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218-081
MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Friday, January 2, 2026 SUBJECT:Mechanical Integrity Tests TO: FROM:Guy Cook P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC 4-26A DUCK IS UNIT SDI 4-26A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 01/02/2026 4-26A 50-029-21835-01-00 218-081-0 G SPT 9529 2180810 2500 4107 4110 4112 4110 84 95 95 95 REQVAR P Guy Cook 11/9/2025 Annual MIT-IA to 2500 psi. per AA AIO 1.015. Testing was completed with a Little Red Services pump truck and calibrated gauges. 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:DUCK IS UNIT SDI 4-26A Inspection Date: Tubing OA Packer Depth 669 2753 2660 2630IA 45 Min 60 Min Rel Insp Num: Insp Num:mitGDC251109154557 BBL Pumped:17.9 BBL Returned:16.5 Friday, January 2, 2026 Page 1 of 1 Large volume pumped/returned inidicates the well was not fluid packed prior to MIT -- jbr You don't often get email from aknswellsintegrity@hilcorp.com. Learn why this is important From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: [EXTERNAL] RE: OPERABLE: END 4-26A (PTD# 2180810) - Re-Classify to Operable Date:Monday, November 10, 2025 9:21:00 AM Attachments:image001.png MIT END 4-26 11-09-25.xlsx From: Alaska NS - Wells Integrity <AKNSWellsIntegrity@hilcorp.com> Sent: Sunday, November 9, 2025 7:51 PM To: Alaska NS - Wells Integrity <AKNSWellsIntegrity@hilcorp.com>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Justus Hinks <jhinks@hilcorp.com>; Ryan Thompson <Ryan.Thompson@hilcorp.com> Subject: RE: [EXTERNAL] RE: OPERABLE: END 4-26A (PTD# 2180810) - Re-Classify to Operable Mr. Wallace, After a 5-day period of END 4-26 (PTD# 2180810) being on stable Injection an AOGCC witnessed MIT-IA to 2630 psi was conducted with Passing results. The well has been re- classified to Operable. Please Respond with any questions. Chris CaseyHilcorp Alaska LLCField Well IntegrityAKI/MPU/WNS chris.casey@hilcorp.com O: (907) 685-1494 C: (907) 242-1021Alt: Steve Soroka Hilcorp North Slope, LLC From: Alaska NS - Wells Integrity Sent: Saturday, November 1, 2025 2:16 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Ryan Thompson <Ryan.Thompson@hilcorp.com>; jim.regg <jim.regg@alaska.gov> Cc: Alaska NS - Wells Integrity <AKNSWellsIntegrity@hilcorp.com>; Justus Hinks <jhinks@hilcorp.com> Subject: RE: [EXTERNAL] RE: NOT OPERABLE: END 4-26A (PTD# 2180810) - Request to place on injection CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Mr. Wallace, END 4-26 (PTD# 2180810) – Slickline set an isolation sleeve with an MCX valve across the tubing retrievable safety valve. An offline MIT-IA Passed to 2700 psi. The well will now be reclassified as Under Evaluation and put on injection. We will obtain a State- witnessed MIT-IA once the well has stabilized. Please call with any questions. Thank You Steve Soroka Hilcorp Alaska LLC Field Well Integrity Steve.Soroka@hilcorp.com P: (907) 830-8976 Alt: Chris Casey From: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Sent: Monday, October 27, 2025 11:16 AM To: Ryan Thompson <Ryan.Thompson@hilcorp.com>; jim.regg <jim.regg@alaska.gov> Cc: Alaska NS - Wells Integrity <AKNSWellsIntegrity@hilcorp.com>; Justus Hinks <jhinks@hilcorp.com> Subject: [EXTERNAL] RE: NOT OPERABLE: END 4-26A (PTD# 2180810) - Request to place on injection Ryan, Plan forward with restart of gas injection and AOGCC online MITIA once stabilized is APPROVED. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov 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, 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. contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. From: Ryan Thompson <Ryan.Thompson@hilcorp.com> Sent: Monday, October 27, 2025 11:03 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Alaska NS - Wells Integrity <AKNSWellsIntegrity@hilcorp.com>; Justus Hinks <jhinks@hilcorp.com> Subject: RE: NOT OPERABLE: END 4-26A (PTD# 2180810) - Request to place on injection Mr. Wallace, Gas Injector END 4-26A (PTD# 2180810) is operated under AA (AIO 1.015) for TxI communication. On 10/26/25 a passing non AOGCC witnessed MIT-IA was performed to 2714 psi with the well shut in, after the below work was performed on the well: 10/17/25 – PPPOT-T passed to 5000 psi, although THA test void pressure was tracking tubing pressure post test. 10/23-24 – Performed sealant treatment of the tubing hanger neck seals. Tested treatment with 1892 psi of gas on wellhead, THA test void stayed at 0 psi. 10/26 – SL set an isolation sleeve across the tubing retrievable safety valve (isolating communication from tubing to IA via the TRSSSV). Passing MIT-IA as mentioned above. Isolation sleeve was pulled in order to add MCX injection valve. Plan forward: 1. Reset TRSSSV isolation sleeve with MCX injection valve. 2. Perform offline non witnessed MIT-IA to 2500 psi. Well to remain shut in if fail. 3. If pass, place well on gas injection. 4. Perform AOGCC witnessed MIT-IA once on stable injection (This will most likely establish a new annual MIT-IA date of November) Please respond if you approve of our plan forward to place the well back on injection pending an additional passing MIT-IA in step 2 of the plan forward. Thank you, Ryan Thompson Milne / Islands / WNS Well Integrity Engineer 907-564-5005 From: Alaska NS - Wells Integrity <AKNSWellsIntegrity@hilcorp.com> Sent: Tuesday, October 14, 2025 5:03 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: jim.regg <jim.regg@alaska.gov>; Justus Hinks <jhinks@hilcorp.com>; Ryan Thompson <Ryan.Thompson@hilcorp.com>; Alaska NS - Wells Integrity <AKNSWellsIntegrity@hilcorp.com> Subject: RE: NOT OPERABLE: END 4-26A (PTD# 2180810) - Pre AOGCC MIT-IA Failed Mr. Wallace, Attached is a 30-day T/I/O chart along with a wellbore schematic. Please respond with any questions. Chris CaseyHilcorp Alaska LLCField Well Integrity CoordinatorWNS/AKI/MPU/PTU chris.casey@hilcorp.com O: (907) 685-1494 C: (907) 242-1021Alt: Steve Soroka Hilcorp North Slope, LLC From: Chris Casey - (C) <chris.casey@hilcorp.com> Sent: Tuesday, October 14, 2025 4:53 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: jim.regg <jim.regg@alaska.gov>; Justus Hinks <jhinks@hilcorp.com>; Ryan Thompson <Ryan.Thompson@hilcorp.com>; Alaska NS - Wells Integrity <AKNSWellsIntegrity@hilcorp.com> Subject: NOT OPERABLE: END 4-26A (PTD# 2180810) - Pre AOGCC MIT-IA Failed Mr. Wallace, Gas Injector END 4-26A (PTD# 2180810) is operated under AA (AIO 1.015) for TxI communication. The well is due for its annual AOGCC MIT-IA this month. On 10/11/25- 10/12/25 we began lube and bleed operations on the IA in order to fluid pack the annulus for the MIT-IA. Today we were able to confirm fluid to surface in the IA and the resulting MIT has failed to 1700 psi after losing 32 psi in the first 15 min and gaining 34 psi in the second 15 min with current injection pressures of ~4150 psi on the tubing. The well is now re-classified as not operable and will be shut in. The well will remain shut in until AOGCC approval is granted to resume injection per condition 7 in the AA. Forward plan: 1. PPPOT-T 2. Troubleshoot SSSV 3. MIT-IA 4. Further diagnostics or secure per OE. Please respond with any questions. Chris CaseyHilcorp Alaska LLCField Well Integrity CoordinatorWNS/AKI/MPU/PTU chris.casey@hilcorp.com O: (907) 685-1494 C: (907) 242-1021Alt: Steve Soroka Hilcorp North Slope, LLC The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that 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. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that 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. Submit to: OPERATOR:Hilcorp Alaska LLC FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 2180810 Type Inj G Tubing 4107 4110 4112 4110 Type Test P Packer TVD 9529 BBL Pump 17.9 IA 669 2753 2660 2630 Interval V Test psi 2500 BBL Return 16.5 OA 84 95 95 95 Result P Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Endicott/DUI/SDI Guy Cook Hilcorp Alaska LLC 11/09/25 Notes:AOGCC annual MIT-IA per AIO1.015 Notes: Notes: Notes: 4-26 Form 10-426 (Revised 01/2017)MIT END 4-26 11-09-25 You don't often get email from aknswellsintegrity@hilcorp.com. Learn why this is important From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: [EXTERNAL] RE: NOT OPERABLE: END 4-26A (PTD# 2180810) - Request to place on injection Date:Monday, November 3, 2025 9:37:40 AM Attachments:image001.png From: Alaska NS - Wells Integrity <AKNSWellsIntegrity@hilcorp.com> Sent: Saturday, November 1, 2025 2:16 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Ryan Thompson <Ryan.Thompson@hilcorp.com>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Alaska NS - Wells Integrity <AKNSWellsIntegrity@hilcorp.com>; Justus Hinks <jhinks@hilcorp.com> Subject: RE: [EXTERNAL] RE: NOT OPERABLE: END 4-26A (PTD# 2180810) - Request to place on injection Mr. Wallace, END 4-26 (PTD# 2180810) – Slickline set an isolation sleeve with an MCX valve across the tubing retrievable safety valve. An offline MIT-IA Passed to 2700 psi. The well will now be reclassified as Under Evaluation and put on injection. We will obtain a State- witnessed MIT-IA once the well has stabilized. Please call with any questions. Thank You Steve Soroka Hilcorp Alaska LLC Field Well Integrity Steve.Soroka@hilcorp.com P: (907) 830-8976 Alt: Chris Casey From: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Sent: Monday, October 27, 2025 11:16 AM To: Ryan Thompson <Ryan.Thompson@hilcorp.com>; jim.regg <jim.regg@alaska.gov> Cc: Alaska NS - Wells Integrity <AKNSWellsIntegrity@hilcorp.com>; Justus Hinks CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. <jhinks@hilcorp.com> Subject: [EXTERNAL] RE: NOT OPERABLE: END 4-26A (PTD# 2180810) - Request to place on injection Ryan, Plan forward with restart of gas injection and AOGCC online MITIA once stabilized is APPROVED. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov 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 Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. From: Ryan Thompson <Ryan.Thompson@hilcorp.com> Sent: Monday, October 27, 2025 11:03 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Alaska NS - Wells Integrity <AKNSWellsIntegrity@hilcorp.com>; Justus Hinks <jhinks@hilcorp.com> Subject: RE: NOT OPERABLE: END 4-26A (PTD# 2180810) - Request to place on injection Mr. Wallace, Gas Injector END 4-26A (PTD# 2180810) is operated under AA (AIO 1.015) for TxI communication. On 10/26/25 a passing non AOGCC witnessed MIT-IA was performed to 2714 psi with the well shut in, after the below work was performed on the well: 10/17/25 – PPPOT-T passed to 5000 psi, although THA test void pressure was tracking tubing pressure post test. 10/23-24 – Performed sealant treatment of the tubing hanger neck seals. Tested treatment with 1892 psi of gas on wellhead, THA test void stayed at 0 psi. 10/26 – SL set an isolation sleeve across the tubing retrievable safety valve (isolating communication from tubing to IA via the TRSSSV). Passing MIT-IA as mentioned above. Isolation sleeve was pulled in order to add MCX injection valve. Plan forward: 1. Reset TRSSSV isolation sleeve with MCX injection valve. 2. Perform offline non witnessed MIT-IA to 2500 psi. Well to remain shut in if fail. 3. If pass, place well on gas injection. 4. Perform AOGCC witnessed MIT-IA once on stable injection (This will most likely establish a new annual MIT-IA date of November) Please respond if you approve of our plan forward to place the well back on injection pending an additional passing MIT-IA in step 2 of the plan forward. Thank you, Ryan Thompson Milne / Islands / WNS Well Integrity Engineer 907-564-5005 From: Alaska NS - Wells Integrity <AKNSWellsIntegrity@hilcorp.com> Sent: Tuesday, October 14, 2025 5:03 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: jim.regg <jim.regg@alaska.gov>; Justus Hinks <jhinks@hilcorp.com>; Ryan Thompson <Ryan.Thompson@hilcorp.com>; Alaska NS - Wells Integrity <AKNSWellsIntegrity@hilcorp.com> Subject: RE: NOT OPERABLE: END 4-26A (PTD# 2180810) - Pre AOGCC MIT-IA Failed Mr. Wallace, Attached is a 30-day T/I/O chart along with a wellbore schematic. Please respond with any questions. Chris CaseyHilcorp Alaska LLCField Well Integrity CoordinatorWNS/AKI/MPU/PTU chris.casey@hilcorp.com O: (907) 685-1494 C: (907) 242-1021Alt: Steve Soroka Hilcorp North Slope, LLC From: Chris Casey - (C) <chris.casey@hilcorp.com> Sent: Tuesday, October 14, 2025 4:53 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: jim.regg <jim.regg@alaska.gov>; Justus Hinks <jhinks@hilcorp.com>; Ryan Thompson <Ryan.Thompson@hilcorp.com>; Alaska NS - Wells Integrity <AKNSWellsIntegrity@hilcorp.com> Subject: NOT OPERABLE: END 4-26A (PTD# 2180810) - Pre AOGCC MIT-IA Failed Mr. Wallace, Gas Injector END 4-26A (PTD# 2180810) is operated under AA (AIO 1.015) for TxI communication. The well is due for its annual AOGCC MIT-IA this month. On 10/11/25- 10/12/25 we began lube and bleed operations on the IA in order to fluid pack the annulus for the MIT-IA. Today we were able to confirm fluid to surface in the IA and the resulting MIT has failed to 1700 psi after losing 32 psi in the first 15 min and gaining 34 psi in the second 15 min with current injection pressures of ~4150 psi on the tubing. The well is now re-classified as not operable and will be shut in. The well will remain shut in until AOGCC approval is granted to resume injection per condition 7 in the AA. Forward plan: 1. PPPOT-T 2. Troubleshoot SSSV 3. MIT-IA 4. Further diagnostics or secure per OE. Please respond with any questions. Chris CaseyHilcorp Alaska LLCField Well Integrity CoordinatorWNS/AKI/MPU/PTU chris.casey@hilcorp.com O: (907) 685-1494 C: (907) 242-1021Alt: Steve Soroka Hilcorp North Slope, LLC 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, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wallace, Chris D (OGC) To:Ryan Thompson; Regg, James B (OGC) Cc:Alaska NS - Wells Integrity; Justus Hinks Subject:RE: NOT OPERABLE: END 4-26A (PTD# 2180810) - Request to place on injection Date:Monday, October 27, 2025 11:16:09 AM Attachments:image001.png Ryan, Plan forward with restart of gas injection and AOGCC online MITIA once stabilized is APPROVED. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov 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 Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. From: Ryan Thompson <Ryan.Thompson@hilcorp.com> Sent: Monday, October 27, 2025 11:03 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Alaska NS - Wells Integrity <AKNSWellsIntegrity@hilcorp.com>; Justus Hinks <jhinks@hilcorp.com> Subject: RE: NOT OPERABLE: END 4-26A (PTD# 2180810) - Request to place on injection Mr. Wallace, Gas Injector END 4-26A (PTD# 2180810) is operated under AA (AIO 1.015) for TxI communication. On 10/26/25 a passing non AOGCC witnessed MIT-IA was performed to 2714 psi with the well shut in, after the below work was performed on the well: 10/17/25 – PPPOT-T passed to 5000 psi, although THA test void pressure was tracking tubing pressure post test. 10/23-24 – Performed sealant treatment of the tubing hanger neck seals. Tested treatment with 1892 psi of gas on wellhead, THA test void stayed at 0 psi. 10/26 – SL set an isolation sleeve across the tubing retrievable safety valve (isolating communication from tubing to IA via the TRSSSV). Passing MIT-IA as mentioned above. Isolation sleeve was pulled in order to add MCX injection valve. Plan forward: 1. Reset TRSSSV isolation sleeve with MCX injection valve. 2. Perform offline non witnessed MIT-IA to 2500 psi. Well to remain shut in if fail. 3. If pass, place well on gas injection. 4. Perform AOGCC witnessed MIT-IA once on stable injection (This will most likely establish a new annual MIT-IA date of November) Please respond if you approve of our plan forward to place the well back on injection pending an additional passing MIT-IA in step 2 of the plan forward. Thank you, Ryan Thompson Milne / Islands / WNS Well Integrity Engineer 907-564-5005 From: Alaska NS - Wells Integrity <AKNSWellsIntegrity@hilcorp.com> Sent: Tuesday, October 14, 2025 5:03 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: jim.regg <jim.regg@alaska.gov>; Justus Hinks <jhinks@hilcorp.com>; Ryan Thompson <Ryan.Thompson@hilcorp.com>; Alaska NS - Wells Integrity <AKNSWellsIntegrity@hilcorp.com> Subject: RE: NOT OPERABLE: END 4-26A (PTD# 2180810) - Pre AOGCC MIT-IA Failed Mr. Wallace, Attached is a 30-day T/I/O chart along with a wellbore schematic. Please respond with any questions. Chris CaseyHilcorp Alaska LLCField Well Integrity CoordinatorWNS/AKI/MPU/PTU chris.casey@hilcorp.com O: (907) 685-1494 C: (907) 242-1021Alt: Steve Soroka Hilcorp North Slope, LLC From: Chris Casey - (C) <chris.casey@hilcorp.com> Sent: Tuesday, October 14, 2025 4:53 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: jim.regg <jim.regg@alaska.gov>; Justus Hinks <jhinks@hilcorp.com>; Ryan Thompson <Ryan.Thompson@hilcorp.com>; Alaska NS - Wells Integrity <AKNSWellsIntegrity@hilcorp.com> Subject: NOT OPERABLE: END 4-26A (PTD# 2180810) - Pre AOGCC MIT-IA Failed Mr. Wallace, Gas Injector END 4-26A (PTD# 2180810) is operated under AA (AIO 1.015) for TxI communication. The well is due for its annual AOGCC MIT-IA this month. On 10/11/25- 10/12/25 we began lube and bleed operations on the IA in order to fluid pack the annulus for the MIT-IA. Today we were able to confirm fluid to surface in the IA and the resulting MIT has failed to 1700 psi after losing 32 psi in the first 15 min and gaining 34 psi in the second 15 min with current injection pressures of ~4150 psi on the tubing. The well is now re-classified as not operable and will be shut in. The well will remain shut in until AOGCC approval is granted to resume injection per condition 7 in the AA. Forward plan: 1. PPPOT-T 2. Troubleshoot SSSV 3. MIT-IA 4. Further diagnostics or secure per OE. Please respond with any questions. Chris CaseyHilcorp Alaska LLCField Well Integrity CoordinatorWNS/AKI/MPU/PTU chris.casey@hilcorp.com O: (907) 685-1494 C: (907) 242-1021Alt: Steve Soroka Hilcorp North Slope, LLC 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, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis 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. You don't often get email from aknswellsintegrity@hilcorp.com. Learn why this is important From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: NOT OPERABLE: END 4-26A (PTD# 2180810) - Pre AOGCC MIT-IA Failed Date:Wednesday, October 15, 2025 7:58:35 AM Attachments:image001.png END 4-26A SCHEMATIC 04-21-2025.pdf From: Alaska NS - Wells Integrity <AKNSWellsIntegrity@hilcorp.com> Sent: Tuesday, October 14, 2025 5:03 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Justus Hinks <jhinks@hilcorp.com>; Ryan Thompson <Ryan.Thompson@hilcorp.com>; Alaska NS - Wells Integrity <AKNSWellsIntegrity@hilcorp.com> Subject: RE: NOT OPERABLE: END 4-26A (PTD# 2180810) - Pre AOGCC MIT-IA Failed Mr. Wallace, Attached is a 30-day T/I/O chart along with a wellbore schematic. Please respond with any questions. Chris CaseyHilcorp Alaska LLCField Well Integrity CoordinatorWNS/AKI/MPU/PTU chris.casey@hilcorp.com O: (907) 685-1494 C: (907) 242-1021Alt: Steve Soroka Hilcorp North Slope, LLC From: Chris Casey - (C) <chris.casey@hilcorp.com> Sent: Tuesday, October 14, 2025 4:53 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: jim.regg <jim.regg@alaska.gov>; Justus Hinks <jhinks@hilcorp.com>; Ryan Thompson <Ryan.Thompson@hilcorp.com>; Alaska NS - Wells Integrity <AKNSWellsIntegrity@hilcorp.com> Subject: NOT OPERABLE: END 4-26A (PTD# 2180810) - Pre AOGCC MIT-IA Failed Mr. Wallace, Gas Injector END 4-26A (PTD# 2180810) is operated under AA (AIO 1.015) for TxI communication. The well is due for its annual AOGCC MIT-IA this month. On 10/11/25- 10/12/25 we began lube and bleed operations on the IA in order to fluid pack the annulus for the MIT-IA. Today we were able to confirm fluid to surface in the IA and the resulting MIT has failed to 1700 psi after losing 32 psi in the first 15 min and gaining 34 psi in the second 15 min with current injection pressures of ~4150 psi on the tubing. The well is now re-classified as not operable and will be shut in. The well will remain shut in until AOGCC approval is granted to resume injection per condition 7 in the AA. Forward plan: 1. PPPOT-T 2. Troubleshoot SSSV 3. MIT-IA 4. Further diagnostics or secure per OE. Please respond with any questions. Chris CaseyHilcorp Alaska LLCField Well Integrity CoordinatorWNS/AKI/MPU/PTU chris.casey@hilcorp.com O: (907) 685-1494 C: (907) 242-1021Alt: Steve Soroka Hilcorp North Slope, LLC The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that 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. Well:4-26 ■ ■ so ■ ■ 4,000 m 3,50D m 3,00D a 2.500 1/1 /1 1 1.1 0911425 09.+2&+25 1 D+12,25 300 290 260 240 220 200 180 160 v 140 120 100 90 60 40 20 TIO Plot f Tubing On ■ Bleed Operable + Not Oper ♦ Under Eval f- Man. IA -A Man.OA Man. OOA Man. OOOA p Man. WHT _____________________________________________________________________________________ Revised By: AJW 04/21/25 SCHEMATIC Duck Island Unit Well: END 4-26A Last Completed: 9/4/2018 PTD: 218-081 PERFORATION DETAIL END Sands Top (MD)Btm (MD)Top (TVD)Btm (TVD)FT Date Status Size HRZ Shale 13,320’13,325’9,548’9,550’5’8/29/18 Sqz 3-1/8” S3A1 13,953’13,973’9,866’9,877’20’9/10/18 Open 3-1/8” GENERAL WELL INFO API: 50-029-21835-01-00 Initial Completion - 8/6/1988 RWO – 2/21/1995 Sand Back & Cmt Cap – 3/31/99 Sidetrack Completion – 8/25/18 END HRZ S CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 30"Conductor N/A / N/A / N/A N/A Surface 161’N/A 13-3/8”Surface 68/ N-80/ Btrs 12.415 Surface 2,502’0.150 9-5/8"Intermediate 47 / NT80S / NSCC 8.681 Surface 5,411’ (KOP)0.0732 7”Prod Liner 26 / L-80 / TXP 6.276 5,255’14,000’0.0383 TUBING DETAIL 4-1/2"Tubing 12.6/ 13Cr/ JFE Bear 3.958 Surface 13,605’0.0152 JEWELRY DETAIL No Depth Item 1 1,485’ 4.5” SLB TRMAXX SSSV w/ X-Nipple - ID= 3.813” w/ MCX set 6/21/22 GLM DETAIL: MMG SPM-1-1/2” w/ RK Latch 2 3,859’STA 6 Dev= , VLV=DMY, TVD=3,859 ’, Date= 12/23/19 3 5,217’STA 5:Dev= , VLV=DMY, TVD= 5,216’, Date= 12/23/19 4 5,255’9-5/8” x 7” BKR HRDE ZXHD Packer GLM DETAIL: Special Clearance SPM-1” w/ RK Latch 5 6,888’STA 4:Dev= , VLV=DMY,TVD= 6,504’, Date= 12/23/19 6 8,793’STA 3:Dev= , VLV= DMY, Port= 0, TVD= 7,369’, Date=9/4/18 7 10,700’STA 2:Dev= , VLV= DMY, Port= 0, TVD= 8,232’, Date=9/4/18 8 12,606’STA 1:Dev= , VLV= DMY, Port= 0, TVD= 9,190’, Date=9/4/18 9 13,182’4-1/2” X Nipple – ID= 3.813” 10 13,283’7” x 4-1/2” Packer – ID= 3.863” 11 13,308’4-1/2” OTIS XN Nipple – ID= 3.725” 12 13,603’4-1/2” WLEG – ID= 3.958” – Btm @ 13,605’ OPEN HOLE / CEMENT DETAIL 13-3/8”4,557 cu/ft Permafrost in 17.5” Hole 7”115 cu/ft Class “G” in 8-1/2” Hole WELL INCLINATION DETAIL Max Hole Angle = 63.7 deg. @ 9,549’ Angle at Top Perf = 59 Deg. @ 13,962 ’ TREE & WELLHEAD Tree 4-1/8” 6.5K CIW Wellhead MCEVOY SAFETY NOTES H2S Readings Average 230 – 260 PPM on A/L & Gas Injectors Well Requires a SSSV 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Water Wash Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 14,005'feet N/A feet true vertical 9,893'feet N/A feet Effective Depth measured 13,999'feet 5,255 & 13,283 feet true vertical 9,887'feet 5,253 & 9,529 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / 13Cr-80 13,605' MD 9,690' TVD 9-5/8 x 7 BKR HRDE ZXH 4-1/2" 1,485' MD Packers and SSSV (type, measured and true vertical depth)7 x 4-1/2TRMAXX SSSV See Above 1,485' TVD 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Contact Name: Contact Email: Authorized Title:Operations Manager Contact Phone: 322-333 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: Authorized Name and Digital Signature with Date: WINJ WAG 20,240 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 0 4,301 Joleen Oshiro joleen.oshiro@hilcorp.com 907-777-8486 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 0 53920,358 0 4,260 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 161' 2,502' 5,417' 700 Conductor TVD 161' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 218-081 50-029-21835-01-00 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL047502 & ADL 047503 ENDICOTT / ENDICOTT OIL Hilcorp Alaska LLC 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: DUCK IS UNIT SDI 4-26A measuredPlugs Junk measured N/A Length 161' 2,502' 5,417' Size Surface Intermediate Liner 30" 13-3/8" 9-5/8" 7"8,745' Casing 2,502' 5,412' 9,891'14,000' 5,410psi 5,020psi 6,870psi 7,240psi Burst N/A Collapse N/A 2,260psi 4,760psi L G Form 10-404 Revised 10/2021 Submit Within 30 days of Operations By Meredith Guhl at 9:55 am, Jul 19, 2022 Digitally signed by Torin Roschinger (4662) DN: cn=Torin Roschinger (4662), ou=Users Date: 2022.07.19 07:45:21 -08'00' Torin Roschinger (4662) Well Name Rig API Number Well Permit Number Start Date End Date END 4-26A Fullbore 50-029-21835-01-00 218-081 7/5/2022 7/5/2022 Water wash. Pump 50 bbls 120* diesel & 195 bbls fresh water with surfactant. Soak for 2 hours. Pump 380 bbls fresh water/surfactant and 25 bbls diesel freeze protect. 7/5/2022 - Tuesday Hilcorp Alaska, LLC Weekly Operations Summary _____________________________________________________________________________________ Revised By: JCM 01/04/20 SCHEMATIC Duck Island Unit Well: END 4-26A Last Completed: 9/4/2018 PTD: 218-081 TD =14,005 (MD) / TD = 9,893(TVD) 30 KB Elev.: 40.9/ GL Elev.: 13.9 7 4 5 9 9-5/8 1 2 14 Min ID=3.725 @ 13,308 MD PBTD =13,999(MD) / PBTD =9,887(TVD) 3 13-3/8 8 7 10 9-5/8 Window: 5,411 MD 11 12 6 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 30" Conductor N/A / N/A / N/A N/A Surface 161 N/A 13-3/8 Surface 68/ N-80/ Btrs 12.415 Surface 2,502 0.150 9-5/8" Intermediate 47 / NT80S / NSCC 8.681 Surface 5,411 (KOP)0.0732 7 Prod Liner 26 / L-80 / TXP 6.276 5,255 14,000 0.0383 TUBING DETAIL 4-1/2" Tubing 12.6/ 13Cr/ JFE Bear 3.958 Surface 13,605 0.0152 JEWELRY DETAIL No Depth Item 1 1,485 4.5 SLB TRMAXX SSSV w/ X-Nipple - ID= 3.813 GLM DETAIL: MMG SPM-1-1/2 w/ RK Latch 2 3,859STA 6 Dev= , VLV=DMY, TVD=3,859 , Date= 12/23/19 3 5,217STA 5: Dev= , VLV=DMY, TVD= 5,216, Date= 12/23/19 4 5,255 9-5/8 x 7 BKR HRDE ZXHD Packer GLM DETAIL: Special Clearance SPM-1 w/ RK Latch 5 6,888STA 4: Dev= , VLV=DMY,TVD= 6,504, Date= 12/23/19 6 8,793STA 3: Dev= , VLV= DMY, Port= 0, TVD= 7,369, Date=9/4/18 7 10,700STA 2: Dev= , VLV= DMY, Port= 0, TVD= 8,232, Date=9/4/18 8 12,606STA 1: Dev= , VLV= DMY, Port= 0, TVD= 9,190, Date=9/4/18 9 13,182 4-1/2 X Nipple ID= 3.813 10 13,283 7 x 4-1/2 Packer ID= 3.863 11 13,308 4-1/2 OTIS XN Nipple ID= 3.725 12 13,603 4-1/2 WLEG ID= 3.958 Btm @ 13,605 PERFORATION DETAIL END Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Size HRZ Shale 13,320 13,325 9,548 9,550 5 8/29/18 Sqz 3-1/8 K2B 13,953 13,973 9,866 9,877 20 9/10/18 Open 3-1/8 OPEN HOLE / CEMENT DETAIL 13-3/8 4,557 cu/ft Permafrost in 17.5 Hole 7 115 cu/ft Class G in 8-1/2 Hole WELL INCLINATION DETAIL Max Hole Angle = 63.7 deg. @ 9,549 Angle at Top Perf = 59 Deg. @ 13,962 TREE & WELLHEAD Tree 4-1/8 6.5K CIW Wellhead MCEVOY GENERAL WELL INFO API: 50-029-21835-01-00 Initial Completion - 8/6/1988 RWO 2/21/1995 Sand Back & Cmt Cap 3/31/99 Sidetrack Completion 8/25/18 SAFETY NOTES H2S Readings Average 230 260 PPM on A/L & Gas Injectors Well Requires a SSSV 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: Operable: END 4-26A (PTD# 2180810) - OA pressure stabilized Date:Tuesday, January 7, 2025 3:36:16 PM Attachments:END 4-26A - 30 day TIO.docx From: Ryan Thompson <Ryan.Thompson@hilcorp.com> Sent: Tuesday, January 7, 2025 3:20 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Justus Hinks <jhinks@hilcorp.com> Subject: Operable: END 4-26A (PTD# 2180810) - OA pressure stabilized Mr. Wallace, On 12/30/24 in preparation for the greenstick treatment of the IC void on Gas Injector END 4- 26A, a PPPOT-IC was performed which initially failed, LDS were then re-torqued and the PPPOT-IC then passed to 3000 psi. The greenstick treatment was not performed following the passing PPPOT-IC and the OA pressure has remained stable at ~300 psi following the passing pack off test. The well is now re-classified as operable. A 30 day TIO plot is attached. Please respond with any questions. Thank you, Ryan Thompson Milne / Islands / WNS Well Integrity Engineer 907-564-5005 From: Ryan Thompson Sent: Monday, December 9, 2024 3:24 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Justus Hinks <jhinks@hilcorp.com> Subject: Under Evaluation: END 4-26A (PTD# 2180810) - OA pressurization Mr. Wallace, Below is a summary of operations for Gas Injector END 4-26A (PTD# 2180810) over the past 28 days. 1. 11/12/24 – replaced packing on IC lock down screws. PPPOT-IC to 3000 psi passed. 2. OA pressure stabilized for ~10 days until re-pressurizing on 11/22/24. 3. 10-403 Sundry submitted 12/5/24 to perform greenstick sealant treatment on IC test void. We will roll the Under Evaluation clock an additional 28 days to perform the below operations: Plan Forward: 1. Execute greenstick sealant treatment on IC test void once 10-403 sundry approval is received. 2. Monitor OA pressure post greenstick treatment. Please respond with any questions or concerns with the proposed plan forward. Attached is a 30 day TIO plot. Thank you, Ryan Thompson Milne / Islands / WNS Well Integrity Engineer 907-564-5005 From: Ryan Thompson Sent: Monday, November 11, 2024 3:24 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Justus Hinks <jhinks@hilcorp.com> Subject: Under Evaluation: END 4-26A (PTD# 2180810) - OA pressurization Mr. Wallace, Below is a summary of operations for Gas Injector END 4-26A (PTD# 2180810) over the past 28 days. 1. 10/14/24 – Re-energized primary seal on IC hanger. Re-torque 5 LDS with small weep, will replace with new packing. OA pressure stabilizes at ~100 psi following this work, until 11/3/24. 2. 10/21/24 – AOGCC witnessed MIT-IA to 2603 psi, passed. 3. 11/3/24 – OA pressure starts building at ~100-150 psi / day. Stabilizes @ 650 psi. 4. 11/10/24 – PPPOT-IC to 3000 psi fails. Attempt to re-energize primary seal on IC hanger. Will need LPE performed. We will roll the Under Evaluation clock an additional 28 days to continue to monitor the well for OA re-pressurization and perform the below operations: Plan Forward: 1. Replace LDS identified on 10/14/24 with new LDS/packing. (planned for 11/12/24) 2. Perform leak path evaluation (LPE) to identify if primary, secondary or both IC seals are leaking. 3. Based on results from LPE, submit sundry for greenstick treatment of IC void if necessary. 4. Continue to monitor for OA re-pressurization with the well on injection. Please respond with any questions or concerns with the proposed plan forward. Attached is a 30 day TIO plot. Thank you, Ryan Thompson Milne / Islands / WNS Well Integrity Engineer 907-564-5005 From: Ryan Thompson Sent: Monday, October 14, 2024 10:31 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Sara Hannegan <shannegan@hilcorp.com> Subject: Under Evaluation: END 4-26A (PTD# 2180810) - OA pressurization Mr. Wallace, Gas Injector END 4-26A (PTD# 2180810) is operated under AA (AIO 1.015) for TxI communication. On 10/13/24 the OA pressure rose to 600 psi and was bled. OA pressure stabilized at 200 psi post bleed. The IC packoff was re-energized and passed a PPPOT-IC on 9/5/24 with the well shut in and at ambient temperature. The well is now classified as under evaluation to determine if the OA pressurization is from thermal effects or other means. Plan forward: 1. Perform PPPOT-IC with the well online at injection temperature. Re-energize IC packoff if necessary. 2. Perform AOGCC witnessed MIT-IA. Please respond with any questions or concerns with the proposed plan forward. Attached is a 30 day TIO plot and WBS. 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 theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Friday, December 13, 2024 SUBJECT:Mechanical Integrity Tests TO: FROM:Kam StJohn P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC 4-26A DUCK IS UNIT SDI 4-26A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 12/13/2024 4-26A 50-029-21835-01-00 218-081-0 G SPT 9529 2180810 2500 4316 4330 4333 4348 75 82 82 82 REQVAR P Kam StJohn 10/21/2024 Yearly MIT-IA to 2500 psi per AIO 1.015 The Barrels back was less than pumped in 9 BBLS while bleeding back it turned to gas at about 1600 psi on the IA after 3 BBLS returned. 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:DUCK IS UNIT SDI 4-26A Inspection Date: Tubing OA Packer Depth 1205 2720 2620 2603IA 45 Min 60 Min Rel Insp Num: Insp Num:mitKPS241021111621 BBL Pumped:9.2 BBL Returned:3 Friday, December 13, 2024 Page 1 of 1 9 9 9 9 99 999 9 9 99 9 9 9 9 Yearly MIT-IA AIO 1.015 while bleeding back it turned to gas at about 1600 psi on the IA after 3 BBLS returned James B. Regg Digitally signed by James B. Regg Date: 2024.12.13 12:51:54 -09'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: Under Evaluation: END 4-26A (PTD# 2180810) - OA pressurization Date:Monday, December 9, 2024 3:29:24 PM Attachments:END 4-26A 30 day TIO.docx From: Ryan Thompson <Ryan.Thompson@hilcorp.com> Sent: Monday, December 9, 2024 3:24 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Justus Hinks <jhinks@hilcorp.com> Subject: Under Evaluation: END 4-26A (PTD# 2180810) - OA pressurization Mr. Wallace, Below is a summary of operations for Gas Injector END 4-26A (PTD# 2180810) over the past 28 days. 1. 11/12/24 – replaced packing on IC lock down screws. PPPOT-IC to 3000 psi passed. 2. OA pressure stabilized for ~10 days until re-pressurizing on 11/22/24. 3. 10-403 Sundry submitted 12/5/24 to perform greenstick sealant treatment on IC test void. We will roll the Under Evaluation clock an additional 28 days to perform the below operations: Plan Forward: 1. Execute greenstick sealant treatment on IC test void once 10-403 sundry approval is received. 2. Monitor OA pressure post greenstick treatment. Please respond with any questions or concerns with the proposed plan forward. Attached is a 30 day TIO plot. Thank you, Ryan Thompson Milne / Islands / WNS Well Integrity Engineer 907-564-5005 From: Ryan Thompson Sent: Monday, November 11, 2024 3:24 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Justus Hinks <jhinks@hilcorp.com> Subject: Under Evaluation: END 4-26A (PTD# 2180810) - OA pressurization Mr. Wallace, Below is a summary of operations for Gas Injector END 4-26A (PTD# 2180810) over the past 28 days. 1. 10/14/24 – Re-energized primary seal on IC hanger. Re-torque 5 LDS with small weep, will replace with new packing. OA pressure stabilizes at ~100 psi following this work, until 11/3/24. 2. 10/21/24 – AOGCC witnessed MIT-IA to 2603 psi, passed. 3. 11/3/24 – OA pressure starts building at ~100-150 psi / day. Stabilizes @ 650 psi. 4. 11/10/24 – PPPOT-IC to 3000 psi fails. Attempt to re-energize primary seal on IC hanger. Will need LPE performed. We will roll the Under Evaluation clock an additional 28 days to continue to monitor the well for OA re-pressurization and perform the below operations: Plan Forward: 1. Replace LDS identified on 10/14/24 with new LDS/packing. (planned for 11/12/24) 2. Perform leak path evaluation (LPE) to identify if primary, secondary or both IC seals are leaking. 3. Based on results from LPE, submit sundry for greenstick treatment of IC void if necessary. 4. Continue to monitor for OA re-pressurization with the well on injection. Please respond with any questions or concerns with the proposed plan forward. Attached is a 30 day TIO plot. Thank you, Ryan Thompson Milne / Islands / WNS Well Integrity Engineer 907-564-5005 From: Ryan Thompson Sent: Monday, October 14, 2024 10:31 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Sara Hannegan <shannegan@hilcorp.com> Subject: Under Evaluation: END 4-26A (PTD# 2180810) - OA pressurization Mr. Wallace, Gas Injector END 4-26A (PTD# 2180810) is operated under AA (AIO 1.015) for TxI communication. On 10/13/24 the OA pressure rose to 600 psi and was bled. OA pressure stabilized at 200 psi post bleed. The IC packoff was re-energized and passed a PPPOT-IC on 9/5/24 with the well shut in and at ambient temperature. The well is now classified as under evaluation to determine if the OA pressurization is from thermal effects or other means. Plan forward: 1. Perform PPPOT-IC with the well online at injection temperature. Re-energize IC packoff if necessary. 2. Perform AOGCC witnessed MIT-IA. Please respond with any questions or concerns with the proposed plan forward. Attached is a 30 day TIO plot and WBS. 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 theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Lau, Jack J (OGC) To:AOGCC Records (CED sponsored) Subject:FW: [EXTERNAL] SDI 4-26A (218-081) Date:Friday, December 6, 2024 2:58:09 PM From: Ryan Thompson <Ryan.Thompson@hilcorp.com> Sent: Friday, December 6, 2024 11:44 AM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Subject: RE: [EXTERNAL] SDI 4-26A (218-081) Jack, SDI 4-26A had a passing MIT-OA to 1127 psi on 2/20/2012. This is the only documented MIT-OA for the well. Please let me know if any other questions. Thanks, Ryan Thompson Milne / Islands / WNS Well Integrity Engineer 907-564-5005 From: Lau, Jack J (OGC) <jack.lau@alaska.gov> Sent: Thursday, December 5, 2024 2:42 PM To: Ryan Thompson <Ryan.Thompson@hilcorp.com> Subject: [EXTERNAL] SDI 4-26A (218-081) Hi Ryan Thompson, What’s the MITOA history for SDI 4-26A? Thanks! Jack Lau Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission (907) 793-1244 Office (907) 227-2760 Cell 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, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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: Wellhead Treatment 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): 14,005'N/A Casing Collapse Conductor N/A Surface 2,260psi Intermediate 4,760psi Liner 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 AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Ryan Thompson Contact Email: Contact Phone: 907-564-5005 Authorized Title: Conditions of approval: Notify AOGCC 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 AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 8,745' 5,417' Perforation Depth MD (ft): 14,000' 9,891' 161' 30" 13-3/8" 9-5/8" 2,502' 2,502' 5,417' 7" Length Size 161' 161' 12.6# / 13Cr-80 TVD Burst 13,605' MD N/A 7,240psi 5,020psi 6,870psi 2,502' 5,412' PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0047502, ADL0047503 218-081 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-21835-01-00 Hilcorp Alaska LLC DUCK IS UNIT SDI 4-26A ENDICOTT / ENDICOTT OIL C.O. 462.007 Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: 5,255' MD/5,253' TVD & 13,283' MD/9,529' TVD & 1,485' MD/1,485' TVD9-5/8"x7" BKR HRDE ZXHD & 7"x4-1/2" Packer & TRMAXX SSSV See Schematic See Schematic 12/10/2024 4-1/2" 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: AOGCC USE ONLY ryan.thompson@hilcorp.com Operations Manager 9,893' 13,999' 9,887' 2,742 N/A Form 10-403 Revised 10/2021 Approved application is valid for 12 months from the date of approval. By Grace Christianson at 1:16 pm, Dec 05, 2024 Digitally signed by Justus Hinks (3691) DN: cn=Justus Hinks (3691) Reason: I attest to the accuracy and integrity of this document Date: 2024.12.05 10:13:37 -09'00' Justus Hinks (3691) 324-684 JJL 12/6/24 A.Dewhurst 06DEC24 DSR-12/10/24 This is an old/obsolete 10-403 form. Please use new form for future sundry applications. 10-404 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.12.10 15:50:26 -09'00'12/10/24 RBDMS JSB 121324 Well: END 4-26A PTD: 2180810 Well Name:END4-26A API Number:50-029-21835-01-00 Current Status:Gas Injector Rig:NA Estimated Start Date:12/10/24 Estimated Duration:1 Day Regulatory Contact:Darci Horner Permit to Drill Number:2180810 First Call Engineer:Ryan Thompson 907-564-5005 907-301-1240 (M) Second Call Engineer:Brenden Swensen 907-748-8581 (M) AFE Number:TBD Current Bottom Hole Pressure:3742 psi @ 10000’ TVD END 4-26 SBHPS – 3/17/17 Max. Anticipated Surface Pressure:2742 psi Gas Column Gradient (0.1 psi/ft) WH Gas Injection Pressure:4061 psi 11/26/24 WH pressure Brief Well Summary END 4-26A was sidetracked in August 2018. In January 2020 the well was converted to gas injection. In June 2020 AIO 1.015 was approved for continued gas injection with TxI communication. On 12/16/21 the casing wellhead seal was re-energized after the well experienced OA pressure build up. On 9/4/24 and again on 10/14/24 the well has experienced OA re-pressurization with subsequent re- energizing of the casing wellhead seal. We will now attempt to greenstick the IC test void in order to -re- establish integrity to the casing wellhead seals. Notes Regarding Wellbore Condition x Under Evaluation well for OA repressurization. x AOGCC MIT-IA passed to 2603 psi on 10/21/24 x Casing wellhead seal re-energized on 9/5/24, 10/14/24 & 11/10/24 x PPPOT-IC failed on 11/10/24, on 11/12/24 LDS packing replaced & passing PPPOT-IC mitigating IxO for 10 days, but OA re-pressurization has now resumed. Objective: x Perform wellhead treatment of the casing hanger test void to help mitigate IAxOA pressure communication across the wellhead. Procedure Wellhead 1. Bleed off IA / OA to 0 psi, may need to establish open bleed on IA. 2. Pump greenstick into the casing hanger test void. Well Integrity 1. Monitor for OA re-pressurization while under evaluation. Attachments: 1. As-built Schematic Well: END 4-26A PTD: 2180810 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: END 4-26A (PTD# 2180810) - OA pressurization Date:Tuesday, November 12, 2024 8:10:55 AM Attachments:END 4-26A TIO"s.docx From: Ryan Thompson <Ryan.Thompson@hilcorp.com> Sent: Monday, November 11, 2024 3:24 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Justus Hinks <jhinks@hilcorp.com> Subject: Under Evaluation: END 4-26A (PTD# 2180810) - OA pressurization Mr. Wallace, Below is a summary of operations for Gas Injector END 4-26A (PTD# 2180810) over the past 28 days. 1. 10/14/24 – Re-energized primary seal on IC hanger. Re-torque 5 LDS with small weep, will replace with new packing. OA pressure stabilizes at ~100 psi following this work, until 11/3/24. 2. 10/21/24 – AOGCC witnessed MIT-IA to 2603 psi, passed. 3. 11/3/24 – OA pressure starts building at ~100-150 psi / day. Stabilizes @ 650 psi. 4. 11/10/24 – PPPOT-IC to 3000 psi fails. Attempt to re-energize primary seal on IC hanger. Will need LPE performed. We will roll the Under Evaluation clock an additional 28 days to continue to monitor the well for OA re-pressurization and perform the below operations: Plan Forward: 1. Replace LDS identified on 10/14/24 with new LDS/packing. (planned for 11/12/24) 2. Perform leak path evaluation (LPE) to identify if primary, secondary or both IC seals are leaking. 3. Based on results from LPE, submit sundry for greenstick treatment of IC void if necessary. 4. Continue to monitor for OA re-pressurization with the well on injection. Please respond with any questions or concerns with the proposed plan forward. Attached is a 30 day TIO plot. Thank you, Ryan Thompson Milne / Islands / WNS Well Integrity Engineer 907-564-5005 From: Ryan Thompson Sent: Monday, October 14, 2024 10:31 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Sara Hannegan <shannegan@hilcorp.com> Subject: Under Evaluation: END 4-26A (PTD# 2180810) - OA pressurization Mr. Wallace, Gas Injector END 4-26A (PTD# 2180810) is operated under AA (AIO 1.015) for TxI communication. On 10/13/24 the OA pressure rose to 600 psi and was bled. OA pressure stabilized at 200 psi post bleed. The IC packoff was re-energized and passed a PPPOT-IC on 9/5/24 with the well shut in and at ambient temperature. The well is now classified as under evaluation to determine if the OA pressurization is from thermal effects or other means. Plan forward: 1. Perform PPPOT-IC with the well online at injection temperature. Re-energize IC packoff if necessary. 2. Perform AOGCC witnessed MIT-IA. Please respond with any questions or concerns with the proposed plan forward. Attached is a 30 day TIO plot and WBS. 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 theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently 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 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. 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: END 4-26A (PTD# 2180810) - OA pressurization Date:Monday, October 14, 2024 10:37:59 AM Attachments:END 4-26 TIO.docx END 4-26A SCHEMATIC 01-04-2020.doc From: Ryan Thompson <Ryan.Thompson@hilcorp.com> Sent: Monday, October 14, 2024 10:31 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Sara Hannegan <shannegan@hilcorp.com> Subject: Under Evaluation: END 4-26A (PTD# 2180810) - OA pressurization Mr. Wallace, Gas Injector END 4-26A (PTD# 2180810) is operated under AA (AIO 1.015) for TxI communication. On 10/13/24 the OA pressure rose to 600 psi and was bled. OA pressure stabilized at 200 psi post bleed. The IC packoff was re-energized and passed a PPPOT-IC on 9/5/24 with the well shut in and at ambient temperature. The well is now classified as under evaluation to determine if the OA pressurization is from thermal effects or other means. Plan forward: 1. Perform PPPOT-IC with the well online at injection temperature. Re-energize IC packoff if necessary. 2. Perform AOGCC witnessed MIT-IA. Please respond with any questions or concerns with the proposed plan forward. Attached is a 30 day TIO plot and WBS. 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 theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, 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 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. _____________________________________________________________________________________ Revised By: JCM 01/04/20 SCHEMATIC Duck Island Unit Well: END 4-26A Last Completed: 9/4/2018 PTD: 218-081 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 30" Conductor N/A / N/A / N/A N/A Surface 161’ N/A 13-3/8” Surface 68/ N-80/ Btrs 12.415 Surface 2,502’ 0.150 9-5/8" Intermediate 47 / NT80S / NSCC 8.681 Surface 5,411’ (KOP) 0.0732 7” Prod Liner 26 / L-80 / TXP 6.276 5,255’ 14,000’ 0.0383 TUBING DETAIL 4-1/2" Tubing 12.6/ 13Cr/ JFE Bear 3.958 Surface 13,605’ 0.0152 JEWELRY DETAIL No Depth Item 1 1,485’ 4.5” SLB TRMAXX SSSV w/ X-Nipple - ID= 3.813” GLM DETAIL: MMG SPM-1-1/2” w/ RK Latch 2 3,859’ STA 6 Dev= , VLV= DMY, TVD=3,859 ’, Date= 12/23/19 3 5,217’ STA 5: Dev= , VLV= DMY, TVD= 5,216’, Date= 12/23/19 4 5,255’ 9-5/8” x 7” BKR HRDE ZXHD Packer GLM DETAIL: Special Clearance SPM-1” w/ RK Latch 5 6,888’ STA 4: Dev= , VLV= DMY,TVD= 6,504’, Date= 12/23/19 6 8,793’ STA 3: Dev= , VLV= DMY, Port= 0, TVD= 7,369’, Date=9/4/18 7 10,700’ STA 2: Dev= , VLV= DMY, Port= 0, TVD= 8,232’, Date=9/4/18 8 12,606’ STA 1: Dev= , VLV= DMY, Port= 0, TVD= 9,190’, Date=9/4/18 9 13,182’ 4-1/2” X Nipple – ID= 3.813” 10 13,283’ 7” x 4-1/2” Packer – ID= 3.863” 11 13,308’ 4-1/2” OTIS XN Nipple – ID= 3.725” 12 13,603’ 4-1/2” WLEG – ID= 3.958” – Btm @ 13,605’ PERFORATION DETAIL END Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Size HRZ Shale 13,320’ 13,325’ 9,548’ 9,550’ 5’ 8/29/18 Sqz 3-1/8” K2B 13,953’ 13,973’ 9,866’ 9,877’ 20’ 9/10/18 Open 3-1/8” OPEN HOLE / CEMENT DETAIL 13-3/8” 4,557 cu/ft Permafrost in 17.5” Hole 7” 115 cu/ft Class “G” in 8-1/2” Hole WELL INCLINATION DETAIL Max Hole Angle = 63.7 deg. @ 9,549’ Angle at Top Perf = 59 Deg. @ 13,962 ’ TREE & WELLHEAD Tree 4-1/8” 6.5K CIW Wellhead MCEVOY GENERAL WELL INFO API: 50-029-21835-01-00 Initial Completion - 8/6/1988 RWO – 2/21/1995 Sand Back & Cmt Cap – 3/31/99 Sidetrack Completion – 8/25/18 SAFETY NOTES H2S Readings Average 230 – 260 PPM on A/L & Gas Injectors Well Requires a SSSV 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: Operable: END 4-26A (PTD# 2180810) - Stable OA Pressure Date:Tuesday, October 1, 2024 4:34:36 PM Attachments:END 4-26A - TIO"s.docx From: Ryan Thompson <Ryan.Thompson@hilcorp.com> Sent: Tuesday, October 1, 2024 4:32 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Sara Hannegan <shannegan@hilcorp.com> Subject: Operable: END 4-26A (PTD# 2180810) - Stable OA Pressure Mr. Wallace, On 9/5/24, Gas Injection well END 4-26A (PTD# 2180810), had the secondary Y seal re- energized on the IC packoff and subsequently passed a PPPOT-IC. The OA pressure has remained stable while online during the under evaluation period. The well is now re-classified as OPERABLE and will remain online. A 90 day TIO plot is attached. Please respond with any questions. Thank you, Ryan Thompson Milne/Islands Well Integrity Engineer 907-564-5005 From: Ryan Thompson Sent: Wednesday, September 4, 2024 3:13 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Sara Hannegan <shannegan@hilcorp.com> Subject: Under Evaluation: END 4-26A (PTD# 2180810) - OA pressurization Mr. Wallace, Gas Injector END 4-26A (PTD# 2180810) is operated under AA (AIO 1.015) for TxI communication. On 8/30/24 the well was shut in due to a facility shut down. On 9/3/24 the OA pressure climbed to 950 psi and the OA was bled to 0. The OA is currently at 450 psi. The well is now classified as under evaluation to determine if the OA pressurization is from thermal effects or other means. The well is currently shut in. Plan forward: 1. Perform PPPOT-IC prior to bringing the well online. 2. If PPPOT-IC passes, put well on injection and monitor for OA repressurization. Attached is a WBS and 90 day TIO plot. Please respond with any questions or comments. 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 theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently 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 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. 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: END 4-26A (PTD# 2180810) - OA pressurization Date:Friday, September 6, 2024 9:09:29 AM From: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Sent: Thursday, September 5, 2024 4:17 PM To: Ryan Thompson <Ryan.Thompson@hilcorp.com>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Sara Hannegan <shannegan@hilcorp.com> Subject: Re: Under Evaluation: END 4-26A (PTD# 2180810) - OA pressurization Ryan, Thanks for the voice-mail. Your plan to bring the well back online is approved. Thanks Chris From: Ryan Thompson <Ryan.Thompson@hilcorp.com> Sent: Thursday, September 5, 2024 2:18:59 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Sara Hannegan <shannegan@hilcorp.com> Subject: RE: Under Evaluation: END 4-26A (PTD# 2180810) - OA pressurization Mr. Wallace, This morning our PPPOT-IC passed to 3000 psi. We did bleed gas from the IC test void down to 0 psi prior to pressuring up with hydraulic fluid. We will now move forward with placing the well on injection under evaluation as outlined below and continue to monitor the OA pressure. Please respond with any questions or concerns. Thank you, Ryan Thompson Milne/Islands Well Integrity Engineer 907-564-5005 From: Ryan Thompson Sent: Wednesday, September 4, 2024 3:13 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Sara Hannegan <shannegan@hilcorp.com> Subject: Under Evaluation: END 4-26A (PTD# 2180810) - OA pressurization Mr. Wallace, Gas Injector END 4-26A (PTD# 2180810) is operated under AA (AIO 1.015) for TxI communication. On 8/30/24 the well was shut in due to a facility shut down. On 9/3/24 the OA pressure climbed to 950 psi and the OA was bled to 0. The OA is currently at 450 psi. The well is now classified as under evaluation to determine if the OA pressurization is from thermal effects or other means. The well is currently shut in. Plan forward: 1. Perform PPPOT-IC prior to bringing the well online. 