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216-139
MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Tuesday, August 26, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Bob Noble P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC B-34 MILNE PT UNIT B-34 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 08/26/2025 B-34 50-029-23569-00-00 216-139-0 N SPT 3979 2161390 1500 365 851 846 835 2 1 1 1 OTHER P Bob Noble 7/16/2025 EPA class 1 well, MIT-IA every year to 3500 psi, EPA was virtual. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:MILNE PT UNIT B-34 Inspection Date: Tubing OA Packer Depth 298 3737 3658 3644IA 45 Min 60 Min Rel Insp Num: Insp Num:mitRCN250718162206 BBL Pumped:1.5 BBL Returned:1.5 Tuesday, August 26, 2025 Page 1 of 1 Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 08/13/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250813 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# KBU 24-06RD 50133204990100 206013 4/2/2025 YELLOWJACKET GPT-PERF MPB-24 50029226420000 196009 7/9/2025 READ CaliperSurvey MPB-34 50029235690000 216139 7/7/2025 READ CaliperSurvey MPF-45 50029225560000 195058 7/30/2025 READ CaliperSurvey ODSK-41 50703205850000 208147 8/9/2025 READ CaliperSurvey ODSN-25 50703206560000 212030 6/22/2025 READ CaliperSurvey ODSN-31 50703205650000 208003 8/11/2025 READ CaliperSurvey PBU 06-11A 50029204280100 225042 7/13/2025 BAKER MRPM PBU 13-19 50029206900000 181180 6/4/2025 HALLIBURTON WFL-TMD3D PBU 14-18C 50029205510300 225040 6/24/2025 BAKER MRPM PBU 14-43A 50029222960100 225041 7/30/2025 BAKER MRPM PBU C-01B 50029201210200 212053 7/19/2025 BAKER MRPM SD-07 50133205940000 211050 7/27/2025 YELLOWJACKET SCBL SP 12-S3 50629235130000 214067 7/18/2025 YELLOWJACKET PERF Please include current contact information if different from above. T40771 T40772 T40773 T40774 T40775 T40776 T40777 T40778 T40779 T40780 T40781 T40782 T40783 T40784 MPB-34 50029235690000 216139 7/7/2025 READ CaliperSurvey Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.08.15 10:11:56 -08'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: Operable: Class 1 Disposal Well MPB-34 (PTD# 2161390) - Passing MIT-IA Date:Thursday, July 17, 2025 10:38:39 AM Attachments:RE EXTERNAL RE NOTICE Notice of Noncompliance Class I Permit AK-1I005-C Milne Point Unit Well MPB-34.msg From: Ryan Thompson <ryan.thompson@hilcorp.com> Sent: Thursday, July 17, 2025 10:35 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Taylor Wellman <twellman@hilcorp.com> Subject: Operable: Class 1 Disposal Well MPB-34 (PTD# 2161390) - Passing MIT-IA Mr. Wallace- On 7/11/25 a PPPOT-IC was performed on the MPB-34 wellhead where IC test void pressure would not bleed to 0 psi. The IC seals were re-energized and the well subsequently passed a PPPOT-IC. A non-witnessed passing MIT-IA was then performed to 3663 psi. On 7/16/25 EPA virtually witnessed and AOGCC witnessed a passing MIT-IA to 3644 psi. EPA has given approval to resume injection in the well (attached email) and the well is now re-classified as Operable. Please respond with any questions. Thank You, Ryan Thompson Milne / Islands / WNS Well Integrity Engineer 907-564-5005 From: Ryan Thompson Sent: Friday, July 11, 2025 12:12 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; jim.regg <jim.regg@alaska.gov> Cc: Taylor Wellman <twellman@hilcorp.com> Subject: Not Operable: Class 1 Disposal Well MPB-34 (PTD# 2161390) - IA/OA Pressures Tracking Mr. Wallace – On 7/11/25 while reviewing pressure data for the upcoming EPA MIT-IA, it was observed that the IA and OA pressures on Class 1 Disposal Well MPB-34 (PTD# 2161390) have been tracking since August of 2024 at pressures less than 250 psi. The well has been shut in and re-classified as Not Operable in order to perform diagnostics on the possible pressure communication between the IA and the OA on this well. Attached is a WBS and 12 month TIO plot. Plan Forward: 1. Perform PPPOT-IC, tighten LDS 2. Bleed OA pressure to 0 and check for equalization with the IA. 3. Perform MIT-IA to 3500 psi. The EPA has been notified, and the well will remain shut in until diagnostic results are obtained and EPA approval to resume injection has been received. Please respond with any questions. Thank you, Ryan Thompson Milne / Islands / WNS 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 theonward 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 EPA, please exercise additional caution when deciding whether to open attachments or click on provided links. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Mayers, Timothy To:Ryan Thompson; Osborne, Evan; Nickel, Brian; Mayers, Timothy Cc:Taylor Wellman; Alaska NS - Milne - Wells Foreman; Alaska NS - Environmental Specialist; Claire Costello - (C); Amy Peloza Subject:RE: [EXTERNAL] RE: NOTICE: Notice of Noncompliance, Class I Permit AK-1I005-C, Milne Point Unit Well MPB-34 Date:Thursday, July 17, 2025 10:18:31 AM Hi Ryan- Yes, based on the passing MIT performed on MPU-34 yesterday, EPA authorizes MPU- 34 to back on injection. Also, this MIT can constitute the annual MIT testing requirement. From: Ryan Thompson <ryan.thompson@hilcorp.com> Sent: Thursday, July 17, 2025 8:44 AM To: Osborne, Evan <Osborne.Evan@epa.gov>; Mayers, Timothy <Mayers.Timothy@epa.gov>; Nickel, Brian <Nickel.Brian@epa.gov> Cc: Taylor Wellman <twellman@hilcorp.com>; Alaska NS - Milne - Wells Foreman <AlaskaNS- WellsForeman@hilcorp.com>; mpuenviro@hilcorp.com; Claire Costello - (C) <ccostello@hilcorp.com>; Amy Peloza <apeloza@hilcorp.com> Subject: RE: [EXTERNAL] RE: NOTICE: Notice of Noncompliance, Class I Permit AK-1I005-C, Milne Point Unit Well MPB-34 Adding Brian Nickel to the request below. Thank you, Ryan From: Ryan Thompson <Ryan.Thompson@hilcorp.com> Sent: Thursday, July 17, 2025 8:37 AM To: Osborne, Evan <Osborne.Evan@epa.gov>; Mayers, Timothy <Mayers.Timothy@epa.gov> Cc: Taylor Wellman <twellman@hilcorp.com>; Alaska NS - Milne - Wells Foreman <AlaskaNS- WellsForeman@hilcorp.com>; Alaska NS - Environmental Specialist <mpuenviro@hilcorp.com>; Claire Costello - (C) <ccostello@hilcorp.com>; Amy Peloza <apeloza@hilcorp.com> Subject: RE: [EXTERNAL] RE: NOTICE: Notice of Noncompliance, Class I Permit AK-1I005-C, Milne Point Unit Well MPB-34 Evan / Tim, Please find the attached MIT-IA form from the passing MIT-IA performed on MPB-34 on CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 7/16/25. The MIT-IA was virtually witnessed by the EPA. Based on these results, Hilcorp requests to place MPB-34 back on injection if you can please let us know if EPA is in agreement. As a follow up, is the EPA still wanting to conduct an additional MIT-IA on MPB-34 when on site at MPU in the coming days or does this test cover our annual testing requirement? Thank you, Ryan Thompson Milne / Islands / WNS Well Integrity Engineer 907-564-5005 From: Osborne, Evan <Osborne.Evan@epa.gov> Sent: Friday, July 11, 2025 1:36 PM To: Amy Peloza <apeloza@hilcorp.com>; Mayers, Timothy <Mayers.Timothy@epa.gov> Cc: Ryan Thompson <Ryan.Thompson@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com>; Alaska NS - Milne - Wells Foreman <AlaskaNS-WellsForeman@hilcorp.com>; Alaska NS - Environmental Specialist <mpuenviro@hilcorp.com>; Claire Costello - (C) <ccostello@hilcorp.com> Subject: [EXTERNAL] RE: NOTICE: Notice of Noncompliance, Class I Permit AK-1I005-C, Milne Point Unit Well MPB-34 Received, Amy. This triggers the five-day written notice, too. We will wait to receive a written submission by the 16th that includes: A description of the noncompliance and its cause(s), The period of noncompliance including exact date and times, The anticipated timeframe the noncompliance is expected to continue, Steps taken or planned to reduce, eliminate, and prevent recurrence of the noncompliance. This will naturally affect the upcoming inspection schedule. We look forward to learning more about what’s going on with the well and how EPA can prepare to respond to any forthcoming requests. Caution: This email originated from outside EPA, please exercise additional caution when deciding whether to open attachments or click on provided links. Please contact me if Hilcorp identifies any evidence of increased risk of fluid migration outside the approved injection zone, including anomalous OA pressure trends on nearby wells. Evan From: Amy Peloza <apeloza@hilcorp.com> Sent: Friday, July 11, 2025 1:05 PM To: Osborne, Evan <Osborne.Evan@epa.gov>; Mayers, Timothy <Mayers.Timothy@epa.gov> Cc: Ryan Thompson <Ryan.Thompson@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com>; Alaska NS - Milne - Wells Foreman <AlaskaNS-WellsForeman@hilcorp.com>; mpuenviro@hilcorp.com; Claire Costello - (C) <ccostello@hilcorp.com> Subject: NOTICE: Notice of Noncompliance, Class I Permit AK-1I005-C, Milne Point Unit Well MPB-34 Evan, Tim~ In accordance with Condition I.E.12.a.2 of Class I Permit AK-1I005-C, Milne Point Unit, Well MPB-34 to notify EPA within 24 hours of “a noncompliance with a permit condition.” On July 11, 2025, Hilcorp Alaska, LLC (Hilcorp) Milne Point Unit (MPU) Field Operations was reviewing pressure data for the upcoming EPA MIT-IA and have identified the Inner Annulus (IA) and Outer Annulus (OA) pressures have been tracking each other since August 2024 at <250 psi, see attachments. While no pressure excursion event has occurred, and no anomalous change to injection pressure has occurred, the tracking of annulus pressures warrants diagnostics to identify if pressure communication exists. Hilcorp is investigating the possible anomaly and if a source of communication is identified between the IA & the OA a repair plan will be developed. The well will remain shut in with no injection until diagnostic results are obtained and EPA approval is received to resume injection. In accordance with Condition I.E.12.b, a written report will be submitted within 5 days. Thank you, Amy Peloza Environmental Team Manager Solid & Hazardous Waste / Class I UIC Contaminated Sites / Restoration Programs Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 (907) 777-8348 – office (907) 317-0521 – cell Email: apeloza@hilcorp.com 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 hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that 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 hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that 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:Darci Horner - (C) To:Regg, James B (OGC); Brooks, Phoebe L (OGC); Wallace, Chris D (OGC); DOA AOGCC Prudhoe Bay Cc:Ryan Thompson; Brenden Swensen; Alaska NS - Milne - Wells Foreman; Alaska NS - Milne - Wellsite Supervisors; Derek Weglin; Alaska NS - Northstar - Field Foreman; Alaska NS - Northstar - Operations Leads; Alaska NS - Environmental Specialist; Chuck Wheat; Amy Peloza; Taylor Wellman; Sara Hannegan; Jess Hall; Matthew Ross; Donald Maxon; Roger Allison; Alaska NS - Milne - Field Operator Leads; Barry Bulot Subject:MIT-IAs for Milne Point, Northstar and Point Thomson Class 1 injection wells (MPB-34, MPB-50, NS-10, NS-32 and PTU DW-1) Date:Friday, August 2, 2024 2:51:56 PM Attachments:MIT NSU NS-10 NS-32 7-23-24.xlsx MIT MPU B-34 B-50 7-29-24.xlsx MIT PTU DW-1 7-17-24.xlsx All, Milne Point wells B-34 (PTD # 2161390), and B-50 (PTD # 2042520) successfully passed MIT- IAs on July 29, 2024. Northstar wells NS-10 (PTD # 2001820) and NS-32 (PTD # 2031580) successfully passed MIT- IAs on July 25, 2024. Also, Point Thomson well DW-1 (PTD# 2142060) successfully passed an MIT on July 17, 2024. All wells are EPA class 1 injection wells requiring annual MITs and were witnessed by EPA personnel. Please call myself or Ryan Thompson (907-564-5005) with any questions. Regards, Darci Horner Technologist Office: (907) 777-8406 Cell: (907) 227-3036 Email: dhorner@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, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 0LOQH3RLQW8QLW% 37' Milne Point wells B-34 (PTD # 2161390), Submit to: OOPERATOR: FIELDD // UNITT // PAD: DATE: OPERATORR REP: AOGCCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2161390 Type Inj I Tubing 664 662 659 656 Type Test P Packer TVD 3,980'BBL Pump 3.3 IA 276 3712 3662 3653 Interval O Test psi 3500 BBL Return 3.1 OA 160 160 170 170 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2042520 Type Inj I Tubing 1397 1390 1368 1344 Type Test P Packer TVD 3890 BBL Pump 4.9 IA 28 3703 3645 3619 Interval O Test psi 3500 BBL Return 5.4 OA 140 196 198 198 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 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 EPA Class 1 injection well annual MIT-IA to 3500 psi. AOGCC witness waived by Brian Bixby. Witnessed by EPA's Nick Bruno/James Robinson. Notes: Notes: Notes: Notes: B-50 Notes:EPA Class 1 injection well annual MIT-IA to 3500 psi. AOGCC witness waived by Brian Bixby. Witnessed by EPA's Nick Bruno/James Robinson. Notes: Hilcorp Alaska, LLC Milne Point / MPU / B Matt Ross 07/29/24 Notes: B-34 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMechanicall Integrityy Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Form 10-426 (Revised 01/2017)2024-0729_MIT_MPU_B-34 9 9 9 9 9 9 99 9 9 -5HJJ B-34 EPA Class 1 injection well annual MIT-IA 1 Regg, James B (OGC) From:Brooks, Phoebe L (OGC) Sent:Tuesday, September 12, 2023 2:48 PM To:Darci Horner - (C) Cc:Regg, James B (OGC) Subject:RE: MIT-IAs for Milne Point Class 1 injection wells B-24, B-34 and B-50 as well as Northstar Class 1 wells NS-10 and NS-32 Attachments:MIT MPU B-24 07-20-23 Revised.xlsx; MIT MPU B-34 & B-50 07-19-23 Revised.xlsx Darci, AƩached are revised reports changing the type of injecƟon to “I”, as we include industrial wastewater (instead of water) for Class 1 wells. Please update your copies or let me know if you disagree. Thank you, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation Commission Phone: 907‐793‐1242 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 Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Darci Horner ‐ (C) <dhorner@hilcorp.com> Sent: Tuesday, July 25, 2023 3:53 PM To: Regg, James B (OGC) <jim.regg@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov> Cc: Ryan Thompson <Ryan.Thompson@hilcorp.com>; Brian Glasheen <Brian.Glasheen@hilcorp.com>; Brenden Swensen <Brenden.Swensen@hilcorp.com>; Alaska NS ‐ Milne ‐ Wells Foreman <AlaskaNS‐WellsForeman@hilcorp.com>; Alaska NS ‐ Milne ‐ Wellsite Supervisors <AlaskaNS‐Milne‐WellsiteSupervisors@hilcorp.com>; Derek Weglin <Derek.Weglin@hilcorp.com>; Josh McNeal <jmcneal@hilcorp.com>; Alaska NS ‐ Northstar ‐ Field Foreman <AlaskaNS‐ Northstar‐Field‐Foreman@hilcorp.com>; Alaska NS ‐ Northstar ‐ Operations Leads <AlaskaNS‐Northstar‐ OperationsLeads@hilcorp.com>; Alaska NS ‐ Environmental Specialist <mpuenviro@hilcorp.com>; Chuck Wheat <cwheat@hilcorp.com>; apeloza <apeloza@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com>; Sara Hannegan <shannegan@hilcorp.com>; Jess Hall ‐ (C) <Jess.Hall@hilcorp.com>; Matthew Ross <Matthew.Ross@hilcorp.com>; Donald Maxon <Donnie.Maxon@hilcorp.com> Subject: MIT‐IAs for Milne Point Class 1 injection wells B‐24, B‐34 and B‐50 as well as Northstar Class 1 wells NS‐10 and NS‐32 All, 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. MPU B-34PTD 2161390 2 Milne Point wells B‐24 (PTD # 1960090), B‐34 (PTD # 2161390), and B‐50 (PTD # 2042520) successfully passed MIT‐IAs on July 20, and 19, 2023, respecƟvely. Northstar wells NS‐10 (PTD # 2001820) and NS‐32 (PTD # 2031580) also successfully passed MIT‐IAs on July 23, 2023. Please note that EPA indicated in 2021 the required test pressure for the Northstar wells has been reduced from 3500 psi to 1500 psi. All wells are class 1 injecƟon wells requiring annual MITs. Please call myself or Ryan Thompson (907‐301‐1240) with any quesƟons. Regards, Darci Horner Technologist Alaska Islands Team Office: (907) 777‐8406 Cell: (907) 227‐3036 Email: dhorner@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, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 2161390 Type Inj I Tubing 626 629 616 606 Type Test P Packer TVD 3,980'BBL Pump 2.1 IA 108 3704 3587 3556 Interval O Test psi 3500 BBL Return 2.1 OA 53 54 54 55 Result P Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 2042520 Type Inj I Tubing 476 473 468 463 Type Test P Packer TVD 3890 BBL Pump 5.5 IA -7 3692 3626 3607 Interval O Test psi 3500 BBL Return 4.8 OA 124 137 137 136 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 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 Hilcorp Alaska, LLC Milne Point / MPU / B Roger Allison 07/19/23 Notes: B-34 EPA Class 1 injection well MIT-IA to 3500 psi. AOGCC witness waived by Brian Bixby (EPA witnessed). Notes: Notes: Notes: Notes: B-50 Notes:EPA Class 1 disposal well. Annual MIT. AOGCC witness waived by Brian Bixby (EPA witnessed). Notes: Form 10-426 (Revised 01/2017)2023-0719_MIT_MPU_B-34 J. Regg; 10/12/2023 Nolan Vlahovich Hilcorp Alaska, LLC Geo Tech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 07/28/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230728 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU-23 50133206350000 214093 7/16/2023 HALLIBURTON PPROF BCU-24 50133206390000 214112 7/15/2022 HALLIBURTON PPROF BRU 223-34 50283201880000 223041 7/9/2023 HALLIBURTON RMT3D KBU 23X-6 50133203710000 184109 6/22/2023 HALLIBURTON EPX KBU 23X-6 50133203710000 184109 6/22/2023 HALLIBURTON MFC KGSF 7A 50133205380100 204163 6/18/2023 HALLIBURTON EPX KGSF 7A 50133205380100 204163 6/18/2023 HALLIBURTON MFC KU 21-6RD 50133100900100 201097 6/24/2023 HALLIBURTON EPX KU 21-6RD 50133100900100 201097 6/24/2023 HALLIBURTON MFC MPU B-24 50029226420000 196009 7/24/2023 HALLIBURTON WFL-TMD3D MPU B-34 50029235690000 216139 7/23/2023 HALLIBURTON WFL-TMD3D MPU B-50 50029232400000 204252 7/21/2023 HALLIBURTON WFL-TMD3D MPU E-23 50029225700000 195094 6/17/2023 HALLIBURTON COILFLAG MPU F-17 50029228230000 197196 7/2/2023 HALLIBURTON COILFLAG MPU L-13A 50029223350100 223017 6/21/2023 HALLIBURTON COILFLAG MPU L-39B 50029227860200 223037 6/30/2023 HALLIBURTON COILFLAG MPU L-39B 50029227860200 223037 6/30/2023 HALLIBURTON RBT PBU 11-07 50029206870000 181177 6/28/2023 HALLIBURTON RMT3D SCU 42-05X 50133205610000 206074 6/20/2023 HALLIBURTON EPX SCU 42-05X 50133205610000 206074 6/20/2023 HALLIBURTON MFC SCU 42-05Z 50133206950000 220069 6/16/2023 HALLIBURTON EPX SCU 42-05Z 50133206950000 220069 6/16/2023 HALLIBURTON MFC Please include current contact information if different from above. T37886 T37887 T37888 T37889 T37889 T37890 T37890 T37891 T37891 T37892 T37893 T37894 T37895 T37896 T37897 T37898 T37898 T37899 T37900 T37900 T37901 T37901 MPU B-34 50029235690000 216139 7/23/2023 HALLIBURTON WFL-TMD3D Kayla Junke Digitally signed by Kayla Junke Date: 2023.08.01 10:05:02 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geo Tech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 07/13/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230713-3 Well API # PTD # Log Date Log Company Log Type AOGCC Eset# MP B-34 50029235690000 216139 7/9/2023 READ CALIPER SURVEY Please include current contact information if different from above. T37844 Kayla Junke Digitally signed by Kayla Junke Date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ůů͕ DŝůŶĞWŽŝŶƚǁĞůůƐͲϮϰ;WdηϭϵϲϬϬϵϬͿ͕Ͳϯϰ;WdηϮϭϲϭϯϵϬͿ͕ĂŶĚͲϱϬ;WdηϮϬϰϮϱϮϬͿƐƵĐĐĞƐƐĨƵůůLJƉĂƐƐĞĚD/dͲ/Ɛ ŽŶ:ƵůLJϭϵ͕ϮϬĂŶĚϮϭ͕ϮϬϮϮ͕ƌĞƐƉĞĐƚŝǀĞůLJ͘ EŽƌƚŚƐƚĂƌǁĞůůƐE^ͲϭϬ;WdηϮϬϬϭϴϮϬͿĂŶĚE^ͲϯϮ;WdηϮϬϯϭϱϴϬͿĂůƐŽƐƵĐĐĞƐƐĨƵůůLJƉĂƐƐĞĚD/dͲ/ƐŽŶ:ƵůLJϭϵ͕ϮϬϮϮ͘ WůĞĂƐĞŶŽƚĞƚŚĂƚ WŝŶĚŝĐĂƚĞĚůĂƐƚLJĞĂƌƚŚĞƌĞƋƵŝƌĞĚƚĞƐƚƉƌĞƐƐƵƌĞĨŽƌƚŚĞEŽƌƚŚƐƚĂƌǁĞůůƐŚĂƐďĞĞŶƌĞĚƵĐĞĚĨƌŽŵϯϱϬϬ ƉƐŝƚŽϭϱϬϬƉƐŝ͘ ůůǁĞůůƐĂƌĞĐůĂƐƐϭŝŶũĞĐƚŝŽŶǁĞůůƐƌĞƋƵŝƌŝŶŐĂŶŶƵĂůD/dƐ͘ WůĞĂƐĞĐĂůůŵLJƐĞůĨŽƌ:ĞƌŝŵŝĂŚ'ĂůůŽǁĂLJ;ϵϬϳͲϱϲϰͲϱϬϬϱͿǁŝƚŚĂŶLJƋƵĞƐƚŝŽŶƐ͘ ZĞŐĂƌĚƐ͕ DarciHorner Technologist Office:(907)777Ǧ8406 Cell:(907)227Ǧ3036 Email:dhorner@hilcorp.com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ubmit to: OOPERATOR: FIEL DD // UNITT // PAD: DATE: OPERATORR REP: AOGCCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2161390 Type Inj I Tubing 730 733 721 713 Type Test P Packer TVD 3,980'BBL Pump 9.3 IA 96 3541 3462 3444 Interval O Test psi 3500 BBL Return 3.0 OA 159 156 157 157 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 MMec hanicall Integrityy Tes t jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: EPA Class 1 injection well MIT-IA to 3500 psi. (well shut in for thermal stability). Witnessed virtually by Tim Mayers (EPA). Notes: Hilcorp Alaska, LLC Milne Point / MPU / B Derek Weglin 07/20/22 Notes: Notes: Notes: Notes: B-34 Form 10-426 (Revised 01/2017)2022-0720_MIT_MPU_B-34 9 9 9 9 9 9 9 -5HJJ EPA Class 1 injection well David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt and return one copy of this transmittal. Received By: Date: Hilcorp North Slope, LLC Date: 08/03/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL MPU B-34 (PTD 216-139) FTP Folder Contents: Log Print Files and LAS Data Files: Please include current contact information if different from above. Received By: 08/03/2021 37' (6HW By Abby Bell at 5:17 pm, Aug 03, 2021 Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 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: 12/04/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU B-34 (PTD 216-139) TMD3D Water Flow Log 08/06/2020 Please include current contact information if different from above. Received by the AOGCC 12/04/2020 PTD: 2161390 E-Set: 34358 Abby Bell 12/09/2020 Pr D 2lwlo Wallace, Chris D (CED) From: Deborah Heebner <dheebner@hilcorp.com> Sent: Saturday, January 11, 2020 10:49 AM To: Wallace, Chris D (CED); Bentley, Marc H (DEC) Cc: Wyatt Rivard; Stan Porhola; Amy Peloza; Matthew Linder; Josh McNeal; Alaska NS - Wells Foreman; Darci Horner - (C) Subject: FW: Shut In Class I Well MPB-34 - Requesting EPA Approval - Return to Injection Attachments: B-34 MIT -IA 1-11-2020 Not Flowing.pdf; MIT MPU B-34 1-11-2020.xlsx; HAK to EPA MPB-34 Annual MIT Report 8-23-19.pdf, WSR-7in casing packoff test.xlsx Chris/Marc, As indicated in our initial email to you from Darci Horner on 1/9/2020, Hilcorp shut-in Class I G&I injector MPB-34 (PTD # 216139) to perform diagnostic testing to ensure we did NOT have a tubing integrity issue following two IA bleeds on January 5 and January 6. The two bleeds were associated with large spikes in injection temperature. We have completed the diagnostic testing listed below and the results are attached: Record pressures of tubing hanger and casing hanger test voids and then conduct void test MIT -IA to 3,500 psi The passing MIT -IA confirms tubing, packer and production casing integrity and is comparable to the attached MITIA witnessed by EPA on 7/14/2019. Pressures of tubing hanger and casing hanger test voids were recorded and a void test conducted on 1/9/2020, which also confirmed integrity of wellhead seals. Hilcorp believes there are no further integrity concerns on this well and is requesting EPA approval to return the well to injection. Let us know if you have any questions. Thank -You! Deborah Heebner I North Slope Environmental Specialist PO Box 2440271 Anchorage, AK 99524-4027 dheebner0hilcorp com 907-670-3382 office 1907-782-7431 mobile www.hilcorp.com From: Deborah Heebner Sent: Saturday, January 11, 202010:34 AM To: Ryan Gross (Gross.Ryan@epa.gov) <Gross.Ryan@epa.gov>; Evan Osborne (osborne.evan@epa.gov) <osborne.eva n @e pa.gov> Cc: Wyatt Rivard <wrivard@hilcorp.com>; Stan Porhola <sporhola@hilcorp.com>; Amy Peloza <apeloza@hilcorp.com>; Alaska NS - Wells Foreman<AlaskaNS-WellsForeman@hilcorp.com>; Matthew Linder <mlinder@hilcorp.com>; Josh McNeal <jmcneal@hilcorp.com>; 'Mayers.Timothy@epa.gov' <Mayers.Timothy@epa.gov> Subject: Shut In Class I Well MPB-34 - Requesting EPA Approval - Return to Injection Ryan, As indicated in our initial email to you, Hilcorp shut-in Class I G&I injector MPB-34 (PTD # 216139) to perform diagnostic testing to ensure we did NOT have a tubing integrity issue following two IA bleeds on January 5 and January 6. The two bleeds were associated with large spikes in injection temperature. We have completed the diagnostic testing listed below and the results are attached: Record pressures of tubing hanger and casing hanger test voids and then conduct void test MIT -IA to 3,500 psi A passing MIT -IA was conducted on MPB-34 (PTD # 216139) to 3500 psi today, 1/11/19 after the well had been shut-in for 2 days. A copy of the test form and pressure chart are included for reference. The passing MIT -IA confirms tubing, packer and production casing integrity and is comparable to the attached MITIA witnessed by EPA on 7/14/2019. Pressures of tubing hanger and casing hanger test voids were recorded and a void test conducted on 1/9/2020, which also confirmed integrity of wellhead seals. Hilcorp believes there are no further integrity concerns on this well and requests EPA approval to return the well to injection. Let us know if you have questions. Thank -You. Deborah Heebner I North Slope Environmental Specialist PO Box 2440271 Anchorage, AK 99524-4027 dheebnerc@hilcorp.com 907-670-3382 office 1907-782-7431 mobile www.hilcorp.com From: Amy Peloza Sent: Thursday, January 09, 2020 1:37 PM To: 'Gross, Ryan (Gross.Ryan @epa.Eov)' <Gross.Ryan (r@epa.eov>; 'Evan Osborne (osborne.evan@epa.zov)' <osborne.evan@epa.eov> Cc: Alaska NS - Environmental Specialist<AlaskaNS- EnvironmentalSpecialist@hilcorp com>; Wyatt Rivard <wrivard@hilcorp.com>; Stan Porhola <sporhola@hilcorp.com>; 'Mayers, Timothy' <Mavers.Timothv eoa.Eov> Subject: RE: INFO: Shut In Class I Well MPB-34; potential integrity issues Please also find attached a TIO plot for reference. Thanks, Amy Peloza Waste Environmental Specialist 1111-lilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 (907) 777-8348 — office (907) 317-0521 — cell Email: apeloza(&hilcorp.com From: Amy Peloza Sent: Thursday, January 9, 20201:29 PM To: Gross, Ryan (Gross.Ryan@epa.eov) <Gross.Rvan@epa.eov>; Evan Osborne (osborne.evan@epa.aov) <osborne.eva n @e pa.gov> Cc: Alaska NS - Environmental Specialist <AlaskaNS-Environ menta lSpecialist@hilcorp com>; Darci Horner - (C) <dhorner@hilcorp.com>; Wyatt Rivard <wrivard@hilcorp.com>; Stan Porhola <sporhola@hilcorp.com>; Matthew Linder <mlinder@hilcorp.com>;'Mayers, Timothy' <Mavers.Timothv epa.