparation WarningPlan: MPI-07 - MPI-07 - MPI-0730.55 2,860.00 25.31 2,860.84 5.8312,860.00Clearance Factor Pass - Plan: MPU I-22 - MPU I-22 - MPU I-22 wp03 715.49 2,560.00 702.60 2,239.96 55.5302,560.00Clearance Factor Pass - Plan: MPU I-23i - MPU I-23i - MPU I-23i wp03728.54 2,560.00 714.54 2,244.39 52.0142,560.00Clearance Factor Pass - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp04374.05 2,560.00 357.55 2,581.13 22.6722,560.00Ellipse Separation Pass - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp04422.40 3,860.00 391.82 4,073.05 13.8153,860.00Clearance Factor Pass - Plan: MPU I-28i - MPU I-28 - MPU I-28i wp05469.30 2,560.00 454.46 2,465.78 31.6292,560.00Clearance Factor Pass - Plan: MPU I-29 - MPU I-29 - MPU I-29 wp03862.52 2,560.00 847.72 2,322.05 58.2502,560.00Clearance Factor Pass - Rig: MPU I-20 - MPU I-20 - MPU I-20 wp0772.44 3,751.70 48.36 3,861.90 3.0093,751.70Centre Distance Pass - Rig: MPU I-20 - MPU I-20 - MPU I-20 wp0774.95 3,785.00 47.25 3,889.19 2.7063,785.00Ellipse Separation Pass - Rig: MPU I-20 - MPU I-20 - MPU I-20 wp0779.98 3,810.00 50.15 3,909.34 2.6813,810.00Clearance Factor Pass - Rig: MPU I-20 - MPU I-20 - MPU I-2072.44 3,751.70 48.36 3,861.85 3.0093,751.70Centre Distance Pass - Rig: MPU I-20 - MPU I-20 - MPU I-2074.95 3,785.00 47.25 3,889.14 2.7063,785.00Ellipse Separation Pass - Rig: MPU I-20 - MPU I-20 - MPU I-2079.98 3,810.00 50.15 3,909.29 2.6813,810.00Clearance Factor Pass - Rig: MPU I-21i - MPU I-21i - MPU I-21i wp11865.95 2,560.00 850.81 2,139.72 57.2002,560.00Ellipse Separation Pass - Rig: MPU I-21i - MPU I-21i - MPU I-21i wp11967.96 3,960.00 924.86 4,993.82 22.4573,960.00Clearance Factor Pass - Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool109.00 2,560.003_MWD2,560.00 2,900.00 MPU I-07A wp05 3_MWD_Interp Azi+Sag2,900.00 7,869.02 MPU I-07A wp05 3_MWD+IFR2+MS+Sag11 January, 2021-23:37COMPASSPage 3 of 6 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPI-07 - MPU I-07A wp05Ellipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.11 January, 2021-23:37COMPASSPage 4 of 6 Revised 2/2015 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 No. _____________, API No. 50-_______________________. Production should continue to be reported as a function of the original API number stated above. Pilot Hole In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name (_______________________PH) and API number (50-_____________________) from records, data and logs acquired for well (name on permit). Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. (_____________________________) as 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' sample intervals from below the permafrost or from where samples are first caught and 10' 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 well ( ) until after ( ) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (________________________) must contact the AOGCC to obtain advance approval of such 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 (_______________________________) 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 well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. 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