2. If PPPOT-IC passes, put well on injection and monitor for OA repressurization. Attached is a WBS and 90 day TIO plot. Please respond with any questions or comments. 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 theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: Under Evaluation: END 4-26A (PTD# 2180810) - OA pressurization Date:Wednesday, September 4, 2024 3:55:38 PM Attachments:4-26 90 day TIO.docx END 4-26A SCHEMATIC 01-04-2020.pdf From: Ryan Thompson <Ryan.Thompson@hilcorp.com> Sent: Wednesday, September 4, 2024 3:13 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Sara Hannegan <shannegan@hilcorp.com> Subject: Under Evaluation: END 4-26A (PTD# 2180810) - OA pressurization Mr. Wallace, Gas Injector END 4-26A (PTD# 2180810) is operated under AA (AIO 1.015) for TxI communication. On 8/30/24 the well was shut in due to a facility shut down. On 9/3/24 the OA pressure climbed to 950 psi and the OA was bled to 0. The OA is currently at 450 psi. The well is now classified as under evaluation to determine if the OA pressurization is from thermal effects or other means. The well is currently shut in. Plan forward: 1. Perform PPPOT-IC prior to bringing the well online. 2. If PPPOT-IC passes, put well on injection and monitor for OA repressurization. Attached is a WBS and 90 day TIO plot. Please respond with any questions or comments. 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 theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, 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 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. 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: END 4-26A (PTD: 2180810) - IA pressure broke MOASP Date:Wednesday, February 28, 2024 7:42:56 AM Attachments:END 4-26A SCHEMATIC 01-04-2020.pdf END 4-26 90 day TIO.docx From: Ryan Thompson <Ryan.Thompson@hilcorp.com> Sent: Tuesday, February 27, 2024 4:21 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Sara Hannegan <shannegan@hilcorp.com> Subject: END 4-26A (PTD: 2180810) - IA pressure broke MOASP Mr. Wallace, END 4-26A is an AA’d gas injector (AIO 1.015). The well is AA’d for TxI communication and is managed with IA bleeds. On 2/27/24 operations found the IA pressure gauge to be frozen, and after installing a gauge on the IA companion valve found the IA pressure to be 2510 psi, breaking MOASP. The well has been bled to 775 psi. The IA jewelry had been freeze protected with methanol. New ½” full port valves have been installed on the IA jewelry and freeze protected, along with the heat trace re-run. The well passed its annual MIT-IA on 12/18/2023. Attached is a 90 day TIO plot and a WBS. Please let me know if you have any additional questions. 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 theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. _____________________________________________________________________________________ Revised By: JCM 01/04/20 SCHEMATIC Duck Island Unit Well: END 4-26A Last Completed: 9/4/2018 PTD: 218-081 TD =14,005’ (MD) / TD = 9,893’(TVD) 30” KB Elev.: 40.9’/ GL Elev.: 13.9’ 7” 4 5 9 9-5/8” 1 2 14 Min ID=3.725” @ 13,308’ MD PBTD =13,999’(MD) / PBTD =9,887’(TVD) 3 13-3/8” 8 7 10 9-5/8” Window: 5,411’ MD 11 12 6 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 30"Conductor N/A / N/A / N/A N/A Surface 161’N/A 13-3/8”Surface 68/ N-80/ Btrs 12.415 Surface 2,502’0.150 9-5/8" Intermediate 47 / NT80S / NSCC 8.681 Surface 5,411’ (KOP)0.0732 7”Prod Liner 26 / L-80 / TXP 6.276 5,255’ 14,000’ 0.0383 TUBING DETAIL 4-1/2"Tubing 12.6/ 13Cr/ JFE Bear 3.958 Surface 13,605’ 0.0152 JEWELRY DETAIL No Depth Item 1 1,485’ 4.5” SLB TRMAXX SSSV w/ X-Nipple - ID= 3.813” GLM DETAIL: MMG SPM-1-1/2” w/ RK Latch 2 3,859’STA 6 Dev= , VLV=DMY, TVD=3,859 ’, Date= 12/23/19 3 5,217’STA 5: Dev= , VLV=DMY, TVD= 5,216’, Date= 12/23/19 4 5,255’ 9-5/8” x 7” BKR HRDE ZXHD Packer GLM DETAIL: Special Clearance SPM-1” w/ RK Latch 5 6,888’STA 4: Dev= , VLV=DMY,TVD= 6,504’, Date= 12/23/19 6 8,793’STA 3: Dev= , VLV= DMY, Port= 0, TVD= 7,369’, Date=9/4/18 7 10,700’STA 2: Dev= , VLV= DMY, Port= 0, TVD= 8,232’, Date=9/4/18 8 12,606’STA 1: Dev= , VLV= DMY, Port= 0, TVD= 9,190’, Date=9/4/18 9 13,182’ 4-1/2” X Nipple – ID= 3.813” 10 13,283’ 7” x 4-1/2” Packer – ID= 3.863” 11 13,308’ 4-1/2” OTIS XN Nipple – ID= 3.725” 12 13,603’ 4-1/2” WLEG – ID= 3.958” – Btm @ 13,605’ PERFORATION DETAIL END Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Size HRZ Shale 13,320’13,325’9,548’9,550’5’8/29/18 Sqz 3-1/8” K2B 13,953’13,973’9,866’9,877’20’9/10/18 Open 3-1/8” OPEN HOLE / CEMENT DETAIL 13-3/8” 4,557 cu/ft Permafrost in 17.5” Hole 7”115 cu/ft Class “G” in 8-1/2” Hole WELL INCLINATION DETAIL Max Hole Angle = 63.7 deg. @ 9,549’ Angle at Top Perf = 59 Deg. @ 13,962 ’ TREE & WELLHEAD Tree 4-1/8” 6.5K CIW Wellhead MCEVOY GENERAL WELL INFO API: 50-029-21835-01-00 Initial Completion - 8/6/1988 RWO – 2/21/1995 Sand Back & Cmt Cap – 3/31/99 Sidetrack Completion – 8/25/18 SAFETY NOTES H2S Readings Average 230 – 260 PPM on A/L & Gas Injectors Well Requires a SSSV MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Thursday, January 25, 2024 SUBJECT:Mechanical Integrity Tests TO: FROM:Sully Sullivan P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC 4-26A DUCK IS UNIT SDI 4-26A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 01/25/2024 4-26A 50-029-21835-01-00 218-081-0 G SPT 9529 2180810 2500 4197 4197 4196 4197 161 186 187 184 REQVAR P Sully Sullivan 12/18/2023 Operator stated that he fluid packed the ia the day prior. Returns were too gassy and had to be bleed to process after .5 bbls and total returns could not be measured. 1 year MIT IA to 2500psi Per AIO 1.015. diesel temp was 160. operator and little red had conflicting schematics. 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:DUCK IS UNIT SDI 4-26A Inspection Date: Tubing OA Packer Depth 1375 2795 2733 2704IA 45 Min 60 Min Rel Insp Num: Insp Num:mitSTS231219084452 BBL Pumped:12 BBL Returned: Thursday, January 25, 2024 Page 1 of 1 Gas injector with known TxIA communication. Concerns raised about gassy IA and need to replace fluids bled at a bbl-for-bbl rate (email dated 1/3/2023; jbr) 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:Regg, James B (OGC) To:AOGCC Records (CED sponsored) Subject:FW: Inconclusive MIT-IA END 4-26 (PTD# 218-081) Date:Tuesday, January 3, 2023 11:11:22 AM Attachments:image001.png Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Regg, James B (OGC) <jim.regg@alaska.gov> Sent: Tuesday, January 3, 2023 11:10 AM To: Jerimiah Galloway <Jerimiah.Galloway@hilcorp.com> Cc: DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Subject: RE: Inconclusive MIT-IA END 4-26 (PTD# 218-081) Endicott SDI 4-26A PTD 2180810 Our inconclusive determination for the MITIA was based on concerns about the bleed frequency and fluid volumes pumped for the test. If an increased bleed frequency was evident this would be indicative of deteriorating conditions which would invalidate AIO 1.015 (refer to Conditions 6 and 7). After reviewing the TIO pressure plot you provided, our well files, and AOI 1.015, I conclude that the bleed frequency has not appreciably changed since AIO 1.015 was approved 6/4/2020. Since the pressures recorded indicate a passing result, I am changing the test result to “PASS”. HOWEVER, you are reminded that the large volume of fluid pumped for the test is a concern. It remains unclear to us where the IA fluids are going – if being removed during the bleeds that are occurring every 10-13 days, Hilcorp should be replacing barrel for barrel. Send your test report no later than 1/5/2023 so it can be imported into our database. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Jerimiah Galloway <Jerimiah.Galloway@hilcorp.com> Sent: Friday, December 30, 2022 3:39 PM To: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: RE: Inconclusive MIT-IA END 4-26 (PTD# 218-081) Mr. Regg, Thank you for taking a few minutes to discuss this one today. Below is a TIO plot of the last 90 days. I went back and reviewed the bleeds information from the last year. It doesn’t look like it has increased in frequency and the repressurization rate has not changed drastically over that time. We are bleeding every 10-13 days. I spoke with our Ops team and they did do a pretest prior to conducting the witnessed test. I am tracking down the information from that test now. I also reviewed the information in written in the AA. The only requirement surrounding IA pressure management is that it can be manage with a weekly pressure bleed. Please let me know if you have any further questions and we can discuss next week. Happy New Year. 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, December 27, 2022 10:29 AM To: Regg, James B (CED) <jim.regg@alaska.gov> Subject: Inconclusive MIT-IA END 4-26 (PTD# 218-081) Mr. Regg, Good morning. I wanted to touch base with you about another inconclusive MIT-IA out at Endicott. END 4-26 (PTD# 218-081) MIT-IA was conducted on 12/22/2022. The IA lost 49 psi and 18 psi during the 30 minute test period. A total of 20.5 bbls was pumped to reach the desired test pressure and a total of 1 bbl was returned after bleeding to pre-test pressure. The onsite personnel deemed that this was an inconclusive test due to the volume pumped to reach test pressure. While this is a larger volume to achieve test pressure than normal, the test passed the pressure criteria. END 4-26 is currently a GI with known TxIA communication. An AA was approved December 2021 to continue gas injection with increased testing and monitoring requirements. With this, there is some volume of fluid that will be lost to the communication. Hilcorp believes that the casing and packer are competent based on the pressure loss and feel that this should be considered a passing MIT-IA. The volume of future MIT’s should will be closely monitored for changes in test volume that could indicate additional impairments. 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 thesender'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 adverselyaffect 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 State of Alaska Alaska Oil and Gas Conservation Commission DATE:Thursday, January 26, 2023 SUBJECT:Mechanical Integrity Tests TO: FROM:Guy Cook P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC 4-26A DUCK IS UNIT SDI 4-26A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 01/26/2023 4-26A 50-029-21835-01-00 218-081-0 G SPT 9529 2180810 2500 3988 3990 3990 3992 89 122 115 110 REQVAR P Guy Cook 12/22/2022 Annual MITIA per AIO 1.015. Annual test required to be to 2500 psi. Testing completed with a Little Red Services pump truck and calibrated gauges. Told by Larry McBride they must bleed the IA approximately every 10 days to keep below 2500 psi. Test determined to be a "P" after review per J. Regg. 30 MinPretest Initial 15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name: DUCK IS UNIT SDI 4-26A Inspection Date: Tubing OA Packer Depth 1611 2757 2708 2690IA 45 Min 60 Min Rel Insp Num: Insp Num:mitGDC221222014135 BBL Pumped:20.5 BBL Returned:1 Thursday, January 26, 2023 Page 1 of 1 Annual MITIA per AIO 1.015. Annual test required to be to 2500 psi. Testing completed with a Little Red Services pump truck and calibrated Annual MITIA per AIO 1.015. Annual test required to be to 2500 psi. Testing completed with a Little Red Services pump truck and calibrated gauges. Told by Larry McBride they must bleed the IA approximately every 10 days to keep below 2500 psi. Test determined to be a "P" after review per J. 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Supervisor FROM: Guy Cook Petroleum Inspector NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Thursday, February 3, 2022 SUBJECT: Mechanical Integrity Tests Hilcorp Alaska, LLC 4-26A DUCK IS UNIT SDI 4-26A Src: Inspector Reviewed By: P.I. Supry Comm Well Name DUCK IS UNIT SDI 4-26A API Well Number 50-029-21835-01-00 Inspector Name: Guy Cook Permit Number: 218-081-0 Inspection Date: 1/22/2022 Insp Num: mitGDC220122063837 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 4-26A Type Inj G- TVD 9529 - Tubing 4503 4503, . 4504• 4505 PTD 2180810 - Type Test SPT Test psi 2500 IA 1596, 2759 2729 - 2728 BBL Pumped: 8 BBL Returned: 5.7 _ OA 199 - 203- 210 - 215, Interval REQVAR - Notes: MITIA per AIO # 1.015. Testing is completed with a triplex, bleed tank and calibrated gauges. —t�!'4— i.-Z�l / 2-07-1 ' t)e-t( pVueCd ulil� 1; - 5 — C(� .V) C', cc - Thursday, February 3, 2022 Page 1 of 1 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: 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. Some people who received this message don't often get email from jerimiah.galloway@hilcorp.com. Learn why this is important From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: OPERABLE: Injector DIU SDI 4-26A (PTD# 218081) anomalous OA repressurization resolved Date:Thursday, January 13, 2022 11:38:06 AM Attachments:image001.png image003.png From: Jerimiah Galloway <Jerimiah.Galloway@hilcorp.com> Sent: Thursday, January 13, 2022 9:31 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Torin Roschinger <Torin.Roschinger@hilcorp.com>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Subject: RE: OPERABLE: Injector DIU SDI 4-26A (PTD# 218081) anomalous OA repressurization resolved Mr. Wallace, Gas Injector DIU SDI 4-26A was placed UNDER EVALUATION and shut-in on 12/15/2021 for suspected IAxOA communication through the IC pack-off. On 12/16/2021, the IC pack-off was re-energized, passed a PPPOT-IC to 3000psi and the well was placed back on injection. The well has been on injection and monitored for a period of 28 days showing no signs of OA repressurization indicating a successful repair of the pack-off. The well is now classified as OPERABLE. Plan Forward: 1. AOGCC Witness MIT-IA Jerimiah Galloway Hilcorp Alaska Well Integrity Engineer Email: jerimiah.galloway@hilcorp.com O: (907)564-5005 C: (828)553-2537 From: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Sent: Thursday, December 16, 2021 2:16 PM To: Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Torin Roschinger <Torin.Roschinger@hilcorp.com> Subject: [EXTERNAL] RE: UNDER EVALUATION: Injector DIU SDI 4-26A (PTD# 218081) anomalous OA repressurization Oliver, Thank you for the email and phone call earlier. You are approved for the restart of injection and up to 28 days injection for monitoring. You are approved for the rescheduling/delay of the MITIA to January 2022. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov 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 Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. From: Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Sent: Thursday, December 16, 2021 1:08 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Torin Roschinger <Torin.Roschinger@hilcorp.com> Subject: RE: UNDER EVALUATION: Injector DIU SDI 4-26A (PTD# 218081) anomalous OA repressurization Mr. Wallace, DIU SDI 4-26A was shut-in on 12/15/2021. Wellhead diagnostics have since been completed. The wellhead tech was initially unable to bleed down pressure in the IC pack-off test void of the wellhead indicating that at least one of the seals was leaking. After torquing the lock-down screws to reenergize the primary seals the test void repressurization rate was significantly reduced. The wellhead tech then reenergized the secondary seals and was able to get a passing 30 min PPPOT-IC to 2800 psi. We request permission to restart injection to evaluate if the OA repressurization has been repaired. If we see no indication of continued OA repressurization within the 28-day evaluation period we will obtain an AOGCC witnessed MIT-IA per the AIO 1.015 requirements. The current annually required MIT-IA is due in December 2021, we request an extension on this to accommodate the 28- day evaluation period such that the pressure test would be completed by 1/12/2021. If repressurization continues after restarting injection we will immediately contact the AOGCC with a revised plan forward. Plan forward: 1. Operations: Restart injection- Monitor for OA repressurization. 2. If no OA repressurization- AOGCC witnessed MIT-IA. 3. If OA repressurization continues- Immediately contact AOGCC with revised plan forward. Regards, Oliver Sternicki Hilcorp Alaska, Hilcorp North Slope LLC Well Integrity Engineer Office: (907) 564 4891 Cell: (907) 350 0759 Oliver.Sternicki@hilcorp.com From: Oliver Sternicki Sent: Wednesday, December 15, 2021 4:29 PM To: Wallace, Chris D (CED) <chris.wallace@alaska.gov> Cc: 'Regg, James B (DOA) (jim.regg@alaska.gov)' <jim.regg@alaska.gov>; Torin Roschinger <Torin.Roschinger@hilcorp.com> Subject: UNDER EVALUATION: Injector DIU SDI 4-26A (PTD# 218081) anomalous OA repressurization Mr. Wallace, Injector DIU SDI 4-26A (PTD# 218081) currently operates under AIO 1.015 for gas injection with slow TxIA communication. An OA bleed was executed on 12/07/21 due to what was thought to be thermally induced pressure. After this bleed the OA pressure remained stable at 200 psi until 12/15/21 when the OA pressure climbed requiring it to be bled again. This OA repressurization constitutes a potential change in the well’s mechanical condition and requires the well be shut-in immediately per AIO 1.015, condition #6. The well is being shut-in today such that diagnostics and testing can be conducted. The well is now considered UNDER EVALUATION and is on a 28 day clock for diagnostics and resolution. Plan forward: 1. Wellhead: IC pack-off diagnostics. Depending on how the repressurization reacts to the well being shut-in it may be necessary to warm the well up (place back on injection) and repeat the wellhead diagnostics. 2. Operations: AOGCC witnessed MIT-IA depending on pack-off diagnostics results 3. Engineering: Additional diagnostics, possible AA amendment. Please respond with any questions or concerns. Oliver Sternicki Hilcorp Alaska, Hilcorp North Slope LLC Well Integrity Engineer Office: (907) 564 4891 Cell: (907) 350 0759 Oliver.Sternicki@hilcorp.com 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, youare 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, thenpromptly 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 ordata. 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. 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, youare 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, thenpromptly 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 ordata. 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: Injector DIU SDI 4-26A (PTD# 218081) anomalous OA repressurization Date:Thursday, December 16, 2021 2:16:56 PM Attachments:image002.png From: Wallace, Chris D (OGC) Sent: Thursday, December 16, 2021 2:16 PM To: Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Torin Roschinger <Torin.Roschinger@hilcorp.com> Subject: RE: UNDER EVALUATION: Injector DIU SDI 4-26A (PTD# 218081) anomalous OA repressurization Oliver, Thank you for the email and phone call earlier. You are approved for the restart of injection and up to 28 days injection for monitoring. You are approved for the rescheduling/delay of the MITIA to January 2022. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276- 7542 (fax), chris.wallace@alaska.gov 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 Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. From: Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Sent: Thursday, December 16, 2021 1:08 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Torin Roschinger <Torin.Roschinger@hilcorp.com> Subject: RE: UNDER EVALUATION: Injector DIU SDI 4-26A (PTD# 218081) anomalous OA repressurization Mr. Wallace, DIU SDI 4-26A was shut-in on 12/15/2021. Wellhead diagnostics have since been completed. The wellhead tech was initially unable to bleed down pressure in the IC pack-off test void of the wellhead indicating that at least one of the seals was leaking. After torquing the lock-down screws to reenergize the primary seals the test void repressurization rate was significantly reduced. The wellhead tech then reenergized the secondary seals and was able to get a passing 30 min PPPOT-IC to 2800 psi. We request permission to restart injection to evaluate if the OA repressurization has been repaired. If we see no indication of continued OA repressurization within the 28-day evaluation period we will obtain an AOGCC witnessed MIT-IA per the AIO 1.015 requirements. The current annually required MIT-IA is due in December 2021, we request an extension on this to accommodate the 28- day evaluation period such that the pressure test would be completed by 1/12/2021. If repressurization continues after restarting injection we will immediately contact the AOGCC with a revised plan forward. Plan forward: 1. Operations: Restart injection- Monitor for OA repressurization. 2. If no OA repressurization- AOGCC witnessed MIT-IA. 3. If OA repressurization continues- Immediately contact AOGCC with revised plan forward. Regards, Oliver Sternicki Hilcorp Alaska, Hilcorp North Slope LLC Well Integrity Engineer Office: (907) 564 4891 Cell: (907) 350 0759 Oliver.Sternicki@hilcorp.com From: Oliver Sternicki Sent: Wednesday, December 15, 2021 4:29 PM To: Wallace, Chris D (CED) <chris.wallace@alaska.gov> Cc: 'Regg, James B (DOA) (jim.regg@alaska.gov)' <jim.regg@alaska.gov>; Torin Roschinger <Torin.Roschinger@hilcorp.com> Subject: UNDER EVALUATION: Injector DIU SDI 4-26A (PTD# 218081) anomalous OA repressurization Mr. Wallace, Injector DIU SDI 4-26A (PTD# 218081) currently operates under AIO 1.015 for gas injection with slow TxIA communication. An OA bleed was executed on 12/07/21 due to what was thought to be thermally induced pressure. After this bleed the OA pressure remained stable at 200 psi until 12/15/21 when the OA pressure climbed requiring it to be bled again. This OA repressurization constitutes a potential change in the well’s mechanical condition and requires the well be shut-in immediately per AIO 1.015, condition #6. The well is being shut-in today such that diagnostics and testing can be conducted. The well is now considered UNDER EVALUATION and is on a 28 day clock for diagnostics and resolution. Plan forward: 1. Wellhead: IC pack-off diagnostics. Depending on how the repressurization reacts to the well being shut-in it may be necessary to warm the well up (place back on injection) and repeat the wellhead diagnostics. 2. Operations: AOGCC witnessed MIT-IA depending on pack-off diagnostics results 3. Engineering: Additional diagnostics, possible AA amendment. Please respond with any questions or concerns. Oliver Sternicki Hilcorp Alaska, Hilcorp North Slope LLC Well Integrity Engineer Office: (907) 564 4891 Cell: (907) 350 0759 Oliver.Sternicki@hilcorp.com 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 recipientor 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, pleaseimmediately 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 anyattachments 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 considersappropriate. 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: Injector DIU SDI 4-26A (PTD# 218081) anomalous OA repressurization Date:Thursday, December 16, 2021 7:04:43 AM Attachments:image004.png From: Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Sent: Wednesday, December 15, 2021 4:29 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Torin Roschinger <Torin.Roschinger@hilcorp.com> Subject: UNDER EVALUATION: Injector DIU SDI 4-26A (PTD# 218081) anomalous OA repressurization Mr. Wallace, Injector DIU SDI 4-26A (PTD# 218081) currently operates under AIO 1.015 for gas injection with slow TxIA communication. An OA bleed was executed on 12/07/21 due to what was thought to be thermally induced pressure. After this bleed the OA pressure remained stable at 200 psi until 12/15/21 when the OA pressure climbed requiring it to be bled again. This OA repressurization constitutes a potential change in the well’s mechanical condition and requires the well be shut-in immediately per AIO 1.015, condition #6. The well is being shut-in today such that diagnostics and testing can be conducted. The well is now considered UNDER EVALUATION and is on a 28 day clock for diagnostics and resolution. Plan forward: 1. Wellhead: IC pack-off diagnostics. Depending on how the repressurization reacts to the well being shut-in it may be necessary to warm the well up (place back on injection) and repeat the wellhead diagnostics. 2. Operations: AOGCC witnessed MIT-IA depending on pack-off diagnostics results 3. Engineering: Additional diagnostics, possible AA amendment. Please respond with any questions or concerns. Oliver Sternicki Hilcorp Alaska, Hilcorp North Slope LLC Well Integrity Engineer Office: (907) 564 4891 Cell: (907) 350 0759 Oliver.Sternicki@hilcorp.com 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 recipientor 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, pleaseimmediately 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 anyattachments 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 considersappropriate. 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: SDI 4-26A (218-081) RST Water flow Log on 11-Jan-2019 Please include current contact information if different from above. 37' (6HW Received By: 07/22/2021 By Abby Bell at 2:04 pm, Jul 22, 2021 MEMORANDUM TO: Jim Regg - --> P.I. Supervisor l 7�� FROM: Bob Noble Petroleum Inspector NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Friday, February 5, 2021 SUBJECT: Mechanical Integrity Tests Hilcorp Alaska, LLC 4-26A DUCK IS UNIT SDI 4-26A Sre: Inspector Well Name DUCK IS UNIT SDI 4-26A API Well Number 50-029-21835-01-00 Inspector Name: Bob Noble Permit Number: 218-081-0 Inspection Date: 12/31/2020 , Insp Num: mitRCN201231180655 Rel Insp Num: MITOP000008393 Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 4-26A -Type Inj G TVD 9529 Tubing 4477 4477 - 4476 4426 PTD 2180810 Type Test SPT Test psi 2500 IA 1676 2788 2745 2736 - BBL Pumped: 3.4 BBL Returned: 3.4 OA r 350 400 400 400 Interval IRequired by Variance - P/F Pass Notes: Yearly MIT -IA to 2500 psi per AIO 1.015 Friday, February 5, 2021 Page 1 of I Samuel Gebert Hilcorp Alaska, LLC GeoTech Assistant 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 10/15/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL SDI 4-26A (PTD 218-081) LeakPointTM Acoustic LDL Survey 05/03/2020 Please include current contact information if different from above. Received by the AOGCC 10/15/2020 PTD: 2180810 E-Set: 34105 Abby Bell 10/15/2020 Wallace, Chris D (CED) From: David Gorm <dgorm@hilcorp.com> Sent: Tuesday, May 5, 2020 8:18 AM To: Wallace, Chris D (CED) Subject: End 4-26 PTD # 218081 Chris, Per our conversation about the results of the leak detect log results on END 4-26 we will return the well to gas injection for 28 days to evaluate our TxIA trend. Thanks David Gorm Sent from my iPhone Wallace, Chris D (CED) From: David Gorm <dgorm@hilcorp.com> Sent: Friday, April 17, 2020 3:43 PM To: Wallace, Chris D (CED) Subject: END 4-26 (PTD#: 218081) Possible TxIA Communication Attachments: END 4-26 TIO, 4-17-20.xlsx Chris, Attached is the TIO plot for END 4-26 (Gas Injector). As we discussed this well has been online as a gas injector since January 2020. In the last few weeks it appears we may have a TxIA communication requiring us to bleed every 2 weeks. We have inspected our WH seals to check for communication there, our seals are holding. We have scheduled to run an acoustic leak detect log on April 27th to evaluate our leak path. As we discussed we will continue our gas injection on END 4-26 until we shut the well in to complete the leak detect log. We will follow up with the results of the logging to review the plan forward. Please let me know if you have any questions. Thanks, David Gorm Operations Engineer— Northstar/Endicott Hilcorp Alaska Office: 907-777-8333 Cell: 505-215-2819 Wallace, Chris D (CED) From: David Gorm <dgorm@hilcorp.com> Sent: Tuesday, March 3, 2020 11:56 AM To: Wallace, Chris D (CED) Subject: END 4-26A (PTD:218-081) - Gas Injector IA Bleed Update Chris, We have been monitoring the IA pressure on END 4-26A since we have initiated gas injection. Per our previous conversations our IA pressure has been steady around 1,750 psi while we were injecting 10 MMCF/day. On 2/25/2020 we increased our injection rate to 15 MMCF/day. In anticipation of thermal response we bled our IA pressure down to 1000 psi on 2/25/2020. We made two more bleeds on the IA on 3/1/2020 and 3/2/2020 to manage our IA pressure increase from the change in Gas injection rate and injection pressure. We have bled back fluid on all the bleeds to date. Please let me know if you have any questions or concerns. Thanks, David Gorm Operations Engineer— Northstar/Endicott Hilcorp Alaska Office: 907-777-8333 Cell: 505-215-2819 The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication maybe legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. 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. Wallace, Chris D (CED) From: David Gorm <dgorm@hilcorp.com> Sent: Thursday, February 6, 2020 1:03 PM To: Wallace, Chris D (CED) Subject: Gas Injector SDI 4-26A (PTD# 2180810) - IA pressure Attachments: 4-26 TIO.xlsx Chris, Recently we converted Endicott SDI 4-26A (PTD# 2180810) to a gas injector on 1/15/2020. We have been injecting 10 MMSCF gas a day with a current injection pressure of 3,346 psi. Since starting injection we been monitoring the IA pressure to ensure we have no communication. The IA pressure appeared to have stabilized around 480 psi. On 2/6/2020 our night operator identified that an ice -plug has interfered with our IA pressure readings. The obstruction was removed and we are now reading an IA pressure of 1,473 psi that is stable. Based on our current injection pressure of 3,346 psi and our recent passing IA MIT to 2,400 psi (12/31/2019) we do not suspect we have an IA communication. We plan to continue injection and monitor the IA pressure to ensure we do not have an increase trend. Our evaluation of the IA pressure at 1,473 psi is due to thermal expansion. Attached current IA pressure chart. Please let me know if you have any questions. Thanks, David Gorm Operations Engineer— Northstar/Endicott Hilcorp Alaska Office: 907-777-8333 Cell: 505-215-2819 The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. 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. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS re� �R I "d ]AN 2 1 2020 1. Operations Abandon LJ Plug Perforations Ll Fracture StimulatLi Pull Tubing Li Operations shut own LJ Performed: Suspend ❑ Perforate ❑ Other Stimulat[] Alter Casin g ❑ Change Approved Program ❑ Plug for Redrill ❑ srforate New Pool ❑ Repair We❑ Re-enter Susp Well ❑ Other: Convert to Gas Injector Q 2. Operator Hilcorp Alaska LLC 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development P ❑ Stratigraphic❑ Ex Exploratory ry ❑ Service ❑ 218-081 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, 6. API Number: AK 99503 50-029-21835-01-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL047502 & ADL 047503 DUCK IS UNIT SDI 4-26A 9. Logs (List lags and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): NIA ENDICOTT / ENDICOTT OIL 11. Present Well Condition Summary: Total Depth measured 14,005 feet Plugs measured N/A feet true vertical 9,893 feet Junk measured N/A feet Effective Depth measured 13,999 feet Packer measured 5,255 & 13,283 feet true vertical 9,887 feet true vertical 5,253 &9,529 feet Casing Length Size MD TVD Burst Collapse Conductor 161' 30" 161' 161' NIA N/A Surface 2,502' 13-3/8" 2,502' 2,502' 5,020psi 2,260psi Intermediate 5,417' 9-5/8" 5,417' 5,413' 6,870psi 4,760psi Production Liner 8,745' 7" 14,000' 9,891' 7,240psi 5,410psi Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth) 4.5" 12.6# 113CR-80 / JFE Bear 13,605' 9,690- 9-5/8" x 7" BKR HRDE ZXHD 1,485' MD Packers and SSSV (type, measured and true vertical depth) 7" x 4-1/2" TRMAXX SSSV See Above 1,485' ND 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Priorto well operation: 135 594 2,735 1 1,800 584 Subsequent to operation: 0 10,000 0 1 100 3,911 14. Attachments (required per20 AAC 25.070, 25.071, &25.283) 15. Well Class after work: Daily Report of Well Operations ❑� Exploratory[] Development ❑ Service ❑� Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil ❑ Gas WDSPL ❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑� SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the f r going is true and correct to the best of my knowledge. Sundry Number or NIA if C.O. Exempt: 7319-543 O �iwra„ ror L, L. ✓C Authorized Name: Chad Helgeson Contact Name: Wyatt Rivard Authorized Title: Operations Manager Contact Email: WriyBrd�hIlCOrp.COr11 Authorized Signature: Date: 1/21/2020 Contact Phone: 777-8547 Form 10-404 Revised 4/2017 �j ��r�2oaD ADDMS I�� JAN 2 3 2020 Submit Original Only Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date END 4-26A Slickline 50-029-21835-01-00 218-081 12/16/2019 1/16/2020 12/11/2019- Wednesday No operations to report. 12/12/2019 - Thursday No operations to report. 12/13/2019-friday No operations to report. 12/14/2019 -Saturday No operations to report. 12/15/2019 -Sunday No operations to report. 12/16/2019 - Monday ***WELL 5/1 ON ARRIVAL***(gas-lift). PT PCE TO 250psi LOW, 2,200psi HIGH. ATTEMPT TO SET 4-1/2" SLIP -STOP CATCHER SUB & UNABLE TO PASS TRSSSV @ 1,460' SLM. SET 4-1/2" KEYLESS RHC -M PLUG BODY W/O PACKING IN XN-NIP @ 13,277' SUM (13,308' MD). ATTEMPTTO PULL STA.# 4 BK-OGLV BUT UNABLE TO EVER LATCH UP AFTER LOCATING, APPEARED THAT WE WERE SETTING DOWN IN BTM OF MANDREL AND NOT LATCHING UP TO VALVE, BUTTHE TBG FLUID LEVEL CAME UP AFTER COMING FREE, AND THE TBG / IA PRESSURE CHANGED (but no valve recovered, and pin in pulling tool untouched). WAS GOING TO MAKE AN ATTEMPT AT UPPER VALVES BUT THE WINDS GUSTING OVER 40MPH, SO DECISION MADE TO LAY DOWN FOR THE NIGHT. SECURE WELL AND NOTIFIED PAD OP OF WELL STATUS. 12/17/2019 -Tuesday No operations to report. Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number I Start Date End Date END 4-26A Slickline 50-029-21835-01-00 218-081 12/16/2019 1/16/2020 12/18/2019- Wednesday No operations to report. 12/19/2019 - Thursday RUN 4-1/2" OK -1 KOT, 7" EXT, 1.25" LIB & GET FAINT IMPRESSION OF BK LATCH STICKING OUT OF STA #4 @ 6,873' SLM / 6,888' MD. PULL 1" BK-DGLV (24/64" PORT) W/ 4-1/2" OK -6 KOT, 1-1/4" CORELESS STUBYJD (UNSHEARABLE) FROM STA #4 @ 6,873' SLM /6,888' MD. PULL 1.5" RK- LGLV (16/64" DOME, TRO=1764psi) FROM STA #5 @ 5,204' SLM / 5,217' MD. PULL 1.5" RK- LGLV (16/64" DOME, TRO=1774psi) & SET 1.5" RK- DGLV IN STA #6 @ 3,845' SLM /3,859' MD. 12/20/2019 - Friday WELL S/I ON ARRIVAL, NOTIFY PAD -OP, PT PCE 300L/2,000H. SET 1.5" RK-DGLV IN STA #5 @ 5,204' SLM / 5,217' MD SET 1" BK-DGLV IN STA #4 @ 6,871' SLM / 6,888' MD. UNABLE TO GET PAST STA #4 TO RETRIEVE CATCHER. PULL 1" BK- DGLV (bent valve @ upper set of pkg) & SET 1" BK-DGLV IN STA #4 @ 6,871' SLM / 6,888' MD. UNABLE TO GET PAST STA #4 TO RETRIEVE CATCHER ONCE AGAIN. 12/21/2019 -Saturday WELL S/I ON ARRIVAL, NOTIFY PAD -OP, PT PCE 300L/2,000H. RUN DBL KNUCKLE, 2.50" LIB, DRIFT TBG TO SEE IF TOOLS WILL GO PAST STA #4, S/D @ 6,871' SLM, IMPRESSION OF STRAIGHT LATCH F/N . RUN 3.75" CENT, 5'x 1-7/8" STEM, 3.77" SWEDGE, 5'x 1-7/8" STEM, 3.70" LIB, TOOLS PASS STA #4, DRIFT TBG & S/D ON TOP OF CATCHER @ 13,274' SLM, IMPRESSION OF G -FISH NECK FROM CATCHER. *PRESSURE UP IA TO 2,040psi & CONFIRM STA #4 IS HOLDING, INITIAL T/IA=1400/1080, PAD OP TO MONITOR OVERNIGHT. 12/22/2019 -Sunday WELL S/I ON ARRIVAL, NOTIFY PAD -OP, PT PCE 300L/2000H. PULL 4-1/2" KEYLESS RHC -M PLUG BODY W/O PACKING (29") FROM XN-NIPPLE @ 13,276' SLM / 13,308' MD, EMPTY. *WELL DID NOT PASS MIT -IA, PRESSURE REACHED 2,400psi THEN FELL OFF QUITE SUDDENLY. 12/23/2019 - Monday WELL S/I ON ARRIVAL, NOTIFY PAD -OP, PT PCE 300L/2,000H. PULL 1" BK-DGLV W/ 4-1/2" OK -6 KOT, 1-1/4" CORELESS STUBYJD (UNSHEARABLE) FROM STA #4 @ 6,871' SLM /6,888' MD, VLV BENT @ UPPER PKG STACK & MISSING UPPER SET OF PKG. SET 1" BK -STUBBY DGLV (cut 2.5" off btm below pkg stack) IN STA #4 @ 6,872' SLM / 6,888' MD. RUN DBL KNUCKLE, 2.50" LIB, DRIFT TBG TO SEE IF TOOLS SKIP PAST STA #4, S/D @ 6,871' SLM, TOOLS SEEM TO DROP PAST MANDREL, IMPRESSION @ VERY BTM OF SIDE OF LATCH. *PAD OPS PRESSURE UP & PERFORM MIT -IA TO 2,400psi, GOOD TEST. JOB COMPLETE. 12/24/2019 -Tuesday No operations to report. Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number StartDate End Date END 3-41 Slickline 50-029-21878-00-00 188-126 12/31/2019 1/16/2020 12/25/2019- Wednesday No operations to report. 12/26/2019 - Thursday No operations to report. 12/27/2019 - Friday No operations to report. 12/28/2019-Saturday No operations to report. 12/29/2019-Sunday No operations to report. 12/30/2019 - Monday No operations to report. 12/31/2019-Tuesday WELL S/I ON ARRIVAL, NOTIFY PAD-OP, PT PCE 300L/4800H. PULL 5-1/2" MCX (SER#: HNM-503, x-eq device 8 x 3/16" ports, std pkg w/ o-ring, oat=41"). FROM HRQ NIPPLE @ 1,532' SLM / 1,564' MD, RECOVER ALL PACKING & NUBBINS. RUN 4-1/2" BLB, 3.80" GAUGE RING, DRIFT TBG & S/D @ 12,630' SLM, WORK TOOLS DOWN TO 12,720' SLM, 1,150# STICKY P/U, UNABLE TO SEE SPANGS, RECOVER SAMPLE OF THICK ASPHALTINE CHUNKS. CLOSE OUT JOB FOR C/O & END OF YEAR, LEAVE WELL S/I UPON DEPARTURE. Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date I End Date END 4-26A Slickline 50-029-21835-01-00 218-081 12/16/2019 1 1/16/2020 1/8/2020 - Wednesday No operations to report. 1/9/2020 - Thursday WELL SHUT IN UPON ARRIVAL (ELINE WFL). RIG UP ELINE. PRESSURE TEST LUBRICATOR TO 250 PSI LOW, 2,000 PSI HIGH. PT PASS. INTIALT/1/0=1640/15/0. RUN IN HOLE WITH WFL/GR/CCL/TEMP/PRESSURE TOOL. SET DOWN IN TIGHT SPOTS FROM GLM #1 @ 12,606' MD AND WORKED DOWN TO 12,983' WHILE WELL ON INJECTION @ 2-5 BPM, BUT DECISION WAS MADE TO HAVE SLICKLINE COME OUT TO CLEAR UP RESTRICTIONS AND DRIFT PRIOR TO ATTEMPTING ELINE WFL AGAIN. RIGGED DOWN ELINE UNIT- NOTIFIED PAD OF WELL STATUS AND DEPARTURE. 1/10/2020 - Friday WELL S/I ON ARRIVAL (drift for WFL). PT PCE TO 250psi LOW, 2,200psi HIGH. BRUSH & FLUSH TBG DOWN TO TD @ 13,947' SUM / 13,974' MD W/ 4.5" BRUSH & 3.71" G -RING WHILE ON WATER INJ (no sign of tight spots). DRIFT & TAG TD W/ 2.96"x 23' DUMMY PERF GUNS, RIH @ 40/50fpm FROM 12,000' -TD TO SIMULATE E -LINE WFL TOOLS (no sign of restrictions). PUMPED 1bbls OF METH DOWN TBG. WELLS/I ON DEPARTURE, PAD -OP NOTIFIED. 1/11/2020 -Saturday WELL SHUT IN UPON ARRIVAL (ELINE WFL). RIG UP ELINE. PRESSURE TEST LUBRICATOR TO 250 PSI LOW, 2,000 PSI HIGH. PT PASS. RIH W/ ELINE WFL LOGGING TOOLS. LOG BASELINE TEMP FROM 12,000 TO TD @ 13,968' WHILE SHUT IN. BRING WELL ONLINE AND LET STABALIZE OUT AT 7,100 BPD @ 2000#. BEGIN LOGGING STATION STOP COUNTS PER PROCEDURE. 1/12/2020 -Sunday Operationscontinued from 1/11/2020 - PERFORM WFL STATION STOPS AT 13,900, 13,700, 13350, 13,300, 13,260, 13,200, 13,100, 13000 & 12,500 WHILE INJECTING 5BPM AT 2,000 PSI. SHUT IN WELL LET STABILIZE FOR 1 HOUR. PERFORM 1 HR WARM BACK TEMPERATURE PASS FROM 12,000' TO TD @ 13,968'. PERFORM 2 HR WARM BACK TEMPERATURE PASS FROM 12,000' TO TD @ 13,968', JOB COM PLETED. 1/13/2020 - Monday No operations to report. 1/14/2020 -Tuesday No operations to report. fL- lea Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date END 4-26A Slickline 50-029-21835-01-00 218-081 12/16/2019 1/16/2020 1/15/2020 - Wednesday No operations to report. 1/16/2020 - Thursday Passing AOGCC SVS test. Witnessed Waived by Adam Earl. 1/17/2020 - Friday No operations to report. 1/18/2020 -Saturday No operations to report. 1/19/2020 -Sunday No operations to report. 1/20/2020 - Monday No operations to report. 1/21/2020 -Tuesday No operations to report. MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg// 1 �n, DATE: Tuesday, January 7, 2020 P.I. Supervisor � VL / 1Zfl, � SUBJECT: Mechanical Integrity Tests Bkorp Alaska LLC 4-26A FROM: Brian Bixby DUCK IS UNIT SDI 4-26A Petroleum Inspector Ste: Inspector Reviewed By: P.I. Supry 513z— NON-CONFIDENTIAL Comm Well Name DUCK IS UNIT SDI 4-26A API Well Number 50-029-21535-01-00 Inspector Name: Brian Bixby Permit Number: 218-081-0 Inspection Date: 12/31/2019 - IBSp Num: mitBDB200101044958 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 4-26A Type Inj w TVD 9529 Tubing 806 815 - 826 - 833 ' PTD 2180810 Type Test SPT Test psi 2382 - IA 349 2553 2520 - 2513 " BBL Pumped: 53 BBL Returned: 5.5 - OA 217 747 - 339 - 336 - Interval tNITAL P/F P Notes: Tuesday, January 7, 2020 Page 1 of 1 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Duck Island Field, Endicott Pool, SDI 4-26A Permit to Drill Number: 218-081 Sundry Number: 319-543 Dear Mr. Helgeson: 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 Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, J 'a rice Chair DATED this I) day of December, 2019. 313DMS O'/0EC 121019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 DEC 21;4il (17 A0G, `r; 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: Convert to Gas Injector ❑� 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development Q Stratigraphic ❑ Service ❑ 218-081 i 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: r Anchorage Alaska 99503 50-029-21835-01-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 462.007 Will planned perforations require a spacing exception? Yes ❑ No ❑� .EN9SDI 4-26A 9. Property Designation (Lease Number): r 10. Field/Pool(s): ADL047502 & ADL 047503 Duck Island Unit / Endicott Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth ND: MPSP (psi): Plugs (MD): Junk (MD): 14,005' 9,893' 13,999' 9,887' 1,900 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 161' 30" 161' 161' N/A N/A Surface 2,502' 13-3/8" 2,502' 2,502' 5,020psi 2,260psi Intermediate 5,417' 9-5/8" 5,417' 5,413' 6,870psi 4,760psi Production Liner 8,745' 7" 14,000' 9,891' 7,240psi 5,410psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 4.5" 12.6# / 13CR-80 / JFE Bear 13,605 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 9-518"x 7" BKR HRDE ZXHD & 7"x 4-1/2" and TRMAXX SSSV 5,255(MD)/ 5,253(TVD) & 13,283(MD)/ 9,529(TVD) and 1,485(MD)/ 1,485(TVD) 12. Attachments: Proposal Summary a Wellbore schematic 141 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: 12/12/2019 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑� r Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson Contact Name: Wyatt Rivard Authorized Title: Operations Manager Contact Email: wrlvard hIIcor .COM Contact Phone: 777-8547 Authorized Signature: Date: 11/26/2019 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity El BOP Test Mechanical Integrity Test u Clearance ❑ �Location { Other: -A All e-c^n.4,- ,pe�c,l/�r-� c�e.,,�c4 ¢�Jo eb rsl-rr-,1/ ,cJ-� � o A -4c- Z� WZ- C �!! i /'v/ /-WJIC4' �O C o i /�e-0 fir.Nc.t2 e <— jlt-5 rh0'e_cy,crh GDM.m- jt 6L3 U Post Initial Injection MIT Req'd? Yes Q�[Jf No ❑ tr Spacing Exception Required? Yes No Subsequent Form Required: `� s� I' ❑ / Q-- (� IBDMS° IKC 12 2019 APPROVED BY \ n\ 1` by: COMMISSIONER THE COMMISSION Date: r Approved L d \I UU Q, - I I\)I`1 Form,1 03 Revisetl /2017 Approved applicati ID Ae date of approval. Submit Form and Attachments in Duplicate ff Elik.o p Alaska. LL GINJ Conversion Well: END 4-26A PTD: 218-081 API: 50-029-21835-01 Well Name: END 4-26A API Number: 50-029-21835-01-00 Current Status: Active Producer Rig: SL+Ops Estimated Start Date: December 12, 2019 Estimated Duration: 5 Reg.Approval Req'std? Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts 777-8398 Permit to Drill Number: 218081 First Call Engineer: Wyatt Rivard (907) 777-8847 (0) (509) 670-8001(M) Second Call Engineer: I Taylor Wellman (907) 777-8449 (0) (907) 947-9533 (M) AFE: 1 1924580 WeIIEZ Entry Required: No Current BHP: 4080 psi @ 10,000' TVDss (Based on SBHPS on 9/13/19) Max Expected BHP: 4080 psi @ 10,000' TVDss (Based on SBHPS on 9/13/19) Max Proposed Surface Pressure:-1900psi (High WC well. Stacks out to Gas Lift Pressure) Recent Shut In WHIP: -1300psi (Taken 9/13/19) Min ID: 4-1/2" XN Nipple @ 13,308' MD Brief Well Summary: Endicott 4-26A was drilled and completed as a gas lifted producer in September 2018. The well is up -dip and in a good position to support gas injection at SDI. 4-26A will represent the first gas -only injector with a surface location on SDI. Converting the well to gas injection should improve oil production on several SDI producers and increase overall oil recovery. Objective: Convert the well service to gas injection. Notes Regarding Wellbore Condition: - Passing MIT -IA to 3000 psi on the rig on 9/6/18. - Well had a bradenhead seal weld with a passing MIT -OA to 1200 psi on 3/17/19. - Injection gas will be sent to SDI via an existing MI injection line and will be limited to an initial injection pressure of -4700 psi. - Well's existing SK tree will be utilized for injection. Variance Requested: 20AAC25.412(b) Packer will be set greater than 200ft measured depth from t/ open perfs. Tubing packer is at 13,283'MD which is 670' MD above the uppermost open perforations at 13,953'. Area of Review -END 4-26A (PTD#218081) Prior to the conversion of well END 4-26A from producer to gas injector, an Area of Review (AOR) must be conducted. This AOR found six other wells (END 3-09A, END 3-31, END 3-29, END 3-23A, & END 3-17 &17A) within % mile of END 4-26A's entry point into the Kekiktuk Formation. See attached table Area of Review END 4-26A for annulus integrity and zonal isolation of all wells within the AOR. Snapshots of available CBLs for wells within the AOR are also attached. Note: Circulation was lost during the primary cementjob of END 4-26A's 7" production liner with no cement reaching the casing shoe. Casing was then perforated from 13,320'-13,325' and circulated/squeezed with 20 bbls of cement prior to setting liner top packer. Subsequent CBL run on 9-1-18 shows a — 800 ft interval of fair/good bond from 12458' to 13260' MD with poor bond/cement a Hih.,P Alaska, LL GINJ Conversion Well: END 4-26A PTD: 218-081 API: 50-029-21835-01 below 13,260' MD. The entire interval from the top of Kekiktuk at 13,952' MD to the packer set at 13,283' MD contains non -permeable silts and shales comprising part of the Lower Cretaceous Unconformity (see attached END 4-26A Open Hole Log). Sundry Procedure (Approval Required to Proceed): Slickline 1. MIRU SL unit. 2. Pressure test to 300 psi low and 2000 psi high (use GL pressure). 3. RIH and set catcher sub below Station # 4 at 6,888' MD 4. Makeup kick over tool, RIH and pull SO GLV (1" valve) from Station # 4 at 6,888' MD 5. RIH and Pull DOME GLVs from stations # 5 & 6 (1-/12" valves) at 5217' MD and 3,859' MD 5F 6. RIH and set DMY GLVs in stations 4,5 &6 �y 7. Pull catcher 8. RD SL unit. Operations 11. Rigup echometer to the IA and shoot fluid level 12. Rigup high pressure hose and barrel meter from nearby injection line. 13. Pressure test line to 2500 psi 14. Begin to lube and bleed produced water into IA. a. 4-1/2"x9-5/8" Annular Volume is .0535 bbl/ft =281 bbis b. 4-1/2"x7" Annular Volume is .0186 bbl/ft = 10 bbls c. Annular volume to the 50 GLV is estimated at 291 bbls d. Pump corrosion inhibi orto ensure a minimum of .5% concentration (1.5-2 bbls). e. Monitor fluid level and swap to diesel freeze protect for final 1500 ft (80 bbls) 15. Once fluid packed. Perform a pre-injection MIT -IA to 2400 psi. f. Packer depth is 13,283' MD (9,529' TVD) g. Notify AOGCC inspectors at least 24 hrs prior to Pre -Injection MIT IA for option to witness, h. Provide completed Pre -Injection MIT -IA form to Darci Horner (dhorner@hilcorp.com) for submission to AOGCC. Temporary water Injection W F -t-/ /—z CJJ1 Additional external mechanical integrity testing viiill be performed to ensure confinement of injection fluids to the K28 injection zone. To accomplish this, the well will be placed on water injection for two weeks and then a water flow log and temperature survey will be performed prior to swapping to gas injection. L d 16. Place well onmater injecition targeting injection pressure of 2000 psi. L Max expected gas injection surface pressure is 4800 psi resulting in a max expected Abfx� injecting reservoir pressure of 5800 psi with a .1 psi/ft gas gradient to 10000' TVD. j. Equivalent water injection surface pressure with a .442 psi/ft gradient to 10000'TVD is 1380 psi (ignoring friction effects) k. No more than 2000 psi injection pressure is appropriate to account for any additional friction losses under water injection. 17. Maintain steady state injection for minimum of two weeks ff 11flooro Alaska, LB GINJ Conversion Well: END 4-26A PTD: 218-081 API: 50-029-21835-01 18. Once injection is stable, obtain AOGCC witnessed MIT -IA to 2400 psi 19. After two weeks of injection, shut-in and freeze protect well at least 24 hrs prior to integrity logging. Eline - External Mechanical Integrity Test 20. MIRU E -line, PT lubricator to 250psi low/ and at least 2000 psi high. Record in WSR. 21. RU WFL/GR/CCL/Temperature/Pressure tool. 22. Log baseline temperature survey down at 40 fpm from 12000' to TD. 23. Bring the well on injection targeting 2000 psi. 24. With well on stable injection for at least 2 hrs, take WFL readings at 13900', 13700', 13350', 13300', 1�I'll 13260', 13200', 13100', 13000' and 12,500' MD (at minitron). < I W F'_ w c� Ftp. A.oa-'_ 25. Once WFL readings are complete, shut in the well. 26. Immediately Log warm back Temperature Pass # 1 down at 40 fpm from 12000' to TD. 27. Pull up hole to 12000' and wait 1 hr 28. Log Temperature Pass # 2 down at 40 fpm from 12000' to TD. 29. Pull up hole to 12000' and wait 1 hr 30. Log Temperature Pass # 3 down at 40 fpm from 12000' to TD. 31. Record additional passes if necessary to estimate height of injection. Presentation should include an overlay of baseline and warmback temperature passes. 32. POOH and RDMO Eline. 