¢ov> Subject: INFO: Shut In Class I Well MPB-34; potential integrity issues Ryan, Hilcorp has shut-in Class I G&I injector MPB-34 (PTD # 216139) following two IA bleeds in the last few days. The bleeds were associated with large spikes in injection temperature. MPB-34 has a history of high IA pressure sensitivity to thermal changes therefore spikes in IA pressure are normal. However we have bled the IA twice in the last few days indicating a possible tubing integrity issue that warrants further diagnostic testing. The well will be shut-in until integrity can be confirmed or restored. Plan Forward Record pressures of tubing hanger and casing hanger test voids and then conduct void test MIT -IA to 3,500 psi If diagnostics are successful we will provide the results to EPA and request EPA approval prior to any return to injection. Let us know if you have questions. Thanks, Amy Peloza Waste Environmental Specialist 11Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 (907) 777-8348 — office (907) 317-0521 — cell Email: aoeloza(ftilcoro.com 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. AAP&C & 34 Regg, James B (CED) Rb Z!6(3rj� From: Darci Horner - (C) <dhorner@hilcorp.com> Sent: Wednesday, July 17, 2019 10:48 AM�' 7(7✓`i f J -';tTo: Regg, James B (CED); Brooks, Phoebe L (CED); DOA AOGCC Prudhoe Bay; Wallace, Chris D (CED) Cc: Wyatt Rivard; Nick Frazier - (C) Subject: Milne Point EPA Class 1 Disposal Well MITs 2019 Attachments: MIT MPU B-34 7-14-19.xlsx, MIT MPU B-24 7-13-19.xisx All, Milne Point Class 1 disposal wells B-24 (PTD # 1960090) and B-34 (PTD # 2161390) successfully passed annual EPA witnessed MIT-IAs on July 13 and 14, 2019, respectively. Please call myself or Wyatt Rivard (777-8547) with any questions. Regards, Darci Horner (Northern Solutions) Technologist Hilcorp Alaska, LLC 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Office: (907) 777-8406 Cell: (907) 227-3036 Email: dhorner@hilcorp.com 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 a -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. 1. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submitto. iim.reaa0alaska.aiw AOGCOInspectorsillialaska.aw choebe.br0oksdalaska9oY OPERATOR: Hilcorp Alaska, LLC FIELD I UNIT I PAD: Milne Point/MPU /B DATE: 07/14/19 OPERATOR REP: Nick F2aier AOGCC REP: Adam Ead Waived witness chns wallaceglIalaska.it Well B34 INTERVAL Codee Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. 4+Four Year Cycle F=Fail PTD 2161390 A Type m; W Tubing 1 517 1 541 527 518 Type Test P Packer WD 3,g80• BBL Pump 2.4 - IA 4 3529 - 3410 — 3381 Interval 0 Test psi 3500 BBL Ratum 2.0 OA 136 137 137 138 Result P Notes EPA Class 1 injection well MIT -IA to 3500 psi. Well Pressures: Pretest Initial 15 Min, 30 Min. 45 Min. 60 Min. PTD Typa Int Tubing Typa Test Packer WD BE Pump IA Interval Test psi BBL Retum OA Result Motes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Int Tubing Type Test Packer WD BEPumP1 I IA I Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Mtn. 45 Min. W Min. PTD Type: Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Norex: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min, 60 Min. PTD Type lnj Tubing Type Test Packer WD BBL Pump IA In(eNal Test psi BBL Return OA Result Nsds: Well Pressures: Pretest Initial 15 Min, 30 Min. 45 Min. 60 Min. PTD Type Int Tubing Typa Test Packer TVD BBLPump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type lnl Tubing Type Test Packer ND BB P1 I IA I Interval Test psi BBL Return OA Result Nobs: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Mtn. PTD Typelnj Tubing Type Test Packer WD 88L Pump IA Interval Test psi BBL Return OA Result Notes: TYPE INJ COEaa TYPETESTCories INTERVAL Codee satiri Coles W=Water P=Feature Test 1=arlul1. P:Pan G - Gee O= Other (drearier, in NNes) 4+Four Year Cycle F=Fail S:slurry V= Required by Variance 1=Inconclusive I = Indwilree Wasnwaler 0 =Other (deserter In nOle9) N = Nat Inlay inp Form 10426 (Revised 01/2017) MIT MPU 8:9 7.14-19 Mr. Edward J. Kowalski RECEIVED Director, Office of Compliance and Enforcement U.S. Environmental Protection Agency MAR 2 % 2019 1200 Sixth Avenue Seattle, WA 98101 d64OGCC Mr. Chris Wallace Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501-3192 Mr. Marc Bentley Department of Environmental Conservation 555 Cordova St. Anchorage, AK 99501 RE: Mechanical Integrity Test Notifications Northstar Class 1 Iniection Wells, UIC Permit AK -1I002 -B, General Wastewater, Permit No. 2016DBOOI-0020 Milne Point Iniection Well, UIC Permit AK -1I005 -B, General Wastewater, Permit No. 2016DB00I -0001 Libertv Class 1 Iniection Well. UIC Permit AK -1I013 -A. General Wastewater, Permit No. 2016DB00I-0025 Dear Sirs: Hilcorp Alaska, LLC (Hilcorp) respectfully submits the following notifications: 1) the annual Mechanical Integrity Test (MIT) and fluid movement tests that are required every two years at the Northstar NS10 and NS32, Class 1 wells to meet the annual permit requirement in UIC Permit AK -1I002 -B; 2) the annual MIT and fluid movement logs that are required every three years at the Milne Point Class 1 wells, MPB-50, MPB-24 and MPB-34 to meet the permit requirement in UIC Permit AK -1I005-13; 3) the MIT and fluid movement test that is required at the Liberty Class 1 well to meet the permit requirement in UIC Permit AK -1I013 -A. ZIP -.3(i Post office Box 244027 Anchorage, AK 995249524 3800 Centerpoint Or Suite 1400 Hileorp Alaska, LLC Anchorage, AK 99503 Phone: 907/777-8300 Fax: 907/777-8560 March 18, 2019 Mr. Edward J. Kowalski RECEIVED Director, Office of Compliance and Enforcement U.S. Environmental Protection Agency MAR 2 % 2019 1200 Sixth Avenue Seattle, WA 98101 d64OGCC Mr. Chris Wallace Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501-3192 Mr. Marc Bentley Department of Environmental Conservation 555 Cordova St. Anchorage, AK 99501 RE: Mechanical Integrity Test Notifications Northstar Class 1 Iniection Wells, UIC Permit AK -1I002 -B, General Wastewater, Permit No. 2016DBOOI-0020 Milne Point Iniection Well, UIC Permit AK -1I005 -B, General Wastewater, Permit No. 2016DB00I -0001 Libertv Class 1 Iniection Well. UIC Permit AK -1I013 -A. General Wastewater, Permit No. 2016DB00I-0025 Dear Sirs: Hilcorp Alaska, LLC (Hilcorp) respectfully submits the following notifications: 1) the annual Mechanical Integrity Test (MIT) and fluid movement tests that are required every two years at the Northstar NS10 and NS32, Class 1 wells to meet the annual permit requirement in UIC Permit AK -1I002 -B; 2) the annual MIT and fluid movement logs that are required every three years at the Milne Point Class 1 wells, MPB-50, MPB-24 and MPB-34 to meet the permit requirement in UIC Permit AK -1I005-13; 3) the MIT and fluid movement test that is required at the Liberty Class 1 well to meet the permit requirement in UIC Permit AK -1I013 -A. Mechanical Integrity Test Notification March 18, 2019 Page 2 of 2 By this letter Hilcorp is providing the written notification required by the aforementioned permits. In addition, Hilcorp staff will be coordinating the timeframes for these MITs with Mr. Ryan Gross of the Environmental Protection Agency (EPA) to maximize efficiencies associated with the travel arrangements of the EPA inspector, so that multiple tests of Class 1 wells can be witnessed in one trip to the North Slope. A summary of the proposed annual testing is presented in the attached table. The fluid movement test procedures that require EPA approval will be sent under separate cover or by email. If you have any questions or require additional information please call me at 907-782-7431, or via e-mail at dheebner@hilcorp.com. Sincerely, Deborah Heebner North Slope Environmental Specialist HILCORP ALASKA, LLC Attachment cc: Ryan Gross, EPA Region 10 U.S. Environmental Protection Agency 1200 Sixth Avenue Seattle, WA 98101 Evan Osborne, EPA Region 10 U.S. Environmental Protection Agency 1200 Sixth Avenue Seattle, WA 98101 Kyle Monkelien, BSEE Bureau of Safety And Environmental Enforcement Alaska OCS Region 3801 Centerpoint Drive Ste 500 Anchorage, AK 99503 Jason Seltisch Proposed Schedule for 2019 Mechanical Integrity Testing Class I Well MIT Deadline Proposed MIT test Flexibility in Fluid Movement (s) (May be extended date test date? Logs Planned up to 3 months after MIT? with Director approval) Milne Point By August 9, Approximately July Coordinate with No Fluid movement MPB-24 2019 15 -20, 2019. Northstar test logs are planned as date. they are required for MPB-24 every three years. Previously done on 7/9/2017. Milne Point By August 8, Approximately July Coordinate with Fluid movement MPB-34 2019 15 -20, 2019. Northstar test logs are planned as date. they are required for MPB-34 every three years. Previously done on 4/9/2017. Milne Point By August 9, Approximately July Coordinate with No Fluid movement MPB-50 2019 15 -20, 2019. Northstar test logs are planned as date. they are required for MPB-50 every three years. Previously done on 7/7/2017. Northstar By August 12, Approximately July Coordinate with No Fluid movement NS10 2019 11 -15, 2019. Milne test date. logs are planned as they are required at NSI 0 every two years. Previously done on 8/13/2018. Northstar By August 13, Approximately July Coordinate with No Fluid,movement NS32 2019 11 -15, 2019 Milne test date. logs are planned as they are required at NS32 every two years. Previously done on 8/14/2018. Liberty CRI N/A The Liberty CRI well All logs required to Well will not be drilled in complete the well 2019. would be scheduled with the MIT. I(0- / 39 i Hilcorp Alaska,LLC Post Office Box 244027 Anchorage,AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage,AK 99503 Phone: 907/777-8547 June 5, 2018 RECEIVED Mr. Guy Schwartz Alaska Oil and Gas Conservation Commission JUN 06 2018 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 AOGCC Re: Conductor Annulus Corrosion Inhibitor Treatments 4/20/18-5/12/18 Dear Mr. Schwartz, Enclosed please find multiple copies of a spreadsheet with a list of wells that were treated with corrosion inhibiting casing filler in the surface casing by conductor annulus. The heavier than water "grease-like" filler displaces water to prevent external casing corrosion that could result in a surface casing leak. The attached spreadsheets include the well names, field, PTD and API numbers, treatment volumes and treatment dates. This treatment campaign represents primarily new Milne Point HAK drill wells along with two Northstar wells which previously had excavations and external surface casing leak repairs. If you have any additional questions, please contact me at 777-8547 or wrivard@hilcorp.com. Sincerely, ��. %mow JUN 0 7'2018 Wyatt Rivard Well Integrity Engineer Hilcorp Alaska, LLC • • (n rn CD U) a) a) a) a) a) a) a) a) m a) (1) a) a) (7) $7) C C CCCCCCCCCCC J J J J J J J J J J J J J Q C CC O C C C CCCCC CCC C4C, OL L LU U a) a) a) a) a) a) a) a) a) a) a) a) a) Q- CC C C C C CC C C C C L a) a) a) a) a) (1) a) a) (1) (1) a) a) a) O O E EEEEEEEEEEEE i LL a) a) a) a) a) a) m a) a) a) a) a) a) D U U U U U U U U U U U U U -0 - Q Q Q Q Q Q Q Q Q Q Q < U U o Q Q U Q _� UU) O o O 0 0 0 L L0 Ln o Ln Ln Ln N N p L p p ' ' ' N _ O C ZC CO CO CO CO CO CO CO CO CO Co CO CO CO CO Co O 5 m N N N N N N N N N N N N O N N 8 .5mU CO 0 O X- - NCNINN M M M M N N a) N N NNNN N NNNNN 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N- Ln M V" 0) Cr) N- CO 0 a) N Cr) Cl N Ln Ln CO M 1.0 Ln Cr) N O CO Ln N O - 0 e- x- 0 N C I- CO N CO CO CO CO Ln Ln CO Ln Ln Lf) N- N N C e- - - - - - r - 0 0 N N N N N NNN NNNN NNN O U 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 C 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 O 0 0 0 0 0 0 0 0 0 0 (00 0 0 0 () 0 0 _0 0 0 0 0 0 0 0 0 0 0 0 0 CO CO N- 0N- CO COO N- LMf) CO LL( d LC) CO CO CO iL Lf) l() Ln L!) 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HILCORP ALASKA LLC B-34 FROM: Jeff Jones MILNE PT UNIT B-34 Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry NON-CONFIDENTIAL Comm Well Name MILNE PT UNIT B-34 API Well Number 50-029-23569-00-00 Inspector Name: Jeff Jones Permit Number: 216-139-0 Inspection Date: 10/3/2017 Insp Num: mitJJ171025081836 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well B-34 Type Inj N TVD 3979 - Tubing 249 - 250 - 249 - 249 PTD 2161390 Type Test SPT Test psi 1500 IA 0 3630 - 3536 3515 - BBL Pumped: 3.5 BBL Returned: 2 ' OA 74 - 75 - 76 75 - Interval OTHER IP/F P ✓' Notes: Class 1 permit#AK-11005-B. 1 well inspected,no exceptions noted. 5. i °,11W(5 Wednesday,October 25,2017 Page 1 of 1 • • o r O I I co co co '�cb CV C 0„, o) N I I I W p a y �I aI o 0 0 0 } } } E N W N o) U o o �I =I �I 2 N 8 c 5 U U U U U a) Q C7 L T O �1 0l U U U ,_ c -8 h u) CV I NI MI v rn Q .c o 'm I m I m a m a m O M a W Z - o ao aE dE aE 00 r -c ° — 2— M— 2 a) g Sm g S2 _ U a La IUEl I I1—I II EI -I Z m °2-n E- o o r-U O o o c°J 0 c°)o U o I U U J a •—N -N —N — N N d U) 2= 2 = 2= 2= 2= W a t_ t. a a �_Q �_Q �_ Q �_Q �_ Q J N LE N u:c) CO LLc) LLc> LLD C Q j c JI o Lit o JI w c JI N c JI m o £ C . °LL(D OLL V OL- OLL>5 °LL '0 m O } ' o a.) o c�1 3 a0i>1 3 a°)�1 3 (�° ° N ix QJ WMV) WMU) WMA WMA WMA N 0 0 0/� Y N 3 n n n n n 40 Q.. s2 To co Om y U 0 0 0 0 o E (/) E 2) 0 5N N N N NLU CO 7 0 Is- U) Z ui N IX < CV N N N � 0 co Il o _ - N LU o o) U) N V E cl) 71 ° E 2 0 J m Z w a) N w Q a) N o o 0) a c d m a E J a CO2 U U O U c AA d 1.1. a) o W 2N O o E N VN U �/\ � o \J } ✓ E ) J �� J E bp ICC oo tia c? n .+ 57ii N O G m N@ O V) M Z � I c c E Z:',.. 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O F) C C U I') dCO Q 610 iii o o Q o. a M I v 1 0 11 •ebra Oudean Hilcorp AlaskaC AK_GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8337 Hilem-p Alaska,Ltd: Fax: 907 777-8510 E-mail: doudean@hilcorp.com DATA LOGGED /2011. DATE 12/4/2017 .K'B M. BENDER To: AOGCC Makana Bender 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL MPU B-34 ' � 1 CD: I MPB 34 CBL LAS Files 12/4/2017 2:24 PM File folder MPB-34 WFL 12/4/2017 2:20 PM File folder 2 8 8 4 3 Prints: CCL / GR / Temp / Press / RST Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By:MALLL4Z44_,‘../) � Date: • • Guhl, Meredith D (DOA) From: Guhl, Meredith D (DOA) Sent: Tuesday, November 28, 2017 8:11 AM To: 'Debra Oudean' Cc: 'Cody Dinger; Schwartz, Guy L (DOA) Subject: RE: MPU B-34, PTD 216-139, CBL LAS files and RST-WFT log and digital data Debra, Following up on this request. I haven't received the data yet. Can you please advise when it will be sent? 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 Guhl at 907-793-1235 or meredith.guhl@alaska.gov. From:Guhl, Meredith D (DOA) Sent: Friday, November 3, 2017 10:07 AM To: 'Debra Oudean' <doudean@hilcorp.com> Cc: 'Cody Dinger' <cdinger@hilcorp.com>; Schwartz,Guy L(DOA) <guy.schwartz@alaska.gov> Subject: MPU B-34, PTD 216-139,CBL LAS files and RST-WFT log and digital data Hello Debra, I'm completing the compliance review for Milne Point Unit B-34, PTD 216-139, completed May 10,2017. During Guy Schwartz's review of the 10-407 packet, he noted that three CBLs and a RST-WFT log were run on this well, and added it to the 10-407 form. I have the CD containing the PDF files for the CBLs, but a LAS file for each log is also required. A RST-WFT paper log and associated digital data is also required for the well to be in compliance. Please send all required data to my attention at the AOGCC. Please send it in a separate envelope. Please supply the required data by November 17, 2017. If you have any questions, please contact me. 1 • • 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 Guhl at 907-793-1235 or meredith.guhl@alaska.gov. 2 • Wallace, Chris D (DOA) From: Wyatt Rivard <wrivard@hilcorp.com> Sent: Friday, September 29, 2017 5:32 PM To: Wallace, Chris D (DOA); Bentley, Marc H (DEC) Cc: Deborah Heebner Subject: Class 1 G&I injector MPB-34 (PTD#216139) SI Following Increased Sensitivity to Injection Temp Changes Attachments: MPB-34 TIO.XLSX; MPB-34 Injection Temp and IAP.JPG Chris/Marc, Hilcorp has shut-in Class 1 G&I injector MPB-34(PTD#216139)following several IA bleeds over the last month.The bleeds were associated with large spikes in injection temperature.We are in communication with the EPA but also wanted to let you know our observations and plan forward.A TIO plot is attached for reference. MPB-34 routinely swaps between G&I and Produced Water injection and over the course of these swaps can see 40+ degF changes in injection temperature.These changes result in large swings in inner annulus pressure.A short higher resolution 3 day plot is also attached which shows this sensitivity to injection temp changes. For example,the well can easily go from injecting 90 degF G&I fluids with IA on a vacuum to injecting produced water at 130 degF with an IA pressure of 800 psi. When the injection stream is swapped back to G&I,the IA goes back to a vacuum and so on. In September, some of the produced water injection temperature spikes reached new highs since the well began injecting and the corresponding high IA pressures were bled back to ensure no exceedance of the 1500 psi IA limit. These were the first bleeds required since the well began injection in June 2017. Recently,the IA bleeds appear to be required more frequently and at temperature spikes that do not represent new record highs.With the apparent increase in IA sensitivity to thermal effects,the decision was made to shut-in the well to allow for diagnostics and ensure that there is no other integrity issues being masked by temperature and pressure fluctuations.The well will remain shut- in until additional diagnostics or remediations are performed. Plan Forward—Operations - Record pressures of tubing hanger and casing hanger test voids and then conduct void test - MIT-IA to 3500 psi (Provide AOGCC and EPA 24 hr notice for option to witness) Thank You, Wyatt Rivard I Well Integrity Engineer I Hilcorp Alaska,LLC 0: (907) 777-8547 I C: (509)670-8001 I wrivard@hilcorp.com 3800 Centerpoint Drive,Suite 1400 I Anchorage,AK 99503 1 ` • • M.PO (3- 34 . Pm ZI(a I31Gr Regg, James B (DOA) From: Wyatt Rivard <wrivard@hilcorp.com> Sent: Thursday, May 4, 2017 4:52 PM 2ft To: Regg,James B (DOA) Cc: Brooks, Phoebe L (DOA) Subject: RE: MIT of MPB-33 (PTD#2161640) on 05/1/17 Attachments: MPB-33 Schematic 4-03-17.doc; MPU B-33 - Definitive Survey.pdf Jim, Sorry about the mixed up attachments. I've double checked the attached dev survey and schematic for B-33. If they still aren't going through properly, I will try a different format. Thanks, • Wyatt Rivard I Well Integrity Engineer Alaska, 11.0 0: (907) 777-8547 I C: 1509)670-8001 wrivard@hilcorp.com 3800 CenterpointDrive,Suite 1100 I Anchorage,AK 99503 From: Regg,James B (DOA) [mailto:jim.regg@alaska.gov] Sent:Thursday, May 04, 2017 1:00 PM To: Wyatt Rivard <wrivard@hilcorp.com> Cc: Brooks, Phoebe L(DOA)<phoebe.brooks@alaska.gov> Subject: RE: MIT of MPB-33 (PTD#2161640) on 05/1/17 I asked because the attachments named B-33 were for B-34. If you have the well schematic and directional survey for B- 33 please send. Thank you. From: Wyatt Rivard [mailto:wrivard@hilcorp.com] Sent:Thursday, May 4, 2017 12:55 PM To: Regg,James B (DOA) <iim.regg@alaska.gov> Cc: Brooks, Phoebe L(DOA) <phoebe.brooks@alaska.gov> Subject: RE: MIT of MPB-33 (PTD#2161640) on 05/1/17 Jim, By coincidence we had separate MIT-lAs on two newly drilled B-Pad injectors within a few weeks of each other. This MIT-IA/email was conducted on produced water injector MPB-33 (PTD# 2161640) on 5/1/17. We also had an EPA witnessed MIT-IA on the Class 1 UIC disposal well MPB-34 (PTD#2161390) on 4/10/17 (sent on 5/2/17). I've attached both MITs again for reference. Please let me know if there is any additional information that I can provide. Thank You, Wyatt Rivard Well Integrity Engineer 11 lcorp Alaska, LEC 0: (907) 777-8547 I C: (509)670-8001 I wrivard@hilcorp.com :3800 Centerpoint Drive,Suite 1100 I Anchorage,AK 99503 1 » •���N� • _ From: Regg,James B (DOA) [nnaihojim.reRg@akaska.gov] Sent:Thursday, May 04, 2017 12:06 PM To:Wyatt Rivard <wrivardhilcorp.com> Cc: Brooks, Phoebe L(DOA) <phoebe.brooksalaska.gov> Subject: RE: MIT of MPB-33 (PTD#2161640) on 05/1/17 Please confirm that the well should be MPU B-34(PTO I161390). - -- - - - - 1 From: Wyatt Rivard [nmai|to:vvrivard@hi|corp.00m] Sent:Wednesday, May 3, 2017 7:55 AM To:Wallace, Chris D (DOA) <chris.wallace@alaska.gov>; Brooks, Phoebe L(DOA)<phoebe.brooks@alaska.gov>; Regg, James B (DOA)<iimsegg@alaska.gov>; DOA AOGCC Prudhoe Bay<doa.aogcc.prudhoe.bav@alaska.gov> Cc:Alaska NS- Milne 'VVeUsiteSupervisors<A|askaNS-K4i|ne'VVeUsiteSupervison@hi|corp.com>; Stan Porhola <sporho|o@hi|corpzum> Subject: MIT ofMPB-33 (PTD#I161640) on0S/1/17 All, Milne Point water injector MPB-33 (PTD#2161640) had a passing initial AOGCC witnessed MIT-IA on 5/1/17. Please see attached MIT form for reference. Deviation survey and wellbore schematic are also attached as this is a new drill well. Thank You, Wyatt Rivard | Well Integrity Engineer |8i\corpA|auka' i[C 0: (907) 777'8547C: (S09)67O'O00livvrh/ordVDbilourp.conn 38OD[cnterpuintDrive,Suite 140OIAnchorage,&K99SO3 • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: jim.reggt6lalaska.aov AOGCC.Inspectorsi alaska.aov phoebe.brooksnalaska.aov chris.wallaceepalaska.00v OPERATOR: Hilcorp,Alaska LLC i"-- eq' Ski 1 t7 FIELD/UNIT/PAD: Milne Point Unit,B pad 1 DATE: 04/10/17 OPERATOR REP: James Fagnant AOGCC REP: Well MPU B-34 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 216-139' Type IN N Tubing 178 177 178 178 NA NA Type Test P Packer TVD 3978 - BBL Pump 3.4 - IA 0 3550 - 3434 - 3410 - NA NA Interval I Test psi 3500 " BBL Retum 3.4 - OA 4 4 4 4 NA NA Result P t/ Notes: Class 1 DW injects under permit AK-11005-B.Well SI during MIT-IA.Witnessed by EPA Jason Seltisch.Waived by AOGCC Bob Noble. 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 Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type lnj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type IN Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: 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 Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type IN Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type lnj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: 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 Retum OA Result Notes: TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W=Water P=Pressure Test I=Initial Test P=Pass G=Gas 0=Other(describe in Notes) 4=Four Year Cycle F=Fail S=Slurry V=Required by Variance I=Inconclusive I=Industrial Wastewater 0=Other(describe in notes) N=Not Injecting Form 10-426(Revised 01/2017) MIT MPU 6-34 4-10-17 • • Milne Point Unit Ili SCHEMATIC Well: MPU B-34 Last Completed: 2/13/2017 flacon):�la.ka.1,1kPTD: 216-139 KBEIev.:50.2'/GLEIev.:23.7' TREE &WELLHEAD RKB—THF:22.98' Innovation) Tree CIW 4-1/16"5M : N' Seaboard Weir,3 spools,w/11"x 5M top flange Wellhead J 4"CIW"H"BPV Profile 20" ' . e -5/8 r OPEN HOLE/CEMENT DETAIL '.` Top Job#2: 4,, 93'MD 42" 50 bbls(10 Yards Pilecrete dumped down backside) 9-5/8" Cmt w/1,965 sx Class C 15.6 ppg in a 12-1/4"Hole d35/g, 9-5/8" Top Job#1:Cmt w/235 bbl Perm L 10.5 ppg from 505'MD A Top Job#1: 9-5/8" Top Job#2:Cmt w/32 bbl Perm L 10.6 ppg from 93'MD 505'MD 7" Cmt w/345 sx Type 111.7 ppg;130 sx Type 115.8 ppg in 8-1/2" 9-5/8' 6 se4-/" Cmt w/25 bbl Type I-II in 6-1/8" i 9-5/8"CBL:2/03/17 Cement to Surface CASING DETAIL 0" Size Type Wt/Grade/Conn Drift ID Top Btm BPF 4-1/z" d 4 20"x34" Conductor(Insulated) 78.6/A-53/Weld N/A Surface 106.5' N/A Tubing 9-5/8" Surface 40/L-80/DWC/C 8.679" Surface 2,672' 0.0758 " 7" Production 26/L-80/DWC/C 6.151" Surface 5,064' 0.0382 v4-1/2" Liner 13.5/L-80/Vam HTTC 3.795" 4,880' 5,369' 0.0149 TUBING DETAIL "V; ; 4-1/2" Tubing 13.5/L-80/GeoConn 3.795" Surf 4,889' 0.0149 WELL INCLINATION DETAIL w KOP @ 300' MD Max Hole Angle=42.7 deg at 1,820' MD Hole angle through perforated interval: 17 deg JEWELRY DETAIL 11 No Depth Item 1 23' Tubing Hanger,4-1/2"TC-Il top&4-1/2" GeoConn btm 2 4,742' 4-1/2 "R" profile Packing Bore=3.688"ID " 2 3 4,879' 4-1/2" Baker Seal Assembly(Ported),5,72" No-Go Min ID=3.688"-- —� 4 4,880' 4-1/2" Liner Top it 5 4,895' 7"x 5" Baker ZXP Liner Top Packer ✓ s 6 4,903' 7"X 5" Baker Flex-Lock Liner Hanger 456 PERFORATION DETAIL Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status ' Ugnu MD 5,204' 5,244' 4,274' 4,312' 40' 4/03/17 Open lid 7" 3-1/8"6 spf Owen HERO(21.5 gm)Good Hole charges(0.52"EH,24.9"Pen) , 7'CBL 2/08/17 Cement to 2,660' ' GENERAL WELL INFO , €,.t API:50 029 23569 00 00 1, ,- Drilled and Cased by Innovation#1 2/13/2017 Perforated Ugnu MD—4/03/2017 t Tag w/2"bailer ,a4W @ 5,246'4/04/17 i , — Ugnu MD 4-t/2 L:' 4-1/2"CBL:2/12/17 Cement to 4,880' TD=5,370(MD)/TD=4,432'(TVD) PBTD=5,285'(MD)/PBTD=4,351'(TVD) Revised by:CJD 4/27/17 • , it Hilcorp Alaska, LLC Milne Point M Pt B Pad MPUB-34 (F Z-ic= l319 50-029-23569-00-00 E l pe ry iii h 111 Definitive Survey Report 10 February, 2017 II u HAL /�'9/° G1 ,,, ,8' , i .. .. U .'''' -....- .. Sperry rilfin, • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-34 Project: Milne Point TVD Reference: Actual:@ 50.60usft Site: M Pt B Pad MD Reference: Actual:@ 50.60usft Well: MPU B-34 North Reference: True Wellbore: MPU B-34 Survey Calculation Method: Minimum Curvature Design: MPU 8-34 Database: Sperry EDM-NORTH US+CANADA Project Milne Point,ACT,MILNE POINT 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 04 Using geodetic scale factor Well MPU 8-34 Well Position +NI-S 0.00 usft Northing: 6,023,979.35 usft Latitude: 70°28'32.874 N +E/-W 0.00 usft Easting: 571,983.88 usft Longitude: 149°24'43.080 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 23.70 usft Wellbore MPU B-34 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (0) (°) (nT) BGGM2016 1/16/2017 17.95 81.06 57,561 Design MPU B-34 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 26.90 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (°) 26.90 0.00 0.00 353.00 Survey Program Date 2/9/2017 From To (usft) (usft) Survey(Wellbore) Tool Name Description Survey Date 100.00 1,069.00 MPU B-34 SRG-SS(MPU B-34) SRG-SS Surface readout gyro single shot 01/16/2017 1,129.85 2,635.58 MPU B-34 MWD+IFR2+MS+sag(1)(MP MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 01/27/2017 2,709.37 5,024.90 MPU B-34 MWD+IFR2+MS+sag(2)(MP MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 02/06/2017 5,087.98 5,333.09 MPU B-34 MWD+IFR2+MS+sag(3)(MP MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 02/09/2017 I I Survey Map Map Vertical MD Inc Azi ND TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (0) (0) (usft) (usft) (usft) (usft) (ft) (ft) (°/100) (ft) Survey Tool Name 26.90 0.00 0.00 26.90 -23.70 0.00 0.00 6,023,979.35 571,983.88 0.00 0.00 UNDEFINED 100.00 0.09 156.02 100.00 49.40 -0.05 0.02 6,023,979.30 571,983.90 0.12 -0.05 SRG-SS(1) 168.00 0.39 145.55 168.00 117.40 -0.29 0.18 6,023,979.06 571,984.06 0.44 -0.31 SRG-SS(1) 199.00 0.45 107.82 199.00 148.40 -0.42 0.35 6,023,978.94 571,984.24 0.90 -0.46 SRG-SS(1) 261.00 0.53 85.91 261.00 210.40 -0.47 0.87 6,023,978.89 571,984.75 0.33 -0.57 SRG-SS(1) 323.00 1.34 14.04 322.99 272.39 0.25 1.33 6,023,979.62 571,985.21 2.06 0.09 SRG-SS(1) 384.00 3.46 356.51 383.93 333.33 2.78 1.39 6,023,982.15 571,985.25 3.64 2.59 SRG-SS(1) 447.00 5.96 2.92 446.72 396.12 7.95 1.44 6,023,987.31 571,985.25 4.05 7.71 SRG-SS(1) 510.00 8.44 7.72 509.21 458.61 15.80 2.23 6,023,995.17 571,985.96 4.05 15.41 SRG-SS(1) 572.00 10.86 5.31 570.33 519.73 26.12 3.38 6,024,005.50 571,987.01 3.96 25.52 SRG-SS(1) 632.00 13.30 5.90 629.00 578.40 38.62 4.62 6,024,018.01 571,988.12 4.07 37.77 SRG-SS(1) 2/10/2017 12:35:20PM Page 2 COMPASS 5000.1 Build 81 III • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-34 • Project: Milne Point TVD Reference: Actual:@ 50.60usft Site: M Pt B Pad MD Reference: Actual:@ 50.60usft Well: MPU B-34 North Reference: True Wellbore: MPU B-34 Survey Calculation Method: Minimum Curvature Design: MPU B-34 Database: Sperry EDM-NORTH US+CANADA 1 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 695.00 16.97 3.27 689.80 639.20 55.01 5.89 6,024,034.41 571,989.23 5.93 53.88 SRG-SS(1) 756.00 21.20 2.71 747.44 696.84 74.92 6.92 6,024,054.33 571,990.07 6.94 73.52 SRG-SS(1) 819.00 25.16 1.50 805.34 754.74 99.70 7.80 6,024,079.11 571,990.72 6.33 98.01 SRG-SS(1) 882.00 28.46 358.80 861.56 810.96 128.11 7.84 6,024,107.51 571,990.48 5.58 126.19 SRG-SS(1) 944.00 32.00 357.43 915.12 864.52 159.30 6.79 6,024,138.69 571,989.13 5.82 157.28 SRG-SS(1) 1,007.00 32.66 354.44 968.36 917.76 192.89 4.40 6,024,172.26 571,986.41 2.75 190.92 SRG-SS(1) 1,069.00 33.88 351.58 1,020.20 969.60 226.64 0.25 6,024,205.96 571,981.93 3.21 224.92 SRG-SS(1) 1,129.85 33.82 348.35 1,070.74 1,020.14 260.01 -5.66 6,024,239.27 571,975.71 2.96 258.76 MWD+IFR2+MS+sag(2) 1,193.18 33.52 348.34 1,123.45 1,072.85 294.39 -12.75 6,024,273.58 571,968.28 0.47 293.75 MWD+IFR2+MS+sag(2) 1,255.82 36.20 348.43 1,174.84 1,124.24 329.46 -19.96 6,024,308.57 571,960.74 4.28 329.44 MWD+IFR2+MS+sag(2) 1,318.28 37.36 349.23 1,224.87 1,174.27 366.15 -27.20 6,024,345.19 571,953.15 2.01 366.74 MWD+IFR2+MS+sag(2) 1,381.06 39.31 350.71 1,274.11 1,223.51 404.49 -33.97 6,024,383.46 571,946.00 3.43 405.62 MWD+IFR2+MS+sag(2) 1,443,46 39.58 351.92 1,322.30 1,271.70 443.68 -39.95 6,024,422.58 571,939.64 1.31 445.24 MWD+IFR2+MS+sag(2) 1,506.76 40.71 352.57 1,370.69 1,320.09 484.12 -45.46 6,024,462.96 571,933.75 1.90 486.05 MWD+IFR2+MS+sag(2) 1,569.40 40.79 353.01 1,418.14 1,367.54 524.68 -50.59 6,024,503.47 571,928.22 0.48 526.94 MWD+IFR2+MS+sag(2) 1,632.43 40.66 353.47 1,465.91 1,415.31 565.52 -55.43 6,024,544.25 571,922.99 0.52 568.06 MWD+IFR2+MS+sag(2) 1,694.43 40.55 354.50 1,512.98 1,462.38 605.65 -59.66 6,024,584.34 571,918.37 1.10 608.41 MWD+IFR2+MS+sag(2) 1,756.29 41.87 351.24 1,559.52 1,508.92 646.07 -64.73 6,024,624.71 571,912.91 4.07 649.15 MWD+IFR2+MS+sag(2) 1,820.29 42.67 350.00 1,606.88 1,556.28 688.54 -71.75 6,024,667.10 571,905.48 1.81 692.16 MWD+IFR2+MS+sag(2) 1,882.49 41.50 350.68 1,653.04 1,602.44 729.64 -78.75 6,024,708.13 571,898.09 2.02 733.80 MWD+IFR2+MS+sag(2) 1,945.93 41.83 351.37 1,700.44 1,649.84 771.30 -85.33 6,024,749.71 571,891.11 0.89 775.95 MWD+IFR2+MS+sag(2) 2,008.12 41.97 351.51 1,746.72 1,696.12 812.37 -91.51 6,024,790.72 571,884.53 0.27 817.46 MWD+IFR2+MS+sag(2) 2,071.42 40.92 351.14 1,794.17 1,743.57 853.78 -97.83 6,024,832.07 571,877.81 1.70 859.34 MWD+IFR2+MS+sag(2) 2,134.66 40.06 350.80 1,842.27 1,791.67 894.34 -104.27 6,024,872.55 571,870.98 1.40 900.38 MWD+IFR2+MS+sag(2) 2,197.74 41.29 352.12 1,890.11 1,839.51 934.99 -110.37 6,024,913.14 571,864.48 2.38 941.47 MWD+IFR2+MS+sag(2) 2,260.59 40.58 352.39 1,937.59 1,886.99 975.80 -115.92 6,024,953.89 571,858.54 1.16 982.65 MWD+IFR2+MS+sag(2) 2,324.08 39.87 351.83 1,986.06 1,935.46 1,016.41 -121.55 6,024,994.44 571,852.52 1.25 1,023.65 MWD+IFR2+MS+sag(2) 2,386.34 40.57 353.56 2,033.60 1,983.00 1,056.28 -126.65 6,025,034.26 571,847.03 2.12 1,063.84 MWD+IFR2+MS+sag(2) 2,449.10 41.02 354.08 2,081.12 2,030.52 1,097.05 -131.07 6,025,074.98 571,842.22 0.90 1,104.84 MWD+IFR2+MS+sag(2) 2,511.68 39.78 353.85 2,128.77 2,078.17 1,137.38 -135.33 6,025,115.26 571,837.57 2.00 1,145.40 MWD+IFR2+MS+sag(2) 2,574.95 39.82 353.89 2,177.38 2,126.78 1,177.65 -139.65 6,025,155.48 571,832.86 0.08 1,185.89 MWD+IFR2+MS+sag(2) 2,635.58 39.65 354.19 2,224.01 2,173.41 1,216.20 -143.68 6,025,193.99 571,828.46 0.42 1,224.64 MWD+IFR2+MS+sag(2) 2,709.37 39.10 354.15 2,281.05 2,230.45 1,262.77 -148.43 6,025,240.50 571,823.25 0.75 1,271.45 MWD+IFR2+MS+sag(3) 2,741.54 38.65 354.08 2,306.09 2,255.49 1,282.85 -150.50 6,025,260.57 571,820.99 1.41 1,291.63 MWD+IFR2+MS+sa9(3) 2,803.92 40.52 352.27 2,354.17 2,303.57 1,322.31 -155.24 6,025,299.98 571,815.87 3.52 1,331.38 MWD+IFR2+MS+sag(3) 2,867.38 40.04 352.10 2,402.58 2,351.98 1,362.96 -160.82 6,025,340.56 571,809.90 0.78 1,372.40 MWD+IFR2+MS+sag(3) 2,930.55 39.28 352.09 2,451.21 2,400.61 1,402.89 -166,36 6,025,380.44 571,803.97 1.20 1,412.71 MWD+IFR2+MS+sag(3) 2,992.48 40.63 351.93 2,498.68 2,448.08 1,442.28 -171.89 6,025,419.76 571,798.06 2.19 1,452.48 MWD+IFR2+MS+sag(3) 3,055.48 40.25 352.33 2,546.63 2,496.03 1,482.76 -177.49 6,025,460.18 571,792.08 0.73 1,493.34 MWD+IFR2+MS+sag(3) 3,105.17 39.69 351.67 2,584.71 2,534.11 1,514.37 -181.93 6,025,491.74 571,787.33 1.41 1,525.25 MVVD+IFR2+MS+sag(3) 2/10/2017 12:35:20PM Page 3 COMPASS 5000.1 Build 81 'c • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-34 Project: Milne Point TVD Reference: Actual:@ 50.60usft Site: M Pt B Pad MD Reference: Actual:@ 50.60usft Well: MPU B-34 North Reference: True Wellbore: MPU B-34 Survey Calculation Method: Minimum Curvature Design: MPU B-34 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (0) (0) (usft) (usft) (usft) (usft) (ft) (ft) (0/100') (ft) Survey Tool Name 3,180.20 39.02 351.29 2,642.73 2,592.13 1,561.42 -188.98 6,025,538.72 571,779.83 0.95 1,572.81 MWD+1FR2+MS+sag(3) 3,243.36 40.62 353.83 2,691.24 2,640.64 1,601.52 -194.20 6,025,578.77 571,774.22 3.61 1,613.25 MWD+IFR2+MS+sag(3) 3,306.13 41.28 354.47 2,738.65 2,688.05 1,642.44 -198.39 6,025,619.64 571,769.63 1.25 1,654.38 MWD+IFR2+MS+sag(3) 3,369.06 40.65 354.30 2,786.17 2,735.57 1,683.50 -202.42 6,025,660.66 571,765.20 1.02 1,695.62 MWD+IFR2+MS+sag(3) 3,432.35 40.39 354.22 2,834.28 2,783.68 1,724.42 -206.54 6,025,701.53 571,760.69 0.42 1,736.73 MWD+IFR2+MS+sag(3) 3,495.17 39.93 353.90 2,882.29 2,831.69 1,764.71 -210.73 6,025,741.78 571,756.11 0.80 1,777.24 MWD+IFR2+MS+sag(3) 3,558.64 41.38 353.60 2,930.44 2,879.84 1,805.82 -215.23 6,025,782.83 571,751.21 2.31 1,818.59 MWD+IFR2+MS+sag(3) 3,621.86 41.06 353.27 2,977.99 2,927.39 1,847.20 -219.99 6,025,824.16 571,746.05 0.61 1,860.24 MWD+IFR2+MS+sag(3) 3,684.99 41.14 352.61 3,025.57 2,974.97 1,888.39 -225.10 6,025,865.29 571,740.55 0.70 1,901.74 MWD+IFR2+MS+sag(3) 3,747.74 40.63 352.59 3,073.01 3,022.41 1,929.12 -230.39 6,025,905.97 571,734.87 0.81 1,942.82 MWD+IFR2+MS+sag(3) 3,810.48 40.46 351,23 3,120.68 3,070.08 1,969.49 -236,12 6,025,946.28 571,728.74 1.43 1,983.59 MWD+IFR2+MS+sag(3) 3,873.69 40.20 352.36 3,168.87 3,118.27 2,009.98 -241.96 6,025,986.71 571,722.51 1.23 2,024.49 MWD+IFR2+MS+sag(3) 3,936.31 40.06 352.18 3,216.75 3,166.15 2,049.98 -247.39 6,026,026.64 571,716.70 0.29 2,064.84 MWD+IFR2+MS+sag(3) 3,998.93 39.81 352.11 3,264.76 3,214.16 2,089.80 -252.89 6,026,066.40 571,710.82 0.41 2,105.04 MVVD+IFR2+MS+sag(3) 4,062.43 41.55 352.35 3,312.92 3,262.32 2,130.81 -258.48 6,026,107.36 571,704.83 2.75 2,146.42 MWD+IFR2+MS+sag(3) 4,125.85 41.43 352.49 3,360.42 3,309.82 2,172.45 -264.02 6,026,148.94 571,698.88 0.24 2,188.44 MWD+IFR2+MS+sag(3) 4,188.10 41.03 351.96 3,407.24 3,356.64 2,213.10 -269,57 6,026,189.53 571,692.94 0.85 2,229.46 MWD+IFR2+MS+sag(3) 4,251.76 40.39 351.82 3,455.50 3,404.90 2,254.21 -275.43 6,026,230.58 571,686.69 1.02 2,270.97 MWD+IFR2+MS+sag(3) 4,313.90 40.23 351.52 3,502.88 3,452.28 2,293.98 -281.25 6,026,270.29 571,680.48 0.40 2,311.16 MWD+IFR2+MS+sag(3) 4,377.26 40.22 351.34 3,551.26 3,500.66 2,334.45 -287.35 6,026,310.69 571,673.99 0.18 2,352.06 MWD+IFR2+MS+sag(3) 4,441.62 39.78 350.66 3,600.56 3,549.96 2,375.31 -293.82 6,026,351.48 571,667.13 0.96 2,393.41 MWD+IFR2+MS+sag(3) 4,504.78 39.57 350.32 3,649.17 3,598.57 2,415.07 -300.48 6,026,391.18 571,660.08 0.48 2,433.69 MWD+IFR2+MS+sag(3) 4,568.21 37.04 349.54 3,698.94 3,648.34 2,453.78 -307.35 6,026,429.81 571,652.84 4.06 2,472.95 MWD+IFR2+MS+sag(3) \,e( L 4,630.51 34.00 351.36 3,749.65 3,699.05 2,489.47 -313.37 6,026,465.43 571,646.47 5.17 2,509.10 MWD+IFR2+MS+sag(3) \+" 7 ` W 4,693.40 32.22 351.77 3,802.32 3,751.72 2,523.45 -318.42 6,026,499.36 571,641.10 2.85 2,543.44 MD+IFR2+MS+sag(3) ‘'' 4,755.90 30.12 350.00 3,855.80 3,805.20 2,555,38 -323.52 6,026,531.24 571,635.69 3.67 2,575.76 MWD+IFR2+MS+sag(3) 4,819.57 27.53 349.16 3,911.57 3,860.97 2,585.57 -329.07 6,026,561.38 571,629.85 4.12 2,606.40 MWD+IFR2+MS+sag(3) 4,881.63 24.11 351.60 3,967.4 3,916.83 2,612.21 -333.62 6,026,587.96 571,625.04 5.77 2,633.39 MWD+IFR2+MS+sag(3) 4,944.59 21.09 352.99 4,025.55 3,974.95 2,636:18 -336.88 6,026,611.90 571,621.55 4.87 2,657.58 MWD+IFR2+MS+sag(3) 5,024.90 16.78 349.60 4,101.50 4,050.90 2,661.93 -340.74 6,026,637.61 571,617.44 5.54 2,683.62 MWD+IFR2+MS+sag(3) 5,087.98 15.53 347.99 4,162.09 4,111.49 2,679.15 -344.14 6,026,654.79 571,613.88 2.10 2,701.12 MWD+IFR2+MS+sag(4) 5,151.37 15.82 349.41 4,223.12 4,172.52 2,695.94 -347.49 6,026,671,55 571,610.36 0.76 2,718.20 MWD+IFR2+MS+sag(4) 5,213.94 16.26 349.56 4,283.25 4,232.65 2,712.94 -350.65 6,026,688.52 571,607.04 0.71 2,735.45 MWD+IFR2+MS+sag(4) 5,277.31 16.75 349.90 4,344.01 4,293.41 2,730.66 -353.86 6,026,706.20 571,603.66 0.79 2,753.43 MWD+IFR2+MS+sag(4) 5,333.09 17.01 350.73 4,397.39 4,346.79 2,746.62 -356.58 6,026,722.14 571,600.79 0.64 2,769.61 MWD+IFR2+MS+sag(4) 5,370.00 17.01 350.73 4,432.69 4,382.09 2,757.28 -358.32 6,026,732.78 571,598.94 0.00 2,780.40 PROJECTED to TD mitchell.laird@halliburton.corn benjamin.hand@halliburton.com Checked By: 2017.02.10093731-09'00' Approved By: 2017.02.101414:38-09'00' Date: 2/10/2017 2/10/2017 12:35:20PM Page 4 COMPASS 5000.1 Build 81 • STATE OF ALASKA • RECEIVED ALASKA OIL AND GAS CONSERVATION COMMISSION APR 2 7 2017 ELL COMPLETIONe OR RECOMPLETION REPORT AND LOG 1a.Well Status: AOG ("� Oil❑ Gas❑ S ❑ EI n p ❑ Class: " 20AAC 25.105 20AAC 25.110 Development ❑ Exploratory ❑ GINJ ❑ WINJ ❑ WAGE WDSPL 2 , No.of Completions: _1 Service Q r Stratigraphic Test ❑ 2.Operator Name: 6. Date Comp.,Susp.,or 14.Permit to Drill Number/ Sundry: Hilcorp Alaska, LLC C .:S S J Aband.: 4/10/2017 216-139/317-118 r 3.Address: 7. Date Spudded: 15.API Number: 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 January 24,2017 50-029-23569-00-00 4a. Location of Well(Governmental Section): 8. Date TD Reached: -z/B114.. 16.Well Name and Number: Surface: 856'FSL,4296'FEL,Sec 18,T13N, R11 E, UM,AK Li. February,8'2017 MPU B-34 Top of Productive Interval: 9. Ref Elevations: KB: 50.2 17. Field/Pool(s): GL:23.7 BF:23.7 Milne Point Field6nu Undef WDSP t Total Depth: 10. Plug Back Depth MDITVD: 18. Property Designation: 1666'FNL,554'FWL,Sec 18,T13N,R11 E, UM,AK 5,285'MD/4,351'TVD 1 ADL047438 4b.Location of Well(State Base Plane Coordinates, NAD 27): 11.Total Depth MD/TVD: 19. Land Use Permit: Surface: x- 571983 y- 6023979 Zone- 4 5,370'MD/4,432'TVD' N/A TPI: x- y- Zone- 12.SSSV Depth MD/TVD: 20.Thickness of Permafrost MD/TVD: Total Depth: x- 571598 y- 6026732 Zone- 4 N/A 1,775'MD/1,573'TVD 5. Directional or Inclination Survey: Yes ❑✓ (attached) No ❑ 13.Water Depth, if Offshore: 21.Re-drill/Lateral Top Window MD/TVD: Submit electronic and printed information per 20 AAC 25.050 N/A (ft MSL) N/A 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-EWR-CTN-ALD 21N MD, DGR-ADR-EWR-CTN-ALD 21N ND �CB '_/7 .Z-/Z \ I- S1 "- ilt- . -- t- ( f-3r'- 7 Z .:3 ..J72' � J (cyc/y" 74 =1ih_) 23. CASING, LINER AND CEMENTING RECORD WT.PER SETTING DEPTH MD SETTING DEPTH ND AMOUNT CASING FT GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 20" 78.6# A-53 Surface 80' Surface 80' 42" 50 bbls Pilecrete dumped Lead-1965 sx 9-5/8" 40# L-80 Surface 2,672' Surface 2,252' 12-1/4" TJ 1 -305 sx TJ 2-49 sx 17 bbls 7" 26# L-80 Surface 5,063 Surface 4,138' 8-1/2" Lead-345 sx/Tail-130 sx 20 bbls 4-1/2" 13.5# L-80 4,880' 5,369' 3,966' 4,428' 6-1/8" 125 sx 24.Open to production or injection? Yes Q No ❑ 25.TUBING RECORD If Yes,list each interval open(MD/TVD of Top and Bottom; Perforation SIZE DEPTH SET(MD) PACKER SET(MD/TVD) Size and Number): 4-1/2" 4,889' 4,879'MD/3,966'ND 5,204'-5,244'MD/4,274'-4,312'NDSeal Assy. 6 SPF e. ,43 ,,, 'r; 26.ACID, FRACTURE,CEMENT SQUEEZE,ETC. c lee 1 b°111. Was hydraulic fracturing used during completion? Yes❑ No Q E+ ;G r r Per 20 AAC 25.283(i)(2)attach electronic and printed information le 1,. DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): N/A N/A Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: Test Period - Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(torr): Press. 24-Hour Rate lio- � R IGLNJ ._SUIDmItORIGINIM.On Form 11/2015ONTON PAGE 2 6 gPlRBDMS �,L- I:. M - 2 201/� � / 1 2017 28.CORE DATA Conventional•(s): Yes ❑ No E Sidewall Corefes ❑ No Q If Yes, list formations and intervals cored(MD/TVD, From/To),and summarize lithology and presence of oil,gas or water(submit separate pages with this form, if needed).Submit detailed descriptions,core chips,photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑� Permafrost-Top If yes, list intervals and formations tested, briefly summarizing test results. Permafrost-Base 1,775' 1,573' Attach separate pages to this form, if needed,and submit detailed test Top of Productive Interval N/A information, including reports,per 20 AAC 25.071. SV3 2,493' 2,114' Ugnu UG4 3,496' 2,883' Ugnu LA3 4,870' 3,957' Ugnu MB 5,135' 4,208' Ugnu MD 5,202' 4,272' Formation at total depth: Ugnu 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys,Csg and Cmt Reports,Surveillance Curves. 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. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Cody Dinger Email: Cdinger(c7hiICorp.com Printed Name: Cody Di ger Title: Drilling Tech /Z //� Signature: Phone: 777-8389 Date: INSTRUCTIONS ? 4- General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed.All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. 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 1 b: Well Class-Service wells:Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection, Observation,or Other. Item 4b: 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 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 11/2015 Submit ORIGINAL Only Milne Point Unit n 5,I SCHEMATIC Well: MPU B 34 Grl- Last Completed: 2/13/2017 Hilcorp Alaska,LLC LW 05 'L 0.1_,P) PTD: 216-139 KBEIev.:50.2'/GLEIev.:23.7' TREE&WELLHEAD RKB—THF:22.98'(Innovation) Tree CIW 4-1/16"5M t Wellhead Seaboard Weir,3 spools,w/11"x 5M top flange 4"CIW"H"BPV Profile It 9-5/8" P4 9 ( Top Job#z: OPEN HOLE/CEMENT DETAIL '7 93'MD 42" 50 bbls(10 Yards Pilecrete dumped down backside) 9-5/8" Cmt w/1,965 sx Class C 15.6 ppg in a 12-1/4"Hole 1 9-5/8" Top Job#1:Cmt w/235 bbl Perm L 10.5 419-5/g, ppg from 505'MD 1 Top Job#1: 9-5/8" Top Job#2:Cmt w/32 bbl Perm L 10.6 ppg from 93'MD 11, 505'MD 7" Cmt w/345 sx Type 111.7 ppg;130 sx Type 115.8 ppg in 8-1/2" 9-5/8" ' 4-4" Cmt w/25 bbl Type I-II in 6-1/8" 35/8"CBL:2/03/17 Cement toSurface CASING DETAIL 1. f � 6.. a� Size Type Wt/Grade/Conn Drift ID Top Btm BPF 4-1/2" 20"x34" Conductor(Insulated) 78.6/A-53/Weld N/A Surface 106.5' N/A :=I Tubing 9-5/8" Surface 40/L-80/DWC/C 8.679" Surface 2,672' 0.0758 7" Production 26/L-80/DWC/C 6.151" Surface 5,064' 0.0382 4-1/2" Liner 13.5/L-80/Vam HTTC 3.795 4,880' 5,369' 0.0149 TUBING DETAIL 4-1/2" Tubing 13.5/L-80/GeoConn 3.795" Surf 4,889' 0.0149 WELL INCLINATION DETAIL KOP @ 300' MD ' Max Hole Angle=42.7 deg at 1,820' MD I C- 0"' Hole angle through perforated interval: 17 deg JEWELRY DETAIL < No Depth Item ( ;y 1 23' Tubing Hanger,4-1/2"TC-II top&4-1/2"GeoConn btm i',; k;; 2 4,742' 4-1/2"R" profile Packing Bore=3.688"ID 2 3 4,879' 4-1/2" Baker Seal Assembly(Ported),5,72" No-Go Min ID=3.688"_u,_ 2 4 4,880' 4-1/2" Liner Top );.* ■, 5 4,895' 7"x 5"Baker ZXP Liner Top Packer 1.'. 3 6 4,903' 7"X 5" Baker Flex-Lock Liner Hanger �. ' 4,5,6 PERFORATION DETAIL Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status Ugnu MD 5,204' 5,244' 4,274' 4,312' 40' 4/03/17 Open ' 7 c6�2/08/173-1/8"6 spf Owen HERO(21.5 gm)Good Hole charges(0.52"EH,24.9"Pen) Y° Cement to 2,660' GENERAL WELL INFO API:50-029-23569-00-00 Drilled and Cased by Innovation#1 -2/13/2017 C�i i' Perforated Ugnu MD—4/03/2017 .,,,„:,,, 1 A,..--- r b' N. Tagw/2"bailer re„ ,:. @ 5,246'4/04/17 : i+=.,. Ugnu MD 4-1/2"CBL:2/12/17 Cement to 4,880' TD=5,370(MD)/TD=4,432'(TVD) PBTD=5,285'(MD)/PBTD=4,351'(TVD) Revised by:CJD 4/27/17 • Hilcorp Energy Company Composite Report Well Name: MP B-34 Field: Milne Point County/State: ,Alaska (LAT/LONG): svation(RKB): API#: Spud Date: 1/24/2017 Job Name: 1612654D MPB-34 Drilling Contractor AFE#: AFE$: .. .... ... ..... ........................:.:.:.:.:.:.:::.:.:::....................... :... 1/21/2017 Continue to Prep for rig move,trucks on location @ 08:00.;PJSM,split modules,Notify MP Security,mobilize modules to B-pad and stage same.;lnstall rear sub tires and yoke,Move sub module off J-02 mats,0-ring failed on DS rear tire.;Flange off kill line,Dig out misc surface items and stage on B-Pad.;Assist peak tire hand to reset bead on tire,Remove misc J-2 wellhead equipment.;Notify MP Security,Mobilize sub module from J-Pad to B-Pad,prep camp to move next.;MIRU on B-34,Align and back sub over well and position same,lay mats in place for catwalk and modules.Notify MP Security,mobilize camp from J-Pad and stage on B-Pad.Align catwalk.;Align and set catwalk into position and pin in place.Back in and spot pipe shed. 1/22/2017 Finish spotting outriggers,spot mud pit and generator modules.R/U outriggers,R/D jeeps,hookup utility lines and Iandings.;Thaw out misc steam lines, replace broken steam valves.;Get steam circulating throughout rig,Prep rig water lines.Install mud and flow line.R/D misc moving equipment.Re-install insulation on steam Iines.;Pressure test water lines,get water circulating,Berm cutting box area,set cuttings box in place.Frame in and cover cellar box with plywood.Install backup wt.indicator on rig floor.;Set diverter equipment in cellar,Prep to scope derrick up.Screen up shakers w/80#screens.Work on rig acceptance checklist.;Continue to R/U.PJSM,Scope derrick up,pin and secure same.R/D bridal line.Set diverter stack in place.Continue to cover cellar box with plywood.Load MWD tools in shed.;PJSM,N/U diverter system,continue to secure derrick.Start loading mud products into hopper room.Install ball valves on conductor. Currently 80%rigged up.;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 0 bbls to G&I for total=0 bbls Hauled 150 bbls water from 6 mile lake for total=150 bbls Daily loss 0 1/23/2017 Continue to N/U Diverter S stY em.,lnstall Knife valve.Install Diverter line sections from Knife Valve to Cat walk Section.Remove bell nipple for modifications.;Test run mouse hole and remove same for modifications.Service Pipe Skate.Prep Pits with Product for Spud. Hang rig tongs.C/0 Saver Sub/Die Block and Bell Guide from HT-38 to 4'%"IF.;Energize Koomey.Perform Derrick Inspection.Install Plumbing on Conductor outlets. Finish fabricating 8' Super Sucker line for cutting box. Prep Pipe shed to PU DP.Off Load 5"DP.;Calibrate/Test and trouble shoot Gas Detection equipment in pits.Retest Gas detection.All Good.Re install bell nipple and mouse hole.N/U 40'Diverter line extension.Stage Diverter Anchor.;Perform Diverter/Knife Valve Function test. Knife Open Time =6 sec,Annular Close Time=10 Sec. Called Jeff Jones @ 18:30 hrs to witness Diverter Test.;PJSM,continue installing 40'section of diverter and anchor down same.Set anchor wt on end of diverter.Set jt 5"DP in table for diverter test. Rig accepted on B-34 @ 21:30 hrs.;Place Barricade and diverter warning signs in place.Set containment @ end of diverter,inspect diverter setup. Unload Mud products from truck.;AOGCC rep Jeff Jones on location @ 21:30 to witness diverter test,Rig electrician test gas alarms,Perform diverter function test,Annular closed in 10 sec,knife valve opened in 5 sec.;Perform accumulator drawdown test,Sys press 2875 psi,after closure 2200 psi,200 psi attained 13 sec,full press in 34 sec,6 N2 bttls avg=2333 psi.Inspect diverter setup. No failures.UD jt DP.;Service top drive,safety wire grabber head bolts.;R/U to P/U DP,Drift and P/U 172 jts 4"HT38 DP and rack 86 stds in derrick,offload 578 bbls 8.8 ppg 56 degree spud mud into pits.;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 0 bbls to G&I for total=0 bbls Hauled 550 bbls water from 6 mile lake for total=700 bbls Daily loss 0 1/24/2017 Load,Strap and Tally 60 joints 5"DP/19 joints HWDP in pipe shed.Stage BHA components in pipe shed.C/O Elevator inserts to 5"DP.Install 2nd 8"Super Sucker Line in cutting box.;P/U and set back 30 stds 5"DP, P/U and set back 10 stds HWDP+Jar.Set Wear Bushing.Assist welder with mods in pits.Finish install on Clean out line in cutting box for Super Sucker.;Work on vent line for mud lab.PT Mud Line to 3000 psi f/5 min.Good.Fill stack and Obtain Hydrostatic test on diverter.;PJSM on P/U BHA.Spud Meeting with Crews.Discuss Conductor Broaching Mitigations and actions to be taken in the event of broaching.Assigned Primary and secondary Muster Areas.;Discuss Diverting Procedure.Implement keeping 1 Gen Idling while Drilling Surface with Rig on Hi Line in case of Field Power Outage.;PU Conductor Clean Out/Rat hole BHA with 8"MTR,12 1/4 Bit,X0 to 4 1/2"IF,1 stand HWDP.Tag @ 105';Wash and Ream down from tag depth of 105'to btm of conductor @ 113'MD w/H2O. Displace well from H2O to 8.8 PPG spud mud w/212 vis @ 113'.;Drill ahead F/ 113'-T/149'MD @ 350 gpm,420 spp,48%flow,20 rpm,1.3K tq,3-5k wob. Pea Gravel @ shakers w/significant amount of sand. Flowline packed off @ 149'MD.;P/U and rack back F/149'-T/surface. B/D TDS.;Attempt to jet and wash flowline clear using mud and water(no go). Remove flow paddle and found flowline packed off 70-80%from possum belly to flowbox. Dump possum belly.;Lineup and flush each jetline individually starting @ possum belly. Wash and clear flowline from flowbox to flowpaddle using water hose and other jetlines.;Confirm 28k tq on bit. RIH F/surface-T/93'MD. Steam and function non- ported plunger float.;Wash down F/93'-T/149'MD. 355 gpm,520 spp,48%Flow,20 rpm,1k tq. Attempt to drill ahead with jetlines isolated on mix pump. Drill F/149-T/150'MD. Flowline packed off.;Pull out of hole. Laydown single and rack back mtr assy w/milltooth bit.;Remove flow paddle. Flowline 70% packed off from possum belly to flow box. Clear flowline and clean stack,cellar and surrounding areas. Discuss options with onsite drilling team.;Clean and prep flowline for jetline install. Gather materials F/"D"pad. Cut and prep nipples for jetline install.;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 0 bbls to G&I for total=0 bbls Hauled 120 bbls water F/6 mile lake for total=820 bbls 0 losses to formation • • 1/25/2017 Prep flow line for jet installation. Plumb in start plumbing in remaining jets up stream on flow line.assist welder as needed.House keep through out the rig. Reconfigure jets as needed.;Test run jets. Drop mud vis to 150.;Grab Mtr and bit rom derrick. Break Mtr at X0 and thaw float.;Wash down to 97'.Trouble shoot IBOP issues.MU Top Drive, break circulation.Stage pump up to 350 gpm/630 psi/10 rpm/1 K Tq/Up/Dn/Rot 45K.Wash down and see fill @ 145'.;See flow line pack off issues simultaneously. P/U and attempt to pump while jetting flow line w/no progress.Kill pump to DP and jet flow line via bleeder before POOH.;See majority of pack off issues just down stream of flow box.Set back std,blow down TD.Milk Mtr&set back BHA.;Clean Floor/Cellar/Flow Box.Prep for Flow Box/Flow Riser Mods.House keep pipe shed.;Stage and rig up welding/cutting equipment.Assist welder as needed to Modify flow riser and install Jet in flow box.Pull Flow box and Notch same to align with flow line.Install jet on Flow box.;lnstall 1"Discharge fittings on existing jets.;P/U 12-1/4"Milltooth I Mtr assy and RIH to 93'MD. 47k up/dn.;PJSM,Discuss jetting manifold and valve operations along with frequency to jet. Establish circulation @ 97'MD,314 1 gpm,360 spp,63%flow,20 rpm,1k tq. Attempt to wash to btm Fl 97'to 145'MD.;Flowline plugged w/gravel. 