33. Freeze Protect Tubing Operations — Initial Gas Infection 34. Once WFL and Temp logs have been provided to and approved by AOGCC, initial gas injection can commence. 35. Place well on gas injection targeting initial rate of -10 MMSCFD. 36. Obtain AOGCC witnessed SVS test within 5 days Attachments: - As Built and Proposed Schematics - AOR Table - AOR Map - AOR CBLs END 4-26A Open Hole Log Ililcorrr Alaeka, LLC KB Bev.: 40.9/ GL Elev.:13,9 TD=14,005' (MD) / TD = 9,893'(TVD) PBTD=13,999' (MD) / PBTD= 9,887(TVD) SCHEMATIC Duck Island Unit Well: END 4-26A Last Completed: 9/4/2018 PTD: 218-081 SAFETY NOTES TREE & WELLHEAD H2SReadings Average 230-260 PPM on A/L&Gas Injectors Tree 4-1/8"CIW Weil Requiresa SSSV Wellhead MCEVOV OPEN HOLE/ CEMENT DETAIL 13-3/8" 4,557 cu/ft Permafrost in 17.5" Hole 7" 115 cu/ft Class "G" In 8-1/2" Hole CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 30" Conductor N/A/ N/A / N/A N/A Surface 161' N/A 13-3/8" Surface 68/ N-80/ Btrs 12.415 Surface 2,502' 0.150 9-5/8" Intermediate 47 / NT80S / NSCC 8.681 Surface 5,411' (KOP) 0.0732 7" Prod Liner 26/L-80/TXP 6.276 5,255' 14,000' 0.0383 TUBING DETAIL Tubing 12.6/13Cr/JFE Bear I 3.958 I Surface 13,605' 0.0152 WELL INCLINATION DETAIL Max Hole Angle= 633 deg. @9,549' Angle at Top Perf= 59 Deg. @ 13,962' JEWELRY DETAIL No Depth Item 1 1,48S' 4.5" SLB TRMAXX SSSV w/ X -Nipple - ID= 3.813" GLM DETAIL: MMG SPM -1-1/2" w/ RK Latch 2 3,859' STA 6 Dew-, VLV= Dome, Port= 16, TVD=3,859', Date=9/9/18 3 5,217' STA 5: Dev---, VLV= Dome, Port= 16, TVD= 5,216', Date=9/9/18 4 5,255' 9-5/8" x 7" BKR HRDE ZXHD Packer GLM DETAIL: Special Clearance SPM -1" W/ RK Latch 5 6,888' STA 4: Dev=, VLV= SO, Port= 24, TVD=6,504', Date=9/9/18 6 8,793' STA 3:Dev=,VLV= DMV, Port= 0, TVD=7,369', Date=9/4/18 7 10,700' STA 2: Dev=, VLV= DMY, Port= 0, TVD= 8,232', Date=9/4/18 8 12,606' STA 1: Dev=, VLV= DMY, Port= 0, TVD=9,190', Date=9/4/18 9 13,182' 4-1/2"X Nipple - ID= 3.813" 10 13,283' 7"x4-1/2"Packer - ID= 3.863" 12 13,308' 4-1/2"OTIS XN Nipple - ID= 3.725" 13 13,603' 4-1/2"WLEG-ID= 3.958" - Bon @13,605' PERFORATION DETAIL :ND Sands I Top (MD) I Pit, (MD) I Top (TVD) I Btm (TVD) I FT I Date I Status I Size K2B I 13,953' 1 13,973' I 9,866' I 9,877' I 20' I 9/10/18 I Open 13-1/8" GENERAL WELL INFO API: 50-029-21835-01-00 Initial Completion -8/6/1988 RWO-2/21/1995 Sand Back & Cmt Cap - 3/31/99 Sidetrack Completion -8/25/18 Revised By: WLR 11/21/2019 ffflcorn Alxska, IJ.0 KB Elev.:46.9'/GL Elev.:139' 30' �. t� 2 3 9•SJS' 4 &518' Wmdow: 5,411' MD 5 6 7 6 9 Mn ID=3.725" tD 13,30B'MD _ 17 6OLI Duck Island Unit Well: END 4-26A PROPOSED Last Completed: 9/4/2018 PTD: 218-081 SAFETY NOTES TREE & WELLHEAD H25 Readings Average 230-260 PPM on A/L &Gas Injectors Tree 4-1/8" 6.5K CIW Well Requiresa SSSV Wellhead MCEVOY ll OPEN HOLE/ CEMENT DETAIL 13-3/8" 4,557 cu/ft Permafrost in 17.5" Hole 7" 115 cu/k Class "G" in 8-1/2" Hole CASING DETAIL Size Type Wt/Grade/Conn Drift ID Top Btm BPF 30" Conductor N/A/N/A/N/A N/A Surface 161' N/A 13-3/8" Surface 68/N-80/Burs 12.415 Surface 2,502' 0.150 9-5/8" Intermediate 47 / NT80S / NSCC 8.681 Surface 5,411' (KOP) 0.0732 7" Prod Liner 26/L-80/TXP 6.276 5,255' 14,000' 0.0383 TUBING DETAIL 4-1/2" Tubing 12.6/ 13Cr/ JFE Bear 3.958 Surface 13,605' 0.0152 WELL INCLINATION DETAIL Max Hole Angle = 63.7 deg. @ 9,549' Angle at Top Perf= 59 Deg. @ 13,962' JEWELRY DETAIL PERFORATION DETAIL END Sands Top (MD) em,5"SLBTRMAXX Top (ND) Bt m (ND) SSSV w/X-Nipple-ID=3.813" Date DETAIL: MMG SPM -1-1/2" w/ RK Latch Size W A 6 Dev=, VLV= DMYND=3859'Date= 13,325' 9,548' A S: Dev=VLV= DMYND= ',Date= 5' 8/29/18 -5/8" x 7" BKR HRDE ZXHD Packer 3-1/8" AIL: Special Clearance SPM -1" w/ RK Latch 13,953' 1 13,973' STA 4:Dev=,VLV=DMY,ND=6,504', Date= 6 8,793' STA 3: Dev=, VLV= DMY, Port= 0, ND= 7,369', Date=9/4/18 7 10,700' STA 2: Dev=, VLV= DMY, Port= 0, ND= 8,232', Date=9/4/18 8 12,606' STA 1: Dev=,VLV=DMY, Port=0, ND= 9,190', Date=9/4/18 9 13,182' 4-1/2"XNipple -J D=3.813" 10 13,283' 7"x4-1/2"Packer - ID= 3,863" 12 13,308' 4-1/2"OTIS XN Nipple -1D=3.725" 13 13,603' 4-1/2" WLEG - ID= 3.958" - Btm @ 13,605' PERFORATION DETAIL END Sands Top (MD) Btm (MD) Top (ND) Bt m (ND) FT Date Status Size HRZ Shale 13,320' 13,325' 9,548' 9,550' 5' 8/29/18 Sqz 3-1/8" K2B 13,953' 1 13,973' 9,866' 9,877 20' 9/10/18 Opert 3-1/8" TD =14,605' (MD) /TD= 9,WY(IVD) PBTD= 13,999'(MD)/PEITD=9AT( VD) GENERAL WELL INFO API: 50-029-21835-01-00 Initial Completion -8/6/1988 RW 0 - 2/21/1995 Sand Back & Cmt Cap - 3/31/99 Sidetrack Completion - 8/25/18 Revised By: WLR 11/22/19 SaL 3-258 smo ;a' .A" 3-17 ll Mile radius - b ae O^ \ 0.10A 4/07F so \ a, fo a,aa 343 n f � seu /� • BDI3 7C47C A- ,+ `31ro / - -15 3-238 \ i 33.-0p�55 3-178 ngoh f � fl - Q / Q I $919 Q 3.21 , axu ••_ 337 31 - A 'Aa ,23. aap•23 3T aa+f a.au O Q O' f 4,225 / 335 403 aas• 3 �i 41 Duckm+r haantl 2 4d3: Q, � � Duck lslaM� " �Q " t O - a-23 i 3d6 "s \ q -1s L•� . _ .Pas+ ° _ �. HILCORP ALASKA LLC ENDICOTT - - 347 - - _._ K2B AOI \' 1/4 Mile Radius WaI1Xu fXiOea xiBl6prarygl Q - •. Inwou WELL"BOIs w.amaPlw aWxmx.Pmf m.Nxm, uvn3Xs CI=Stl WM • O x,,. oox a f o w EE 11 it N W O m i ,Q N N 0 Z W mr v au s z° 3a m S N N o o Or o u ra o s_" o mo C .s, cr a c t c p a ro v `+ n vti "i- a o-ov0 w Y m aom o y "� - °b of u. 2 0 °1 m o` m u `� wr a o EutR n W. c v Y 3 - c i u o o m v E v u "- ❑ cb q m '� c ., -+ a c u v « 'r m a$ v v E n no y a ¢U m a v H v_ " v `° o m c v m o_ a m.-� E r. w maN E❑ vwm E nmo moi±+ E v 0 4K 3 E Y Him .=�u v ti in c i l'J m vu u' c N u N { N m m o 0 3� 3 o m a -a a to o ?Ou oN c U'.'.Ni m ca m o N m s 75 Yu ti -O m m v m u 3 a 3 u v o v E oN V v a v a r a o E v '+ u E ., O v 0 ,uu O v o a `na E �^ w'v" nm Y '^'° o v '^ p- `on.cowr n o rzJ m J O s «emu, w E E m m o �wsp-a E U p o._u Y L o o w vi L«\ m �g a au?'° u QO in � 3= o E N`.° Y E�iry s O o 0 u^i15 vaoo m o « a sv �v V O o a y O o� -6 zvvZ ou a« wvv Eo� ti3N❑ou `mm^ w T `v &� v« cE3o_ vols 'm Qnb m'omoE n N n u crv_ o w'oo�.+�a v �m o v smo3 c v 3 ON ti n E c o v N 1 E Z, 3 n` .Ni i n' m n w .Ni i 9 u w .Mi i. 3 w w t .Ni d \i o 0 t n E 0 0 v E v° v 0 0 00 m �' o a v E N y ti ti n N a amNa aF�An -aE 0 0 oa�Vl \O.mi1 mo O s"uE Nn «o 1 mrYanr < 3 ao a m v m o.. w �._ m ti m mm m r c v o = o'ti o n a-oo m m Nv-o m. r a o._ n Q� c ¢ F h n n H o o o a 0 Q c +� a LL 03a m na Q c N« m m - a 0 w -�n L V ry Y M c 0 ❑ O ❑ ❑ ❑ d u ❑ � n�i ❑❑ emr 7 > O 7 ❑ O n -1 m m �> I- ? O> ❑ ❑ ❑ W O Y N O m o a r y m m y � tim ry m m m .i m ti m a m ti m m m ti m m ti m W C N Nm ti w O O uNi r p^j N N p Q n Q 2 Q 2 p Q d Q d N T N h H m m O m IYI T N fYl ry M 3 ❑ w _ ❑ w ❑ ❑ z z w w o z ❑ w ❑ w 0 0 0 0 0 0 00 0 0 0 g 0 0 m � � � m N m N m NN m N N N N N N N m N m N R o S o 0 0 0 0 o m O o 0 op 0 ma Om O m N N O o p O 0 p y N 12450 12500 r-... 15 ----------- ----------- L 12600 ee' -7 - END 4-26A CBL 9-1-18 12400 12450 12500 r-... 15 ----------- ----------- L 12600 ee' f " 12800 t' END 4-26A CBL 9-1-18 i 4 � � I 12750 i, � I - L I sr i - I 1 Iti t S , r t IS 12850 i I i f " 12800 ? tJ r 4 � � I i, � I - L I sr � 1 Iti t S , r t IS 12850 i I i �'i' fi n t I _ 12900 T ? tJ r 4 � � I � I - L I sr � 1 12950 r t IS i T I - L I � 1 r t i �'i' fi i`If'i' v _I s 331 • ' j � i F.I 7 T I i �'i' fi i`If'i' til 331 • ' j � i F.I 7 4 I1 i �s: .• •,• ll t t'I� 13050) D (� E 26A CBL 1 A00 AWN _ r 3 ----1----- kk 115 i#�f - i r I _ t- pp •Q01111 X ? ` j f r E� I! E+ 1 0 Log Depth(ft) 13000 - 13050 - 13100 - 13150 - 13200 - 13250 - 13300 - 13350 - 13400 - 13450 - 4-26A O 9/10/2018 74,203 78,673 720,009 END 4-26A Open Hole Log scQz 100-�p 133,- i332S' Ko Log Depth(ft; - 13000 - 13050 13100 -13150 - 13200 - 13250 - 13300 -13350 - 13400 1 - 13450 1 13500 - 13550 - 13600 - 13650 - 13700 - 13750 - 13800 - 13850 - 13900 - EN-LCU 13950- EN K28 14000 - H5=1 - 13500 - 13550 - 13600 - 13650 - 13700 - 13750 - 13800 13850 - 13900 -13950 - 14000 N MAX III Schwartz, Guy L (CED) From: Wyatt Rivard <wrivard@hilcorp.com> Sent: Tuesday, December 10, 2019 10:38 AM To: Schwartz, Guy L (CED) Subject: END 4-26A (PTD # 218081) GINJ Conversion Sundry Procedure Update Attachments: END 4-26A 2019 GINJ Conversion Revised 12-9-19.docx Follow Up Flag: Follow up Flag Status: Flagged Hello Guy, Please see attached update to the sundry procedure for the gas injection conversion of Endicott well 4-26A (PTD#218081). Revisions to the procedure begin at step 16 and including a temporary two week water injection period followed by Eline Water Flow and Temperature Surveys. Our target water surface injection pressure is —2000 psi. With a max expected gas injection surface pressure of 4800 psi, our equivalent water injection surface pressure is 1380 psi. The extra -600 psi surface pressure that we are targeting is to account for any additional friction effects under water injection and is in line with our other SDI water injector surface pressures. Please let me know if you have any additional questions or would like this submitted in an alternate format. Thank You, Wyatt Rivard! Well Integrity Engineer IHilcorp Alaska, LLC 0: (907) 777-8547 I C: (509)670-8001 1 wrivardPhilcorp corn 3800 Centerpoint Drive, Suite 1400 1 Anchorage, AK 99503 The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. 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. Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 !riles. kl,,An. LJ.0 Fax: 907 777-8510 E-mail: doudean@hilcorp.com DATE 08/06/2019 To: Alaska Oil & Gas Conservation Commission Abby Bell Natural Resource Technician II 333 W 7th Ave Suite 100 Anchorage, AK 99501 CBL ANALYSIS FIELD -DATA 7/18/2019 2:01 PM 7!1820191:59 PM Please include current contact information if different from above. File folder File folder 2 1808 1 3 106 3 RECEIVED AUG 0 6 2019 AOGCC Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS RECEIVE® MAR 2 9 2019 1. Operations Abandon Plug Perforations Performed: ❑ C LJ Fracture Stimulatu Pull Tubing {yglDnryl8bwn LJ ❑ Suspend Perforate Other Stimulat Alter Casing ❑ Cha6n Y+JP a roVgram ❑ P Plug for Redrill ❑ ;rforate New Pool ❑ Repair We❑ Re-enter Susp Well ❑ Other: Bradenhead Weld 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska LLC Development ❑� Stratigraphic❑ Exploratory ❑ Service ❑ 218-081 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, 6. API Number: AK 99503 50-029-21835-01-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL047502 & ADL 047503 END SDI 4-26A 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Duck Island Unit / Endicott Pool 11. Present Well Condition Summary: Total Depth measured 14,005 feet Plugs measured N/A feet true vertical 9,893 feet Junk measured N/A feet Effective Depth measured 13,999 feet Packer measured 5,255 & 13,283 feet true vertical 9,887 feet true vertical 5,253 & 9,529 feet Casing Length Size MD TVD Burst Collapse Conductor 161' 30" 161' 161' N/A N/A Surface 2,502' 13-3/8" 2,502' 2,502' 5,020psi 2,260psi Intermediate 5,417' 9-5/8" 5,417' 5,413' 6,870psi 4,760psi Production Liner 8,745' 7" 14,000' 9,891' 7,240psi 5,410psi Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth) 4.5" 12.6# / 13CR-80 / JFE Bear 13,605' 9,690' 9-5/8" x 7" BKR HRDE ZXHD 1,485' MD Packers and SSSV (type, measured and true vertical depth) 7" x 4-1/2" TRMAXX SSSV See Above 1,485' TVD 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mof Water -Bbl Casing Pressure I Tubing Pressure Prior to well operation: 153 682 GL 1,815 1,850 1 505 Subsequent to operation:1 155 723 GL 1,750 1,700 1610 14. Attachments (required per 20 AAC 25.070, 25.071, a 25.283) 15. Well Class after work: Daily Report of Well Operations R1 Exploratory❑ Development ❑� Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil Q Gas ❑ WDSPL ❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 319-024 vv� Authorized Name: Chad Helgeson Contact Name: Wyatt Rivard Authorized Title: Operations Manager Contact Email: wriyardahllcorp.com Authorized Signature: Date: 3/20/2019 Contact Phone: 777-8547 lIBM H&-1 APR 0 12019 Form 10-404 Revised 412017 X /01 /07 Submit Original Only Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number StartDate End Date END 4-26A Slickline/ Weld 50-029-21835-01-00 218-081 3/15/2019 3/19/2019 Daily Operations. 3/13/2019- Wednesday No activity to report. 3/14/2019 - Thursday No activity to report. 3/15/2019 - Friday Pressure test the 9 5/8 void and the tbg hgr void. Noted 0 psi on IA; 0 psi on OA and 0 psi on tbg. MU pump to 9 5/8 void. Could not exceed 500 psi. Hook up plastic injection gun onto upper seal and energize seal to 3,000 psi for 5 min -PASS. Hook up hyd pump to Tbg Hgr test port and PT to 5,000 psi for 10 min --PASS. 3/16/2019 -Saturday RU welder and leads. Establish N2 purge across the OA. Complete circumferential seal weld of starting head. Begin 24 hour colling period for NDE inspections. RDMO welding equipment and crew. 3/17/2019 -Sunday Welds cooled for NDE inspection. Perform shear wave inspection and mag test. Welds passed both tests. Performed passing MIT -OA to 1200#. Initial pressures 0/1/0, Starting test pressures 0/1/1,218, 15 min. pressures 0/1/1,164, 30 min. test pressures 0/1/1,138. Pumped a total of 3 bbls of diesel for test, bled OA pressure to 28# after test was complete. 3/18/2019 - Monday No activity to report. 3/19/2019 -Tuesday WELL S/I UPON ARRIVAL, PTPCE: 300L -3,1001-I**. PULL P -PRONG @ 13,256' SLM, RECOVER ALL PACKING. PULL PXN PLUG BODY @ 13,264' SLM, 13,308' MD, PULLED HEAVY TO SURFACE. SEE FLUID @ 3500' SLM. **PAD OP BRINGING WELL ONLINE UPON DEPARTURE** **JOB COMPLETE** DATA SUBMITTAL COMPLIANCE REPORT 1118/2019 Permit to Drill 2180810 Well Name/No. DUCK IS UNIT SDI 4-26A Operator HILCORP ALASKA LLC API No. 50-029-21835.01.00 MD 14005 TVD 9893 Completion Date 9/10/2018 Completion Status 1-01L REQUIRED INFORMATION / / Mud Log No 1/ Samples No t/ DATA INFORMATION List of Logs Obtained: ROP -DGR -ADR -ABG 275" MD/TVD, CAST -CBL Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Type Med/Frmt Number Name Scale Media No ED C 29677 Digital Data ED C 29677 Digital Data ED C 29677 Digital Data ED C 29677 Digital Data ED C 29677 Digital Data ED C 29677 Digital Data ED C 29677 Digital Data ED C 29677 Digital Data ED C 29677 Digital Data ED C 29677 Digital Data ED C 29677 Digital Data ED C 29677 Digital Data ED C 29677 Digital Data ED C 29677 Digital Data Log C 29677 Log Header Scans ED C 29763 Digital Data ED C 29763 Digital Data Interval OH/ Start Stop CH_ 5400 14006 0 0 Current Status 1 -OIL UIC No Directional Survey Yes V (from Master Well Data/Logs) Received Comments 9/7/2018 Electronic Data Set, Filename: SDI 4-26A DGR ABG EWR.Ias 9/7/2018 Electronic File: SDI 4-26A LWD FINAL MD.cgm 9/7/2018 Electronic File: SDI 4-26A LWD FINAL TVD.cgm 9/7/2018 Electronic File: 4-26A Definitive Survey Report.pdf 9/7/2018 Electronic File: 4.26A_0efinitive Survey.bd 9/7/2018 Electronic File: 4-26A GIS.TXT 9/7/2018 Electronic File: SDI 4-26A LWD FINAL MD.emf 9/7/2018 Electronic File: SDI 4-26A LWD FINAL TVD.emf 9/7/2018 Electronic File: SDI 4-26A LWD FINAL MD.pdf 9/7/2018 Electronic File: SDI 4-26A LWD FINAL TVD.pdf 9/7/2018 Electronic File: SDI 4-26A LWD FINAL MO.tif 9/7/2018 Electronic File: SDI 4-26A LWD FINAL TVD.tif 9/7/2018 Electronic File: EMFVieW3_1.zip 9/7/2018 Electronic File: Readme.txt 2180810 DUCK IS UNIT SDI 4-26A LOG HEADERS 5062 13881 10/5/2018 Electronic Data Set, Filename: END 4- 26A_ACE_02SEP18_ProcessedLog.las 10/5/2018 Electronic File: END 4- 26A_ACE_02SE P18_ProcessedLog.dlis AOGCC Pagel of2 Friday, January 18, 2019 DATA SUBMITTAL COMPLIANCE REPORT 1/18/2019 Permit to Drill 2180810 Well Name/No. DUCK IS UNIT SDI 4-26A Operator HILCORP ALASKA LLC API No. 50-029-21835.01-00 MD 14005 TVD 9893 Completion Date 9/10/2018 Completion Status 1-0I1 Current Status 1-0I1 UIC No ED C 29763 Digital Data 10/5/2018 Electronic File: END 4- 26A_AC E_02S E P 18_P rocessed Log. pdf ED C 29763 Digital Data 10/5/2018 Electronic File: END_4- 26A_ACE_02SEP 18_ProcessedLog.tif ED C 29763 Digital Data 10/5/2018 Electronic File: END _4- 26A_ACE_02SEP 18_Segm entedQC.pdf ED C 29763 Digital Data 10/5/2018 Electronic File: END_4- 26A_ACE_02SEP18_SegmentedQC.tif Well Cores/Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments INFORMATION RECEIVED Completion Report O p Production Test Informatiofl Yl/ NA Geologic Markers/Tops 0 COMPLIANCE HISTORY Completion Date: 9/10/2018 Release Date: 7/23/2018 Description Comments: Directional / Inclination Data V Mechanical Integrity Test Information Yom/ NA Daily Operations Summary 1Y I Date Comments Compliance Reviewed By: AOGCC Page 2 of 2 Mud Logs, Image Files, Digital Data Y / J9 Composite Logs, Image, Data Files Cuttings Samples Date: Core Chips Y / Core Photographs Y/./� Laboratory Analyses Y/wH Friday, January 18, 2019 THE STATE 01ALASKA GOVERNOR MIKE DUNLEAVY Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Duck Island Field, Endicott Oil Pool, END SDI 4-26A Permit to Drill Number: 218-081 Sundry Number: 319-024 Dear Mr. Helgeson: r Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.cogcc.olaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. DATED this C dlay of January, 2019. RBDMS4N° NJAN J 12019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 90 AAC 95 9Rn RIEECFEIVED JAN 2 2 23 9 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: Bradenhead Weld ❑� 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development Q Stratigraphic Service El 218-081 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-029-21835-01-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 462.007 Will planned perforations require a spacing exception? Yes ❑ No 0 END SDI 4-26A 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL047502 & ADL 047503 Duck Island Unit! Endicott Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 14,005' 9,893' 13,999' 9,887' 3,100 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 161' 30" 161' 161' N/A N/A Surface 2,502' 13-3/8" 2,502' 2,502' 5,020psi 2,260psi Intermediate 5,417' 9-5/8" 5,417' 5,413' 6,870psi 4,760psi Production Liner 8,745' 7" 14000- 9,891' 7,240psi 5,410psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 4.5" 12.6# / 13CR-80 / JFE Bear 13,605 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 9-5/8"x 7" BKR HRDE ZXHD & 7" x 4-1/2" and TRMAXX SSSV 5,255(MD)/ 5,253(TVD) & 13,283(MD)/ 9,529(TVD) and 1,485(MD)/ 1,485(TVD) 12. Attachments: Proposal Summary Q Wellbore schematic 21 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Strati ra hic g p ❑ Development ❑✓ Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 2/5/2019 OIL R( 41N WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned El17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. n Authorized Name: Chad Helgeson Contact Name: Watt Rivard tom/ L Authorized Title: Operations Manager Contact Email: wrivard hilcor .Com Contact Phone: 777-8547 Authorized Signature: Date: 121/2019 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: G - O ) t "//t v Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes ❑ No ❑ A Spacing Exception Required? Yes rl, No Subsequent Form Required: (� V APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date:/ 2, / Zy 11 'fX X0\/A RBDMSv.rm 10-403 Revised 4/2017 Approved applicationOR�ALate of approval. �' 1l JAN 3 1 Y0*bmit Form and Attachments in Duplicate ���1rIf �.B.ot-z3-19 U nacos Alaska, LU Bradenhead Weld Well: END 4-26A PTD: 218081 API: 50-029-21835-01-00 Well Name: END 4-26A API Number: 50-029-21835-01-00 Current Status: Shut in — BH Leak Rig: SL Estimated Start Date: February 5, 2019 Estimated Duration: 3 day Reg.Approval Req'std? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts 777-8398 Permit to Drill Number: 218-081 First Call Engineer: Wyatt Rivard (907) 777-8547 (0) (509) 670-8001(M) Second Call Engineer: Taylor Wellman (907) 777-8449 (0) (907) 947-9533 (M) AFE Number: WeIIEZ Entry Required? Yes Current Bottom Hole Pressure: 4,100 psi @ 10,000' TVD (K213 BHP taken on 6/30/18) Maximum Expected BHP: 4,100 psi @ 10,000' TVD (K2B BHP taken on 6/30/18) Max Predicted Surface Pressure: 3,100 psi (Max Expected BHP— (.1 psi/ft * 10,000 ft)) Max Deviation: 63.7 deg at 7,401' and Minimum ID: 3.725" XN Nipple @ 13,308' MD Brief Well Summary: END4-26A was SI on 1/20/19 following a confirmed hydrocarbon leak at the casing starting head/bradenhead with WHPs of T/I/O = 482/1,850/600. The leak was observed at the connection of the 13-3/8" N-80 Surface Casing to the slip on weld 8630 McEvoy Starting Head. The OA was promptly bled down to —0 psi with the leak stopping at roughly —80 psi. A TTP will need to be set to secure the well prior to welding. Objective: Perform a weld repair at the 13-3/8" Surface Casing to Starting Head connection to restore OA integrity. Procedure: Pre -Sundry Work Slickline —Well Prep 1. MIRU SL unit and Pressure test PCE to 300 psi low and at least 3,100 psi high. 2. RIH and drift for 4-1/2" XN plug to bottom. 3. Set 4-1/2" XN plug at 13,308', POOH a. Bleed Tubing to 0 psi and monitor 4. RD Slickline Operations- Well Prep 5. Conduct tubing hanger void test to 5,000 psi. 6. Conduct casing hanger void test to 3,000 psi. 7. Conduct UT inspection of SC at starting head to confirm no increase in casing damage. a. Previous UT in 2009 showed 19.23% max loss over a 16" by 4" area 8. Bleed T/IA/OA to 0 psi. Watch for at least 24 hrs prior to welding. 9. Install companion valve on the OA for N2 Puree. ✓ 10. Establish double block and bleed on the AL line. 11. Establish double block and bleed on the flowline. 12. Remove wellhouse floor. Vac out cellar and remove gravel around wellhead to a depth of 2-3 feet. Setup safety equipment for access to wellhouse with floor removed. 13. Prep and clean well cellar. Ensure hydrocarbons are not present on the tree and/or around the wellhead. Thoroughly clean the wellhead and weld area. Install fire blankets in cellar. ( head Weld Well: S Well: END 4-26A PTD: 218081 Rdmrp M.skp Lb API: 50-029-21835-01-00 14. Stage two six packs of N2 at the well along with N2 manifold. Sundry Work (Approval required to proceed) Operations - SH Weld 15. Sniff cellar and adjacent area with muti-gas meter for LEL, CO and 02• Ensure confined space, egress and ventilation is adequate for operations. Establish continuous LEL, CO and 02 monitoring. 16. Inject and bleed N2 into the OA two or three times as needed to displace trapped gas until returns during the bleed are <5% 02 and <50% LEL. 17. Begin nitrogen purge across the OA. Returns at the OA bleed should be <5% 02 and <50% LEL before proceeding. a. Utilize a choke downstream of purge (bleed side) to provide a small amount of back pressure (5- 10 psi). This will ensure a small positive pressure differential across wellhead seals to the IA. 18. Establish fire watch and stage fire extinguishers. 19. Verify both AL line and flowline double blocked and bled to 0 psi and bleed hose is not frozen/plugged. 20. Prep the area to be welded with torch and wire brushes. Ensure weld area is clean and oil free for weld integrity. 21. Certified welder to repair the threaded 13-3/8" Surface Casing (N-80) by Starting Head (8630) connection per welding procedure. b. Constant monitoring of annulus pressures and OA N2 purge required throughout welding procedure. Discontinue welding if there is any indication of annulus pressurization or if OA bleed is >5% 02 or >50% LEL. c. Monitor wellhead temperature across upper packoffs, allow wellhead to cool if temperature could cause damage to elastomers (>250 degF) 22. Wrap with blankets for cool -down. 23. Discontinue OA NZ purge. 24. Rig down equipment. 25. After weld repair has cooled to 60-100degF. Perform QC inspection. 26. MIT -OA to 1,200psi. Slickline— Well RTP 27. MIRU SL unit and Pressure test PCE to 300psi low and at least 3,100psi high. 28. RIH and pull 4-1/2" XN plug at 13,308', POOH 29. RD Slickline ff Nileora Alaska. 1.1.1: KB Elev.: 40.91/ GL Elew 13.9' TD=14,005' (NAD)/TD=9,893'(IVD) PBTD=±13,999' (MD) / PBTD=9,887 TM) SCHEMATIC Duck Island Unit Well: END 4-26A Last Completed: 9/4/2018 PTD: 218-081 SAFETY NOTES TREE & WELLHEAD H25 Readings Average 230 -260 PPM on A/L & Gas In'ectors Tree 4.1/8" CIW Well Requiresa 555V Wellhead MCEVOY OPEN HOLE / CEMENT DETAIL 13-3/8" 4,557 cu/ft Permafrost In 17.5" Hole 9-5/8" 575 cu/ft Class'G' in a 12-1/4" Hole 7" 1 115 cu/ft Class "G" In 8-1/2" Hole CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 30" Conductor N/A/N/A/N/A N/A Surface 161' N/A 13-3/8" Surface 68/ N-80/ Btrs 12.415 Surface 2,502' 0.150 9-5/8" Intermediate 47/NT80S/NSCC 8.681 Surface 5,411' (KOP) 0.0732 7" Prod Liner 26/L-80/TXP 6.276 5,255' 14,000' 0.0383 TUBING DETAIL 4-1/2" Tubing 12.6/13Cr/JFE Bear 1 3.958 1 Surface 13,605' 0.0152 WELL INCLINATION DETAIL Max Hole An Angle at Top Perf= 59 Deg. @ 13,962' JEWELRY DETAIL No Depth Item 1 1,485' 4.5"SLBTRMAXXSSSVw/X-Nipple-ID=3.813" Date GLM DETAIL: MMG SPM -1-1/2" w/ RK Latch 2 3,859' STA 6 Dev=, VLV= Dome, Port= 16, TVD=3,859', Date=9/9/18 3 5,217' STAS: Dev=, VLV= Dome, Port- 16,TVD=5,216', Date --9/9/18 4 5,255' 9-5/8" x 7" BKR HRDE ZXHD Packer 3-1/8" GLM DETAIL: Special Clearance SPM -1" w/ RK Latch 5 6,888' STA4: Dev=, VLV=50, Port= 24, TVD=6,504', Date=9/9/18 6 8,793' STA 3:Der-,VLV= DMY, Port -0, TVD=7,369', Date=9/4/18 7 10,700' STA 2: De-VLV= DMY, Port -0, TVD=8,232', Date=9/4/18 8 12,606' STA 1: Dev=, VLV= DMY, Port= 0, TVD=9,190', Date=9/4/18 9 13,182' 4-1/2"X Nipple - ID= 3.813" 10 13,283' 7"x4-1/2"Packer - ID- 3.863" 12 13,308' 4-1/2"OTIS XN Nipple - ID= 3.725" 13 13,603' 4-1/2"WLEG-ID- 3.958'- Bon @13,605' PERFORATION DETAIL ENDSands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Size HRZShale 13,320' 13,325' 9,548' 9,550' 5' 8/29/18 Sqz 3-1/8" K2B 13,953' 13,973' 9,866' 9,877' 20' 9/10/18 Open 3-1/8" GENERALWELLINFO API: 50-029-21835-01-00 Initial Completion -8/6/1988 RWO - 2/21/1995 Sand Back & Cmt Cap - 3/31/99 Sidetrack Completion -8/25/18 Revised By: TDF 1/21/2019 to w m C 0 0 O p N O W ��c Q HF- .`CyK7 NOD W OC x W y ' ^ ix `.` _ M N CD LO LO Lo 0 Z^=LL x x.T Cl) W U Z p co y N O U°' CO T MCY) ,a1 V/ 1� T CD m Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Wednesday, January 23, 2019 8:41 AM To: 'Wyatt Rivard' Cc: Wallace, Chris D (DOA) Subject: RE: 4-26A (PTD # 2180810) Starting Head Leak - Return to Production Wyatt, You have approval to produce well as proposed below (for up to 2 months) which include the following mitigations. 1. Minimum of twice daily well house inspections 2. Install High OA shutdown trip at —50 psi 3. Install LEL detector in wellhouse mounted directly to the tree above the well cellar. LEL alarm set points to be set at 40%. 4. Include the well in monthly TIO monitoring Provide a sundry to repair the wellhead as soon as possible. There are two tested barriers in the well (tubing and production casing) with recent passing MIT's. Regards, Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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(sl. 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 if, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ) or (Guv.schwartz@alaska.gov). From: Wyatt Rivard <wrivard@hilcorp.com> Sent: Wednesday, January 23, 2019 8:11 AM To: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Subject: RE: 4-26A (PTD # 2180810) Starting Head Leak - Return to Production Wyatt Rivard I Well Integrity Engineer IHilcorp Alaska, LLC 01 ( u- 1 7-8547 I C: (509)670-80011 wrivard(@hilcorp.com 3800 Centerpoint Drive, Suite 1400 1 Anchorage, AK 99503 From: Wyatt Rivard Sent: Tuesday, January 22, 2019 11:07 AM To:'Schwartz, Guy L (DOA' <guy.schwa rtz@aIaska.gov> Subject: 4-26A (PTD # 2180810) Starting Head Leak - Return to Production Hello Guy, As discussed, Endicott gas lifted producer 4-26A (PTD # 2180810) was observed Saturday 1/19 with a small starting head leak while producing with T/I/O = 482/1850/600. The leak path is through the slip on welded surface casing to starting head connection. Once discovered, the OA was bled to -0 psi where it has held flat. The leak sopped at -80 psi. The well was shut-in on 1/19. 4-26A was sidetracked over last summer/fall and is currently one of the field's best producers at - 300 BOPD with the field's lowest GOR & a low WC. The well had a passing MIT -IA to 3000 psi as part of the workover on 9/6/18. Since shut- in, the IA was also bled down and is holding flat at - 50 psi with the tubing stacked out at 1100 psi. There are no indications of additional integrity issues (TIO plot attached) and the OA pressure can be managed to prevent additional thermal induced starting head leaks until the connection can be repaired. Hilcorp would like to leave the well on production for up to two months to allow for Sundry approval and starting head weld repair with the following mitigations in place: - Minimum of twice daily well house inspections - Install High OA shutdown trip at -50 psi - Install LEL detector in wellhouse mounted directly to the tree above the well cellar. LEL alarm set points to be set at 40%. - Include the well in monthly TIO monitoring Please let me know if you have any additional questions. Thank You, Wyatt Rivard I Well Integrity Engineer IHilcorp Alaska, LLC u: (1w ; 7-8547 1 C: (509)670-8001 I wrivard(@hilcorp.com 3800 Centerpoint Drive, Suite 1400 1 Anchorage, AK 99503 END 4-26A I 7-6-18 CURRENT CONFIGURATION 13 3/8 x 9 518 x 4 Yz tubulars 13 3/8" 3K x 13 3/8" 5K McEvoy Split Speeedhead, 5 seal extended neck. 3 1/8" 5K outs. 0A ?Id Repair r -a • t� fy _ � f V t s-tif END 4-26A I 7-6-18 CURRENT CONFIGURATION 13 3/8 x 9 518 x 4 Yz tubulars 13 3/8" 3K x 13 3/8" 5K McEvoy Split Speeedhead, 5 seal extended neck. 3 1/8" 5K outs. 0A ?Id Repair 2,000 1,800 1,600 1,400 1,200 v L N 1,000 N N L d 800 600 400 200 0 SDI 4-26A TIO Plot 00 00 0� oo ao m eo 00 00 m a o0 0o w o0 00 00 00 0o a o0 00 00 00 0o co 00 00 0o m w w oo ao m m m m m m m m m m m 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ m \ m \ \ m \ \ \ \ m \ m \ \ m \ \ \ \ \ \ \ \ \ \ \ \ V lD W O 0 M 0 0 m ti M L!1 I� in ti m V1 I� m ti M� n m N M V1 I� m .-1 M V1 1� m .-1 N c{ l0 0 O N d' l0 a0 O N N N N m 0 0 0 0 0 N ti ti �-I c-1 N N N N N O O O O O ti N a-1 .-1 H N N N N N M 0 0 0 0 \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ O O O O� .-i cy .� ti N ti ti ti ti c -i c -i .-� ti ti ti ti ti ti ti ti ti ti ti ti ti c -I N .-� ti ti ti N ti c -i 0 0 0 0 0 0 0 0 0 0 0 —Tubing —IA —OA Gas Prod —Oil Prod —Water Prod HEGEIVED STATE OF ALASKA I UL 1 U 5 2018 ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a. Well Status: oil ❑✓ Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended[-] 20AAC 25.105 20MC 25.110 GINJ ❑ WINJ ❑ WAGE] WDSPL ❑ No. of Completions: _ 1 1b. Wels Development ✓ • xploratory ❑ Service ❑ Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Date Comp., Susp., or Aband.: 9/10/2018 14. Permit to Drill Number/ Sundry: • 218-081 / 318-362 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: August 2018 u 15. API Number: , 50-029-21835-01-00 4a. Location of Well (Governmental Section): Surface: 2592' FSL, 736' FEL, Sec 8, T11 N, R17E, UM, AK Top of Productive Interval: 901' FNL, 203' FWL, Sec 4, T1 IN, R17E, UM, AK Total Depth: 850' FNL, 209' FWL, Sec 4, T11 N, R17E, UM, AK 8. Date TO Reached: August 19, 2018 16. Well Name and Number: END SDI 4-26A 9. Ref Elevations: KB: 40.4' - GL: 13.9' BF 13.9' 17. Field / Pool(s): Duck Island Unit Endicott Pool 10. Plug Back Depth MD/TVD: 13,999' MD / 9,887' TVD 18. Property Designation: • ADL047502 / ADL047503 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 270300 y- 5970808 , Zone- 3 TPI: x- 271435 y- 5977843 Zone- 3 Total Depth: x- 271442 y- 5977894 Zone- 3 11. Total Depth MD/TVD: • 14,005' MD / 9,893' TVD • 19. DNR Approval Number: N/A 12. SSSV Depth MDfFVD: 1,485' MD / 1,485' TVD 20. Thickness of Permafrost MD/TVD: • 1,466' MD / 1,466' TVD - 5. Directional or Inclination Survey: Yes ✓ (attached) No Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: N/A (ft MSL) 21. Re-drill/Lateral Top Window MD/TVD: - 5,411' MD / 5,406' TVD - 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, 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 ROP -DGR -ADR -ABG 2"/5" MDfFVD, CASTM-CBL 23. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING FT GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 7" 26# L-80 5,255' 14,000' 5,253' 9,888' 8-1/2" 100 sx Class G 15.8 ppg 24. Open to production or injection? • Yes ❑✓ No ❑ If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Pertd):4-1/2" 13,953'- 13,973' MD / 9,8661- 9,877' TVD 3.125" x 20' Gun, 6 SPF, Shot on 9/10/18 COMPLETION DATE 41101115 VER• FIED 1- (Z- 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 13,605' 13,283' MD / 9,530' TVD 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes No ✓ Per 20 AAC 25.283 (1)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: 9/11/2018 Method of Operation (Flowing, gas lift, etc.): Gas Lift Date of Test: 9/23/2018 Hours Tested: 24 Production for Test Period Oil -Bbl: 415.3 Gas -MCF: 1100 Water -Bbl: 1437.2 Choke Size: N/A Gas -Oil Ratio: 2648 Flow Tubing Press. 789 Casing Press: 1800 Calculated 24 -Hour Rate -.0o. Oil -Bbl: 415.3 Gas -MCF: 1100 Water -Bbl: 1437.2 Oil Gravity - API (corr): 23.5 Form 10-407 Revised 5/2017/� P, i 8 CONTINUE P il�iuniS � -f , j MU Submit ORIGINIAL on 28. CORE DATA Conventional Core(s): Yes ❑ No ❑� - Sidewall Cores: Yes ❑ No ❑� If Yes, list formations and intervals cored (MD/TVD, From7ro), 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. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑� If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base 1466' 1466' Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval 13953' K2B 9,866' information, including reports, per 20 AAC 25.071. K2B (Top Kekiktuk) 13,951' 9,865' Formation at total depth: K2B 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Defintive Directional Surveys, Csg and Cmt Report. 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. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Monty Myers Contact Name: Cody Dinger Authorized Title: Drilling Manager Contact Email: CdID 2f(alhilcor .com Authorized Contact Phone: 777-8389 Signature: — - Date: f A 16 INSTRUCTIONS General: This form and the required attachments pr ids 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. Item 1 a: 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. Item 1b: Well Class - Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 41b: TPI (Top of Producing Interval). Item 9: 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. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 19: 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. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: 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). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: 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. Item 30: 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. Item 31: 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. Form 10-407 Revised 5/2017 Submit ORIGINAL Only 0 eom Alaska. LLC KB Elev.: 40.9'/GL Elev.: 13.5 TD =14,005' (MD) /TD = 9,893'M) PB1D=±13,995 (MD) / PBTD= 9,887 MO) Schematic Duck Island Unit Well: END 4-26A Last Completed: 9/4/2018 PTD: 218-081 SAFETY NOTES TREE & WELLHEAD H25 Readings Average 230-260 PPM on A/L &Gas Injectors Tree 1 4-1/8" CIW Well Requires a SSSV Wellhead I MCEVOY OPEN HOLE / CEMENT DETAIL 13-3/8" 4,557 cu/ft Permafrost in 17.5" Hole 9-5/8" 575 cu/ft Class'G' in a 12-1/4" Hole 7" 115 cu/ft Class "G" in 8-1/2" Hole CASING DETAIL Size Type Wt/Grade/Conn Drift I Top Btm BPF 30" Conductor N/A/N/A/N/A N/A Surface 161' N/A 13-3/8" Surface 68/ N-80/ Btrs 12.415 Surface 2,502' 0.150 9-5/8" Intermediate 47 / NT80S / NSCC 8.681 Surface 5,411' (KOP) 0.0732 7" Prod Liner 26/L-80/TXP 6.276 5,255' 14,000' 0.0383 TUBING DETAIL - 4-1/2" Tubing 12.6/13Cr/JFE Bear 1 3.958 1 Surface 1 13,605' 1 0.0152 WELL INCLINATION DETAIL Max Hole Angle = 63.7 deg. @9,549' Angle at Top Perf=59 Deg. @ 13,962' JEWELRY DETAIL No Depth Item 1 1,485' 4.5" SLB TRMAXX SSSV w/ X -Nipple - ID= 3.813" 2 5,255' 9-5/8"x7" BKR HRDE 2XHD Packer HRZShale GLM DETAIL: Mana SPM -1-1/2" w/ RK Latch 4 3,859' STA 6 Dev=, VLV= Dome, Port= 16, TVD=3,859', Date=9/9/18 5 5,217' STA 5: Dev-, VLV= Dome, Port= 16, TVD= 5,216', Date=9/9/18 3-1/8" GLM DETAIL: Special Clearance SPM -1" w/ RK Latch 5 6,888' STA 4: Dev=, VLV= SO, Port= 24, TVD= 6,504', Date=9/9/18 6 8,793' STA 3: Dev=, VLV= DMY, Port= 0, TVD= 7,369', Date=9/4/18 7 10,700' STA 2: Dev=, VLV= DMY, Port= 0, TVD=8,232', Date=9/4/18 8 12,606' STA 1: Dev=, VLV= DMV, Port= 0, TVD= 9,190', Date=9/4/18 9 13,182' 4-1/2"X Nipple - ID= 3.813" 10 13,283' 7" x 4-1/2" Packer - I D= 3.863" 12 13,308' 4-1/2"OTIS XN Nipple -ID=3.725" 13 13,603' 4-1/2"WLEG-ID=3.958"-Btm@13,605' Proposed PERFORATION DETAIL END Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Size HRZShale 13,320' 13,325' 9,548' 9,550' 5' 1 8/29/18'" Sqz 3-1/8" K21313,953' 13,973' 9,866' 9,877' 20' 1 9/10/18 Open 3-1/8" GENERAL WELL INFO API: 50-029-21835-01-00 Initial Completion -8/6/1988 RW O - 2/21/1995 Sand Back & Cmt Cap - 3/31/99 Sidetrack Completion - 8/25/18 Revised By: CJD 10/2/2018 nHilcorp Energy Company Composite Report Well Name: END 4-26A Field: Endicott County/State: , Alaska r (LAT/LONG): evation (RKB): API #: Spud Date: 8/5/2018 Job Name: 1811484D END 4-26A Drilling Contractor Innovation APE #: APE $: Activity Date. _... Ops: Summary•k 814!2018 Cont Pick up, drift (3.13") singles, Washing and reaming down f/ 5271'- 5282' with 5" drill pipe. Tag hard CMT @ 5282'. PUW/SOW 150K, 500 gpm/790 psi, 40 rpms/1900 ft-Ibs.;Drill hard CMT from 5282'to Planned Whipstock setting depth of 5436'. w/515 gpm/780 psi, 45 rpm/ 2.3K Tq. PUW 155K, SOW 155K, Rot 152K. Pump 10 bbls LS ND Mud Sweeps every 50'.;CBU w/ Sea Water @ 580 gpm/990 psi.;Displace well from Sea Water to New 9.5 ppg LSND Mud system. Circulate with 9.5 ppg in/out.;UD 1 jt OF. R/U to test Casing. Test Casing to 3100 psi on chart for 30 min. Test good. R/D test equipmrnt.Blow down Choke and Kill.;Pump Slug and POOH w/ Clean out Assy standing back 5" DP from 5426'to surface. LID Clean out BHA.;Clear rig floor. Stage BHA #2 Whipstock assembly. MIU BHA #2: Window mill, lower mill, upper mill, HWDP. Scribe line. M/U bottom set anchor and whipstock slide with 35K shear bolt. Continue to M/U BHA, DM collar, TM collar. Measure RFO MWD to whipstock = 1.4/6.7 = 75.22. M/U Float sub and;UBHO. Orient UBHO. RIH with 9 stands of HWDP. Shallow pulse test MWO.;Continue to RIH with BHA#2 Whipstock assembly with drillpipe from derrick;1 min/stand from 661'to 5394'. PUW 153K, SOW 155K.;Fill pipe and establish circulation at 450 gpm/935 psi. Orientate whipstock to 32L. Slack off ensuring orientation maintains 32L. Tag up at 5437'. Slack off to 15K (140K) observing anchor shear at IOK down. Pick up 1 O over. Set down 15K and overpull 15K. Slack off and shear off whipstock;wfth 32K down. Pickup 5'. Slack off and tag top of whipstock at 5411'.;Obtain parameters, SPR's. 350 gpm/590 psi. Slack off and tag top of whipstock at 5411'. Pickup and establish rotary at 60 rpms/ 2200 ft -lbs free torque. PUW 152K, SOW 155K, ROT 150K. Mill window from 541 Vie 5414'. Metal collect thus far= 5lbs.;Daily Fluid Hauled to MP G&I: 523 bbls Total Fluid Hauled to MP G&I: 580 bbls Y Daily Fluid Hauled to 8-50:0 bbls Total Fluid Hauled to B-50: 0 bbls C )? Daily Fluid Hauled to ORT: 580 bbls Total Fluid Hauled to ORT: 580 bbls;Daily Fluid Hauled to GPB G&I: 0 bbls .Y Total Fluid Hauled to GPB G&I:0 bbls Daily H2O from Duck Lake: 150 bbls j Total H2O from Duck Lake: 950 bbls Daily Fluid Lost to Formation: 0 bbls Total Fluid Lost to Hole: 0 bbls 8/5/20'j8 Continue Mill window from 5413' to 5428', w/350 gpm/690 psi, 80 rpm(2.SK - 6K Tq, WOM 3/4K. Drill 20' new formation to 5448'.;Pump H1 Vise Sweep around /with 10% increase @ shakers. Pass through window with no pumps/Rotary x3. No issues passing through window. Top of window @ 5411'. Bottom Of Window \ @ 542S.:Perform FIT to 12.5 ppg EMW w/ existing 9.5 ppg MW. Pump 1.7 bbs, apply 880 psi, 10 sec 856 psi, 5 min 725 psi, bleed off pressure, 1.2 bbls bled \ back, open UPR.;Monitor well. Pump dry job. TOH from 5396'to 635'.;UD 6joints of HWDP. UD BHA and mills. Upper mill in gauge, lower mill 1/8 under, indow mill 1/4 under.;Pull wear ring and inspect. MIU stack washing tool and clean out BOPE, function rams. B/D choke and kill line. Set wear bushing. ;Rig up Q and pick up BHA as per DD. 8.5" Kymera bit, StrataForce mud motor, DM coil, HOC, UBHO. Measure RFO =1.55/6.75 = 82.66. Orientate USHA. Pick (2) drill collars, (6) HWDP, Jars, (5) HWDP. Shallow pulse test MWD.;Pick up, drift and single in hole with drill pipe from 488' to 5376'. PUW/SOW1 Si.;Fill pipe. Orientate motor to 24L. RIH to 5444', 6K bobble going through window at 5420'. Set down 5K at 5444'. Pick up and establish circulation 450gpm/1120 psi. Wash down to 5448'.;Slide drill at 30L from 5448'to 5463', 450 gpm/1400 psi with 100-200 psi diff, WOB 5-10K;Daily Fluid Hauled to MP G&1:58 bbls Total Fluid Hauled to MP G&1:638 bbls Daily Fluid Hauled to B-50: 0 bbls Total Fluid Hauled to B-50:0 bbls Daily Fluid Hauled to ORT: 580 bbls Total Fluid Hauled to ORT: 580 bbls;Daily Fluid Hauled to GPB G&I: 0 bbls Total Fluid Hauled to GPB G&I: 0 bbls Daily H2O from Duck Lake: 150 bbls Total H2O from Duck Lake: 1100 bbis Daily Metal Collected: 380 Lbs Total Metal Collected: 380 Lbs Daily Fluid Lost to Formation: 0 bbls Total Fluid Lost to Hole: 0 bbls 8/6/2018 Continue to slide from 5466to 5533'MD with 450gpm/1305 psi, 8-20K WOB. Initial drilling was ratty and slow, to 5472'. Surveys on they fly were showing a drop in inclination down to 9.2' after 21' of good slide.;Rack back 1 stand and circulate 200gpm/356 psi.;Rig up Pollard E-line and RIH with Gyro. Gyro surveys showing an offset error of 130° -160° ;Service rig. Grease blocks, crown and washpipe.;POOH from 5533' to 488' racking drill pipe back.;Rack back HWDP and drill collars. Confirm RFO error; was measured from motor to MWD. Drain motor. Break out Kymera bit. Bit grade 5-6-BT-A-E-1-CT.;M/U BHA: Pick up new Baker TD 606X bit. Change out DM collar. Measure RFO MWD to Motor= 6.416.76 = 340.83°. RIH with non-mag collars, HWDP, and jars. Shallow pulse test.;Continue to RIH with 5" drill pipe from derrick, to 534T.;Service rig. Grease and inspect blocks, top drive spinners, crowns.;Fill pipe. Orientate motorto 30L. Continue to RIH to 5533' wfth 4K bobble at 5430' (BOW 5428').;Continue drilling 8-1/2" hole from 5533'to 5726; 450 gpm/1180 psi off bottom, 100-250 psi diff, WOB 6-12K ROP 50-120 fph. PUW 156K, SOW 150K.;Daily Fluid Hauled to MP G&I: 0 bbls Total Fluid Hauled to MP G&I: 638 bbls Daily Fluid Hauled to ORT: 580 bbls Total Fluid Hauled to ORT: 580 bbls Daily Fluid Hauled to GPB G&I: 0 bbls Total Fluid Hauled to GPB G&I: 0 bbls;Daily H2O from Duck Lake: 110 bbls Total H2O from Duck Lake: 1210 bbls Daily Metal Collected: 20 Lbs Total Metal Collected: 400 Lbs Daily Fluid Lost to Formation: 0 bbls Total Fluid Lost to Hole: 0 bbis 8/7/2018 Drill 8.5" hole F/ 5725'T/6058'(333') AROP 55.5 FPH. GPM 550,1490/1330 PSI WOB 6k, 80 RPM, 3-61K TO MW in/out 9.4+ Vis 40, BGG 304u PU/SO/ROT 161/152/158.;Drill 8.5" hole F/ 6,058'T/ 6.356'(298AROP 49.66' FPH. GPM 500,1540/1330 PSI WOB 8-12k, MW iniout 9.5 Vis 40, BGG 100u PU/SO/ROT 168/156/160.;Canrig failed at 18:02. Cont. to slide F/ 6,356' to 6,416' MD (6,267' TVD) total 60' (AROP 60) 500 GPM, 1,540 PSI, WOB 8- 12K, Diff 80-220 PSI, P/U 168K, SLK 156K. MW 9.5 ppg. Circ. and reciprocate while working with Canrig IT. Distance from plan 29.4', 29.15' high, 3.77' Ieft.;Cont. Circ. and reciprocate, racked one stand back F/ 6,416'to 6,356 MD due working on Canrig. Pumping 400 GPM, 1,000 PSI, 65 RPM, 4K TRQ, After discussion with Canrig IT appears server has failed to a read only. IT contacted service Rep for replacement sewer.;Decision was made to pull up into casing until Canrig server could be repaired.;Monitor well 10 min. with slight seepage loss. POOH on elevators F/ 6,356'to 5,34T MD. Encountered tight spots at 5,770' pulling 20K over. Break Circ. at 400 GPM, 950 PSI, 65 RPM, 3-4K TRQ, back ream to 5,717' MD. No over pull or erratic torque. ROT 155K .;Tight spot at 5,540' to 5,530' MD pulled 30K over, broke Circ. 400 GPM, 65 RPM, 34K TRQ no over pull or erratic torque. Orient to 30° left of high side. Lost 61K in P/U WT at 5,469'. Pull through window (BOW 5,428', TOW 5,411') without issue. Pulled to 5,347' MD. PAJ 151 K, SLK 146K.;At 5,34T put floor valve in monitoring well with trip tank and set manual pit marker. Manual strap every 15 Min. Seepage loss rate at 1.6 bph. Service rig, grease IDS35OPE, blocks, crown, inspect Drawworks and Spinners. Cont. with general maintenance and house keeping.;Changed globe valves on steam system. Tighten up hydraulic line to shot pin, Worked on inventory list. C/O couple valves in pits for mud system. Total metal for day 51b, Total 423 Ib.;Daily Fluid Hauled to MP G&1:231 bbls Total Fluid Hauled to MP G&I: 869 bbls Daily Fluid Hauled to ORT:0 bbls Total Fluid Hauled to ORT: 580 bbls Daily Fluid Hauled to GPB G&I: 0 bbls Total Fluid Hauled to GPB G&I: 0 bbls;Daily H2O from Duck Lake: 300 bbls Total H2O from Duck Lake: 1510 bbls Daily Metal Collected: 22 Lbs Total Metal Collected: 407 Lbs Daily Fluid Lost to Formation: 0 bbls Total Fluid Lost to Hole: 0 bbls 8/812018 Waiting on Canrig rep to fix server. Install shut off valves on ODS tugger. Disassemble suction side of MP #2 and inspect. C/O 2 warn valves and seats.;Decision was made to POOH to C/O BHA to rotary steerable. POOH on elevators F/ 5,347' to 488' MD. P/U 60K, SLK 60K. Observed proper hole fill. UD 2 Jnts of 5" HWDP, rack back Jar stand and HWDP.;Rack back NMFC. UD MWD tools. Break bit off and UD Motor for BHA#4. Bit Grade 2,1,BT, N, X, I, WT, BHA.;Clean and clear rig floor.;Bring BHA components to rig floor. P/U M/U 8.5" NOV SK616M-J7 D, Geo Pilot, 6 314" ADR, 8 3/8" ILS, 6 3/4" DM Collar, 6 3/4" DGR Collar, 6 3/4" PWD, 6 3/4" TM Collar. Plug into download tool, MWD tools not communicating. Retest and no communication.;Canng server up and running. PJSM C/O 6 3/4" DM Collar. Plug into MWD tool and good download. Cont. to M/U BHA #5. RIH W/ 5" HWDP to 460' MD. Shallow hole test MWD at 450 GPM, good test.;PJSM Single in hole 5" D.P. F/ 460' to 5,381' MD. Drift 3.13". Correct hole displacement while RIH. Fille Pipe and break Circ. to break in Geo Pilot as per DD. 515 GPM, 1,150 PSI, stage RPM's up F/ 5 to 60 RPM in 5 min.;PJSM Slip and cut drilling line 56',. Re calibrate block position. Check crown o-mafic and floor saver. Grease crown, blocks, wash pipe, spinners, elevators and inspect Equip.;Cont. to RIH on elevators W/ 5" D.P. to F/ 5,381'to 6,260' MD. Encountered tight spots at 5,480' 1 OK down, 5,525' 18K down pumped down at 167 GPM, 290 PSI, 5,670'6-8K down. At 6,260' MD 21 K down pump at 167 GPM, 290 PSI, 30 RPM, 3,800 TRQ P/U 161 K, SLK 159K.;Wash and ream down F/ 6,260' to 6,416' MD. 167 GPM, 320 PSI, 30 RPM, P/U 161 K, ROT 159K. Shot survey at 6,372' MD.;Drill ahead 8.5" F/ 6,416 to 6,454' MD. Total 38' (AROP 76) 490 GPM, 1,290 PSI, 120 RPM, 5K TRQ, WOB 5K, ECD 10.1 ppg. P/U 165K, SLK 153K, ROT 161 K.;Daily Fluid Hauled to MP G&I: 58 bbls Total Fluid Hauled to MP G&1:927 bbls Daily Fluid Hauled to ORT: 0 bbls Total Fluid Hauled to ORT: 580 bbls Daily Fluid Hauled to GPB G&I: 0 bbls Total Fluid Hauled to GPB G&I: 0 bbls;Daily H2O from Duck Lake: 130 bbls Total H2O from Duck Lake: 1640 bbls Daily Metal Collected: 1 Lbs Total Metal Collected: 424 Lbs Daily Fluid Lost to Formation: 9.6 bbls Total Fluid Lost to Hole: 9.6 bbls 8/9/2018 Drill ahead 8.5" F/ 6A54'to 6,701' MD. Total 247' (AROP 41 FPH') 500 GPM, 1,295 PSI, 120 RPM, 5.5K TRQ , WOB 5-8K, ECD 10.1 ppg. Max Gas 325u P/U 171 K, SLK 150K, ROT 161 K.;SPR at 6,454' MD (6,289' TVD) MW 9.5 ppg MP #1 32-190 PSI, 48-235 PSI, MP #2 32-190 PSI, 48-235 PSI.;Drill ahead 8.5" F/ 6,701' to 6,976' MD. Total 275' (AROP 45.8 FPH') 500 GPM, 1,296 PSI, 120 RPM, 6K TRQ , WOB 2-6K, ECD 10.1 ppg. Max Gas 138u P/U 174K, SLK 148K , ROT 162K.;Pump tandem low 35 vis/ 8.5 ppg weight, high 100 vis/ 10.5 ppg weight @ 6,956' MD. Observed sweep back as calculated W/ 100% increase in clay at shakers. ART= 7.63 Hrs, Bit 7.63 Hrs, Jar 17.83 Hrs.;Drill ahead 8.5" F/ 6,976' to 7,338' MD. Total 362' (AROP 60.3) 500 GPM, 1,410 PSI, 100 RPM, TRQ on 6.5K, TRQ off 4K , WOB 10-12K, ECD 10.1 ppg. P/U 174K, SLK 153K, ROT 163K Max Gas 143U.;Drill ahead 8.5" F/ 7,338' to 7,667' MD. Total 329' (AROP 54.8') 500 GPM, 1,450 PSI, 120 RPM, TRQ on 6.5K, TRQ off 4K, WOB 10-12K, ECD 10.1 ppg. P/U 174K, SLK 153K, ROT 163K Max Gas 143U.;Pump tandem low 35 vis/ 8.5 ppg weight, high 100 vis/ 10.5 ppg weight @ 7,463' MD. Observed sweep back as calculated W/ 100% increase in clay at shakers. ART= 6.55 Hrs, Bk 14.18 Hrs, Jar 24.38 Hrs. Distance from plan 13.42', 13.37' low, 1.23' right.;Daily Fluid Hauled to MP G&I: 231 bbis Total Fluid Hauled to MP G&I: 1,158 bbis Daily Fluid Hauled to ORT: 0 bbls Total Fluid Hauled to ORT: 580 bbis Daily Fluid Hauled to GPB G&I: 0 bbis Total Fluid Hauled to GPB G&1: 0 bbls;Daily H2O from Duck Lake: 300 bbis Total H2O from Duck Lake: 1940 bbis Daily Metal Collected: 4 Lbs Total Metal Collected: 428 Lbs Daily Fluid Lost to Formation: 0 bbis Total Fluid Lost to Hole: 9.6 bbis 8/102018 Drill 8.5" hole F/ 7,667'to 8,009' MD. Total 342' (AROP 57') 500 GPM, 1,600 PSI, 120 RPM, TRQ on 14-15K, TRQ off 7.5K, WOB 10-12K, MW 9.5, ECD 10.1 ppg. P/U 184K, SLK 154K, ROT 167K Max Gas 120u.;Drill 8.5" hole F/ 8,009' to 8,218' MD. Total 209' (AROP 465) 500 GPM, 1,630 PSI, 120 RPM, TRQ on 14.5K, TRQ off 15K , WOB 11-12K, MW 9.5, ECD 10.1 ppg. P/U 186K, SO 155K, ROT 168K Max Gas 48u.;Rack back i stand at 8,158' MD. CBU @ 550 gpm/1880 psi, Rot 150 rpm/19.5k Tq. Follow bottoms up pumping tandem low 35 vis/ 8.5 ppg weight, high 100 vis/ 10.5 ppg weight sweeps.;Cont. Circ. BU 550 GPM, 1,880 PSI, 150 RPM, TRQ 19.5K, Sweeps back as calculated with 5% increase at shakers. Monitor well for 10 Min. static.;Pump out of hole F/ 8.158' to 6,400' MD 500 GPM, 1,600 PSI. Encountered tight spot at 7,875' weight dropped F/ 190K to 185K no Press. spike. Tight at 7,845'to 7,838' pulled to 212K , SLK 137K wiped clean. At 7,11 V to 7,104 pulled to 205K, SLK 138K wiped clean.;RIH F/ 6,400'to 6,517' MD Circ. and reciprocate BU at 120 RPM, 500 GPM, 1,650 PSI, 15.5K TRQ. RIH F/ 6,517' to 6,580' MD Circ. and Reciprocate BU at 120 RPM, 500 GPM, 1,650 PSI, 15.5K TRQ.;C/O air boot on stack. Inspect and clean Bell Nipple. Well static.;RIH F/ 6,580' to 8,156' MD. Wash down F/ 8,156to 8,219' MD 500 GPM, 1,625 PSI. No issues running to bottom.;Drill ahead 8.5" F/ 8,218' to 8,472' MD. Total 254' (AROP 56.4') 500 GPM, 1,747 PSI, 120 RPM, TRQ on 17.5K. TRQ off 15K, WOB 10-12K, ECD 10.39 ppg. P/U 190K, SLK 157K, ROT 163K Max Gas 180U.;Distance to plan 