8.9 MW with 145 vis @ 60°F. P/U off btm and blow down TDS.;Discuss options w/drilling manager. Decision made to reduce vis as needed with a minimum of 80 vis. Circulate pits and reduce active to 100 vis. Wash do to 149'w/15'fill.;350 gpm,370 psi,58%flow,20 rpm,1k tq. Drilled 2'new formation to 151'MD. Fluid built to top of flow box and climbing.;P/U inside conductor to 97'MD. Roll pumps @ 1 bpm while clearing flowline.;Wash down to 151'MD. 402 gpm,433 psi,58%flow,20 rpm, 1k tq. Flow paddle stuck on 0 and flow in flowbox continually rising. P/U and shut down due to lack of flow @ flowline.;P/U into conductor to 97'MD. Re-configure flowline jets w/air @ 45°elbow and @ Geo Span outlet in flowline. Use mix pump on other jet lines.;Wash back to btm @ 151'and drill ahead F/151'-T/280' MD. Increase pump rate to 450 gpm,510 spp,40 rpm,2k tq. Jet flowline with air and mud w/success.;Attempt to pull on elevators(no go). 20k over pull. Pump out of hole F/280'-T/105'. Blowdown TDS. Pull on elevators F/105'to surface.;Clean and inspect bit(1,1). M/U 12-1/4"VDM-3 Milltooth,Motor assy w/MWD.;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 100 bbls to G&I for total=100 bbls Hauled 375 bbls water F/6 mile lake for total=1195 bbls 1/26/2017 Continue PU BHA, Plug in&Up Load MWD.Grab Stnd NM DC's,TIH and see fill @ 170'.LID DC.;Break Circulation.Stage pumps to 460 gpm/830 psi,20 rpm/1K Tq, Up/Dn/Rot 55K.Clean out to 270',attempt to RIH with no Pump/Rot after washing Dn and see fill again.;Continue to Circulate and clean hole for Gyro @ 460 gpm.;Park @ 270'and run Multi Shot Survey&Orient TooL Face to Gyro;Drill 12 1/4"Hole f/280'to 483'w/450 GPM/830 PSI,10-20 WOB, UP/Dn 58K ROP 150 Average,2-3K Tq.;PU off Bottom and CBU staging up to 480 GPM to clean up hole.;Drill ahead sliding for build section F/483'-T/918' MD,20-30k wob,80 rpm,2k tq off,4k tq on,480 gpm,960 psi off, 1200 psi on,54%flow,75k S/O,78k P/U.;Predominantly fine sand w/increasing MW to 9.3. 4 .,7 Troubleshoot surface equipment while drilling ahead.;Continue drill ahead sliding for build section F/918'-T/1232'MD.20-30k wob,80 rpm,2k tq off,4k tq on, 11 480 gpm,1045 psi off, 1210 psi on,54%flow,75k S/O,90k P/U.;First clean svy @ 1067'MD. 3x clean svy's to 1232'MD. Release Gyro and R/D. BR prior to connections starting @ 732'MD. Found tail shaker#1 screen was off seat. Clean and re-install w/140.;Circ and condition hole @ 1232'MD. Rot and Recip I pipe,480 gpm, 1200 psi,54%flow,80 rpm,3.5k tq. Pump 10 bbl 100 vis sweep @ 1232'MD.;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 228 bbls to G&I for total=328 bbls Hauled 375 bbls water F/6 mile lake for total=1570 bbls 1/27/2017 Circulate and condition hole. Cont T/pump @ drilling rate. Circ out 100 vis sweep. R/D Gyro and release. Made connection,saw 200 psi drop in spp F/1270 to 1070 psi. Troubleshoot surface equip.;Didn't find any issues w/surface equipment. Proceed to drill ahead w/new pump psi.;Drill ahead F/1232'-T/1736' MD. 480 gpm, 1325 psi on,80 rpm,4k off,4.5k on,90k P/U,75k S/O,78k Rot,15-20k wob. Change out shaker screens to 100's.;lncrease pump rate as flowbox,flowline and shakers permit. Max pump rate reached 505 gpm,1415 psi.;Circulate and condition @ 1736'MD. 480 gpm,1120 psi. Pipe drain came loose. Re-install pipe drain in flowline.;Drill ahead F/1736'-T/1922'MD. 480 gpm, 1325 psi on,80 rpm,4k off,4.5k on,100k P/U,77k S/0,86k Rot, 15-20k wob. Backream each connections.;Mud pump and drawworks system shut down while drilling ahead. Re-set and continue drilling ahead while troubleshooting issue offline. Replace communication cable in doghouse;Observed ECD spikes to 11.2 EMW. CBU @ 480 gpm,1150 psi to reduce ECD's and clean up hole. ECD's reduced to 10.5 avg. Continue drilling ahead.;Continue drilling ahead F/1922'-T/2235'MD. 480 gpm,1150 psi off,1260 psi on,28k wob,80 rpm, 5.7k tq on,5k tq off, 105k P/U,83k S/0,87k Rot. Continue backream each connection.;Continue drilling ahead F/2235'-T/TD @ 2675'MD as per HAK Geo(Eastham).480 gpm,1150 psi off,1240 psi on,28k wob,80 rpm,7.5k tq on,6.5k tq off,110k P/U,83k S/O,91k Rot, 10.2 ECD's.;Obtain final svy. Extrapolated to bit @ TD(2675'MD) / 5 High and 5'Right. Base of permafrost between 1690'-1730'TVD. Continue to troubleshoot system shutdown issues w/no resolve as of yet.;No directional work Fl 1600'-T/1800'TVD. 230,444 Total Est Revs on bit.;Circulate and condition hole @ TD(2675'MD). 480 gpm, 1350 psi,68%flow,80 rpm,7.5k tq. Pump 15 bbl 200 vis sweep w/nut plug for marker. 0 bbls loss to formation for hole section.;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 1211 bbls to G&I for total=1539 bbls Hauled 1500 bbls water F/6 mile lake for total=3070 bbls 1/28/2017 Cont pump flagged hi vsc sweep to surf @ 500 GPM/1300 PSI,w/40 RPM/6.5 Tq.Sweep back 120 bbls late.Cont.circ hole clean.CBU x3 UP 118K/Dn 84K/Rot 99K,480 GPM/1215 PSI.;Flow Check Well.Pump OOH f/2675'-1231'@ 300 GPM/610 PSI.Adjust Flow Rate as hole dictates. Encounter pack off issue with all rates.200 GPM/395 PSI.;See pack off issues more often in slide intervals.Orient Tool Face to minimize pack offs.Depths of Slides: 1879-1859,1774-1733, 1505-1484,1396-1358,1282-1232.;BackReam @ 40 RPM/6.5K @ 1605-1573,1360-1270,See 10-20K over periodically.;Circulate hole clean w/450-500 GPM.See Increase in gravels and clay.CBU x3;POOH on elevators to BHA.Monitor well, POOH and rack back HWDP and Drilling Jars, pulled 20K over @ 560'. Lay down 3 x Flex collars.Plug in and download MWD data.Pull pulser from HOC and L/D BHA,;BHA looked fine;Bit was graded 1-1-WT-A-E-1-ER-TD.;Clean and clear rig floor and Pipe Shed. Kick out BHA from Pipe Shed.;Pull Wear Bushing,Grab 9 5/8"Bushing Inserts.R/D Hyd. Elevators.M/U Floor Valve X0. RID Short Bails,C/O MP#2 Gear oil pump.Spot Smoke Shack,P/U&MU Volant tool.;R/U Weatherford 1450 double stack tongs for high tq connections. Fit casing slips(no go). P/U and install Weatherford false table w/#3 bushings(slips compatible).;PJSM,Run 9-5/8",L- 80,40#,DWC/C casing. M/U 80'shoe track(bakerlok). Flashlight float equipment prior to makeup. Check floats(ok). Adjust double stack backups to pipe size.;Continue running 9-5/8"casing from 80'-T/1202'MD. Tq 9-5/8"DWC/C connection to 32k.;Circulate and condition mud lx casing volume(91 bbls)@ 1202'MD. Stage pumps up to 6 BPM,45 psi. Shut down pumps. Work past slight bridge @ 1190'MD.;Continue running casing F/1202'-T/1260'MD. Work past bridge @ 1220'MD w/3-6 BPM,10-20 rpm,1l k tq. No packing off or pump psi increase observed while working pipe. 80k up,55k dn.;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 575 bbls to G&I for total=2114 bbls Hauled 650 bbls water F/6 mile lake for total=3720 bbls;Daily losses to formation 0 bbls for total=0 bbls Charged off 288 bbls Spud Mud from LMP. EPA onsite to observe casino run and uocomina cement iob. • • i.l 1/29/2017 Continue to Run 9 5/8",40#,L-80 DWC/C Casing.Wash and Rotate casing f11260'to 2675(BTM)See stalls @ 18K,10 RPM/10-13K Free Tq,230 GPM/100 PSI.PU 131K,SO 85K. See mostly sand @ Shakers.;Circulate and condition mud for cement job,lowering YP to 17.,stage pumps from 252 GPM/130 PSI to 300 GPM/130 PSI.Reciprocating pipe 30'with no rotation.Up Wt 131K,SO Wt 85K.;R/D WOT Power tongs.Stage CMT Head on Rig floor.Clean and clear rig floor of running tools.Walk through and inspect R/U for handling CMT Returns to Surface.Spot and Rig up HES Cement Unit.;Shut Dn pump.RID Volant CRT,Blow dn TDS.DSM witness loading of Top&Btm Plugs in Cmt Head,M/U Cmt Head&HP Lines.Continue circ via Cmt Line.;PJSM with HES Cementers and Drillling Crew on pumping CMT.;Perform cmt job as follows: Pressure test lines to 3500 psi Pump 54 bbls of Tunned Spacer III at 10.5 ppg. Drop btm plug.;Mix and pump 1965 sxs(335 bbls)of Class C cement at 15.6 ppg. Drop top plug Cmt Unit displace cmt w/20 bbls of 8.3 ppg FW,Rig take over&pump 177.50 bbls 9.5 ppg Mud f/Rig pits.;Bump plug @ 2839 stks(pump output back calculated @.0625 bps). Psi up 500 psi over final circulating pressure.Hold 5 min. Bleed off pressure-floats held(1 bbl bled back).;Details: Full returns throughout job DFinal circulation pressure prior to t�uring plug 600 psi at 3 bpm ..,No cmt or spacer to surface taring Cmt in place at 19:50 hrs;R/D cement head. B/D surface lines and R/D same. Drain stack and flush. Bleed dn koomey. Disconnect knife valve. Psi up koomey. Top wash BOP's.Function and flush annular.;R/D long bails and 9-5/8"casing elevators. R/U short drilling bails and 5"dp elevators. Load(50 ea) 10'sticks 3/4"top job pipe in shed. Build mule shoe jt w/circ holes.;P/U and RIH w/3/4"top job pipe to current depth of 260'MD.;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 592 bbls to G&I for total=2706 bbls Hauled 550 bbls water F/6 mile lake for total=4270 bbls;Daily losses to formation 0 bbls for total=0 bbls EPA Rep-Jasen Truman onsite to witness cmt iob 1/30/2017 Continue P/U and RIH w/3/4"top job pipe from 260'to 500'MD(50 stick's Conduit)More Conduit in route.;Service Rig,Grease Pipe Traveling/Handling Equipment. Continue Cleaning Pits and Rig areas.Clean Pill pits for FW to pump down 3/4"Pipe.;Continue Cleaning Pits and Rig areas.Clean Pill pits for RN to pump down 3/4"Pipe.;R/U to circulate water down Top Job Pipe.Pumping down 3/4"Pipe taking returns to cellar.See returns at cellar box w/9.6 ppg,PH 8.3;Bring on pump and stage up to 1 bpm with Pressure limit set @ 150 psi.See returns at cellar box w/9.6 ppg, PH 8.3. Pump 52 bbls annular volume w/Mud only ofreturns.Monitor MW/PH every 5-10 bbls;@ 85bbls away start to see pump stall f/150-180 psi.;Continue to clean pits.Work on Misc rig inventories/check list.;Cont circulate w/3/4"pipe(top job). 2bpm,33 psi. Final MW 9.1 ppg,PH @ 8.2. S/D pumps. w/260 bbls mud pumped. R/D pump equipment and blow down same.;POOH F/500'-T/surface laying down 3/4"pipe. Stage 37 jts of 1"CS Hydril(2.25#)pipe in shed. strap and tally. Size safety clamp. (0 v Modify handling no-go plate to fit 1.3"O.D on tube.;RIH w/3'mule shoe and 21 jts+20'(674'MD)before tagging. Verify tag w/AOGCC witnessing tag(Chuck gi Scheve). POH T/654'MD. L/D jt#22.;R/U circulating equipment and attempt to circulate with MP 1&2. Unable to circulated Troubleshoot surface equipment. Unable to circulate through bleeder w/any resistance.;lsolate both pumps and try individually with same results. Clean mud end on#2 MP. Replace 1 suction valve. Clean suction screen and suction manifold(lots of pea gravel).;Found small rocks and debris on valve seats during tear down. Re-assemble pump.;Line up on#2 MP and clean MP#1 offline. Attempt to psi up @ low SPM w/no success. Troubleshoot equipment. We were able to establish prime on pump @ 50 spm using bleeder.;String repetitively built pressure and would not circulate. Indications of plugged string. Attempt to gain circulation wl quick psi drops via bleeder but no success.;Saw a max psi of 1200. Shut down and held psi @ 1050 psi. Bleed off psi. R/D circulate equipment.;POH w/wet string 1"Hydril CS F/654'-TI 285. Re-attempt to circulate(no circulation). Continue POH F/285'. Found#2 jt was plugged off with rocks and debris(1/4"to 3/4"size)at pin end.;Shoe was clear and no other obstructions observed. Verify pill pit is clean and free of debris. Lineup on pill pit for remaining top job operations until other pits have been cleaned.;EPA rep Jason B.Selitsch onsite to witness top job and well progress.;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 252 bbls to G&I for total=2958 bbls Hauled 750 bbls water F/6 mile lake for total=5020 bbls 1/31/2017 Clear plugged joint 1"pipe. Drill(12)3/8"holes above mule shoe. RIH with 1"pipe&tag up at 696'. Attempt to break circ with rig pumps.No go. MP#1 full of gravel.;Open up MP#1 &clean out same.Swap to cmt unit. Attempt to break circ with cmt unit. Pressure up to 2000 psi.No go. POOH with work string. Found plugged mule shoe&sand and gravel in to second;joint. RIH with 1"work string 7 joints to 217'.Break circ with cmt unit to 1.8 bpm 530 psi.Good.Circ 13 bbl total. RIH&tag up @ 310'. R/U&break circ @ 1.8 bpm 700 psi. Good.Circ 6 bbl.;Attempt to work past 310'with no go.Try several diferant 0 parameters working 60'up and down rotating pipe. No go. Consult Drilling manager and decide to POOH for CBl;Blow down surface equipment.R/D circ equipment. POOH with work string&LID same.;R/U false table and set 9 5/8 in slips. R/D drive sub and LID 5"working joint on the TD. R/U Pollard E line. i Hang sheave in elevators.;Bring Pollard tools to floor and M/U same. RIH with wire line T/2549'.Tag up.Log Fl 2549'T/Surface. Log showing good bond F/ �8• 2549'T/820'+/-. R/D Pollard E line.;M/U Drive sub&5"Dp to TD. Pull casing out of slips.R/D false table. Prep to P/U 1"Pipe for Top job.;RIH w/1"Hydril CS pipe to 300'MD. R/U to wash dn with test pump. Pump while tagging up @ 310'MD. Unable to pump. Plugged string. Psi up to 800 psi. Bleed of and re attempt (no pump).;POOH and LID pipe F/310'-T/248'MD. Observed flow @ stump. R/U and establish circulation using cmtrs pumping 9.4 spud mud. RIH washing dn each jt Fl 248'to tag depth 310'MD.:Work past 310'and continue washing down @.7 BPM/700 psi to final tag depth of 505'MD. Unable to �+�,` wash and work past 505'MD. Establish circulation w/100%returns.;R/U to cmt. S/D pumps and B/D lines. Lineup mix water to cmtrs. Lineup to take 0 1( ,i% returns to cellar. Batch @ 01:20 hrs. Start pumping"Perm L"cement @ 01:30 hrs.;1000 psi ICP @ 1.6 BPM, 1080 FCP @ 1.6 BPM. Pumped a total of 235 ./fj bbls 10.5 ppg"Perm L"cement w/full returns. No cement observed @ surface. Final mud check was 8.6 ph,9.6 mw(returns).;Chase cmt with 2 bbls H2O. -" 'TD pumpi g CIP @ 04:05 hrs.;R/D cmtrs and cleanup lines. Blowdown same. Pull 1"Hydril pipe F/505-T/surface. Flush and laydown each jt. Found residual cmt on jt#8 out of hole. Est TOC @ 250'MD.;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 446 bbls to G&I for total=3404 bbls Hauled 150 bbls water F/6 mile lake for total=5170 bbls • ff, i 2/1/2017 Wait on cmt and cmt crew. Continue working on housekeeping around rig.Continue cleaning gravel from pits and lines. Prep for N/D diverter system.;Cmt crew on location with cmt.Notify Chuck Scheve with AOGCC of cmt operations. AOGCC waived witness of cmt operations. Notified EPA rep Jason Selitsch of cmt operations.;RIH with 1"CS hydril pipe T/90'.Tag up.Work down T/120'. Try to establish circulation. Pressured up.Unable to circ. POOH F/120'. Found green cmt in the mule shoe.;Clean out same.RIH T/93'.R/U Halliburton cmt unit. Conduct PJSM.Pump 2 bbl H20.Pressure test to 2500 psi. Good. Pump 32 bbl 10.6 ppg Perm L Cmt dumping all returns to cellar.;Started getting contaminated cmt at surface @ 15 bbl away.Continued pumping until good 10.6 ppg cmt returned to surface.Pumped 32 bbl total. R/D cmt lines.Blow down same.;EPA rep on location to witness cmt to surface. CMT in place @ 18:16.;POOH with 1"CS hydrill.Flush and L/D same. Clean out cellar box.Start N/D operation. Flush bops and surface equipment with black water.N/D bops&diverter system.;P/U BOP stack. Clean wellhead work area. Set"E"slips(type 830)on 9.625"surface casing with 150k string wt in slips. BIO stand and rack back. P/U on 9.625"stump with tugger.;Rough cut casing. Pull cutoff jt and L/D same. Finish cleaning pits.;Set Stack. N/D diverter"T"on wellhead. Clear BOP stack from diverter"T". P/U and remove diverter"T"from cellar. Make final cut on casing and dress same for packoff install. Install packoff.;N/U multi bowl to stack while staged in cellar. P/U and set down on wellhead. N/U same. R/U and test packoff 500/2800 psi w/5 min hold on each (ok).;N/U BOP equipment. Tighten all flange connections.Prep and install bell nipple. M/U Koomey lines. M/U choke and kill lines. Remove 3"valves and equipment from conductor,clean and store.;RKB measurements-G/L=26.65',LLDS=23.91', ULDS=22.98',LPR=20.85',Blind=17.26',UPR=15.78', Ctr Ann=13.26',Top Ann=12.19'MD.;Circulate through bleeder to flush MP lines. Circulate 505 bbls @ 7 BPM w/200 psi(full open bleeder on rig floor).;R/U BOP test equipment. Bring TIW and Dart valves to rig floor(4-1/2 IF&HT-38).;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 716 bbls to G&I for total=4120 bbls Hauled 450 bbls water F/6 mile lake for total=5620 bbls 2/2/2017 M/U test joint&set test plug with 4"test joint.;Test bops&equipment to 250/3500 high with 4"&5"test joint. Perform bleed down on manual and Hyd TD valves.Perform function test of gas alarms&H2S.;Check Flow paddle and pit sensors as per AOGCC rep Matt Herrera. Perform accumulator Drawdown test. Starting PSI 2975 After Shut in 1700 200 PSI INC 20 sec Full Pressure 69 sec 6 btl N2 @ 2333.;All test Witnessed by Matt Herrera with the AOGCC. Total test time 5 hrs.;Drain stack. Install wear bushing.10"ID.;Ready floor for BHA. etBring tools and equipment to rig floor.;R/U and PT 9-5/8",40#,L-80. Psi up T/2950 psi w/30 min hold(ok). Flood lines and purge air. Chart and record same. Pump 1.75 bbls/Bled back 1.75 bbls. Final psi=2910 psi.;Remove and thaw Kelly hose. Found water and sand ice plug in belly. Re-install Kelly cp hose.;M/U cleanout assy. 8-1/2"hughes milltooth(new)w/1.5°mtr. float sub(ported plunger float)HWDP w/jars.;RIH out of pipeshed w/10 jts 5"dp F/647'- 961'MD. Continue RIH out of derrick w/5"DP F/961'-T/2530'MD.;Circulate and condition mud. Obtain flow rate test for surface equipment. Data captured t'd"\ on excel and in"0"drive. Flow rates Fl 350-T/600 gpm's. Vis range 43 vis-100 vis.;Wash down F/2530'-T/tag depth 2567'w/5k. Drill cmt F/2567'-T/ 2675'MD.Found float collar and shoe on depth.Work through shoe track w/no rotary(clean). Drill 20'new formation T/2695'.;Drill shoe track @ 450-600 gpm,20 rpm,7.5k tq w/5-15k wob. 100-200 diff. Observed plugs back©shakers. EPA rep Jason Selitsch witness cmt tag.;Circulate and condition mud IN/OUT 9.2 ppg. 450 gpm,880 psi w/61%flow.;P/U into shoe. B/D TDS. R/U to perform FIT. Lineup on drill string and kill. 1/4 BPM w/max osi 390 osi for, 12.5 EMW. Held 10 min w/264 psi final. No break over(good test).;R/D test equipment. Blowdown same.;Monitor well(static). POH F/2655'-T/2467'MD on elevators. 1z 2/3/2017 Continue PON F/2,467'-T/Surface. L/D last 10 jts to shed w/total of 30 stds 5"DP racked back. Rack back BHA in derrick. Clean and clear rig floor.;R/U Pollard E-line. Run CBL to 2680'MD and log up to surface. R/D E-line and release same.;P/U misc BHA components to rig floor. Inspect handling equipment. Install mousehole.;M/U 8-1/2"mtr directional BHA. Download MWD and check tools(ok). RIH with remaining BHA out of derrick T/712' MD.;Shallow pulse test MWD(ok)450 gpm, 1000 psi. Stage pumps up to 550 gpm/1350 psi for flow test rate on surface equipment.;RIH F/712'-T/2593' L MD on elevators w/5";Circulate and condition mud. Pump 40 bbl high vis sweep @ 450 gpm,1000 psi. 113k P/U,78k S/O. 9.2 MW IN/OUT;Thorough rig service. Grease crown,blocks,TDS,Spinner,Drawworks. Check fluid levels in TDS.;C/O 4-1/2 IF saver sub to 4"HT-38.;RIH F/2593'-T/2660'MD. Wash ✓�,J do last std T/2695'MD. Drill ahead F/2,695'-T/ 3,163'MD,2,629'TVD. 500 gpm,1310 psi off, 1380 psi on,65%flow out. 40 rpm while mwd inside 4 casing.;lncrease rpm's to 80 once mwd in open hole. 7.8k tq off,8.5k on. ECD's=9.9 EMW. BGG avg 8 units,Max gas observed=12 units.;Last survey @ 3,055'MD put us 1'high and 5'right of plan.;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 171 bbls to G&I for total=4405 bbls Hauled 175 bbls water F/6 mile lake for total=6495 bbls • • 2/4/2017 Drilling 8.5 Directional hole F/3163'T/3729' 565'@ 94 fph average 500 GPM @ 1650 PSI 80 RPM 8.5K TQ 250 FPH Max 10-18 K WOB MW 9.2+ 50 vis in 9.3+out.;MW 9.2+ 50 vis Back reaming 30'on connections at Reduced RPM&Flow in. Pumped Sweep @ 3325' 3795'Both came back on time with 50%inc.;Drilling 8.5 Directional hole F/ 3729'T/4300' 571'@ 95 fph average 500-550 GPM @ 2150 PSI 80 RPM 8.5K TQ 250 FPH Max 15-18 K WOB MW 9.2+ 50 vis in 9.3+out.;Drilling 8.5 Directional hole F/4300'-T/4693' 393'@ 66 fph average 500-550 GPM @ 2250 PSI 80 RPM 10K TQ 250 FPH Max 15-18KWOB MW 9.2+ 51 vis in 9.3+out.;Had high bearing temp alarms on both pumps and winding high temp on MP Traction mtr#2. Intake was frosted over. Cleared intake and seemed to clean up bearing high temp alarm.;Found lube pump had failed on#2 MP. Continue drilling ahead @ diminished rate w/MP#1. Replaced lube pump and put back online(1 hr 30 min total time). Event occurred @ 21:45 hrs.;Pumped 25 bbl hi vis sweep(180 vis)@ 4420'MD. Came back on time w/50%increase in cuttings. Extended TD as per Geo(Kevin Eastham). Proposed TD 4900'MD then reassess log for final TD.;Start drop section as per directional plan @ 4550'MD.;Drilling 8.5 Directional hole F/4693'-T/4900' 207'@ 60 fph average 500-550 GPM @ 2250 PSI 80 RPM 10K TO 250 FPH Max 15-18 K WOB MW 9.2+ 51 vis in 9.3+out.;Continue with slides to adhere to drop section as per directional plan. Stop drilling @ 4900'to assess logs and determine final TD.;Assessing logs(HAK Geo-Kevin Eastham). Continue drilling ahead to new TD depth 5070'MD.;Drilling 8.5 Directional hole F/4900'-T/4989' 89'@ 59 fph average 500-550 GPM @ 2350 PSI 80 RPM 10K TQ 250 FPH Max 15-18 K WOB Rotating,20-25k sliding. 2/5/2017 Drilling 8.5 Directional hole F/4989'T/5070 81'@ 40 fph average 560 GPM @ 2425 PSI 80 RPM 10K TO 15-18 K WOB Rotating,20-25k sliding. MW 9.2+ 51 vis in 9.3+out. 9.9 ECD UP/DN/ROT 155/91/113;Circ 50 bbl nut plug sweep around three btm up total. Sweep came back 20 bbl late with 100%increase in cuttings. Monitor well.Slight seepage.;Pump out of the hole @ 400 gpm F/5070'T/2675'. No over pulls observed.;Pull in to shoe.Monitor well.Static. Circ two btm up.Fine sand and clay in returns.Cleaned up after first btm up. Pump Dryjob.;Change handling equipment. UD 5"DP F/2598'T/1195'. L/D 5"HWDP F/1195'T/412'.;Continue POH laying down all 5"HWDP F/412'T! 6-3/4"BHA @ 96'MD.;Plug in and download MWD. B/O and UD MWD. Noted damage on btm of ILS stab. Showed first 2 inches of blades were 1/4"under gauge(rung).;Slight balling around stab's. No other damage noted. Drained mtr, B/O bit and LID same. Bit grade=1,2,WT,A,E,3,RG,TD. Trip disp =-8 bbls.;Clean and clear rig floor.;Pull wear bushing. RIH and set test plug. Close blind rams. C/O upper pipe rams to 7"fixed body. R/U and test upper pipe and annular w/7"test jt. 250/3500 psi(ok). Chart and record same.;R/D test equipment. B/D lines. Pull test plug and L/D test jt. Clean and clear rig floor.;PJSM, R/U WOT-762 series double stack tongs,Size dog collar,C/O elevators T/7"-150T side doors. Function equipment(ok). Stage air slips.;Verify LDS are backed out. Dummy run 7"hanger. Landout on depth. Verified by wellhead tech(Greg Ruge). L/D hanger and stage in shed.;PJSM, Run 7",DWC/C,26#, L- 80 casing F!surface-T/1874'MD. Make up 80'shoe track w/bakerlok. Flashlight all float equip(ok). Check floats(ok). 21k tq on shoe track.;lnstall solid body turbolizer 10'F/shoe. Install bow spring turbolizer 30'from shoe. Jt 2&3 had solid body turbolizer in ctr of jt.;Install bow spring turbolizer on collar of ea jt starting#4jt. Top fill pipe. Daily losses to formation=5 bbls Total losses to formation=5 bbls;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 528 bbls to G&I for total=5332 bbls Hauled 700 bbls water F/6 mile lake for total=7595 bbls • i 2/6/2017 Run 7"Casino F/1874'T/2590'.;Clrc Liner volume @ shoe with cmt line and swedge.4 BPM©180 PSI. Install long bails while circulating.Install bail clamps for kickers on long bails. M/U CRT to TD in mouse hole while circ.;Take parameters©shoe.10,20,30 RPM. 8800,8300,8000K. UP/DN 100K/71 K;P/U casing Fl 2590'T/3875'.M/U Port collar. Install centralizer on joint before and after the Port collar. Fill casing on the fly.Toping off every 10.Casing Fill keeping up with running.;P/U 7"DWC 26#Casing F/3875'T/5035'. M/U hanger and landing joint.;Break circ @1 bpm 350 psi.Work pipe while staging up pump rate 1 bpm each btm up.Stage up pumps to 6 BPM @ 400 psi. Circ 3.5 btm up. While treating mud for cmt job.;Shut down pump&land hanger.R/D CRT. Blow down TD. R/U Halliburton cmt head. Start to circ&work pipe. UP/DN 150/87:Stage pumps up T/5 BPM,440 psi w/50%Flow. 170k up, 100k do wl pumps off. R/U blackwater to annulus. Recip pipe during circulation. No losses for casing trip. SID and turnover to HES cmtrs.;PJSM,Wet cmt lines. Cmt as follows: 5 bbls 10.5#Tuned Spacer III W/251bs polyflake P/T linespsi(ok) 35 35 bbls 10.5#Tuned Spacer III Drop btm plug(750 rated burst) tt 19:40-Batch Lead 11.7#;151 bbls 11.7#Lead(Type I)t 4.7 BPM/350 psi(345 sxs) C`' 20:20-Batch Tail 50 bbls 15.8#Tail(Type 1)@ 3.5 BPM/430 psi(130 sxs) Drop Top Plug 20 bbls H2O to clear lines;Turnover to rig. Displace w/9.2#spud mud @ 6 BPM(first 140 bbls). Reduce T/3BPM w/FCP 1240 psi Bumped 170.9 bbls(179.8 bbls calc)(.0625 bps pump output) Psi up 1880 psi. Hold 5 min:Started seeing Poly Flake at shakers after swapping to Rig. Roughly 100 bbl early. Started dumping returns 73 bbl in to displacement.;Check Floats(ok).Bled back 1.25 bbls. 20 bbls cmt back to surface. CIP @ 21:28 hrs Full returns throughout job(0 bbls lost during job).;Set Packoff. RILDS. Inject plastic. Test inner,outer neck seals,500 psi low(5 min)/5000 psi high(10 min). Test good. Sym Ops-Clean and clear rig floor. LID landing jt. R/U short bails.;R/U Johnny Wacker and flush stack w/blackwater. Flush choke and kill lines wl blackwater.B/D lines. Open gates and clean residual mud and cmt. C/O upper rams T/2-7/8"x 5-1/2"VBR's.;Set test plug. Fill stack and purge air. Test upper pipe and annular w/4"test joint. 