41.39, 38.57' low, 15.02' Ieft.;Daily Fluid Hauled to MP G&1: 272 bbls Total Fluid Hauled to MP G&I: 1,431 bbls Daily Fluid Hauled to ORT:0 bbis Total Fluid Hauled to ORT: 580 bbis Daily Fluid Hauled to GPB G&1: 0 bbis Total Fluid Hauled to GPB G&I: 0 bbls;Daily H2O from Duck Lake: 350 bbis Total H2O from Duck Lake: 1290 bbls Daily Metal Collected: 4 Lbs Total Metal Collected: 432 Lbs Daily Fluid Lost to Formation: 0 bbis Total Fluid Lost to Hole: 9.6 bbis 8/11/2018 Drill 8.5" hole F/ 8471' to 8815" MD. Total 344' (AROP 573) 500 GPM, 1,875 PSI, 120 RPM, TRQ on 17.6K, TRQ off 17K, WOB 16-18K, MW 9.6, ECD 10.4 ppg. P/U 200K, SO 157K, ROT 172K Max Gas 97u.;Pump Tandem Sweep @ 8665', back on time with 50% increase cutting at shaker.;Drill 8.5" hole F/ 8815'to 9169 MD. Total 354' (AROP 59') 500 GPM, 1,790 PSI, 120 RPM, TRO on 19.5K, TRQ off 18.5K, WOB 18K, MW 9.6, ECD 10.3 ppg. P/U 205K, SO 158K, ROT 179K Max Gas 113u.;DnII ahead 8.5" F/ 9,169' to 9,177' MD. Total 8', 500 GPM, 1,390 PSI, 120 RPM, TRQ on 19.5K, TRQ off 18.5K, WOB 18K, ECD 10.39 ppg. P/U 205K, SLK 158K, ROT 179K Max Gas 1000. ART 10.82 Hrs, Bit 10.82 Hrs, Jar 42.73 Hrs. Distance to plan 72.35', 66.74' low, 27.94' Ieft.;Pump tandem 20 bbl low 35 vis/ 8.5 ppg weight, 20 bbl high 100 vis/ 10.5 ppg weight sweeps.;Stand pipe pressure dropped from 400 PSI. MWD turbine speed reduced RPM. Shut in GEO Span. Started trouble shooting surface Equip. Cleaned suction screens, checked over pumps, test surface lines to 2,000 PSI.;Took new SPR and compare to previous, with a 60 PSI reduction in pressure. Determined it is a hole in the D.P. Decision was made to POOH. Finish Circ. sweep out, no real indication at surface.;POOH F/ 9,169'to 8,259' MD. Attempt to POOH on elevators to reduce washing out hole. Encountered numerous tight spots, wash and ream through, 9,104', 8,982'- 8,972', 8,958', 8,920', 8,891', 8,872', 8,634', 8,609', 8,546, 8,470', 8,418', 8,383', 8,325', 8,278' Pump out of hole F/ 8,278' to 7,74T.;250 GPM, ICP 565 PSI. Started pumping out of hole F/ 8,259'to 6,490' MD 350 GPM ICP 565 PSI, FCP 460 PSI. Pulled on elevators F/ 6,490' to 5,639 MD. Pulled tight and pumped through 400 GPM, 440 PSI, reduce flow to 350 PSI, 380 PSI. 20 RPM TRQ 3.2K.;Back ream F/ 5,639' to 5,439' MD 10 RPM, 350 GPM, 360 PSI slight over pull. Pulled through window without pumps at 5,428'to 5,211' did not see any over pull. Found hole at 5,408'. Lay down 2 joints. Lost 13 bbl for trip.;CBU at 5,376'. MD 400 GPM, 1,090 PSI. Not real increase at shakers. Service rig, IDS350PE and grease crown.;C/O Shot Pin Assy on TDS350.;Daily Fluid Hauled to MP G&1:413 bbis Total Fluid Hauled to MP G&I: 1,844 bbls Daily Fluid Hauled to ORT: 0 bbis Total Fluid Hauled to ORT: 580 bbls Daily Fluid Hauled to GPB G&I: 0 bbis Total Fluid Hauled to GPB G&I: 0 bbls;Oaily H2O from Duck Lake: 440 bbis Total H2O from Duck Lake: 2730 bbis Daily Metal Collected: 4 Lbs Total Metal Collected: 436 Lbs Daily Fluid Lost to Formation: 0 bbis Total Fluid Lost to Hole: 9.6 bbls 8/12/2018 Parked up inside Window. Remove Shot Pin Assy and replace seals. Function test same. Monitor hole on trip tank.;Replace bad joint on std 79. RIH on elevators f/5376' to 7385'. Correct displacement on TIH.;CBU from 7385, w/ 550 gpm/1770 psi, 150 rpm/21-22k Tq PU 185K, SO 161 K, Rot 177K . Saw 50% increase on shakers at bottoms up.;Continue TIH V7385' to 9020'. Tempt to work through tight spot @ 9020' on elevators with no success with mx set down @ 1 OK. Kelly up and fill pipe.;Wash and ream f/9020'to 9177'w/450 gpm/1450 psi, 80 rpm/8.8 tq, Encounter signs of Packoffs from 9020'-9080', 9132'-9152'. Tag 25' of fill on bottom. Load sweep in pipe and make connection.;Drill 8.5" hole F/ 9177'to 9,335' MD. Total 158' (AROP 31.6) 500 GPM, 1,860 PSI, 140 RPM, TRQ on 20- 22K, TRQ off 18.5K, WOB 20K, MW 9.6, ECD 10.3 ppg. PIU 203K, SO 161 K, ROT 180K Max Gas 50u.;Pump Tandem Sweep @ 917T Sweep back 300 strokes late with 25% fine clay and sands. SPR 9,229' MD ( 7,559' MD) MW 9.6 ppg MP #1 32-217 PSI, 48- 284 PSI MP #2 32-215 PSI, 48-285 PSI.;Drill ahead 8.5" F/ 9,335' to 9,588' MD. Total 253', (AROP 42.2') 500 GPM, 2,022 PSI, 120-145 RPM, TRQ on 23-24K, TRQ off 25K, WOB 20K, ECD 10.4 ppg. P/U 211K, SLK 164K, ROT 182K Max Gas 103U.;Drill ahead 8.5" F/ 9,588' to 9,859' MD. Total 271', (AROP 452) 500 GPM, 2,061 PSI, 120-130 RPM, TRQ on 21-22K, TRQ off 23K, WOB 21 K, ECD 10.4 ppg. P/U 215K, SLK 165K, ROT 182K Max Gas 88U. ART 9.86 His, Bit 9.86 Hrs, Jar 52.59 His. Distance to plan 41.97', 38.89' low, 15.8' left.;ART 10.82 His, Bit 10.82 Hrs, Jar 42.73 Hrs.;At 9,673' MD pump tandem 28 bbl low 32 vis / 8.7 ppg weight, 22 bbl high 140 vis/ 10.8 ppg weight sweeps. Sweeps came back 25% increase at shakers W/ sand and small clay and 250 strokes late. SPR at 9,736' (7,786' ND) MW 9.6 ppg. MP #1 32- 200 PSI, 48-275 PSI MP #2 32-195 PSI, 48-265 PSI.;Daily Fluid Hauled to MP G&I: 353 bbis Total Fluid Hauled to MP G&I: 2,197 blots Daily Fluid Hauled to ORT: 0 bbis Total Fluid Hauled to ORT: 580 bbis Daily Fluid Hauled to GPB G&I: 0 bbls Total Fluid Hauled to GPB G&I:0 bbls;Daily H2O from Duck Lake: 160 bbis Total H2O from Duck Lake: 2,890 bbis Daily Metal Collected: 14 Lbs Total Metal Collected: 450 Lbs Daily Fluid Lost to Formation: 0 bbis Total Fluid Last to Hole: 9.6 bbis 8/13/2018 Drill 8.5" hole F/ 9859' to 10,223' MD. Total 376' (AROP 62') 500 GPM, 1,860 PSI, 120-135 RPM, TRQ on 15.5K, WOB 20K, MW 9.6, ECD 10.4 ppg. PIU 210K, SO 165K, ROT 187K Max Gas 50u.;Drill 8.5" hole F/ 10,235' to 10,556' MD. Total 321' (AROP 53.5 FPH') 500 GPM, 2,100 PSI, 120-135 RPM, TRQ on 11-17K , WOB 21K, MW 9.6, ECD 10.4 ppg. P/U 218K, SO 167K, ROT 188K Max Gas 50u.;Pumped tandem sweeps at 10,235'w/10% increase in cuttings and back 16 bbis Iate.;Ddll ahead 8.5" F/ 10,556' to 10,809' MD. Total 253', (AROP 42.2') 500- 530 GPM, 2,100 PSI, 120-145 RPM, TRQ on 18-20K, TRQ off 15- 17K, WOB 20-22K, ECD 10.6 ppg. P/U 230K, SLK 170K, ROT 184K Max Gas 55U. Bit 60.16 Hrs, Jar 70.36 Hrs.;At 10,745' MD pump tandem 20 bbl low 32 vis / 8.7 ppg weight, 20 bbl high 128 vis/ 10.7 ppg weight sweeps. Sweeps came back 50% increase at shakers W/ sand and small clay and 200 strokes (12.4 bbl) Iate.;Distance to plan 19.46', 18.77' high, 5.1' right. SPR at 10,745' (8,246' TVD) MW 9.7 ppg MP #1 32-226 PSI, 48-307 PSI MP #2 32-227 PSI, 48-305 PSI.;Drill ahead 8.5'F/ 10,809'to 10,933' MD. Total 124', (AROP 35.5) 500.530 GPM, 1,470-2,222 PSI, 120 RPM, TRQ on 20K, TRQ off 14.51K. WOB 20K, ECD 10.5 ppg. P/U 231 K, SLK 168K, ROT 184K Max Gas 103U. Increase water to 25 bph to control MW.;Pump Press. decreased at 10,838' MD F/ 2,200 PSI to 2,000 PSI after down link. MWD turbine speed reduced RPM. Shut in GEO Span. Started trouble shooting surface Equip. Checked over pumps.;Rotate and Circ. CBU 500 GPM, ICP 1,370 PSI, FCP 1,260120 RPM, TRO off 16.5-20K, ECD 10.4 ppg. Gas 5U. No increase at shakers at BU. Perform SPR W/ 60-70 PSI lower Press. Monitor hole for 15 Min, static.;Pump out of hole F/ 10,933'to 10,304' MD. 350 GPM, ICP 685 PSI, 670 FCP P/U 230K, SLK 189K.;Daily Fluid Hauled to MP G&1:531 blols Total Fluid Hauled to MP G&I: 2,728 bbls Daily Fluid Hauled to ORT: 0 bbis Total Fluid Hauled to ORT: 580 bbls Daily Fluid Hauled to GPB G&I: 0 bola Total Fluid Hauled to GPB G&I: 0 bbls;Daily H2O from Duck Lake: 510 bbls Total H2O from Duck Lake: 3,400 bbis Daily Metal Collected: 4 Lbs Total Metal Collected: 454 Lbs Daily Fluid Lost to Formation:0 bbis Total Fluid Lost to Hole: 9.6 blols 8/14/2018 Pump out of hole F/ 10,304' to 9991' MD. Unable to work thru tight spot @ 9991' MD (30k max overpull). Backream thru tight spot @ 9991'— 9920' MD. Continue pump out of hole looking for washout in string w/ 250 gpm, 410 psi.;Found washout it @ 7558' MD bit depth. UD and replace. Continue pump out of hole inspecting drill string for notable damage. Found 2 more damage its and replaced same (btm it of std #98 and Min it of std #80).;Damage was moderated scarring on tube 10-15' down from box end. Top drive washpipe pipe starting leaking while pumping out of hole. Pullout of hole on elevators F/ 6896'to 5698' MD. Work thru tight hale F/ 5698'to 5503'w/ minimal pump and rotary.;Monitor well on trip tank. Loss rate 1.5 bph. C/O swivel packing and Press. wash top drive. C/O swab and liner on MP #2 Pod #3. C/O liner wash pump mechanical seal on MP #2. C/O leaking hydraulic fitting on top drive.;Kelly up and test swivel packing to 3,000 PSI. Good test.;RIH on elevators F/ 5,516to 10,933' MD. Kelly upon last stand and wash down. P/U 230K, SLK 170K. No Fill and no issue getting to bottom. Lost 14.3 bbl for trip.;Drill ahead 8.5" F/ 10,933' to 11,080' MD. Total 147', (AROP 29.4') 500-530 GPM, 2,317 PSI, 100-135 RPM, TRQ on 25- 26K, TRQ off 21K, WOB 18-20K, ECD 10.6 ppg. P/U 240K, SLK 170K, ROT 184K Max Gas 335U. Increase water to 20 bph to control MW.;Distance to plan 23.70', 23.17' high, 5.04' dght.;Daily Fluid Hauled to MP G&1:340 bbls Total Fluid Hauled to MP G&I: 3,068 bbis Daily Fluid Hauled to ORT: 0 bbis Total Fluid Hauled to ORT: 580 bbis Daily Fluid Hauled to GPB G&I:0 bbls Total Fluid Hauled to GPB G&I:0 bbls;Daily H2O from Duck Lake: 390 blols Total H2O from Duck Lake: 3,790 bbis Daily Metal Collected: 4 Lbs Total Metal Collected: 458 Lbs Daily Fluid Lost to Formation: 14.3 bbls Total Fluid Lost to Hole: 23.9 bbis 8/15/2018 Continue drlg 8.5" RSS F/ 11,080'- T/ 11,370' MD (291' total, 49 AROP) 20k wob, 130 rpm, 21k tq, 530 gpm, 2385 psi, 63% flow 10.4 ECD, 50 bgg.;lncrease lubes slightly from 3.5% to 4% and saw a 3-5k reduction in rotating tq.;Confinue drig 8.5" RSS F/ 11,370'- T/ 11,634' MD (264' total, 44 AROP) 20k wob,125 rpm, 20k tq, 550 gpm, 2620 psi, 63% flow 10.8 ECD, 56 bgg.;Pump tandem sweep @ 11,438' MD (lo/lo then hi/hi). Came back 50 bbls late w/ 10% increase in cuttings. SPR at 11,375' (8,552' TVD) MW 9.75 ppg MP #1 32-303 PSI, 48-382 PSI MP #2 32-306 PSI, 48-386 PSI.;Drill ahead 8.5" Ft 11,634'to 11,952' MD. Total 318', (AROP 53') 560 GPM, 2,726 PSI, 130 RPM, TRQ on 23-24K, TRQ off 24-25K, WOB 18-20K, ECD 11.0 ppg. P/U 251K, SLK 171K, ROT 188K Max Gas 60U, BGG 50U. Water at 25 bph to control MW.;Pump tandem sweep at 11,960' MD, 20 bbl low 35 vis/ 8.5 ppg weight, 20 bbl high 300 vis/ 10.9 ppg weight sweeps. Sweep back 600 (37.2 bbl) strokes late W/ 10% increase of fine sand and small clay. SPR at 11,880' (8,811' TVD) MW 9.75 ppg MP #132-332 PSI, 48-414 PSI MP #2 32-333 PSI, 48-420 PSI.;Drill ahead 85'F/ 11,952' to 12,321' MD. Total 369', (AROP 615) 560 GPM, 2,920 PSI, 130 RPM, TRQ on 23- 24K, TRQ off 26K, WOB 21 K, ECD 11.2 ppg. P/U 257K, SLK 169K, ROT 194K Max Gas 70U. Water at 25 bph to control MW.;Distance to plan 20.52', 19.62' high, 6.03' right.;Daily Fluid Hauled to MPG&1: 521 bbls Total Fluid Hauled to MP G&l: 3,589 bbls Daily Fluid Hauled to ORT:0 bbls Total Fluid Hauled to ORT: 580 bbls Daily Fluid Hauled to GPB G&I: 0 bbls Total Fluid Hauled to GPB G&I:0 bbls;Daily H2O from Duck Lake: 460 bbls Total H2O from Duck Lake: 4,250 bbls Daily Metal Collected: 3 Lbs Total Metal Collected: 461 Lbs Daily Fluid Lost to Formation: 0 bbls Total Fluid Lost to Hole: 23.9 bbls 8/16/2018 CBU @ 12,321' MD, 9036' TVD. 500 gpm, 2375 psi, 60% flow, 150 rpm, 25k to, 10 MW w/ 11.1 ECD's. 263k up, 181k dn, 198k rot. 18 max gas @ btms up. Pump tandem sweep, no increase, 60 bbls late.;SPR @ 12,321' MD / 9036' TVD w/ 10 ppg MW. 32/48 spm #1 MP 320/415, #2 MP 327/420 psi. Monitorwell (very slight losses /+/- 1 bph) POOH on elevators F/ 12,321'- T/ 10,808' MD. Pulled clean without issues. Calculated displacement for trip.;Monitor well and R/U floor to trip in (static). TIH on elevators F/ 10,808'- T/ 12,321' MD. Trip to btm was clean. Calculated displacement for trip. Wash down last stand, no fill.;Drill ahead 8.5" F/ 12.321'- T/ 12,714' MD. Total 393', (AROP 562) 80-125 RPM, 16K To, WOB 16-20K, ECD 11.0. Max Gas 525U, BGG 120U. 550 GPM, 2,825 PSI, 58%flow. 270K up,168K dn, 202K rot. Top of Tuffs @ 12,390' MD / 9071' TVD.;AOGCC witness notification for BOP test sent via email @ 1:13 pm. Will update AOGCC in the morning. SPR at 12,510' (9,134' TVD) MW 9.9 ppg MP #1 32-320 PSI, 48-409 PSI MP #2 32-322 PSI, 48-416 PSI.;Drill ahead 8.5" F/ 12,714' to 13,018' MD. Total 304', (AROP 50.6) 540 GPM, 2,925 PSI, 150 RPM, TRQ on 14-15K, TRQ off 14K, WOB 20K, ECD 11.1 ppg. P/U 296K, SLK 168K, ROT 202K Max Gas 393U. Water at 15 bph to control MW.;Pump tandem sweep at 12,830' MD, 20 bbl low 37 vis/ 8.6 ppg weight, 20 bbl high 300 vis/ 10.8 ppg weight sweeps. Sweep back 900 (58.9 bbl) strokes late W/ 50% increase of small shale, clay, sand and sand stone.;At 11,952' MD started increasing BAROTROL/BARAFLC 515 concentrations to 8 ppb and BARACARB concentrations to 20 ppb with 2% v/v GEM.;Drill ahead 8.5' F/ 13,018' to 13,205' MD. Total 187', (AROP 53.7') 530 GPM, 2,770 PSI, 150 RPM, TRQ on 15-16K, TRQ off 14K, WOB 16K, ECD 11.1 ppg. P/U 283K, SLK 170K, ROT 206K Max Gas 571 U. Start weight up F/ 9.9 ppg to 10.3 ppg.;Distance to plan 8.94', 7.45' high, 4.94' right.;Circ. and reciprocate F/ 13,205'to 13,142'550 GPM, 2,890 PSI, 150 RPM, 14-15K TRQ. Cont. to weight up F/ 9.9 ppg to 10.3 ppg. Max Gas 637U.;Pump tandem sweep at 13,205' MD, 25 bbl low 32 vis/ 8.7 ppg weight, 25 bbl high 200 vis/ 11.5 ppg weight sweeps. Sweep back 800 (49.6 bbl) strokes late W/ 25% increase of small shale, clay, sand and sand stone.;Daily Fluid Hauled to MPG&I: 571 bbls Total Fluid Hauled to MP G&1: 4,160 bbls Daily Fluid Hauled to ORT: 0 bbls Total Fluid Hauled to ORT: 580 bbls Daily Fluid Hauled to GPB G&1: 0 bbls Total Fluid Hauled to GPB G&I: 0 bbls;Daily H2O from Duck Lake: 650 bbls Total H2O from Duck Lake: 4,900 bbls Daily Metal Collected: 5 Lbs Total Metal Collected: 466 Lbs Daily Fluid Lost to Formation: 0 bbls Total Fluid Lost to Hole: 23.9 bbls 8/17/2018 Obtain survey for MWD. Monitor well, static. POOH on elevators F/ 13,205! to 3,993' MD No issues pulling out of hole. Lost 5 bbl for trip. SPR at 13,205' (9,488' TVD) MW 10.3 ppg MP #132-307 PSI, 48407 PSI MP #2 32-307 PSI, 48-410 PSI.;Clean and clear rig floor. Grease IDS350PE.;PN MAJ Baker RetrieveOMatic to 5" string and RIH 1 stand. Set packer and release from twin thread as per Baker Rep onsite. POOH one stand and break out Pup and twin thread sub. Test packer to 500 PSI for 10 Min. Center of element at 67.8'.;Pull Wear Ring and set test plug RILDS as per NOS Rep onsite. P/U rebuilt Dart Valve and M/U TIW.;M/U side entry, TIW, Dart Valve and UD. WU top drive test fitting. C/O CMV 15. Fill lines and perform shell test to 4000 PSI.;Perform BOPE test W/ 5" and 4.5" test joint, 250 PSI low and 4,000 PSI high for 5 Min all charted. Tested Choke Manifold vlaves 1-15, Annular, Blinds, upper and lower pipe rams, Mem Kill, HCR Choke and Kill, Manual Choke and Kill, Manual and Super Chokes.;Koomey draw down 200 PSI increase in 23 Sec, full charge 97 Sec. 6 nitrogen bottle average 2,300 PSI. BOP test witnessed by AOGCC inspector Matt Herrera.;Break TIW, Dart Valve, side entry sub and pump in sub from test joint. Pull test plug and install Wear Ring RILDS. Blow down Choke and kill Iines.;Pull riser and dress rough edges that have been causing air boot failures. Reinstall riser. Change out swivel packing.;PJSM P/U Baker overshot and M/U 5' pup. RIH and release Retrievomatic as per Baker Rep onsite. Well took 2 bbl of mud when packer was released. POOH and UD Packer.;RIH on Elevators F/ 3,993'to 5,319' MD.;CBU at 5,319 MD. 500 GPM, 1,750 PSI. SIMOPS Prep for Slip and cut drilling line. No Iosses.;Daily Fluid Hauled to MP G&I: 423 bbls Total Fluid Hauled to MP G&1:4,583 bbls Daily Fluid Hauled to ORT: 0 bbls Total Fluid Hauled to ORT: 580 bbls Daily Fluid Hauled to GPB G&1: 0 bbls Total Fluid Hauled to GPB G&I: 0 bbls;Daily H2O from Duck Lake: 190 bbls Total H2O from Duck Lake: 5,090 bbls Daily Metal Collected: 0 Lbs Total Metal Collected: 466 Lbs Daily Fluid Lost to Formation: 5 bbls Total Fluid Lost to Hole: 28.9 bbis 8/18/2018 Cut and slip drilling line, Svc rig.;RIH on elevators F/ 5319' to 12,905' MD. Trip was clean to 12905' MD. Attempt to work past tag @ 12,905 w/ 20k do several times on elevators (no go). Wash and ream past 12,905' MD. Started seeing packing off and stall issues @ 12,955' MD.;CBU 2x rot and recip pipe F112,955'to 13,018' MD. Establish rot/circulation w/ initial packoffs, 24k stalls and overpulls. MW outl0.5 and cold. Slowly stage up pumps to 525 gpm, 2300 psi, 80 rpm, 15-20k tq. 293k up, 155k dn.;Wash and Ream F/ 13,018' to 13,205' MD. 440 gpm, 2135 psi, 58% flow, 80 rpm, 15.5k tq. 800u gas @ btms up, 155u bgg.;Drill ahead 8.5" F/ 13,205' to 13,480' MD. Total 275', (AROP 45.8') 540 GPM, 3,090 PSI, 120-150 RPM, TRO on 10-18K, TRO off 17K, WOB 18-24K, ECD 11.4 ppg. P/U 291 K, SLK 170K, ROT 199K Max Gas 426U.;Appears HRZ top came in at 13,400' MD (9,588' TVD) as per Gamma.;Drill ahead 8.5" F/ 13,480' to 13,712' MD. Total 232', (AROP 19.3) 540 GPM, 3,080 PSI, 150 RPM, TRQ on 15-17K, TRQ off 17K, WOB 15K, ECD 11.5 ppg. PIU 289K, SLK 166K, ROT 202K Max Gas 812U.;Pump tandem sweep at 13,600' MD, 25 bbl low 32 vis/ 8.7 ppg weight, 25 bbl high 200 vis/ 11.5 ppg weight sweeps. Sweep back 1,100 (68.2 bbl) strokes late W/ 25% increase of small shale, clay, sand and sandstone. 812U Gas.;Distance to plan 5.64', 5.12' high, 2.37' IeR;Daily Fluid Hauled to MPG&I: 111 bbis Total Fluid Hauled to MP G&1:4,694 bbls Daily Fluid Hauled to ORT: 0 bbls Total Fluid Hauled to ORT: 580 bbls Daily Fluid Hauled to GPB G&I: 0 bbls Total Fluid Hauled to GPB G&I: 0 bbls;Daily H2O from Duck Lake: 60 bbis Total H2O from Duck Lake: 5,150 bbls Daily Metal Collected: 0 Lbs Total Metal Collected: 466Lbs Daily Fluid Lost to Formation: 0 bbls Total Fluid Lost to Hole: 28.9 bbls 8/19/2018 'TD). Drill ahead 8.5" F/ 13,712' to 14.005' MD (TD). Total 293', (AROP 26.6') 540 GPM, 2,820 PSI, 150 RPM, TRQ on 27.5K, WOB 2-5K, ECD 11.2 ppg. P/U 301K, SLK 172K, ROT 202K Max Gas 433U. 11.3 ppg EMW with 10.3 ppg mud.;Circulate hole clean total of 6 annularvolumes at 540 gpm/2810 psi, 150 rpms 20-28Kft-lbs reciprocating pipe. Pump two sets of tandem low vis/high vis & weight sweeps with no increase in cuttings, 74 bbls late. ECD's 11.2 ppg EMW with 10.3 ppg mud. Monitor well, static.;POOH to 13,247 proper displacement. Wipe tight spots clean of 25K over at 13848', 13481', 13821', 13819, 13803'; wipe one time and pulled clean. Wipe from 13798'to 13769' with 30K overpull muliple times until clean.;RIH from 13,247'to 13781', sat down 25K. Work pipe from 13781' to 13800' with multiple 25-30K set downs, unable to work past 13800'. Pick up to 13790' and establish circulate staging up to 350 gpms, packing off. Pick up to 13765' and establish rotary at 60 rpms. Wash and ream from 13765';varying pump rate 350-420 gpm and rotary 0.80 rpms fighting pack - offs and high torque. Back ream each stand and slack off with no pumps/rotary to ensure clean. Wash and ream to 14,005'Max gas while reaming at bottoms up 658U.;Stage pumps up to 525 gpm/2763 psi, 150 rpms/20Kft-lbs, reciprocate pipe. Pump high vis/high weight sweep. Start weighing mud system up to 10.5 ppg. PUW 301, SOW 170, ROT 209.;Distance to plan 28.97', 7.31' high, 28.03' Ieft.;Daily Fluid Hauled to MP G&I: 231 bbls Total Fluid Hauled to MP G&1:4,925 bbls Daily Fluid Hauled to ORT:0 bbls Total Fluid Hauled to ORT: 580 bbls Daily Fluid Hauled to GPB G&I: 0 bbis Total Fluid Hauled to GPB G&I:0 bbls;Daily H2O from Duck Lake: 390 bbls Total H2O from Duck Lake: 5,540 bbls Daily Metal Collected: 0 Lbs Total Metal Collected: 466 Lbs Daily Fluid Lost to Formation: 0 bbls Total Fluid Lost to Hole: 28.9 bbls U Well Name: END 4-26A Field: Endicott County/State: , Alaska (LAT/LONG): avation (RKS): API #: Hilcorp Energy Company Composite Report Spud Date: Job Name: 1811484C END 4-26A Completion Contractor Innovation AFE #: 1811484C AFE $: $1.472.984 ActIYjty Date Ops Summary 8/20/2018 Circulate and condition mud weighting up from 10.3 to 10.5 while rotate and recip pipe @ 14,005'-13,952' MD. 540 gpm, 2800 psi, 150 rpm, 17k tq, 11 3 ECD. 301 k up, 170k dn, 209k rot. Saw 586 pressure drop on standpipe psi @ 06:20 ms. Shut in Geo Span and troubleshoot surface equipment (good). Continue circulating @ reduced rate. Psi continue falling, MWD RPM's reduced from 3300 to 2200 on tools. Flow out remained.,Reduced rotary RPM's from 150 to 80 along with flow rate in to 500 gpm to help minimize excessive tq and psi on drill string. Assumed washout in string. 10.5 In/ 10.3 Out (Est top of 10.5 mud in annulus 8580' MD, 249 bbls in annulus),Rack back two stands to get above LCU/K2B. Monitor well @ 13,860' (static). PIT surface equip to 3k (good). RIH clean to 14,005' and spot 50 bbls liner running pill on btm to above HRZ (20 ppb steel seal, 5.5% lube, 6 ppb baratrol, 6 ppb berate 515).,POOH on elevators clean F/ 14,005'to 13,184' MD. Pump out F/ 13,184' to 12,874' MD @ 350 gpm, 685 psi while inspecting stands for washout. Stop pumping out and pull on elevators F/ 12,874'to 7650' MO clean without issue. Broke circulation @ 10,866 but continued to show decreasing psi and slower RPM at 540 gpm than during drilling interval. Cont POOH. Repeat @ 7950' w/same results. Found washout @ 7560'. C/O jt.,Circulate after changing out bad jt on std 114. Saw normal psi and MWD rpms (3300+/-). WOT rep (Josh Cheshier) onsite to investigate potential cause of 3rd washout. See "0" drive for pics. Continue to POOH to 6832' with no issues.,POOH from 6832'to 5811'. From 5811'to 5563' backream out of hole getting 3 x bottoms up at 11 bpm/1560 psi, 20 rpms/2500 ft -lbs. Stop rotating as jars go through window. No issues.,Continue to POOH from 5563' to 5366', no issues as BHA comes through window -Monitor well, 1 bph static loss rate. Pump dry job and POOH laying down drill pipe from 5355' to 460'. Monitor well, static.,UD BHA. Inline stabilizer 3/16" undergauge. Plug in MWD and download. Continue to UD BHA.,Daily Fluid Hauled to MP G&I: 0 bbls Total Fluid Hauled to MP G&I: 4,867 bbls Daily Fluid Hauled to ORT:0 bbls Total Fluid Hauled to ORT: 580 bbls Daily Fluid Hauled to GPB G&I: 173 bbls Total Fluid Hauled to GPB G&I: 173 bbls,Daily H2O from Duck Lake: 0 bbls Total H2O from Duck Lake: 5,540 bbls Daily Metal Collected: 0 Lbs Total Metal Collected: 466 Lbs Daily Fluid Lost to Formation: 74.6 bbls Total Fluid Lost to Hole: 103.5 bbls 8121/2018 Continue Download MWD. UD MWD, B/O bit and UD Geo -Pilot. Bit grade - 1,1,CT,T,X,I,BU,TD. No notable damage to BHA.,Clean and clear rig floor.,Service Rig. Grease blocks, TOS, Drawworks.,C/0 upper pipe rams to 7" fixed body. Pull wear ring. Set test plug and RILDS. Fill and purge BOP stack. Test upper 7" pipe rams 250/4000. Test annular w/ 7" fast it 250/2500 Chart and record same. RID test equipment. Pull test plug and set 9" ID wear ring, RILDS.,R/U Volant CRT, double stack power tongs and air slips. M/U bail extensions and 250T side door elevators. 234 total jts 7" in shed. Flashlight float equipment and verify running order.,PJSM, M/U 7" shoe track. Bakerlok same. Circulate thru and check floats (good). Run 7" TXP BTC, 26#, L-80 F/ surface to 2389'. Install 2 centralizers per joint first 11 joints, then 1 centralizer per joint.,Confinue running 7" TXP BTC casing as per detail from 2389' to 5330'. Installing bowspring centrix centralizer ever joint to joint 88. 92 centralizers ran.,Establish circulation at 1 bpm and stage up to 5 bpm/430 psi. Circulate annular volume. Obtain parameters ROTW 125K, SOW 137K, PUW 142K,Continue running 7" TXP BTC casing as per detail from 5330'to 7500'. Start observing 5-10K drag at 7409.,Establish circulation 1 bpm/300 psi, slowly stage up to 5 bpm ICP 635 psi, FCP 555 psi. Circulate 1.5x annular volume, observe mud weights up to 10.85 ppg coming outwith 10.5 ppg going in. Circulate until even mud weights 10.5 ppg.,Con5nue running 7" TXP BTC casing as per detail from 75001 to 8713'. Observe 10-15K drag. Correct hole fill.,Circulate and condhion hole prior to picking up liner hanger. Stage pumps up to 4 bpm/700 psi.,Daily Fluid Hauled to MP G&I: 0 bbls Total Fluid Hauled to MP G&1:4,867 bbls Daily Fluid Hauled to ORT: 0 bbls Total Fluid Hauled to ORT: 580 bbls Daily Fluid Hauled to GPB G&I: 58 bbls Total Fluid Hauled to GPB G&I: 231 bbls,Daily H2O from Duck Lake: 0 bbls Total H2O from Duck Lake: 5,540 bbls Daily Metal Collected: 0 Lbs Total Metal Collected: 466 Lbs Daily Fluid Lost to Formation: 12.7 bbls 8/22/2018 Circulate and condition mud while roVrecip @ 8713' MD. 210 gpm/700 psi. RID csg elevators, bail extensions, remove air slips, and install dp elevators. 140k dn. 185k up. 10.5 MW In/Out. Circ 1 csg vol.,Rig down volant CRT. M/U HRDE ZXHD Baker liner hanger w/ dual plug latch assy & RIH T/ 8745' MD. Pour pal mix in tieback sleeve. PUW 215K, SOW 156K.,RIH with 7" TXP, 26# liner on 5" NC50, 5-135 drill pipe, drifting out of derrick (3.15" O.D) from8745"o. 9,990' MD. Fill and wash down pipe every 10 stands.,Circulate open hole volume @ 9,990' MD staging up to 3.5 bpm/840 psi, 34%flow.,Cont RIH with 7" TXP, 26# liner on 5" NC50, S-135 drill pipe, drifting out of derrick (3.15" O.D) from 9990'to 11,904' MD. Fill and wash down pipe every 10 stands.,Circulate open hole volume @ 11,904' MD staging up to 3.5 bpm/840 psi, 34% flow. Max gas observed 271U. Full returns.,Continue to RIH wfth T' 26# TXP liner on 5" drill pipe, drifting out of derrick from 11,904' to 13,608 filling pipe every 10 stands. PUW 350K, SOW158K. 20-30 fpm running speed. Saw 5-10k drag @ 13,608 MD.,Wash down staging up to 2 bpm/940 psi from 13,606 to 13,668'. Set down 30K, packing off. Work pipe from 430K up (13,644' max up depth) to 135K down varying pump rate.,Continue circulating hole working pack off issues. Attempting to stage pumps up @ 2 bpm / 680 psi -750 psi packed off. Re- establish circulation at 1 bpm 450-600 psi, unable to stage pumps up any further without packing off.,Wash 7" 26# TXP liner down from 13,668' at 1 bpm 450 psi, working pack offs. Work pipe down to 120K hookload and breaking over at 320-360K. Wash down to 13,720' packed off. No losses. MW in 10.35, MW out 10.85 ppg. Max gas 808U.,Attempt to regain circulation working pipe up to 440K without breaking over and down to 115K. Attempt to establish rotary with torque limiter set at 14 Kft-lbs stalled out, increase limit to 19Kft-lbs still stalled out. Work pipe with torque and 600 psi trapped pressure. No losses. Obtain circulation at 0.75 -1 bpm/500 psi.,Continue washing down from 13,720'to 13,800', 1 bpm 450 psi, packing off. Work pipe down to 115K or until packing off and breaking over at 310 to 350K. Packed off at 13,800, no circulation holding 500 psi no losses. Max gas 630U. M W in 10.35, MW out 10.55 ppg.,Attempt to regain circulation working pipe up to 440K without breaking over and down to 115K. Attempt to establish rotary with torque limiter set at 14 Kft-lbs stalled out, increase limit to 19Kft-lbs still stalled out. Work pipe with torque and 500 psi trapped pressure. No losses. Work pipe down with intermittent 1-3 rpms gaining 0.75-1 bpm/500 psi (limiter set).,Wash and ream T'26# TXP liner from 13,800'to 13,955' at 1 bpm/500 psi (limiter set point), with intermittent 1-3 rpms torque limit set at 19,000 ft-Ibs.,Daily Fluid Hauled to MP G&I: 0 bbls Total Fluid Hauled to MP G&I: 4,867 bbls Daily Fluid Hauled to ORT: 0 bbls Total Fluid Hauled to ORT: 580 bbis Daily Fluid Hauled to GPB G&I: 57 bbls Total Fluid Hauled to GPB G&I: 288 blols Daily Fluid Hauled to Pad 3: 290 bbls Total Fluid Hauled to Pad 2: 290 bbls,Daily H2O from Duck Lake: 110 bbls Total H2O from Duck Lake: 5,650 blols Daily Metal Collected: 0 Lbs Total Metal Collected: 466 Lbs Daily Fluid Lost to Formation: 6.7 bbls Total Fluid Lost to Hole: 122.9 bbis 8/23/2018 Wash and ream 7" 26# TXP liner from 13,955'to TO @ 14,005' at 1 bpm/500 psi (limiter set point), with intermittent 1-3 rpms torque limit set at 19,000 ft- Ibs.,Work 7" TXP liner F/ 14,005' up to 13,982' MD establishing circulation. Initially had 10.3 in 110.6+ out. Did have 10.31n/Out @ 12:30 hrs. 680 units max gas and slowly trending down thru out tour 340 bgg. Significant amounts of stalls and packoffs thru out tour. Use various parameters to free pipe and establish circulation, max tq 22k, 430k max up, 90k max on, 700 psi max packoff psi.,160k do and 290k up when pipe is free. Rot and recip pipe F/ 14,005 up to 13,988' MD. Staged pumps up slowly eventually circulating @ 2.5 bpm, 555 psi, 27% flow. Lost circulation while working tight hole.,Work to re-establish circulation but only able to establish intermittent flow w/ max rate 1 bpm. Continue seeing packoff issues and rotary stalls when attempting to work pipe and or circulate. Max packoff psi 650, max tq 19k, 430k max up, 100k max dn.,Work pipe with minimal flow rate 1/2 bpm, 22k tq and find free point where we were able to rotate @ 18.9k tq, 3-5 rpm, .3 bpm, 250 psi. Continue staging pumps up while working free pipe F/ 14,000'to 13,884'. Stage pumps up to 1.25 bpm/350 psi at 1 spm increments with intermittent 1-5 rpms. Pack off.,Work pipe attempting to regain circulation with max pull 340K up, intermittent 1-3 rpms in downstroke 15Kft-lbs up to stall outs at 19Kft-lbs. Establish circulation at 0.4 bpm/224 psi.,Conflnue to work 7" TXP liner attempting to stage circulation up up to 1.25 bpm ]420 psi with frequent pack offs working pipe up to 13,982' (380K) and down to 14,000' with and without torque/rotary. Increase pump rate in upstroke, decrease in downstroke. BGG 300 U. MW inlout 10.3 ppg.,Work pipe from 13,984'to 14,000' with no torque/rotary. Working pack off issues. At 14,000' stage pumps up to 1.25 bpm/325 psi prior to packing off. Work pipe up to 13,978' with 440K up weight. Continue varying parameters, attempt to rotate. Intermittent 1-3 rpms/18,000 ft -lbs. Appears to pack off more often with rotaryttorque.,Set pipe at 14,000' establish circulation at 0.5 bpm/200 psi, increase rate by 0.25 every 15 minutes in two stages. Able to obtain 1 bpm/260 psi, while staging up to 1.2 bpm packed off. Re-establish rotary and continue working pipe. Max pump rate 1.43 bpm/350 psi. Clean SOW 182 K, PUW 270K. Max Gas 648U,Daily Fluid Hauled to MP G&I: 0 bbls Total Fluid Hauled to MP G&I: 4,867 bbls Daily Fluid Hauled to ORT: 0 bbls Total Fluid Hauled to ORT: 580 bbls Daily Fluid Hauled to GPB G&I: 57 blots Total Fluid Hauled to GPB G&l: 288 bbls Daily Fluid Hauled to Pad 3: 290 bbls Total Fluid Hauled to Pad 2: 290 bbis,Daily H2O from Duck Lake: 130 bbis Total H2O from Duck Lake: 5,780 bbls Daily Metal Collected: 0 Lbs Total Metal Collected: 466 Lbs Daily Fluid Lost to Formation: 8 bbls Total Fluid Lost to Hole: 130.9 bbis a/24=18 Work tight hole F/ 14,001 - T/ 13,982' MD. Establish circulation @ 1.3 bpm, 320 psi, 15% flow. Recip pipe slowly putting 7" liner shoe on depth @ 13,998' MD (deep as we could before seeing packing off issues).,Shut down pumps. B/O and UD working single from string. M/U 15' & 5' drill pipe pups. WU BOT rotating dual cmt head. M/U cmt lines and valves. Secure same.,Stage pumps back up to 1.3 BPM without any packing off issues. New circ psi 322 w/ 17% flow. 697u max gas, 360u bgg.,Turnoverto HES cmtrs PJSM, Wet lines w/ 5 bbis H2O and P/T lines, 1000/4500 psi (good), 22.7 bbis 10.5 spacer, Drop 1st dart, batch cmt @ 15:27 hrs. Pump 40 bbis 14.5 ppq class "G" cmt 0 1.7 bpm fcp 60 17%Flow, Drop 2nd dart, pump 20 bbls H2O @ 1.7 bpm, 60 psi, 17% flow., Turnover to rig for displacement.,Displace cmt w/ 10.3 LSND mud using MP #2 (96% pump output--.062) 1.3 bpm, 2040 psi, 17% flow. Saw 1 st dart land on wiper plug and shear @ 435 stks, 1780 psi. Packed off wellbore due to surge from shearing plug from LRT. Work pipe for next 50 mins and re- established minimal circulation @ .25-.4 bpm. Continue working pipe and started seeing progress w/ flow rate, slowly work pipe up/dn w/ and without rotation.,Saw 2nd dart on seat @ 1184 stks. Psi up 2040, saw stall for several seconds before 2nd dart sheared top plug from liner running tool. Continue working pipe and pumps seeing progress attempting to work rate up. Observe multiple oackoffs from 0.7 - 1bom. slow pumps down to good rate/pressure while working pipe when packing off. Achieve 1.1 bpm at 449 psi.,At 4100 strokes into displacement hole began packing off. Slow pumps down and work pipe attempting to clear packoff, slow pumps down to 0.25 bpm1420 psi still packing off. Bleed pressure and start pumping 3-4spm 400-500 psi still appears to be packing off. Work rate up to 0.5 bpm 650-700 psi. Work rate up in stages to 1.1 bpm with pressure maintaing 650-700 psi. Starting to pack off, slow rale to 0.75 bpm.,at 5175 strokes with 80 bbis left to displace pressure starts building. Continue to work pipe and adjust pumps. Pressure up to 1000 psi. Bleed pressure and pump 0.5 bpm, pressure continues to build with no returns. Bleed pressure and set limit at 1250 psi. Unable to obtain circulation. CIP at 01:45. Est. TOC 11,900' in T' casing. Discuss options with town.,Rig up testing equipment. Slack off down to 90K, pick up to 230K up weight. Pressure up to 3100 psi to set liner han_g_e_r_,_sTa_cR_o7g0Kto confirm. Hold 3100 psi for 30 minutes to test liner- good. Continue to pressure up to 3900 psi to release. Pick up to confirm release. Broke over at 137K. Pressure up to 500 psi and continue picking up, observe pressure drop when pack-off pulls free. Est. TOL at 5254'.,Lay down cement head. Breakout pup joints below. Blow down cement Iines.,Pump 1 standout of the hole to confirm clear of liner top and rack back. Install wiper ball. Circulate pipe clean at 12 bpm/680 psi. PUW 130K, SOW 130K.,Daily Fluid Hauled to MPG&l: 50 bbis Total Fluid Hauled to MP G&1:4,917 bbls Daily Fluid Hauled to ORT:0 bbls Total Fluid Hauled to ORT: 580 bbis Daily Fluid Hauled to GPS G&1: 0 bbis Total Fluid Hauled to GPB G&1:288 bbis Daily Fluid Hauled to Pad 3: 0 bbls Total Fluid Hauled to Pad 3: 290 bbls,Daily H2O from Duck Lake: 130 bbis Total H2O from Duck Lake: 5,910 bbis Daily Metal Collected: 0 Lbs Total Metal Collected: 466 Lbs Daily Fluid Lost to Formation: 8.8 bbls 8/25/2018 Continue to circulate pipe clean at 5178'; 12 bpm/680 psi. PUW 130K, SOW 130K.,Slip and cut 96' of drilling line. Inspect brakes.,POOH from 5178' to surface, standing back 24 stands of drill pipe (84 stands total in derrick) and laying down remainder excess drill pipe. Break down and lay down liner running tool.,Change UPR from 7" solid body to 2-7/8" x 5-1/2" VBR's.,Pull wear ring. Set test plug. Fill stack. Rig up test joint. Test UPR, annular, UPR on 4" TJ, test UPR on 5" test joint to 25014000p5i. Test TIW and dart.,Rig down test equipment. Breakdown test joint. Pull test plug. Set wear ring, RILDS (4).,Rig up floor and mobilize BHA components to floor, check ID's, OD's and Iengths.,M/U BHA: 6-1/8" Varel tricone bit, 5" straight Halliburton mud motor, Float sub, (2) DC, XO, (2) HWDP.,RIH with cleanout BHA, single in the hole drifting and picking up and drifting 4" drill pipe from shed from 270'to 8812'; filling pipe every 3000'. PUW 138K, SOW 110K. (2) 34K bobbles seen entering liner top.,Daily Fluid Hauled to MP G&I: 50 bbis Total Fluid Hauled to MP G&I: 4,917 bbis Daily Fluid Hauled to ORT: 0 bbis Total Fluid Hauled to ORT: 580 bbls Daily Fluid Hauled to GPB G&I: 0 bbis Total Fluid Hauled to GPB G&1: 288 bbis Daily Fluid Hauled to Pad 3: 0 bbis Total Fluid Hauled to Pad 3: 290 bbls,Daily H2O from Duck Lake: 0 bbis Total H2O from Duck Lake: 5,910 bbis Daily Metal Collected: 0 Lbs Total Metal Collected: 466 Lbs Daily Fluid Lost to Formation: 8.8 bbis 8/26/2018 Continue TIH w/ 4!'x 5" tapered string F/ 8812'- T/ 11,530' MD on 5" DP out of derrick. Tag w/ 5k @ 11,530' MD.,Obtain parameters. 135k dn, 200k up, 148k rot. 350 gpm, 2940 psi off, 3100 psi on, 52% flow, 5-10k wob, 40 rpm, 8.6k tq. Drill hard cmt F/ 11,530'- T/ 12 287' MD. Wiper plug rubber back @ btms up. Pump hi vis sweeps at 11,740'(0% increase), 11,970 (25%), and 12,165' (0%).,Continue drilling hard cement from 12,287' to 12,497'; 375 gpm, 3350 psi on (100 -150 psi diff), 52% flow, 40 rpms/8500 ft-lbs, WOB 5-10K, ROP 150-175 psi. Broke through cement at 12,487'. Continue washing and reaming down to 13,360' with no WOB or diff pressure. Pump high vis sweep at 12,413'(10% increase).,RIH on elevators from 13360'to 13786, set down 10k. Pickup, establish circulation 375 gpm/3400 psi, rotary 40 rpms/9000 ft-lbs. Continue washing and reaming chasing junk down to landing collar at 13,870' (on depth). Drill plug and landing collar with WOB 5K, 375 gpm/3450 psi 40 rpms/10.8Kft-lbs to 13,873'.,Continue washing and reaming down from 13,873' to float collar at 13,955' (on depth). Drill float collar with WOB 3k, 375 gpm, 40-150 psi diff pressure, 40 rpms/12Kft-lbs to 13,957'. Continue to wash and ream to 13987', no WOB or diff pressure. Pick up single and RIH tagging shoe at 13,999' wfth 2K.,Pump high vis sweep (0% increase in cuttings) and circulate hole clean, reciprocating pipe, 375 gpm/3550 psi, 40 rpms/12Kft-lbs. Flow check, static.,POOH from 13987'to 13,651'. Pump dryjob, blow down top drive. Continue to POOH on elevators to 10,393'. PUW 179K, SOW 124K. Proper displacement fortrip.,Daily Fluid Hauled to MPG&I: 171 bbis Total Fluid Hauled to MPG&I: 5,086 bbis Daily Fluid Hauled to ORT:0 bbls Total Fluid Hauled to ORT: 580 bbis } �- Daily Fluid Hauled to GPB G&I: 0 bbis Total Fluid Hauled to GPB G&1:288 bbis Daily Fluid Hauled to Pad 3: 0 bbis Total Fluid Hauled to Pad 3: 290 bbls,Daily H2O from Duck Lake: 140 bbis Total H2O from Duck Lake: 6,050 bbis Daily Metal Collected: 0 Lbs Total Metal Collected: 466 Lbs Daily Fluid Lost to Formation: 0 bbis Total Fluid Lost to Hole: 139.7 bbis 8/27/2018 Continue to POOH with cleanout assembly from 10,393! to 2500'. PUW 75K. Proper displacement for trip.,Sewice rig; top drive, blocks, crowns. Inspect tugger brakes. Knock ice off derrick.,Continue to POOH from 2500' racking back stands and HWDP to 89'.,UD BHA, (2) DC, float sub, mud motor and bit. Flush water through motor. Bit grade 1-1-I-E.,Make up CIBP as per BOT and RIH to 13,346', 100 fpm in 9-5/8" casing and 90 fpm in 7" casing turning to left 1 rotation every 30001 to prevent setting early as per BOT. PUW 243K, SOW 153K. Proper displacement for trip.,Pick up single and set CIBP on depth 13 357 (top of CIBP at 13,350'). Set CIBP as per BOT: Pickup to up weight and 3'. Rotate 14 turns, slack off to setting depth. Pickup and overpull 35K, slack off 40K x2. Set. Pickup 2K over and rotate 14 turns to release from CIBP. Tag top with 3K at 13,359. Lay down working single. Monitor well, static. Pump dry job.,POOH with CIBP setting tool from 13,350'to 2515' PUW 67K, SOW 67K. Proper displacement during trip.,Daily Fluid Hauled to MPG&1: 0 bbis Total Fluid Hauled to MP G&1:5,088 bbls Daily Fluid Hauled to ORT: 0 bbis Total Fluid Hauled to ORT: 580 bbis Daily Fluid Hauled to GPB G&I: 0 bbis Total Fluid Hauled to GPB G&1:288 bbis Daily Fluid Hauled to Pad 3:0 bbis Total Fluid Hauled to Pad 3:290 bbls,Daily H2O from Duck Lake: 0 bbis Total H2O from Duck Lake: 6,050 bbis Daily Metal Collected: 0 Lbs Total Metal Collected: 466 Lbs Daily Fluid Lost to Formation: 0 bbis Total Fluid Lost to Hole: 139.7 bbis 8/28/2018 Continue to POOH 1/2516to surface. UD CIBP running tool. CIBP Set @ 13,350'.,Rig up Pollard E -Line. RIH with 5' x 3-1/8", 22 grain, 6 SPF, 60 deg Phasing Perfgun. Tag Top of CIBP. Log CCL and fire guns. Top Shot @ 13,320'/Btm Shot @ 13326. (Shot Diameter .42"). POOH to surface all shots fired. R/D Pollard E-Line.,M/U BOT Retrievamatic Packer. TIH with PKR to 5355'.Set PKR as Per BOT Rep. Up Wt 115, Dn Wt 115. Set On 30K to confirm set.,Establish Circulation below PKR through Perfs. staging pumps: .50 bpm/270 1 bpm/375 psi, 1.5 bpm/450 psi, 2 bpm/540 psi, 2.5 bpm/l000 psi, 3 bpm/1700 psi. Shut down pumps. PU and Release Packer elements, leaving slips engaged. Pump and spot 10 bbis 300 visc pill above PKR @ 5355'to TOL @ 5255', to prevent debris from falling in ontop of PKR while Circ and condition hole. Reset packer. Establish circulation staging up.,to 3 bpm, packing off. Slow pump rate to 2 bpm and attempt to stage back up to 3 bpm fighting packoffs.,Continue circulating at 2 bpm ICP 1330 psi FCP 1220 psi with packoffs up to 1420 psi. Stage pumps up once pressure stabilized at 1220 psi up to 2.5 bpm ICP 1335 psi, packing off. Slow rate back to 2 bpm pressure stabilized at 1220 psi with one pack off. Stage up to 2.12 bpm 1230 psi no pack offs. Stage up to 2.25 bpm packing off. Finish circulating 2.5X open hole volume at 2 bpm 1150 psi. Max Gas 788U.,Unseat packer. Pump high vis pill up the hole 30 bbis while pulling above liner hanger to 5235'.,Pump 20 bbis high vis spacer (no increase) and circulate hole clean at 101ppm/1045 psi. Monitor the well, stafic.,Cut and slip drilling line 69' of drilling line while monitoring well on trip tank.,POOH with Baker Retrievamatic packer and UD. Proper hole fill.,MIU Baker K-1 cement retainer as per BOT rep, RIH 100 fpm to 4528', observe proper displacement. PUW/SOW 88K.,Daily Fluid Hauled to MP G&1:57 bbis Total Fluid Hauled to MP G&1:5,145 bbis Daily Fluid Hauled to ORT: 0 bbis Total Fluid Hauled to ORT: 580 bbls Daily Fluid Hauled to GPB G&I: 0 bbis Total Fluid Hauled to GPB G&I: 288 bbis Daily Fluid Hauled to Pad 3:0 bbis Total Fluid Hauled to Pad 3: 290 bbls,Daily H2O from Duck Lake: 280 bbis Total H2O from Duck Lake: 6,330 bbis Daily Metal Collected:0 Lbs Total Metal Collected: 466 Lbs Daily Fluid Lost to Formation:0 bbis Total Fluid Lost to Hole: 139.7 bbis 8/29/2018 Continue TIH w/Cmt retainer f/4528' to 13,275'. No issue passing through TOL. Up Wt 240K, Dn Wt 148K,MU Cement Head. Set CMT Retainer as per BOT Rep @ 13,275'. Pull 25K Over, set Dn 30K & confirm set. Release f/Retainer. Sting back in and set 30K Dn. RU 2" circulating Hose.,Establish circulation staging pumps to 2 bpm/690 psi. Attempt to reach 3 bpm but started packing off @ 2.5 bpm. Continue circulate 2 bpm while holding PJSM with no Pack off i sues.,Pump Cement: Flood lines w/ 3 bbis Spacer. PIT lines 100014300 psi. Batch up 20.5 bbis, 15.8 Premium G Cement. GQ45ump remaining 7 bbis 10.5 ppg Spacer. Pump 100 sxs (20.5 bbis) Primary Cement at 15.8 ^oo Displace omt w/5 bbis spacer and 10 bbis FW f/ Cmt Unit. Rig Pump 152.7 bbis, 10.3 ppg mud @ 2 bpm. FCP = 950 @ 1 bpm. Come Down on pump holding 450 psi, un sting from retainer and see pressure drop. CIP @ 16:20 hrs.,L/D Cement Head. Drop foam Wiper Ball and circulate STS @ 10 bpm/3000 psi. Slight PH increase @ bottoms up but no cement.,POOH from 13252'to surface. LID cement retainer running tool as per BOT rep. Proper hole fill.,Sewice rig: grease washpipe, top drive, blocks and crown.,Pick up BHA: 6-1/8" Varel tricone, 5" mud motor with 0 bend, float sub with solid float, (2) DC. Kelly up and pump through motor.,RIH with cement cleanout assembly from 89'to 6863' filling pipe every 3000'. PUW 120K SOW 105K. observe proper hole fill,Daily Fluid Hauled to MP G&1:25 bbis Total Fluid Hauled to MP G&I: 5,170 bbis Daily Fluid Hauled to ORT: 0 bbis Total Fluid Hauled to ORT: 580 bbis Daily Fluid Hauled to GPB G&I: 0 bbis Total Fluid Hauled to GPB G&1: 288 bbis Daily Fluid Hauled to Pad 3:0 bbls,Daily H2O from Duck Lake: 190 bbis Total H2O from Duck Lake: 6,520 bbis Daily Metal Collected:0 Lbs Total Metal Collected: 466 Lbs Daily Fluid Lost to Formation:0 bbis Total Fluid Lost to Hole: 139.7 bbis 8/30/2018 Continue to RIH with cleanout assembly filling pipe every 3000' from 6863'to 13,171' on elevators. Obtain parameters, PUW 240, SOW 152 ROTW 168. 35 rpms/10Kft-lbs, 370 gpm/3250 psi. Wash down from 13,171' and tag top of retainer at 13,275'.,DHII cement retainer from 13,275'to 13,277' with WOB 5-15K, 330 gpm/2850 psi. Continue to wash and ream down to 13,34T and tag CIBP/junk. Continue drilling varying parameters WOB 5-20K, 310 - 370 gpm. Attempt to break up CIBP setting down with no rotary or pumps. Observe some diff pressure but weight not drilling off, torque decreasing. Drill down to 13,348'.,Stand back one stand. Monitor well, static. Pump dry job. Blow down top drive.,POOH from 13,28T PUW 248 to 89'. Rack back HWDP. Observe proper hole fill.,UD drill collars, mud motor and Bit. Bit 5-3-BT-1116,Service rig, top drive, blocks and crown.,M/U cleanout BHA #2 to 102'; 6-1/8" Hycalog RT4GP roller cone, new mud motor, double pin sub, (2) junk baskets, bit sub, (2) DC. Check OD/ID length of junk baskets/bit sub/double pin. M/U XO and top drive. Pump through motor - good.,Daily Fluid Hauled to MP G&I: 57 bbls Total Fluid Hauled to MP G&I: 5,227 bbls Daily Fluid Hauled to ORT:0 bbis Total Fluid Hauled to ORT: 580 bbis Daily Fluid Hauled to GPB G&1: 0 bbis Total Fluid Hauled to GPB G&I: 288 bbis Daily Fluid Hauled to Pad 3:0 bbls,Daily H2O from Duck Lake: 0 bbis Total H2O from Duck Lake: 6,520 bbls Daily Metal Collected: 0 Lbs Total Metal Collected: 466 Lbs Daily Fluid Lost to Formation: 0 bbls I Total Fluid Lost to Hole- 139 7 blols 8/31/2018 Continue to RIH with cleanout assy #2 to 13,244'. PUW 147 K, SOW 154K. Proper displacement. Wash and ream from 13,244'to CIBP at 13,349'312 gpm12760 psi.,Drill CIBP varying parameters from 200-300 gpm/1400-1920 off bottom psi with 100-600 psi diff pressure. WOB 3-23K, 20-40 rpms/l0.5 - 11.5Kft-lbs of torque. Stack 10-20K down with no pumps or rotary multiple times in attempt to break CIBP up. Drill CIBP up down to 13,351'. Work through stand with and without pumps - clean.,RIH to 13,999' (previous tag depth) and set down 4K, did not see anything during trip. PUW 260 SOW 155,Pump sweep and circulate hole clean at 8 bpm/3100 psi, 20 rpms/l0600 ft -lbs reciporcating pipe. Monitor well, static.,POOH with cleanout assembly from 13970' to 13,737'. Pump dryjob. Continue to POOH to 9962' PUW 172K, SOW 122K,Daily Fluid Hauled to MP G&I: 0 bbis Total Fluid Hauled to MP G&I: 5,227 bbis Daily Fluid Hauled to ORT: 0 bbls Total Fluid Hauled to ORT: 580 bbis Daily Fluid Hauled to GPB G&I: 0 bbis Total Fluid Hauled to GPB GU 288 bbls Daily Fluid Hauled to Pad 3:0 bbls,Daily H2O from Duck Lake: 140 bbis Total H2O from Duck Lake: 6,660 bbis Daily Metal Collected: 0 Lbs Total Metal Collected: 466 Lbs Daily Fluid Lost to Formation: 0 bbis Total Fluid Lost to Hole: 139.7 bbls 9/1/2018 Continue TOH F/9962'to 280'. Observed proper hole fill on TT. Encounter 8K over pull @ 5270' while pulling through liner top PKR. Slack off and rotate pipe 180 deg, ease through top of liner with no further issues.,Rack back 4"HWDP. UD Flex Collars, boot baskets. Milk and LID Mud Mir. Bit Graded DBR. Recovered 81bs debris from boot baskets. Clean and Clear rig Floor.,Pull 9" ID Wear Bushing.,MU 4" Test A w/HT-38 Dart/TIW & UD Same. MU 5" Test Aw/4 1/2" IF Oari/TIW. Flood Lines.,Test all ROPE components 25014000 psi with 4" and 5" test joint. AOGCC right to witness waived by Adam Earl via email. Accumulator drawdown: starting pressure 3250 psi, final 1600 psi. 1st 200 recharge 23 seconds, full recharge 97 seconds. 