250 low/3500 high w/5 min hold on each. Chart and record same. R/D test equipment and B/D same.;Set upper wear bushing. L/D test jt and running tool. Bring BHA tools to rig floor. Daily losses to formation 0 bbls for total=5 bbls;Hauled 0 bbls to B-50 for total=0 bbls 2/7/2017 P/U Clean out BHA#4. Used 6.125 Bit, Motor,2 NMFC, 11 joints HWDP, T/456'.;TIH F/456'T/1147'.M/U TD&ROT past Port Collar. Clean.RIH with 4"DP From Derrick Fl 1200'T/4900'.Start taking wt.POOH TI 4850'.;Circ btm up while prepping for Slip&Cut.;Slip&Cut line.Service rig. Calibrate blocks,;PJSM,R/U to test casing. Test casing T/3600 psi. Pressure up to 3680.bled down to 3620 in 30 min. R/D testing equipment. Blow down all testing equipment.;Wash down from 4856'to 4926'tag cement.247 gpm,1200 psi,PU 110k,SO 70k, ROT 88k.;Drill cement f/4926'to 4976',drill plug and flt collar to 4980',drill hard cement f/4980'to 5062',obtain SPR,drill out shoe to 5063',cleanup rathole,drill new formation f/5070'to 5090';Circulate and condition mud for FIT pumping 247 gpm,1200 psi,MW in/out 9.2 ppg,vis 43. Rack 1 std back parking in 7"casing @ 5040';M/U top drive.close annular,Perform FIT to 12.5 ppg EMW with existing 9.2 ppg MW,pump.81 bbl,apply 710 psi,10 sec 705 psi,1 min 700 psi,8 min leveling off @ 600 psi,good test.;bleed off ^r` press,.81 bbl bled back,open annular;Flow check well,static,pump dry job,blow down top drive.;POOH f/5040'to 456'@ HWDP,rack HWDP and BHA in 1 h� derrick.Bit grade=1/1/WT/A/E/I/NO/LOG Note:2 bbls over calculated displacement on trip out. Note:kick while TOOH drill,secure well 56 sec.;R/U Pollard E- x+ line,M/U tools=centralizer,2 3/4"GR,centralizer,Sector bond tool,centralizer,CCL,RS=23.69'RIH CBL tools to 5086',tagging bottom,log up f/5086'to 4843'(EOP 5061'ELM).;RIH to 5085',Log up 60 fpm to 2000',while logging install 3 flow line jets.;Daily losses to formation 2 bbls,total losses 7 bbls.;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 271 bbls to G&I for total=6157 bbls Hauled 400 bbls water F/6 mile lake for total=8545 bbls 2/8/2017 Finish 7"CBL F/2000'To surface.R/D Pollard wire line.;Drain BOP stack.Remove wear bushing.;R/U 4.5 test joint and set test plug.Test upper and lower ,, rams to 250/3500 psi.good.R/D testing equipment.Pull test plug.Set wear bushing..;P/U BHA#5,P/U BHA to the TM collar&M/U TD. Upload MWD. Pulse test tools.Good. Have nuclear source PJSM,Load Nuclear sources. RIH with NMFC,HWDP&Jars to 535'.;RIH F/535'T/5062'.Filled pipe&Test 2tools©2737'. UP/DN 77/63K. Get SPR.;Wash f/5062'tagging bttm @ 5090'pumping 200 gpm,1040 psi,madd pass shoe, Drill 6 1/8"hole f/5090'to 5370'@ TD in shales just dere \ Schrader bluff-per Hilcorp Geo,AV rop 62.2 fph,280'.;250 gpm,1540 psi,60 rpm,6k tq,wob 7-10k,MW in/out 9.2,vis 43,ECD 10.1,PU/SO/ROT 122/90/71 Note:457u trip gas @ BU.;Reciprocate and rotate full stand,80 rpm,load 25 bbl 180 hi vis sweep in DP,pump sweep around 250 gpm,1450 psi cleaning up wellbore,pumping 2 bottoms up,sweep back @ calc stks,75%increase sand.;Pump out of the hole 250 gpm,1450 psi f/5370'to 5060'just above 7"shoe with no issues.;Reciprocate and rotate full stand,80 rpm,load 25 bbl 180 hi vis sweep in DP,pump sweep around 250 gpm,1450 psi cleaning up wellbore. Sweep back©calc stks,25%increase sand©shakers;Flowcheck well 10 min,static.Pump dry job,drop 2.375"drift on wire,blow down top drive.;POOH on elevators f/5060'to 535', Note:3.54 bbls over calculated displacement on trip out.;POOH f/535'LID 11 jts HWDP and jars.L/D BHA;Daily losses to formation 0 bbls,total losses 7 bbls.;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls 14/‘' Hauled 144 bbls to G&I for total=6271 bbls Hauled 150 bbls water F/6 mile lake for total=8695 bbls /.►3 2/9/2017 L/D BHA,LID DC,Conduct PJSM to remove nuclear sources. Remove sources. Finish L/D BHA#5. Bit Grade 1,1,WT,A,E,1,No,TD.Clean and clear rig floor.;R/U Weatherford casing equipment.Flush casing tongs, R/U Safety valve and XO,Change Elevators to 4.5.Count pipe in shed.;PJSM on Running 4.5 Liner. Ready FOSV and XO.P/U Shoe joint,FC joint,&LC Joint. Baker Ioc the connections.Check float operation.P/U,RIH with 11 jts 4.5",13.5#L-80.;Vam HTTC Liner to 450',TQ connections to 8100 ft/lbs,M/U LT hanger/packer assembly,RT and XO,fill liner tie back sleeve w/pal mix, Run 1 std 4"DP to 497', pump thru liner 3 bpm,60 psi.;to ensure clear flow path,Note:AFE change @ 12:00 to 1612654C.;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 107 bbls to G&I for total=6378 bbls Hauled 0 bbls water F/6 mile lake for total=8695 bbls S • Hilcorp Energy Company Composite Report Well Name: MP B-34 Field: Milne Point County/State: ,Alaska (LAT/LONG): :vation(RKB): 26.4 API#: Spud Date: 1/24/2017 Job Name: 1612654C MPB-34 Completion Contractor AFE#: AFE$: 2/9/2017 RIH with 4 1/2"lower completion conveyed on 4"stds of DP f/derrick f/497'to 5024'@ 90 fpm,fill pipe on the fly every std per BOT rep.(72 stds).,Circulate, pumping 2 bpm,170 psi,1 string volume.Get parameters pumping 2 bpm,10 rpm,5k tq, P/U 104K,S/O 74K, ROT 82K. Blow down top drive.,RIH f/5046' exiting shoe @ 5064'RIH to 5337'drifting last 5 stds f/derrick(77 stds total)M/U cement head and lines on drifted single in mousehole.M/U to string.Close manual IBOP.,Stage pump up 1 bpm,180 psi, P/U 112K,S/O 80K,RIH tagging bttm @ 5372'see pressure increase, P/U to 5369',stage pump to 5 bpm, 640 psi,work pipe 7'until B/U.,Note:swivel packing on cmt head leaking, BOT expediting another swivel f/shop,at BU,B/0 cement head,install FOSV and head pin,continue to circulate 2 bpm 180 psi, Remove old swivel. R/D head pin and FOSV,M/U top drive,circulate 2 bpm,180 psi,reciprocate pipe 30'while waiting on swivel to arrive.Swivel on location @ 00:30,M/U same, pump 5 bpm,640 psi,good,PJSM for cement job,pump 10 bbls water,3/4 bbl to fill line,Shut in TIW,pressure test lines to 500/4500 psi,good.Bleed off pressure,open TIW.Pump 20 bbls 10 ppg tunned spacer 2.5 bpm,320 psi,add poly flake in 1st 10 bbls spacer.Pump 25 bbls 15.8 ppg type I-II cement 2.5 bpm,305 psi,shut down,flush lines,cleanup cementers. Drop wiper dart.,Swap to rig,displace cement w/9.2 ppg mud 5 bpm,140 psi,30 bbls away caught cement,45 bbls away slow pump to 3 bpm,500 psi,48.7 bbls away,latch up dart in LWP. 2400 psi shear,Bump plug 54.2 bbls away,3.1 bbls under calculated,CIP @ 03:42, Pressure to 3200 psi,S/0 35k block wt.to confirm hanger set. 14.7 bbls mix water,125 sx cement.,R/U test pump,pressure to 4200 psi to release running tool from liner,bleed off pressure,check float,good.P/U 7'to expose dog sub,S/O set ZXP,seen shear 29k down.,R/D lines and confirm rotation 20 rpm,7300 tq,down wt 84k,S/0 to 35k,Pressure to 500 psi, P/U 12' est circ,P/U 30'CBU 4.5 bpm,530 psi, 15 bbls cement and 20 bbls spacer returned to surface. Liner top @ 4880.18,shoe @ 5369.40. Daily losses to formation 0 bbls,total losses 7 bbls,Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 107 bbls to G&I for total=6378 bbls Hauled 0 bbls water F/6 mile lake for total=8695 bbls 2/10/2017 Continue to circulate through TD @ 8.5 BPM,140 SPM,1020 PSI.UPwt 70, ROT 77K 50 RPM,8K TQ. Circ&treat mud to 55 vis.,BDTD,R/U Testing equipment. Test liner and liner lap to 1500 psi for 10 min Good.Bled 20 PSI. Blow down surface lines&R/D Same.,POOH F/4800'T/LRT. Inspect&UD LRT.Good.,Drain stack,Flush out BOPs&Surface equipment with black water. Function all rams. Wash stack with Johnny whacker.,P/U 3.75 Mill,4.5 Scraper,13 Joints of 2 7/8 Fox tubing.,7"Casing scraper,4"HT 38 Dp T/4800'. Take parameters Before entering Liner top,P/U 103K,S/O 70K„No issues entering TOL 4880',RIH to 5068',M/U top drive,wash 2 bpm,370 psi f/5068'to 5284'tagging top of landing collar on depth.,P/U 4',Circulate BU @ 5280 pumping 4 bpm,850 psi,some clabbored mud @ BU,rack 1 std back parking @ 5262',blow down top drive.,M/U FOSV,head pin and swivel,flood lines,close upper pipe ram,pressure up and test 7”x 4 1/2"casing thru kill line and down DP to 3500 psi for 30 charted min, good test. Pumped 2.3 bbls,2.2 bbls bled back.Open upper pipe ram,blow down choke.R/D test equip.,Note:UIC inspector with EPA on location to witness test.,M/U std and top drive,park pipe just above LC @ 5282',load trip tank 1 and pit 2 w/8.5 ppg seawater,clean under shaker.,Pump 40 bbl 180 vis spacer,displace well to 8.5 ppg seawater 4 bpm,750 psi,blow down top drive.,POOH f/5282'to 415'scraping 4 1/2"to TOL @ 4880' and 7"casing to surface,while POOH vac out drlg mud from pits 4&5,inspect scraper.,Service top drive,blocks and draworks.,Daily losses to formation 0 bbls,total losses 7 bbls,Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 442 bbls to G&I for total=6820 bbls Hauled 0 bbls water F/6 mile lake for total=8695 bbls 2/11/2017 Finish rig service.RIH with 4"DP T/5284'.,Pump wash train,50 bbl Baraclean Pill,50 BBL Caustic Pill,50 BBL high vis Spacer,chase with seawater to surface. Over displace by one string volume. Circ @ 7 bpm 1650 psi.,POOH F/5284'T/416'.Inspect 7"scraper.Good.RIH T/5284'.,Line up to reverse circ. Close top rams. Pump down annulus @ 6 bpm 1350 psi. Displace with 1.5 hole volumes with clean seawater.,Blow down top drive,POOH racking 4"DP in derrick f/5284'to 420', UD XOs and 7"casing scraper, R/U 2 7/8"handling equip.POH UD 2 7/8"work string,XOs,4 1/2"scraper and 3 3/4"flat bttm mill.,Clear scraper tools from rig floor,load polish tools to rig floor.Change to 4"handling equipment.,Rig service,service elevators,pipe spinners and top drive.,M/U 5.15"TBR polish mill,2 spacer subs,5.73"TBR top dress mill,pup and X0=21.88',Spaceout between mills 9.88', RIH w/4"DP to 4861',M/U top drive.Pump 2 bpm,60 psi. P/U 96K,S/0 80K, ROT 85K,30 rpm,4K tq.,RIH entering 4 1/2 liner top @ 4880', dry tag @ 4891',11'in liner top,P/U to 4876',pump 2 bpm,60 psi,30 rpm,4k tq,polish seal bore to 4891'and LT @ 4880'3 times setting down 10k,7k and 3k per BOT rep. P/U to 4865',rack 1 std back,blow down top drive,POOH UD 4"DP f/4865'to 2300',Hauled 590 bbls to GPB G&I for total=590 bbls Hauled 399 bbls to G&I for total=7219 bbls Hauled 300 bbls water F/6 mile lake for total=8995 bbls Daily losses to formation 0 bbls,total losses 7 bbls • . �� Cry 2/12/2017 L/D 4"DP F/2099'T/Surface. RIH with remaining 4"DP F/Derrick TI 558'. POOH L/D Same to surface.,Service Rig. Remove hyd Elevators&Install Guards on TD.,R/U Pollard Wire Line. RIH T/5284'&Lo5 4 5 Liner T/4880'. Make two,passes to verify log.,Good. POOH&R/D Pollard Wire line.,Clean and clear rig floor, R/u Weatherford 4.5 Tubing equipment. Tongs,Slips, DC, Proper Dope for Geoconn.,Conduct PJSM for running 4.5,13.5# Geoconn tubing. Go over running tally and procedure for running Geoconn. P/U&Inspect seals.Good. Ports 1.6'From Mule Shoe. Run in three joints. Run R Nipple in between joint 3&4. RIH T/4879' (112 jts Make Joints up to mark&Shoulder out @ 5200#). P/U 90K,S/0 70K,C/O to 4"elevators.M/U XOs,jt 4"DP and top drive, Pump 2 bpm,40 psi,S/0 entering TOL @ 4881',pressure increased to 100 psi.shut off pump, Bleed off pressure,S/O 8.5'in to 4891.57'mule shoe depth,set down 10k„Blow down top drive.L/D single DP,C/O to 4 1/2"elevators, L/D jts 112 and 111,space out with 2-10.15'pups,and 1=2.27'pup,M/U jt 111,C/O to 4"elevators,M/U pup jt and hanger per wellhead rep,M/U X0,JT 4"DP f/ landing jt with pump in sub and pup jt on top,M/U top drive,close IBOP.,P/U circ hose, PJSM,pump 2.5 bpm,50 psi,circulate down and locate seals @ 17.5'in on landing jt, P/U 1'to expose ports, R/U LRS to pump down annulus,test lines to 3000 psi.close annular.Rev circulate,pump 31.6 bbls diesel 3 bpm,350 psi slowing to 2 bpm,450 psi.Swap to rig pump,rev circulate 38.4 bbls,2.5 bpm200 psi,followed w/49.6 bbls corrosion inhibitor,swap to LRS, pump 40.9 bbl diesel 2 bpm,500 psi,Freeze protecting tbg and I/A to 2200',spotting corrosion inhibitor in I/A from 2200'to 4870',Close annulus valve,set down 1.5'sealing ports,bleed off pressure,open annular.,Drain stack,flush out lines. Land hanger, RILDS per hanger rep.Mule shoe @ 4889.37',(38k on hanger)seals 1.22'from fully locating.,R/U test pump,pressure test tbg to 3500 psi w/diesel for 30 min charted,monitor tbg and 0/A, 1.68 bbls pumped, 1.66 bbls bled back.good R/U and pressure test I/A with diesel,pressure to 3500 psi f/30 min charted.Monitor tbg and 0/A, 1.87 bbls pumped, 1.85 bbls bled back.good. Note: UIC inspector on_locationto,wdness,MIT s. te ,Back out and pull landing jt,set TWC per wellhead rep, L/D Landing jt,pump in sub and XOs,flush lines, R/D power tongs,Hauled 0 bbls to GPB'Gil for total=590 bbls Hauled 0 bbls to G&I for total=7219 bbls M j Hauled 0 bbls water F/6 mile lake for total=8995 bbls 1 Daily losses to formation 0 bbls,total losses 7 bbls 2/13/2017 Flush out stack&lines. Remove choke&kill lines. N/D BOPS, N/U adapter&Dry hole tree.Test void to 3000 psi. EPA rep Jason Selitsch on location to witness test. Prep for rig move to B-32. Note:2 spills,(03:00hrs 1 gallon diesel in secondary containment in choke house)and(11:00hrs 47 gallons diesel in secondary containment in pipe shed) Rig released @ 14:00 hrs,Working on B-32 Report. 4/3/2017 MIRU Pollard E-Line. PU lubricator with GR/CCL tools.Stab on well.PT. 1st PT failed-loose lubricator collar-C/0 0-ring.2nd PT passed to 250 psi/3000 psi.,RIH with GR/CCL.Tag at-5,284'elmd uncorrected. Log up to surface at 48 fpm.Tie into Halliburton MD log dated 24-Jan-2017. -5'depth shift showing PBTD at 5279'ELMD corrected.,00H. Arm and PU 20'gun-3-1/8"OD,6 SPF,60 degree phasing, DP charges. CCL to top shot=7.8',to bottom shot= 27.8',to bottom of gun=28.5',RIH with gun run#1.Tag PBTD,make correlation pass from PBTD to 5000'.Tie into Hal MD log and GR/CCL correlation log. RBIH,tag, log up to firing position. Stop at 5216.2'CCL deptilto shoot interval 5224'to 5244'. Fir un,good indication.WHP went from 0 psi to 250 psi. Line weight 850 lbs to 500 lbs. Log off depth and POOH,O0H. L/D spent gun,ASF.Arm and PU 2nd 20'gun-3-1/8"OD,6 SPF,60 degree phasing, DP charges. CCL to top shot=7.8',to bottom shot=27.8',to bottom of gun=28.5',Open well to 225 psi WHP. RIH with gun run#2. Tag. Log up for correlation pass to 5000'. Tie into Hal MD log and GR/CCL correlation log. Make-4.5'depth shift. PBTD now at 5258.5' -20'of fill dumped in from 1st gun fire. RBIH. Tag,log up to firing position.Stop at 5196.1'CCL depth to shoot interval 5204'-5224'. Fire gun.WHP>225 to 240 psi,line wt 1700 lbs to 700 lbs. Log off depth and POOH.,00H. L/D spent gun,ASF. RDMO E-Line equipment.Secure well. Notify Pad OP of well status. ***Job Complete"`,No Activity 4/4/2017 MIRU Slickline unit.RIH with a 3.7"OD GR.Tag R-Nipple at 4,374'ELM for depth control. POOH.MU and RBIH with 2"sample catcher.Tag top of fill and correct depth. Found top of fill at 5246'corrected to ELM-2'below bottom pert. Perfs at 5204'-5244'ELM. POOH.Prepare to RBIH with bailer.Winds exceeding 30+mph.SDFN due to weather.,No Activity,LRS Well Testing arrive on site.Start RU 3"hardline from tree cap of B-24 to tree cap of B-34 for step rate test. Install Flowcross with valve on 6-34 to allow wireline work while injecting. 4/5/2017 Complete RU of 3"1502 hardline from 13-24 to B-34. PT same to 3000 psi.Good.,PJSM with G&I personnel,walk injection lines and flow path to B-34 via B- 24.Review pump schedule.Start step rate test wl_Ball mill pumps pumping source water from G&I ,1.7 bpm/304 psi tubing/400 psi IAP/0 psi OAP,Step Rate Test ti 1.7 bpm for 50 bbls T/I/O=339/400/0 K 2 bpm for 50 bbls T/I/O=1640/730/40 1) /`��� 4 bpm for 50 bbls T/I/0=1600/910/40 6 bpm for 50 bbls T/110=1720/960/50 >f,(/ 7.8 bpm for 50 bbls T/I/0=1835/1040/50. Shut down,274 bbls pumped.Monitor pressure till stable.Stable after 1 hr at 145 psi. Freeze protect B-34 and injection line back to G&I,No Activity until upcoming Water flow log. 4/9/2017 MIRU SLB E-Line. PJSM. MU toolstring and perform surface checks.On well. PT to 450 psi/3500 psi.Good,BEGIN RIH(BARRIERS=GREASEHEAD/ LUBRICATOR-CONTINGENT/SECONDARY=SWAB/WLVS)TOOLSTRING: HEAD(6X3)I SWIVEL/6'X1-11/16"WEIGHT BAR/PBMS/TUBING GUIDE/RST/TUBING GUIDE.OAL=47',TOOL WEIGHT=260#. MAKE TEMP BASELINE PASS DOWN TO TD AT 120 FPM.VERIFY MINITRON TOOL WORKING AND RELIABLE.,AT BOTTOM. PERFORM TIE IN n 6 LOG.LOG CORRELATED TO HALIBURTON MD LOG DATED 09-FEBRUARY-2017. PUT WELL ON INJECTION AT 11,500 BPD-110 DEG F.-1690 PSI i�-•�v WHP.PERFORM STATION STOPS AT 5150',5000',4950',4900',4850',4800'. PERFORM SLOW,NORMAL,AND FAST STATION CYCLES AT EACH STOP. „LOG 5237'TO 4625'ZONE OF INTEREST. SHUT IN INJECTION.,MAKE 3 WARMBACK PASSES WITH 2 HRS BETWEEN EACH PASS FROM 4650' TO 5237'ELM.,POOH,BEGIN RD E-LINE. 4/10/2017 COMPLETE RD OF SLB E-LINE EQUIP. DEPART LOCATION.WELL SHUT IN AND SECURE.,NO ACTIVITY,MIRU LRS FOR MITIA. EPA witnessed M,ITIA to 3500 psi passed. Lost 116 psi in 1st 15 min and 24 psi in 2nd 15 min.Total loss of 140 psi. Freeze protect tubing with 40 bbls 60/40 ti • • Hilcorp Alaska, LLC Milne Point M Pt B Pad MPU B-34 50-029-23569-00-00 t: Sperry Drilling Definitive Survey Report 10 February, 2017 HALLIBURTON 1111 Sperry Drilling • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-34 Project: Milne Point TVD Reference: Actual:@ 50.60usft Site: M Pt B Pad MD Reference: ..„ _ , = Actual:@ 50.60usft Well: MPU B-34 North Reference: ' .; True Wellbore: MPU B-34 Survey Calculation Method: Minimum Curvature Design: MPU B-34 Database: Sperry EDM-NORTH US+CANADA Project Milne Point,ACT,MILNE POINT 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 04 Using geodetic scale factor Well MPU B-34 .. Well Position +N/-S 0.00 usft Northing: 6,023,979.35 usft Latitude: 70°28'32.874 N +E/-W 0.00 usft Easting: 571,983.88 usft Longitude: 149°24'43.080 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 23.70 usft Wellbore MPU B-34 Magnetics Model Name Sample Date Declination Dip Angle ' Field Strength ��ra (°) (°) ,.1tv _.. (nT) 5 ^; BGGM2016 1/16/2017 17.95 81.06 57,561 Design MPU B-34 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 26.90 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (°) 26.90 0.00 0.00 353.00 Survey Program Date 2/9/2017 From To (usft) (usft) Survey(Wellbore) Tool Name Description Survey Date 100.00 1,069.00 MPU 8-34 SRG-SS(MPU B-34) SRG-SS Surface readout gyro single shot 01/16/2017 1,129.85 2,635.58 MPU B-34 MWD+IFR2+MS+sag(1)(MP MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 01/27/2017 2,709.37 5,024.90 MPU B-34 MWD+IFR2+MS+sag(2)(MP MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 02/06/2017 5,087.98 5,333.09 MPU B-34 MWD+IFR2+MS+sag(3)(MP MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 02/09/2017 S ey ;,r Map Map Vertical MD ' Inc Azi TVD TVDSS +N/-S +E/-W Northing EastingDLS Section ' (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 26.90 0.00 0.00 26.90 -23.70 0.00 0.00 6,023,979.35 571,983.88 0.00 0.00 UNDEFINED 100.00 0.09 156.02 100.00 49.40 -0.05 0.02 6,023,979.30 571,983.90 0.12 -0.05 SRG-SS(1) 168.00 0.39 145.55 168.00 117.40 -0.29 0.18 6,023,979.06 571,984.06 0.44 -0.31 SRG-SS(1) 199.00 0.45 107.82 199.00 148.40 -0.42 0.35 6,023,978.94 571,984.24 0.90 -0.46 SRG-SS(1) 261.00 0.53 85.91 261.00 210.40 -0.47 0.87 6,023,978.89 571,984.75 0.33 -0.57 SRG-SS(1) 323.00 1.34 14.04 322.99 272.39 0.25 1.33 6,023,979.62 571,985.21 2.06 0.09 SRG-SS(1) 384.00 3.46 356.51 383.93 333.33 2.78 1.39 6,023,982.15 571,985.25 3.64 2.59 SRG-SS(1) 447.00 5.96 2.92 446.72 396.12 7.95 1.44 6,023,987.31 571,985.25 4.05 7.71 SRG-SS(1) 510.00 8.44 7.72 509.21 458.61 15.80 2.23 6,023,995.17 571,985.96 4.05 15.41 SRG-SS(1) 572.00 10.86 5.31 570.33 519.73 26.12 3.38 6,024,005.50 571,987.01 3.96 25.52 SRG-SS(1) 632.00 13.30 5.90 629.00 578.40 38.62 4.62 6,024,018.01 571,988.12 4.07 37.77 SRG-SS(1) 2/10/2017 12:35:20PM Page 2 COMPASS 5000.1 Build 81 To i • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-34 Project: Milne Point TVD Reference: Actual:@ 50.60usft Site: M Pt B Pad MD Reference: Actual:@ 50.60usft Well: MPU B-34 North Reference: True Wellbore: MPU B-34 Survey Calculation Method: Minimum Curvature Design: MPU B-34 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (I) (°) (usft) (usft) (usft) (usft) (ft) (ft) (1/100') (ft) Survey Tool Name 695.00 16.97 3.27 689.80 639.20 55.01 5.89 6,024,034.41 571,989.23 5.93 53.88 SRG-SS(1) 756.00 21.20 2.71 747.44 696.84 74.92 6.92 6,024,054.33 571,990.07 6.94 73.52 SRG-SS(1) 819.00 25.16 1.50 805.34 754.74 99.70 7.80 6,024,079.11 571,990.72 6.33 98.01 SRG-SS(1) 882.00 28.46 358.80 861.56 810.96 128.11 7.84 6,024,107.51 571,990.48 5.58 126.19 SRG-SS(1) 944.00 32.00 357.43 915.12 864.52 159.30 6.79 6,024,138.69 571,989.13 5.82 157.28 SRG-SS(1) 1,007.00 32.66 354.44 968.36 917.76 192.89 4.40 6,024,172.26 571,986.41 2.75 190.92 SRG-SS(1) 1,069.00 33.88 351.58 1,020.20 969.60 226.64 0.25 6,024,205.96 571,981.93 3.21 224.92 SRG-SS(1) 1,129.85 33.82 348.35 1,070.74 1,020.14 260.01 -5.66 6,024,239.27 571,975.71 2.96 258.76 MWD+IFR2+MS+sag(2) 1,193.18 33.52 348.34 1,123.45 1,072.85 294.39 -12.75 6,024,273.58 571,968.28 0.47 293.75 MWD+IFR2+MS+sag(2) 1,255.82 36.20 348.43 1,174.84 1,124.24 329.46 -19.96 6,024,308.57 571,960.74 4.28 329.44 MWD+IFR2+MS+sag(2) 1,318.28 37.36 349.23 1,224.87 1,174.27 366.15 -27.20 6,024,345.19 571,953.15 2.01 366.74 MWD+IFR2+MS+sag(2) 1,381.06 39.31 350.71 1,274.11 1,223.51 404.49 -33.97 6,024,383.46 571,946.00 3.43 405.62 MWD+IFR2+MS+sag(2) 1,443.46 39.58 351.92 1,322.30 1,271.70 443.68 -39.95 6,024,422.58 571,939.64 1.31 445.24 MWD+IFR2+MS+sag(2) 1,506.76 40.71 352.57 1,370.69 1,320.09 484.12 -45,46 6,024,462.96 571,933.75 1.90 486.05 MWD+IFR2+MS+sag(2) 1,569.40 40.79 353.01 1,418.14 1,367.54 524.68 -50.59 6,024,503.47 571,928.22 0.48 526.94 MWD+IFR2+MS+sag(2) 1,632.43 40.66 353.47 1,465.91 1,415.31 565.52 -55.43 6,024,544.25 571,922.99 0.52 568.06 MWD+IFR2+MS+sag(2) 1,694.43 40.55 354.50 1,512.98 1,462.38 605.65 -59.66 6,024,584.34 571,918.37 1.10 608.41 MWD+IFR2+MS+sag(2) 1,756.29 41.87 351.24 1,559.52 1,508.92 646.07 -64.73 6,024,624.71 571,912.91 4.07 649.15 MWD+IFR2+MS+sag(2) 1,820.29 42.67 350.00 1,606.88 1,556.28 688.54 -71.75 6,024,667.10 571,905.48 1.81 692.16 MWD+IFR2+MS+sag(2) 1,882.49 41.50 350.68 1,653.04 1,602.44 729.64 -78.75 6,024,708.13 571,898.09 2.02 733.80 MWD+IFR2+MS+sag(2) 1,945.93 41.83 351.37 1,700.44 1,649.84 771.30 -85.33 6,024,749.71 571,891.11 0.89 775.95 MWD+IFR2+MS+sag(2) 2,008.12 41.97 351.51 1,746.72 1,696.12 812.37 -91.51 6,024,790.72 571,884.53 0.27 817.46 MWD+IFR2+MS+sag(2) 2,071.42 40.92 351.14 1,794.17 1,743.57 853.78 -97.83 6,024,832.07 571,877.81 1.70 859.34 MWD+IFR2+MS+sag(2) 2,134.66 40.06 350.80 1,842.27 1,791.67 894.34 -104.27 6,024,872.55 571,870.98 1.40 900.38 MWD+IFR2+MS+sag(2) 2,197.74 41.29 352.12 1,890.11 1,839.51 934.99 -110.37 6,024,913.14 571,864.48 2.38 941.47 MWD+IFR2+MS+sag(2) 2,260.59 40.58 352.39 1,937.59 1,886.99 975.80 -115.92 6,024,953.89 571,858.54 1.16 982.65 MWD+IFR2+MS+sag(2) 2,324.08 39.87 351.83 1,986.06 1,935.46 1,016.41 -121.55 6,024,994.44 571,852.52 1.25 1,023.65 MWD+IFR2+MS+sag(2) 2,386.34 40.57 353.56 2,033.60 1,983.00 1,056.28 -126.65 6,025,034.26 571,847.03 2.12 1,063.84 MWD+IFR2+MS+sag(2) 2,449.10 41.02 354.08 2,081.12 2,030.52 1,097.05 -131.07 6,025,074.98 571,842.22 0.90 1,104.84 MWD+IFR2+MS+sag(2) 2,511.68 39.78 353.85 2,128.77 2,078,17 1,137.38 -135.33 6,025,115.26 571,837.57 2.00 1,145.40 MWD+IFR2+MS+sag(2) 2,574.95 39.82 353.89 2,177.38 2,126.78 1,177.65 -139.65 6,025,155.48 571,832.86 0.08 1,185.69 MWD+IFR2+MS+sag(2) 2,635.58 39.65 354.19 2,224.01 2,173.41 1,216.20 -143.68 6,025,193.99 571,828.46 0.42 1,224.64 MWD+IFR2+MS+sag(2) 2,709.37 39.10 354.15 2,281.05 2,230.45 1,262.77 -148.43 6,025,240.50 571,823.25 0.75 1,271.45 MWD+IFR2+MS+sag(3) 2,741.54 38.65 354.08 2,306.09 2,255.49 1,282.85 -150.50 6,025,260.57 571,820.99 1.41 1,291.63 MWD+IFR2+MS+sag(3) 2,803.92 40.52 352.27 2,354.17 2,303.57 1,322.31 -155.24 6,025,299.98 571,815.87 3.52 1,331.38 MWD+IFR2+MS+sag(3) 2,867.38 40.04 352.10 2,402.58 2,351.98 1,362.96 -160.82 6,025,340.56 571,809.90 0.78 1,372.40 MWD+IFR2+MS+sag(3) 2,930.55 39.28 352.09 2,451.21 2,400.61 1,402.89 -166.36 6,025,380.44 571,803.97 1.20 1,412.71 MWD+IFR2+MS+sag(3) 2,992.48 40.63 351.93 2,498.68 2,448.08 1,442.28 -171.89 6,025,419.76 571,798.06 2.19 1,452.48 MWD+IFR2+MS+sag(3) 3,055.48 40.25 352.33 2,546.63 2,496.03 1,482.76 -177.49 6,025,460.18 571,792.08 0.73 1,493.34 MWD+IFR2+MS+sag(3) 3,105.17 39.69 351.67 2,584.71 2,534.11 1,514.37 -181.93 6,025,491.74 571,787.33 1.41 1,525.25 MWD+IFR2+MS+sag(3) 2/10/2017 12:35:20PM Page 3 COMPASS 5000.1 Build 81 • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-34 Project: Milne Point TVD Reference: Actual:@ 50.60usft Site: M Pt B Pad MD Reference: Actual:@ 50.60usft Well: MPU B-34 North Reference: True Wellbore: MPU B-34 Survey Calculation Method: Minimum Curvature Design: MPU B-34 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 3,180.20 39.02 351.29 2,642.73 2,592.13 1,561.42 -188.98 6,025,538.72 571,779.83 0.95 1,572.81 MWD+IFR2+MS+sag(3) 3,243.36 40.62 353.83 2,691.24 2,640.64 1,601.52 -194.20 6,025,578.77 571,774.22 3.61 1,613.25 MWD+IFR2+MS+sag(3) 3,306.13 41.28 354.47 2,738.65 2,688.05 1,642.44 -198.39 6,025,619.64 571,769.63 1.25 1,654.38 MWD+IFR2+MS+sag(3) 3,369.06 40.65 354.30 2,786.17 2,735.57 1,683.50 -202.42 6,025,660.66 571,765.20 1.02 1,695.62 MWD+IFR2+MS+sag(3) 3,432.35 40.39 354.22 2,834.28 2,783.68 1,724.42 -206.54 6,025,701.53 571,760.69 0.42 1,736.73 MWD+IFR2+MS+sag(3) 3,495.17 39.93 353.90 2,882.29 2,831.69 1,764.71 -210.73 6,025,741.78 571,756.11 0.80 1,777.24 MWD+IFR2+MS+sag(3) 3,558.64 41.38 353.60 2,930.44 2,879.84 1,805.82 -215.23 6,025,782.83 571,751.21 2.31 1,818.59 MWD+IFR2+MS+sag(3) 3,621.86 41.06 353.27 2,977.99 2,927.39 1,847.20 -219.99 6,025,824.16 571,746.05 0.61 1,860.24 MWD+IFR2+MS+sag(3) 3,684.99 41.14 352.61 3,025.57 2,974.97 1,888.39 -225.10 6,025,865.29 571,740.55 0.70 1,901.74 MWD+IFR2+MS+sag(3) 3,747.74 40.63 352.59 3,073.01 3,022.41 1,929.12 -230.39 6,025,905.97 571,734.87 0.81 1,942.82 MWD+IFR2+MS+sag(3) 3,810.48 40.46 351.23 3,120.68 3,070.08 1,969.49 -236.12 6,025,946.28 571,728.74 1.43 1,983.59 MWD+IFR2+MS+sag(3) 3,873.69 40.20 352.36 3,168.87 3,118.27 2,009.98 -241.96 6,025,986.71 571,722.51 1.23 2,024.49 MWD+IFR2+MS+sag(3) 3,936.31 40.06 352.18 3,216.75 3,166.15 2,049.98 -247.39 6,026,026.64 571,716.70 0.29 2,064.84 MWD+IFR2+MS+sag(3) 3,998.93 39.81 352.11 3,264.76 3,214.16 2,089.80 -252.89 6,026,066.40 571,710.82 0.41 2,105.04 MWD+IFR2+MS+sag(3) 4,062.43 41.55 352.35 3,312.92 3,262.32 2,130.81 -258.48 6,026,107.36 571,704.83 2.75 2,146.42 MWD+IFR2+MS+sag(3) 4,125.85 41.43 352.49 3,360.42 3,309.82 2,172.45 -264.02 6,026,148.94 571,698.88 0.24 2,188.44 MWD+IFR2+MS+sag(3) 4,188.10 41.03 351.96 3,407.24 3,356.64 2,213.10 -269.57 