6N2 bottles @2300 psi average.,Break down test joints. Rig down test equipment. Clean and clear rig floor.,PJSM. Rig up Pollard E -Line with Halliburton CBUCAST. Halliburton surface test CAST tool - good.,RIH with CAST/CBL on E -line to 5600', log up to get free pipe log. Continue to RIH to 8113',Unable to obtain clean signal from CAST tool. Troubleshoot. Suspect power supply not clean enough interferring with signal. Swap to backup battery. Attempt to put tool into'log' mode crashes program. Restart program and reconfigure tools. Still crashing program. Change to a new'database'still crashing. POOH to 7100' where good signal was previously obtain. Swap to primary battery and reconfgure.Able to obtain clean enough signal with primary battery.,Confinue to RIH with CAST/CBL on E -Line to 13969, motor on CAST stalled out. Pick up and get motor spinning. Perform repeat log from 13959to 13673',Daily Fluid Hauled to MP G&I: 151 bbis Total Fluid Hauled to MP G&I: 5,378 bbis Daily Fluid Hauled to ORT:0 bbis Total Fluid Hauled to ORT: 580 bbls Daily Fluid Hauled to GPB G&1: 0 bbls Total Fluid Hauled to GPB G&1:288 bbis Daily Fluid Hauled to Pad 3:0 bbls,Daily H2O from Duck Lake: 0 bbis Total H2O from Duck Lake: 6,660 bbis Daily Metal Collected: 0 Lbs Total Metal Collected: 466 Lbs Daily Fluid Lost to Formation: 0 bbis Total Fluid Lost to Hole: 139.7 bbis 912/2018 Continue to log CBUCAST from 13969to TOW @ 5411'. Ease through Liner top and POOH. Rig Down E -Line. SIMOPS: Off load mud in pits. Set pit liner & mats for sub on next well. Crane heater off roof -MU PKR Setting w/Doa Sub. TIH to 5252'. PUW 132K, SOW 135K.,Set Down 70K and see PKR set. Pressure test Liner top PKR and 9 5/8" Casing to 3000 psi on chart for 30 minutes Test Good.,Cut/Slip Drill line 100' of drilling line, inspecting line past cut- good. n Calibrate drum/block position. Service rig: monthly inspection on crown sheave, grease top drive, blocks, spinners. Remount dolly extend sensor.,POOH with W ./� packer setting tool on elevators. UD packer setting tool,Clean and clear dg floor. Rig up to RIH with 4" drill pipe, add inserts on elevators. PJSM,Pick up CIBP and RIH to 8796'. Enter TOL with no issues. Change out handling equipment from 4" to 5". Continue to RIH with 5" drill to 9,812'.,Daily Fluid V pipe pipe Hauled to MP G&I: 679 bbls Total Fluid Hauled to MP GU 6,057 bbis Daily Fluid Hauled to ORT: 0 bbis Total Fluid Hauled to ORT: 580 bbis Daily Fluid Hauled to GPB G&1:0 bbis Total Fluid Hauled to GPB G&I: 288 bbis Daily Fluid Hauled to Pad 3:0 bbls,Daily H2O from Duck Lake: 140 bbis Total H2O from Duck Lake: 6,800 bbis Daily Metal Collected: 0 Lbs Total Metal Collected: 466 Lbs Daily Fluid Lost to Formation: 0 bbis 913/2018 Continue to TIH with CIBP f/9812'to set depth @ 13995'. PUW 246K, SOW 163K. Encounter 9K Set On @ 13960' (Drilled up Float Collar Depth) Work past Float collar with 2 bpm. No further issues running to set depth @ 13,996. Set CIBP as per BOT Rep. Top of CIBP @ 13,993'. UD Working single.,R/U circulating hose. Circulate drill string volume @ 10 bpm/3280 psi. Close annular and test 7" Liner to 1500 psi to top of CIBP @ 13,993'. Chart for 30 min. Test good.,Displace well from mud to 8.6 ppg Brine; pump 40 bbis high viscosity spacer followed by 870 bbis seawater at 7.5 bpm ICP 2480 FCP 1180. Shutdown and clean surface equipment. Displace well to filtered 3% KCL 8.6 ppg brine at 7.5 bpm/1180 psi.,Monitor well, static. POOH laying down 5" drill pipe PUW 262K, SOW 145K from 13973'to 87991. Correct hole fli.,Sewice rig. Grease top drive.,Change out pipe handling equipment to 4" and continue POOH with drill pipe from 8799'to surface. UD CIBP running tool.,Pull wear bushing. Flush stack, mud pumps, choke, top drive and poor boy with freshwater. Clean and clear rig floor.,Rig up Weatherford handling equipment, power tongs, torque turn.,Daily Fluid Hauled to MP G&I: 1621 bbis Total Fluid Hauled to MP G&1: 7,678 bbls Daily Fluid Hauled to ORT:0 bbis Total Fluid Hauled to ORT: 580 bbis Daily Fluid Hauled to GPB G&I: 0 bbls Total Fluid Hauled to GPB G&I: 288 bbis Daily Fluid Hauled to Pad 3: 0 bbls,Daily H2O from Duck Lake: 140 bbis Total H2O from Duck Lake: 6,940 bbis Daily Metal Collected: 0 Lbs Total Metal Collected: 466 Lbs Daily Fluid Lost to Formation: 0 bbls Total Fluid Lost to Hole: 139.7 bbis 9/4/2018 Finish rigging up Weatherford torque turn Equip. and test. Load completion jewelry in Pipe Shed. SIMOPS CIO hydraulic Press, switch on top drive.,Weatherford trouble shoot turn counter on Power Tongs. C/O Power Tongs with back up set. Tested good.,PJSM Torque turn all connections to an average of 6,750 Ib. WU 5" WLEG, 7joints 4.5" 12.6#, 13CR-80, JFE Bear Tubing, X/N Nipple, 1 joint 4.5" Tubing, AHR Packer, 1 Joint 4.5" Tubing, X Nipple, 14 joints 4.5" Tubing, GLM Special Clearance 1" Dummy Valve at 988' MD. Cont to RIH 4.5" Tubing 2,895' MD add in GLM Special Clearance 1" Dummy Valve.,Cont. to RIH 4.5" Tubing to 6,707' add GLM Special Clearance 1" Dummy Valve. RIH to 7,226' MD-PJSM Torque turn all connections to an average of 6,750 lb. RIH 4.5" 12.6#, 13CR-80, JFE Bear Tubing F/ 7,226' MD to 8,377' add GLM MMG 1.5" Dummy Valve. RIH 4.5" Tubing to 9,735' MD add GLM MMG 1.5" SOV Annular to Tubing. RIH 4.5" Tubing to 12,094' MD. PIU 151 K SLK 103K,PJSM for rigging up and P/U SSSV. Bring sheave, pipe clamps and spooler to rig floor. M/U SSSV and control line. Test control line to 6,100 PSI for 15 Min as per SLB Rep onsite.,Cont. RIH 4.5" Tubing and Control line F/ 12,094' MD to 13,566' MD. Torque turn and use Clear Glide pipe dope. Total 38 Cannon Clamps, 76 Cannon Clamp Pins. No Losses. PIU 170K, SLK 110K.,C/O elevators to 5" manuals. P/U M/U Landing joint and Hanger. M/U Hanger to the string. Terminate SSSV line and run in Hanger as per SLB and NOS Rep onsite. RID Weatherford tools and Equip.,Daily Fluid Hauled to MP G&I: 518 bbls Total Fluid Hauled to MP G&1:8,196 bbis Daily Fluid Hauled to ORT: 0 bbis Total Fluid Hauled to ORT: 580 bbis Daily Fluid Hauled to GPB G&I: 0 bbls Total Fluid Hauled to GPB G&I: 288 bbis Daily Fluid Hauled to Pad 3: 0 bbls,Daily H2O from Duck Lake: 140 bbls Total H2O from Duck Lake: 7,080 bbls Daily Metal Collected: 0 Lbs Total Metal Collected: 466 Lbs Daily Fluid Lost to Formation: 0 bbis Total Fluid Lost to Hole: 139.7 bbis 9/5/2018 Continue terminating SSSV control line through Tbg Hgr && test same. Slack off and stop 2' above Tbg Head. PUW 170K, SOW 113K.,R/1-I and Pump 125 bbis of Corrosion inhibited 8.5 ppg brine off truck @ 3 bpm/250 psi. Chase w/203 bbis filtered brine from pits and spot Corrosion inhibited brine from 13604' to 7000'-Dram Stack, Land Tbg Hgr, RILDS. Drop Ball and Rod, let fall 20 minutes. Attempt to pressure up, getting returns up IA. Pump 25 bbls with no success landing ball. Reverse circulate 30 bbis @ 2 bpm and spot inhibited brine back in place. Wait 15 minutes and pump 50 bbls trying to seat ball with no success. Call out Slick line to chase ball on seat. Reverse circulate Inhibited brine back in place.,R/D SLB Control line sheave and tools while W/O Slick line.,PJU Halliburton Slick Line. RIH with Slick line wl3" Gauge Ring and Knuckle Jts. POOH and set Slick line aside.,PT Tubing to 3000 Psi for 30 minutes on Chart. Step Pressure to 4500 psi and set PKR. Bleed Tbq to 1500 Psi. PT IA to 3000 Psi for 30 minutes on chart. Bleed off tubing and see SOV Shear. Bleed tuboing and IA to zero. RID test equipment. Pull and UD Landing Jt.,NOS Installed TWC in Well.,PJSM for N/D BOPE. Bleed of Koomey, remove bell nipple, RID Choke and Kill lines, un-Flange BOPE and rack back on stump. Secure BOPE.,PJSM WU Tree as per NOS Rep onsite. Test void to 5,000 PSI for 10 Min. Rig up and test Tree to 5,000 PSI for 10 Min. on chart. All witnessed by Co Rep onsite. SIMOPS R/U bridle lines to scope Derrick. Make final clean on Pits. RID MP # 1 & 2. Inspect and C/O fluid end expendables as needed.,PJSM for Freeze Protect, SLB Press. SSSV to 4,500 PSI to open. R/U LRS and test lines to 3,000 PSI for 5 Min. LRS Freeze Protect well with 103 bbl Diesel at 2 bpm 205 PSI. Shut down and shut in well. RID LRS. M/U U Tube line from IA to Tubing. Open well and let Diesel U Tube.,PJSM Prep and scope down Derrick. RID Mezz interconnects and mud lines. RID Cutting box. Blow down water lines. Cont. with MP #1 & 2. Prep Pipe Shed, all rig roofs, chain down HAL tool box and Smoke Shack.,Daily Fluid Hauled to MP G&I:0 bbls Total Fluid Hauled to MP G&I: 8,196 bbls Daily Fluid Hauled to ORT: 0 bbis Total Fluid Hauled to ORT: 580 bbls Daily Fluid Hauled to GPB G&I: 0 bbls Total Fluid Hauled to GPB G&I: 0 bbis Daily Fluid Hauled to Pad 3: 0 bbls,Daily H2O from Duck Lake: 0 bbis Total H2O from Duck Lake: 7,080 bbis Daily Metal Collected:0 Lbs Total Metal Collected: 466 Lbs Daily Fluid Lost to Formation: 0 bbls Total Fluid Lost to Hole: 139.7 bbis 9/8/2018 PT PCE 250psi LOW - 2,500psi HIGH (pass) PULL BALL & ROD ASSEMBLY FROM RHC-M @ 13,299' SLM PULL STA.#4 BK-DGLV FROM 6,887' SLM (6,900' MD) PULL STA15 RK-DGLV FROM 5,208' SLM (5,2171 MD 9/92018 PT PCE 250psi LOW - 2,OOOpsi HIGH (pass) Set GL valves. PULL RHC-M PLUG BODY FROM XN-NIP @ 13,303' SLM (13,307' MD) DRIFT TO TO 13 997' SLM W/ 20'x 3.50" DUMMY PERF GUN no obstruction /u weight is 950#lbs, on btm 9/10/2018 IPTPCE2501-P-3250HP. RUN PRESS/TEMP SURVEY AND CALCULATE BHP TO PERFORATE 500# UNDERBALANCED. PERFORATE FROM 13953'- 13973' RKB WITH 3.126'X 20' GUN LOADED 6 SPF, 60 DEG PHASING. CCL STOP DEPTH 13,945.2' CCL TO TOP SHOT 7.8' TOP SHOT STOP DEPTH' 13 953' RKB. Hilcorp Alaska, LLC Duck Island Unit End SDI 4-26A 500292183500 Sperry Drilling Definitive Survey Report 24 August, 2018 HALLIBURTON Sperry Drilling Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well 4-26 Project: Duck Island Unit TVD Reference: SDI 4-26A Actual @ 40.90usft (Innovation) Site: End SDI MD Reference: SDI 4-26A Actual @ 40.90usft (Innovation) Well: 4-26 North Reference: True Wellbore: 4-26A Survey Calculation Method: Minimum Curvature Design: 4-26A Database: Sperry EDM - NORTH US + CANADA project Duck Island Unit, North Slope, UNITED STATES dap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level 3eo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point dap Zone: Alaska Zone 03 Using geodetic scale factor Well 4-26,4-2610-34 Well Position +N/ S 0.00 usft Northing: +E/.W 0.00 usft Easting: Position Uncertainty 0.00 usft Wellhead Elevation: Wellbore 4-26A Magnetics Model Name BGGM2018 Design 4-26A Audit Notes: Version: 1.0 Vertical Section: Sample Date 7/15/2018 5,970,808.75 usft Latitude: 70° 19' 18.742 N 270,300.99 usft Longitude: 147° 51'45.138 W 13.90 usft Ground Level: 13.90 usft Declination 17.55 Phase: ACTUAL Depth From (TVD) +N/ -S (usft) (usft) 27.00 0.00 Dip Angle (°) Field Strength (nT) 81.04 57,461 Tie On Depth: 5,399.20 +E/ -W Direction (usft) (I 0.00 7.48 Survey Program Date 8/21/2018 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 36.20 5,399.20 1 : Schlumberger GCT multishot (4-26) 2_Gyro-NS-CT_OWSG A021 Ga: Continuous gyro in casing 08/03/1988 5,411.00 5,469.00 Survey #2 (4-26A) 2_Gyro-NS-GC_Drill coil: H029Ga: North seeking single shot in drill colla 08/06/2018 5,493.26 5,684.95 MWD+Interp Azi+sag(4-26A) 2_MWD_Interp Azi+Sag H003Mb: Interpolated azimuth+ sag correction 07/28/2018 5,747.50 13,945.70 MWD+IFR2+MS+sag (4-26A) 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +sa 08/07/2018 Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +E/ -W Northing Easting DLS Section (usft) (I (I (usft) (usft) (usft) (usft) (ft) (ft) (°1700') (ft) Survey Tool Name 27.00 0.00 0.00 27.00 -13.90 0.00 0.00 5,970,808.75 270,300.99 0.00 0.00 UNDEFINED 36.20 0.18 202.76 36.20 -4.70 -0.01 -0.01 5,970,808.74 270,300.98 1.96 -0.01 2 Gyro-NS-CT_OWSG(1) 38.40 0.18 203.87 38.40 -2.50 -0.02 -0.01 5,970,808.73 270,300.98 0.16 -0.02 2_Gyro-NS-CT_OWSG(1) 59.70 0.32 233.77 59.70 18.80 -0.09 -0.07 5,970,808.67 270,300.92 0.88 -0.09 2_Gyro-NS-CT_OWSG(1) 68.40 0.37 244.18 68.40 27.50 -0.11 -0.11 5,970,808.64 270,300.87 0.92 -0.13 2_Gyro-NS-CT_OWSG(1) 84.80 0.47 259.16 84.80 43.90 -0.15 -0.23 5,970,808.61 270,300.76 0.90 -0.18 2_Gyro-NS-CT_OWSG(1) 101.20 0.52 266.54 101.20 60.30 -0.16 -0.37 5,970,808.60 270,300.62 0.49 -0.21 2_Gyro-NS-CT_OWSG(1) 117.60 0.53 272.29 117.60 76.70 -0.17 -0.52 5,970,808.60 270,300.47 0.33 -0.23 2_Gyro-NS-CT_OWSG(1) 134.10 0.53 275.74 134.10 93.20 -0.16 -0.67 5,970,808.61 270,300.31 0.19 -0.24 2_Gyro-NS-CT_OWSG(1) 150.50 0.48 277.78 150.50 109.60 -0.14 -0.81 5,970,808.64 270,300.17 0.32 -0.24 2_Gyro-NS-CT_0WSG(1) 167.00 0.43 281.25 167.00 126.10 -0.12 -0.94 5,970,808.66 270,300.04 0.35 -0.24 2_Gyro-NS-CT_OWSG(1) W4/2018 6:35:09PM Page 2 COMPASS 5000.1 Build 81E Company: Hilcorp Alaska, LLC Project: Duck Island Unit Site: End SDI Well: 4-26 Wellbore: 4-26A Design: 4-26A Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well 4-26 SDI 4-26A Actual @ 40.90usft (Innovation) SDI 4-26A Actual @ 40.90usft (Innovation) True Minimum Curvature Sperry EDM - NORTH US + CANADA Map Vertical Easting DLS Section (ft) Map MD Inc Azi TVD TVDSS +NIS +EI -W Northing (usft) (1 (') (usft) (usft) (usft) (usft) (ft) 183.50 0.45 281.24 183.50 142.60 -0.09 -1.07 5,970,808.69 200.00 0.45 277.79 200.00 159.10 -0.07 -1.20 5,970,808.72 216.50 0.47 273.58 216.49 175.59 -OA6 -1.33 5,970,808.73 233.00 0.42 269.00 232.99 192.09 -0.06 -1.46 5,970,808.74 249.50 0.38 265.39 249.49 208.59 -0.06 -1.57 5,970,808.74 266.00 0.33 263.78 265.99 225.09 -0.07 -1.67 5,970,808.73 282.50 0.28 262.04 282.49 241.59 -0.08 -1.76 5,970,808.72 299.10 0.25 261.89 299.09 258.19 -0.09 -1.84 5,970,808.71 315.60 0.18 269.14 315.59 274.69 -0.10 -1.90 5,970,808.71 332.10 0.13 289.27 332.09 291.19 -0.09 -1.94 5,970,808.72 348.30 0.15 311.18 348.29 307.39 -0.07 -1.97 5,970,808.74 364.60 0.22 313.33 364.59 323.69 -0.04 -2.01 5,970,808.78 380.90 0.25 304.48 380.89 339.99 0.01 -2.06 5,970,808.82 397.20 0.25 297.82 397.19 356.29 0.04 -2.13 5,970,808.86 413.40 0.27 291.51 413.39 372.49 0.07 -2.19 5,970,808.89 429.70 0.27 286.05 429.69 388.79 0.10 -2.27 5,970,808.92 446.00 0.27 278.01 445.99 405.09 0.11 -2.34 5,970,808.94 462.30 0.27 269.06 462.29 421.39 0.12 -2.42 5,970,808.94 478.60 0.25 261.98 478.59 437.69 0.11 -2.49 5,970,808.94 494.90 0.22 255.80 494.89 453.99 0.10 -2.56 5,970,808.93 511.10 0.20 251.51 511.09 470.19 0.08 -2.61 5,970,808.91 527AO 0.20 249.47 527.39 486.49 0.06 -2.67 5,970,808.90 543.60 0.18 242.51 543.59 502.69 0.04 -2.72 5,970,808.88 559.90 0.15 235.51 559.89 518.99 0.02 -2.76 5,970,808.85 576.20 0.12 230.89 576.19 535.29 0.00 -2.79 5,970,808.83 592.40 0.10 226.66 592.39 551.49 -0.02 -2.81 5,970,808.81 608.70 0.10 225.40 608.69 567.79 -0.04 -2.83 5,970,808.79 625.00 0.08 221.05 624.99 584.09 -0.06 -2.85 5,970,808.77 641.20 0.07 202.14 641.19 600.29 -0.08 -2.86 5,970,808.76 657.50 0.05 170.24 657.49 616.59 -0.10 -2.86 5,970,808.74 673.70 0.05 141.00 673.69 632.79 -0.11 -2.86 5,970,808.73 690.00 0.05 111.92 689.99 649.09 -0.12 -2.84 5,970,808.72 706.30 0.08 86.82 706.29 665.39 -0.12 -2.83 5,970,808.72 722.50 0.10 69.40 722.49 681.59 -0.11 -2.80 5,970,808.72 738.80 0.10 33.24 738.79 697.89 -0.10 -2.78 5,970,808.74 755.00 0.10 356+42 754.99 714.09 -0.07 -2.77 5,970,808.76 771.30 0.10 344.35 771.29 730.39 -0.04 -2.78 5,970,808.79 787.60 0.10 336.26 787.59 746.69 -0.02 -2.79 5,970,808.82 803.80 0.10 325.85 803.79 762.89 0.01 -2.80 5,970,808.84 820.10 0.13 317.23 820.09 779.19 0.03 -2.82 5,970,808.87 Well 4-26 SDI 4-26A Actual @ 40.90usft (Innovation) SDI 4-26A Actual @ 40.90usft (Innovation) True Minimum Curvature Sperry EDM - NORTH US + CANADA Map Vertical Easting DLS Section (ft) (°/1001) (ft) Survey Tool Name 270,299.92 0.12 -0.23 2_Gyro-NS-CT_OWSG(1) 270,299.79 0.16 -0.23 2_Gyro-NS-CT0WSG(1) 270,299.66 0.24 -0.23 2_Gyro-NS-CT_OWSG(1) 270,299.53 0.37 -0.24 2_Gyro-NS-CT_OWSG(1) 270,299.42 0.29 -0.26 2_Gyro-NS-CT_OWSG(1) 270,299.32 0.31 -0.29 2_Gyro-NS-CT_OWSG(1) 270,299.23 0.31 -0.31 2_Gyro-NS-CT_OWSG (1) 270,299.15 0.18 -0.33 2_Gyro-NS-CT_0WSG(1) 270,299.09 0.45 -0.34 2_Gym-NS-CT_OWSG(1) 270,299.05 0.44 -0.34 2_Gyro-NS-CT_OWSG(1) 270,299.01 0.35 -0.33 2_Gyro-NS-CT_OWSG(1) 270,298.98 0.43 -0.30 2 -Gyro -NS -CT OWSG (1) 270,298.93 0.29 -0.26 2_Gyro-NS-CT_OWSG(1) 270,298.87 0.18 -0.23 2_Gyro-NS-CT_OWSG(1) 270,298.80 0.22 -0.21 2_Gy10-NS-CT_0WSG(1) 270,298.73 0.16 -0.20 2_Gyro-NS-CT_OWSG(1) 270,298.65 0.23 -0.19 2_Gym-NS-CT_OWSG(1) 270,298.58 0.26 -0.20 2_Gyro-NS-CT_OWSG(1) 270,298.50 0.23 -0.21 2_Gyro-NS-CT_OWSG(1) 270,298.44 0.24 -0.23 2_Gyro-NS-CT_OWSG(1) 270,298.38 0.16 -0.26 2_Gyro-NS-CT_OWSG(1) 270,298.33 0.04 -0.28 2_Gyro-NS-CT_0WSG(1) 270,298.28 0.19 -0.31 2_Gyro-NS-CT_OWSG(1) 270,298.24 0.22 -0.34 2_Gyro-NS-CT_OWSG(1) 270,298.20 0.20 -0.37 2_Gyro-NS-CT_OWSG(1) 270,298.18 0.13 -0.39 2_Gyro-NS-CT_OWSG(1) 270,298.16 0.01 -0.41 2_Gym-NS-CT_OWSG(1) 270,298.14 0.13 -0.43 2_Gyro-NS-CT_OWSG(1) 270,298.13 0.16 -0.45 2_Gyro-NS-CT OWSG(1) 270,298.13 0.23 -0.47 2_Gyro-NS-CT_OWSG(1) 270,298.13 0.16 -0.48 2_Gyro-NS-CT_OWSG(1) 270,298.14 0.15 -0.49 2_Gyro-NS-CT_OWSG(1) 270,298.16 0.25 -0.49 2_Gyro-NS-CT_OWSG(1) 270,298.19 0.21 -0.48 2_Gyro-NS-CT_OWSG(1) 270,298.21 0.38 -0.46 2_Gyro-NS-CT_OWSG(1) 270,298.21 0.39 -0.43 2_Gyro-NS-CT_OWSG (1) 270,298.21 0.13 -0.40 2_Gyro-NS-CT_OWSG(1) 270,298.20 0.09 -0.38 2_Gyro-NS-CT_OWSG(1) 270,298.19 0.11 -0.36 2_Gyro-NS-CT_OWSG(1) 270,298.17 0.21 -0.33 2_Gyro-NS-CT_OWSG(1) 8242018 6:35:09PM Page 3 COMPASS 5000.1 Build 81E Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Project: Duck Island Unit TVD Reference: Site: End SDI MD Reference: Well: 4-26 North Reference: Wellbore: 4-26A Survey Calculation Method: Design: 4-26A Database: Survey Well 4-26 SDI 4-26A Actual @ 40.90usft (Innovation) SDI 4-26A Actual @ 40.90usft (Innovation) True Minimum Curvature Sperry EDM - NORTH US + CANADA Vertical Section (ft) Survey Tool Name -0.31 2_Gyro-NS-CT_OWSG (1) -0.29 2_Gyro-NS-CT_OWSG(1) -0.28 2_Gyro-NS-CT_OWSG(1) -0.27 2_Gyro-NS-CT_OWSG(1) -0.27 2_Gyro-NS-CT_0WSG(1) -0.28 2_Gyro-NS-CT_OWSG(1) -0.28 2_Gyr-NS-CT_OWSG(1) -0.29 2_Gyro-NS-CT_OWSG(1) -0.30 2_Gyro-NS-CT_OWSG(1) -0.31 2_Gy10-NS-CT_0WSG (1) -0.31 2_Gym-NS-CT_OWSG (1) -0.32 2_Gyro-NS-CT_OWSG(1) -0.31 2_Gyro-NS-CT_OWSG (1) -0.29 2_Gyro-NS-CT_OWSG(1) -0.25 2_Gyro-NS-CT_OWSG(1) -0.21 2_Gyro-NS-CT_OWSG (1) -0.15 2_Gyro-NS-CT_OWSG(1) -0.09 2_Gyro-NS-CT_OWSG(1) -0.02 2_Gyro-NS-CT_OWSG(1) 0.05 2_Gyro-NS-CT_OWSG(1) 0.12 2_Gyro-NS-CT_OWSG(1). 0.19 2_Gyro-NS-CT_OWSG(1) 0.25 2_Gyro-NS-CT_OWSG(1) 0.30 2 Gyro-NS-CT_OWSG(1) 0.35 2_Gyro-NS-CT_OWSG(1) 0.39 2_Gyro-NS-CT_OWSG(1) 0.41 2_Gyro-NS-CT_0WSG (1) 0.44 2_Gyro-NS-CT_OWSG(1) 0.46 2_Gyro-NS-CT_0WSG(1) 0.47 2_Gyro-NS-CT_OWSG(1) 0.48 2_Gyro-NS-CT_0WSG(1) 0.49 2 Gyro-NS-CT_OWSG(1) 0.50 2_Gyro-NS-CT_OWSG(1) 0.50 2_Gyro-NS-CT_OWSG(1) 0.50 2_Gyro-NS-CT_OWSG(1) 0.50 2_Gyro-NS-CT_OWSG (1) 0.50 2_Gyro-NS-CT_OWSG(1) 0.51 2_Gyro-NS-CT_OWSG (1) 0.52 2_Gyro-NS-CT_OWSG(1) 0.53 2_Gyro-NS-CT_OWSG(1) 8242018 6:35:09PM Page 4 COMPASS 5000.1 Build 81E Map Map MD Inc Azi TVD TVDSS +N/ -S +El -W Northing Easting DLS (usft) (1) (1) (usft) (usft) (usft) (usft) (ft) (ft) ('1100') 836.40 0.15 308.48 836.39 795.49 0.06 -2.85 5,970,808.90 270,298.14 0.18 852.60 0.15 299.16 852.59 811.69 0.08 -2.89 5,970,808.92 270,298.11 0.15 868.90 0.15 290.69 868.89 827.99 0.10 -2.93 5,970,808.94 270,298.07 0.14 885.10 0.12 280.64 885.09 844.19 0.11 -2.96 5,970,808.95 270,298.03 0.24 901.40 0.08 268.36 901.39 860.49 0.12 -2.99 5,970,808.96 270,298.00 0.28 917.70 0.05 264.49 917.69 876.79 0.11 -3.01 5,970,808.96 270,297.99 0.19 934.00 0.05 247.88 933.99 893.09 0.11 -3.02 5,970,808.95 270,297.97 0.09 950.20 0.03 224.09 950.19 909.29 0.11 -3.03 5,970,808.95 270,297.96 0.16 966.50 0.03 190.03 966.49 925.59 0.10 -3.04 5,970,808.94 270,297.96 0.11 982.80 0.03 150.16 982.79 941.89 0.09 -3.03 5,970,808.93 270,297.96 0.13 999.10 0.05 129.37 999.09 958.19 0.08 -3.03 5,970,808.92 270,297.97 0.15 1,015.40 0.07 105.75 1,015.39 974.49 0.08 -3.01 5,970,808.92 270,297.98 0.19 1,031.70 0.10 74.41 1,031.69 990.79 OA8 -2.99 5,970,808.92 270,298.01 0.33 1,048.00 0.15 50.24 1,047.99 1,007.09 0.09 -2.96 5,970,808.93 270,298.04 0.44 1,064.30 0.18 40.17 1,064.29 1,023.39 0.13 -2.93 5,970,808.97 270,298.07 0.26 1,080.60 0.22 35.17 1,080.59 1,039.69 0.17 -2.89 5,970,809.01 270,298.11 0.27 1,096.90 0.23 32.39 1,096.89 1,055.99 0.23 -2.86 5,970,809.06 270,298.14 0.09 1,113.20 0.25 30.35 1,113.19 1,072.29 0.28 -2.82 5,970,809.12 270,298.18 0.13 1,129.40 0.25 28.26 1,129.39 1,088.49 0.35 -2.79 5,970,809.18 270,298.22 0.06 1,145.60 0.27 24.46 1,145.59 1,104.69 0.41 -2.75 5,970,809.25 270,298.25 0.16 1,161.60 0.27 19.45 1,161.59 1,120.69 0.48 -2.72 5,970,809.31 270,298.28 0.15 1,177.70 0.23 11.35 1,177.69 1,136.79 0.55 -2.71 5,970,809.38 270,298.30 0.33 1,193.70 0.20 3.67 1,193.69 1,152.79 0.61 -2.70 5,970,809.44 270,298.31 0.26 1,209.80 0.17 2.51 1,209.79 1,168.89 0.66 -2.69 5,970,809.49 270,298.32 0.19 1,225.90 0.15 4.76 1,225.89 1,184.99 0.70 -2.69 5,970,809.54 270,298.32 0.13 1,242.00 0.12 0.89 1,241.99 1,201.09 0.74 -2.69 5,970,809.57 270,298.32 0.19 1,258.00 0.08 356.28 1,257.99 1,217.09 0.77 -2.69 5,970,809.60 270,298.32 0.25 1,274.10 0.08 0.35 1,274.09 1,233.19 0.79 -2.69 5,970,809.62 270,298.32 0.04 1,290.10 0.07 11.88 1,290.09 1,249.19 0.81 -2.69 5,970,809.65 270,298.33 0.11 1,306.20 0.05 21.77 1,306.19 1,265.29 0.83 -2.68 5,970,809.66 270,298.33 0.14 1,322.20 0.02 10.65 1,322.19 1,281.29 0.84 -2.68 5,970,809.67 270,298.34 0.19 1,338.30 0.03 6.17 1,338.29 1,297.39 0.85 -2.68 5,970,809.68 270,298.34 0.06 1,354.30 0.02 6.13 1,354.29 1,313.39 0.85 -2.68 5,970,809.68 270,298.34 0.06 1,370.40 0.00 344.56 1,370.39 1,329.49 0.86 -2.68 5,970,809.69 270,298.34 0.12 1,386.40 0.00 280.94 1,386.39 1,345.49 0.86 -2.68 5,970,809.69 270,298.34 0.00 1,402.50 0.00 290.78 1,402.49 1,361.59 0.86 -2.68 5,970,809.69 270,298.34 0.00 1,418.60 0.02 11.83 1,418.59 1,377.69 0.86 -2.68 5,970,809.69 270,298.34 0.12 1,434.60 0.05 54.77 1,434.59 1,393.69 0.87 -2.67 5,970,809.70 270,298.35 0.24 1,450.70 0.10 78.38 1,450.69 1,409.79 0.87 -2.65 5,970,809.70 270,298.37 0.36 1,466.80 0.13 79.02 1,466.79 1,425.89 0.88 -2.62 5,970,809.71 270,298.40 0.19 Vertical Section (ft) Survey Tool Name -0.31 2_Gyro-NS-CT_OWSG (1) -0.29 2_Gyro-NS-CT_OWSG(1) -0.28 2_Gyro-NS-CT_OWSG(1) -0.27 2_Gyro-NS-CT_OWSG(1) -0.27 2_Gyro-NS-CT_0WSG(1) -0.28 2_Gyro-NS-CT_OWSG(1) -0.28 2_Gyr-NS-CT_OWSG(1) -0.29 2_Gyro-NS-CT_OWSG(1) -0.30 2_Gyro-NS-CT_OWSG(1) -0.31 2_Gy10-NS-CT_0WSG (1) -0.31 2_Gym-NS-CT_OWSG (1) -0.32 2_Gyro-NS-CT_OWSG(1) -0.31 2_Gyro-NS-CT_OWSG (1) -0.29 2_Gyro-NS-CT_OWSG(1) -0.25 2_Gyro-NS-CT_OWSG(1) -0.21 2_Gyro-NS-CT_OWSG (1) -0.15 2_Gyro-NS-CT_OWSG(1) -0.09 2_Gyro-NS-CT_OWSG(1) -0.02 2_Gyro-NS-CT_OWSG(1) 0.05 2_Gyro-NS-CT_OWSG(1) 0.12 2_Gyro-NS-CT_OWSG(1). 0.19 2_Gyro-NS-CT_OWSG(1) 0.25 2_Gyro-NS-CT_OWSG(1) 0.30 2 Gyro-NS-CT_OWSG(1) 0.35 2_Gyro-NS-CT_OWSG(1) 0.39 2_Gyro-NS-CT_OWSG(1) 0.41 2_Gyro-NS-CT_0WSG (1) 0.44 2_Gyro-NS-CT_OWSG(1) 0.46 2_Gyro-NS-CT_0WSG(1) 0.47 2_Gyro-NS-CT_OWSG(1) 0.48 2_Gyro-NS-CT_0WSG(1) 0.49 2 Gyro-NS-CT_OWSG(1) 0.50 2_Gyro-NS-CT_OWSG(1) 0.50 2_Gyro-NS-CT_OWSG(1) 0.50 2_Gyro-NS-CT_OWSG(1) 0.50 2_Gyro-NS-CT_OWSG (1) 0.50 2_Gyro-NS-CT_OWSG(1) 0.51 2_Gyro-NS-CT_OWSG (1) 0.52 2_Gyro-NS-CT_OWSG(1) 0.53 2_Gyro-NS-CT_OWSG(1) 8242018 6:35:09PM Page 4 COMPASS 5000.1 Build 81E Halliburton Definitive Survey Report Company: Project: Site: Well: Wellbore: Design: Hilcorp Alaska, LLC Duck Island Unit End SDI 4-26 4-26A 4-26A Local Coordinate Reference: Well 4-26 TVD Reference: SDI 4-26A Actual @ 40.90usft (Innovation) MD Reference: SDI 4-26A Actual @ 40.90usft (Innovation) North Reference: True Survey Calculation Method: Minimum Curvature Database: Sperry EDM - NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +FJ -W Northing Easting DLS Section (usft) (1 (1) (usft) (usft) (usft) (usft) (ft) (ft) (°1100-) (ft) Survey Tool Name 1,482.80 0.15 75.93 1,482.79 1,441.89 0.89 -2.58 5,970,809.72 270,298.44 0.13 0.54 2_Gyro-NS-CT_OWSG(1) 1,498.90 0.20 70.86 1,498.89 1,457.99 0.90 -2.54 5,970,809.73 270,298.48 0.32 0.56 2_Gyro-NS-CT_OWSG(1) 1,515.00 0.22 68.38 1,514.99 1,474.09 0.92 -2.48 5,970,809.75 270,298.54 0.14 0.59 2_Gyro-NS-CT_OWSG(1) 1,531.00 0.27 66.13 1,530.99 1,490.09 0.95 -2.42 5,970,809.77 270,298.60 0.32 0.63 2 Gyro-NS-CT_OWSG(1) 1,547.10 0.33 63.47 1,547.09 1,506.19 0.98 -2.34 5,970,809.81 270,298.68 0.38 0.67 2_Gyro-NS-CT_OWSG(1) 1,563.20 0.40 60.59 1,563.19 1,522.29 1.03 -2.25 5,970,809.85 270,298.77 0.45 0.73 2_Gyro-NS-CT_OWSG(1) 1,579.20 0.45 58.40 1,579.19 1,538.29 1.09 -2.15 5,970,809.91 270,298.88 0.33 0.80 2_Gyro-NS-CT_OWSG(1) 1,595.30 0.48 58.06 1,595.29 1,554.39 1.16 -2.04 5,970,809.97 270,298.99 0.19 0.89 2 -Gyro-NS-CT OWSG (1) 1,611.40 0.52 57.42 1,611.39 1,570.49 1.24 -1.92 5,970,810.04 270,299.11 0.25 0.98 2 Gyro-NS-CT_OWSG(1) 1,627.50 0.58 56.01 1,627.49 1,586.59 1.32 -1.79 5,970,810.13 270,299.24 0.38 1.08 2_Gyro-NS-CT_OWSG(1) 1,643.60 0.67 55.33 1,643.58 1,602.68 1.42 -1.64 5,970,810.22 270,299.39 0.56 1.19 2_Gyro-NS-CT_OWSG(1) 1,659.70 0.75 55.31 1,659.68 1,618.78 1.53 -1.48 5,970,810.33 270,299.56 0.50 1.33 2_Gyro-NS-CT_OWSG(1) 1,675.70 0.82 55.11 1,675.68 1,634.78 1.66 -1.30 5,970,810.45 270,299.74 0.44 1.48 2_Gyro-NS-CT_OWSG(1) 1,691.80 0.85 53.59 1,691.78 1,650.88 1.80 -1.11 5,970,810.58 270,299.94 0.23 1.64 2_Gyro-NS-CT_0WSG(1) 1,707.90 0.92 51.31 1,707.88 1,666.98 1.95 -0.91 5,970,810.72 270,300.14 0.49 1.81 2_Gyro-NS-CT_OWSG(1) 1,724.00 0.95 49.19 1,723.98 1,683.08 2.12 -0.71 5,970,810.89 270,300.34 0.28 2.01 2_Gyro-NS-CT_OWSG(1) 1,740.10 0.98 46.87 1,740.07 1,699.17 2.30 -0.51 5,970,811.06 270,300.55 0.31 2.21 2_Gyro-NS-CT_OWSG(1) 1,756.20 1.02 44.48 1,756.17 1,715.27 2.49 -0.31 5,970,811.25 270,300.76 0.36 2.43 2_Gyro-NS-CT_OWSG(1) 1,772.30 1.07 42.76 1,772.27 1,731.37 2.71 -0.11 5,970,811.46 270,300.97 0.37 2.67 2_Gyro-NS-CT_OWSG(1) 1,788.30 1.08 41.12 1,788.27 1,747.37 2.93 0.09 5,970,811.68 270,301.17 0.20 2.92 2_Gyro-NS-CT_OWSG(1) 1,804.50 1.10 39.57 1,804.46 1,763.56 3.16 0.29 5,970,811.90 270,301.38 0.22 3.18 2_Gyro-NS-CT_OWSG(1) 1,820.60 1.10 38.64 1,820.56 1,779.66 3.40 0.49 5,970,812.14 270,301.58 0.11 3.44 2_Gyro-NS-CT_OWSG(1) 1,836.70 1.10 38.27 1,836.66 1,795.76 3.65 0.68 5,970,812.37 270,301.78 0.04 3.70 2_Gyro-NS-CT_OWSG(1) 1,852.80 1.07 38.19 1,852.75 1,811.85 3.89 0.87 5,970,812.61 270,301.98 0.19 3.97 2_Gyro-NS-CT_OWSG(1) 1,868.90 1.05 38.04 1,868.85 1,827.95 4.12 1.05 5,970,812.84 270,302.17 0.13 4.22 2_Gyro-NS-CT_OWSG(1) 1,885.10 1.05 37.58 1,885.05 1,844.15 4.35 1.24 5,970,813.06 270,302.36 0.05 4.48 2_Gyro-NS-CT_OWSG(1) 1,901.20 1.00 37.47 1,901.15 1,860.25 4.58 1.41 5,970,813.29 270,302.54 0.31 4.73 2_Gyro-NS-CT_OWSG(1) 1,917.30 0.93 37.87 1,917.24 1,876.34 4.80 1.58 5,970,813.50 270,302.71 0.44 4.96 2_Gym-NS-CT_OWSG(1) 1,933.40 0.88 38.25 1,933.34 1,892.44 5.00 1.73 5,970,813.69 270,302.88 0.31 5.18 2_Gyro-NS-CT_OWSG(1) 1,949.40 0.83 38.69 1,949.34 1,908.44 5.18 1.88 5,970,813.87 270,303.03 0.32 5.39 2_Gyro-NS-CT_OWSG(1) 1,965.30 0.80 39.17 1,965.24 1,924.34 5.36 2.02 5,970,814.05 270,303.18 0.19 5.58 2_Gyro-NS-CT_OWSG(1) 1,981.20 0.78 39.71 1,981.14 1,940.24 5.53 2.16 5,970,814.21 270,303.32 0.13 5.76 2_Gyro-NS-CT_OWSG(1) 1,997.10 0.78 39.45 1,997.04 1,956.14 5.70 2.30 5,970,814.37 270,303.46 0.02 5.95 2_Gyro-NS-CT_OWSG(1) 2,013.00 0.77 39.55 2,012.93 1,972.03 5.86 2.44 5,970,814.54 270,303.61 0.06 6.13 2_Gym-NS-CT_OWSG(1) 2,028.90 0.77 39.60 2,028.83 1,987.93 6.03 2.57 5,970,814.70 270,303.75 0.00 6.31 2_Gyro-NS-CT_OWSG(1) 2,044.80 0.80 37.78 2,044.73 2,003.83 6.20 2.71 5,970,814.86 270,303.89 0.25 6.50 2_Gyro-NS-CT_OWSG (1) 2,060.70 0.82 38.20 2,060.63 2,019.73 6.37 2.85 5,970,815.03 270,304.03 0.13 6.69 2_Gyro-NS-CT_OWSG(1) 2,076.60 0.78 40.42 2,076.53 2,035.63 6.55 2.99 5,970,815.20 270,304.18 0.32 6.88 2_Gyro-NS-CT_OWSG(1) 2,092.50 0.78 40.93 2,092.43 2,051.53 6.71 3.13 5,970,815.36 270,304.32 0.04 7.06 2_Gyro-NS-CT_OWSG(1) 2,108.40 0.78 41.51 2,108.32 2,067.42 6.87 3.27 5,970,815.52 270,304.47 0.05 7.24 2_Gyro-NS-CT_OWSG(1) W4/2018 6:35:09PM Page 5 COMPASS 5000.1 Build 81E Company: Hilcorp Alaska, LLC Project: Duck Island Unit Site: End SDI Well: 4-26 Wellbore: 4-26A Design: 4-26A Survey MD (usft) 2,124.20 2,140.10 2,156.00 2,171.90 2,187.80 2,203.60 2,219.50 2,235.40 2,251.20 2,267.10 2,283.00 2,298.80 2,314.70 2,330.60 2,346.50 2,362.40 2,378.20 2,394.10 2,410.00 2,425.80 2,441.70 2,457.60 2,473.40 2,489.30 Inc Azi TVD (1) (1) (usft) 0.78 41.48 2,124.12 0.78 40.72 2,140.02 0.80 40.62 2,155.92 0.82 40.54 2,171.82 0.82 38.83 0.78 33.31 0.72 28.78 0.70 28.13 0.70 28.03 0.72 27.69 0.73 27.47 0.73 27.71 0.75 27165 0.77 27.26 0.80 27.74 0.83 28.80 0.85 29.64 0.87 30.29 0.87 30.89 0.87 0.87 0.82 0.82 0.82 30.98 31.38 33.43 34.44 35.35 2,505.20 0.85 36.90 2,521.10 0.90 37.81 2,536.90 0.93 39.84 2,552.80 0.93 42.16 2,568.70 0.92 45.15 2,584.50 2,600.40 2,616.30 2,632.20 2,648.10 2,664.00 2,679.90 2,695.80 2,711.70 2,727.60 2,743.20 0.92 48.37 0.95 50.56 0.95 52.94 0.98 54.84 1.02 53.64 2,187.72 2,203.52 2,219.41 2,235.31 2,251.11 2,267.01 2,282.91 2,298.71 2,314.61 2,330.51 2,346.40 2,362.30 2,378.10 2,394.00 2,409.90 2,425.70 2,441.59 2,457.49 2,473.29 2,489.19 2,505.09 2,520.98 2,536.78 2,552.68 2,568.58 2,584.38 2,600.27 2,616.17 2,632.07 2,647.97 TVDSS (usft) 2,083.22 2,099.12 2,115.02 2,130.92 2,146.82 2,162.62 2,178.51 2,194.41 2,210.21 2,226.11 2,242.01 2,257.81 2,273.71 2,289.61 2,305.50 2,321.40 2,337.20 2,353.10 2,369.00 2,384.80 2,400.69 2,416.59 2,432.39 2,448.29 2,464.19 2,480.08 2,495.88 2,511.78 2,527.68 2,543.48 2,559.37 2,575.27 2,591.17 2,607.07 0.98 52.73 2,663.87 2,622.97 0.98 54.30 2,679.76 2,638.86 0.98 55.88 2,695.66 2,654.76 0.98 56.84 2,711.56 2,670.66 0.98 57.14 2,727.46 2,686.56 0.98 57.48 2,743.05 2,702.15 Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well 4-26 SDI 4-26A Actual @ 40.90usft (Innovation) SDI 4-26A Actual @ 40.90usft (Innovation) True Minimum Curvature Sperry EDM - NORTH US + CANADA 8242018 6:35:09PM Page 6 COMPASS 5000.1 Build 8fE Map Map Vertical +NIS +EI -W Northing Easting DLS Section (usft) (usft) (ft) (ft) ("I100-) (ft) Survey Tool Name 703 3.42 5,970,815.68 270,304.62 0.00 7.42 2_Gyro-NS-CT_OWSG(1) 7.20 3.56 5,970,815.84 270,304.77 0.07 7.60 2 Gyro-NS-CT_OWSG(1) 7.36 3.70 5,970,816.00 270,304.91 0.13 7.78 2_Gyro-NS-CT_OWSG(1) 7.53 3.85 5,970,816.16 270,305.07 0.13 7.97 2_Gyro-NS-CT_OWSG(1) 7.71 3.99 5,970,816.33 270,305.22 0.15 8.16 2_Gyro-NS-CT_OWSG(1) 7.89 4.12 5,970,816.51 270,305.35 0.55 8.36 2_Gyro-NS-CT_OWSG(1) 8.07 4.23 5,970,816.68 270,305.46 0.53 8.55 2 Gyro-NS-CT_OWSG(1) 8.24 4.32 5,970,816.85 270,305.56 0.14 8.73 2_Gyro-NS-CT_OWSG(1) 8.41 4.41 5,970,817.02 270,305.66 0.01 8.91 2_Gyro-NS-CT_OWSG(1) 8.58 4.51 5,970,817.19 270,305.76 0.13 9.10 2_Gyro-NS-CT_OWSG (1) 8.76 4.60 5,970,817.37 270,305.85 0.07 9.29 2_Gyro-NS-CT_OWSG(1) 8.94 4.69 5,970,817.54 270,305.95 0.02 9.48 2 Gyro -NS -CT OWSG(1) 9.12 4.79 5,970,817.72 270,306.05 0.13 9.67 2_Gym-NS-CT_OWSG(1) 9.31 4.88 5,970,817.91 270,306.16 0.13 9.87 2_Gyro-NS-CT_0WSG(1) 9.50 4.99 5,970,818.10 270,306.26 0.19 10.07 2_Gyro-NS-CT_OWSG(1) 9.70 5.09 5,970,818.29 270,306.38 0.21 10.28 2_Gyro-NS-CT_OWSG(1) 9.90 5.21 5,970,818.49 270,306.50 0.15 10.50 2_Gyro-NS-CT_OWSG(1) 10.11 5.32 5,970,818.69 270,306.62 0.14 10.72 2_Gyro-NS-CT_OWSG(1) 10.32 5.45 5,970,818.90 270,306.75 0.06 10.94 2_Gyro-NS-CT_OWSG(1) 10.52 5.57 5,970,819.10 270,306.88 0.01 11.16 2_Gyro-NS-CT_OWSG(1) 10.73 5.70 5,970,819.30 270,307.01 0.04 11.38 2_Gyro-NS-CT_OWSG(1) 10.93 5.82 5,970,819.49 270,307.14 0.37 11.59 2_Gyro-NS-CT_OWSG(1) 11.12 5.95 5,970,819.68 270,307.28 0.09 11.80 2_Gyro-NS-CT_0WSG(1) 11.30 6.08 5,970,819.86 270,307.41 0.08 12.00 2_Gyro-NS-CT_OWSG(1) 11.49 6.21 5,970,820.04 270,307.55 0.24 12.20 2_Gyro-NS-CT_OWSG(1) 11.68 6.36 5,970,820.23 270,307.71 0.33 12.41 2_Gyro-NS-CT_OWSG(1) 11.88 6.52 5,970,820.42 270,307.87 0.28 12.63 2_Gyro-NS-CT_OWSG(1) 12.07 6.69 5,970,820.61 270,308.05 0.24 12.84 2_Gyrc-NS-CT_OWSG(1) 12.26 6.87 5,970,820.79 270,308.23 0.31 13.05 2_Gyro-NS-CT_OWSG(1) 12.43 7.05 5,970,820.96 270,308.42 0.33 13.25 2_Gyro-NS-CT_OWSG(1) 12.60 7.25 5,970,821.12 270,308.62 0.29 13.44 2_Gyro-NS-CT_OWSG(1) 12.77 7.46 5,970,821.28 270,308.83 0.25 13.63 2_Gyro-NS-CT_OWSG(1) 12.92 7.67 5,970,821.43 270,309.05 0.28 13.81 2_Gyro-NS-CT_OWSG(1) 13.09 7.90 5,970,821.59 270,309.28 0.28 14.00 2 -Gyro -NS -CT OWSG (1) 13.25 8.12 5,970,821.75 270,309.51 0.27 14.20 2_Gyro-NS-CT_OWSG(1) 13.41 8.34 5,970,821.90 270,309.73 0.17 14.38 2_Gyro-NS-CT_OWSG (11 13.57 8.56 5,970,822.05 270,309.96 0.17 14.57 2_Gyro-NS-CT_OWSG (1) 13.72 8.79 5,970,822.19 270,310.19 0.10 14.75 2_Gyro-NS-CT_OWSG(1) 13.87 9.02 5,970,822.33 270,310.43 0.03 14.92 2_Gyro-NS-CT_OWSG (1) 14.01 9.24 5,970,822.47 270,310.65 0.04 15.10 2_Gyro-NS-CT_OWSG(1) 8242018 6:35:09PM Page 6 COMPASS 5000.1 Build 8fE Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well 4-26 Project: Duck Island Unit TVD Reference: SDI 4-26A Actual @ 40.90usft (Innovation) Site: End SDI MD Reference: SDI 4-26A Actual @ 40.90usft (Innovation) Well: 4-26 North Reference: True Wellbore: 4-26A Survey Calculation Method: Minimum Curvature Design: 4-26A Database: Sperry EDM - NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +EI -W Northing Easting DLS Section (usft) (1) (1) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 2,758.90 0.98 57.64 2,758.75 2,717.85 14.16 9.47 5,970,822.61 270,310.88 0.02 15.27 2_Gyro-NS-CT_OWSG(1) 2,774.50 0.97 58.14 2,774.35 2,733.45 14.30 9.69 5,970,822.74 270,311.11 0.08 15.44 2_Gyro-NS-CT_OWSG(1) 2,790.20 0.95 58.92 2,790.05 2,749.15 14.43 9.92 5,970,822.87 270,311.34 0.15 15.60 2_Gyro-NS-CT_OWSG(1) 2,805.90 0.95 59.25 2,805.74 2,764.84 14.57 10.14 5,970,823.00 270,311.57 0.03 15.76 2_Gyro-NS-CT_OWSG(1) 2,821.50 0.95 59.51 2,821.34 2,780.44 14.70 10.36 5,970,823.13 270,311.80 0.03 15.92 2_Gyro-NS-CT_OWSG(1) 2,837.20 0.97 59.99 2,837.04 2,796.14 14.83 10.59 5,970,823.25 270,312.03 0.14 16.08 2_Gyro-NS-CT_0WSG(1) 2,852.90 0.98 60.37 2,852.74 2,811.84 14.97 10.82 5,970,823.38 270,312.26 0.08 16.25 2_Gyro-NS-CT_OWSG(1) 2,868.50 0.97 60.93 2,868.34 2,827.44 15.10 11.05 5,970,823.50 270,312.50 0.09 16.41 2_Gyro-NS-CT_OWSG(1) 2,884.20 0.95 63.17 2,884.03 2,843.13 15.22 11.28 5,970,823.62 270,312.73 0.27 16.56 2_Gyro-NS-CT_OWSG(1) 2,899.80 1.02 63.05 2,899.63 2,858.73 15.34 11.52 5,970,823.73 270,312.98 0.45 16.71 2_Gyro-NS-CT_OWSG(1) 2,915.50 1.03 60.51 2,915.33 2,874.43 15.47 11.77 5,970,823.85 270,313.23 0.30 16.87 2_Gyro-NS-CT_OWSG(1) 2,931.10 0.97 61.03 2,930.93 2,890.03 15.61 12.01 5,970,823.98 270,313.47 0.39 17.04 2_Gyro-NS-CT_OWSG(1) 2,946.80 0.97 63.88 2,946.62 2,905.72 15.73 12.24 5,970,824.10 270,313.71 0.31 17.19 2_Gyro-NS-CT_OWSG(1) 2,962.40 0.97 65.79 2,962.22 2,921.32 15.84 12.48 5,970,824.20 270,313.95 0.21 17.33 2_Gyro-NS-CT_OWSG(1) 2,978.00 0.97 66.72 2,977.82 2,936.92 15.95 12.72 5,970,824.30 270,314.20 0.10 17.47 2_Gyro-NS-CT_OWSG(1) 2,993.60 0.95 66.78 2,993.42 2,952.52 16.05 12.96 5,970,824.40 270,314.44 0.13 17.60 2_Gyro-NS-CT_OWSG(1) 3,009.30 0.92 66.36 3,009.12 2,968.22 16.15 13.20 5,970,824.49 270,314.68 0.20 17.73 2_Gyro-NS-CT_OWSG(1) 3,024.90 0.90 67.03 3,024.71 2,983.81 16.25 13.43 5,970,824.58 270,314.91 0.15 17.86 2_Gyro-NS-CT_OWSG(1) 3,040.60 0.93 67.81 3,040.41 2,999.51 16.35 13.66 5,970,824.67 270,315.14 0.21 17.99 2_Gyro-NS-CT_OWSG(1) 3,056.20 0.95 68.25 3,056.01 3,015.11 16.44 13.90 5,970,824.76 270,315.38 0.14 18.11 2_Gyro-NS-CT_OWSG(1) 3,071.90 0.90 71.30 3,071.71 3,030.81 16.53 14.13 5,970,824.84 270,315.62 0.45 18.23 2_Gyro-NS-CT_OWSG(1) 3,087.50 0.97 74.63 3,087.31 3,046.41 16.60 14.38 5,970,824.91 270,315.87 0.57 18.33 2_Gyro-NS-CT_OWSG(1) 3,103.20 1.12 72.93 3,103.00 3,062.10 16.68 14.65 5,970,824.98 270,316.15 0.98 18.45 2_Gyro-NS-CT_OWSG(1) 3,118.80 1.12 70.06 3,118.60 3,077.70 16.78 14.94 5,970,825.07 270,316.44 0.36 18.58 2_Gyro-NS-CT_OWSG(1) 3,134.40 1.12 69.40 3,134.20 3,093.30 16.89 15.23 5,970,825.16 270,316.73 0.08 18.73 2_Gyro-NS-CT_OWSG(1) 3,150.10 1.12 69.78 3,149.89 3,108.99 16.99 15.51 5,970,825.26 270,317.02 0.05 18.87 2_Gyro-NS-CT_OWSG(1) 3,165.70 1.13 70.17 3,165.49 3,124.59 17.10 15.80 5,970,825.36 270,317.31 0.08 19.01 2_Gyro-NS-CT_OWSG(1) 3,181.40 1.17 70.20 3,181.19 3,140.29 17.21 16.10 5,970,825.45 270,317.61 0.25 19.15 2_Gyro-NS-CT_OWSG(1) 3,197.00 1.18 69.75 3,196.78 3,155.88 17.31 16.40 5,970,825.55 270,317.91 0.09 19.30 2_Gyro-NS-CT_OWSG(1) 3,212.70 1.22 69.67 3,212.48 3,171.58 17.43 16.71 5,970,825.66 270,318.22 0.26 19.46 2_Gyro-NS-CT_OWSG(1) 3,228.30 1.22 70.79 3,228.08 3,187.18 17.54 17.02 5,970,825.76 270,318.54 0.15 19.61 2_Gyro-NS-CT_OWSG(1) 3,244.00 1.20 71.19 3,243.77 3,202.87 17.65 17.33 5,970,825.86 270,318.86 0.14 1976 2_Gyro-NS-CT_OWSG(1) 3,259.60 1.20 71.14 3,259.37 3,218.47 17.75 17.64 5,970,825.96 270,319.17 0.01 19.90 2_Gyro-NS-CT_OWSG(1) 3,275.30 1.25 71.59 3,275.07 3,234.17 17.86 17.96 5,970,826.05 270,319.49 0.32 20.05 2_Gyro-NS-CT_OWSG(1) 3,291.00 1.28 71.59 3,290.76 3,249.86 17.97 18.29 5,970,826.15 270,319.82 0.19 20.20 2_Gyro-NS-CT_OWSG(1) 3,306.60 1.32 71.14 3,306.36 3,265.46 18.08 18.63 5,970,826.26 270,320.16 0.26 20.36 2_Gyro-NS-CT_OWSG(1) 3,322.30 1.35 70.69 3,322.05 3,281.15 18.20 18.97 5,970,826.36 270,320.51 0.20 20.52 2_Gyro-NS-CT_OWSG(1) 3,338.00 1.33 71.05 3,337.75 3,296.85 18.32 19.32 5,970,826.47 270,320.86 0.14 20.68 2_Gyro-NS-CT_OWSG (1) 3,353.60 1.32 71.64 3,353.35 3,312.45 18.44 19.66 5,970,826.58 270,321.20 0.11 20.84 2_Gyro-NS-CT_OWSG (1) 3,369.30 1.33 71.46 3,369.04 3,328.14 18.55 20.00 5,970,826.68 270,321.55 0.07 21.00 2_Gyro-NS-CT_OWSG(1) 8/242018 6:35:09PM Page 7 COMPASS 5000.1 Build 81E Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well 4-26 Project: Duck Island Unit TVD Reference: SDI 4-26A Actual @ 40.90usft (Innovation) Site: End SDI MD Reference: SDI 4-26A Actual @ 40.90usft (Innovation) Well: 4-26 North Reference: True Wellbore: 4-26A Survey Calculation Method: Minimum Curvature Design: 4-26A Database: Sperry EDM - NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +FJ -W Northing Easting DLS Section (usft) (1) (1) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 3,385.00 1.35 71.39 3,384.74 3,343.84 18.67 20.35 5,970,826.79 270,321.90 0.13 21.16 2_Gyro-NS-CT_OWSG(1) 3,400.70 1.33 71.64 3,400.43 3,359.53 18.79 20.70 5,970,826.90 270,322.25 0.13 21.32 2_Gyro-NS-CT_OWSG(1) 3,416.40 1.27 73.66 3,416.13 3,375.23 18.89 21.04 5,970,826.99 270,322.60 0.48 21.47 2_Gyro-NS-CT_OWSG(1) 3,432.10 1.28 78.35 3,431.83 3,390.93 18.98 21.38 5,970,827.06 270,322.94 0.67 21.60 2_Gyro-NS-CT_OWSG(1) 3,447.80 1.32 81.99 3,447.52 3,406.62 19.04 21.73 5,970,827.11 270,323.29 0.58 21.71 2_Gyro-NS-CT_OWSG(1) 3,463.50 1.23 83.24 3,463.22 3,422.32 19.08 22.08 5,970,827.15 270,323.64 0.60 21.80 2_Gyro-NS-CT_0WSG(1) 3,479.10 1.20 82.72 3,478.81 3,437.91 19.12 22.40 5,970,827.18 270,323.97 0.20 21.88 2_Gyro-NS-CT_OWSG(1) 3,494.80 1.13 79.27 3,494.51 3,453.61 19.17 22.72 5,970,827.22 270,324.28 0.63 21.97 2_Gyro-NS-CT_OWSG(1) 3,510.40 1.00 76.46 3,510.11 3,469.21 19.24 23.00 5,970,827.27 270,324.57 0.90 22.07 2_Gyro-NS-CT_OWSG(1) 3,525.90 0.92 76.75 3,525.61 3,484.71 19.30 23.26 5,970,827.32 270,324.82 0.52 22.16 2_Gyro-NS-CT_OWSG(1) 3,541.30 0.85 76.65 3,541.00 3,500.10 19.35 23.49 5,970,827.37 270,325.06 0.45 22.24 2_Gyro-NS-CT_OWSG(1) 3,556.80 0.82 76.45 3,556.50 3,515.60 19.40 23.71 5,970,827.42 270,325.28 0.19 22.32 2_Gyro-NS-CT_OWSG(1) 3,572.20 0.80 77.13 3,571.90 3,531.00 19.45 23.92 5,970,827.46 270,325.49 0.14 22.40 2_Gyro-NS-CT_OWSG(1) 3,587.70 0.82 77.57 3,587.40 3,546.50 19.50 24.13 5,970,827.50 270,325.71 0.14 22.48 2_Gyro-NS-CT_OWSG(1) 3,603.20 0.85 77.32 3,602.90 3,562.00 19.55 24.35 5,970,827.54 270,325.93 0.19 22.55 2_Gyro-NS-CT_OWSG(1) 3,618.60 0.85 77.41 3,618.30 3,577.40 19.60 24.58 5,970,827.59 270,326.15 0.01 22.63 2_Gyro-NS-CT_0WSG(1) 3,634.10 0.85 77.95 3,633.79 3,592.89 19.65 24.80 5,970,827.63 270,326.38 0.05 22.71 2_Gyro-NS-CT_OWSG (1) 3,649.60 0.85 78.67 3,649.29 3,608.39 19.70 25.03 5,970,827.67 270,326.61 0.07 22.79 2_Gyro-NS-CT_OWSG(1) 3,665.00 0.85 79.50 3,664.69 3,623.79 19.74 25.25 5,970,827.71 270,326.83 0.08 22.86 2_Gyro-NS-CT_OWSG(1) 3,680.40 0.87 79.45 3,680.09 3,639.19 19.78 25.48 5,970,827.74 270,327.06 0.13 22.93 2_Gyro-NS-CT_OWSG(1) 3,695.90 0.85 81.75 3,695.59 3,654.69 19.82 25.71 5,970,827.77 270,327.29 0.26 23.00 2_Gyro-NS-CT_OWSG(1) 3,711.30 0.95 84.42 3,710.99 3,670.09 19.85 25.95 5,970,827.79 270,327.53 0.70 23.06 2_Gyro-NS-CT_OWSG(1) 3,726.80 0.98 82.87 3,726.48 3,685.58 19.88 26.21 5,970,827.81 270,327.79 0.26 23.12 2_Gyro-NS-CT_OWSG(1) 3,742.30 0.92 82.19 3,741.98 3,701.08 19.91 26.46 5,970,827.84 270,328.05 0.39 23.18 2_Gyro-NS-CT_OWSG(1) 3,757.70 0.97 83.52 3,757.38 3,716.48 19.94 26.71 5,970,827.86 270,328.30 0.35 23.25 2_Gyro-NS-CT_OWSG(1) 3,773.10 1.02 84.17 3,772.78 3,731.88 19.97 26.98 5,970,827.88 270,328.57 0.33 23.31 2_Gyro-NS-CT_OWSG(1) 3,788.60 1.07 85.46 3,788.27 3,747.37 20.00 27.26 5,970,827.90 270,328.85 0.36 23.37 2_Gyro-NS-CT_OWSG(1) 3,804.00 1.12 87.01 3,803.67 3,762.77 20.01 27.55 5,970,827.91 270,329.14 0.38 23.43 2_Gyro-NS-CT_OWSG(1) 3,819.50 1.15 88.27 3,819.17 3,778.27 20.03 27.86 5,970,827.91 270,329.45 0.25 23.48 2_Gyro-NS-CT_OWSG(1) 3,834.90 1.15 88.96 3,834.57 3,793.67 20.03 28.17 5,970,827.91 270,329.76 0.09 23.53 2_Gyro-NS-CT_OWSG(1) 3,850.40 1.17 89.54 3,850.06 3,809.16 20.04 28.48 5,970,827.91 270,330.07 0.15 23.58 2_Gyro-NS-CT_OWSG(1) 3,865.80 1.17 90.43 3,865.46 3,824.56 20.04 28.80 5,970,827.90 270,330.39 0.12 23.62 2_Gyro-NS-CT_OWSG(1) 3,881.30 1.15 91.70 3,880.96 3,840.06 20.03 29.11 5,970,827.88 270,330.70 0.21 23.65 2_Gyro-NS-CT_OWSG(1) 3,896.70 1.15 92.74 3,896.35 3,855.45 20.02 29.42 5,970,827.86 270,331.01 0.14 23.68 2_Gyro-NS-CT_OWSG(1) 3,912.20 1.20 92.85 3,911.85 3,870.95 20.01 29.74 5,970,827.84 270,331.33 0.32 23.71 2_Gyro-NS-CT_OWSG(1) 3,927.60 1.20 93.71 3,927.25 3,886.35 19.99 30.06 5,970,827.81 270,331.65 0.12 23.73 2_Gyro-NS-CT_0WSG(1) 3,943.10 1.22 95.13 3,942.74 3,901.84 19.96 30.39 5,970,827.77 270,331.97 0.23 23.75 2_Gyro-NS-CT_OWSG(1) 3,958.50 1.25 96.14 3,958.14 3,917.24 19.93 30.72 5,970,827.73 270,332.30 0.24 23.76 2_Gyro-NS-CT OWSG(1) 3,974.00 1.27 99.06 3,973.64 3,932.74 19.88 31.05 5,970,827.67 270,332.64 0.43 23.76 2_Gyro-NS-CT_OWSG (1) 3,989.50 1.27 99.55 3,989.13 3,948.23 19.83 31.39 5,970,827.61 270,332.97 0.07 23.75 2_Gyro-NS-CT_OWSG (1) W42018 6:35:09PM Page 8 COMPASS 5000.1 Build 81E Company: Hilcorp Alaska, LLC Project: Duck Island Unit Site: End SDI Well: 4-26 Wellbore: 4-26A Design: 4-26A Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database! Well 4-26 SDI 4-26A Actual @ 40.90usft (Innovation) SDI 4-26A Actual @ 40.90usft (Innovation) True Minimum Curvature Sperry EDM - NORTH US + CANADA Map Vertical Easting DLS Section (ft) Map (ft) Survey Tool Name MD Inc Azi TVD TVDSS +NI -S +E! -W Northing (usft) (I r) (usft) (usft) (usft) (usft) (ft) 0.13 4,004.90 1.20 97.79 4,004.53 3,963.63 19.78 31.72 5,970,827.55 0.09 4,020.40 1.18 98.96 020.02 3,979.12 19.73 32.04 5,970,827.49 0.28 4,035.90 1.22 99.94 4,035.52 3,994.62 19.68 32.36 5,970,827.43 0.43 4,051.30 1.18 100.04 4,050.92 4,010.02 19.62 32.68 5,970,827.36 0.08 4,066.70 1.17 100.72 4,066.31 4,025.41 19.57 32.99 5,970,827.30 0.21 4,082.20 1.17 101.67 4,081.81 4,040.91 19.50 33.30 5,970,827.22 0.33 4,097.70 1.18 102.93 4,097.31 4,056.41 19.44 33.61 5,970,827.15 0.49 4,113.20 1.22 103.78 4,112.80 4,071.90 19.36 33.93 5,970,827.06 0.18 4,128.60 1.23 104.18 4,128.20 4,087.30 19.28 34.24 5,970,826.97 0.08 4,144.10 1.28 105.22 4,143.70 4,102.80 19.20 34.57 5,970,826.88 0.34 4,159.50 1.30 106.97 4,159.09 4,118.19 19.10 34.91 5,970,826.77 0.33 4,175.00 1.33 108.34 4,174.59 4,133.69 18.99 35.25 5,970,826.65 4,190.50 1.38 109.06 4,190.08 4,149.18 18.87 35.59 5,970,826.52 4,206.00 1.38 111.19 4,205.58 4,164.68 18.75 35.94 5,970,826.39 4,221.50 1.43 112.98 4,221.08 4,180.18 18.60 36.29 5,970,826.23 4,237.00 1.47 113.05 4,236.57 4,195.67 18.45 36.66 5,970,826.07 4,252.40 1.47 113.24 4,251.97 4,211.07 18.29 37.02 5,970,825.90 4,267.80 1.48 113.53 4,267.36 4,226.46 18.14 37.38 5,970,825.73 4,283.10 1.47 115.80 4,282.66 4,241.76 17.97 37.74 5,970,825.56 4,298.30 1.53 118.69 4,297.85 4,256.95 17.79 38.09 5,970,825.36 4,313.60 1.52 117.53 4,313.14 4,272.24 17.60 38.45 5,970,825.16 4,328.80 1.40 115.71 4,328.34 4,287.44 17.42 38.80 5,970,824.98 4,344.10 1.38 115.74 4,343.64 4,302.74 17.26 39.13 5,970,824.81 4,359.30 1.33 115.86 4,358.83 4,317.93 17.11 39.46 5,970,824.64 4,374.60 1.27 116.43 4,374.13 4,333.23 16.95 39.77 5,970,824.48 4,389.80 1.20 117.16 4,389.32 4,348.42 16.81 40.06 5,970,824.32 4,405.00 1.13 118.31 4,404.52 4,363.62 16.66 40.34 5,970,824.17 4,420.30 1.07 119.30 4,419.82 4,378.92 16.52 40.59 5,970,824.02 4,435.50 1.02 120.48 4,435.02 4,394.12 16.38 40.83 5,970,823.87 4,450.70 1.00 121.51 4,450.21 4,409.31 16.24 41.06 5,970,823.73 4,465.90 0.98 121.85 4,465.41 4,424.51 16.11 41.29 5,970,823.59 4,481.20 0.93 122.06 4,480.71 4,439.81 15.97 41.50 5,970,823.44 4,496.40 0.92 121.67 4,495.91 4,455.01 15.84 41.71 5,970,823.31 4,511.70 0.92 122.26 4,511.20 4,470.30 15.71 41.92 5,970,823.17 4,526.90 0.88 123.28 4,526.40 4,485.50 15.58 42.12 5,970,823.04 4,542.10 0.85 126.07 4,541.60 4,500.70 15.45 42.31 5,970,822.90 4,557.30 0.80 126.00 4,556.80 4,515.90 15.32 42.49 5,970,822.77 4,572.60 0.75 123.79 4,572.10 4,531.20 15.21 42.66 5,970,822.64 4,587.80 0.70 123.75 4,587.30 4,546.40 15.10 42.82 5,970,822.53 403.00 0.62 123.06 4,602.50 4,561.60 15.00 42.96 5,970,822.43 Well 4-26 SDI 4-26A Actual @ 40.90usft (Innovation) SDI 4-26A Actual @ 40.90usft (Innovation) True Minimum Curvature Sperry EDM - NORTH US + CANADA Map Vertical Easting DLS Section (ft) ('1100') (ft) Survey Tool Name 270,333.30 0.52 23.74 2_Gyro-NS-CT_OWSG(1) 270,333.62 0.20 23.73 2_Gyro-NS-CT_OWSG(1) 270,333.94 0.29 23.72 2_Gyro-NS-CT_OWSG(1) 270,334.25 0.26 23.71 2_Gyro-NS-CT_OWSG(1) 270,334.56 0.11 23.69 2_Gyro-NS-CT_OWSG(1) 270,334.87 0.13 23.67 2_Gyro-NS-CT_OWSG(1) 270,335.18 0.18 23.65 2_Gyro-NS-CT_OWSG(1) 270,335.49 0.28 23.61 2_Gyro-NS-CT_OWSG(1) 270,335.81 0.09 23.58 2_Gyro-NS-CT_OWSG(1) 270,336.13 0.35 23.53 2_Gyro-NS-CT_OWSG(1) 270,336.46 0.29 23.48 2_Gyro-NS-CT_OWSG(1) 270,336.80 0.28 23.42 2_Gyro-NS-CT_OWSG(1) 270,337.14 0.34 23.35 2_Gyro-NS-CT_OWSG(1) 270,337.49 0.33 23.26 2_Gyro-NS-CT_OWSG(1) 270,337.84 0.43 23.17 2_Gyro-NS-CT_OWSG(1) 270,338.19 0.26 23.06 2_Gyro-NS-CT_0WSG(1) 270,338.55 0.03 22.96 2_Gym-NS-CT_0WSG(1) 270,338.91 0.08 22.85 2_Gyro-NS-CT_OWSG(1) 270,339.26 0.39 22.73 2_Gyro-NS-CT_OWSG(1) 270,339.61 0.64 22.60 2_Gyro-NS-CT_OWSG (1) 270,339.96 0.21 22.45 2_Gyro-NS-CT_OWSG (1) 270,340.30 0.85 22.33 2_Gyro-NS-CT_0WSG(1) 270,340.63 0.13 22.21 2_Gyro-NS-CT_OWSG(1) 270,340.95 0.33 22.10 2_Gyro-NS-CT_OWSG(1) 270,341.26 0.40 21.99 2_Gyro-NS-CT_OWSG(1) 270,341.55 0.47 21.88 2_Gyro-NS-CT_OWSG(1) 270,341.81 0.49 21.77 2_Gyro-NS-CT_OWSG(1) 270,342.07 0.41 21.66 2_Gyro-NS-CT_OWSG(1) 270,342.30 0.36 21.56 2_Gyro-NS-CT_OWSG(1) 270,342.53 0.18 21.45 2_Gym-NS-CT_OWSG(1) 270,342.75 0.14 21.34 2_Gyro-NS-CT_OWSG(1) 270,342.96 0.33 21.24 2_Gyro-NS-CT_OWSG(1) 270,343.16 0.08 21.14 2_Gyro-NS-CT_OWSG(1) 270,343.37 0.06 21.04 2_Gyro-NS-CT_OWSG(1) 270,343.57 0.28 20.93 2_Gyro-NS-CT_OWSG(1) 270,343.75 0.34 20.83 2_Gyro-NS-CT_OWSG(1) 270,343.92 0.33 20.72 2_Gyro-NS-CT_OWSG (1) 270,344.09 0.38 20.63 2_Gyro-NS-CT_OWSG(1) 270,344.25 0.33 20.54 2_Gyro-NS-CT_OWSG(1) 270,344.39 0.53 20.47 2_Gyro-NS-CT_OWSG(1) 8242018 6:35:09PM Page 9 COMPASS 5000.1 Build 81E Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well 4-26 Project: Duck Island Unit TVD Reference: SDI 4-26A Actual @ 40.90usft (Innovation) Site: End SDI MD Reference: SDI 4-26A Actual @ 40.90usft (Innovation) Well: 4-26 North Reference: True Wellbore: 4-26A Survey Calculation Method: Minimum Curvature Design: 4-26A Database: Sperry EDM - NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NI -S +EI -W Northing Easting DLS Section (usft) (1) (a) (usft) (usft) (usft) (usft) (ft) (ft) (a/10(') (ft) Survey Tool Name 4,618.20 0.52 123.75 4,617.69 4,576.79 14.92 43.09 5,970,822.34 270,344.51 0.66 20.40 2_Gyro-NS-CT_OWSG(1) 4,633.50 0.45 125.07 4,632.99 4,592.09 14.85 43.19 5,970,822.27 270,344.62 0.46 20.34 2 Gyro -NS -CT OWSG(1) 4,648.70 0.43 126.27 4,648.19 4,607.29 14.78 43.29 5,970,822.20 270,344.71 0.14 20.29 2_Gyro-NS-CT_OWSG(1) 4,663.90 0.42 126.92 4,663.39 4,622.49 14.71 43.38 5,970,822.13 270,344.80 0.07 20.23 2_Gyro-NS.CT_OWSG(1) 4,679.20 0.38 126.12 4,678.69 4,637.79 14.65 43.47 5,970,822.06 270,344.88 0.26 20.18 2_Gyro-NS-CT_OWSG(1) 4,694.40 0.35 127.03 4,693.89 4,652.99 14.59 43.54 5,970,822.00 270,344.96 0.20 20.13 2_Gyro-NS-CT_OWSG(1) 4,709.60 0.32 126.77 4,709.09 4,668.19 14.54 43.61 5,970,821.94 270,345.03 0.20 20.09 2_Gyro-NS-CT_OWSG(1) 4,724.90 0.28 129.88 4,724.39 4,683.49 14.49 43.68 5,970,821.89 270,345.09 0.28 20.05 2_Gyro-NS-CT_OWSG(1) 4,740.10 0.28 134.83 4,739.59 4,698.69 14.44 43.73 5,970,821.84 270,345.14 0.16 20.01 2_Gyro-NS-CT_OWSG(1) 4,755.30 0.32 129.72 4,754.79 4,713.89 14.38 43.79 5,970,821.79 270,345.20 0.32 19.96 2_Gyro-NS-CT_OWSG(1) 4,770.50 0.28 125.47 4,769.99 4,729.09 14.33 43.85 5,970,821.74 270,345.26 0.30 19.92 2_Gyro-NS-CT_OWSG(1) 4,785.80 0.27 129.41 4,785.29 4,744.39 14.29 43.91 5,970,821.69 270,345.32 0.14 19.88 2_Gyro-NS-CT_OWSG(1) 4,801.00 0.27 129.32 4,800.49 4,759.59 14.24 43.97 5,970,821.64 270,345.37 0.00 19.85 2_Gyro-NS-CT_OWSG(1) 4,816.20 0.27 126.69 4,815.69 4,774.79 14.20 44.02 5,970,821.60 270,345.43 0.08 19.81 2_Gyro-NS-CT_OWSG(1) 4,831.50 0.25 125.62 4,830.99 4,790.09 14,16 44.08 5,970,821.55 270,345.48 0.13 19.78 2_Gyro-NS-CT_OWSG(1) 4,846.70 0.22 125.72 4,846.19 4,805.29 14.12 44.13 5,970,821.52 270,345.53 0.20 19.75 2_Gyro-NS-CT_OWSG(1) 4,862.00 0.18 124.85 4,861.49 4,820.59 14.09 44.17 5,970,821.48 270,345.57 0.26 19.72 2_Gyro-NS-CT_OWSG(1) 4,877.20 0.15 119.38 4,876.69 4,835.79 14.07 44.21 5,970,821.46 270,345.61 0.22 19.70 2_Gyro-NS-CT_OWSG(1) 4,892.50 0.10 115.59 4,891.99 4,851.09 14.05 44.24 5,970,821.44 270,345.64 0.33 19.69 2_Gyro-NS-CT_OWSG(1) 4,907.70 0.13 133.54 4,907.19 4,866.29 14.04 44.27 5,970,821.42 270,345.66 0.31 19.68 2_Gyro-NS-CT_OWSG(1) 4,923.00 0.15 141.84 4,922.49 4,881.59 14.01 44.29 5,970,821.40 270,345.69 0.19 19.65 2_Gyro-NS-CT_OWSG(1) 4,938.20 0.13 130.41 4,937.69 4,896.79 13.98 44.32 5,970,821.37 270,345.71 0.23 19.63 2_Gyro-NS-CT_OWSG(1) 4,953.50 0.12 107.51 4,952.99 4,912.09 13.97 44.34 5,970,821.35 270,345.74 0.33 19.62 2_Gyro-NS-CT_OWSG (1) 4,968.80 0.07 65.02 4,968.29 4,927.39 13.96 44.37 5,970,821.35 270,345.76 0.54 19.62 2_Gyro-NS-CT_OWSG(1) 4,984.00 0.07 38.01 4,983.49 4,942.59 13.98 44.38 5,970,821.36 270,345.78 0.22 19.63 2_Gyro-NS-CT_OWSG(1) 4,999.30 0.07 5.53 4,998.79 4,957.89 13.99 44.39 5,970,821.38 270,345.78 0.26 19.65 2_Gyro-NS-CT_OWSG(1) 5,014.50 0.20 350.53 5,013.99 4,973.09 14.03 44.39 5,970,821.41 270,345.78 0.88 19.69 2_Gyro-NS-CT_OWSG(1) 5,029.60 0.63 359.24 5,029.09 4,988.19 14.14 44.38 5,970,821.52 270,345.78 2.87 19.79 2_Gyro-NS-CT_OWSG(1) 5,044.60 1.35 357.02 5,044.09 5,003.19 14.40 44.37 5,970,821.78 270,345.78 4.81 20.052_Gyro-NS-CTOWSG(1) 5,059.70 2.45 356.35 5,059.18 5,018.28 14.90 44.34 5,970,822.28 270,345.76 7.29 20.54 2_Gyro-NS-CT_OWSG(1) 5,074.70 3.50 356.00 5,074.16 5,033.26 15.67 44.29 5,970,823.06 270,345.73 7.00 21.30 2_Gyro-NS-CT_OWSG(1) 5,089.70 4.08 355.85 5,089.13 5,048.23 16.66 44.22 5,970,824.05 270,345.69 3.87 22.28 2_Gyro-NS-CT_OWSG(1) 5,104.70 4.40 355.81 5,104.08 5,063.18 17.77 44.14 5,970,825.16 270,345.65 2.13 23.36 2_Gyro-NS-CT_OWSG(1) 5,119.80 4.82 355.25 5,119.14 5,078.24 18.98 44.04 5,970,826.37 270,345.59 2.80 24.55 2_Gyro-NS-CT_OWSG(1) 5,134.80 5.47 354.66 5,134.08 5,093.18 20.32 43.92 5,970,827.71 270,345.51 4.35 25.86 2_Gyro-NS-CT_OWSG (1) 5,149.80 6.07 354.79 5,149.00 5,108.10 21.82 43.78 5,970,829.22 270,345.42 4.00 27.33 2_Gyro-NS-CT_OWSG (1) 5,164.80 6.62 354.92 5,163.91 5,123.01 23.47 43.64 5,970,830.87 270,345.32 3.67 28.95 2_Oyro-NS-CT_OWSG(1) 5,179.80 7.13 354.92 5,178.80 5,137.90 25.26 43.48 5,970,832.66 270,345.22 3.40 30.70 2_Gyro-NS-CT_OWSG(1) 5,194.80 7.57 355.19 5,193.68 5,152.78 27.17 43.31 5,970,834.58 270,345.11 2.94 32.58 2_Gyro-NS-CT_OWSG(1) 5,209.80 7.92 355.69 5,208.54 5,167.64 29.18 43.15 5,970,836.60 270,345.01 2.38 34.55 2_Gyro-NS-CT_OWSG(1) &24/2018 6:35:09PM Page 10 COMPASS 5000.1 Build 81E Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Project: Duck Island Unit TVD Reference: Site: End SDI MD Reference: Well: 4-26 North Reference: Wellbore: 4-26A Survey Calculation Method: Design: 4-26A Database: Survey We114-26 SDI 4-26A Actual @ 40.90usft (Innovation) SDI 4-26A Actual @ 40.90usft (Innovation) True Minimum Curvature Sperry EDM - NORTH US + CANADA Map Vertical Easting DLS Section (ft) Map MD Inc Azi TVD TVDSS +NI -S +EI -W Northing (usft) (1) (1 (usft) (usft) (usft) (usft) (ft) 5,224.80 8.27 356.33 5,223.39 5,182.49 31.29 43.00 5,970,838.71 5,239.80 8.68 357.12 5,238.23 5,197.33 33.50 42.88 5,970,840.92 5,254.80 9.08 357.65 5,253.05 5,212.15 35.81 42.77 5,970,843.23 5,269.80 9.45 357.81 5,267.85 5,226.95 38.23 42.68 5,970,845.65 5,284.80 9.78 357.86 5,282.64 5,241.74 40.73 42.58 5,970,848.15 5,290.90 9.93 357.90 5,288.65 5,247.75 41.77 42.54 5,970,849.20 5,307.70 10.35 357.78 5,305.19 5,264.29 44.73 42.43 5,970,852.16 5,351.30 11.45 357.75 5,348.00 5,307.10 52.97 42.11 5,970,860.40 5,399.20 12.50 358.71 5,394.86 5,353.96 62.90 41.81 5,970,870.34 5,411.00 14.18 358.27 5,406.34 5,365.44 65.62 41.74 5,970,873.06 5,428.00 14.03 0.57 5,422.83 5,381.93 69.76 41.69 5,970,877.20 5,448.00 13.17 4.77 5,442.27 5,401.37 74.46 41.91 5,970,881.89 5,469.00 11.82 11.38 5,462.77 5,421.87 78.95 42.53 5,970,886.36 5;557.62 7.80 2.37 5,550.08 5,509.18 93.86 44.57 5,970,901.20 5,620.68 13.03 345.68 5,612.09 5,571.19 105.04 42.99 5,970,912.42 5,684.95 16.70 337.32 5,674.21 5,633.31 120.58 37.63 5,970,928.12 5,747.50 20.50 332.36 5,733.48 5,692.58 138.59 29.08 5,970,946.38 5,810.53 24.13 338.46 5,791.79 5,750.89 160.36 19.23 5,970,968.44 5,873.64 27.70 344.71 5,848.56 5,807.66 186.52 10.62 5,970,994.85 5,936.33 29.52 348.60 5,903.60 5,862.70 215.72 3.72 5,971,024.25 5,999.15 31.88 350.30 5,957.61 5,916.71 247.25 -2.13 5,971,055.94 6,063.46 35.50 356.06 6,011.12 5,970.22 282.64 -6.28 5,971,091.44 6,125.71 37.06 356.34 6,061.30 6,020.40 319.39 -8.72 5,971,128.24 6,189.02 39.93 359.92 6,110.85 6,069.95 358.76 -9.97 5,971,167.63 6,252.32 42.95 1.57 6,158.30 6,117.40 400.64 -9.40 5,971,209.48 6,315.10 47.00 4.09 6,202.71 6,161.81 444.94 -7.18 5,971,253.69 6,392.49 52.01 6.53 6,252.95 6,212.05 503.51 -1.69 5,971,312.06 6,454.88 55.67 7.69 6,289.76 6,248.86 553.48 4.56 5,971,361.81 6,517.62 57.08 9.14 6,324.50 6,283.60 605.16 12.21 5,971,413.23 6,581.47 58.62 9.26 6,358.48 6,317.58 658.52 20.85 5,971,466.30 6,644.09 60.29 8.58 6,390.30 6,349.40 711.80 29.21 5,971,519.29 6,707.54 62.14 9.12 6,420.85 6,379.95 766.74 37.77 5,971,573.95 6,770.58 62.89 9.42 6,449.95 6,409.05 821.94 46.78 5,971,628.84 6,833.98 62.97 9.48 6,478.80 6,437.90 877.62 56.05 5,971,684.21 6,896.90 62.75 8.74 6,507.50 6,466.60 932.91 64.91 5,971,739.20 6,959.71 63.18 7.93 6,536.05 6,495.15 988.26 73.02 5.971,794.28 7,023.07 63.13 7.99 6,564.66 6,523.76 1,044.25 80.85 5,971,850.00 7,086.55 63.30 8.23 6,593.27 6,552.37 1,100.35 88.84 5,971,905.83 7,149.60 63.13 7.56 6,621.68 6,580.78 1,156.10 96.57 5,971,961.31 7,213.06 62.99 7.82 6,650.44 6,609.54 1,212.17 104.14 5,972,017.12 We114-26 SDI 4-26A Actual @ 40.90usft (Innovation) SDI 4-26A Actual @ 40.90usft (Innovation) True Minimum Curvature Sperry EDM - NORTH US + CANADA Map Vertical Easting DLS Section (ft) (`1100') (ft) Survey Tool Name 270,344.93 2.41 36.62 2_Gyro-NS-CT_OWSG(1) 270,344.87 2.84 38.80 2_Gyro-NS-CT_OWSG(1) 270,344.84 2.72 41.08 2_Gyro-NS-CT_OWSG(1) 270,344.82 2.47 43.46 2_Gyro-NS-CT_OWSG(1) 270,344.80 2.20 45.93 2_Gyro-NS-CT_OWSG(1) 270,344.79 2.46 46.95 2_Gym-NS-CT_OWSG(1) 270,344.77 2.50 49.87 2_Gym-NS-CT_OWSG(1) 270,344.70 2.52 58.00 2_Gyro-NS-CT_OWSG(1) 270,344.70 2.23 67.812_Gyro-NS-CTOWSG(1) 270,344.71 14.26 70.50 2_Gyro-NS-GC_Drill collar (2 270,344.80 3.41 74.60 2_Gyro-NS-GC_Drill collar (2 270,345.15 6.55 79.28 2_Gyro-NS-GC_Drill collar (2 270,345.91 9.36 83.82 2_Gyro-NS-GC_Drill collar (2 270,348.41 4.84 98.87 2_MWD _Intem Azi+Sag(3) 270,347.17 9.49 109.74 2_MWD_Interp Azi+Sag(3) 270,342.29 6.60 124.46 2_ MWD_Interp Azi+Sag(3) 270,334.30 6.58 141.19 2_MWD+IFR2+MS+Sag (4) 270,325.12 6.82 161.50 2_MWD+IFR2+MS+Sag (4) 270,317.31 7.12 186.32 2_MWD+IFR2+MS+Sag (4) 270,311.31 4.15 214.37 2_MWD+IFR2+MS+Sag(4) 270,306.43 4.00 244.87 2_MWD+IFR2+MS+Sag(4) 270,303.36 7.50 279.41 2_MWD+IFR2+MS+Sag (4) 270,302.05 2.52 315.54 2_MWD+IFR2+MS+Sag (4) 270,302.01 5.74 354.41 2_MWD+IFR2+MS+Sag (4) 270,303.85 5.07 396.01 2_MWD+IFR2+MS+Sag (4) 270,307.43 7.05 440.22 2_MWD+IFR2+MS+Sag(4) 270,314.71 6.90 499.01 2_MWD+IFR2+MS+Sag(4) 270,322.48 6.06 549.37 2_MWD+IFR2+MS+Sag(4) 270,331.71 2.96 601.60 2_MWD+IFR2+MS+Sag (4) 270,341.98 2.42 655.63 2_MWD+IFR2+MS+Sag(4) 270,351.97 2.83 709.54 2_MWD+IFR2+MS+Sag (4) 270,362.20 3.01 765.13 2 MWD+IFR2+MS+Sag (4) 270,372.90 1.26 821.03 2_MWD+IFR2+MS+Sag(4) 270,383.87 0.15 877.45 2_MWD+IFR2+MS+Sag(4) 270,394.42 1.10 933.42 2_MWD+IFR2+MS+Sag(4) 270,404.22 1.34 989.36 2_MWD+IFR2+MS+Sag(4) 270,413.76 0.12 1,045.89 2_MWD+IFR2+MS+Sag(4) 270,423.46 0.43 1,102.56 2_MWD+IFR2+MS+Sag (4) 270,432.90 0.99 1,158.84 2_MWD+IFR2+MS+Sag (4) 270,442.18 0.43 1,215.41 2 MWD+IFR2+MS+Sag (4) 8242018 6.35:09PM Page 11 COMPASS 5000.1 Build 81E Halliburton Definitive Survey Report Company: Project: Site: Well: Wellbore: Design: Hilcorp Alaska, LLC Duck Island Unit End SDI 4-26 4-26A 4-26A Local Co-ordinate Reference: Well 4-26 TVD Reference: SDI 4-26A Actual @ 40.90usft (Innovation) MD Reference: SDI 4-26A Actual @ 40.90usft (Innovation) North Reference: True Survey Calculation Method: Minimum Curvature Database: Sperry EDM - NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NI -S +EI -W Northing Easting DLS Section (usft) (1 (1) (usft) (usft) (usft) (usft) (ft) (ft) ('1100') (ft) Survey Tool Name 7,275.86 63.20 7.20 6,678.85 6,637.95 1,267.69 111.46 5,972,072.38 270,451.19 0.94 1,271.41 2_MWD+IFR2+MS+Sag(4) 7,338.91 63.19 7.22 6,707.29 6,666.39 1,323.52 118.53 5,972,127.97 270,459.96 0.03 1,327.69 2_MWD+IFR2+MS+Sag(4) 7,401.39 63.66 8.81 6,735.24 6,694.34 1,378.85 126.32 5,972,183.03 270,46944 2.40 1,383.56 2_MWD+IFR2+MS+Sag(4) 7,465.01 63.39 9.86 6,763.60 6,722.70 1,435.04 135.56 5,972,238.92 270,480.40 1.54 1,440.48 2_MWD+IFR2+MS+Sag(4) 7,528.60 63.47 9.93 6,792.05 6,751.15 1,491.07 145.33 5,972,294.62 270,491.88 0.16 1,497.30 2_MWD+IFR2+MS+Sag(4) 7,591.33 63.39 9.69 6,820.10 6,779.20 1,546.36 154.89 5,972,349.58 270,503.13 0.37 1,553.36 2_MWD+IFR2+MS+Sag(4) 7,654.67 63.33 9.11 6,848.50 6,807.60 1,602.21 164.14 5,972,405.12 270,514.08 0.82 1,609.94 2_MWD+IFR2+MS+Sag (4) 7,717.73 63.18 8.09 6,876.88 6,835.98 1,657.89 172.56 5,972,460.52 270,524.20 1.46 1,666.25 2_MWD+IFR2+MS+Sag(4) 7,781.55 62.97 8.70 6,905.78 6,864.88 1,714.18 180.86 5,972,516.53 270,534.22 0.91 1,723.14 2_MWD+IFR2+MS+Sag (4) 7,843.60 63.05 8.82 6,933.94 6,893.04 1,768.83 189.28 5,972,570.89 270,544.31 0.22 1,778.42 2_MWD+IFR2+MS+Sag (4) 7,907.24 63.18 8.65 6,962.72 6,921.82 1,824.93 197.90 5,972,626.70 270,554.65 0.31 1,835.17 2_MWD+IFR2+MS+Sag (4) 7,970.71 63.18 8.00 6,991.36 6,950.46 1,880.98 206.11 5,972,682.46 270,564.56 0.91 1,891.80 2_MWD+IFR2+MS+Sag(4) 8,032.94 63.31 7.87 7,019.37 6,978.47 1,936.01 213.78 5,972,737.24 270,573.91 0.28 1,947.37 2_MWD+IFR2+MS+Sag (4) 8,096.41 63.04 7.52 7,048.02 7,007.12 1,992.14 221.36 5,972,793.11 270,583.21 0.65 2,004.01 2_MWD+IFR2+MS+Sag (4) 8,155.54 63.24 8.37 7,074.73 7,033.83 2,044.39 228.65 5,972,845.10 270,592.09 1.33 2,056.76 2_MWD+IFR2+MS+Sag(4) 8,221.67 63.07 9.09 7,104.59 7,063.69 2,102.71 237.61 5,972,903.12 270,602.83 1.00 2,115.74 2_MWD+IFR2+MS+Sag (4) 8,284.99 63.25 9.50 7,133.18 7,092.28 2,158.46 246.73 5,972,958.56 270,613.66 0.64 2,172.22 2_MWD+IFR2+MS+Sag (4) 8,349.11 63.11 9.88 7,162.11 7,121.21 2,214.87 256.36 5,973,014.65 270,625.01 0.57 2,229.39 2_MWD+IFR2+MS+Sag (4) 8,411.89 63.10 9.87 7,190.51 7,149.61 2,270.03 265.97 5,973,069.48 270,636.30 0.02 2,285.34 2_MWD+IFR2+MS+Sag (4) 8,475.31 63.23 9.32 7,219.14 7,178.24 2,325.83 275.40 5,973,124.97 270,647.43 0.80 2,341.89 2_MWD+IFR2+MS+Sag(4) 8,538.63 63.20 9.63 7,247.68 7,206.78 2,381.58 284.70 5,973,180.41 270,658.44 0.44 2,398.38 2_MWD+IFR2+MS+Sag (4) 8,602.01 63.14 9.53 7,276.28 7,235.38 2,437.35 294.12 5,973,235.86 270,669.55 0.17 2,454.90 2_MWD+IFR2+MS+Sag(4) 8,665.05 63.25 9.23 7,304.71 7,263.81 2,492.86 303.29 5,973,291.06 270,680.42 0.46 2,511.13 2_MWD+IFR2+MS+Sag(4) 8,727.58 63.04 8.52 7,332.96 7,292.06 2,547.98 311.89 5,973,345.89 270,690.71 1.07 2,566.90 2_MWD+IFR2+MS+Sag(4) 8,790.91 63.31 8.02 7,361.54 7,320.64 2,603.91 320.02 5,973,401.54 270,700.54 0.82 2,623.41 2_MWD+IFR2+MS+Sag (4) 8,853.80 63.03 8.14 7,389.92 7,349.02 2,659.47 327.91 5,973,456.83 270,710.13 0.48 2,679.53 2_MWD+IFR2+MS+Sag (4) 8,916.97 63.16 8.68 7,418.51 7,377.61 2,715.20 336.15 5,973,512.28 270,720.07 0.79 2,735.85 2_MWD+IFR2+MS+Sag(4) 8,980.44 63.03 9.04 7,447.23 7,406.33 2,771.12 344.87 5,973,567.91 270,730.49 0.55 2,792.44 2_MWD+IFR2+MS+Sag(4) 9,043.86 63.19 9.10 7,475.91 7,435.01 2,826.98 353.78 5,973,623.46 270,741.11 0.27 2,848.98 2_MWD+IFR2+MS+Sag(4) 9,107.03 63.40 8.57 7,504.30 7,463.40 2,882.74 362.45 5,973,678.93 270,751.48 0.82 2,905.39 2_MWD+IFR2+MS+Sag(4) 9,170.22 63.24 7.89 7,532.67 7,491.77 2,938.62 370.53 5,973,734.54 270,761.27 0.99 2,961.85 2_MWD+IFR2+MS+Sag (4) 9,232.67 63.44 8.60 7,560.70 7,519.80 2,993.85 378.54 5,973,789.50 270,770.96 1.07 3,017.65 2 MWD+IFR2+MS+Sag(4) 9,296.24 63.04 9.22 7,589.32 7,548.42 3,049.93 387.33 5,973,845.27 270,781.46 1.07 3,074.40 2_MWD+IFR2+MS+Sag(4) 9,358.86 63.68 8.84 7,617.40 7,576.50 3,105.21 396.11 5,973,900.26 270,791.93 1.16 3,130.35 2_MWD+IFR2+MS+Sag(4) 9,422.06 63.25 9.59 7,645.63 7,604.73 3,161.02 405.17 5,973,955.76 270,802.69 1.26 3,186.87 2_MWD+IFR2+MS+Sag (4) 9,485.02 63.23 9.72 7,673.98 7,633.08 3,216.44 414.59 5,974,010.87 270,813.81 0.19 3,243.04 2_MWD+IFR2+MS+Sag (4) 9,54858 63.72 9.86 7,702.36 7,661.46 3,272.48 424.26 5,974,066.58 270,825.19 0.80 3,299.87 2_MWD+IFR2+MS+Sag (4) 9,611.42 63.34 8.88 7,730.37 7,689.47 3,327.98 433.42 5,974,121.78 270,836.05 1.52 3,356.09 2_MWD+IFR2+MS+Sag (4) 9,674.00 63.46 8.86 7,758.39 7,717.49 3,383.27 442.05 5,974,176.77 270,846.36 0.19 3,412.03 2_MWD+IFR2+MS+Sag(4) 9,737.85 63.16 9.42 7,787.07 7,746.17 3,439.59 451.11 5,974,232.79 270,857.14 0.91 3,469.05 2_MWD+IFR2+MS+Sag (4) 8/242018 6:35:09PM Page 12 COMPASS 5000.1 Build 81E Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well 4-26 Project: Duck Island Unit TVD Reference: SDI 4-26A Actual @ 40.90usft (Innovation) Site: End SDI MD Reference: SDI 4-26A Actual @ 40.90usft (Innovation) Well: 4-26 North Reference: True Wellbore: 4-26A Survey Calculation Method: Minimum Curvature Design: 4-26A Database: Sperry EDM - NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +E/ -W Northing Easting DLS Section (usft) (I M (usft) (usft) (usft) (usft) (ft) (ft) (^/100•) (ft) Survey Tool Name 9,800.79 63.45 9.49 7,815.35 7,774.45 3,495.06 460.35 5,974,287.94 270,868.07 0.47 3,525.25 2_MWD+IFR2+MS+Sag (4) 9,863.77 63.19 8.72 7,843.63 7,802.73 3,550.62 469.26 5,974,343.21 270,878.67 1.17 3,581.50 2_MWD+IFR2+MS+Sag (4) 9,927.17 63.31 8.34 7,872.16 7,831.26 3,606.61 477.65 5,974,398.91 270,888.78 0.57 3,638.10 2_MWD+IFR2+MS+Sag(4) 9,989.91 62.98 8.98 7,900.51 7,859.61 3,661.95 486.08 5,974,453.96 270,898.90 1.05 3,694.06 2_MWD+IFR2+MS+Sag(4) 10,053.01 63.47 9.23 7,928.93 7,888.03 3,717.57 495.00 5,974,509.28 270,909.51 0.85 3,750.38 2_MWD+IFR2+MS+Sag (4) 10,116.23 63.80 8.86 7,957.01 7,916.11 3,773.51 503.90 5,974,564.92 270,920.12 0.74 3,807.00 2_MWD+IFR2+MS+Sag(4) 10,179.60 62.97 8.93 7,985.40 7,944.50 3,829.48 512.66 5,974,620.60 270,930.59 1.31 3,863.64 2_MWD+IFR2+MS+Sag(4) 10,242.54 63.11 8.51 8,013.93 7,973.03 3,884.94 521.17 5,974,675.76 270,940.79 0.64 3,919.72 2_MWD+IFR2+MS+Sag (4) 10,305.33 63.06 9.14 8,042.35 8,001.45 3,940.26 529.75 5,974,730.79 270,951.07 0.90 3,975.69 2_MWD+IFR2+MS+Sag (4) 10,368.40 63.30 8.99 8,070.81 8,029.91 3,995.84 538.62 5,974,786.08 270,961.63 0.44 4,031.96 2_MWD+IFR2+MS+Sag (4) 10,431.45 61.82 8.73 8,099.86 8,058.96 4,051.13 547.24 5,974,841.07 270,971.94 2.38 4,087.90 2_MWD+IFR2+MS+Sag(4) 10,494.51 62.00 8.46 8,129.56 8,088.66 4,106.14 555.56 5,974,895.80 270,981.93 0.47 4,143.52 2_MWD+IFR2+MS+Sag(4) 10,557.73 61.93 7.51 8,159.27 8,118.37 4,161.40 563.31 5,974,950.79 270,991.37 1.33 4,199.32 2_MWD+IFR2+MS+Sag (4) 10,621.21 61.86 7.11 8,189.18 8,148.28 4,216.94 570.43 5,975,006.08 271,000.19 0.57 4,255.31 2_MWD+IFR2+MS+Sag (4) 10,683.89 62.28 7.06 8,218.54 8,177.64 4,271.89 577.26 5,975,060.80 271,008.70 0.67 4,310.69 2_MWD+IFR2+MS+Sag(4) 10,747.32 62.00 7.29 8,248.18 8,207.28 4,327.53 584.27 5,975,116.20 271,017.40 0.55 4,366.77 2_MWD+IFR2+MS+Sag (4) 10,810.98 62.14 7.25 8,277.99 8,237.09 4,383.32 591.38 5,975,171.75 271,026.22 0.23 4,423.01 2_MWD+IFR2+MS+Sag (4) 10,874.55 61.86 7.14 8,307.84 8,266.94 4,439.01 598.41 5,975,227.19 271,034.95 0.47 4,479.14 2_MWD+IFR2+MS+Sag (4) 10,935.41 61.80 7.61 8,336.57 8,295.67 4,492.22 605.30 5,975,280.16 271,043.47 0.69 4,532.79 2_MWD+IFR2+MS+Sag(4) 10,998.99 61.67 6.47 8,366.68 8,325.78 4,547.79 612.16 5,975,335.50 271,052.03 1.59 4,588.79 2_MWD+IFR2+MS+Sag(4) 11,061.66 62.02 6.89 8,396.25 8,355.35 4,602.67 618.59 5,975,390.15 271,060.13 0.81 4,644.03 2_MWD+IFR2+MS+Sag (4) 11,125.29 61.73 6.21 8,426.25 8,385.35 4,658.42 624.99 5,975,445.68 271,068.24 1.05 4,700.14 2_MWD+IFR2+MS+Sag(4) 11,188.44 60.03 6.49 8,456.98 8,416.08 4,713.25 631.09 5,975,500.29 271,076.01 2.72 4,755.30 2_MWD+IFR2+MS+Sag(4) 11,251.48 59.11 6.72 8,488.91 8,448.01 4,767.25 637.35 5,975,554.07 271,083.91 1.49 4,809.65 2_MWD+IFR2+MS+Sag(4) 11,314.80 59.09 6.44 8,521.42 8,480.52 4,821.22 643.57 5,975,607.82 271,091.79 0.38 4,863.97 2_MWD+IFR2+MS+Sag (4) 11,378.03 58.98 6.51 8,553.96 8,513.06 4,875.09 649.69 5,975,661.48 271,099.55 0.20 4,918.18 2_MWD+IFR2+MS+Sag(4) 11,441.39 59.23 6.60 8,586.49 8,545.59 4,929.11 655.89 5,975,715.28 271,107.40 0.41 4,972.55 2_MWD+IFR2+MS+Sag(4) 11,504.36 58.81 7.42 8,618.90 8,578.00 4,982.69 662.48 5,975,768.63. 271,115.63 1.30 5,026.53 2_MWD+IFR2+MS+Sag(4) 11,568.06 58.97 9.02 8,651.82 8,610.92 5,036.67 670.28 5,975,822.34 271,125.07 2.17 5,081.06 2_MWD+IFR2+MS+Sag(4) 11,630.82 59.20 8.39 8,684.06 8,643.16 5,089.89 678.43 5,975,875.29 271,134.85 0.94 5,134.89 2_MWD+IFR2+MS+Sag (4) 11,694.24 59.08 6.66 8,716.59 8,675.69 5,143.86 685.56 5,975,929.01 271,143.62 2.35 5,189.33 2_MWD+IFR2+MS+Sag(4) 11,755.68 59.24 5.20 8,748.09 8,707.19 5,196.33 691.01 5,975,981.29 271,150.68 2.06 5,242.06 2_MWD+IFR2+MS+Sag(4) 11,820.61 59.05 5.84 8,781.39 8,740.49 5,251.81 696.37 5,976,036.57 271,157.73 0.90 5,297.77 2_MWD+IFR2+MS+Sag(4) 11,882.89 59.10 5.67 8,813.40 8,772.50 5,304.96 701.72 5,976,089.54 271,164.71 0.25 5,351.17 2_MWD+IFR2+MS+Sag (4) 11,946.65 59.18 4.55 8,846.10 8,805.20 5,359.48 706.60 5,976,143.88 271,171.26 1.51 5,405.86 2_MWD+IFR2+MS+Sag(4) 12,009.76 59.46 5.89 8,878.31 8,837.41 5,413.53 711.54 5,976,197.75 271,177.85 1.88 5,460.09 2_MWD+IFR2+MS+Sag (4) 12,073.30 59.26 6.81 8,910.69 8,869.79 5,467.86 717.58 5,976,251.87 271,185.55 1.28 5,514.75 2_MWD+IFR2+MS+Sag (4) 12,135.65 59.53 8.50 8,942.44 8,901.54 5,521.04 724.73 5,976,304.81 271,194.32 2.37 5,568.41 2_MWD+IFR2+MS+Sag(4) 12,199.26 59.37 10.66 8,974.77 8,933.87 5,575.06 733.85 5,976,358.51 271,205.09 2.94 5,623.15 2_MWD+IFR2+MS+Sag (4) 12,260.82 59.25 9.40 9,006.19 8,965.29 5,627.18 743.07 5,976,410.33 271,215.90 1.77 5,676.03 2_MWD+IFR2+MS+Sag (4) 8242018 6:35:09PM Page 13 COMPASS 5000.1 Build 81E Company: Hilcorp Alaska, LLC Project: Duck Island Unit Site: End SDI Well: 4-26 Wellbore: 4-26A Design: 4-26A Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well 4-26 SDI 4-26A Actual @ 40.90usft (Innovation) SDI 4-26A Actual @ 40.90usft (Innovation) True Minimum Curvature Sperry EDM - NORTH US + CANADA 8/242018 6:35:09PM Page 14 COMPASS 5000.1 Build 81E Map Map Vertical MD Inc Azi ND TVDSS +NIS +EI -W Northing Easting DLS Section (usft) (`) (1 (usft) (usft) (usft) (usft) (ft) (ft) ('1100') (ft) Survey Tool Name 12,325.39 59.95 9.38 9,038.87 8,997.97 5,682.13 752.15 5,976,464.97 271,226.66 1.08 5,731.69 2_MWD+IFR2+MS+S89(4) 12,388.58 59.27 8.40 9,070.83 9,029.93 5,735.98 760.58 5,976,518.54 271,236.73 1.72 5,786.18 2_MWD+IFR2+MS+Sag (4) 12,450.61 58.33 7.82 9,102.97 9,062.07 5,788.51 768.07 5,976,570.81 271,245.82 1.71 5,839.24 2_MWD+IFR2+MS+Sag (4) 12,514.67 58.18 9.10 9,136.67 9,095.77 5,842.39 776.08 5,976,624.42 271,255.48 1.72 5,893.70 2_MWD+IFR2+MS+Sag(4) 12,577.82 59.34 8.51 9,169.42 9,128.52 5,895.74 784.34 5,976,677.49 271,265.37 2.00 5,947.68 2_MWD+IFR2+MS+Sag (4) 12,640.84 58.77 8.41 9,201.83 9,160.93 5,949.21 792.29 5,976,730.68 271,274.96 0.91 6,001.72 2_MWD+IFR2+MS+Sag (4) 12,703.96 59.32 6.92 9,234.30 9,193.40 6,002.85 799.51 5,976,784.08 271,283.81 2.20 6,055.85 2_MWD+IFR2+MS+Sag(4) 12,767.30 58.89 6.02 9,266.82 9,225.92 6,056.86 805.64 5,976,837.87 271,291.59 1.40 6,110.19 2_MWD+IFR2+MS+Sag (4) 12,829.23 58.59 6.70 9,298.96 9,258.06 6,109.47 811.50 5,976,890.28 271,299.06 1.06 6,163.12 2_MWD+IFR2+MS+Sag(4) 12,893.89 60.02 4.66 9,331.96 9,291.06 6,164.79 817.00 5,976,945.40 271,306.24 3.50 6,218.69 2_MWD+IFR2+MS+Sag(4) 12,956.85 59.96 4.42 9,363.45 9,322.55 6,219.14 821.31 5,976,999.59 271,312.22 0.34 6,273.14 2_MWD+IFR2+MS+Sag(4) 13,019.98 59.76 4.16 9,395.15 9,354.25 6,273.58 825.40 5,977,053.88 271,317.97 0.48 6,327.65 2_MWD+IFR2+MS+Sag (4) 13,082.82 59.82 4.64 9,426.77 9,385.87 6,327.73 829.56 5,977,107.87 271,323.79 0.67 6,381.87 2_MWD+IFR2+MS+Sag (4) 13,145.55 59.35 7.99 9,458.54 9,417.64 6,381.48 835.51 5,977,161.42 271,331.38 4.67 6,435.95 2_MWD+IFR2+MS+Sag (4) 13,209.34 59.87 11.01 9,490.81 9,449.91 6,435.74 844.59 5,977,215.37 271,342.12 4.16 6,490.93 2_MWD+IFR2+MS+Sag (4) 13,272.85 58.69 8.77 9,523.26 9,482.36 6,489.52 853.97 5,977,268.84 271,353.14 3.56 6,545.47 2_MWD+IFR2+MS+Sag (4) 13,336.20 58.96 7.05 9,556.05 9,515.15 6,543.21 861.43 5,977,322.27 271,362.24 2.36 6,599.67 2_MWD+IFR2+MS+Sag(4) 13,398.84 60.18 6.66 9,587.78 9,546.88 6,596.83 867.88 5,977,375.66 271,370.32 2.02 6,653.67 2_MWD+IFR2+MS+Sag(4) 13,462.07 60.36 6.74 9,619.14 9,578.24 6,651.36 874.28 5,977,429.97 271,378.39 0.31 6,708.58 2_MWD+IFR2+MS+Sag(4) 13,525.35 60.09 6.31 9,650.56 9,609.66 6,705.93 880.53 5,977,484.32 271,386.30 0.73 6,763.49 2_MWD+IFR2+MS+Sag (4) 13,587.51 60.13 4.83 9,681.54 9,640.64 6,759.57 885.76 5,977,537.77 271,393.17 2.07 6,817.35 2_MWD+IFR2+MS+Sag(4) 13,651.70 59.77 5.22 9,713.68 9,672.78 6,814.92 890.62 5,977,592.94 271,399.73 0.77 6,872.86 2_MWD+IFR2+MS+Sag(4) 13,714.18 59.85 5.60 9,745.10 9,704.20 6,868.68 895.71 5,977,646.52 271,406.46 0.54 6,926.83 2_MWD+IFR2+MS+Sag (4) 13,777.29 59.38 6.49 9,777.02 9,736.12 6,922.82 901.45 5,977,700.46 271,413.85 1.43 6,981.26 2 MWD+IFR2+MS+Sag (4) 13,839.83 59.25 6.99 9,808.94 9,768.04 6,976.23 907.76 5,977,753.65 271,421.79 0.72 7,035.04 2_MWD+IFR2+MS+Sag(4) 13,902.86 59.30 6.81 9,841.14 9,800.24 7,030.02 914.27 5,977,807.21 271,429.94 0.26 7,089.22 2_MWD+IFR2+MS+Sag (4) 13,945.70 59.23 6.59 9,863.04 9,822.14 7,066.59 918.56 5,977,843.64 271,435.36 0.47 7,126.04 2_MWD+IFR2+MS+Sag (4) 14,005.00 59.23 6.59 9,893.37 9,852.47 7,117.21 924.41 5,977,894.05 271,442.75 0.00 7,176.98 PROJECTED to TD Checked By: Chelsea Wright ww.o.aw�.w.•w Approved By: Mitch Laird `- a. ,q ., Date: 81941gn1R 8/242018 6:35:09PM Page 14 COMPASS 5000.1 Build 81E Lease & Well No. County Hilcorp Energy Company CASING & CEMENTING REPORT END 4-26A Date Run 21 -Aug -18 State Alaska Supv. S. Barber/ C. Montague CASING RECORD Production � TD 14,005.00 Shoe Depth: 14,000.00 PBTD: 13,993.00 No. As. Delivered 234 No. Jts. Run 212 No. Jis. Returned 22 Fig. Delivered 9,607.66 Fig. Run 8,705.48 Fig. Returned 902.18 Length Measurements W/O Threads Fig. Cut JL Ftg. Balance RKB RKB to BHF RKB to CHF RKB to THF Csg WL On Hook: Csg Wt. On Slips: Rotate Csg Fluid Description: Liner hanger Info (Make/Model): Liner hanger lest pressure: Centralizer Placement: Stage Collar@ 13220 reflush(Spacer) 260 93 Yes X No LSND Type Float Collar: Type of Shoe: Recip Csg Conventional Bullnose _ Yes X No No. His to Run: 43 Casing Crew: Weatheford Ft. Min. 10.3 PPG Baker HRDE ZXHD Liner Top Packer Liner top Packer?: X Yes No 3000 Floats Held _ Yes _ No Centex SII 7" x 8.5" Bowspring 2 centralizers each with stop ring In middle of joint to joint 8 (13662'), 1 each floating to joint 85 (10503' CEMENTING REPORT Type Perforations Closure OK Clean Spacer III Denshy (ppg) Slurry Class G Tall Slurry Type: m Density(ppg) _ Z Post Flush (Spacer) 00 Type: Clean Spacer III w N rllenlenn.nnn, 15.8 Volume pumped (BBLs) 20.5 10.5 Volume pumped (BBLs) 10 Sacks: 99.5 Yield: 1.16 Mixing / Pumping Rate (bpm): Sacks: Yield: Volume pumped (BBLs) Moving / Pumping Rate (bpm): Densfty(ppg) 10.5 Rate (bpm): 5 Volume: 2 LSND Drilling fluid Density (ppg) 10.3 Casing (Or Liner) Detail 2 Volume (actual / calculated): 162.7 (psi): 950 Setting Depths As. Component Size Wt. Grade THD Make Length Bottom Top ant returns to surface? Float Shoe 75/8 26.0 _Yes X No Vol to Surf: TXP ant In Place At: 2.40 14,000.00 13,997.60 1 Casing 7 26.0 L-80 TXP 39.61 13,997.60 13,957.99 Float Collar 75/8 TXP 2.50 13,957.99 13,955.49 2 Casing 7 26.0 L-80 UP 82.32 13,955.49 13,873.17 Landing Collar 75/8 26.0 UP Baker 3.35 13,873.17 13,869.82 209 Casing 7 26.0 L-80 TXP 8,583.55 13,869.82 5,286.27 Liner Pup Joint 7 26.0 L-80 TXP 4.84 5,286.27 5,281.43 Flex Lock Han er 85/8 L-80 H563 xTXP Baker 9.19 5,281.43 5,272.24 Crossover 75/8 26.0 P-110 VamHTxH563 0.95 5,272.24 5,271.29 HRDE ZXHD Liner Top Packer 1 85/8 VAM Top HT I Baker 16.25 5,271.29 5,255.04 Csg WL On Hook: Csg Wt. On Slips: Rotate Csg Fluid Description: Liner hanger Info (Make/Model): Liner hanger lest pressure: Centralizer Placement: Stage Collar@ 13220 reflush(Spacer) 260 93 Yes X No LSND Type Float Collar: Type of Shoe: Recip Csg Conventional Bullnose _ Yes X No No. His to Run: 43 Casing Crew: Weatheford Ft. Min. 10.3 PPG Baker HRDE ZXHD Liner Top Packer Liner top Packer?: X Yes No 3000 Floats Held _ Yes _ No Centex SII 7" x 8.5" Bowspring 2 centralizers each with stop ring In middle of joint to joint 8 (13662'), 1 each floating to joint 85 (10503' CEMENTING REPORT Type Perforations Closure OK Clean Spacer III Denshy (ppg) Slurry Class G Tall Slurry Type: m Density(ppg) _ Z Post Flush (Spacer) 00 Type: Clean Spacer III w N rllenlenn.nnn, 15.8 Volume pumped (BBLs) 20.5 10.5 Volume pumped (BBLs) 10 Sacks: 99.5 Yield: 1.16 Mixing / Pumping Rate (bpm): Sacks: Yield: Volume pumped (BBLs) Moving / Pumping Rate (bpm): Densfty(ppg) 10.5 Rate (bpm): 5 Volume: 2 LSND Drilling fluid Density (ppg) 10.3 Rate (bpm): 2 Volume (actual / calculated): 162.7 (psi): 950 Pump used for disp: Rig Bump Plug? _Yes --X- No Bump press ig Rotated? _Yes X No Reciprocated? Yes X No % Returns during job 100 ant returns to surface? _Yes X No Spacer returns? _Yes X No Vol to Surf: 0 ant In Place At: 16:20 Date: Estimated TOC: 12,460 Dd Used To Determine TOC: CAST / If illi X8/29/2018- 5.42 `.-.,/ da- /3320' - = w« ->'i=n- VS a �a ' "- �+ 10 r - Is Post lob Calculations: Calculated Cmt Vol ® 0% excess: 15.15 Total Volume cmt Pumped: 20.5 Cmt returned to surface: 0 Calculated cement left in wellbore: 20.5 OH volume Calculated: 11.29 OH volume actual: 13.48 Actual % Washout: 19 Schwartz, Guy L (DOA) From: Taylor Wellman <twellman@hilcorp.com> Sent: Tuesday, September 04, 2018 10:32 AM To: Schwartz, Guy L (DOA) Subject: RE: (EXTERNAL] RE: Hilcorp End 4-26A (PTD #218-081) Update Guy, I forgot to include the information you asked for on the phone. Top of Reservoir: 13,953' and Angle across reservoir: 63 deg Thanks, Taylor Taylor Wellman Hilcorp Alaska, LLC— Ops Engineer: Alaska North Slope Team Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com From: Taylor Wellman Sent: Tuesday, September 04, 2018 9:52 AM To: Schwartz, Guy L (DOA) Cc: Monty Myers; Rixse, Melvin G (DOA); Joe Engel Subject: RE: [EXTERNAL] RE: Hilcorp End 4-26A (PTD #218-081) Update Guy, Here is a copy of the CBL for Endicott 4-26A. I've had to cut it down to the section above where the cement was placed. You'll get another email from this point down to the PBTD and the section across the production reservoir you have any concerns with the CBL let me know. After the CBL, a CIBP was run and the liner passed a pressure test to 1500psi. Currently we are readying to run completion. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC — Ops Engineer: Alaska North Slope Team Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com From: Joe Engel Sent. Thursday, August 30, 2018 3:40 PM To: Schwartz, Guy L (DOA) Cc: Monty Myers; Taylor Wellman; k,_. e, Melvin G (DOA) Subject: RE: [EXTERNAL] RE: Hilcorp End 4-26A (PTD #218-081) Update Thank you, Guy. The MOC has been updated. Joe Joe Engel I Drilling Engineer I Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 1 Anchorage I AK 199503 Office: 907.777.8395 1 Cell: 805.235.6265 From: Schwartz, Guy L (DOA) [mailto:guy.schwartz@alaska.gov] Sent: Thursday, August 30, 2018 1:51 PM To: Joe Engel <jengel@hilcorp.com> Cc: Monty Myers <mmyers@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com>; Rixse, Melvin G (DOA) <me Ivi n. rixse@a laska.gov> Subject: [EXTERNAL] RE: Hilcorp End 4-26A (PTD #218-081) Update Joe, You have approval to test the liner and LT packer to 1500 psi as proposed below. Hopefully the squeeze perfs can hold that much pressure. The Liner lap will be tested again later to 3000 psi once the production packer is set. Update the MOC with the changes. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Cot nrnission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). If 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 Guy Schwartz at (907-793-1226) or (Guv.schwartz@alaska.aov). From: Joe Engel <jen2el@hilcorp.com> Sent: Thursday, August 30, 2018 12:43 PM To: Schwartz, Guy L (DOA) <guv.schwartz@alaska.eov> Cc: Monty Myers <mmyers@hilcorp.com>; Taylor Wellman <tweliman@hilcorp.com> Subject: Hilcorp End 4-26A (PTD #218-081) Update Mr. Schwartz — I wanted to give you an update on the remedial cement job on End 4-26A. We were able to successfully circulate 20.5 bbl of 15.8 ppg cement through our perforations at 13,325' MD, with full returns through the entire job (the 7" liner top packer was not set). We will be proceeding with operations outline in Taylors previous email, copied again below for reference: • Drill out Cement retainer, cement and CIBP • Perform CBL After the CBL is performed we will be setting a 7" CIBP on top of our liner shoe at "' 13,993' MD. Once the CIBP has been set we will RIH and set the 7" liner top packer, pressure test the 9-5/8" x 7" liner top packer, and then pressure test the 7" Liner. In the PTD, the liner test was approved at 3000psi for 30 min. We tested our 7" liner with the initial TOC at 11,530' MD inside the 7" liner to 3100psi prior to drilling the cement column out. In order to not compromise the cement behind the 7" at the perforations, Hilcorp would like to reduce the liner test pressure to 1500 psi for 30 min. Regarding the gas lift upper completion, we will be setting the production packer above the perforations at — 13,225' MD. Once the 4.5" x 7" production packer is set, we will test the 4.5"x7" annulus to 3000psi. Please let me know if you would like any further information . Thank you for your time. Joe Joe Engel I Drilling Engineer I Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 1 Anchorage I AK 199503 Office: 907.777.8395 1 Cell: 805.235.6265 Guhl, Meredith D (DOA) From: Cody Dinger <cdinger@hilcorp.com> Sent: Friday, October 5, 2018 2:10 PM To: Guhl, Meredith D (DOA); Davies, Stephen F (DOA) Subject: FW: [EXTERNAL] DIU SDI 4-26A, PTD 218-081, Complete list of Formations for 10-407 Hi Meredith, Please see the response from Daniel below. Thanks, Cody From: Daniel Yancey Sent: Friday, October 05, 2018 1:52 PM To: Cody Dinger <cdinger@hilcorp.com> Subject: RE: [EXTERNAL] DIU SDI 4-26A, PTD 218-081, Complete list of Formations for 10-407 We kicked off just above the Colville Top Tuff: 12385' MD 9069' TVD Top HRZ: 13344' MD 9560' TVD LCU: 13955' MD 9868' TVD Top K2B: 13955' MD 9868' TVD At TD the well is in the K2B From: Cody Dinger Sent: Friday, October 05, 2018 1:00 PM To: Daniel Yancey <dvancev@hilcorn.com> Subject: FW: [EXTERNAL] DIU SDI 4-26A, PTD 218-081, Complete list of Formations for 10-407 Da n, Looks like we needed more on 4-26A. Please provide ASAP. From: Guhl, Meredith D (DOA)[mailto:meredith.guhl@alaska.gov] Sent: Friday, October 05, 2018 11:21 AM To: Cody Dinger <cdinger@hilcoro.com> Cc: Davies, Stephen F (DOA) <steve.davies@alaska.gov> Subject: [EXTERNAL] DIU SDI 4-26A, PTD 218-081, Complete list of Formations for 10-407 Hi Cody, Could you please provide a complete list of formations and markers encountered (box 29) in Duck Island Unit SDI 4-26A, completed 9/10/2018? Thank you, Meredith Meredith Guhl 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 GuhI at 907-793-1235 or meredith.¢uhl@alaska.eov. DATE 09/06/2018 Z1 8081 Sc,., Nolan Hilcorp Alaska, LLC p G GeoTech II 3800 Centerpoint Drive, Suite 1400 J V 7 7 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Abby Bell Natural Resource Technician II 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTA RECEIVED SEP 0 7 2018 AOGCC CD 1: Log Viewers 8/27/2018 8:26 PM File folder CGM 8/27/2018 8:26 PM File folder . Definitive Survey 8/27/2018 8:26 PM File folder . EMF 8/27/2018 8:26 PM File folder . LAS 8/27/2018 8:26 PM File folder . PDF 8/27/2018 8:26 PM File folder . TIFF 8/27/2018 8:26 PM File folder Please include current contact information if different from above. Please acknowledge receipt by sig*g and ret�rniiyg one copy of this transmittal or FAX to 907 777.8337 Received By: / I // // ///L, \ I I Date: THE STATE GOVERNOR BILL WALKER Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Duck Island Unit, Endicott Oil Pool, END SDI 4-26A Permit to Drill Number: 218-081 Sundry Number: 318-362 Dear Mr. York: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1 433 Fax 907.276.7542 W W W.aogcc.alaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Hollis S. French Chair r� DATED this27� day of August, 2018. RBDM&� AUG 2 7 2018 r STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 RECEIVE® Ips 2` (z4//e AOGCC 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑Q ` 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: Hilcorp Alaska LLC Exploratory ❑ Development ❑Q Stratigraphic ❑ Service ❑ 218-081 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-029-21835-01-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 462.007 Will planned perforations require a spacing exception? Yes ❑ No Q END SDI 4-26A ' 9. Property Designation (Lease IN 10. Field/Pool(s): ADL047502 & ADL 047503 Duck Island Unit / Endicott Pool' 11, PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): ±14,005 ±9,893 ±13,395 ±9,888 3,100 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 161' 30" 161' 161' N/A N/A Surface 2,502' 13-3/8" 2,502' 2,502' 5,020psi 2,260psi Intermediate 5,417' 9-5/8" 5,417' 5,413' 6,870psi 4,760psi Production Liner I ±8,745' 7" 1±14,005 ±9,893' 7,240psi 5,410psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic N/A N/A N/A Packers and SSSV Type: Packers and SSSV MO (ft) and TVD (ft): NA and N/A NA and N/A 12. Attachments: Proposal Summary Q Wellbore schematic Q 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: 8/28/2018 OIL Q ' WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Be York Contact Name: Taylor Wellman —1k/ Authorized Title: Operations Manager Contact Email: twellma0 hllcor .com (` ��?j Contact Phone: 777-8449 Authorized Signatur '!. ArJ O/ L Date: 8/21/2018 COMMISSION USE ONLY Conditions of app vel: Notify Commission so that a representative may witness Sundry Number: I Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes No I�'-�7 Spacing Exception Required? Yes ❑ No Subsequent Form Required: ' 0 — i V / APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: l 7 r CJ RBDMS44AUG 2 7 2018 �{D'[, Submit Form and Form 10-403 Revised 4/2017 Approved application is v Y F 1, n INtAtof approval. Attachm is in uplicate IKYy/�� S•2Z o U Hil.n, Alaska. LG Post Sidetrack Work Well: END 4-26A PTD: 218-081 API: 50-029-21835-01-00 Well Name: END 4-26A API Number: 50-029-21835-01-00 Current Status: Shut in — Post sidetrack Rig: SL/EL Estimated Start Date: August 28, 2018 Estimated Duration: 2 day Reg.Approval Req'std? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts 777-8398 Permit to Drill Number: 218-081 First Call Engineer: Taylor Wellman (907) 777-8449 (0) (907) 947-9533 (M) Second Call Engineer: Chris Kanyer (907) 777-8377 (0) (907) 250-0374 (M) AFE Number: 1811484C WeIIEZ Entry Required? Yes Current Bottom Hole Pressure: 4,100 psi @ 10,000' TVD (K2B BHP taken on 6/30/18) Maximum Expected BHP: 4,100 psi @ 10,000' TVD (K2B BHP taken on 6/30/18) Max Predicted Surface Pressure: 3,100 psi (Max Expected BHP — (A psi/ft * 10000 ft)) Max Deviation: 63.7 deg at 7,401' and Minimum ID: 3.725" XN Nipple @ ±13,590' and (will be updated in final well schematic following completion) Brief Well Summary: The Endicott 4-26A well is a recently sidetracked well into the K2B. Objective: 1. Install gas lift design 2. Perforate K2B Notes: - The well is currently unperforated and is hydraulically isolated from any formations. - All completion component depths are approximate depths and need to be confirmed on the finalized tallies. Procedure: No sundry required to proceed with the initial steps (see note below when sundried operations begin) Slickline 1. RU SL unit. Pressure test PCE to 250psi low / 2,000psi high. 2. Pull ball & rod and RHC plug body from XN nipple at ±13,550' md. a. NOTE: All completion component depths are approximate depths and need to be confirmed on the finalized tallies. 3. MU 3.65" drift and drift tubing down to the PBTD. 4. Pull DGLV's from Sta #5 at ±3,851' and and Sta #6 at ±5,450' md. 5. Set LGLV's in Sta #5 & 6 as per GL design pull/run sheet. 6. RD SL unit. Operations 7. Apply gaslift to the IA to circulate out fluid from the s/o valve at 5,450' md. a. Shoot FL shots to confirm tbg FL is at this GLM. b. Pump 1-2bbls of McOH into the IA to help prevent ice formation at the GLM's during the circ. S. Bleed down the IA and tubing pressure to 500psi. H llilc ,p Alaska. LD Post Sidetrack Work Well: END 4-26A PTD: 218-081 API: 50-029-21835-01-00 a. This will provide an underbalance of 1,OOOpsi when perforating into the K2B. Steps beyond this point are require an approved Sundry. Do not proceed without this in hand. E -Line 9. RU EL unit and pressure test PCE to 250psi low/3,250psi high. 10. MU perforating toolstring and RIH. a. Perf guns to be used: 2-7/8" to 3-1/8", 6-12spf, 60 deg phasing with deep penetrating charges. Run # Perf Top Perf Bottom Perf Length Formatio-n--F— ormation Carrier/Charge/Note 1 ±13,962' ±13,982' 20' K2B Shooting-1,000psi underblanced Total 20' Table 1: Proposed Perf Gun Runs Note: Final depths to be confirmed in "Final Approved Perf Sheet" 11. Correlate and perforate for Run #1 as in Table 1: Proposed Perf Gun Runs. a. These will be perforated underbalanced. Target is to be 1,OOOpsi under. This equates to a surface tubing pressure of 500psi with a FL at 5,450' md. b. Correlation log to be used: END 4-26A HES Cast -M CBL. c. Note any pressure changes in the report. 12. POOH and RD E -Line unit. 0 Hil.im Alaaka, LLC KB Elev.: 54.6/ BF Elev.: 16 TD=±14,005' (MD)/TD=+.5,893'(TVD) PBTD=±13,395' (MD) / PBTD = 9,888'(TVD) PROPOSED Duck Island Unit Well: END 4-26A Last Completed: xx/xx/xxxx PTD: 218-081 SAFETY NOTES TREE & WELLHEAD H25 Readings Average 230-260 PPM on A/L&Gas Injectors Tree 4-1/8"CIW Well Requires a SSSV Wellhead MCEVOY OPEN HOLE / CEMENT DETAIL 13-3/8" 4,557 cu/ft Permafrost in 17.5" Hole 9-5/8" 575 cu/ft Class'G' in a 12-1/4" Hole 7" 420 cu/ft Class "G" in 8-1/2" Hole CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 30" Conductor N/A/N/A/N/A N/A Surface 161' N/A 13-3/8" Surface 68/ N-80/ Btrs 12.415 Surface 2,502' 0.150 9-5/8" Intermediate 47/NT80S/NSCC 8.681 Surface 5'417 (KOP) 0.0732 7" Prod Liner 26 / L-80 / TXP 3.958 5,260' 14,005' 0.0372 TUBING DETAIL 4-1/2" Tubing 12.6/ 13Cr/JFE Bear 1 3.958 1 Surface 1 ±13,600 1 0.0152 WELL INCLINATION DETAIL Max Hole Angle = 63.7 deg. @ 7,401' Angle at Top Perf= Deg. @' JEWELRY DETAIL No Depth Item 1 ±1,500' 4.5"SLBTRMAXXSSSVW/X-Nipple-ID=3.813" 2 ±5,250' 9-5/8"0" BKR HRDE ZXHD Packer K26 GLM DETAIL: Mana SPM -1-1/2" w/ RK Latch 4 ±3,851' STA 5: Dev=, VLV= DMY, Port= 0, TVD=', Date= 5 ±5,450' STA S: Dev=, VLV= DMY, Port= 0, TVD=', Date= 3-1/8" GLM DETAIL: Special Clearance SPM -1" w/ RK Latch 5 ±6,900' STA 4: Dev=, VLV= DMY, Port= 0, TVD=', Date= 6 1:8,800' STA 3: Dev=, VLV= DMY, Port= 0, TVD=', Date= 7 ±10,700' STA 2: Dev=, VLV= DMY, Port= 0, TVD=', Date= 8 ±12,600' STA 1: Dev= , VLV= DMY, Port= 0, TVD=', Date= 9 ±13,430' 4-1/2"X Nipple -ID=3.813" 10 ±13,480' 7" x 4-1/2" Packer - ID= 3.958" 12 ±13,550' 4-1/2"OTIS XN Nipple - ID- 3.725" 13 ±13,600' 4-1/2"WLEG-ID= 3.958"-Stm@13,602' PERFORATION DETAIL END Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Size K26 ±13,962' ±13,982' 1 1 20' 1 Future Future 3-1/8" GENERAL WELL INFO API: 50-029-21835-01-00 Initial Completion -8/6/1988 RWO - 2/21/1995 Sand Back & Cmt Cap -3/31/99 Sidetrack Completion - 8/25/18 Revised By: TDF 08/21/2018 THE STATE Alaska Oil and Gas °fALASKA Conservation Commission GOVERNOR BILL WALKER Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Endicott Field, Endicott Oil Pool, SDI 4-26A Hilcorp Alaska, LLC Permit to Drill Number: 218-081 Surface Location: 2592' FSL, 736' FEL, Sec. 8, TI IN, R17E, UM Bottomhole Location: 859' FNL, 218' FWL, Sec. 4, TI IN, R17E, UM Dear Mr. Myers: .333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.claska.gov Enclosed is the approved application for the permit to redrill the above referenced development 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. 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. 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, Hollis S. French Chair ,a DATED this Z3 day of July, 2018. STATE OF ALASKA / F SKA OIL AND GAS CONSERVATION COMIC . SION PERMIT TO DRILL �l�L�•[w�Yi1u.� RECEIVED JUL 0 5 2018 Ia. Type of Work: Well Class: Exploratory - Gas Service- WAG ❑ Service - Disp ❑ 1c. g�I,tefIN ifWeltis proposed for: Drill ❑ Lateral T1,11b.trProposecil etigrphicTest ❑ Development -Oil ❑� Service- Winj ❑ Single Zone ❑� ' Co31bZd Gas ❑ Gas Hydrates ❑Redrill❑� ' Reentry xploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket Q • Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 ' Endicott SDI 4-26A 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 MD: 13,906' • TVD: 9,890' Duck Island Unit Endicott Pool 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: 2592' FSL, 736' FEL, Sec 8, T11 N, R1 7E, UM, AK ADL047502 (SHL) ADL047503 (TPH, BHL) Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 951' FNL, 206' FWL, Sec 4, T11 N, R1 7E, UM, AK N/A 7/27/2018 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 859' FNL, 218' FWL, Sec 4, T11 N, R17E, UM, AK 5029 5,018' to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 40.4 15. Distance to Nearest Well Open Surface: x-270300 y- 5970808 Zone -3 GL / BF Elevation above MSL (ft): 13.9 to Same Pool: 650' to END 3-09A 16. Deviated wells: Kickoff depth: 5,417 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 60 degrees Downhole: 4100 Surface: 3164 ' 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 8-1/2" 7" 26# L-80 TXP 8,656' 5,250' 5,248' 13,906' 9,890' 215 ft3 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): 11,730' 10,648' 5,367' 5,367' 5,364' 11,600' Casing Length Size Cement Volume MD TVD Conductor/Structural 161' 30" Driven 161' 161' Surface 2,504' 13-3/8" 4557 ft3 2,504' 2,504' Intermediate 10,725' 9-5/8" 575 ft3 10,725' 9,836' Production/Liner 1,263' 7" 420 ft3 11,730' 10,648' Liner Perforation Depth MD (ft): See attached current Wellbore Perforation Depth TVD (ft): See attached current Wellbore Schematic Schematic Hydraulic Fracture planned? Yes ❑ No 0 20. Attachments: Property Plat O BOP Sketch Divener Sketch v e Drilling Program Time v. Depth Plot v Shallow Hazard Analysis Seabed Report e Dri g Fluid Program e 20 AAC 25.050 requirements e 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Joe Engel Authorized Name: Monty Myers Contact Email: 'en el hilcor .Com Authorized Title: Drilling Manager Contact Phone: 777-8395 Authorized Signature: Date: �%• SIR Commission Use Only Permit to Drill 77 � /� Number: L�[� ^1Z Number: jA; 0-(�7j —� � ©/—C� Permit Approval Date: See cover letter for other requirements. 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: Other: y�O,pSr ^ 5T Samples req'd: Yes❑,No� Mudlogreq'd:Yes❑ NoO F51 HzS measures: Yes NoDirectional svy req'd: Yes 4 N E] �V�� �' %/�j F w!►L4'�rR�� T� Spacing exception req'd: Yes El No Inclination -only svy req'd: Yes ❑ No 0Q Post initial injection MIT req'd: Yes ❑ No ❑ Pyr WEta- APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: 10 Submit Form and �i Form 10-401 Revised 5/2017 This permit is valid r ntt ssf o the ate of approval per 20 AAC 25.0055 g) chm is in Duplica n'� t 7 t / H Hilrnrp Aleeka, LIT.. 7/5/2018 Commissioner Alaska Oil & Gas Conservation Commission 333 W. 71h Avenue Anchorage, Alaska 99501 Re: Application for Permit to Drill Endicott SDI 4-26A Dear Commissioner, Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 Tel 907 777 8395 Email jengel@hilcorp.com Hilcorp Alaska, LLC hereby submits for review and approval for a Permit to Drill a sidetrack production well at Endicott Satellite Drilling Island (SDI), well slot 4-26. Endicott SDI 4-26A is to be a slot recovery sidetrack producer with the Kekiktuk 2B sand as the primary target. - The parent well, 4-26, is a long term shut in injector (S/I since 2007) where the reservoir was abandoned and prepared for the sidetrack with the E -line & the ASR rig in June 2018 (operations submitted on a separate sundry). Current wellbore schematic is attached. y_ z 64rDL1,#VV oryL/ Drilling operations are expected to commence approximately July 27th, 2018, pending rig move / barge schedule. The Innovation Rig will be used to sidetrack and complete the wellbore. Before sidetrack operations begin, the existing 4.5" kill string will be pulled. The existing 9-5/8" surface casing will be used and a pressure test conducted prior to drilling the sidetrack. A clean out run will be performed, a whip stock assembly will be run and set, and a window will be milled at ±5,400' MD / 5,395' TVD. The directional plan for this sidetrack will be to build to a 60° inclination and held to TD, 8-1/2" hole will be drilled to ± 13,906 MD / 9,891' TVD. 7" liner will then be run and cemented. The well completed with a 4-1/2" gas lift completion. Post rig evaluation and perforation will follow. Please find attached the Form 10-401, Application For Permit to Drill per 20 AAC 25.005 (a), and the drilling program for Endicott SDI 4-26A, which includes information required by 20 AAC 25.005 (c). If you have any questions, or require further information, please do not hesitate to contact myself (Joe Engel) at 777-8395 or jengel@hilcorp.com or Monty Myers at 777-8431 or mmyers@hilcorp.com. Sincerely, e� Joe Engel Drilling Engineer Hilcorp Alaska, LLC Page 1 of 1 Hilcorp Alaska, LLC Endicott SDI 4-26A Sidetrack Drilling Program Version 1 July 5, 2018 K END 4-26A Sidetrack Drilling Procedure 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 Current Wellbore Schematic..........................................................................................................6 8.0 Proposed Wellbore Schematic........................................................................................................7 9.0 Drilling / Completion Summary.....................................................................................................8 10.0 Mandatory Regulatory Compliance / Notifications.....................................................................9 11.0 Rig Orientation on Endicott SDI: ................................................................................................ 11 12.0 Reservoir Abandonment & Sidetrack Preparation....................................................................12 13.0 Milling & Drilling Fluid Program................................................................................................13 14.0 Cleanout Run, MU and RIH with 9-5/8" Whipstock Assembly................................................15 15.0 Set Whipstock and Mill 9-5/8" Window: ..................................................................................... 18 16.0 Drill 8-1/2" Hole Section...............................................................................................................20 17.0 Run 7" Casing................................................................................................................................23 18.0 Cement 7" Casing..........................................................................................................................26 19.0 Perform 7" Cleanout Run.............................................................................................................28 20.0 Contingency 6-1/8" OH x 4-1/2" Liner........................................................................................28 21.0 Run 4-1/2" Upper Completion.....................................................................................................29 22.0 RDMO............................................................................................................................................29 23.0 Innovation Rig BOP Schematic....................................................................................................30 24.0 Days vs Depth.................................................................................................................................31 25.0 Formation Tops & Information...................................................................................................32 26.0 Anticipated Drilling Hazards.......................................................................................................34 27.0 Innovation Rig Layout..................................................................................................................35 28.0 FIT Procedure................................................................................................................................36 29.0 Innovation Choke Manifold Schematic.......................................................................................37 30.0 Casing Design Information...........................................................................................................38 31.0 8-1/2" Hole Section MASP............................................................................................................39 32.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................40 33.0 Surface Plat (As Built) (NAD 27).................................................................................................41 34.0 Drill Pipe Information 5" 19.5# 5-135 DS -50 & NC50...............................................................42 ff Ilikc ,I. Al.kn, LIA: 1.0 Well Summary END 4-26A Sidetrack Drilling Procedure Well 4-26A Pad Endicott SDI - Planned Completion Type 7" Cemented Liner / 4-1/2" Gas Lift Target Reservoirs Kekiktuk K2B Planned Well TD, MD / TVD 13,907' MD / 9,891' TVD PBTD, MD / TVD ±13,820' MD / 9,832 TVD Surface Location(Governmental) 2592' FSL, 736' FEL, Sec 8, TI IN, R17E, UM, AK Surface Location (NAD 27 — Zone 4) X=270300.61, Y=5970808.6 - Top of Productive Horizon (Governmental) 951' FNL, 206' FWL, Sec 4, T11N, R17E, UM, AK TPH Location (NAD 27) X= 271437.86, Y= 5977793.48 BHL Governmental 859' FNL, 218' FWL, Sec 4, TI IN, R17E, UM, AK BHL AD 27) X=271451.45, Y=5977884.78 AFE Number 1811484 AFE Drilling Das 19 AFE Completion Das 4 AFE Drilling Amount $3,789,268 AFE Completion Amount $2,032983 AFE Facility Amount $450,000 Maximum Anticipated Pressure (Surface) 3,164 psig Maximum Anticipated Pressure (Downhole/Reservoir) 4,100 si Work String 5" 19.5# NC50 & DS50 KB Elevation above MSL: 26.5 + 13.9 ft = 40.4 ft AMSL GL Elevation above MSL: 13.9 ft AMSL BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams Page 2 July 2018 2.0 Management of Change Information END 4-26A Sidetrack Drilling Procedure 11 Hilcorp Alaska, LLC Hilc rp Changes to Approved Permit to Drill Date: July 2, 2018 Subject: Changes to Approved Permitto Drill for Endicott SDI 4-26A File #: Endicott SDI 4-26A Drilling and Completion Program) Any modifications to Endicott SDI 4-26A Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be approved by AOGCC prior to operations. Approval: Manager Prepared: Drilling Engineer Date Page 3 July 2018 3.0 Tubular Program: END 4-26A Sidetrack Drilling Procedure HoleOD (in) ID (in) Drift Conn Wt Grade Conn B" Section in OD in #/ft 7240 5410 604 8-1/2" 7" 6.276 6.151 7.656 26 L-80 TXP 4.0 Drill Pipe Information: 5.0 Casing Inspection All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 4 July 2018 K Ililm.,p Al.k., IAA: 6.0 Internal Reporting Requirements END 4-26A Sidetrack Drilling Procedure 6.1 Fill out daily drilling report and cost report on WellEz. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 6.2 Detailed Daily Plan Forwards • Distributed to jen el hilcop.com and mmyers@hilcop.com 6.3 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp com, ienael@hilcoM.com and cdinger@hilcorp.com 6.4 Intranet Home Page Morning Update • Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 6.5 EHS Incident Reporting • Health and safety: Notify EHS field coordinator. • Environmental: Drilling Environmental coordinator • Notify Drilling Manager & Drilling Engineer • Submit Hilcorp Incident report to contacts above within 24 hrs 6.6 Casing Tally • Send final "As -Run" Casing tally to mmvers .hilcorp.com, ienael@hilcoM.com and cdin er .hilcorp.com 6.7 Casing and Cmt report • Send casing and cement report for each string of casing to mmyers@hilcoM.com. ien el hilcorp.com and cdinger(ahilcorp.com 6.8 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmvers@hilcoro.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 ienael@hilcoro.com Completion Engineer Taylor Wellman 907.777.8449 907.943.9533 twellman@hilcorp.com Geologist Daniel Yancey 907.748.8458 907.250.9632 dvancev@hilcoro.com Reservoir Engineer Chris Kanyer 907.777.8377 907.250.0374 ckanver@hilcoro.com Drlg Environmental Coord Keegan Fleming 1 907.777.8477 1 907.350.9439 1 kfleminaC@hilcoro.com EHS Manager Carl Jones 907.777.8327 907.382.4336 caiones@hilcoro.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinaer@hilcoro.com Page 5 July 2018 7.0 Current Wellbore Schematic END 4-26A Sidetrack Drilling Procedure Duck Island 6 Well : END 4-2-26 SCHEMATIC Last Completed: 2/20/1995 114 Pro: 188-072 SAFETY NOTES TREE & WELLHEAD KSEW.:SAE'/6PPe.: 13 2115 Re431 230-2rD PW- A/li Gu In Tree MCNtri T WeBRequresa SSSY WNNeM M[F.V11Y 2 OPEN HOLE/CEMENTDErAIL u •s• 6.ss1ra Peradrmlmns•Nwe 9$8" 5]5¢1 Class'G'ina 12 -Ile Ilu1e a.y.' T 42(2 Cla Ina 'Hale CASING DEFAIL s ftr„}3�Ti � 1A a 3yR �6 Tma�eYrw'c w Tma vcR r3r� TD-II'M (nc{ / TD=1454i "115=11,407(NV)/Ism, X'V7T Cj Page 6 TUBING DETAIL 410.' K185W 12.WL TlS 3958 Surh¢ 1509 0.0152 4- Tub' TDS 3958 3' 140] 0.0152 WELL INCLINATION DETAIL MU Hnk e:6D . @B19C M61eaITap Ped=366eg. P 14798' JEWELRY DETAIL No Depth Rem 1 i'iIIL—IIIIII 968"UBP 2 Size Type Vim! / Grade/ Conn Drift III I Top Btm BPF 30' WA/WAYWA WA Surtam 161' WA 13-3,M' S,efe¢ 69/14w 12615 Surla¢ 3502' am 9-5/8' pna noon d]/MICS NSCC fl681 SurFate 9ATr 011332 93/6' Prodeceion I 41/"SII/NSCC fl681 9,0]8' 14]35' OA]32 T Inver I 29/Yr1111N9n 6.184 14667 11730 (UXIM s ftr„}3�Ti � 1A a 3yR �6 Tma�eYrw'c w Tma vcR r3r� TD-II'M (nc{ / TD=1454i "115=11,407(NV)/Ism, X'V7T Cj Page 6 TUBING DETAIL 410.' K185W 12.WL TlS 3958 Surh¢ 1509 0.0152 4- Tub' TDS 3958 3' 140] 0.0152 WELL INCLINATION DETAIL MU Hnk e:6D . @B19C M61eaITap Ped=366eg. P 14798' JEWELRY DETAIL No Depth Rem 1 5551' 968"UBP 2 1425 4-11r OTSa Ni k -ICN 3.913- 3 14216 "Ir A¢Mr utdr 4 142]] ejff. 4-Itr TNe 110BP Porker- ID. "IF S 10.311' 6 OT15KNi 6r-103913' 6 10,394' q -]/Y 0115 #J Hiade-Ip=3.)2S 1 14GS' 4-U2"WLEG-IO=3.ffie"-$tnp 1440]-F1M0=10,412' e I47ItY [apvdabkN w/16 0.l temn8vn tw PERFORATION DETAIL END Sands Top(MD) MM(MD) Tap(IVO) ,ZMnw) 1T Data stay{ size 14]9e' 14806' SAW 9906• 10 6/19/3W1 Omed 24ir 14869' 148]6' 9,953' 995T S 6!19!3001 Owed 2-1 10919 14920 9,906' 9990 10 6110./3001 arced 2-741' 10930 14946' 106mr Vzole 14 6,11812001 0¢ed 2-7111' 11910 Hoer 1 066' 10,109' 52 $13/1 s� 5 11 20 SI,aeor IoA7x ]CAW 20 4,,'IW999 Clmed 3-3Ar FNDUb 11953' 111066' 1 101' m,1139• 10 4/IS/199I a¢ed 3 3j 11.149 31,130 loner 14161' M &6/1996 cia 3-3t8" 11,100 11,142' 14ar 30.1]1' 43 SV411M S4. WA 13.1 11,1]6' 1419, 111 6 8/29/1996 O¢ed IV'A 11.139 13,]80' 14193' 10,201' l0 8tV19Re 3-313' 11,200' 11110 1 21T ]0.225' f0 2/1/199] arced 3-319' 11.221! 