6,026,189.53 571,692.94 0.85 2,229.46 MWD+IFR2+MS+sag(3) 4,251.76 40.39 351.82 3,455.50 3,404.90 2,254.21 -275.43 6,026,230.58 571,686.69 1.02 2,270.97 MWD+IFR2+MS+sag(3) 4,313.90 40.23 351.52 3,502.88 3,452.28 2,293.98 -281.25 6,026,270.29 571,680.48 0.40 2,311.16 MWD+IFR2+MS+sag(3) 4,377.26 40.22 351.34 3,551.26 3,500.66 2,334.45 -287.35 6,026,310.69 571,673.99 0.18 2,352.06 MWD+IFR2+MS+sag(3) 4,441.62 39.78 350.66 3,600.56 3,549.96 2,375.31 -293.82 6,026,351.48 571,667.13 0.96 2,393.41 MWD+IFR2+MS+sag(3) 4,504.78 39.57 350.32 3,649.17 3,598.57 2,415.07 -300.48 6,026,391.18 571,660.08 0.48 2,433.69 MWD+IFR2+MS+sag(3) 4,568.21 37.04 349.54 3,698.94 3,648.34 2,453.78 -307.35 6,026,429.81 571,652.84 4.06 2,472.95 MWD+IFR2+MS+sag(3) 4,630.51 34.00 351.36 3,749.65 3,699.05 2,489.47 -313.37 6,026,465.43 571,646.47 5.17 2,509.10 MWD+IFR2+MS+sag(3) 4,693.40 32.22 351.77 3,802.32 3,751.72 2,523.45 -318.42 6,026,499.36 571,641.10 2.85 2,543.44 MWD+IFR2+MS+sag(3) 4,755.90 30.12 350.00 3,855.80 3,805.20 2,555.38 -323.52 6,026,531.24 571,635.69 3.67 2,575.76 MWD+IFR2+MS+sag(3) 4,819.57 27.53 349.16 3,911.57 3,860.97 2,585.57 -329.07 6,026,561.38 571,629.85 4.12 2,606.40 MWD+IFR2+MS+sag(3) 4,881.63 24.11 351.60 3,967.43 3,916.83 2,612.21 -333.62 6,026,587.96 571,625.04 5.77 2,633.39 MWD+IFR2+MS+sag(3) 4,944.59 21.09 352.99 4,025.55 3,974.95 2,636.18 -336.88 6,026,611.90 571,621.55 4.87 2,657.58 MWD+IFR2+MS+sag(3) 5,024.90 16.78 349.60 4,101.50 4,050.90 2,661.93 -340.74 6,026,637.61 571,617.44 5.54 2,683.62 MWD+IFR2+MS+sag(3) 5,087.98 15.53 347.99 4,162.09 4,111.49 2,679.15 -344.14 6,026,654.79 571,613.88 2.10 2,701.12 MWD+IFR2+MS+sag(4) 5,151.37 15.82 349.41 4,223.12 4,172.52 2,695.94 -347.49 6,026,671.55 571,610.36 0.76 2,718.20 MWD+IFR2+MS+sag(4) 5,213.94 16.26 349.56 4,283.25 4,232.65 2,712.94 -350.65 6,026,688.52 571,607.04 0.71 2,735.45 MWD+IFR2+MS+sag(4) 5,277.31 16.75 349.90 4,344.01 4,293.41 2,730.66 -353.86 6,026,706.20 571,603.66 0.79 2,753.43 MWD+IFR2+MS+sag(4) 5,333.09 17.01 350.73 4,397.39 4,346.79 2,746.62 -356.58 6,026,722.14 571,600.79 0.64 2,769.61 MWD+IFR2+MS+sag(4) 5,370.00 17.01 350.73 4,432.69 4,382.09 2,757.28 -358.32 6,026,732.78 571,598.94 0.00 2,780.40 PROJECTED to TD mitchell.laird@halliburton.com benjamin.hand@halliburton.com Checked By: 2017.02.10 0937:31-09'00' Approved By: 2017.021014s438w•00' Date: 2/10/2017 2/10/2017 12.35:20PM Page 4 COMPASS 5000.1 Build 81 • • Hilcorp Energy Company CASING &CEMENTING REPORT Lease&Well No. MP B-34 Date Run 29-Jan-17 County State Alaska Supv. J.Lott/S.Barber CASING RECORD 1 Surface • TD 2,675.00 Shoe Depth: 2,672.16 PBTD: 2,595.34 No.Jts.Delivered 67 No.Jts.Run 67 No.Jts.Returned Length Measurements W/O Threads Ftg.Delivered 2,672.00 Ftg.Run 2,672.00 Ftg.Returned Casing(Or Liner)Detail Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top Shoe 10 3/4 DWC/C Downhole Products 1.69 2,672.16 2,670.47 2 Casing 9 5/8 40.0 L-80 DWC/C Tenaris 73.41 2,670.47 2,597.06 Float Collar 10 3/4 DWC/C Downhole Products 1.72 2,597.06 2,595.34 65 Casing 9 5/8 40.0 L-80 DWC/C Tenaris 2,602.08 2,595.34 26.65 Csg Wt.On Hook: 185,000 Type Float Collar: Conventional float collar No.Hrs to Run: 15.5 Csg Wt.On Slips: 150,000 Type of Shoe: Conventional Bull Nose Float Casing Crew: WOT Rotate Csg X Yes No Recip Csg X Yes No 40 Ft.Min. 9.4 PPG Fluid Description: Spud Mud Liner hanger Info(Make/Model): Liner top Packer?: _Yes No Liner hanger test pressure: Floats Held X Yes No Centralizer Placement: CEMENTING REPORT Shoe @ 2672.16 FC @ 2,595.34 Top of Liner Preflush(Spacer) Type: Tuned Spacer Ill Density(ppg) 10.5 Volume pumped(BBLs) 54 Lead Slurry Type: Perm"C"cement Sacks: 1965 Yield: 0.96 Density(ppg) 15.6 Volume pumped(BBLs) 335 Mixing/Pumping Rate(bpm): 5 Tail Slurry w Type: Sacks: Yield: a Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): 1— w Post Flush(Spacer) re Type: Density(ppg) Rate(bpm): Volume: E Displacement: Type: Spud Mud Density(ppg) 9.4 Rate(bpm): 6 Volume(actual/calculated): 197.4/197.5 FCP(psi): 600 Pump used for disp: MP 1 Bump Plug? X Yes No Bump press 1250 Casing Rotated? Yes X No Reciprocated? X Yes No %Returns during job 100 Cement returns to surface? Yes X No Spacer returns? Yes X No Vol to Surf: 0 Cement In Place At: 19:50 Date: 1/29/2017 Estimated TOC: 560 Method Used To Determine TOC: Lift Psi Post Job Calculations: Calculated Cmt Vol @ 0%excess: 177.9 Total Volume cmt Pumped: 335 Cmt returned to surface: 0 Calculated cement left in wellbore: 335 OH volume Calculated: 143.07 OH volume actual: Actual%Washout: 172 www.wellez.net WellEz Information Management LLC ver_102716bf • • Hilcorp Energy Company CASING &CEMENTING REPORT Lease&Well No. Milne Point, B-34 Date Run 1-Feb-17 County Prudhoe Bay State Alaska Supv. S.Sunderland/S.Barber CASING RECORD Surface V TD 2,675.00 Shoe Depth: 2,672.16 PBTD: 2,595.34 No.Jts.Delivered No.Jts.Run No.Jts.Returned Ftg.Delivered Ftg.Run Ftg.Returned Length Measurements W/O Threads Ftg.Cut Jt. Ftg.Balance RKB 26.50 RKB to BHF RKB to CHF RKB to THF Top Job Pipe Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top 1"Hydril CS 1" 2.3 Weatherford 505' 505.00 CEMENTING REPORT Preflush(Spacer) Type: N/A Density(ppg) N/A Volume pumped(BBLs) N/A f S First Top o ype: Perm"L" Sacks: 305 Yield: 4.33 Density a•• 10.7 Volume pumped(BBLs) X236 ' Mixing/Pumping Rate(bpm): 1.5 ,2v9 econd Top Jo. .-• Perm"L" Sacks: 49 Yield: 4.33 p Density(ppg) 10.7 Volume pumped(BBLs) (...3Zi Mixing/Pumping Rate(bpm): 0.7 1- Post Flush(Spacer) aType: Density(ppg) Rate(bpm): Volume: o Displacement: Type: H2O Density(ppg) 8.34 Rate(bpm): 1.7 Volume(actual/calculated): 2-Feb FCP(psi): Pump used for disp: HES Bump Plug? Yes N/A No Bump press N/A Casing Rotated? Yes N/A No Reciprocated? N/A Yes x No %Returns during job 100 Cement retums to surface? X Yes No Spacer retums? Yes x No Vol to Surf: 17 bbls '✓ Cement In Place At: 18:40 Date: 2/1/2017 Estimated TOC: Surface Method Used To Determine TOC: Cmt returns to surface. Verified w/sample,PH monitor,and scale. Post Job Calculations: Calculated Cmt Vol @ 0%excess: 51 Total Volume cmt Pumped: 267 Cmt returned to surface: 17 Calculated cement left in wellbore: 250 OH volume Calculated: 22 OH volume actual: 221 Actual%Washout: 1004% t i.1 j, A51 Hilcorp Energy Company r CASING&CEMENTING REPORT 4 it Lease&Well No. MP B-34 Date Run 6-Feb-17 County State Alaska Supv. S.Sunderland /S.Barber CASING RECORD Intermediate • TD 5,070.00 Shoe Depth: 5,063.66 PBTD: 4,978.56 No.Jts.Delivered 126 No.Jts.Run 126 No.Jts.Returned Ftg.Delivered 5,032.56 Ftg.Run 5,032.56 Ftg.Returned Length Measurements W/O Threads Ftg.Cut Jt. Ftg.Balance 5,032.56 RKB RKB to BHF RKB to CHF RKB to THF Casing(Or Liner)Detail Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top Float Shoe 7 3/4 26.0 L-80 DWC/C DownHole Products 1.57 5,063.66 5,062.09 2 Casing 7 26.0 L-80 DWC/C 81.61 5,062.09 4,980.48 Float Collar 7 3/4 26.0 L-80 DWC/C Down Hole Products 1.92 4,980.48 4,978.56 97 Casing 7 26.0 L-80 DWC/C 3,790.39 4,978.56 1,188.17 Tam Port 7 3/4 DWC/C Tam 3.08 1,188.17 1,185.09 126 Casing 7 26.0 L-80 DWC/C 1,157.14 1,185.09 27.95 Pup Joint 7 26.0 L-80 DWC/C 3.42 27.95 24.53 Hanger 10 3/4 DWC/C 0.62 24.53 23.91 Csg VVt.On Hook: 100,000 Type Float Collar: Conventional No.Hrs to Run: 12 Csg Wt.On Slips: 65,000 Type of Shoe: Bull Nose Casing Crew: WOT Rotate Csg Yes X No Recip Csg X Yes No 20 Ft.Min. 9.2 PPG Fluid Description: Spud Mud Liner hanger Info(Make/Model): Liner top Packer?: _Yes _No Liner hanger test pressure: Floats Held X Yes_ No Centralizer Placement: 3 solid body turbolizers on jts 1-3. 1 ea bow spring turbolizer on jt 1. 56 ea bow spring turbolizers on jts 4-59. CEMENTING REPORT Shoe @ 5063.66 FC @ 4,978.56 Top of Liner Preflush(Spacer) Type: Tuned Spacer III Density(ppg) 10.5 Volume pumped(BBLs) 40 Lead Slurry Type: Type I Sacks: 345 Yield: 2.47 Density(ppg) 11.7 Volume pumped(BBLs) 151 ✓' Mixing/Pumping Rate(bpm): 4.7 Tail Slurry w Type: Type 1 Sacks: 130 Yield: 1.16 F Density(ppg) 15.8 Volume pumped(BBLs) �6t1' Mixing/Pumping Rate(bpm): 3.5 N Post Flush(Spacer) L 1 re Type: Density(ppg) Rate(bpm): Volume: LL Displacement: Type: Spud Mud Density(ppg) 9.2 Rate(bpm): 3 Volume(actual/calculated): 190.9/190.8 FCP(psi): 1240 Pump used for disp: #2 Rig Mud Pump Bump Plug? X Yes No Bump press 1880 Casing Rotated? Yes X No Reciprocated? X Yes-No %Returns during job 100 Cement returns to surface? X Yes No Spacer returns? X Yes No Vol to Surf: 20 Cement In Place At: 21:28 Date: 2/6/2017 Estimated TOC: 0 Method Used To Determine TOC: Visual/Scale/PH Post Job Calculations: Calculated Cmt Vol @ 0%excess: 129.6 Total Volume cmt Pumped: 201 Cmt returned to surface: 20 Calculated cement left in wellbore: 181 OH volume Calculated: 54.2 OH volume actual: 105.6 Actual%Washout: 95 WELLHEAD Make Seaboard Type 11",5M Multibowl Serial No. A33573-003 Size 11 W.P. 5000 Test head to 5000 PSIG 10 MIN OK OK Remarks: www.wellez.net WellEz Information Management LLC ver_102716bf • • Hilcorp Energy Company CASING &CEMENTING REPORT Lease&Well No. MPB-34 Date Run 9-Feb-17 County Milne Point State Alaska Supv. CASING RECORD 4.5"Liner TD 5,370.00 Shoe Depth: 5,369.00 PBTD: 5,244.00 Casing(Or Liner)Detail Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top 1 Shoe 5 HTTC DHP 1.59 5,369.00 5,367.41 1 Casing 41/2 13.5 L-80 HTTC 41.35 5,367.41 5,326.06 1 Float Collar 5 HTTC 1.15 5,326.06 5,324.91 1 Casing 41/2 13.5 L-80 HTTC 39.56 5,324.91 5,285.35 1 Landing Collar 5 BUT 0.84 5,285.35 5,284.51 14 Casing 41/2 13.5 L-80 HTTC 366.86 5,284.51 4,917.65 LTP 37.87 4,917.65 4,879.78 Csg Wt.On Hook: 5,000 Type Float Collar: DHP No.Hrs to Run: Csg Wt.On Slips: 5,000 Type of Shoe: DHP Casing Crew: Weatherford Rotate Csg Yes X No Recip Csg X Yes No Ft.Min. 9.2 PPG Fluid Description: WBM Liner hanger Info(Make/Model): ZXP LT Liner top Packer?: x Yes No Liner hanger test pressure: 1500 Floats Held x Yes No Centralizer Placement: Installed two centralizers on shoe joint,One cetralizer on FC joint and LC Joint. Placed one floating Cent on each joint after. CEMENTING REPORT Preflush(Spacer) Type: Tunned Spacer Density(ppg) 10 Volume pumped(BBLs) 20 Lead Slurry Type: Type I-II Sacks: 125 Yield: 1.12 Density(ppg) 15.8 Volume pumped(BBLs) 25 Mixing/Pumping Rate(bpm): 2.5 Tail Slurry Type: Sacks: Yield: Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): R Post Flush(Spacer) Type: Density(ppg) Rate(bpm): Volume: Displacement: Type: Mud Density(ppg) 9.2 Rate(bpm): 5 Volume(actual/calculated): 54.2/51.1 FCP(psi): Pump used for disp: Rig Bump Plug? x Yes No Bump press 2400 Casing Rotated? Yes x No Reciprocated? x Yes No %Returns during job 100 Cement returns to surface? x Yes No Spacer returns? x Yes No Vol to Surf: 15 bbls ./.- Cement Cement In Place At: 3:42 Date: 2/11/2017 Estimated TOC: 4,880 Method Used To Determine TOC: Returns to surface 4 MPB-34 FINAL Days vs Depth 0 —MPB-34 Actual -MPB-34 Plan 500 milmal -MPB-34 Stretch 1000 1500 2000 2500 a v 3000 U, N CO 3500 4000 4500 5000 5500 6000 0 5 10 15 20 25 30 Days • • MPB-34 MW vs Depth 0 MPB-34 Plan 1000 MPB-34 Actual 2000 3000 4000 5000 6000 s v 7000 3 8000 9000 10000 11000 12000 13000 14000 8.0 9.0 10.0 11.0 12.0 13.0 14.0 Mud Density(ppg) 2R.0 _1309k Et • 1111 Post Box Hilcorp Alaska,LLC Ancho a'ge,AK 995247 ��' 3800 Centerpoint Dr 6W Suite 1400 CERTIFIED MAIL Anchorage,AK 99503 Phone: 907/777-8300 March 12, 2017 Fax:907/777-8560 Mr. Edward J. Kowalski Director, Office of Compliance and Enforcement RECEIVED MAR g N17 U.S. Environmental Protection Agency 1200 Sixth Avenue A,OGGC Seattle, WA 98101 Mr. Chris Wallace Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501-3192 Mr. Marc Bentley Department of Environmental Conservation 555 Cordova St Anchorage, AK 99501 RE: Mechanical Integrity Test Notifications Northstar Class 1 Injection Wells, UIC Permit AK-1I002-B, General Wastewater., Permit No. 2005DB001-0020 Milne Point Injection Well, UIC Permit AK-11005-B, General Wastewater, Permit No. 2005DB001-0001 Liberty Class 1 Iniection_Well. UIC Permit AK-11013-A. General Wastewater. Permit No. 2005DB001-0025 Dear Sirs: Hilcorp Alaska, LLC (Hilcorp)respectfully submits the following notifications: 1) The annual Mechanical Integrity Test (MIT) and fluid movement tests that are required every two years at the Northstar NS 10 and NS32, Class 1 wells to meet the annual permit requirement in UIC Permit AK-11002-B; 2) The annual MIT and fluid movement logs that are required every three years at the Milne Point Class 1 wells, MPB-50, MPB-24 and MPB-34 to meet the permit requirement in UIC Permit AK-1I005-B; 3) The MIT and fluid movement test that is required at the Liberty Class 1 well to meet the permit requirement in UIC Permit AK-11013-A. Mechanical Into Test Notification March 12,2017 Page 2 of 2 By this letter Hilcorp is providing the written notification required by the aforementioned permits. In addition, Hilcorp staff will be coordinating the timeframes for these MITs with Mr. Evan Osborne of the Environmental Protection Agency (EPA) to maximize efficiencies associated with the travel arrangements of the EPA inspector, so that multiple tests of Class 1 wells can be witnessed in one trip to the North Slope. A summary of the proposed annual testing is presented in the attached table. The fluid movement test procedures that require EPA approval will be sent under separate cover or by email. If you have any questions or require additional information please call me at 907-782- 7431, or via e-mail at dheebner@hilcorp.com. Sincerely, Ck .4fi/elt eCittAgw— Deborah Heebner North Slope Environmental Specialist p HILCORP ALASKA,LLC Attachment cc: Evan Osborne, EPA Region 10 U.S. Environmental Protection Agency 1200 Sixth Avenue Seattle, WA 98101 Kyle Monkelien, BSEE Bureau of Safety and Environmental Enforcement Alaska OCS Region 3801 Centerpoint Drive Ste 500 Anchorage,AK 99503 Kevin Pendergast, BSEE Bureau of Safety and Environmental Enforcement Alaska OCS Region 3801 Centerpoint Drive Ste 500 Anchorage, AK 99503 Timothy Mayers, EPA Region 10 Jason Selitsch, Denali Environmental • • Proposed Schedule for 2017 Mechanical Integrity Testing Class I Well (s) MIT Proposed MIT test Flexibility in Fluid Movement Deadline date test date? Logs Planned after MIT? Northstar NS10 By July 6, Approximately July 5- Coordinate with No Fluid 2017 10, 2017. Milne test date. movement logs are planned as (May be they are required extended up at NS10 every to 3 months two years. with Director Previously done approval) on 7/7/2016. Northstar NS32 By July 8, Approximately July 5- Coordinate with No Fluid 2017 10, 2017 Milne test date. movement logs are planned as (May be they are required extended up at NS32 every to 3 months two years. with Director Previously done approval) on 7/9/2016. Milne Point By July 10, Approximately July 10- Coordinate with Fluid movement MPB-24 2017 15, 2017. Northstar test logs are planned date. even though logs were previously done on 7/23/2015. This will get MPB-24 on the same schedule as MPB-50. Milne Point By July 10, Following the Well's Coordinate with The Mechanical MPB-34 2017 Completion Evan Osborne Integrity Testing and Jason and Fluid Selitsch with Movement Logs EPA will be done following the Well's completion Milne Point By July 10, ApproximatelyJuly 10 - Coordinate with Fluid movement MPB-50 2017 15, 2017. Northstar test logs are planned date. as they are required for MPB- 50 every three years. Previously done on 7/24/2014. Liberty CRI Well N/A The Liberty CRI well All logs required will not be drilled in to complete the 2017. well would be scheduled with the MIT. 11111.1111.11111111111.11.111MMIMITIMMIMMIMIIIMMIMIMM • OF 77, Alaska Oil and Gas �\\ 1�j,�� THE STATE F o f LASKA Conservation Commission 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 LASIJ.' Fax: 907.276.7542 �✓ www.aogcc.alaska.gov Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage,AK 99503 Re: Milne Point Field,Undefined WDSP Pool, MPU B-34 Permit to Drill Number: 216-139 Sundry Number: 317-118 Dear Mr. York: Enclosed is the approved application for 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, Cathy P. Foerster Chair DATED this ZZ day of March, 2017. RBDMS i+i- L 3 2017 • • RECEIVED STATE OF ALASKA BAR 1 7 2.011 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 13'7 3 Z/ 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑✓ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program p 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 ❑ 216-139 - 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic ❑ Service 0. 6.API Number: Anchorage Alaska 99503 50-029-23569-00-00 • 7. If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? 20 AAC 20.055 • Will planned perforations require a spacing exception? Yes ❑ No El / MILNE PT UNIT B-34 • 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL047438 . Milne Point Unit/Undefined WDSP 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): 5,370' . 4,433' , 5,284' . 4,350' , 1,440 5,284' N/A Casing Length Size MD TVD Burst Collapse Conductor 113' 20" 107' 107' N/A N/A Surface 2,672' 9-5/8" 2,672' 2,252' 5,750psi 3,090psi Production 5,064' 7" 5,064' 4,139' 7,240psi 5,410psi Liner 489' 4-1/2" 5,369' 4,432' 9,020psi 8,540psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic/ See Attached Schematic 4-1/2" 13.5/L-80/Geo Con 4889 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): 7"x 4-1/2"ZXP LTP and N/A . 4,880(MD)/3,966(TVD)and N/A 12.Attachments: Proposal Summary ❑✓ Wellbore schematic 0 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: C,css Ji Commencing Operations: 3/30/2017 OIL ❑ WINJ ❑ Disposal 0 • Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved sp herein will not be deviated from without prior written approval. Contact Stan Porhola Email sporholaia'�.hilcorp.com Printed Name �/ Bo York Title Operations Manager Signature /mac G` f c - Phone 777-8345 Date 3/15/2017 //J COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: kl- \\4� Plug Integrity ❑ BOP Test El Mechanical Integrity Test Location Clearance ❑ -- ' 1 -xi 4 Other: In,Gckev. of a pel a Llo- S 'ro e. fCC Ce (.vi 7t, EIA CIU./1 ecryv1il , Owl,d11k fat-0 c i-e y 1. ON-VO Post Initial Injection MIT Req'd? Yes No ❑ Spacing Exception Required? Yes ❑ Nod Subsequent Form Required: ! O -4t07- Q APPROVED BY 7 Approved by: ` COMMISSIONER THE COMMISSION Date: 3_ZZ_(.ettia / J/ / - ,/��7' ,- S- i-i 7 3�� Submit Form and Form 10-403 Revised 11/20150 JicAoij is valid for 12 months fro the date of approval. / / attachments in Duplicate • • Well Prognosis Well: MPB-34 Flilcorp Alaska.LL Date: 3/16/2017 Well Name: MPB-34 API Number: 50-029-23569-00-00 Current Status: SI (Unperforated) Pad: B-Pad Estimated Start Date: March 30th, 2017 Estimated Duration 3 days • Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: 3/30/2017 Regulatory Contact: Tom Fouts Permit to Drill Number: 216-139 _ First Call Engineer: Stan Porhola (907) 777-8412 (0) (907) 331-8228 (M) Second Call Engineer: Wyatt Rivard (907) 777-8547 (0) (509) 670-8001 (M) iNumb;aNii'; ' , 16126540 Job Type. 'ORM;Ill ol" P rfor tine- Current Bottom Hole Pressure: 0 psi @ 4,274'TVD (No perforations) Max Bottom Hole Pressure: "' 1,867 psi @ 4,274'TVD (Estimated SBHP/8.4 ppg EMW) Max. Proposed Surface Pressure: — 1,440 psi (0.1 psi/ft gas gradient) Max Deviation: 42 deg at 1,820' MD Min ID: 3.688" (R Nipple @ 4,742' MD) Reference Log: To be run before perforating ! Brief Well Summary: The Milne Point B-34 well was drilled and completed in February 2017 as an EPA Class 1 Disposal well.The well will provide backup capacity for G&I injection currently taking place on the MPB-24 disposal well. Following completion of the 4-1/2" liner and production tubing strings,the well had a passing MIT-IA to 3,500 psi.Thp-well nulin is ready for perforations into the U preparation for initial injection and compliance testing. �/ Area of Review — MPB-34 Disposal Injection Well This AOR found no wells withinY4 mile of MPB-34's entry into the Ugnu formation. The table below illustrates the completion details and integrity conditions of the MPB-34 well. Table 1: Wells within AOR Well Name PTD Distance, Ft.'' Annulus Integrity Surface 9-5/8" casing ran to 2,672' and cemented back to surface. 9-5/8" tested to 2,950 psi on 2/02/17. Production 7" casing ran to 5,064' and cemented to 2,660' (based on, CBL). 7"tested to 3,600 psi on 2/07/17.4-1/2" liner(184' MPB-34 216-139 N/A overlap 4-1/2" x 7") ran to 5,369' cemented to the liner top (based on CBL). Test Liner top packer to 1,500 psi on 2/10/17.4-1/2"tubing stabbed into liner top.Tubing tested to 3,500 psi on 2/13/17. MIT-IA of 3500 psi was performed on 2/13/17 to confirm tubing and casing integrity. • • Well Prognosis Well: MPB-34 ililcoro Alaska.LL' Date:3/16/2017 E-Line Objective: Complete initial perforations in Ugnu MD sands for Class I Disposal operations. E-line Procedure: 1. MIRU E-line, PT lubricator to 250psi low/2,000psi high. 2. RIH w/GR/CCL and log from PBTD to surface for jewelry/correlation log. 3. RU 3-1/8" 12 spf Big Hole guns (2 ea 20' guns). 4. RIH to perforate Ugnu MD from 5,204'-5,244' (in 2 runs). a. Perforate intervals based on signed "Final Approved Perforation Request Form"TBD. b. Correlate using GR/CCL log from run prior to perforating. c. Consult Geologist Kevin Eastham by phone (0: 907-777-8455 or C: 907-360-5087) prior to perforating to confirm tie-in. d. Record tubing pressures before and after perforating run. 5. POOH. RD E-line. 6. Turn well over to production. PERFORATION TABLE Sands Gun Size Top (MD) Btm (MD) Top(TVD) Btm(TVD) FT Ugnu MD 3-1/8" 5,204' 5,244' / 4,274' 4,312' 40' Step-Rate Procedure: 7. MIRU Pump, PT lines to 250psi low/3,000psi high. 8. Perform step-rate injection test(maximum injection pressure not to exceed 2,500 psi). "v Volume [BBLS] Rate [BPM] Rate [BWPD] 5 0.25 360 10 0.5 720 50 1.0 1,440 50 2.0 2,880 50 4.0 5,760 50 6.0 8,640 50 8.0 11,520 Attachments: 1. Area of Review Map 2. As-built Schematic 3. Proposed Schematic • Milne Point Unit II 411 SCHEMATIC [Bleary Alaska,LLC Well: MPU B-34 Last Completed: 2/13/2017 PTD: 216-139 KBEIev.:50.2'/GL EIev.:23.7' TREE&WELLHEAD RKB—THF:22.98'(Innovation) Tree CIW 4-1/16"5M gM 1 Seaboard Weir,3 spools,w/11"x 5M top flange k Wellhead 4"CIW"H"BPV Profile 20" it 9-5/8" + OPEN HOLE/CEMENT DETAIL t Top Job#2: u' 93'MD 42" 50 bbls(10 Yards Pilecrete dumped down backside) G' 9-5/8" Cmt w/1,965 sx Class C 15.6 ppg in a 12-1/4"Hole L 9-5/8" Top Job#1:Cmt w/235 bbl Perm L 10.5 ppg from 505'MD s 9-5/8" s 1 Top Job#1: 9-5/8" Top Job#2:Cmt w/32 bbl Perm L 10.6 ppg from 93'MD it* 505'MD 7" Cmt w/345 sx Type 111.7 ppg;130 sx Type 115.8 ppg in 8-1/2" 9_5/8„ 0,..,:t ',gig 4-'/" Cmt w/25 bbl Type I-II in 6-1/8" t ,"19-5/8"CBL:2/03/17 °,Cement toSurface CASING DETAIL - Size Type Wt/Grade/Conn Drift ID Top Btm BPF 41/2" 20"x34" Conductor(Insulated) 78.6/A-53/Weld N/A Surface 106.5' N/A Tubing 4 9-5/8" Surface 40/L-80/DWC/C 8.679" Surface 2,672' 0.0758 iw 7" Production 26/L-80/DWC/C 6.151" Surface 5,064' 0.0382 4-1/2" Liner 13.5/L-80/Vam HTTC 3.795" 4,880' 5,369' 0.0149 4 TUBING DETAIL 'yd k 4- 1/2" Tubing 13.5/L-80/GeoConn 3.795" Surf 4,889' 0.0149 i, ", WELL INCLINATION DETAIL KOP@300' MD �,. Max Hole Angle=42.7 deg at 1,820' MD ti Hole angle through perforated interval:N/A iii JEWELRY DETAIL �* No Depth Item 11 t` 1 23' Tubing Hanger,4-1/2"TC-Il top&4-1/2"GeoConn btm V,," 2 4,742' 4-1/2"R" profile Packing Bore=3.688"ID g il , 2 3 4,879' 4-1/2" Baker Seal Assembly(Ported),5,72" No-Go Win ID=3.688"–.iy,,.. — 4 4,880' 4-1/2" Liner Top 4 1 1 V 5 4,895' 7"x 5" Baker ZXP Liner Top Packer 144 1 °a' 3 6 4,903' 7"X 5" Baker Flex-Lock Liner Hanger 4,5,6 GENERAL WELL INFO API:50-029-23569-00-00 �,, , Drilled and Cased by Innovation#1 -2/13/2017 ti 7s• 7"CBL:2/08/17 ,,c,(.:..4 Y Cement to 2,660' 1:4!..g' 'i.,'''. Fes , `. a :, k",: .* ,, ' 41/2„ ,.4-1/2"CBL:2/12/17 Cement to 4,880' f3(v`t TD=5,370(MD)/TD=4,428'(TVD) PBTD=5,285'(MD)/PBTD=4,351'(TVD) Revised by:STP 3/13/17 • � Milne Point Unit • II PROPOSED Well: MPU B-34 Last Completed: 2/13/2017 Hikorp Alaska.LLC PTD: 216-139 KBEIev.:50.2'/GL EIev.:23.7' TREE&WELLHEAD RKB—THF:22.98'(Innovation) Tree CIW 4-1/16"5M Seaboard Weir,3 spools,w/11"x 5M top flange ' Wellhead P 4"CIW"H"BPV Profile zo° m i9-5/8"" OPEN HOLE/CEMENT DETAIL TopJob#2: P. 93'MD 42" 50 bbls(10 Yards Pilecrete dumped down backside) `°"` 9-5/8" Cmt w/1,965 sx Class C 15.6 ppg in a 12-1/4"Hole d 9-5/8" Top Job#1:Cmt w/235 bbl Perm L 10.5 ppg from 505'MD }•1 9-5/8" 1Topiob#1: 9-5/8" Top Job#2:Cmt w/32 bbl Perm L 10.6 ppg from 93'MD h 505'MD 7" Cmt w/345 sx Type 111.7 ppg;130 sx Type 115.8 ppg in 8-1/2" 0 1 9-5/8' : , k 4-%" Cmt w/25 bbl Type I-II in 6-1/8" '9-5/8"CBL:2/03/17 'CementtoSurface CASING DETAIL I"A IV Size Type Wt/Grade/Conn Drift ID Top Btm BPF 4-1/2" ! 20"x34" Conductor(Insulated) 78.6/A-53/Weld N/A Surface 106.5' N/A Tubing ,, 9-5/8" Surface 40/L-80/DWC/C 8.679" Surface 2,672' 0.0758 i * 7" Production 26/L-80/DWC/C 6.151" Surface 5,064' 0.0382 r `, 4-1/2" Liner 13.5/L-80/Vam HTTC 3.795" 4,880' 5,369' 0.0149 TUBING DETAIL " 4-1/2" Tubing 13.5/L-80/GeoConn 3.795" Surf 4,889' 0.0149 WELL INCLINATION DETAIL 1.: r KOP@300' MD ;• Max Hole Angle=42.7 deg at 1,820' MD v. tr Hole angle through perforated interval:17 deg kV tJEWELRY DETAIL No Depth Item Ire 1 23' Tubing Hanger,4-1/2"TC-Il top&4-1/2"GeoConn btm 2 4,742' 4-1/2 "R" profile Packing Bore=3.688" ID 5 ii rg 2 3 4,879' 4-1/2" Baker Seal Assembly(Ported),5,72" No-Go Nin ID=3.688"-- 4 4,880' 4-1/2" Liner Top m5 4,895' 7"x 5" Baker ZXP Liner Top Packer 3 6 4,903' 7"X 5" Baker Flex-Lock Liner Hanger 4,5,6 PERFORATION DETAIL Sand Top(MD) Btm(MD) Top(ND) Btm(TVD) FT Date Status Ugnu MD ±5,204' ±5,244' ±4,274' ±4,312' ±40' Proposed Proposed Y " ,� ' ' 7 CBL 2/08/17 3-1/8"12 spf Big Hole charges ,4�' Cement toe'660' GENERAL WELL INFO ' API:50-029-23569-00-00 t=; Drilled and Cased by Innovation#1 -2/13/2017 44 4 1 , lz.fs ¢ ) .' t''' Ugnu MD l rx _.._ 41/2 .,,. `' 4-1/2"CBL•2/12/17 Cement to 4,880' TD=5,370(MD)/TD=4,428'(ND) PBTD=5,285'(MD)/PBTD=4,351'(TVD) Revised by:STP 3/15/17 • • xixA ee A_ Oryiii) er.aoX+° er.aoX / ' \ B-50 i / D-02 D-01 / \ I r / B-24 j / MPB-34_Prop 1 / // B-19 �► \ ! • I B=08 ` 11. // // � // I B-18 \\\�\\ -12 /�G/ i ( fb..__B_10_ B-1'I\�\ ' / , HILCORP ALASKA LLC /B-04 M-Ya Arp 11.-..„:— • ' MILNE POINT FIELD -- B.--41 —__.. 41111 AOR Map __,4,B _f _-,_\ B-05 Proposed B-34 G&l Well Ag,-- B-07 / 1 D 7 000 3.900 --/ ,/ iiia;0 7---. \\-\\ / FEET B'1 -04//'/��,f / \ \ B-05A POSTED WELL DATA 11, '' / / B-01 \ \ \ Well Number • Ask/ /�/ 6 15 B-13 WELL SYMBOLS III /4\ \ f Active Oil B-09 a-og/� i \ OSA ® INJ Well(Water Flood) \ /}0 PM Oil Cat l \\ a WO Sector cation \B-27 REMARKS K/ Well Symbol at top otignu u MB Sand B-G2 Blac Dash Circle 1320'nrad us om&proposed MB top Purple Line=Current Milne Point Unit Boundary Ocbber 10.2016 • • 216139 Debra Oudean Hilcorp Alaska, LLC 2 8 0 0 AK_GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8337 I(.Ienrp.th La_l.i.( RECEIVED: Fax: 907 777-8510 E-mail: doudean@hilcorp.com DATA LOGGED MAR 13 2017 /14/2017 K.BENDER DATE: 3/8/2017 AOGCC To: AOGCC Makana Bender 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL MPU B-34 POLLARD E-LINE SERVICES CD: Name Date modified Type P MPU B-34 4.Sin CBL 2-12-17.pdf 2/12/2017 12:16 PM PDF Document a MPU B-34 7in CBI.2-8-17.pdf 2/8/2017 7:07 AM PDF Document Q MPU B-34 9.625 CBL 2-3-17.pdf 2/12/2017 12:30 PM PDF Document Prints: GR CBL 9 5/8" SURFACE CASING GR CBL 4.5' LINER GR CBL 7" CASING Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: ����%�1'tx � Date: • • 216139 11 Maile Sweigart 2 8 0 0 6 RECEIVED Alaska North Slope Team Hilcorp Alaska,LLC 3800 Centerpoint Drive, Ste 1400 1 Anchorage,Alaska 99503 F{8rnrp Magic'.1.1,{, FEB 2 1 2017 Office: 907.777.8473 msweigart@hilcorp.com AOGCCDATA LOGGED Z /24/201'7 M K. BENDER Date: 2/20/2017 To: Alaska Oil & Gas Conservation Commission Makana Bender 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU B-34 B-34 Prints: ROP-DGR-ADR-EWR-CTN-ALD 2IN MD,DGR-ADR-EWR-CTN-ALD 2IN TVD E log data CD 1 : Final Well Data _Log Viewers 2/10/2017 5:03 PM File folder CGM 2/10/2017 5:03 PM File folder . Definitive Survey 2/1012017 5:03 PM File folder EMF 2/10/2017 5:03 PM File folder . LAS 2.110/2017 5:03 PM File folder . PDF 2/10/2017 5:03 PM File folder TIFF 2110/2017 5:03 PM File folder Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received y: Date: SOF T4 g \ I%yy � THE STATE Alaska Oil and Gas - /� i A S l�iC� �1 Conservation Commission l 1L JL`�l 333 West Seventh Avenue _�_ GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 ALAS Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Paul Mazzolini Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage, AK 99503 Re: Milne Point Field, Undefined WDSPL Pool, MPU B-34 Permit to Drill Number: 216-139 Sundry Number: 317-056 Dear Mr. Mazzolini: Enclosed is the approved application for 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, v eiv Cathy P. Foerster Chair DATED this lay of February, 2017. RBDMS ( L FEB - 3 2017 • • ` RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION JAN 31 2017 APPLICATION FOR SUNDRY APPROVALS ,( 21.2.//7 20 MC 25.280 AOGCC 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well /' Ope1 Operations t P ❑ Operations shutdown❑ Suspend ❑ Perforate El Other Stimulate ❑ Pull Tubing ❑ Change Approved Program Q Plug for Redrill ❑ Perforate New Pool El Re-enter Susp Well El Alter CasingCiv1T- El Other: Top Job 0 ✓ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development El 216-139 • 3.Address: Stratigraphic ❑ Service El 6.API Number: 3800 Centerpoint Drive,Anchorage,AK 99503 50-029-23569-00-00 • 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? N/A Will planned perforations require a spacing exception? Yes El No El 9.Property Designation(Lease Number): MPU B-34 10.Field/Pool(s): ADL 047438 - Milne Point Unit/Undef WDSP 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): 2,675' 2,254' 2,595' 2,193' 1935 N/A N/A Casing Length Size MD ND Burst Collapse Structural Conductor 80' 20" 80' 80' Surface 2,672' 9-5/8" 2,672' 2,254' 5,750 3,090 Intermediate Production Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: TubingGrade: Tubing MD(ft): N/A N/A N/A N/A N/A Packers and SSSV Type: N/A Packers and SSSV MD(ft)and ND(ft): N/A 12.Attachments: Proposal Summary 0 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: 1/30/2017 OIL ❑ WINJ ❑ WDSPL ❑✓ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG El GSTOR El SPLUG ❑ Commission Representative: GINJ El Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Paul Mazzolini Email pmazzolini@hilcorp.com Printed Name Paul Mazzolini Title Drilling Manager Signature � 01/31 i!� Phone 777-8369 Date /2017 I COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity FIff BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ CJS 2-I-L hq Other: Pi)f 1 1—�se.e, ,,z k t.�r w.,,� C i... A1s3•cam/ Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No Subsequent Form Required: /0 Y Ci 7 (6.4.:,,,,,,_)'' LJcj 147,2„,"--) RBDMS {-(- FE3 - 3 2017 /���; APPROVED BY Approved by: ,,ii, COMMISSIONERATHE COMMISSION Date:z, -Z _1 7 Form10 403 vised 11/2015 O'f +G+'Fth �{Salid for 12 months fro the date of approv ("1 Attachments in Duplicate • • Well Prognosis Hilcorp Alaska,LLC Well: MPU B-34 Date:1/31/2017 Well Name: MPB-34 API Number: 50-029-23569-00-00 Current Status: Cased and cemented Leg: N/A Estimated Start Date: Ongoing Rig: Innovation Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Cody Dinger 777-8389 Permit to Drill Number: 216-139 First Call Engineer: Paul Mazzolini (907)777-8369 (0) Second Call Engineer: Monty Myers (907) 777-8341 (0) AFE Number: N/A Cement Job Summary MPB-34 was spudded on 1-24-2017. 12-1/4"surface hole was drilled to 2675' MD.Surface hole TD was called by Geologist. 9-5/8"surface casing was run to 2675' MD and mud circulated and conditioned with no problems encountered. The cement job followed. The cement job was mixed and pumped with no issues. Neither weighted spacer nor cement returns were observed at surface. Cement job details as follows: 16:00—20:00 on 1-29-2017: Pressure test cement lines to 3500 psi, Pump 54 bbls of Tunned Spacer III at 10.5 ppg. Drop btm plug. Mix and pump 1965 sxs(335 bbls)of Class C cement at 15.6 ppg. Drop top plug.Cement Unit displace Class C cement w/20 bbls of 8.3 ppg FW. Rig take over&pumped 177.50 bbls 9.5 ppg mud from I Rig pits. Bumped plug 0.5 over calculated volume @ 177.5 bbls/2839 stks(pump output back calculated @ .0625 bbl/stk). Bumped plug to 500 psi over final circulating pressure of 600 psi, 1100 psi total. Hold 5 min. Bleed off pressure—floats held (1 bbl bled back). Had returns to surface up to 165 bbls cement pumped away and got returns back with 205 bbls of cement. Full returns noted at the time just before the top plug bumped. Final circulation pressure prior to bumping plug was 600 psi at 3 bpm. Neither the weighted spacer nor cement was observed at surface. Cement in place at 19:50 hrs on 01-29-2017. Top Out Procedure: 1. RIH to 500' MD&attempt tag TOC in 9-5/8"x OH annulus with%"top out tubing. TOC not found. 2. Circ hole with 235 bbls FW, 183 bbls over hole vol. Mud weight returns decreased from 9.6 ppg to 9.3 ppg. Swap hole back to 9.6 ppg mud. 3. POH with%" pipe and RIH with 1",2.25 lb/ft tubing. 4. RIH to tag TOC at 674' MD. 5. Pump 10.7 ppg ArcticCrete top out cement until cement returns observed at surface (with AOGCC and EPA to witness). ✓ 6. Proceed with N/U BOPE and testing. If unable to tag TOC: 1. R/U wireline equipment and run CBL with temperature probe across surface casing to identify TOC. 2. Consult with AOGCC to develop plan to effectively isolate surface casing annulus. J rd,,,. F 're C ,2`r`17 + 11 • • Milne Point Unit B-034 Current SCHEMATIC Well:PTDD: 2116-16-1 34 API: 50-029-23569-00-00 Hilcorp Alaska,LLC IRig RKB: 26.5' CASING DETAIL zo••41 L Size Type Wt Grade Conn. ID Top Btm 20" Conductor - - - Surf 80' 9-5/8" Surf.Csg 40 L-80 DWC/C 8.835" Surf 2,672' « a a itz 4 ' Tagged TOC @ 674' 4:4v PI All A 0 4 "_4t4 4te4 A 4 x .5 4,sq 95/8" A..ift TD=2,675'MD—2,254'ND PBTD FC=2,595'MD—2,193'ND Updated by CD 1/30/17 of TMJ �40",\ 1y/,'s THE STATE Alaska Oil and Gas ofLASKA Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 rh, GOVERNOR BILL WALKER g Main: 907.279.1433 ALAOJ" Fax: 907.276.7542 www.aogcc.alaska.gov Paul Mazzolini Drilling Manager Hilcorp Alaska, LLC 3 800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Unit, Undefined WDSP, MPU B-34 Permit to Drill Number: 216-139 Sundry Number: 317-049 Dear Mr. Mazzolini: Enclosed is the approved application for 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, Cathy P. oerster y Chair DATED this Z? day of January, 2017. RBDMS (,v F - 3 2117 • • RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION JAN 2 6 2017 APPLICATION FOR SUNDRY APPROVALS 0 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program El- Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑., . Other: 64.5/1-9(4 j'r [y]' 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Glia-y...- Hilcorp Alaska, LLC Exploratory ❑ Development ❑ 216-139 ' 3.Address: Stratigraphic ❑ Service Q, 6.API Number: 3800 Centerpoint Drive,Anchorage,AK 99503 50-029-23569-00-00 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? N/A Will planned perforations require a spacing exception? Yes ❑ No ❑., 7 MPU B-34 ' 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL 047438 - Milne Point Unit/Ugnu tJn erOnJ4, 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): 280' 280' 280' 280' 1935 N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 20" 80' 80' Surface Intermediate Production Liner Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): N/A N/A N/A N/A N/A Packers and SSSV Type: N/A Packers and SSSV MD(ft)and ND(ft): N/A 12.Attachments: Proposal Summary ❑i Wellbore schematic Q 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ Development❑ Service 0 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 1/26/2017 OIL ❑ WINJ ❑ WDSPL Q ' Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Paul Mazzolini Email pmazzolini@hilcorp.com Printed Name Paul Mazzolini Title Drilling Manager 1 01/25 Signature Phone 777-8369 Date �20/7 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 1 Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ F i 1-L414, 13 Other: X' 35-02) ' €c/%a f-- /i G Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ Nod Subsequent Form Required: /0_ V 07 mow' wL- - lll. DRB Pins L 1, - 3 Lull i) 32e--1,-)4-'"----- y / APPROVED BY Approved by: (I(�"�` COMMISSIONER THE COMMISSION Date: t'— 2.7-/ 044464NnA Submitsn Form and Form 10-403 ev' ed 11/2015 lid for 12 months from the date of approval. Attachments in Duplicate • Hilcorp Alaska, LLC P.O. Box 244027 • Paul Mazzolini Anchorage,AK 99524-4027 Drilling Manager Tel 907 777 8369 Email pmazzolini@hilcorp.com Hilcorp Energy Compmy 1/26/2017 Commissioner Alaska Oil &Gas Conservation Commission RECEIVED 333 W. 7th Avenue Anchorage, Alaska 99501 JAN 2 6 2017 Re: MPB-34 Change to Approved ProgramOG CC Dear Commissioner, Please see the attached 10-403 Change to Approved Program Sundry. We revised the surface and intermediate casing depths and cement volumes for the surface/intermediate casing job. If you have any questions, please don't hesitate to contact myself at 777-8369. Sincerely, ?Ctij )/YOIMP--L\-- Paul Mazzolini Drilling Manager Hilcorp Alaska,LLC Page 1 of 1 H . PLANNED SCHEMATIC Milne Point Unit Well: B-034 PTD: • API: Ililcorp Alaska,LLC IRig RKB: 26.5' CASING DETAIL 20" J, 1c ) 1. Size Type Wt Grade Conn. ID Top Btm rP 20" Conductor - Surf 113 9-5/8" Surf.Csg 40 L-80 DWC/C 8.835" Surf ±2,780' w 7" Production Casing 26 L-80 DWC/C 6.276" Surf ±5,000' 9-5/8" 4 7 4-1/2" Production Liner 13.5 L-80 HTTC 3.849" ±4,850' 5,356' TUBING 4„,„ 4-1/2" Production Tubing 13.5 L-80 Geo-Conn 3.849" Surf ±4,900' JEWELRY DETAIL No. Depth ID OD Item , , 1 26.5' Tubing Hanger 4-1/2"GeoConn ' , 3 2 ±4,400' GLM#1,4-1/2"SFO-1,GeoConn,Orifice Am 3 ±4,500' X-Nipple 4 ±4,900' 7"x 4-1/2"ZXP Liner Top Packer 4 5 ±4,900' Seal Bore Receptacle e 6 ±4,910' Seal Assy 7 ±5,250' Landing collar,PBTD 3 i.i I 4 5 7" x" 4 9 rr'r PERFORATIONS ., Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date Ugnu MB 5,120' 5,180' Ugnu MD2 5,200' 5,250' , t,, ,, Ugnu MB _ Ugnu MD2 7 4-1/2" C' la- TD eTD=5,356'MD 4,427'TVD Max Deviation 40.4°f/1,200'to 4,500' PBTD=5,250'MD—4,322'TVD Max Dogleg 5°/100'f/600'to 1,200' Updated by CD 1/25/17 • • Hilcorp Alaska, LLC Hilcorg Changes to Approved Permit to Drill Date: 01-25-2017 Subject: Changes to Approved Permit to Drill for MPU B-034 File#: MPU B-034 Drilling and Completion Program Any modifications to MPU B-034 Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be communicated to and approved by the AOGCC. Sec Page Date Procedure Change Approved Approved By By 8 7 01-19-17 Utilize Innovation Rig 13 5/8", 5000 psi BOP stack in MMM PM conjunction with 13 5/8" diverter T and 16" knife gate valve as diverter assembly as presented to AOGCC personnel. 9 9 01-19-17 13 5/8" 5K BOP Stack w/ 13 5/8" diverter tee & 16" knife MMM PM gate valve for 12 %4" hole section. 11 10 01-19-17 13 5/8" 5K BOP Stack w/ 13 5/8" diverter tee & 16" knife MMM PM gate valve for 12 %4" hole section. 7 6 01-24-17 Extend 9 5/8" surf csg depth to 2780' MD/2330' TVD PM 8 7 01-24-17 Extend 9 5/8" surf csg depth to 2780' MD/2330' TVD PM 7 6 01-24-17 Extend 7" intermediate csg depth to 5000' MD/4076' TVD PM Approval: ?a4.4._.erycilitri_L_. 0 f /Zto 17 Drilling Manager Date Prepared: Drilling Engineer Date • • MPU B 034 General sequence of operations: 1. MOB Innovation Rig to well site 2. N/U 13 5/8"BOP/Diverter configuration, diverter tee, knife valve and 16" diverter line. Function test diverter. 3. Drill 12-1/4" hole to TD of 2780' MD/2330' TVD. Run and cement 9-5/8" surface casing. Run CBL. 4. N/D 13 5/8" diverter tee and 16" diverter line,N/U&test 13-5/8"x 5M BOP. 5. Drill 8-1/2"hole to TD of 5000' MD/4076' TVD. 6. Run and cement 7"production casing. Run CBL. 7. Drill 6-1/8"hole to TD of 5356' MD/4427' TVD. 8. Run and cement 4-1/2" injection liner. Run CBL. 9. Run injection tubing. 10. N/D BOP,N/U temp abandonment cap, RDMO. 11. Perforate well. Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR+Res 2. Production Hole: No mud logging. On site geologist. LWD: GR+Res 3. Cased Hole Logs: CBL on surface, intermediate and injection liner. Rationale for request to_deepen surface and intermediate casing„setting depths. Hilcorp requests to deepen the setting depth of 9 5/8" surface casing 480' MD from 2300' MD/ 1969' TVD to 2780' MD/2330' TVD in Well MPU B-34 which will be a G&I disposal well. / Gas hydrates were encountered by Hilcorp in drilling Well B-28 and B-29 in 2016 at 2235' MD and 2165'MD respectively. It is anticipated that the gas hydrates will be encountered about 2540' MD in Well B-34 and that setting the surface casing at 2780' MD will allow for geologic uncertainty and ensure the gas hydrates will be isolated behind pipe. / Section 30 in the B-34 Drilling Program identifies best practices for drilling gas hydrates and will be executed to safely drill the gas hydrates as previously drilled in Wells B-28 and B-29. Hilcorp is also requesting the deepening of the 7" intermediate casing 200' MD from 4800' MD/ 3890' TVD to 5000' MD /4076' TVD. This request is being made to ensure the liner top packer for the 4 %2" liner hanger is within 100' from the top of the injection zone interval to meet EPA requirements.iThe call of the top of the injection zone, the TUZC stratigraphic marker within the Ugnu Formation will be made once penetrated by the LWD logs. See revised casing design factors and cement volumes on the following pages. • Calculation & Casing Design Factors Milne Point Unit DATE: 01-26-2017 WELL: MPU B-034 DESIGN BY: Paul Mazzolini Design Criteria: Hole Size 12-1/4" Mud Density: 9.5 Hole Size 8-1/2" Mud Density: 9.5 Hole Size 6-1/8" Mud Density: 9.5 Drilling Mode MASP(6-1/8"): 1496 psi (see attached MASP determination &calculation) Production Mode MASP: 1496 psi (see attached MASP determination &calculation) Collapse Calculation: Section Calculation 1, 2, 3 Max MW gradient external stress and the casing evacuated for the internal stress Casing Section Calculation/Specification 1 2 3 Casing OD 9-5/8" _ 7" 4-1/2" Top(MD) 0 0 4,850 Top(TVD) 0 0 3,936 Bottom (MD) 2,780 5,000 5,356 Bottom (TVD) 2,330 4,076 4,427 Length 2,780 5,000 506 Weight(ppf) 40 26 13.5 Grade L-80 L-80 L-80 Connection DWC DWC VAM HTTC Weight w/o Bouyancy Factor(lbs) 111,200 130,000 6,831 Tension at Top of Section (lbs) 111,200 130,000 6,831 Min strength Tension (1000 lbs) 916 604 307 Worst Case Safety Factor(Tension) 8.24 4.65 44.94 Collapse Pressure at bottom (Psi) 1,165 2,038 2,258 Collapse Resistance w/o tension (Psi) 3,090 5,410 8,540 Worst Case Safety Factor(Collapse) 2.65 2.65 3.78 MASP (psi) 1,398 1,496 1,496 Minimum Yield (psi) 5,750 7,240 9,020 Worst case safety factor(Burst) 4.11 4.84 6.03 S14 • Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 14.0 Cement 9-5/8" Surface Casing 14.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud&water can be delivered to the cmt unit at acceptable rates. • How to handle cmt returns at surface. Ensure vac trucks are on standby and ready to assist. • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. • Positions and expectations of personnel involved with the cmt operation. • Review test reports and ensure pump times are acceptable. • Conduct visual inspection of all iron used to route slurry to rig floor. 14.2 Document efficiency of all possible displacement pumps prior to cement job. 14.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cmt pump or treating iron will not be pumped downhole. 14.4 R/U cmt head(if not already done so). Ensure top and bottom plugs have been loaded correctly. 14.5 Pump 5 bbls 10.5 ppg tuned spacer. Test surface cmt lines. 14.6 Pump remaining 55 bbls 10.5 ppg tuned spacer. 14.7 Drop bottom plug. Mix and pump cmt per below calculations. 14.8 Cement volume based on annular volume+ 100% open hole excess. Job will be pumped in a single stage, TOC brought to surface. Estimated Total Cement Volume: Section: Calculation: Vol(BBLS) Vol(ft3) 12-1/4" OH x 9-5/8" casing: (2780'- 113')x 0.05578 bpf x 2 = 298 bbls 1667 ft3 Conductor x 9-5/8" casing: 113 x 0.26 bpf= 29.5 bbls 165 ft3 9-5/8" Shoe track: 90 x .0764 bpf = 6.88 bbls 38.6 ft3 Total: 334.38 bbls 1870.6 ft3 Page 20 Version 1 Jan, 2017 • S • Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company Cement Slurry Design: Slurry System SwiftCEM TM System Density 15.8 lb/gal Yield 1.16 ft3/sk Mixed Water 5.04 gal/sk 14.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets "sticky", land the hanger on seat and continue with the cement job. 14.10 After pumping cement, drop top plug and displace cement with spud mud out of mud pits. 14.11 Ensure rig pump is used to displace cmt. Displacement calcs have proven to be very accurate using 0.101 bps for pump output. 14.12 Displacement calculation: 2690' x .0764 bpf=205 bbls total 14.13 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 14.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Overdisplace by no more than 3 bbls before consulting with drilling engineer. 14.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 14.16 Be prepared for cement returns to surface. Dump cmt returns in the cellar or open the shaker bypass line to the cuttings tank. Have sacks of sugar available and vac trucks ready to assist. Ensure to flush out any rig components used to route cmt. Page 21 Version 1 Jan,2017 • O Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Cowen), 18.0 Cement 7" Intermediate Casing 18.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. • How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Positions and expectations of personnel involved with the cmt operation. • Document efficiency of all possible displacement pumps prior to cement job. 18.2 R/U cmt head(if not already done so). Ensure top and bottom plugs are loaded correctly. 18.3 Pump 5 bbls 10.5 ppg spacer. Close low torque on plug dropping head, test surface cmt lines to 4000 psi. 18.4 Pump remaining 35 bbls 10.5 ppg spacer. 18.5 Drop bottom plug, Mix and pump slurry per below calculations: Section: Calculation: BLS) Vol (ft3) (BLEAD: 9-5/8" casing x 7" casing: 2780' x 0.02886 bpf= 80 bbls 449 ft3 8-1/2" OH x 7" casing: (4300 - 2780)x 0.02259 bpf x 2 = 68.7 bbls 384 ft3 Total Lead: 148.7 bbls 833 ft3 TAIL: 8-1/2" OH x 7" casing: (5,000' —4,300')x 0.02259 bpf x 2 = 31.6 bbls 177 ft3 TAIL: 3.5 bbls 20 ft3 7" Shoe Track: 90' x .038 bpf= Total Tail: 35.1 bbls 197 ft3 Page 30 Version 1 Jan, 2017 • • 111 Milne Point Unit B-034 Drilling Procedure Hilcorp Emu r Slurry Information Lead Slurry Tail Slurry System ExtendaCEM TM System SwiftCEM TM System Density 11.7 lb/gal 15.8 lb/gal Yield 2.375 ft3/sk 1.16 ft3/sk Mixed 11.297 gal/sk 5.04 gal/sk Water 18.7 After pumping cement, drop top plug and displace cement with drilling mud. Use rig pumps for displacement. Ensure to have a good baseline measurement for pump displacement ahead of time. Displacement calcs: • 4,910' x .038 bpf= 186 bbls. 18.8 Monitor returns closely while displacing cement. Adjust pump rate if necessary. 18.9 Do not overdisplace by more than 1/2 shoe track volume. Total volume in shoe track is 3.5 bbls 18.10 There should be +1- 50 bbls cmt returns to surface. Be prepared to handle cmt. 18.11 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. • If this is the case, monitor the pressure on the casing and do not let it exceed 500 psi over the final pump pressure. Page 31 Version 1 Jan,2017 • Bettis, Patricia K (DOA) From: Davies, Stephen F(DOA) Sent: Wednesday, January 25, 2017 2:53 PM To: Schwartz, Guy L(DOA); Bettis, Patricia K(DOA) Subject: RE: Deepen Surface Casing for Gas Hydrates MPU B-34 I read through the daily drilling operations summaries for 13 of the wells that lie near the planned MPU B-34 well: MPU B-1, B-2, B-3, B-4, B-8, B-12, B-14, B-24, B-28, B-29, B-50, D-1 and D-2. I also pulled and reviewed mud logs for B-1, B-2, D-1 and D-2 (nearby wells that were mud logged). None of the daily drilling operations summaries mention any drilling or gas-related problems while drilling the hydrate-bearing sections of these well with the exception of B-28, which states only : "Max gas 965 units at 2235 btms up. . .Continue to fight mud wt." and "Saw ECD's go from 10.4 to 9.97 ECD's." on 3/7/2016. B-29 encountered 7778 units of gas at 2365' MD, but "Continued drilling ahead with no other hydrates encountered." From the mud logs: B-1 was not mud logged shallower than 2400' MD. That well encountered about 170units of gas (C1 and C2) at 2730' MD / TVD, but it was in close association with a thin coal bed. B-2 encountered 30 units of gas in sand at 2130' MD / TVD. D-1 was not mud logged shallower than 2565' MD, and the gas chromatograph was not functional until 3450' MD / 3385' TVD. D-2 was not mud logged shallower than 2580' MD / 2466' TVD. That well encountered 60 units of Cl in silt and sand between 2660' MD / 2537' TVD and 2880' MD / 2729' TVD. So, based on the records from 13 nearby wells that I've reviewed, none reported any significant drilling or well-control problems while drilling through the gas hydrate-bearing section. Please let me know if you have any questions or need additional information. Thank you. Steve D. 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 Steve Davies at 907-793-1224 or steve.davies@alaska.gov. Original Message From: Paul Mazzolini [mailto:pmazzolini@hilcorp.com] Sent: Wednesday, January 25, 2017 2:20 PM To: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Cc: Bettis, Patricia K (DOA) <patricia.bettis@alaska.gov>; Davies, Stephen F (DOA) <steve.davies@alaska.gov>; Cody Dinger <cdinger@hilcorp.com>; Monty Myers <mmyers@hilcorp.com> Subject: Re: Deepen Suface Casing for Gas Hydrates MPU B-34 Guy, Thanks for the reply to my email. I will get a sundry generated which will include both casing depth changes. • • Sent from my iPhone On Jan 25, 2017, at 11:58 AM, Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov<mailto:guy.schwartz@alaska.gov» wrote: Paul, Discussed with our Geologists. . . they are looking at the data in the offset wells regarding the hydrates and casing point. I forgot to mention when we talked that this change will also require a sundry (change of approved program) . Please send as submit as you can with the supporting documentation as listed below and the new casing and cement info. There may be some small changes to LOT/FIT that should be addressed in the sundry also. 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(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 Guy Schwartz at (907-793-1226 ) or (Guy.schwartz@alaska.gov<mailto:Guy.schwartz@alaska.gov>). From: Paul Mazzolini [mailto:pmazzolini@hilcorp.com] Sent: Tuesday, January 24, 2017 5:05 PM To: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov<mailto:guy.schwartz@alaska.gov>> Subject: Deepen Suface Casing for Gas Hydrates MPU B-34 Guy, Thank you for your time this afternoon. As discussed, Hilcorp requests to deepen the setting depth of 9 5/8" surface casing 480' MD from 2300' MD / 1969' TVD to 2780' MD / 2330' TVD in Well MPU B-34 which will be a G&I disposal well. Gas hydrates were encountered by Hilcorp in drilling Well B-28 and B-29 in 2016 at 2235' MD and 2165'MD respectively. It is anticipated that the gas hydrates will be encountered about 2540' MD in Well B-34 and that setting the surface casing at 2780' MD will allow for geologic uncertainty and ensure the gas hydrates will be isolated behind pipe. Section 30 in the B-34 Drilling Program identifies best practices for drilling gas hydrates and will be executed to safely drill the gas hydrates as previously drilled in Wells B-28 and B-29. Hilcorp is also requesting the deepening of the 7" intermediate casing 400' MD from 4800' MD / 3890' TVD to 5200' MD / 4173' TVD. This request is being made as the liner top packer for the 4 (1/2)" liner hanger needs to be 100' from the top of the perforated interval to meet EPA requirements. As I mentioned in our discussion the Innovation should spud Well B-34 sometime tonight. 