11,23W I 1413Y 10,246 14 1/1/199] ci a 3-38' Refererl¢Pmf .A11A50uJGaan1/30JI9BR GENERAL WELLINFO Revised br IDP N22/2ols July 2018 K lliie,q..AI.kq I.IA: 8.0 Proposed Wellbore Schematic ------------ 11 w 0265TAtoyeGL TOW@ 5,417 LD 1, IgA /�y- z6 E 3 5 T r / f4 1�7 Vm1 END 4-26A Sidetrack Drilling Procedure Duck Island Unit Well: END 4-26A Completed: Future PTD: TBD Size I Type I !WGrade/Conn I n I Top I Btm TUBING DETAIL ____________________________________________------------------------------ JEWELRY ____ - JEWELRY DETAIL- Lower Completion j No Depth Item 4 15250' 9-5:8:7' Uner Top Packer PERFORATION DETAIL END Sands I Top(MD) I Btm(MO) I Too ITVD) I BtM(TVD) I Fr I Date I Status I Size ------------------------------------------- OPEN HOLE / CEMENT DETAIL g 8.112- 1 216tr3 y w 10ri /2/7? •' / WELL INCLINATION DETAIL Nlax Hole Angle =TBD Anile xTop ---- =780 TREE & ELLHEAD i W Tne &1w CM 7,)aEJ7 /3/ 9 B c walnaa TDs 13,906' (M7)/To- 9,8NUVDI PBTD=I9,81V(MI PBTD-29,B37Mq GENERAL WELL INFO API: Sp-02321835-0DOp Ori nal Com on - 6 198E Page 7 July 2018 JEWELRY DETAIL- Upper Completion No Depth Item 1 11,500' HES NE Tft858V w/x rofile IILiE23^ GLM Detail: Mana / RK Latch / 1-1/2' 2 TBD GLM 3 TED GLM S TBD GLM 6 TBD GLM T THD GLM 8 TBD GLM 9 TED X41ipple(3.813^) 10 TBD 7" x 41/2^ HES TNf ParkM 11 TBD XN Nipple (3.72Y) 12 ± lSo VAEG ____________________________________________------------------------------ JEWELRY ____ - JEWELRY DETAIL- Lower Completion j No Depth Item 4 15250' 9-5:8:7' Uner Top Packer PERFORATION DETAIL END Sands I Top(MD) I Btm(MO) I Too ITVD) I BtM(TVD) I Fr I Date I Status I Size ------------------------------------------- OPEN HOLE / CEMENT DETAIL g 8.112- 1 216tr3 y w 10ri /2/7? •' / WELL INCLINATION DETAIL Nlax Hole Angle =TBD Anile xTop ---- =780 TREE & ELLHEAD i W Tne &1w CM 7,)aEJ7 /3/ 9 B c walnaa TDs 13,906' (M7)/To- 9,8NUVDI PBTD=I9,81V(MI PBTD-29,B37Mq GENERAL WELL INFO API: Sp-02321835-0DOp Ori nal Com on - 6 198E Page 7 July 2018 H Ilii oq, M.A., LIX 9.0 Drilling / Completion Summary END 4-26A Sidetrack Drilling Procedure Endicott SDI 4-26A is to be a slot recovery sidetrack producer with the Kekiktuk K213 as the primary target. The parent well, 4-26, is a long term shut in injector (S/I since 2007) where the reservoir was abandoned and prepared for the sidetrack with the E -line & the ASR rig in June 2018 (operations submitted on a separate sundry). Current wellbore schematic is attached. Drilling operations are expected to commence approximately July 27th, 2018. ' The Innovation Rig will be used to sidetrack and complete the wellbore. The existing 9-5/8" surface casing will be used and a pressure test conducted prior to drilling the sidetrack. A clean out run will be performed, a whip stock assembly will be run and set, and a window will be milled at (5,400' MD / 5,395' TVD. The directional plan for this sidetrack will be to build to a 60° inclination and held to TD, 8-1/2" hole will be drilled to f 13,906 MD / 9,891' TVD. 7" liner will then be run and cemented. The well completed with a 4-1/2" gas lift completion. Post rig evaluation and perforation will follow. All waste & mud generated during drilling operations will be hauled to the Milne Point G&I facility on `B" pad. A separate sundry notice has been submitted to cover reservoir abandonment and wellbore preparation for the sidetrack. The aforementioned sundry will cover the following operations: 1. MIRU E -Line & ASR and abandon reservoir and prep for sidetrack. RDMO 2. MIRU the Innovation Rig. Test BOPE 3. RIH w/ 9-5/8" cleanout assembly to top of cement plug +/- 5,400' MD 4. RIH w/ whipstock and set on top of cement 5. Mill window at +/- 5,400' MD General sequence of operations pertaining to this approved drilling procedure: Kick off and drill 8-1/2" production hole section to TD 2. Run 7" and cement 3. Run 4-1/2" Completion 4. N/D BOP, N/U tree, RDMO Page 8 July 2018 H ❑ilcorp Alaska, Gd: END 4-26A Sidetrack Drilling Procedure 10.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with all 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. • BOPs shall be tested at (2) week intervals during the drilling and completion of 4-26A. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. • 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 10/10 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. • If the BOP is used to shut in on the well in a well control situation, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". • Ensure both AOGCC approved drilling permit is posted on the rig floor and in Co Man office. Variance Requests: • There are no variance requests at this time. Page 9 July 2018 U Ilir oq Alaska, FAX Summary of BOP Equipment and Test Requirements END 4-26A Sidetrack Drilling Procedure Hole Section Equipment Test Pressure(psi) • 13-5/8" x 5M Control Technology Inc Annular BOP • 13-5/8" x 5M Control Technology Inc Double Gate Initial Test: 250/4000 o Blind ram in btm cavity (Annular 2500 psi) 8-i/2" OH x 7" Mud cross w/ 3" x 5M side outlets 13-5/8" x 5M Control Technology Single ram Casing Casing • 3-1/8" x 5M Choke Line Subsequent Tests: • 3-1/8" x 5M Kill line 250/4000 • 3-1/8" x 5M Choke manifold (Annular 2500 psi) • Standpipe, floor valves, etc Primary closing unit: Control Technology Inc. (CTI), 6 station, 3000 psi, 220 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is electric triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: • Well control event (BOPs utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPS. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Additional requirements may be stipulated on APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: iim.regg@alaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guv.schwartz(Ralaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria.loeppna alaska.gov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / (C): 907-xxx-xxxx / Email: melvin.rixsegalaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: httl2://doa.alaska.gov/oge/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 10 July 2018 11.0 Rig Orientation on Endicott SDI: END 4-26A Sidetrack Drilling Procedure PBgc 1 I July 2018 4-2 3-1 4-4 3-3 4-6 3-5 3-7 4-10 3-9 3-11 4-14 3-15 4-16 3-17 4-20 ■ 3-19 4-18 3-21 4-20 3-23 4-26 3-25 = 4-26 4-28 3-27 3-29 4-28 4-32 - 3-31 4-34 ■ - -_ 3-33 4-32 3-35 ■' 4-34 4-36 ■ 3-37 4-40 3-39 4-4Y 3-41 3-43 4-46 3-45 4-48 ■- --- - 3-47 4-50 E - -■ 3-49 Endicott SDI .Craws Not T. 5 ak PBgc 1 I July 2018 H nileorp AWk: UX END 4-26A Sidetrack Drilling Procedure 12.0 Reservoir Abandonment & Sidetrack Preparation 12.1 Reservoir abandonment was completed pre rig by ASR & E -line. A separate sundry was submitted and approved by the AOGCC (Sundry #318-145). A summary of sundry operations is below: MIRE E -line, Abandon Reservoir & Cut 4-1/2", RDMO 12.2 Level pad and layout rig mats for footprint of rig. 12.3 MIRU Innovation over well and ensure rotary centered over wellhead. Confirm that rig is over appropriate well — 4-26. 12.4 Spot & tie in service company shacks and water/displacement tanks. 12.5 Ensure Sundry, PTD and drilling program are posted in the rig office and on the rig floor. 12.6 Mud loggers will not be used on this well. 12.7 Keep 5" liners in mud pumps. • White Star Quattro 1300 Hp mud pumps are rated at 4097 psi, 381 gpm @ 140 spm @ 96.5% volumetric efficiency. 12.8 Set test Plug in wellhead prior to N/U BOP to ensure nothing can fall into the wellbore if it is accidentally dropped. 12.9 ND tree, NU BOPE and test f6 Z/000/5; f e -r • 4-1/2" & 5" Test Joints 12.10 Pull & Lay Down 4-1/2" Kill String, — 3000' MD ,91, F/6w CRoss 12.11 Sidetrack preparation operations were by E -line & ASR. A separate sundry was submitted and approved by the AOGCC (Sundry #318-145). A summary of sundry operations is below: MIRU ASR, Pull 4-1/2" tubing & set CIBP, RDMO • MIRU E -line, perforate and squeeze cement, set cement on top of CIBP, RDMO Page 12 July 2018 H ilila.rp .Al.eku, LLC 13.0 Milling & Drilling Fluid Program • Fluid Type: 9.5 —11.0 ppg 3% KCl Gem GP LSND Fluid Density: MD, ft Density, ppg 5,400- 12,795- 9.5 12,795 - TD 10.3 Afte r TD 10.8 END 4-26A Sidetrack Drilling Procedure o Maintain 9.5 ppg until - 500' above HRZ. Increase MW to 10.5, using pre sheared balanced spike fluid for hole stability while drilling to TD. Increase MW at TD to 10.8. Mud weights chosen based upon pore pressures and hole stability pressures while drilling through unstable formations. 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. ✓ Rheology: o Milling Fluid: Maintain YP 40-60 for metal cuttings removal o Drilling Fluid: Maintain YP between 14 — 21, 6 RPM/Tau reading of 1.0 - 1.2 x the hole diameter to optimize hole cleaning. Other: o Stabilize the HRZ shale formation with the use of mud weight and adequate concentrations of shale stabilizers (GEM, BAROTROL PLUS, Soltex and BDF-515). o Increase the KCl concentration from 3% to 6% and add BARASURE-499 at 4 ppb if heavy clays are encountered to increase inhibition of the native clays Solids Control: o Run shakers with as fine a screen as possible • Size shakers screens with coarse mesh initially. • Adjust screen size as solids loading, mud rheology and flowrates allow. • Inspect the shakers frequently, taking time to repair/replace damaged screens. • 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. Run the centrifuge continuously while drilling this hole section, this will help with solids removal and minimize sand content and LGS to maintain fluid properties and quality of the mud system. o Dump and dilute as necessary to keep drilled solids to a minimum o Optimize solids control equipment to maintain density, ECD and minimize LGS Properties: Depths I Densit Plastic Viscosity Yield Point Total Solids MBT HPHT H 5,400'— 13,907 1 9.5-10.8 15-25 14-18 <6% <20 <11.0 9-10 Page 13 July 2018 H HH.,p Al.kn, LLC System Formulation: END 4-26A Sidetrack Drilling Procedure Product Mill Out to Top of ERZ Top of HRZ to TD Concentration Concentration Water 0.94 bb] 0.94 bbls KCL 11 ppb 11 ppb Caustic soda 0.2 ppb 0.2 ppb BARAZAN D PLUS 1.25 ppb (as required for 14 - 18 YP) 1.25 ppb (as required for 14 —18 YP) N-DRIL HT 3.0 ppb 4.0 ppb GEM GP 0 % v/v 2 % v/v BARACARB 5 2.5 ppb 4 ppb BARACAPB 50 2.5 ppb 4 ppb BARACARB 150 0 ppb 12 ppb BAROTROL PLUSBDF-515 4.0 ppb (2 ppb each) 8 ppb (4 ppb each) BARASURE - 499 2-4 ppb (if heavy clays are encountered) 2-4 ppb (if heavy clays are encountered) BAROID 41 as required for a 9.5 ppg MW as required for 10.4 — 10.8 ppg BARACOR 700 1.0 ppb 1.0 ppb BARASCAV D 0.5 ppb 0.5 ppb ALDACIDE G 0.25 ppb 0.25 ppb Page 14 July 2018 H Ilikorp AI.A., 1AA: END 4-26A Sidetrack Drilling Procedure 14.0 Cleanout Run, MU and RIH with 9-5/8" Whipstock Assembly 14.1 M/U window milling assembly as per Baker BHA tally • Based upon E -line preparation work, cement was squeezed behind the 9-5/8" casing at the window interval. The milling BHA will consist of: 0 8.5" Window Mill 0 8.25" Lower Mill 0 8.5" Upper Mill Ensure BHA components have been inspected previously. Caliper and drift all BHA components before running them in the hole. Ensure there is an extra set of mills on location in the event that the upper mills come back under gauge and a dress off run is required. 14.2 Perform cleanout run with mill BHA • Cleanout BHA will be the same as the window mill BHA. • RIH on 5" DP to — 5,367' MD, tag top of cement and displace wellbore to 9.5 ppg LSND milling fluid • Confirm with casing tally, CCL log and tae depth placement log to ensure whisytock and window will not be across a collar, if necessary, drill cement to ensure proper whipstock placement • CBU & circ at least (1) hi -vis sweep to remove any debris created by the clean out run. Anything left in the wellbore could affect the setting of the Whipstock. • Obtain PU/SO and ROT, document. This will be used to set up shear pins and bolt for whipstock and anchor • POOH, ensure no changes to DP tally after cleanout run. • This is to prevent tagging up early and inadvertently setting the anchor 14.3 PU remaining components of milling/whipstock BHA • Make up HWDP, 2-3 String Magnets, and float sub • Ensure magnets are in the trough under the shakers and flow area Page 15 July 2018 H n&..p M.A., u.c END 4-26A Sidetrack Drilling Procedure WindowMaster G2 BHA BHA Component Approx. Length OD Bottom Trip Anchor 3 8.375 Window Master G2 Whipstock 18.5 8 Window Mill 1.6 8.5 Lower Watermelon Mill 5.7 8.25 Flex Joint 9 5 Upper Mill 6.3 8.5 HWDP 30 5 MWDCollar 18 6.75 Float Sub 3 5 UBHO 4 5 XO 4 5 HWDP 30 5 String Magnets 5 BAKER I UGHES Gen II Whipstock C�ff. MCorp wem r R.29 lnnovaton 7 aw W q.ro.a Page 16 .,.- oo rr. xbn uY pp iw•D7 Y QQ Low.. WY 9 Y8' 00 aw• W if••b . Yn.b.w lW -lam e trr Op _� July 2018 H I lil,.q Al"ku, LU] 14.4 Install MWD and UBHO, and orient. Rack back mill assembly. END 4-26A Sidetrack Drilling Procedure Ensure a dedicated MWD is available for orientation of the whipstock 14.5 Pick up Whipstock per Baker rep using the Baker Whipstock handling system using air hoist. Allow assy to hang while Baker Rep inspects and removes shear screws as needed, based upon previous down hole parameters and any safety screws. Note: Anchor should be pinned with 6 shear screws initially. Shear screws are rated for 6,630 lbs each. Pending PU/SO on cleanout run, REMOVE 2-3 screws for a set down shear of 6,630 x 3=19,890lbs. Note: Attach mills to Whipstock with (1) 35k mill shear bolt (45k boll will be available if necessary) 14.6 Run the Whipstock in the hole, install safety clamp as per Baker Rep, and install hole cover 14.7 Release pick up system at this point, Make up mills. 14.8 With the top drive, pick the mill assembly and position the starting mill to align with the hole in the slide. The Baker Rep will instruct the driller when the slot is lined up, the shear bolt then can be made up by the Baker Rep. 14.9 The assembly can now be picked up to ensure that the shear bolt is tight. 14.10 Remove the handling system. 14.11 Verify offset between MWD and Whipstock tray, witnessed by Drilling Supervisor, MWD and Baker Rep. Document and record in well file. 14.12 Slowly run in the hole as per Baker Rep. Run extremely slow through the BOP & wear bushing to prevent damaging the shear bolt. 14.13 Run in hole at 1 r/z to 2 minutes per stand. 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. Shallow test MWD 14.14 Fill every 30 stands or as needed, do not rotate or work the string. 14.15 Call for Baker Rep. 15 — 10 stands before setting depth 14.16 Stop at least 30' — 45' above the tagged cement, obtain survey using the MWD. Consider having gyro personnel on standby in the event the MWD is not working. Page 17 July 2018 K Ililc ,p .AI.A., LLC 15.0 Set Whipstock and Mill 9-5/8" Window: END 4-26A Sidetrack Drilling Procedure 15.1 With the bottom of the Whipstock 30 — 45' above the cement base, work torque out of string, measure and record P/U and S/O weights. Obtain good survey to orient Whipstock face. 15.2 Orient Whipstock to desired direction by turning DP in '/4 round increments. P/U and S/O on DP to work all torque out after oriented. (Being careful not to set trip anchor). Target orientation is 30° LOHS. Whipstock Orientation Diagram: 45L Desired orientation of the Whipstock face is 15L to 45L, target is 30 LOHS Hole Angle at window interval (5,400 MD) is —12 deg. 15.3 Once Whipstock is in desired orientation, slack off and tag anchor to set Bottom Trip Anchor. 15.4 Set down 15-20K on anchor (based upon number of shear pins) to trip, 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. (35k shear value, verify after whipstock is picked up). 15.5 P/U 5-10' above top of Whipstock. /i)o 7-7Z441AqV`::5 crVWki 15.6 CBU and confirm 9.5 ppg MW in/out • Ensure Mud properties are sufficient for transporting metal cuttings • Vise: 40-60, YP: 18-20 15.7 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 Baker Rep. Utilize 4 ditch magnets on the surface to catch metal cuttings. Pump high vise sweeps as necessary. (� 15.8 If possible, install catch trays in shaker underflow chute to help catch metal cuttings. IN 15.9 Clean catch trays and ditch magnets frequently while milling window Page 18 July 2018 U IH6,q, Alaska, LIA: END 4-26A Sidetrack Drilling Procedure 15.10 Mill window until the uppermost mill has passed across the entire tray. Dress and polish window as needed. With upper mill at the end of the tray, this will drill — 20' of new hole. 15.11 Estimated metal cuttings volume from cutting window: 9-5/8" 47# N95 Cuttings Weight Window Tray Length Casing Weight Min (lbs) Avg (lbs) Max (lbs) 17 47# 120 160 240 15.12 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. 15.13 Circulate Bottoms Up until even MW in/out and hole is clean of metal shavings. Reduce mud properties for drilling. / I 15.14 Pull back into 9-5/8" casing and perform FIT t/ 12.5 ppg EMW. Chart Test. �9�el/S 15.15 POOH & LD Milling BHA. Gauge Mills for wear. ,�k 71-0/r.a4-e- .e 15.16 If upper mill is under gauge, pick up second mill BHA with same assembly (to ensure same cut pattern) and perform dress off run to ensure window is correct diameter. 15.17 PU stack washer and wash BOPE stack. Function all rams to clear any potential milling debris. Page 19 July 2018 K Ilil,.rp AI.A., LLC 16.0 Drill 8-1/2" Hole Section 16.1 Pick up 8.5" Motor BHA END 4-26A Sidetrack Drilling Procedure • Motor BHA will be used ensure kick off and drill enough full gauge OH for the RSS BHA Motor and MWD 16.2 RIH with Motor BHA t/ 3 stands above whipstock 16.3 CBU to ensure even MW in/out and mud properties are back to desired for drilling • Double check tally's to make sure bit is well above whipstock to prevent rotating bit tagging whipstock 16.4 Orient motor and continue lowering assembly through window with no flow or rotation • Ensure BHA and DP tally are verified • Circulating can cause the rotating bit to catch the whipstock and result in rotating it or becoming mechanically stuck 16.5 Once through the window and tagged up on bottom, drill ahead to confirm kick off, build to tangent angle and ensure clearance for RSS BHA. 16.6 Orient motor and pull through the window with no flow or rotary 16.7 POOH and LD Motor BHA 16.8 P/U 8-1/2" RSS directional BHA. • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Ensure MWD is R/U and operational. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. • Workstring will be 5" 19.5# S-123 NC50 & DS50 • Ensure float is ported 16.9 TIH w/ 8-1/2" directional assembly to 2-3 stands above window. Shallow test MWD and LWD on trip in. 16.10 Trip through window with no flow or rotation, to bottom 16.11 Drill 8-1/2" hole section to section TD, — 13,907' MD, as per Geologist and Drilling Engineer. • Flow Rate: 400-550 gpm (Target is 200 ft/min AV for hole cleaning) • RPM: 120+ • WOB: 10-30 klb Page 20 July 2018 U nil,.rp .Al.k., LLC END 4-26A Sidetrack Drilling Procedure • Adjust RPM and WOB as needed • Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. • Pump tandem high weight high vise / low weight low vise sweeps to aid in hole cleaning. • Keep swab and surge pressures low when tripping. • Take MWD surveys every stand drilled • Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. • Endicott Formation Descriptions are attached to this program. • Monitor Drag, Torque and ECD Curves for indication of hole cleaning. Circulate at full flow and full rpm if necessary • Maintain ECD maximum of 1 ppg over static MW after drilling in to HRZ to minimize pressure cycles on formations • Monitor breakover torque and PUW on connections for differential sticking risk. 16.12 8-1/2" Section Mud Weights: MD, ft Density, ppg 5,400- 12,795' 9.5 12,795 - TD 10.3 Afte r TD 0.8 Window — 500' MD Above HRZ (-12,7 D): 9.5 ppg 500' MD Above HRZ — TD: 10.3 ppg, increase inhibition, GEM and black products Baratrol and Baranex / o There is a high differential stickine risk across the hieh Dermeabilitv Kekiktuk Sands. ✓ Estimated pore pressure is — 8.1 ppg Static MW necessary for shale stability is 10.3 ppg This is over 2 ova difference. Ensure mud properties are sufficient to provide eood filter cake. Keep pipe moving at all times. 16.13 At TD, Circulate 5-6 BU at maximum circulation and rotation, pump tandem sweeps as needed. Alternate reciprocation depths while CBU to reduce risk of troughing and dropping inclination • Flow Rate: 400 gpm, Min • RPM: 120 16.14 After CBU's, Perform a short trip to above the HRZ This will give an indication of hole quality 16.15 CBU and TIH to Bottom Page 21 July 2018 U Ilik.,p Alaska, LLC END 4-26A Sidetrack Drilling Procedure 16.16 Weight up at TD for shale/hole stability while TOOH, 10.3 -10.8 ppg MW at TD will be based upon and different sticking risk seen at 10.3 ppg. - Spot liner running pill t/ above HRZ after weight up 16.17 POOH to - 2 stands below window Minimize surge/swab pressures String speed 500 fph t/ above HRZ, Increase as hole conditions allow above HRZ. Max pulling speed 2000 ft/min Watch overpulls, if any overpull over 25klb is encountered, RIH 2 stands and CBU 16.18 CBU x 2 below window, 400 gpm, 120 rpm 16.19 Pull through window with no pumps or rotation 16.20 If backreaming is necessary: • CBU x 2 before beginning backreaming operations, this is to clear the BHA of cuttings and reduce packoff risk • Circulate at max rate, matching ECD's seen while drilling • Rotate at maximum rpm that can be sustained. • Limit pulling speed to 5 -10 min/std (slip to slip time, not including connections). • If backreaming operations are commenced, continue backreaming to the 2 stands below window • CBU x2 outside of window • Pull through the window with no pumps or rotation. 16.21 TOH with the drilling assembly, racking back DP, Rabbit DP on TOH at the window for liner run • Do not lay down drill pipe or soft break connections while TOOK Drill pipe will be handled after 7" liner is landed and cemented 16.22 Lay Down BHA 16.23 No additional logs are planned for the 8-1/2" hole section. Page 22 July 2018 17.0 Run 7" Casing 17.1 Change upper pipe rams to 7" solids and test with 7" test joint. 17.2 Ensure wear bushing is installed in wellhead. END 4-26A Sidetrack Drilling Procedure 17.3 R/U 7" casing running equipment. • Ensure 7" x NC50 crossover is on rig floor and M/U to FOSV. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 17.4 Run 7" liner per completion tally • Use "API Modified" or "BOL 4010 NM" thread compound. Dope pin end only w/ paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Run 1 centralizer / jt until — 3000' MD above shoe Centek SII 7" x 8.5" Bowsprings This is to ensure good standoff and mitigate differential sticking while picking up liner hanger • Slow running liner across whipstock to ensure centralizers do not catch • Fill liner every 10-20 joints, more frequently if needed 7" Tenaris TXP M/U for ues Casing OD Minimum Maximum Yield Torque Operating Torque 7" 13,280 ft -lbs 14,750 ft -lbs 16,230 ft -lbs 20,000 ft -lb *7" TXP is compatible with DWC/C & BTC Page 23 July 2018 H I i4mrp Al.k., LIX END 4-26A Sidetrack Drilling Procedure TXPO BTC ---05109.12016 Outside Diameter 7.000 in. Min. Wall 87.5"a GEOMETRY Thickness (')Grade LBO 401150 261t, Orifi 6.151, Ploremal I9 6276 in. Type 1 0.362in. Wall Thickness 0362 in Connection DO REGULAR PERFORMANCE Dimon COUPL0I13 I'm BODY Body Yield Strength 604 X1000 His IntemalYeld 7240 psi SMYS Body: Red 1st Band, Red Grade L80 T 1' Type Drift API Standard 1st Bard: Brown 2nd Band- GEOMETRY 2nd Band: - Brown Type Casing 3rd Band:- 3rd Band r.- 0166._ Make-up Loss 4579 in. Threads per. 5 Conneckcn OD C Wn !th Band: - PIPE BODY DATA GEOMETRY Nominal OD 7.000 in. Nominal Weght 261t, Orifi 6.151, Ploremal I9 6276 in. Waillsckes 0.362in. Plain End Wevghl 25.69 Lwh 00 Tolerance API PERFORMANCE I Body Yield Strength 604 X1000 His IntemalYeld 7240 psi SMYS 811000 psi Ccllapse 5410 psi CONNECTION DATA GEOMETRY Connection OD 7.656.. _-_�.— Coupling L.14;; 1DZOD'n. rine. Ctnnec0an l0 0166._ Make-up Loss 4579 in. Threads per. 5 Conneckcn OD C Wn REGULAR PERFORMANCE Tension Eltcieney 100.0% Joint Yreld Strength 604.000000) haemal Pramm Capacity 1' 1 7240.000 psi Ibs Congression EFadency 100% Compression Strength 604.DOO COD Mm Abowwable Ber6ng 52'nDO t Ihs E Bernal Preswre Capacity 541 DIDD psi MANE -UP TORQUES 1Uinirnum 13210 tis clilnun 14750flabs tiardnun �] 16230 fate OPERATION LIMIT TORQUES OperaEng Tmgue 2000-D t4bs Yield Togie 23400 ft -lbs Notes This connection is fully interchangeable With: TXn BTC - 7 in. - 23 / 29132) 35138 Ibsfft Page 24 July 2018 H Ilil.q Alk., LLC END 4-26A Sidetrack Drilling Procedure 17.5 Ensure to run enough liner to provide for — 150' overlap inside 7" casing. Ensure hanger/pkr will not be set in a 9-5/8" connection. 17.6 Before picking up Baker ZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 17.7 M/U Baker ZXP liner top packer. Fill liner tieback sleeve with "Pal mix", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 17.8 Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 17.9 RIH w/ liner on DP no faster than 1-1/2 min / stand. Watch displacement carefully and avoid surging the hole and catching liner on whipstock. Slow down running speed if necessary. 17.10 Fill DP every 5 stands, or more frequently if needed 17.11 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + S/O depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 17.12 Obtain up and down weights of the liner before RIH. Record rotating torque at 10, 20, & 30 rpm. Liner will be ran through historically troublesome formations. Rotation of the liner may be necessary. If rotation and circulation is required, ensure to say well below torque and pressure limits, dictated by liner spec sheet and Baker hanger/setting tool pressures. Break circulation slowly and limit reciprocation speeds to limit surge and swab pressures 17.13 RIH t/ planned setting depth of 13,907' MD. • Limit running speeds to reduce pressure cycles on shales • Differential sticking has been seen across the Kekiktuk. Minimize the time the pipe is left station while running through this interval. Estimated pore pressure is 8.1 ppg, and MW for shale stability is 10.3 ppg minimum. • At depth, double check all drill pipe and liner tallies. Ensure all numbers agree with final depth • If unable to get 7" liner to TD, liner will be set high and cemented and lowest achievable depth. A 6-1/8" cleanout run will be performed and an 4-1/2" contingency liner ran. Page 25 July 2018 K I lilcaq, .Alaska, LIX 18.0 Cement 7" Casing 18.1 Circulate and condition mud for cement job END 4-26A Sidetrack Drilling Procedure Break circulation slowly and stage up rate with reciprocation. Rotate DP slowly if hole condition allows, not exceed max liner torque or 20 rpms Circulate minimum 3 liner annular volumes to condition hole and mud for cement job Max flow rate 12-14 bpm, with one annular volume at cementing rate — ensure to not exceed 13 ppg EMW, estimated fracture gradient of Kekiktuk 18.2 Hold pre job safety meeting over upcoming liner cementing operations. Make room in pits for volume gained during cement job. Ensure adequate displacement volume is available. • Cement returns are not expected to surface, but may be seen after setting liner hanger and circulating, discuss how to hand returns if they are seen • Rig pumps will be used for displacement • Positions and expectations of all personnel involved in cement operations, have one hand in the pits specifically for strapping pits and recording volume returned. 18.3 7" Liner cementjob will be a single stage. 18.4 Cement Volume Calculations: • TOC: 12785' MD, -- 1000' MD above K2B • As per AOGCC Reg 20 AAC 25.030(d)(5), required TOC is 500' MD or 250' TVD above hydrocarbon bearing zone, whichever is greater i. As Per 4-26A wp06, required TOC is 13,283' MD, Planned TOC is 12,785' MD • More cement volume may be pumped if wellbore conditions allow • Ensure cement slurry thickening time accounts for 30 min shutdown time for setting and releasing from liner hanger / packer. Confirm compressive strength sufficient for perforation. Section: Calculation Vol(bbls) Vol 113 8.5" OH x 7" Liner: (13,906-12,785) x.02258 6 f X 1.4 = 35.4 198.7 7" Shoe Track 80' x .038 6 f = 3.04 17.06 Total Volume 38.44 215.76 18.5 18.6 18.7 Cement Slurry System SwiftCEM Density 15.8 ppg Yield 1.16 ft3/sk Mixed Water 5.04 al/sk Pump 5 bbls fresh water. Pressure test surface cement lines to 4000 psi. Pump 60 bbls of 11.5 ppg spacer Pump 15.8 ppg Class G Single Stage Slurry as per calculations above. Page 26 July 2018 /1� S/S/k/ H nilmrp Awaka, Lu END 4-26A Sidetrack Drilling Procedure 18.8 Drop liner wiper plug and displace with drilling mud. Target displacement rates are 7-8 bpm. • Check to ensure displacement rates do not exceed 13 ppg EMW, estimated FG of Kekiktuk • Slow pumps enough to check for liner wiper plug shear release 18.9 Continue displacing cement until liner wiper plug bumps, or displacement volume has been pump. Pressure up over 1000psi to verify plug has bumped. • If plug does not bump, do not set the liner top packer, as string will be unsupported by an unset liner hanger. Discuss with Baker Rep. 18.10 Increase drill pipe pressure to set liner hanger, - 2700psi. Slack off to ensure liner hanger is set. 18.11 Increase pressure to test 7" liner t/ 3000 psi for 30 minutes, chart test. /' ! y' -f -�esGj 18.12 Increase pressure to release running tool from liner hanger. Pressure up in 500 psi increments holding for 5 min each up to 4000 psi until indication that running tool has released. 18.13 Pickup to expose rotating dog sub, set down on liner and set ZXP liner top packer. 18.14 With packoff on running tool still engaged, bleed DP pressure to zero, close BOP and test 9-5/8" x 7" annulus to 3000 psi for 30 min and chart record same. Rotate and set down, if necessary to ensure liner packer is set. Bleed off pressure and open BOPE. 18.15 Pressure up t/ 500 psi, pickup 2-3' to verify that the HRD setting tool has released. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 18.16 Pick up above liner top. 18.17 CBU x 2, to clean up wellbore and check for any cement returns to surface or above liner top 18.18 Displace entire wellbore to completion brine. Pump at 10-12 bpm. 18.19 POOH, L/D 5" DP and inspect running tools. 18.20 L/D remaining 5" DP out of derrick. Page 27 July 2018 H Ilika q.Alaska, I.IA: 19.0 Perform 7" Cleanout Run 19.1 PU 4" DP & MU 7" Cleanout BHA END 4-26A Sidetrack Drilling Procedure i. Ensure Cement has reached 500 psi compressive strength, minimum, prior to clean outrun 19.2 RIH, watch as BHA enters 7" liner top 19.3 Perform 7" cleanout run to top of shoe track, cleaning up any cement stringers seen 19.4 If necessary, drill up length of shoe track to ensure perforation intervals are exposed i. If part of shoe track is drilled, perform a second pressure test, 3000 psi for 30 min. 19.5 Circulate bottoms up to ensure 7" liner is clean 19.6 Displace wellbore to 8.6 ppg 3% KCL Brine 19.7 POOH 20.0 Contingency 6-1/8" OH x 4-1/2" Liner 20.1 In the event that the 7" liner is unable to get to TD, it will be cemented and the lowest possible depth. A 6-1/8" cleanout run / drill to TD will be performed and a contingency 4-1/2" liner will be ran. AOGCC will be notified if this contingency occurs. 20.2 RD Cement equipment, change UPR to 2-7/8" x 5" VBR and Test 20.3 PU 4" DP & MU 6-1/8" BHA. 20.4 RIH & test MWD, continue RIH to liner bottom, watch BHA as it enters liner top 20.5 Drill out float equipment and 20' new formation. CBU and pull back into liner. 20.6 Perform FIT t/ 12.5 ppg EMW. Chart Test 20.7 Drill 6-1/8" hole to well TD 20.8 CBU x 4, 200 ft/min AV and 120 rpm 20.9 POOH and LD BHA 20.10 RU and run 4-1/2" 13Cr HE Bear liner to TD 20.11 Cement liner, ensuring entire liner has cement coverage or 500' MD above Kekiktuk is covered with cement. 20.12 Well completion will remain the same. Page 28 July 2018 H Ilil.,p Aluwka, LAA: 21.0 Run 4-1/2" Upper Completion END 4-26A Sidetrack Drilling Procedure 21.1 M/U 4-1/2" 13Cr HE Bear gas lift completion as per tally and RIH to setting depth. i. Ensure appropriate well control crossovers on rig floor and ready. ii. Monitor displacement from wellbore while RIH. 21.2 Space out tubing, Spot Cl Brine and Packer fluid 21.3 Terminate SSSV control line, Land hanger, RILDs and test hanger seals. 0K- ' 21.4 Drop ball and rod, pressure up and test tubing t/ �W psi for 30 minutes, then pressure up to 21.5 Test annulus to 3000 psi f/ 30 min. 21.6 Shear SOV, 2500 psi, casing to tubing. Circulate annulus through tubing to confirm shear. 21.7 Install TWC and N/D BOP. 3 21.8 N/U tree adapter and tree. Conduct pressure tests of same to 250/.3,0Kpsi. 21.9 Pull TWC 21.10 Circulate freeze protect down IA, allow freeze protect to U-tube down tubing. 21.11 Set BPV 21.12 Shut in well. 22.0 RDMO Page 29 July 2018 H llih--I, Va�ka. 1A: 23.0 Innovation Rig BOP Schematic 3-1/8" Kill 9-5/8' DBL D Casing 13-5/8" NOM 9-5/8" BTC Btm x 10.5"-4 SA Pin Top W/ Primary Seal A [Hil T1 END 4-26A Sidetrack Drilling Procedure _13-5/8" 5M Control Technology Annular BOP —13-518' 5M Control Technology Double Ram Choke Line I ------13-518" 5M Control Technology Single Ram 3-5/8" x 5M -11" x 5M x 5 13-518" x 5M \— 2-1/16" x 5M Casing " Casing Page 30 July 2018 24.0 Days vs Depth 0 m $A I �0, m IT. a END 4-26A Sidetrack Drilling Procedure END SDI 4-26A Kekiktuk K2B Producer 0 5 10 15 20 Days tuk K26... 25 30 Page 31 July 2018 ff 11H.,p Alaska, LIA: 25.0 Formation Tops & Information END 4-26A Sidetrack Drilling Procedure End 4-26A Formations (wp06) MD (ft) TVDss (ft) ND (ft) Formation Pressure (psi) EMW (ppg) Schrader/ West Sak 8246 7026 7066 3292 8.96 Colville 8884 7345 7385 3323 8.65 Tuffs 12236 9018 9058 4076 8.65 HRZ 13295 9546 9586 4314 8.65 LCU / K26 13785 9790 9830 4100 8.02 Formation Description Drilling Notes West Sak/Schrader Wet Sand A,_eoj 0i SVl7 xfD Potential for pea gravel, but should be Yaa4 rJs f z -'It, &,95 above window depth Seabee (Colville) Silt / Mudstone 7.4.43 Homogeneous formation, steady drilling Tuffs Volcanic Interval with interbedded glass. Historically tough on bits and hard drilling. High torque, slow rop, abrasive and heat. HRZ Organic shale, historically unstable Historically unstable shale, sensitive to time open as well as pressure cycles between pumps on/off and surge/swab LCU Erosional surface. Historically gravel, pyrite and chert. Potential for impact damage Itkiliarak High compressive strength limestone Abrasive, high heat, slow drilling (Not expected on 4-26A Kekiktuk Oil bearing reservoir Erratic drilling with layers of coals. Differential sticking is prevalent, keep pipe movin as much as possible Coals (Not Coals. Possibly Eroded. Utilize coal drilling best practices. expected on 4-26A) Treat drilling breaks as coals, drilling 4-5' max, pull up and ream through until coal has been worked through. Goal is to wipe the hole without laying down a sin le Page 32 July 2018 i n llitt-nq. U.4a. 1.11: END 4-26A Sidetrack Drilling Procedure 5.006' 6.000' Cretaceous Colville Group 4600 to 8700' WEST SAK F.000' SAND GROUP e(. 6856- 7800' TOP OF SEA&EE SHALE remains me lama"Wada fntCN.ddid"Raton.,.1d.hos, maaaira to oarse Walnad anANreaa f45.59 Las aTCL sands wM unaremglwrwauL iriervah. HARD SPOTS 4400 TO 5300 TVD. y� WATCH FOR SWABBING 5300 TO 5200 TVD. "I'amaddedeanM. silWanea and Make. WARNINGI POSSIBLE PRESSURE FROM CRETACEOUS INJECTION VHF LL AT +i 7200' TVD. Intermittent produced water Inleetlon Into 2-02tP-1 B. Wait Sax lana grout, mode up a•..1. 6 sands, good pberar. FMT 8.8 ppg on 1-2370-15. apdraa.road -n1aress 7X'TVn. Praia. mrweMUI SDI. Lithol." slmlkr to MPI. WATCH FOR KEYSEATS AND STUCK PIPE "BlK-34, 7211 TVD )Ne it TVD: Predominately Mato and clay- Vary Side sand. FredWnlmlal,atoll rt, ctoy vary We sand ------ ----- -010� design to kick out In AND STUCK PIPE: 3-031J-33, 8476 TVD the Seabee Interval (for convenience of WATCH FOR KEYSEATS Standard sidetrack -010� design to kick out In AND STUCK PIPE: 3-031J-33, 8476 TVD the Seabee Interval (for convenience of directional work In a stable formation). 2003 SIDETRACI PROGRAM A SUCCESS. SEE g,00a- LESSONS LEARNED (THIS .1.9ton n> L SHEET AND L Top of Tilts (y,,)o er. 8800 -to 9401 Shale with .u.mteroeddedTuft(volcanicglass)endashstringers. SHEET28j TUFFS k Some pyrite with calcareous sands. Not a +'" • L recommended Interval tar Sidetrack windows (kick arm.rrrr awanns �=mr.ua"...-una.ve ane � 9aoa -H 1)�ITt1 l lRZ t9 9d°0� Top of (highly Top of HRZ (highly radioactive zone(. Shale interbedded with sands. Warning: HRZ has been HRZ problematic In the high angle area of the field (J-33. HRZ 3-17CfM31 and K44). TIGHT HOLE INTERVAL SEVERE STUCK Put River Sandstone: unabgy rapes nom shall sanalolw ax lwlah sarA. Essaolany presamtlbaplwa sDl PIPE AND TIGHT nom amaenaa .+nub, HOLE INTERVAL! PutMet Met" msrmnnanmt-iiat a nucx uknd H. PMsw.l m.i...1 x as9az Tw. LCU: rn. Lcu..m a ..m...v m..b—olr... HRZ. RIYeI River -- GOOD3,1170-30;OE CLEANING ilsk: ....as..lr....rm.rc.kbwk.. e.rt.....y. GOOD EQUIR kidlya kk0yansk:wau..dxw. [r...ranm. x -.orad wrL.r...am. PROCEDURES REQUIRED Saov DUES LCU MM Lmkmr,® .e ..m.rw ssanL.a n,.rra.rm..rnm".. . 960D' nda— a.mMkVm lam.ramra. s.m..M um.n.haaMdym..rt.M eemunJp.n in mnw.r.e..iLf Mredliar. to aem.M 'din pnonaan..W.a b.nbivl6.b.rtaaaLaJWY.bur.�d tkily ItkilyarWk wtr�n�rmntr,e.rea�rmmr.w".. Ir.bArr.k mK.,r..,.ma...mre,. �n la— I m.4aP.ova NLR mm. tic�n>a1-intandisa .4n m. Limestone . m n naanonrtrL.r...a.r.Ln,s.,�m.,aL.,rrm.ra.,rnr...., W,m.rt rYlyarltl. LM mnu..Yy vqm. macMnna�Weem lM }n wL [roml m 113P.11 .1 f W 31. 'i[IId1IDiL'MLM S.nl.lrv.. in l-rrtMYry.r1�c iM.n Kp �� ro erv" mNb m.vnauam.IMM emA SEVERE STUCK 9813D to dd4D ,e.00a' GAS! CAUTION! PIPE AND TIGHT r: Kekikt,. Sand: Sand with interbedded and coals. HOLE INTERVAL! -d Hydmcarban hearing, Producing horzon. Mid - olid fault separtes 3.2SUM--31. COAL; MPI and SO#em hydraulically. A gas iI mere art no g on whiz N28 SHALE 2 G25Ai HOL SDI, there is a gss cap DI and SDI and zonae indication of gas pressure GOOD HOLE CLEANING . gas Kekiktuk fr. Il Sea fr�mthe MPI inj[don wells crossing lhrmid-ficW buil. PRek ES4wfro — Ispe , l Stuck Pipen Abjor Mems To P8 Sand P3= COAL WATCH OUT FOR COALS IN MID TO LOWER Watch Odd KEKIKTUKIII P3 coals are In 2 seams, the upper 5 to 10 n thick and the lower 15 to 20 In Intek. r. ,___ The lower appears to slough more dull; dH81ng. K I lil.o p .Ala k., LLC 26.0 Anticipated Drilling Hazards END 4-26A Sidetrack Drilling Procedure Hole Cleaning: Maintain sufficient hole cleaning parameters (120+ rpm and 200 ft/min AV). Maintain rheology of mud system. Pump tandem sweeps as needed. 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, minimum 120. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out or troughing 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 annular velocities of 200 ft/min or greater. Lost Circulation: j 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. Differential Sticking: Ensure pipe movement and fluid flow at all time. Differential sticking has been seen across the high permeability Kekiktuk formation. Ensure LSND mud properties are in excellent shape to provide a good filter cake. Reservoir pressure is estimated to be - 8.1 ppg. MW required for shale stability is 10.3 ppg, minimum. This is over 2ppg difference. -- - Unstable formations: Ensure proper hole cleaning practices are followed and sufficient MW is used for stability. Coals have caused packoffs and stuck pipe problems in the past. Follow good coal drilling practices. Faulting: No faults are expected. Montior resistivity and gamma ray if any indications of faults have been seen and formations have changed. H2S: Endicott SDI is designated as and 1-12S site. Personnel are to have individual 1-12S detectors and this rig will have its own 1-12S detection equipment. Ensure H2S monitors and detection systems are tested. The AOGCC will be notified within 24 hours if 1-12S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic 1-12S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event 1-12S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: There are no abnormal pressures or temperatures observed on at SDI. Page 34 July 2018 H 11H.,p .Al.ka, LLC 27.0 Innovation Rig Layout END 4-26A Sidetrack Drilling Procedure Page 35 July 2018 END 4-26A Sidetrack Drilling Procedure 28.0 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 36 July 2018 H lhlrnq, Alaska. LIX 29.0 Innovation Choke Manifold Schematic END 4-26A Sidetrack Drilling Procedure Page 37 July 2018 30.0 Casing Design Information 11 Hole Size Drilling Mode MASP(8.5"): Collapse Calculation: Section Calculation Calculation & Casing Design Factors Endicott SDI DATE: 7.5.2018 WELL: 4-26A DESIGN BY: Joe Engel Design Criteria: 8-1/2" END 4-26A Sidetrack Drilling Procedure Mud Density: 10.3 ppg 3,164 psi (see attached MASP determination & calculation) Max MW gradient external stress and the casing evacuated for the internal stress Casina Section Calculation/Specification 1 Casing OD T Top (MD) 5,400 Top (TVD) 5,395 Bottom (MD) 13,906 Bottom (TVD) 9,890 Length 8,506 Weight (ppt) 26 Grade L-80 Connection T)p Weight w/o Bouyancy Factor (lbs) 221,156 Tension at Top of Section (lbs) 221,156 Min strength Tension (1000 lbs) 604 Worst Case Safety Factor (Tension) 2.73 Collapse Pressure at bottom (Psi) 4,100 Collapse Resistance w/o tension (Psi) 5,410 Worst Case Safety Factor (Collapse) 1.32 MASP (psi) 3,164 Minimum Yield (psi) 7,240 Worst case safety factor (Burst) 2.29 Page 38 July 2018 U I lvoq, :A 1.4., 1.1.1: 31.0 8-1/2" Hole Section MASP END 4-26A Sidetrack Drilling Procedure Maximum Anticipated Surface Pressure Calculation xil1 8-1/2" Intermediate Hole Section '°"�`" T SDI 4-26A Endicott MD TVD Planned Top: 5400 5395 Planned TD: 13,906 9890 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Kekiktuk K2B 9,830 4100 1 Oil 8.0 0.420 Offset Well Mud Densities Well MW range Top (TVD) Bottom (TVD) Date 3-23A 10.30 9,905 1 10,121 1 Jul -2017 Assumptions: 1. Fracture gradient at shoe is estimated at 0.7 psi /ft based on field test data. 2. Maximum planned mud density for the 8-1/2" hole section is 10.8ppg. 3. Calculations assume Kekiktuk reservior contains 100% gas (worst case). 4. Calculations assume worst case event is complete evacuation of wellbore to gas. Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 9-5/8" Shoe/Window 5400' MD / 5395' TVD 5395 (ft) x 0.7(psi/ft)= 3,776.50 3776.5 (psi) - [0.1(psi/ft)*5395(ft)]= 3237 psi Drilling Mode MASP MASP from pore pressure (wellbore completely evacuated to gas) 9890(ft) x 0.42(psi/ft)= 4153 psi 4153(psi)-[0.1(psi/ft)*9890(ft)]= 3164 psi Summary: 1. MASP while drilling 8-1/2" Intermediate hole is governed by the wellbore completely evacuated to gas from the Kekiktuk Reservior Page 39 July 2018 END 4-26A Sidetrack Drilling Procedure Ililcerp Alaska+ 1.1.1: 32.0 Spider Plot (NAD 27) (Governmental Sections) I s., SecSec.33.� I ,r . 32' r ,MI r U012NO17E '5c,1 ADL312528 vo' 1 rl n 5 1 .ir r♦' �-TS 11 -� �\ ♦ 04-26A BHL 1 j ' ♦' ♦♦ 04-26.A_TPH 1 I ♦ y0 � 1 1 , ♦ S Ir ' `• ; rr � p ;- 11 � >+fo` vex.'•' \t 5 ,1 / L .,•y 41 10% u I Sec 5, '; Sec. 4 1 /' I l 1 I 11 �1 ♦N I/ CIUCK y1130AND UNIT \ DL0147502 / f , 6 �A5 ' \ 5 \ \ . 5 \ 5 1 1 I 1 1 t b / Is ` ' � 5 ♦1 1 �, n / , � i iii \ \' 1 S e , • ' L047503 ��-' ��'•�� ♦Sec. e`\•. \`N5115 it Ir�/i •��%Zr � �' '' l .� � -I ___. �\� 5 51 i 1 r7,y,'ii . � .' ., /-.�' �'' Secy9�_ - - _ _ `t•- _ Legend _• • 04-26A SHL Oke, Surface F les (SHL) _7 X O4_26A_TPH T Other Bd[dn Holes (BHL) OA -26.4 SHL 1 \_2` -`- _ _ _ -'i: _ _ - Otho Well Pans 04-26A_BHL O Oil and Gas Unit Boanoary r_ I - . Pad Foolpa nl Duck Island Unit Alaska state Plane zone 3 NAD 1927 SDI 4-26A Well 0 500 1,000 1.500 2.000 M., dam: a3629.9 wp06 Feet Page 40 July 2018 33.0 Surface Plat (As Built) (NAD 27) END 4-26A Sidetrack Drilling Procedure Page 41 July MR I— ODETIC CELLAR s J NO. 9' S2 99 ggRi A7 ay 4-26 • -1 - 6 a N 70.3218727 739' mlD n — a9 3 Q 12 7 9 d3 J-7 e R -b - }R YII 7M PRC�CT rb {..R t2 'RIL "4 5-21 ] 43 4-2b 4-0s VItlN17Y MAP 1-28 5-27 1-0R 5-.17 ,-2B 1-b - Y2B y1:'•• .''F9 4-14 Y,1. -45 4921 .... thy a9N 84 8 1 ••, 1 D200 �BL:SIGML 1F� {��rl F I�1 I 1 SI3R'. MnN CER7IFlCATF xmmr mnn Iw.r 1 w PRdPILr rrmnwn Aw umaFe b PWCIIIL LNO vNwmB N as STATE Y AIA9tA SDI Wn A % A9-WILTRPPP6E A91T WA My YALE 9Y b f4RFST LWE AN WPERLSYW AN) fNAT Ill AU Ram rc URRMrn OF U. M& CORREM AS OF MAY t>. 4011 COA No.: AECC582 LF—Qa 1 CLOSES, -b AS fANT EONBI.CTIIB I. MAVA STATE PIAXL WBXO XS ARE IM L am R L MK G ( W TT 50 YMIIYIYTS Y00724fi9. ■ :Yt£MG OEIIGICiOa 5 O UNW OARw l Y GRAPHIC SCALE L "MEN ENDOWS ARE NMV. L PAO YEAH � FI TOR IT RRi9b ' 0 3 tIIO 2M i DATE IF BW Wt.. WAY 21 2414 f W FEET ) i RIIERLMR4 /L{B BRK W S-02 IP. 19-f4 1 YWh � 100 R. LCCATED NBTTON PROTRACIEO SEC. 86 T. 11 EL R. 17 E. WIAT MCRIOIAN, ALASKA NELL A.S.P. PLANT GEGEHETTC leiAS—BUILT RRwm _ 'X HiicorpAlmska _ _ s a -R-1°- Mat_ ENDICOT-r SDI CONDUCTOR IK w XAO.Pr wo•.a wAv WELL 4-26 T a 1 o. Page 41 July ODETIC CELLAR SECTION NO. COONATES OOROINATL+ W1 W1POu7715) RDI P09TIORl(O.DO) 86X ELEV. OFFSETS 4-26 • Y=597O,80[IJ5 N=1,7fi4.94' N 70'19.18.742' N 70.3218727 739' 2592•FSL • X= 270300.99' E=1680.04' W 1A751'45.136' W 147.6625383• • 736' FEL 2018 U IIOaNp A .A., LLC END 4-26A Sidetrack Drilling Procedure 34.0 Drill Pipe Information 5" 19.5# S-135 DS -50 & NC50 Drill Pipe Configuration Pice1y OD ,^. 5-000 Pipe Body WDTNtluness m. 0.362 Pipe Body Grade 5735 NO Pipe Length RarW2 Connection GPDS50 Tod JOW OD 6.625 Tod Joint to ,^. 3.250 Pyr Tony 9 Box Tong �^ 12 80 % Inspection Gass Nominal Weight Designation 19.50 Drill Rpe Approximate Length r<, 31,5 SmoothEdge Height (-43/32 Raised Tool Joint SMYS ,>• 120.000 Upset Type FEU Max Upset OD (DTE) 5-125 Friction Factor 1.0 N Ve i«9 iPYe'^e) M1UWC M1VCY,M Drill Pipe Performance M-,-- 80 % inspection Gass Drill -Pipe Length RwW2 msn Performance of Drill Pipe with Pipe Body at Best Estimates Nominal 80 % Ins on Class ,mr O , "'e'0o , """"°""") "e'"""'°•" opeetcnal Maz Trmsiu, NO Ad W "°`'" 24.11 23.29 rv" res, T moa, ma, Fluid Oisdacemenl ,w*i 0.37 Fluid Disspiacement ,mtr 0.36 0.0085 wn, 17.105 �x^w*43,100 Temgn onh 0 1560.800 rimenee �39.600 410.500 10.029 10.029 Fluid capacity rwa* 0.70 0.72 4.855 Fluid 11 a 0.0169 0.0167 0.0172 0,362 0290 0.290 Nominal Pipe ID m44276 14.276 Te'von 0,* 10 560,800 Drift Size 125 14.154 cv«+,.day.mro32.100 m• 18.635 1467.400 18.514 Goss Sectional Area of ID N«e ae as ears m,v,a.xus anm. 14.360 14.360 Section Mo" nom om von x:<..my..w�>.e eev esu, xea a+e mer.Yv «: m we oom .a mmara,.mnw vaax oam,o +.o ovw. nma Connection Performance GPDS50 6.625 r^n OD X 3.250 r^n to ) 120.000 mo 1 10 maa,ti[e[onrc[La,oXr!]CMIYmm. a OUT rt11-lr'l, M-,-- 80 % inspection Gass 1Tod2 Torsional Strength M msn 71.800 560 600 1.250.000 Tool Josh Tensile stnmoth ,mr 58,100 Elevator Shoulder Information TJMVeBody Torsional Ratio 0.97 SmoothEdge Height 124 3/32 Rased (,nsp 59300 46.500 Box D 6812 wn, 17.105 15,638 [Elevator Ca mi1.658 .0007 15.672 10.029 10.029 Tool Joint Dimensions Balenced OD '-V r�n..n rvv xnm nen 5.930 vrm,uncwa m w,vn rv«xn ooa 5.93 cenneon m WMe om to m TJ OD for AM Premium pass Assumed Elevator r ,ameer^5.219 ,,,,, ,,, �«,a„m,�,,.oa„u,„� ,_M•r�„",""'d"'m0 "e1x1°"`«,•o.,000=' Pipe Body Slip Crushing Capacity PO Body ( 5- OD ®V 0.362n) Wall S-135) PiDe Bodv Performance N )� Orent Pipe Body Cmrpueden ( 5 mm OD 0.362 r^) Wall S-135) Page 42 July 2018 Nc4': NmYN, &lfl urnuma «er sw wew o«.n Nominal 80 % inspection Gass API Premien Class Pipe Tensile Streno 712,100 560 600 560.600 Pipe Tovonal Str mcsi 74.100 58,100 58.100 TJMVeBody Torsional Ratio 0.97 1,24 124 800/a Moe Torsional Strength (,nsp 59300 46.500 46.500 Bust wn, 17.105 15,638 15638 Collapse 15.672 10.029 10.029 Pate OD m 5.000 4.855 4.855 Wall Thickness 0,362 0290 0.290 Nominal Pipe ID m44276 14.276 14.276 Cross Sectional Area of Roe Body --', 5.275 14.154 14.154 Cross Sectional Area of OD m• 18.635 18.514 18.514 Goss Sectional Area of ID (w2,114 360 14.360 14.360 Section Mo" w3n5.708 14.476 14.476 Polar Section Modulus M-3,1111.415 18953 1&953 Page 42 July 2018 Nc4': NmYN, &lfl urnuma «er sw wew o«.n 0 I Iile-1, u.A. IX 1W END 4-26A Sidetrack Drilling Procedure 500204050016200 5" 19.501bfft S-135 w/ NC 50 6-5/8" OD x 3-1/4" ID Tool Joint DRILL PIPE SPECIFICATIONS Grade S-135 Connection NC 50 Interchangeable With 5' XH R 4-1/2" IF Upset Type IEU Nominal Weight per Foot 19.50 lbs Adjusted Weight With Tool Joint per Foot 23.08 lbs TOOL JOINT DATA Outside Diameter 6-5/8' Inside Diameter 3-1/4" API Drift 3-1/8' Rabbit OD. Suggested 3-1/16" Minimum Make-up Torque 25.900 ft -lbs Maximum Recommend Make-up Torque 26.800 ft -lbs Torsional Yieltl Slren h 51.700 ft -lbs Tensile Strength 1,269.000 lbs TUBE DATA New Premium Outside Diameter 5.000" 4.855' Inside Diameter 4.276" 4.276' Wall Thickness 0.362" 0.290' Cross Sectional Area 5.275 sq in 4.154 sq in Maximum Hook Load/Tensile Strength 712.000 lbs 560,800 lbs Slip Crushing I Slip Type (SDXL) 572,100 lbs 453,500 lbs Burst Pressure 17,100 psi 16.100 psi Collapse Pressure 15,700 psi 10,000 psi Torsional Yield Stren h 74 100 ft -lbs 58.100 ft -lbs Capacity WI Tool Joint 0.726 US a0ft 0.726 US a]M Displacement W/ Tool Joint 0.353 US autt 0.322 US al/ft Excessive heat or pulling when tube is torqued can cause the maximum pull to decrease. Where possible all figures are obtained from OEM data source. NOTE: Weatherford in no way assumes responsibility or liability for any loss, damage or injury resulting from the use of the information listed above. All applications are for guidelines and the data described are at the user's own risk and are the user's responsibility. Page 43 July 2018 Hilcorp Alaska, LLC Duck Island Unit End SDI Plan: DIU 4-26A Plan: 04-26A Plan: DIU 4-26A wp06 Standard Proposal Report 06 June, 2018 HALLIBURTON Sperry Drilling Services HALLIBURTON 3000 WELL DETAILS: Plan: DIU 4-26A Hilcorp Alaska, LLC REFERENCE INFORMATION 5820.40 5780.00 +N/ -S +E/ -W Northing Easting Latittude Calculation Memoct Minimum Curvature Coordinate (WE) Reference: Well Plan: DIU 4-26A, True North Sperry Or tiling SURVEY PROGRAM 7026.00 Error System: ISCWSA Depth From Vertiral(TVD)Reference: DIU 4-26Avry06 R1KB@40A0usft Qnnovatioi 35.70 5400.00 1 : Schlumberger GCT muitishot (4-26) 2_Gyro-NSCT_OWSG Scan Method: Closest Approach 3D Error Surface: Elliptical Conn Measured Depth Reference: DIU 4-25Awp06 RKB@ 10.40usit(Innovattoi 2MWD+IFR2+MS+Sag Top Colville CASING DETAILS Winning Method: Error Ratio Size Calculation Method: Minimum Curvature Project. Duck Island Uni7rec 7" x 8 1/2" 9018.00 FORMATION TOP DETAILS TUFF NDPath TVDssPath MDPath Formation 9586.40 9546.00 13295.89 THRZ 3750 _ Site: End SDI 9830A0 SECTION DETAILS 13785.42 LCU/K2B Well: Plan: DIU 4-26AMD 4000 Inc Azi TVD +N/ -S +E/ -W Dleg TFace VSect Target Wellbore: Plan: 04-26A400.00 to 12.53 358.74 5395.63 63.18 41.80 0.00 0.00 68.09 Design: DIU 4-26A wp06 p 417.08 12.72 349.18 5412.29 66.89 41.41 12.29 -85.00 71.71 3 5447.08 12.72 349.18 5441.56 73.38 40.17 0.00 0.00 77.98 4 6241.13 60.00 1.94 6063.60 529.49 35.10 6.00 15.00 529.55 5 6300.00 60.00 1.94 6093.04 580.45 36.83 0.00 0.00 580.30 MD, 5412.29' ND 6 6503.76 60.00 9.00 6195.02 755.94 53.63 3.00 91.77 756.49 DDI = 6.085 7 10267.76 60.00 9.00 8077.02 3975.53 563.57 0.00 0.00 4015.06 "--�" StartDir6°/100': 8 10333.93 60.10 6.71 8110.06 4032.32 571.40 3.00 -87.58 4072.39 Cretaceous Sands 5500 00 End Dir : 6241.13' MD, 6063.6' TVD 9 13785.42 60.10 6.71 9830.40 7004.00 921.12 0.00 0.00 7064.31 04-26AwpO5K2B 00 10 13906.46 60.10 6.71 9890.73 7108.21 933.39 0.00 0.00 7169.24 -750 yp0, no 750 1500-- 13 3/8" 500 1000 1500 2000 50 0 TUFF - - - - - - - _ - - - _ - _ - _ �00� _ - _ - _ - _ - _ _ _ _ nh 000 THRZ10500___ - DIU 4-26A wp06 LCU/K2B0 _ 0 500 04-26A wpO5 K2B 7"x 8 1/2" 1 a-zs -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 Vertical Section at 7.48° (1500 usft/in) 3000 WELL DETAILS: Plan: DIU 4-26A 3000 Ground Levet 13.90 5820.40 5780.00 +N/ -S +E/ -W Northing Easting Latittude Longitude 0.00 0.00 5970808.75 270300.99 70° 19 18.742 N 147'51'45.138 W SURVEY PROGRAM 7026.00 8246.53 Depth From Depth To Survey/Plan Tool 35.70 5400.00 1 : Schlumberger GCT muitishot (4-26) 2_Gyro-NSCT_OWSG 5,10000 13906.46 DIU 4-26A vP05(Plan: 04-26A) 2MWD+IFR2+MS+Sag Top Colville CASING DETAILS TVD TVDSS MD Size 9890.73 9850.33 13906.46 7" x 8 1/2" 9018.00 FORMATION TOP DETAILS TUFF NDPath TVDssPath MDPath Formation 50 0 TUFF - - - - - - - _ - - - _ - _ - _ �00� _ - _ - _ - _ - _ _ _ _ nh 000 THRZ10500___ - DIU 4-26A wp06 LCU/K2B0 _ 0 500 04-26A wpO5 K2B 7"x 8 1/2" 1 a-zs -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 Vertical Section at 7.48° (1500 usft/in) 3000 3000 5820.40 5780.00 5869.07 Cretaceous Sands 7066.40 7026.00 8246.53 Schrader/West Sak 7385.40 7345.00 8884.53 Top Colville 3500 9058.40 9018.00 12236.58 TUFF 9586.40 9546.00 13295.89 THRZ 3750 _ 9830A0 9790.00 13785.42 LCU/K2B 4000 to p KOP: Start Dir 12,29-/100': 5400' MD, 5395.63'ND : 85° LT TF 0 4500 4500 ' rn ' s End Dir 5417.08' MD, 5412.29' ND - 5000 _ - -' m O 5250 "--�" StartDir6°/100': 5447.08'MD,5441.56'ND Cretaceous Sands 5500 00 End Dir : 6241.13' MD, 6063.6' TVD 00 - " StartDir 3°/100' : 6300' MD, 6093.04'ND 6000 yp0, j 60p0 - - -oo- - - - - End Dir : 6503.76' MD, 6195.02' ND 1 ~ Start Dir 3°/100': 10267.76' MD, 8077.02'ND 6 X000 750 6750- X000 - Schrader/West Salk - 0- End Dir MD, 8110.06' ND Top Colville :10333.93' - - - - - - - - - - O 00 o 7500 000 oyo 00 o- 0g00 o 0 8250 op00 0 00 O Oo Total Depth : 13906.46' MD, 9890.73' ND 50 0 TUFF - - - - - - - _ - - - _ - _ - _ �00� _ - _ - _ - _ - _ _ _ _ nh 000 THRZ10500___ - DIU 4-26A wp06 LCU/K2B0 _ 0 500 04-26A wpO5 K2B 7"x 8 1/2" 1 a-zs -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 Vertical Section at 7.48° (1500 usft/in) HALLIBURTON Site: Site: Duck Island Unit End SDI sPe.�v Drilling REFERENCE INFORMATION Well: Wellbore: Plan: DIU Plan: 04-26A6A ® Plan: DIU 4-26A wp06 6175 WEM DETAE.S: Plan: DIU 4-26A Ground love[: 13.90 NmMir, E.m, D uimmin Lonptude 0,00 0.00 5970808.75 27030099 70-19-18.742N 147°51'45,138W REFERENCE INFORMATION C.aMimle (NIE, Rererence: Weu Plan: DiU a28a Tma Nndh WMul ("10) Reference: DIU 4-26A wp06 RNB @ 40A0ust (Innaumon) Measured DuW Rekrenu: DIU 4d6AwpN MB @ 4040usa (Innovation) Calwlalion Method: Minimum Curvature .Ont - CASING DETAILS - TVD TVDSS MD Name End Dir : 6241.13' b4D, 60616' ]VD - 9890.73 9850.33 13906.46 7" x 8 1/2" DIU26AwP06 T'x812" _-- W-26A w 05 P B 9250 8500 c 4275 End Dir : 6503.76MD, 619502'TVD 7500 8250 � Stet DIrY/W':63WM 'D,W93n:VD End Dir :10333.93' M1m, 811006' TVD 950 .Ont - Stan Dir 3°/100': 10267.76' MD, BOT/.02TVD - - End Dir : 6241.13' b4D, 60616' ]VD - + 3800 Start Dir W100: 5447.08' MD, 5441.56ND-' 8000 L 4-26 6500 C End Dir : 5417.01[2.9' 6000 O - 106117 6000 3325 Dir 12.2VfIW': 54W MD, 5395.639VD: 85-ITTF; 575 0 s 5750 3 10001 00 2850 95W 6750 -1900 -1425 -950 475 0 475 950 1425 1900 2375 2850 3325 3800 4275 4750 West( -)/East( -t) (950 mft/in) End Dir : 6503.76MD, 619502'TVD 7500 6506 Stet DIrY/W':63WM 'D,W93n:VD 950 .Ont - --6250 70 00 End Dir : 6241.13' b4D, 60616' ]VD - Start Dir W100: 5447.08' MD, 5441.56ND-' 6500 475 End Dir : 5417.01[2.9' 6000 - 6000 XOP: Start Dir 12.2VfIW': 54W MD, 5395.639VD: 85-ITTF; 575 5750 -1900 -1425 -950 475 0 475 950 1425 1900 2375 2850 3325 3800 4275 4750 West( -)/East( -t) (950 mft/in) HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Duck Island Unit Site: End SDI Well: Plan: DIU 4-26A Wellbore: Plan: 04-26A Design: DIU 4-26Awp06 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: DIU 4-26A TVD Reference: DIU 4-26AwpD6 RKB @ 40.40usft (Innovation) MD Reference: DIU 4-26A wp06 RKB @ 40.40usft (Innovation) North Reference: True Survey Calculation Method: Minimum Curvature Project Duck Island Unit, North Slope, UNITED STATES Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) - Using Well Reference Point Map Zone: Alaska Zone 03 Using geodetic scale factor Site Site Position: From: Position Uncertainty: End SDI, TR -11-17 Northing: Map Easting: 0.00 usft Slot Radius: 5,969,322.46usft Latitude: 272,231.79 usft Longitude: 0° Grid Convergence: 70'19'4.709N 147° 50'47,497 W -1.74 ° well Plan: DIU 4-26A, 4-26/0-34 Well Position +N/S 0.00 usft Northing: 5,970,808.75 usfl . Latitude: 70° 19' 18.742 N +E/ -W 0.00 usft Easting: 270,300.99 usft . Longitude: 147° 51'45.138 W Position Uncertainty 0.00 usfl Wellhead Elevation: 13.90 usft Ground Level: 13.90 usfl Wellbore Plan: 04-26A Magnetics Model Name Sample Date Declination Dip Angle Field Strength BGGM2018 7/15/2018 17.55 81.04 57,461 Design DIU 4-26A wp06 Audit Notes: Version: Phase: PLAN Tie On Depth: 5,400.00 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction (usft) (usft) (usft) V) 26.50 0.00 0.00 7.48 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/ -S +E/ -W Rate Rate Rate Tool Face (usft) (°) (I (usft) usft (usft) (usft) (1100usft) ('/100usft) ('/100usft) (1) 5,400.00 12.53 358.74 5,395.63 5,355.23 63.18 41.80 0.00 0.00 0.00 0.00 5,417.08 12.72 349.18 5,412.29 5,371.89 66.89 41.41 12.29 1.08 -55.59 -85.00 5,447.08 12.72 349.18 5,441.56 5,401.16 73.38 40.17 0.00 0.00 0.00 0.00 6,241.13 60.00 1.94 6,063.60 6,023.20 529.49 35.10 6.00 5.95 1.61 15.00 6,300.00 60.00 1.94 6,093.04 6,052.64 580.45 36.83 0.00 0.00 0.00 0.00 6,503,76 60.00 9.00 6,195.02 6,154.62 755.94 53.63 3.00 0.00 3.46 91.77 10,267.76 60.00 9.00 8,077.02 8,036.62 3,975.53 563.57 0.00 0.00 0.00 0.00 10,333.93 60.10 6.71 8,110.06 8,069.66 4,032.32 571.40 3.00 0.16 -3.46 -87.58 13,785.42 60.10 6.71 9,830.40 9,790.00 7,004.00 921.12 0.00 0.00 0.00 0.00 13,906.46 60.10 6.71 9,890.73 9,850.33 7,108.21 933.39 0.00 0,00 0.00 0.00 61612018 2:21:38PM Page 2 COMPASS 5000.1 Build 81E Planned Survey Halliburton H A LL I B U R TO N Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Plan: DIU 4-26A Company: Hilcorp Alaska, LLC ND Reference: DIU 4-26A wp06 RKS @ 40.40usft (Innovation) Project: Duck Island Unit MD Reference: DIU 4-26A wp06 RKB @ 40.40usft (Innovation) Site: End SDI North Reference: True Well: Plan: DIU 4-26A Survey Calculation Method: Minimum Curvature Wellbore: Plan: 04-26A Depth Inclination Design: DIU 4.26Awp06 Depth 7VDss Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth 7VDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (') (I (usft) usft (usft) (usft) (usft) (usft) 59.60 100.00 0.52 266.25 100.00 59.60 -0.16 -0.36 5,970,808.60 270,300.62 0.00 -0.21 200.00 0.45 277.79 200.00 159.60 -0.07 -1.20 5,970,808.72 270,299.79 0.12 -0.23 300.00 0.24 262.34 299.99 259.59 -0.09 -1.84 5,970,808.71 270,299.15 0.22 -0.33 400.00 0.25 296.46 399.99 359.59 0.05 -2.14 5,970,808.86 270,298.85 0.15 -0.23 500.00 0.21 254.41 499.99 459.59 0.09 -2.58 5,970,808.92 270,298.42 0.17 -0.24 600.00 0.10 226.66 599.99 559.59 -0.03 -2.82 5,970,808.80 270.298.17 0.13 -0.40 700.00 0.07 93.19 699.99 659.59 -0.12 -2.83 5,970,808.72 270,298.15 0.15 -0.49 800.00 0.10 327.97 799.99 759.59 0.00 -2.80 5,970,808.84 270,298.19 0.15 -0.36 900.00 0.08 269.34 899.99 859.59 0.12 -2.99 5,970,808.96 270,298.01 0.09 -0.27 1,000.00 0.05 129.37 999.99 959.59 0.08 -3.03 5,970,808.92 270,297.97 0.12 -0.31 1,100.00 0.23 32.39 1,099.99 1,059.59 0.24 -2.85 5,970,809.07 270,298.15 0.24 -0.14 1,200.00 0.19 3.23 1,199.99 1,159.59 0.63 -2.70 5,970,809.46 270,298.31 0.11 0.27 1,300.00 0.06 17.48 1,299.99 1,259.59 0.82 -2.69 5,970,809.66 270,298.33 0.13 0.47 1,400.00 0.00 0.00 1,399.99 1,359.59 0.86 -2.68 5,970,809.69 270,298.34 0.06 0.50 1,500.00 0.20 70.86 1,499.99 1,459.59 0.90 -2.53 5,970,809.73 270,298.49 0.20 0.57 1,600.00 0.49 57.84 1,599.99 1,559.59 1.19 -2.00 5,970,810.00 270,299.03 0.30 0.91 1,700.00 0.89 52.31 1,699.98 1,659.58 1.88 -1.00 5,970,810.66 270,300.04 0.40 1.73 1,800.00 1.09 39.95 1,799.96 1,759.56 3.11 0.24 5,970,811.85 270,301.33 0.30 3.11 1,900.00 1.00 37.48 1,899.95 1,859.55 4.57 1.40 5,970,813.28 270,302.53 0.10 4.72 2,000.00 0.78 39.45 1,999.93 1,959.53 5.73 2.33 5,970,814.41 270,303.49 0.22 5.99 2,100.00 0.78 40.93 2,099.93 2,059.53 6.79 3.20 5,970,815.44 270,304.40 0.02 7.15 2,200.00 0.79 34.44 2,199.92 2,159.52 7.85 4.10 5,970,816.47 270,305.33 0.09 8.32 2,300.00 0.73 27.71 2,299.91 2,259.51 8.96 4.70 5,970,817.56 270,305.96 0.11 9.50 2,400.00 0.87 30.29 2,399.90 2,359.50 10.19 5.37 5,970,818.77 270,306.67 0.14 10.81 2,489.70 0.82 35.35 2,489.59 2,449.19 11.31 6.09 5,970,819.87 270,307.42 0.10 12.01 13 318" 2,500.00 0.84 36.45 2,499.89 2,459.49 11.43 6.17 5,970,819.99 270,307.51 0.26 12.14 2,600.00 0.95 50.56 2,599.87 2,559.47 12.60 7.25 5,970,821.12 270,308.62 0.25 13.44 2,700.00 0.98 55.88 2,699.86 2,659.46 13.61 8.63 5,970,822.09 270,310.03 0.09 14.62 2,800.00 0.95 58.92 2,799.85 2,759.45 14.52 10.06 5,970,822.96 270,311.49 0.06 15.71 2,900.00 1.02 63.05 2,899.83 2,859.43 15.35 11.53 5,970,823.73 270,312.99 0.10 16.72 3,000.00 0.94 66.60 2,999.82 2,959.42 16.10 13.07 5,970,824.44 270,314.55 0.10 17.66 3,100.00 1.09 73.19 3,099.80 3,059.40 16.67 14.60 5,970,824.96 270,316.09 0.20 18.43 3,200.00 1.19 69.73 3,199.78 3,159.38 17.34 16.47 5,970,825.58 270,317.98 0.12 19.34 3,300.00 1.30 71.31 3,299.76 3,259.36 18.04 18.49 5,970,826.21 270,320.03 0.12 20.29 3,400.00 1.33 71.64 3,399.73 3,359.33 18.79 20.70 5,970,826.89 270,322.25 0.03 21.32 3,500.00 1.08 78.32 3,499.71 3,459.31 19.20 22.83 5,970,827.24 270,324.39 0.28 22.00 3,600.00 0.84 77.36 3,599.70 3,559.30 19.54 24.31 5,970,827.54 270,325.89 0.24 22.54 3,700.00 0.88 82.61 3,699.69 3,659.29 19.83 25.78 5,970,827.78 270,327.36 0.09 23.02 3,800.00 1.11 86.67 3,799.67 3,759.27 20.01 27.49 5,970,827.91 270,329.07 0.24 23.42 3,900.00 1.16 92.77 3,899.65 3,859.25 20.02 29.50 5,970,827.85 270,331.09 0.13 23.69 4,000.00 1.22 98.31 3,999.63 3,95923 19.79 31.63 5,970,827.56 270,333.21 0.13 23.74 4,100.00 1.19 103.09 4,099.61 4,059.21 19.42 33.67 5,970,827.13 270,335.23 0.11 23.64 4,200.00 1.38 110.43 4,199.58 4,159.18 18.79 35.82 5,970,826.44 270,337.37 0.25 23.30 4,300.00 1.53 118.69 4,299.55 4,259.15 17.76 38.15 5,970,825.34 270,339.66 0.26 22.58 6/6.2018 2:21:38PM Page 3 COMPASS 5000.1 Build 81E HALLIBURTON Database: Sperry EDM - NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Duck Island Unit Site: End SDI Well: Plan: DIU 4-26A Wellbore: Plan: 04-26A Design: DIU 4-26A wp06 Planned Survey Measured Vertical Depth Inclination Azimuth Depth TVDss (usft) (°) (I (usft) usft 4,400.00 1.15 117.95 4,399.52 4,359.12 4,500.00 0.92 121.67 4,499.51 4,459.11 4,600.00 0.63 123.19 4,599.50 4,559.10 4,700.00 0.34 126.93 4,699.49 4,659.09 4,800.00 0.27 129.41 4,799.49 4,759.09 4,900.00 0.11 126.21 4,899.49 4,859.09 5,000.00 0.08 2.60 4,999.49 4,959.09 5,100.00 4.31 355.82 5,099.40 5,059.00 5,200.00 7.70 355.39 5,198.83 5,158.43 5,300.00 10.17 357.83 5,297.60 5,257.20 5,400.00 12.53 358.74 5,395.63 5,355.23 KOP: Start Dir 12.29°/100' : 5400' MD, 5395.63'TVD : 65° LT TF 5,417.08 12.72 349.18 5,412.29 5,371.89 End Dir : 5417.08' MD, 5412.29' TVD 5,447.08 12.72 349.18 5,441.56 5,401.16 Start Dir 6°/100': 5447.08' MD, 5441.56 -TVD 5,500.00 15.81 352.20 5,492.84 5,452.44 5,600.00 21.71 355.59 5,587.49 5,547.09 5,700.00 27.66 357.57 5,678.31 5,637.91 5,800.00 33.62 358.90 5,764.31 5,723.91 5,869.07 37.74 359.60 5,820.40 5,780.00 Cretaceous Sands 5,900.00 39.59 359.87 5,844.55 5,804.15 6,000.00 45.57 0.62 5,918.15 5,877.75 6,100.00 51.55 1.23 5,984.30 5,943.90 6,200.00 57.54 1.75 6,042.28 6,001.88 6,241.13 60.00 1.94 6,063.61 6,023.21 End Dir : 6241.13' MD, 6063.6' TVD 6,300.00 60.00 1.94 6,093.04 6,052.64 Start Dir 3'/100' : 6300' MD, 6093.04 -TVD 6,400.00 59.95 5.41 6,143.09 6,102.69 6,500.00 60.00 8.87 6,193.14 6,152.74 6,503.76 60.00 9.00 6,195.02 6,154.62 End Dir : 6503.76' MD, 6195.02' TVD 6,600.00 60.00 9.00 6,243.14 6,202.74 6,700.00 60.00 9.00 6,293.14 6,252.74 6,800.00 60.00 9.00 6,343.14 6,302.74 6,900.00 60.00 9.00 6,393.14 6,352.74 7,000.00 60.00 9.00 6,443.14 6,402.74 7,100.00 60.00 9.00 6,493.14 6,452.74 7,200.00 60.00 9.00 6,543.14 6,502.74 7,300.00 60.00 9.00 6,593.14 6,552.74 7,400.00 60.00 9.00 6,643.14 6,602.74 7,500.00 60.00 9.00 6,693.14 6,652.74 7,600.00 60.00 9.00 6,743.14 6,702.74 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: DIU 4-26A TVD Reference: DIU 4-26Awp06 RK8 @ 40.40usft (Innovation) MD Reference: DIU 4-26Awp06 IRKS @ 40.40usft (Innovation) North Reference: True Survey Calculation Method: Minimum Curvature 838.26 66.67 Map Map 0.00 839.81 +N/S +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) (usft) 4,359.12 1,012.95 16.70 40.26 5,970,824.21 270,341.74 0.38 21.80 15.81 41.77 5,970,823.27 270,343.22 0.24 21.11 15.02 42.94 5,970,822.45 270,344.37 0.29 20.48 14.57 43.57 5,970,821.98 270,344.99 0.30 20.12 14.25 43.97 5,970,821.64 270,345.37 0.07 19.85 14.05 44.25 5,970,821.43 270,345.65 0.16 19.69 13.99 44.39 5,970,821.38 270,345.78 0.17 19.65 17.45 44.16 5,970,824.84 270,345.66 4.23 23.05 27.92 43.25 5,970,835.34 270,345.07 3.39 33.32 43.45 42.48 5,970,850.87 270,344.78 2.50 48.61 63.18 41.80 5,970,870.62 270,344.70 2.37 68.09 66.89 41.41 5,970,874.34 270,344.42 12.28 71.71 73.38 40.17 5,970,880.86 270,343.38 0.00 77.98 86.25 38.09 5,970,893.79 270,341.70 6.00 90.48 118.22 34.82 5,970,925.84 270,339.41 6.00 121.75 159.89 32.41 5,970,967.57 270,338.28 6.00 162.75 210.80 30.90 5,971,018.50 270,338.32 6.00 213.03 251.08 30.38 5,971,058.77 270,339.04 6.00 252.90 270.40 30.29 5,971,078.09 270,339.54 6.00 272.04 338.03 30.61 5,971,145.67 270,341.93 6.00 339.14 412.95 31.84 5,971,220.52 270,345.45 6.00 413.58 494.35 _ 33.97 5,971,301.81 270,350.07 6.00 494.56 529.50 35.10 5,971,336.90 270,352.28 6.00 529.56 580.45 36.83 5,971,387.78 270,355.56 0.00 580.30 666.83 42.37 5,971,473.95 270,363.75 3.00 666.67 752.72 53.13 5,971,559.46 270,377.13 3.00 753.23 755.94 53.63 5,971,562.66 270,377.73 3.00 756.49 838.26 66.67 5,971,644.54 270,393.28 0.00 839.81 923.80 80.22 5,971,729.62 270,409.44 0.00 926.38 1,009.33 93.77 5,971,814.70 270,425.60 0.00 1,012.95 1,094.87 107.32 5,971,899.78 270,441.76 0.00 1,099.52 1,180.41 120.86 5,971,984.86 270,457.92 0.00 1,186.09 1,265.94 134.41 5,972,069.93 270,474.08 0.00 1,272.67 1,351.48 147.96 5,972,155.01 270,490.23 0.00 1,359.24 1,437.01 161.51 5,972,240.09 270,506.39 0.00 1,445.81 1,522.55 175.05 5,972,325.17 270,522.55 0.00 1,532.38 1,608.09 188.60 5,972,410.25 270,538.71 0.00 1,618.95 1,693.62 202.15 5,972,495.33 270,554.87 0.00 1,705.53 6/62018 2:21:38PM Page 4 COMPASS 5000.1 Build 81E HALLIBURTON Halliburton Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Plan: DIU 4-26A Company: Hilcorp Alaska, LLC TVD Reference: DIU 4-26A wp06 IRKS @ 40.40usft (Innovation) Project: Duck Island Unit MD Reference: DIU 4-26Awp06 RKB @ 40.40usft (Innovation) Site: End SDI North Reference: True Well: Plan: DIU 4-26A Survey Calculation Method: Minimum Curvature Wellbore: Plan: 04-26A Design: DIU 4-26Awp06 Planned Survey - -- Measured Vertical Map Map Depth Inclination Azimuth Depth TVD.. +NIS +EI -W Northing Easting DLS Vert Section (usft) (•) M (usft) usft (usft) (usft) (usft) (usft) 6,752.74 7,700.00 60.00 9.00 6,793.14 6,752.74 1,779.16 215.70 5,972,580.40 270,571.03 0.00 1,792.10 7,800.00 60.00 9.00 6,843.14 6,802.74 1,864.70 229.24 5,972,665.48 270,587.19 0.00 1,678.67 7,900.00 60.00 9.00 6,893.14 6,852.74 1,950.23 242.79 5,972,750.56 270,603.34 0.00 1,965.24 8,000.00 60.00 9.00 6,943.14 6,902.74 2,035.77 256.34 5,972,835.64 270,619.50 0.00 2,051.81 8,100.00 60.00 9.00 6,993.14 6,952.74 2,121.30 269.89 5,972,920.72 270,635.66 0.00 2,138.39 8,200.00 60.00 9.00 7,043.14 7,002.74 2,206.84 283.43 5,973,005.79 270,651.82 0.00 2,224.96 8,246.53 60.00 9.00 7,066.40 7,026.00 2,246.64 289.74 5,973,045.38 270,659.34 0.00 2,265.24 SchraderNJest Sak 8,300.00 60.00 9.00 7,093.14 7,052.74 2,292.38 296.98 5,973,090.87 270,667.98 0.00 2,311.53 8,400.00 60.00 9.00 7,143.14 7,102.74 2,377.91 310.53 5,973,175.95 270,684.14 0.00 2,398.10 8,500.00 60.00 9.00 7,193.14 7,152.74 2,463.45 324.08 5,973,261.03 270,700.30 0.00 2,484.68 8,600.00 60.00 9.00 7,243.14 7,202.74 2,548.99 337.63 5,973,346.11 270,716.45 0.00 2,571.25 8,700.00 60.00 9.00 7,293.14 7,252.74 2,634.52 351.17 5,973,431.19 270,732.61 0.00 2,657.82 8,800.00 60.00 9.00 7,343.14 7,302.74 2,720.06 364.72 5,973,516.26 270,748.77 0.00 2,744.39 8,884.53 60.00 9.00 7,385.40 7,345.00 2,792.36 376.17 5,973,588.18 270,762.43 0.00 2,817.57 Top Colville 8,900.00 60.00 9.00 7,393.14 7,352.74 2,805.60 378.27 5,973,601.34 270,764.93 0.00 2,830.96 9,000.00 60.00 9.00 7,443.14 7,402.74 2,891.13 391.82 5,973,686.42 270,781.09 0.00 2,917.54 9,100.00 60.00 9.00 7,493.14 7,452.74 2,976.67 405.36 5,973,771.50 270,797.25 0.00 3,004.11 9,200.00 60.00 9.00 7,543.14 7,502.74 3,062.20 418.91 5,973,856.58 270,813.41 0.00 3,090.68 9,300.00 60.00 9.00 7,593.14 7,552.74 3,147.74 432.46 5,973,941.65 270,829.56 0.00 3,177.25 9,400.00 60.00 9.00 7,643.14 7,602.74 3,233.28 446.01 5,974,026.73 270,845.72 0.00 3,263.82 9,500.00 60.00 9.00 7,693.14 7,652.74 3,318.81 459.55 5,974,111.81 270,861.88 0.00 3,350.40 9,600.00 60.00 9.00 7,743.14 7,702.74 3,404.35 473.10 5,974,196.89 270,878.04 0.00 3,436.97 9,700.00 60.00 9.00 7,793.14 7,752.74 3,489.89 486.65 5,974,281.97 270,894.20 0.00 3,523.54 9,800.00 60.00 9.00 7,843.14 7,802.74 3,575.42 500.20 5,974,367.05 270,910.36 0.00 3,610.11 9,900.00 60.00 9.00 7,893.14 7,852.74 3,660.96 513.74 5,974,452.12 270,926.52 0.00 3,696.68 10,000.00 60.00 9.00 7,943.14 7,902.74 3,746.49 527.29 5,974,537.20 270,942.67 0.00 3,783.26 10,100.00 60.00 9.00 7,993.14 7,952.74 3,832.03 540.84 5,974,622.28 270,958.83 0.00 3,869.83 10,200.00 60.00 9.00 8,043.14 8,002.74 3,917.57 554.39 5,974,707.36 270,974.99 0.00 3,956.40 10,267.76 60.00 9.00 8,077.02 8,036.62 3,975.53 563.57 5,974,765.01 270,985.94 0.00 4,015.06 Start Dir 3"1100' : 10267.76' MD, 8077.02 -TVD 10,300.00 60.05 7.88 8,093.13 8,052.73 4,003.15 567.67 5,974,792.49 270,990.88 3.00 4,042.98 10,333.93 60.10 6.71 8,110.05 8,069.65 4,032.32 571.40 5,974,821.53 270,995.51 3.00 4,072.39 End Dir : 10333.93' M0, 8110.06' TVD 10,400.00 60.10 6.71 8,142.99 8,102.59 4,089.20 578.10 5,974,878.18 271,003.94 0.00 4,129.66 10,500.00 60.10 6.71 8,192.83 8,152.43 4,175.30 588.23 5,974,963.93 271,016.70 0.00 4,216.35 10,600.00 60.10 6.71 8,242.67 8,202.27 4,261.40 598.36 5,975,049.67 271,029.47 0.00 4,303.03 10,700.00 60.10 6.71 8,292.52 8,252.12 4,347.50 608.49 5,975,135.42 271,042.23 0.00 4,389.72 10,800.00 60.10 6.71 8,342.36 8,301.96 4,433.60 618.63 5,975,221.16 271,054.99 0.00 4,476.40 10,900.00 60.10 6.71 8,392.20 8,351.80 4,519.70 628.76 5,975,306.90 271,067.75 0.00 4,563.09 11,000.00 60.10 6.71 8,442.05 8,401.65 4,605.79 638.89 5,975,392.65 271,080.52 0.00 4,649.77 11,100.00 60.10 6.71 8,491.89 8,451.49 4,691.89 649.02 5,975,478.39 271,093.28 0.00 4,736.46 11,200.00 60.10 6.71 8,541.73 8,501.33 4,777.99 659.16 5,975,564.14 271,106.04 0.00 4,823.14 11,300.00 60.10 6.71 8,591.58 8,551.18 4,864.09 669.29 5,975,649.88 271,118.80 0.00 4,909.83 61&2018 2:21:38PM Page 5 COMPASS 5000.1 Build 8fE HALLIBURTON Database: Company: Project: Site: Well: Wellbore: Design: Planned Survey Sperry EDM - NORTH US + CANADA Hilcorp Alaska, LLC Duck Island Unit End SDI Plan: DIU 4-26A Plan: 04-26A DIU 4-26A wp06 Measured 770.61 Map Vertical 271,246.43 Depth Inclination Azimuth Depth TVDss (usft) (•) (_) (usft) usft 11,400.00 60.10 6.71 8,641.42 8,601.02 11,500.00 60.10 6.71 8,691.26 8,650.86 11,600.00 60.10 6.71 8,741.11 8,700.71 11,700.00 60.10 6.71 8,790.95 8,750.55 11,800.00 60.10 6.71 8,840.79 8,800.39 11,900.00 60.10 6.71 8,890.64 8,850.24 12,000.00 60.10 6.71 8,940.48 8,900.08 12,100.00 60.10 6.71 8,990.33 8,949.93 12,200.00 60.10 6.71 9,040.17 8,999.77 12,236.58 60.10 6.71 9,058.40 9,018.00 TUFF 5,603.31 5,638.98 760.48 5,976,421.58 12,300.00 60.10 6.71 9,090.01 9,049.61 12,400.00 60.10 6.71 9,139.86 9,099.46 12,500.00 60.10 6.71 9,189.70 9,149.30 12,600.00 60.10 6.71 9,239.54 9,199.14 12,700.00 60.10 6.71 9,289.39 9,248.99 12,800.00 60.10 6.71 9,339.23 9,298.83 12,900,00 60.10 6.71 9,389.07 9,348.67 13,000.00 60.10 6.71 9,438.92 9,398.52 13,100.00 60.10 6.71 9,488.76 9,448.36 13,200.00 60.10 6.71 9,538.60 9,498.20 13,295.89 60.10 6.71 9,586.40 9,546.00 THRZ 7,076.95 7,102.65 932.73 13,300.00 60.10 6.71 9,588.45 9,548.05 13,400.00 60.10 6.71 9,638.29 9,597.89 13,500.00 60.10 6.71 9,688.14 9,647.74 13,600.00 60.10 6.71 9,737.98 9,697.58 13,700.00 60.10 6.71 9,787.82 9,747.42 13,785.42 60.10 6.71 9,830.40 9,790.00 LCU/K2B 13,800.00 60.10 6.71 9,837.67 9,797.27 13,900.00 60.10 6.71 9,887.51 9,847.11 13,906.46 60.10 6.71 9,890.73 • 9,850.33 Total Depth : 13906.46' M0, 9890.73' TVD - 7" x 81/2" Targets Target Name - hiVmiss target Dip Angle -Shape 0426Awp05 K2B 0.00 - plan hits target center -Circle (radius 100.00) 13,906.46 9,890.73 7" .811T Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan: DIU 4-26A DIU 4-26A wp06 RKB fig 40.40usft (Innovation) DIU 4.26Awp06 RKB @ 40.40usft (Innovation) True Minimum Curvature 5,725.08 770.61 Map Map 271,246.43 0.00 +N/S +E/.W Northing Easting DLS Vert Section (usft) (usft) (usft) (usft) 8,601.02 5,976,678.82 4,950.19 679.42 5,975,735.63 271,131.57 0.00 4,996.51 5,036.29 689.55 5,975,821.37 271,144.33 0.00 5,083.20 5,122.39 699.69 5,975,907.12 271,157.09 0.00 5,169.88 5,208.48 709.82 5,975,992.86 271,169.85 0.00 5,256.57 5,294.58 719.95 5,976,078.61 271,182.61 0.00 5,343.25 5,380.68 730.08 5,976,164.35 271,195.38 0.00 5,429.94 5,466.78 740.22 5,976,250.10 271,208.14 0.00 5,516.62 5,552.88 750.35 5,976,335.84 271,220.90 0.00 5,603.31 5,638.98 760.48 5,976,421.58 271,233.66 0.00. 5,689.99 5,670.47 764.19 5,976,452.95 271,238.33 0.00 5,721.70 5,725.08 770.61 5,976,507.33 271,246.43 0.00 5,776.68 5,811.17 780.75 5,976,593.07 271,259.19 0.00 5,863.36 5,897.27 790.88 5,976,678.82 271,271.95 0.00 5,950.05 5,983.37 801.01 5,976,764.56 271,284.71 0.00 6,036.73 6,069.47 811.14 5,976,850.31 271,297.48 0.00 6,123.42 6,155.57 821.28 5,976,936.05 271,310.24 0.00 6,210.10 6,241.67 831.41 5,977,021.80 271,323.00 0.00 6,296.78 6,327.76 841.54 5,977,107.54 271,335.76 0.00 6,383.47 6,413.86 851.67 5,977,193.29 271,348.52 0.00 6,470.15 6,499.96 861.81 5,977,279.03 271,361.29 0.00 6,556.84 6,582.52 871.52 5,977,361.25 271,373.52 0.00 6,639.96 6,586.06 871.94 5,977,364.76 271,374.05 0.00 6,643.52 6,672.16 882.07 5,977,450.52 271,386.81 0.00 6,730.21 6,758.26 892.20 5,977,536.27 271,399.57 0.00 6,816.89 6,844.36 902.33 5,977,622.01 271,412.34 0.00 6,903.58 6,930.45 912.47 5,977,707.75 271,425.10 0.00 6,990.26 7,004.00 921.12 5,977,781.00 271,436.00 0.00 7,064.31 7,016.55 922.60 5,977,793.50 271,437.86 0.00 7,076.95 7,102.65 932.73 5,977,879.24 271,450.62 0.00 7,163.63 7,108.21 933.39 5,977,884.78 271,451.45 0.00 7,169.23 Dip Dir. TVD +N/ -S (°) (usft) (usft) 0.00 9,830.40 7,004.00 +E/ -W Northing Eastmg (usft) (usft) (usft) 921.12 5,977,781.00 271,436.00 6/6/2018 2:21:38PM Page 6 COMPASS 5000.1 Build 81E HALLIBURTON Database: Sperry EDM - NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Duck Island Unit Site: End SDI Well: Plan: DIU 4-26A Wellbore: Plan: 04-26A Design: DIU 4-26Awp06 Formations Measured Depth (usft) 13,785.42 13,295.89 12,236.58 8,884.53 8,246.53 5,869.07 Plan Annotations Measured Depth (usft) 5,400.00 5,417.08 5,447.08 6,241.13 6,300.00 6,503.76 10,267.76 10,333.93 13,906.46 Vertical Depth (usft) 9,830.40 9,586.40 9,058.40 7,385.40 7,066.40 5,820.40 Vertical Depth lush) 5,395.63 5,412.29 5,441.56 6,063.61 6,093.04 6,195.02 8,077.02 8,110.05 9,890.73 Vertical Depth SS Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Name LCU/K2B THRZ TUFF Top Colville Schrader/West Bak Cretaceous Sands Local Coordinates +NIS +EJ -W (usfi) (usft) 63.18 41.80 66.89 41.41 73.38 40.17 529.50 35.10 580.45 36.83 755.94 53.63 3,975.53 563.57 4,032.32 571.40 7,004.00 921.12 Comment Halliburton Standard Proposal Report Well Pian: DIU 4-26A DIU 4-26A wp06 RKB @ 40.40usft (Innovation) DIU 4-26A wp06 RKB @ 40.40usft (Innovation) True Minimum Curvature Dip Dip Direction Lithology (I (I KOP: Start Dir 12.29°/100' : 5400' MD, 5395.63'TVD : 85` LT TF End Dir : 5417.08' MD, 5412.29' TVD Start Dir 6°/100' : 5447.08' MD, 5441.56'TVD End Dir : 6241.13' MD, 6063.6' TVD Start Dir 3-1100': 6300' MD, 6093.04'TVD End Dir : 6503.76' MD, 6195.02' TVD Start Dir 3°/100: 10267.76' MD, 8077.02'TVD End Dir : 10333.93' MD, 8110.06' TVD Total Depth : 13906.46' MD, 9890.73' TVD 6/62018 2:21:38PM Page 7 COMPASS 5000.1 Build 81E Hilcorp Alaska, LLC Duck Island Unit End SDI Plan: DIU 4-26A Plan: 04-26A DIU 4-26A wp06 Sperry Drilling Services Clearance Summary Anticollision Report 17 July, 2018 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: End SDI - Plan: DIU 4 -26A -Plan: 04-26A-DIU 4-26A wp06 Well Coordinates: 5,970,808.75 N, 270,300.99 E (70° 19' 18.74" N, 147' 61'46.14" W) Datum Height: DIU 4-26A wp06 RKB @ 40.40usft (Innovation) Scan Range: 6,400.00 to 13,907.07 usft. Measured Depth. Scan Radius is 1,688.06 usft. Clearance Factor cutoff Is Unlimited. Max Ellipse Separation is Unlimited Geodetic Scale Factor Applied Version: 6000.1 Build: 81E Scan Type: • •- Scan Type: 25.00 HALLIBURTON Sperry Drilling Services Hilcorp Alaska, LLC HALLIBURTON Duck Island Unit Anticollision Report for Plan: DIU 4-26A - DIU 4-26A wp06 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: End SDI - Plan: DIU 4 -26A -Plan: 04.26A-DIU 4-26A wp06 Scan Range: 5,400.00 to 13,907.07 usft. Measured Depth. Scan Radius is 1,688.06 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft End Duck Is DI -01 - DI -01 - DI -01 5,852.04 635.00 5,852.04 561.08 6,638.23 8.590 Centre Distance Pass - DI -01 - DI -01 - DI -01 5,875.00 635.29 5,875.00 561.03 6,660.70 8.555 Ellipse Separation Pass - DI -01 - DI -01 - DI -01 5,975.00 643.01 5,975.00 567.25 6,761.16 8.487 Clearance Factor Pass - End SDI 3-01-3-01-3.01 5,400.00 1,404.09 5,400.00 1,372.90 4,650.13 45.024 Ellipse Separation Pass - 3 -01-3-01-3-01 8,100.00 1,587.57 8,100.00 1,419.53 7,081.80 9.448 Clearance Factor Pass - 3 -03-3-03-3-03 9,276.40 1,470.74 9,276,40 1,393.64 8,202.48 19.076 Centre Distance Pass - 3 -03-3.03-3-03 9,350.00 1,471.27 9,350.00 1,393.04 8,252.59 18.808 Ellipse Separation Pass - 3 -03-3-03-3-03 10,775.00 1,586,18 10,775.00 1,476.74 9,541.76 14.493 Clearance Factor Pass - 3 -05-3-05-3-05 5,400.00 1,320,07 5,400.00 1,287.61 4,876.11 40.668 Ellipse Separation Pass - 3 -05-3-05-3-05 7,775.00 1,586,07 7,775.00 1,405.33 6,834.55 8.776 Clearance Factor Pass - 3 -07.3.07-3-07 5,400,00 1,142.90 5,400.00 1,112.90 4,790.86 38.095 Ellipse Separation Pass - 3 -07-3-07-3-07 7,700.00 1,581.95 7,700.00 1,427.47 6,725.59 10.241 Clearance Factor Pass - 3 -07 -3 -07A -3-07A 5,400.00 1,142.90 5,400.00 1,112.90 4,791.46 38.095 Ellipse Separation Pass - 3 -07.3 -07A -3-07A 7,700.00 1,581.95 7,700.00 1,427.47 6,726.19 10.241 Clearance Factor Pass- 3 -07A" -3 -07A -3-07A 5,400.00 1,143.30 5,400.00 993.50 4,791.12 7.632 Ellipse Separation Pass- 3.07A"- 3-07A- 3-07A 7,700.00 1,582.26 7,700.00 1,290.70 6,726.02 5.427 Clearance Factor Pass - 3 -09-3-09-3-09 5,400.00 646.36 5,400.00 605.69 5,138.41 15.896 Clearance Factor Pass - 3 -09- 3-09A- 3-09A 13,750.00 426.09 13,750.00 308.54 14,501.00 3.625 Clearance Factor Pass- 3.09- 3-09A- 3-09A 13,825.00 419.72 13,825.00 305.22 14,551.51 3.666 Ellipse Separation Pass - 3 -09- 3-09A- 3-09A 13,845.62 419.41 13,845.62 305.48 14,562.93 3.681 Centre Distance Pass - 3 -11 - 3-11 - 3-11 5,400.00 1,371.83 5,400.00 1,342.29 4,651.77 46.441 Centre Distance Pass - 3 -11-3-11-3-11 11,950.00 1,474.78 11,950,00 1,074.11 10,993.16 3.681 Ellipse Separation Pass - 3 -11-3-11-3-11 12,750.00 1,584.27 12,750.00 1,130.87 11,684.76 3.494 Clearance Factor Pass - 3 -15-3-15-3-15 7,795,04 514.95 7,795.04 376.36 7,254.66 3.716 Centre Distance Pass - 3 -15-3-15-3-15 9,200.00 642.50 9,200.00 325.90 8,644.75 2.029 Ellipse Separation Pass - 3 -15-3-15-3-15 10,250.00 776.92 10,250.00 363.53 9,675.91 1.879 Clearance Factor Pass - 17 July, 2018 - 19:12 Page 2 of 8 COMPASS HALLIBURTON Hilcorp Alaska, LLC Duck Island Unit Anticollision Report for Plan: DIU 4-26A - DIU 4-26A wp06 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: End SDI - Plan: DIU 4-26A- Plan: 04.26A- DIU 4-26A wp06 Scan Range: 5,400.00 to 13,907.07 usft. Measured Depth. Scan Radius is 1,588.06 usft. Clearance Factor cutoff Is Unlimited. Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (weft) (usft) (usft) (usft) usft 3-17-3-17-3-17 13,907.07 588.91 13,907.07 461.81 12,818.22 4.633 Clearance Factor Pass - 3 -17 -3.17A -3-17A 13,907.07 601.01 13,907.07 474.73 12,745.73 4.759 Clearance Factor Pass - 3 -17- 3-178- 3-17B 12,342.80 751.28 12,342,80 606.94 11,382.25 5.205 Centre Distance Pass - 3 -17-3-17B-3.178 12,350.00 751.31 12,350.00 606.79 11,384.75 5.199 Ellipse Separation Pass - 3 -17 - 3-17B - 3-178 12,425.00 755.25 12,425.00 609.34 11,411.95 5.176 Clearance Factor Pass - 3 -17 -3 -17C -3-17C 12,342.80 751,28 12,342.80 606.72 11,382.50 5.197 Centre Distance Pass - 3 -17- 3-17C- 3-17C 12,350.00 751.31 12,350.00 606.58 11,385.00 5.191 Ellipse Separation Pass - 3 -17 - 3-17C - 3.17C 12,425.00 755.25 12,425.00 609.12 11,412.20 5.168 Clearance Factor Pass - 3-17-3.17C Pal -3-17C PB1 12,342.80 751.28 12,342.80 606.72 11,382.50 5.197 Centre Distance Pass - 3 -17 - 3-17C PBI - 3.17C PBI 12,350.00 751.31 12,350.00 606.58 11,385.00 5.191 Ellipse Separation Pass - 3-17 - 3-17C PB1 - 3.17C PB1 12,425.00 755.25 12,425.00 609.12 11,412.20 5.168 Clearance Factor Pass - 3.17-3-17D-3-171) 12,301,55 769.88 12,301.55 633.20 11,269.96 5.633 Centre Distance Pass - 3 -17 -3.17D -3-17D 12,325.00 770.20 12,325.00 633.03 11,277.18 5.615 Ellipse Separation Pass - 3 -17-3.171)-3-17D 12,350.00 771.23 12,350.00 633.38 11,288.15 5.595 Clearance Factor Pass - 3 -17- 3-17E- 3-17E 11,497.06 1,022.83 11,497.06 928.59 10,263.89 10.854 Centre Distance Pass - 3 -17- 3-17E- 3-17E 11,550.00 1,023.15 11,550.00 928.09 10,302.94 10.764 Ellipse Separation Pass - 3 -17 -3 -17E -3-17E 13,907.07 1,418.30 13,907.07 1,227.69 12,862.97 7.440 Clearance Factor Pass - 3 -17- 3-17F- 3-17F 13,907.07 985.68 13,907.07 878.45 15,389.18 9.192 Clearance Factor Pass - 3 -17 - 3-17F P81 - 3-17F PB1 11,497.06 1,022.83 11,497.06 928.38 10,263.89 10.830 Centre Distance Pass - 3-17-3-17F PB1-3-17F P81 11,550.00 1,023.15 11,550.00 927.88 10,302.94 10.740 Ellipse Separation Pass - 3 -17-3-17F PB1-3-17F PB1 13,907.07 1,418.30 13,907.07 1,227,66 12,862.97 7.439 Clearance Factor Pass - 3 -21-3-21-3-21 5,400.00 525.71 5,400.00 490.09 5,216.74 14.757 Ellipse Separation Pass - 3 -21-3-21-3-21 10,300.00 1,580.14 10,300,00 1,194.28 9,603.45 4.095 Clearance Factor Pass - 3 -27-3-27-3-27 10,111.05 217.20 10,111.05 102.81 9,290.64 1.899 Centre Distance Pass - 3 -27-3-27-3-27 10,125.00 217.26 10,125.00 102.64 9,303.67 1.895 Ellipse Separation Pass - 3 -27-3-27-3-27 10,150.00 217.67 10,150.00 102.72 9,327.01 1.894 Clearance Factor Pass - 3 -29-3-29-3-29 11,287.87 401.19 11,287.87 264.11 10,475.00 2.927 Centre Distance Pass - 3 -29-3-29-3-29 11,375.00 402.66 11,375.00 262.70 10,554.07 2.877 Ellipse Separation Pass - 3.29 - 3-29 - 3-29 11,525.00 410.05 11,525.00 265.91 10,693.88 2.845 Clearance Factor Pass - 3-31 - 3-31 - 3-31 13,907.07 770.16 13,907.07 460.95 12,568.61 2.491 Clearance Factor Pass - 17 July, 2018 - 19:12 Page 3 of 8 COMPASS HALLIBURTON Anticollision Report for Plan: DIU 4-26A - DIU 4-26A wp06 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: End SDI -Plan: DIU 4.26A -Plan: 04-26A-DIU 4.26AWp06 Scan Range: 6,400.00 to 13,907.07 usft. Measured Depth. Scan Radius is 1,588.06 usft. Clearance Factor cutoff Is Unlimited. Max Ellipse Separation is Unlimited Hilcorp Alaska, LLC Duck Island Unit 17 July, 2018 - 19'12 Page 4 of 8 COMPASS Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (uaft) (usft) (usft) usft 3 -33 -3 -33/K -37-3-33/K-37 5,400.00 1,411.54 5,400,00 1,309.89 4,618.01 13.866 Clearance Factor Pass - 3 -33- 3-33A/J-35- Plan #13 5,400.00 1,411.54 5,400.00 1,309.89 4,618.01 13.886 Clearance Factor Pass - 3 -33- 3-33A/J-35- 3-33A/J-35 5,400.00 1,411.54 5,400.00 1,309.89 4,618.01 13.866 Clearance Factor Pass - 3-33-3-33APBIIJ-35-3-33APBi/J-35 5,400.00 1,411.54 5,400.00 1,309.89 4,618.01 13.886 Clearance Factor Pass - 3-33-3-33APB2/J-35-3-33APB2/J-35 5,400.00 1,411.54 5,400.00 1,309.89 4,618.01 13.886 Clearance Factor Pass - 3.35 - 3-35 - 3-35 5,400.00 493.73 5,400.00 359.03 5,256.53 3.665 Clearance Factor Pass - 3 -39 -3 -39/J -39-3-39/J-39 5,400.00 879.17 5,400.00 818.59 4,997.80 14.514 Ellipse Separation Pass - 3 -39-3-39/J-39-3-391.1-39 7,250.00 1,582.72 7,250.00 1,436.52 6,085.71 10.826 Clearance Factor Pass - 3 -39 - 3.39A/1.37 - 3-39A/1-37 5,400.00 879.17 5,400.00 818.59 4,997.80 14.514 Ellipse Separation Pass - 339.3-39A/1-37-3-39AII-37 7,250.00 1,582.72 7,250.00 1,436.52 6,065.71 10.626 Clearance Factor Pass- 341 - 341 - 341 5,400.00 1,552.95 5,400.00 1,432.82 4,555.98 12.927 Clearance Factor Pass - 343 - 343 - 343 6,540.84 374.41 6,540.84 329.16 6,243.06 8.274 Centre Distance Pass - 3.43-3-43-343 6,550.00 374.48 6,550.00 329.10 6,248.37 6.251 Ellipse Separation Pass - 3 -43-343-343 6,600.00 377.48 6,600.00 331.43 6,277.27 8.196 Clearance Factor Pass - 345-345-345 5,400.00 1,252.22 5,400.00 1,111.30 4,789.44 8.886 Clearance Factor Pass - 347 -347/0-35-347/0-35 5,819.94 154.76 5,619.94 114.06 5,798.82 3.802 Centre Distance Pass - 347 -34710-35-347/Q-35 5,825.00 154.79 5,825.00 114.05 5,602.97 3.800 Clearance Factor Pass - 349 -349-349 5,400.00 798.33 5,400.00 656.55 5,061.80 5.631 Clearance Factor Pass - 349 -349-349 5,400.00 798.33 5,400.00 656.55 5,061.80 5,631 Centre Distance Pass- 349A"- 349A- 349A 5,400.00 798.33 5,400.00 656.55 5,061.80 5.631 Clearance Factor Pass - 349A" -3 -49A -349A 5,400.00 798.33 5,400.00 656.55 5,061.80 5.631 Centre Distance Pass - 4 -02-4-02-4-02 5,400,00 513.27 5,400.00 446.49 5,219.77 7.686 Clearance Factor Pass - 4 -02-4-02-4-02 5,400.00 513.27 5,400.00 463.68 5,219.77 10.349 Centre Distance Pass - 4 -04-4-04/r-26-4-04/1-26 5,400.00 1,323.96 5,400.00 1,225.98 4,633.25 13.511 Clearance Factor Pass - 4 -04 -4 -04? -26-4-04/r-26 5,400.00 1,323.96 5,400.00 1,239.94 4,633.25 15.756 Centre Distance Pass - 4-04-4-04AIT-30-4-04A/r-30 5,400.00 1,323.96 5,400.00 1,225.98 4,626.60 13.511 Clearance Factor Pass- 4-04-4-04A/r-30-4-04A/r-30 5,400.00 1,323.96 5,400.00 1,239.94 4,626.60 15.756 Centre Distance Pass - 4 -06-4-06-4-06 5,400.00 193.39 5,400.00 142.06 5,407.59 3.768 Ellipse Separation Pass - 4 -06-4-06-4-06 5,525.00 204.86 5,525.00 149.71 5,524.18 3.715 Clearance Factor Pass- 4-06A`--4-06A-4-06A 5,400.00 193.39 5,400.00 142.06 5,407.59 3.766 Ellipse Separation Pass - 17 July, 2018 - 19'12 Page 4 of 8 COMPASS HALLIBURTON Anticollision Report for Plan: DIU 4-26A - DIU 4-26A wp06 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: End SDI -Plan: DIU 4 -26A -Plan: 04.26A-DIU 4.26Awp06 Scan Range: 5,400.00 to 13,907.07 usft. Measured Depth. Scan Radius is 1,588.06 gall. Clearance Factor cutoff Is Unlimited. Max Ellipse Separation Is Unlimited Hilcorp Alaska, LLC Duck Island Unit 17 July, 2018 - 19:12 Page 5 of 8 COMPASS Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on She Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft 4-06A'--4-06A-4-06A 5,525.00 204.86 5,525.00 149.71 5,524.18 3.715 Clearance Factor Pass - 4 -08-4-08-4-08 5,400.00 1,282.23 5,400.00 1,215.70 4,720.88 19.271 Ellipse Separation Pass - 4 -08-4-08-4-08 6,450.00 1,585.66 6,450.00 1,469.02 5,587.03 13.594 Clearance Factor Pass - 4.14 - 4-14 - 4-14 5,400.00 92.75 5,400.00 53.89 5,410.65 2.387 Clearance Factor Pass - 4-14-4-14A/S-37-4-14A/S-37 5,400.00 92.75 5,400.00 53.69 5,403.57 2.387 Clearance Factor Pass - 4 -18-4-18-4.18 5,400.00 1,000.36 5,400.00 910.67 5,078.50 11.154 Ellipse Separation Pass - 4 -18-418-4-18 6,850.00 1,532.03 6,850.00 1,366.28 6,072.04 9.243 Clearance Factor Pass - 420 -420-4-20 5,400.00 136.14 5,400.00 97.95 5,386.31 3.565 Clearance Factor Pass - 4 -20 -4 -20A -4-20A 6,290.41 133.87 6,290.41 72.34 6,192.91 2.176 Centre Distance Pass - 4.20 -4 -20A -4-20A 6,400.00 141.56 6,400.00 64.63 6,287.64 1.840 Ellipse Separation Pass - 4 -20 -4 -20A -4-20A 6,475.00 152.24 6,475.00 67.56 6,356.16 1.798 Clearance Factor Pass - 4 -28-428-4-28 5,400.00 164.48 5,400.00 126.65 5,380.64 4.348 Clearance Factor Pass - 428 -4-28-4-28 5,400.00 164.48 5,400.00 145.11 5,380.64 8.491 Centre Distance Pass - 434-434/0.38-DEAP defin 5,400.00 466.18 5,400.00 432.44 5,333.92 13.818 Clearance Factor Pass - 434-4-34/0-38-DEAP defin 5,400.00 466.18 5,400.00 451.03 5,333.92 30.773 Centre Distance Pass - 434 -4-34/0-38-434/0-38 5,400.00 466.82 5,400.00 360.17 5,333.57 4.377 Clearance Factor Pass - 438 -438-4-38 5,400.00 684,14 5,400.00 549.19 5,164.64 5.070 Ellipse Separation Pass - 438 -438-4-38 8,575.00 1,581.59 8,575.00 1,216.30 7,802.92 4.330 Clearance Factor Pass - 4 -42-4-42-4-42 5,400.00 125.76 5,400.00 87.27 5,390.73 3.268 Clearance Factor Pass - 4 -46-4-46-446 5,400.00 1,057.48 5,400.00 967.68 5,013.31 11.776 Ellipse Separation Pass - 446 -4-06-446 6,675.00 1,581.46 6,675.00 1,443.55 5,928.27 11.468 Clearance Factor Pass- DIU 3-23A- 3-23- 3-23 7,867.65 363.58 7,867.65 245.52 7,323.22 3.080 Centre Distance Pass- DIU 3.23A- 3-23-3-23 8,000.00 369.74 8,000.00 240.87 7,435.22 2.869 Ellipse Separation Pass- DIU 3-23A- 3-23-3.23 8,175.00 390.59 8,175.00 250.04 7,598.12 2.779 Clearance Factor Pass - DIU 3-23A - SDI 03 -23A -SDI 03-23A 7,867.65 363.58 7,867.65 245.52 7,307.94 3.080 Centre Distance Pass - DIU 3-23A - SDI 03 -23A -SDI 03-23A 8,000.00 369.74 8,000.00 240.87 7,419.94 2.869 Ellipse Separation Pass - DIU 3-23A - SDI 03 -23A -SDI 03-23A 8,175.00 390.59 8,175.00 250.04 7,582.84 2.779 Clearance Factor Pass- DIU 3 -23A -SDI 03-23A PB1-SDI 03-23A P61 7,867.65 363.58 7,867.65 245.52 7,307.94 3.080 Centre Distance Pass - DIU 3-23A - SDI 03-23A PB1-SDI 03-23A PB1 8,000.00 369.74 8,000.00 240.87 7,419.94 2.869 Ellipse Separation Pass - DIU 3-23A - SDI 03.23A Pal -SDI 03-23A PB1 8,175.00 390.59 8,175.00 250.04 7,582.84 2.779 Clearance Factor Pass - 17 July, 2018 - 19:12 Page 5 of 8 COMPASS HALLIBURTON Anticollision Report for Plan: DIU 4-26A - DIU 4-26A wp06 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: End SDI - Plan: DIU 4-26A - Plan: 04-26A - DIU 4-26A wp06 Scan Range: 5,400.00 to 13,907.07 usft. Measured Depth. Scan Radius is 1,588.06 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Site Name Comparison Well Name - Wellbore Name - Design Plan. DIU 4-26A - 4-26 - 4-26 Survey too/ program Measured Minimum @Measured Depth Distance Depth (usft) (usft) (usft) 5,700.00 From To (usft) (usft) 35.70 5,400.00 5,400.00 13,906.46 DIU 4-26A wp06 Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor= Distance Between Profiles/(Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 18.35 5,700.00 Survey/Plan Ellipse @Measured Clearance Summary Based on Separation Depth Factor Minimum (usft) usft 12.77 5,713.42 3.287 Clearance Factor Survey Tool 2_Gyro-NS-CT_OWSG 2 MWD+IFR2+MS+Sag Hilcorp Alaska, LLC Duck Island Unit Separation Warning Pass - 17,l4,1y. 2018 - 19:12 Page 6 of 8 COMPASS HALLIBURTON Anticollision Report for Plan: DIU 4-26A - DIU 4-26A wp06 Direction and Coordinates are relative to True North Reference. Vertical Depths are relative to DIU 4-26A wp06 RKB @ 40.40usft (Innovation). Northing and Easting are relative to Plan: DIU 4-26A, Coordinate System is US State Plane 1927 (Exact solution), Alaska Zone 03. Central Meridian is -146.00°, Grid Convergence at Surface is: -1.75 °. C 7 Ladder Plot 0 2500 5000 7500 10000 12500 Measured Depth (2500 usft/in) Hilcorp Alaska, LLC Duck Island Unit -X- 3-25,3-25APB1,3-25APB1 V1 3-25,325BA--27,3-25BrL-27 V10 -� 3-Z,325BrL-27,325BL-27wp23V17 $ 327,327,327V1 -A- 329,3-29,329V1 $ 3.31,331,331 V6 $ 333,333M37,333MJ7V3 -E 333,3- 3 J-35.333AIJ35V7 -Y- 3-33,333A0,35, Plan#13V1 $ 333,333APB1/J-35,333APB1/J35V2 -A- 333,333APBW35,333APB2/J35V1 -ih- 335,335,335V1 -$ 337,337,337V1 $ 3 -39,3 -39/L39,3 -39W9\/2 -(- 339,339A637,339A437V6 -+- 3-41,3-41,3-41 V1 $ 3-43,343,3.43V1 -X- 345,345,3-45V1 -dr 3-47,3.47A-35,347Rk35V1 -er 349,349,3-49V1 -1116- 3-49R-3-49A,349AV4 -9-- 4-02,4-02,4-02V1 -} 4 -04,4 -041r -26,4-04/17-26V1 $ 4-04+NA/r30,4-04A/f-30V0 -*- 4-06,4-06,4-06V1 17 July, 2018 - 19:12 1,.. .... COMPASS HALLIBURTON Anticollision Report for Plan: DIU 4-26A - DIU 4-26A wp06 Clearance Factor Plot: Measured Depth versus Separation(Clearance) Factor ri Messuled Depth (2500 usfn) Hilcorp Alaska, LLC Duck Island Unit -0- 3-25,3-25,3-25V1 -K- 3-25,3-25APB1,3-25A�PB1 V1 -11- 3-25,325BL-27,3.25BL-27V10 -&- 3-25,3.25&L-27,325B�L-27vp23V17 $ 3-27,327,3-27Vl -h- 3.29,3-29,3-29V1 $ 3-31,331,3-31 V6 $ 3.33,3 -33M -37,3 -33K -37V3 -W 333,333A/J35,3-33A/J-35 V7 -4� 333,333A/J-35, Plan #13V1 $ 3.33,333APB1/J35,333APBl/ L35 V2 -d- 3-33,333APB2/J35,333APB2/J-35V7 -� 335, 3.35, 335 V1 $ 3-37, 3-37, 337 V1 $ 339,3 -39/J -39,3 -39/J -39V2 -X- 339,3-39AA37,339A437V6 -+- 341,341,341 V1 $ 343,343,343V1 -X- 345,345,345V1 -A- 347,347/2 -35,347/Q -35V1 -�- 349,349,349V1 f- 349A-,349A,349AV4 -�- 4-02,4-02,4-02V1 -} 4.04,4-04/r-26,444/l26V1 $ 4-04,4-04AT-30,404A/r-30V0 -)ME- 4-06,4-06,4-06V1 $ 4-06A-,4-06A,4-06AV2 17 July, 2018 - 19.12 Page 8 of 8 COMPASS Rixse, Melvin G (DOA) From: Joe Engel <jengel@hilcorp.com> Sent: Thursday, July 19, 2018 3:43 PM To: Rixse, Melvin G (DOA) Cc: Schwartz, Guy L (DOA); Monty Myers; Taylor Wellman; Regg, James B (DOA) Subject: RE: [EXTERNAL] RE: Hilcorp DIU 4-26A (PTD# TBD) Questions Mel Thank you for the question. The Innovation will be using the following rams for the operations on DIU 4-26A: BOP Preventer Operation Annular Upper Pipe Rams Annular Annular JAnnular 2-7/8" x 5-1/2" VBR 2-7/8" x 5-1/2" VBR 7" Solid Rams Blind Rams Lower Pipe Rams Blind Rams IBlindRams 181ind Rams 2-7/8" x 5-1/2" VBR 2-7/8" x 5-1/2" VBR 2-7/8" x 5-1/2" VBR Please let me know if you have any further questions. Thank you for your time. -Joe Joe Engel I Drilling Engineer I Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 1 Anchorage ( AK ) 99503 Office: 907.777.8395 1 Cell: 805.235.6265 Annular 2-7/8" x 5-1/2" VBR Blind Rams From: Rixse, Melvin G (DOA) [mailto:melvin.rixse@alaska.gov] Sent: Thursday, July 19, 2018 9:26 AM To: Joe Engel <jengel@hilcorp.com> Cc: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov>; Monty Myers <mmyers@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com>; Regg, James B (DOA) <jim.regg@alaska.gov> Subject: [EXTERNAL] RE: Hilcorp DIU 4-26A (PTD# TBD) Questions Joe, Thanks for your reply. Regarding the PTD BOPE schematic, I have recently noticed that some of the PTD applications from Hilcorp, label the ram sizes that will be utilized while drilling. After reviewing a legacy of PTD applications from Hilcorp, it appears that it has not been a requirement by AOGCC. I won't continue to request this convenience. Please provide ram sizes you plan to utilize while operating on this well. Step 12.9 on page 12 of this PTD application suggests you will be testing on 4-1/2" x 5" test joint. Specifically describe if these are VBRs, their size, and where they will be placed in your stack. Will you have blind rams? Step 17.1 on page 23 is clear what size you will utilize and where they will be placed. Thank you for that. Notably, I have been getting more phone calls from Hilcorp to allow a variance for rams. I am hopeful that if you accurately describe the rams you will be utilizing while operating on a well, you and your drilling foreman will have the foresight to plan for proper ram sizing. Mel Rixse Senior Petroleum Engineer (PE) Remark: AOGCC PTD No. 218-081 Coordinate Check 9 July 2018 INPUT Geographic, NAD27 DIU SDI 04-26A Latitude: 70 19 18.742 Longitude: 147 51 45.138 OUTPUT State Plane, NAD27 5003 -Alaska 3, U.S. Feet 1/1 Northing/Y: 5970808.791 Easting/X: 270300.985 Convergence: -1 45 13.80505 Scale Factor: 0.999959936 Corpscon v6.0.1, U.S. Army Corps of Engineers TRANSMITTAL LETTER CHECKLIST WELL NAME: �(LC �K iL 7 Z�vTi PTD: moi/y — Ue / Development _ Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: �v/ % POOL: Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50 - (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69 hi accordance with 20 AAC 25.005(1), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50— from from records, data and logs acquired for well name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Companv Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company -Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company -Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. hi addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements 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 da s after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Held & Pool ENDICOTT, ENDICOTT OIL - 220100 Public Well Name: DUCK IS UNIT SDI 4-26A — Program DEV Well bore seg PTD#:2180810 Company HILCORP ALASKA LLC _ _ - Initial Class/Type _ DEV /PEND_ GeoArea 86-0._ __- _ Un8 10450 On/Off Shore Off _ Annular Disposal Administration '17 Nonconven. gas conforms to AS31.05.0300.1..A),Q.2.A-D) NA - .......- 1 Permit fee attached... - - - - - - - NA - - - - - ,2 Lease number appropriate - Yes - Surface Location lies within ADL0047502; Top Prod Int & TO lie within ADL0047503____ 13 Unique well name and number _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - A Well located in a defined pool - - - - .. Yes Endicott,. Endicott Oil Pool - 220100, governed by CO 462 (effective January 7, 2002) as modified by CO . ,5 Well located proper distance from drilling unit boundary- - - Yes 501, which concerns sustained. casing pressures in development wells.. 6 Well located proper distance from other wells .. . . . . . . . ..... _ _ - _ - _ Yes CO 462, Rule 3 -(amended by CO 462.007 -effective March 30, 2017): There shall be no restrictions as to ... . 7 Sufficient acreage available in. drilling unit - ... - - - - - Yes wellspacingwithin the. Endicott Oil Pool, except that the.pool shall -not be. opened in any well closer . 8 If deviated, is wellbore plat. included . . . . . . ............ .. Yes - - - than 500 feet to the exterior bounda y,of the affected area, unless owner and landowner is the same on - - - 9 Operator only affected party . . . . . . . . ........... Yes both sides of the affected area boundary.. As proposed, well. conforms to spacing requirements.- 10 Operator has. appropriate bond in force - - - - - - - - Yes ...... .................... Appr Date 11 Permit can be issued without conservation order. - - - _ - _ - - - - - - Yes - - - - - - - - - - SFD 7/9/2018 12 Permit can be issued without administrative. approval - - - - - - - Yes 13 Can permit be approved before 15 -day wait - --- - -- - - - - - - - - - - - - Yes 14 Well located within area andstrataauthorized by Injection Order # (put 10# in. comments) (For NA - - - - - - 15 All wells. within 1/4 mile area of review identified (For service well only)- - ...... - - - NA 16 18 Pre -produced injector: duration of pre -production less than 3 months - (For service well only) - Conductor string. provided - _ - - - - - - - ---- - - - - - - - - - - - - - ... NA NA - - -Sidetrack off whipstock from existing intermediate hole Engineering 19 Surface casing protects all -known USDWs - -------- - - - - - - - - - NA. - - - Sidetrack off whipstock from existing Intermediate hole 20 CMT vol adequate to circulate -on conductor & surf csg . . . . . . . . . . ........ . . NA - - - - Sidetrack off whipstock from existing intermediate. hole - - - - 21 CMT vol adequate to tie-in.long string to.surf csg-- - - - - - - - ------- - - - - - - NA .... 22 CMT. will coverall known_ productive horizons - - _ _ - - _ _ _ Yes . 23 Casing designs adequate for C, T. B & permafrost.. - - - - . . . . . . . . ..... . .. Yes 24 .Adequate tankage or reserve pit .... - - - - - - - Yes 25 If a re -drill, has -a 10-403 for abandonment been approved - - - - - - - - --- - - - - Yes 26 Adequate wellbore separation proposed... - - - - - - - - - - Yes 27 If diverter required, does it meet_ regulations ... - . - - - - - - - ...... NA - _ - - - - - _ Sidetrack off whipstock from existing intermediate hole. Appr Date 28 Drilling fluid program schematic & equip list adequate- - - - - - . _ - Yes - - - - MGR 7/19/2018 29 BOPEs, do they meet regulation . . . . . . . . . . .. . ......... . Yes 30 BOPE-press rating appropriate: test to (put psig in comments).. .. - - - Yes - - - - - - - - - ----- - - - - - - 31 Choke manifold complies w/API. RP -53 (May 84), . . . . . . . . Yes 32 Work will occur without operation shutdown- - _ - - - _ - - .. Yes - 33 Is presence of H2S gas. probable _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes ..... 34 Mechanical.condition of wells within AOR verified (For service well only) ....... . . . . . . NA - .... 35 Permit. can be issued w/o hydrogen. sulfide measures ............. . . - - . .. No....... - Endicott Pool wells are H2S-bearing. H2S measures are required.- Geology 36 Data presented on potential overpressure zones....... - - - - - ...... Yes _ - _ Planned drilling mud program. (about 9.5 to 10.3-ppg) appears adequate to control operator's forecast Appr Date 37 Seismic analysis of shallow gaszones....... _ _ _ _ _ _ _ _ _ _ _ ...... NA - - - - pore pressure.gradient. Kekiktuk-reservoir expected to be under -pressured at about 8.0 ppg, Elevated- - SFD 7/9/2018 Seabed condition survey(ifoff-shore) - .. ..... ..... - _ _ _ - - ... _ NA _ _ _ _ mud weight of 1o,3.ppg is.needed to control overlying, unstable HRZ shale, Differential sticking.and/or 138 39 Contact name/phone for weekly.progress reports -[exploratory only] _ _ - NA lost circulation are possible. See pages -32,34 for discussion and mitigation measures.. . L' Geologic Engineering Public Date: Commissioner: Commissioner; Date Commissionel Date