2 s 411 • • Attached is the MOC for your records. Kevin Eastham, Milne Point Geologist and I are available to discuss and answer questions you may have. Regards Paul 3 V OF T7.1 . • andGas \ //7, sA THE STATE Alaska Oil , ice of F TTASI(�1-1 /� Conservation Commission __ L 333 West Seventh Avenue 2'— iGOVERNOR BILL WALKER Anchorage, Alaska 99501-3572- * O'''�^�,,• Main: 907.279.1433 A :gI' Fax: 907.276.7542 www.aogcc.alaska.gov Luke Keller Drilling Engineer Hilcorp Alaska,LLC 3800 Centerpoint Drive, Suite 1400 Anchorage,AK 99503 Re: Milne Point Field, Ugnu Undefined Pool, MPU B-34 Hilcorp Alaska, LLC Permit to Drill Number: 216-139 Surface Location: 856' FSL, 4296' FEL, SEC. 18,T13N,R11E, UM,AK Bottomhole Location: 1710' FNL, 570' FWL, SEC. 18, T13N, R11E,UM,AK Dear Mr. Keller: Enclosed is the approved application for permit to drill the above referenced service well. Per Statute AS 31.05.030(d)(2)(B)and Regulation 20 AAC 25.071,composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Injection operations to be conducted in accordance with EPA issued Class I permit or an AOGCC issued Class II permit. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Cathy '. Foerster Chair DATED this j day of November, 2016. STATE OF ALASKA AlitOIL AND GAS CONSERVATION COMMEAN OCT ; PERMIT TO DRILL 20 AAC 25.005 c f.k 5 S .F" AOGCC la.Type of Work: 1 h.Proposed Well Class: Exploratory-Gas ❑ Service- WAG 0 Service-Disp 0 • lc.Specify if well is proposed for: Drill ❑✓ 'Lateral 0 Stratigraphic Test ❑ Development-Oil 0 Service- Winj ❑ Single Zone 0 Coalbed Gas 0 Gas Hydrates 0 Reda❑ Reentry ❑ Exploratory-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, MPU B-34 3.Address: 6.Proposed Depth: 1 12.Field/Pool(s): 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 MD: 5,6'535(o TVD: 4,427', Milne Point Unit ' 4a. Location of Well(Governmental Section): 7.Property Designation(Lease Number): Ugnu Undefined • Surface: 856'FSL,4296'FEL,Sec 18,T13N,R11 E,UM,AK . ADL 047438 . Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 1852'FNL,589'FWL,Sec 18,T13N,R11E,UM,AK N/A 12/15/2016 Total Depth: 9.Acres in Property: 14.Distance to Nearest Property: 1710'FNL,570'FWL,Sec 18,T13N,R11 E,UM,AK • 2544 • 4288'to nearest unit boundary 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL(ft): 57.4' ' 15.Distance to Nearest Well Open Surface: x-571983 y-6023979 Zone-4 c GL Elevation above MSL(ft): 23.7'• to Same Pool: 3747'to B-24 16.Deviated wells: Kickoff depth: 300 feet • 17.Maximum Potential Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 40.4 degrees . Downhole: 1935 4 Surface: 1496 • 18.Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade Coupling Length MD ND MD TVD (including stage data) 42" 20" 78.6# A-53 Weld 80' Surface Surface 80' 80' 280 ft3 12-1/4" 9-5/8" 40# L-80 DWC/C 2,300' Surface Surface 2,300' 1,969' 1573 ft3 8-1/2" 7" 26# L-80 DWC/C 4,800' Surface Surface 4,800' 3,892' 1021 ft3 6-1/8" 4-1/2" 13.5# L-80 VAM HTTC 656' 4,700' 3,805' 5,356' 4,427 174 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): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): 20. Attachments: Property Plat Q BOP Sketch Q Drilling Program ❑., Time v.Depth Plot ❑✓ Shallow Hazard AnalysiSO Diverter Sketch Q Seabed Report ❑ Drilling Fluid Program 0 20 AAC 25.050 requirements 21. Verbal Approval: Commission Representative: Date 22.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Email Ikeller(a'�,hilcorp.com Printed Name Luke Keller Title Drilling Engineer // Signature L% Phone 777-8395 Date <' -CA0 b Commission Use Only Permit to Dri I API Number: Permit Approval See cover letter for other Number: D 1(0 /3 '( 50-CA9— ot.'q1 356 1c�—O—clic) Date: requirements. Conditions of approval: If box is checked,well may not be used to explore for,test,or produce coalbed urethan gas hydrates,or gas contained in shales: gOther: ]C !r 3 S I 'igo t % Samples req'd: Yes❑ No0 Mud log req'd:Yes NO H2S measures: Yes[✓t No❑ Directional svy req'd:Yes No 1=1/ /G°S j/(:A% 0 -'1 �t rI•1--1-__ i,.A,-- Spacing exception req'd: Yes❑ Nod Inclination-only svy req'd:Yes❑ No ZI .4,,,,-_,„.-,i9 (......./ .ErA Cl.t. r p r .L .. Post initial injection MIT req'd:Yes❑ No❑ t c — k'\.r.)i \kj APPROVED BY Y1 Approved b : COMMISSIONER THE COMMISSION Date:// 23 l l ila 1h I1 D 4' `� l) I I—/7-16Su/bmit Form and/ Form 10-401(Revised 11/2015) O f1�Ietsf(adjar 1months from th dateeof royal(20 AA 5.005(g)) Attachments in Duplicate IV HL <Or (8 • Luke Keller • Hilcorp Alaska, LLC Drilling Engineer P.O. Box 244027 Anchorage, AK 99524-4027 Tel 907 777 8395 Email Ikeller@hilcorp.com ‘iad.a.I.t.c 10/25/2016 RECEIVED Commissioner Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue OCT 2 6 2016 Anchorage, Alaska 99501 AOGCC Re: MPB-34 VIVV Dear Commissioner, Enclosed for review and approval is the Permit to Drill for MPB-34 waste injection well. MPU B-034 is a grassroots disposal well for the Milne Point G&I Facility located on"B" pad. The directional plan is a slant well with the kick off point at 300' MD/TVD. Maximum hole angle is 40.4 degrees. Drilling operations are expected to commence approximately Dec 15th, 2016. D00 3-1,4 will be used to drill and complete the wellbore. If you have any questions, please don't hesitate to contact myself at 777-8395 or Paul Mazzolini at 777-8369. Sincerely, Luke Keller Drilling Engineer Hilcorp Alaska, LLC Page 1 of 1 9 s Area of Review — Proposed MPB-34 Disposal Injection Well This AOR found no wells within % mile of MPB-34's entry into the Ugnu formation. The table below illustrates the completion details and integrity conditions of the proposed MPB-34 well. Table 1: Wells within AOR Well Name PTD Distance, Ft. Annulus Integrity Surface 9-5/8" casing to be run to 2300' and cemented back to surface. Intermediate 7" casing to be run to 4800'and cemented back to surface. 4-1/2" liner("approx. 100' MPB-34 TBD N/A overlap 4-1/2" x 7") to be run to 5356'cemented to LTP. Test LTP to 3600 psi. Conduct CBL after 7" and 4-1/2" cement jobs. 4-1/2"Tubing packer to be set within 100'of Top of Injection zone. MIT-IA 3500 psi will be conducted to confirm tubing and casing integrity. • • H Hilcorp Alaska, LLC Milne Point Unit (MPU) B-034 Drilling Program Version 0 Oct 3rd, 2016 • • Milne Point Drilling Procedure Hilcorp Energy Company 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 Planned Wellbore Schematic 6 8.0 Drilling/Completion Summary 7 9.0 Mandatory Regulatory Compliance/Notifications 8 10.0 R/U and Preparatory Work 10 11.0 N/U 21-1/4"2M Diverter System 10 12.0 Drill 12-1/4"Hole Section 12 13.0 Run 9-5/8"Surface Casing 17 14.0 Cement 9-5/8"Surface Casing 20 15.0 BOP N/U and Test 23 16.0 Drill 8-1/2"Hole Section 24 17.0 Run 7"Intermediate Casing 28 18.0 Cement 7"Intermediate Casing 30 19.0 Drill 6-1/8"Hole Section 33 20.0 Run 4-1/2"Injection Liner 38 21.0 Cement 4-1/2"Production Liner 41 22.0 Wellbore Clean Up&Displacement 44 23.0 Completion Operations 45 24.0 Well Perforation: 46 25.0 Diverter Schematic 47 26.0 BOP Schematic 48 27.0 Wellhead Schematic 49 28.0 Days Vs Depth 50 29.0 Formation Description 51 30.0 Anticipated Drilling Hazards 52 31.0 Doyon 14 Rig Layout 54 32.0 FIT Procedure 55 33.0 Choke Manifold Schematic 56 34.0 Casing Design Information 57 35.0 8-1/2"Hole Section MASP 58 36.0 6-1/8"Hole Section MASP 59 37.0 Spider Plot(NAD 27)(Governmental Sections) 60 38.0 Surface Plat(As Built)(NAD 27) 61 39.0 Offset MW vs TVD Chart 62 40.0 Drill Pipe Information 4"14#S-135 HT-38 63 S Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 1.0 Well Summary Well MPU B-034 Pad Milne Point"B"Pad Planned Completion Type 4-1/2" Injection Tubing Target Reservoir(s) Ugnu Planned Well TD,MD/TVD 5,356' MD/4,427' TVD PBTD,MD/TVD 5,250' MD/4,322' TVD Surface Location(Governmental) 856' FSL, 4,296' FEL Sec 18,T13N,RI 1E,UM,AK Surface Location(NAD 27—Zone 4) X=571,983.88 Y=6,023,979.35 Surface Location(NAD 83) Top of Productive Horizon (Governmental) 1852'FNL, 589'FWL, Sec 18, T13N,R11E,UM,AK TPH Location(NAD 27) X=571,635.3, Y=6,026,547 TPH Location(NAD 83) BHL(Governmental) 1710'FNL, 570'FWL, Sec 18,T13N,R11E,UM,AK BHL(NAD 27) X=571,615.5, Y=6,026,688.8 BHL(NAD 83) AFE Number 1612654D AFE Drilling Days 13 Days AFE Completion Days 5 Days AFE Drilling Amount $2,932,000 AFE Completion Amount $1,032,500 AFE Facility Amount $350,000 Maximum Anticipated Pressure (Surface) 1496 psi Maximum Anticipated Pressure (Downhole/Reservoir) 1935 psi Work String 4" 14# S-135 HT-38 Weatherford Rental—Contingency KB Elevation above MSL: 33.7 ft+23.7 ft= 57.4 ft GL Elevation above MSL: 23.7 ft BOP Equipment 13-5/8"x 5M Annular, (3)ea 13-5/8"x 5M Rams Page 2 Version 0 Oct,2016 • • 111 Milne Point Unit B-034 Drilling Procedure Hilcorp EnerBY COmPaff 2.0 Management of Change Information Hilcorp Alaska, LLC Fnmy Compaq Hilcorp Changes to Approved Permit to Drill Date: 10-3-2016 Subject: Changes to Approved Permit to Drill for MPU B-034 File#: MPU B-034 Drilling and Completion Program Any modifications to MPU B-034 Drilling&Completion Program will be documented and approved below. Changes to an approved APD will be communicated to and approved by the AOGCC. Sec Page Date Procedure Change Approved Approved BY BY Approval: Drilling Manager Date Prepared:. Drilling Engineer Date Page 3 Version 0 Oct, 2016 • ! Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 3.0 Tubular Program: Hole OD ID (in) Drift Conn Wt Grade Conn Burst Collapse Tension Section (in) (in) OD (in) (#/ft) (psi) (psi) (k-lbs) Cond 20" 19.25" - - 78.6 A-53 Weld 12-1/4" 9-5/8" 8.835" 8.75" 10.235" 40 L-80 DWC/C 5,750/ 3,090 916 8-1/2" 7" 6.276" 6.151" 7.656" 26 L-80 DWC/C 7,240/ 5,410 604 VAM 6-1/8" 4-1/2" 3.849 3.75 4.93 13.5 L-80 HTTC 9020 -/ 8540 307 4.0 Drill Pipe Information: Hole OD ID(in) TJ ID TJ OD Wt Grade Conn M/U M/U Tension Section (in) (in) (in) (#/ft) (Min) (Max) (k-lbs) ALL 4" 3.34" 2.5625" 4.875" 14 S-135 HT-38 12,200 17,700 649,200 5.0 Casing Inspection All casing will be new, PSL 1 (100%mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Version 0 Oct, 2016 • • Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 6.0 Internal Reporting Requirements 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 tab. • 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 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcorp.com , lkeller@hilcorp.com and cdinger@hilcorp.com 6.3 Intranet Home Page Morning Update • Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 6.4 EHS Incident Reporting • Health and safety: Notify EHS field coordinator. • Environmental: Drilling Environmental coordinator • Notify Drlg Manager&Drlg Engineer • Submit Hilcorp Incident report to contacts above within 24 hrs 6.5 Casing Tally • Send final"As-Run"Casing tally to lkeller@hilcorp.com and cdinger(a hilcorp.com 6.6 Casing and Cmt report • Send casing and cement report for each string of casing to lkeller@hilcorp.com and cdinger@hilcorp.com 6.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Paul Mazzolini 907.777.8369 907.317.1275 pmazzolini@hilcorp.com Drilling Engineer Luke Keller 907.777.8395 832.247.3785 Ikeller@hilcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com Reservoir Engineer Vanessa Hughes 907.777.8445 vhughes@hilcorp.com Drlg Environmental Coord Keegan Fleming 907.777.8477 907-350-9439 kfleming@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 caiones@hilcorp.com EHS Field Coordinator Jimmy Watson 907.777.8450 907.744.7376 iiwatson@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com Page 5 Version 0 Oct,2016 0 0 II Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 7.0 Planned Wellbore Schematic KB-THF: 33.7' D CASING DETAIL 1111.11, 20*4/7 ( Size 20" ;ue Conductor Wt Grade Conn. ID Top Btm Surf 113 9-5/8" Surf.Csg 40 L-80 DWC/C 8.835" Surf 2,300' 7" Production Casing 26 L-80 DWC/C 6.276" Surf 4,800' F 93/8' � ri.7-) / / 4-1/2" Production Liner 13.5 L-80 HTTC 3.849' 4,700' 5,356' - TUBING 4-1/2' Production Tubing 13.5 L-80 Geo-Conn 3.849' Surf4,700'JEWELRY DETAIL No. Depth ID OD Item 1 26.5' Tubing Hanger 4-1/2"Geoconn 2 4,400' GLM#i,4-1/2"SFO i,GeoConn,Orifice Surf 4,500' X-Nipple 4,700' 7''x 4-1/2"ZXP Liner Top Packer 5 4,700' Seal Bore Receptacle t 4,c, 6 4,710' Seal Assy 7 5,250' Landing collar,PBTD 1 (1 r ' 7- X tj it814) 5 PERFORATIONS Zone Top(MD) Btrn(MD) Top(TVD) Btm(TVD) Amt wt. Comments Date Ugnu MB 5,120' 5,180' ,' i Ugnu MD2 5,200' 5,250' Ugnu MB t ,. gnu MD2 t= x 4 4-1/2.. Aliftik TD=5,356'MD—4,427'TVD Max Deviation 40.4°f/1,200'to 4,500' PBTD=5,250'MD—4,322'TVD Max Dogleg 5°/100'f/600'to 1,200' Page 6 Version 0 Oct, 2016 i ! Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 8.0 Drilling / Completion Summary MPU B-034 is a grassroots disposal well for the Milne Point G&I Facility located on"B"pad. The directional plan is a slant well with the kick off point at 300' MD/TVD. Maximum hole angle is 40.4 degrees. Drilling operations are expected to commence approximately Dec 15th,2016. Surface casing will be run to 2,300' MD / 1,969' TVD and cemented to surface via a single stage primary cement job. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed, a Temp log will be run between 6 — 18 hrs after CIP to determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All waste & mud generated during drilling operations will be hauled to the Milne Point G&I facility located on"B"pad. General sequence of operations: 1. MOB Doyon#14 to well site 2. N/U 21-1/4" conductor and 16" diverter line. 3. Drill 12-1/4"hole to TD of surface hole section. Run and cmt 9-5/8" surface casing. 4. N/D diverter,N/U&test 13-5/8"x 5M BOP. 5. Drill 8-1/2"hole to TD. 6. Run and cmt 7"production casing. Conduct CBL. 7. Drill 6-1/8"hole to TD. 8. Run and cmt 4-1/2" injection liner. Conduct CBL. 9. Run injection tubing. 10.N/D BOP,N/U temp abandonment cap, RDMO. 11. Perforate well. Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR+ Res 2. Production Hole: No mud logging. On site geologist. LWD: GR+ Res 3. Cased Hole Logs: CBL on intermediate and injection liner. Page 7 Version 0 Oct,2016 • S Milne Point Unit B-034 Drilling Procedure Hilcorp Ent*BY Comamr 9.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at(2)week intervals during the drilling and completion of MPU B-034. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. • The initial test of BOP equipment will be to 2501-343Orrpsi & subsequent tests of the BOP equipment will be to 250/38gpsi for 5/5 min(annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • 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 AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: • There are no variance requests at this time. Page 8 Version 0 Oct, 2016 • • Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) 12-1/4" • 21-1/4"2M diverter(Hydril MSP)w/16"diverter line Function Test Only • 13-5/8"x 5M Hydril"GK"Annular BOP 3} • 13-5/8"x 5M Hydril MPL Double Gate Initial Test:250/3086` o Blind ram in btm cavity (Annular 2500 psi) • Mud cross w/3"x 5M side outlets 8-1/2"&6-1/8" • 13-5/8"x 5M Hydril MPL Single ram • 3-1/8"x 5M Choke Line Subsequent Tests: .i) • 3-1/8"x 5M Kill line 250/3j300- • 50/3• 3-1/8"x 5M Choke manifold (Annular 2500 psi) • Standpipe,floor valves,etc Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: • Well control event(BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPs. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg/AOGCC Inspector/(0): 907-793-1236/Email:jim.regg@alaska.gov Guy Schwartz/Petroleum Engineer/(0): 907-793-1226/(C): 907-301-4533 /Email: guy.schwartz@alaska.gov Victoria Loepp/Petroleum Engineer/(0): 907-793-1247/Email: Victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification/Emergency Phone: 907-793-1236 (During normal Business Hours) Notification/Emergency Phone: 907-659-2714(Outside normal Business Hours) Page 9 Version 0 Oct,2016 • • Milne Point Unit B-034 Drilling Procedure Hilcorp Energy company 10.0 R/U and Preparatory Work 10.1 Install and cement insulated 20"x 34" conductor. 10.2 Dig out and set impermeable cellar inside existing culvert. 10.3 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 10.4 Install Seaboard slip-on 16-3/4" 3M "A" section. Ensure to orient wellhead so that tree will line up with flowline later. 10.5 Insure (2) 3"threaded nipples are installed on opposite sides of the conductor with ball valves on each nipple. These will be used to take cement returns to the cellar during the surface cmt job, and also to wash out the diverter and hanger in preparation for running the pack-off. 10.6 Level pad and ensure enough room for layout of rig footprint and R/U. 10.7 MIRU Doyon#14. 10.8 Mud loggers WILL NOT be used on B-034. / 10.9 Mix spud mud for 12-1/4" surface hole section. Keep mud cool. 10.10 Set test plug in wellhead prior to N/U diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 10.11 Install 6" liners in mud pumps. • Continental EMSCO FB-1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @ 95%volumetric efficiency. 11.0 N/U 21-1/4" 2M Diverter System 11.1 N/U 21-1/4" Hydril MSP 2M diverter System(Diverter Schematic at Sec 20 at back of program). • N/U 16-3/4" 3M x 21-1/4" 2M DSA on 16-3/4" 3M wellhead. • N/U 21-1/4"diverter"T". • Knife gate, 16" diverter line. • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). • Diverter line must be 75 ft from nearest ignition source • Place drip berm at the end of diverter line. 11.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. Page 10 Version 0 Oct, 2016 • S Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 11.3 Ensure to set up a clearly marked"warning zone" is established on each side and ahead of the vent line tip. "Warning Zone" must include: • A prohibition on vehicle parking. • A prohibition on ignition sources or running equipment. • A prohibition on staged equipment or materials. • Restriction of traffic to essential foot or vehicle traffic only. 11.4 Set 15.375" ID wear bushing in wellhead. 11.5 Rit & Diverter Orientation: -10 h Dlverier Lha • .,1 1, .. ;; 6��� 1-- •• 1 �I 6 1.8 , l I � 30 r]I-.-v I I , l_ Page 11 Version 0 Oct, 2016 • • II Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 12.0 Drill 12-1/4" Hole Section 12.1 P/U 12-1/4" directional drilling assy: • 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. • Be sure to run a UBHO sub so that wireline orientation is possible if necessary. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Workstring will be 4" 14# S-135 HT-38 • Run a solid float in the surface hole section. / 12.2 12-1/4" BHA(GR+Res LWD and PWD planned in surface hole): ✓ COMPONENT DATA ?I Item OD ID Gauge Weight Top Length Cumulat # Description Serial Number (in) (€n) (in) (Ibpt) Connection (ft) Lenallb 1 OHC1GRC 8.000 3.600 12.250 136.62 P 6-5/8"REG 1.00 1.00 2 8"SperryDrill Lobe 4.5-5.3 stg 8.000 5.000 103.09 B 6-5/8"REG 31.47 32.47 Stabilizer IIIIIIIIIIIII 12.125 _� - 3 Float Sub 8.000 2.880 149.10 8 6-558"REG 2.40 34.87 4 8"DM Collar 8.000 3.500 147.40 B 6-5/8"REG 9.20 44.07 5 8"DGR Collar 8.000 1.920 142.70 B 6-518"REG 4.55 48.62 6 8'EWR-P4 Collar 8.000 1.985 151.00 B 6-5/8"REG 12.19 60.81 7 8"PWD IIIIIIIIIIIIII 8.000 1.920 143.40 B 6-5'8"REG 4.44 IIMM 8 8"HCIM Collar 8.000 1.920 149.90 B 6-518"REG 4.97 70.22 9 8"POS PULSER IIIIIIIIIIIIII 8.000 4.000 IIIIIIIII 145.20 B 6-5+8"REG 15.44 85.66 10 Orienting Sub UBHO 8.000 2.875 149.18 B 6-518"REG 2.50 88.16 11 NM Flex Collar 8.000 2.813 150.13 B 6-5 8"REG 31.00 119.16 12 NM Flex Collar 8.000 2.813 150.13 B 6-5•8"REG 31.00 150.16 13 NM Flex Collar 8.000 2.813 150.12 B 6-5.8"REG 31.00 181.16 14 6 jts x 5'X 3"HWDP#49.3-NC50{IF) 5.000 3.000 49.30 189.00 370.16 15 Jar 7.500 2.813 129.38 B 4-1 2"IF 35.00 405.16 16 14 its x 5"X 3"HWDP#49.3 NC50 5.000 3.000 49.30 441.00 846.16 p ' 846.16 Page 12 Version 0 Oct, 2016 • • II Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 12.3 Primary Bit: 11111111111111111111111111 S:elt Sheet Ir/ja1111 12 1/4" GT-C1 BAKER (311.2 mm) HUGHES ■ XL&IA Hardt-acing FeaturesA patented.strategically placed bead of hardfacing is added to key areas on specific teeth to retard tooth wear f.-4 t and improve tooth strength and durability. * I. a ■ Endura tiardtacint;A unique.extremely wear resistant coating that is .., 11 very tough and resistant to flaking and chipping. ■ GT Technology(Sti GT improves the drilling efficiency of the cutting if' structure with trimmer pads that remove uncut rock ribs at the comer of ' the hole,relieved cone steel.aggressive tooth pitches and active shear cutting gauge compacts. ■ :Maximum Penetration Aggro-:sire drilling action because of very large t cone offset and deep intermesh tooth design with good ventilation. • High RPM Drilling Durable sled tooth bit designed for hitch rotary speeds in very soft formations with low compressive strengths. - y ... Y. Product Specifications IADC: 117 Bearing:Seal Package: Journal/0-ring Cutting Structure: Inner Row DC,EV867i MG095/EV882 Heel Row Bi-Metallic Gauge Row Macro G2 Bearing Gauge Trimmers Pad Tooth Hardfacing: Endura OD Hardfacing: Shirttail ° Nozzle Type: Standard ,' t 4 Center Jet Display: FK or VK Makeup Torque: 28.0-32.0 klbf-ft(38.0-43.4 kNml Connection: 6-5 8 REG API Approx.Shipping Weight: 235 lb( 106.6 kg) Reference Part Number 11221 B4 Operating Recommendations*: Weight On Bit: 20-50 klb(9-22 to or kdaN) Rotation Speed: For Rotary and Motor Applications 'The ranges of bit weight and RPM shown arc representative of typical operating parameters.but will not necessarily,yield optimum bit lite or lowest drilling cow.It is WWW.bakerhuglies.coni not recommended that the upper limits of both weight and RPM be run simultaneously. {'2012 Raker Hughes Incorporated.All rights reserved. Contact}imus local Hughes Christensen representative for recommendations in your area. Page 13 Version 0 Oct, 2016 Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 12.4 4" Workstring, HWDP, and Jars will come from Weatherford. 12.5 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. 12.6 Drill 12-1/4"hole section to section TD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. We want to be approx. 200' through the base of the permafrost. Permafrost base is estimated at 1700' TVD • Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. • Hold a safety meeting with rig crews to discuss: • Conductor broaching ops and mitigation procedures. • Well control procedures and rig evacuation. • Flow rates, hole cleaning, mud cooling, etc. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Keep mud as cool as possible to keep from washing out permafrost. • Pump at 450-600 gpm. Ensure shaker screens are set up to handle this flowrate. • Keep swab and surge pressures low when tripping. • Make wiper trips if necessary. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. • Take MWD surveys every stand drilled(95' intervals). • Be prepared for GAS HYDRATES at the base of the permafrost. Both 2016 "B" pad wells (B-28 and B-29) encountered gas hydrates btwn 2160' —2190' TVD. • Do not stop to circulate out gas hydrates—this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 fph MAX)through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. Consider adding mud products such as Lecithin to allow the gas to break out. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • Do not stop to circulate on wiper trips with bit across a slide interval, especially not in an area where DLS is> 4. • Do not slide for 100' MD above the base of the permafrost or 100' below the base. We want to leave this transition as undisturbed as possible. Page 14 Version 0 Oct,2016 • • Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 12.7 12-1/4"hole mud program summary: • Density: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system(1) ppg above highest anticipated MW. We will start with a simple gel +FW spud mud at 8.8 ppg. • PVT System: An electronic PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, and Toolpusher office. • Hydrates: Hydrates have been encountered on"B"pad from 2160' to 2190' TVD. Be prepared and don't stop to circulate out gas. Control drill when hydrates encountered. • Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. • Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 —9.0 range with caustic soda. Daily additions of ALDACIDE G/X-CIDE 207 MUST be made to control bacterial action. • Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP <20 (check with the cementers to see what YP value they have targeted). System Type: 8.8—9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL Temp pH Surface 8.8-9.5/ 75-175 20-40 25-45 <10 <70° F 8.5-9.0 Page 15 Version 0 Oct, 2016 • S Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company System Formulation: Gel + FW spud mud Product Concentration Fresh Water 0.905 bbl soda Ash 0.5 ppb AQUAGEL 15 -20 ppb caustic soda 0.1 ppb(8.5—9.0 pH) BARAZAN D+ as needed BAROID 41 as required for 8.8—9.5 ppg PAC-L/DEXTRID LT if required for<10 FL ALDACIDE G 0.1 ppb 12.8 At TD; pump sweeps, CBU, and pull a wiper trip back to the 20" conductor shoe. 12.9 If hole conditions will not allow the BHA to be pulled out on elevators,prior to initiating backreaming, try to orient motor to high side and attempt to pump out to avoid damaging the wellbore. 12.10 Should backreaming be absolutely necessary to get out of the hole: • Prior to initiating backreaming, ensure at least 3 —4 B/U have been circulated to get hole as clean as possible. • Pump at full drill rate (450—550 gpm), and maximize rotation. • Pull slowly, 5 — 10 ft/minute. • Monitor well for any signs of packing off or losses. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 12.11 TOH with the drilling assy, handle BHA as appropriate. 12.12 No open hole logging program planned. Page 16 Version 0 Oct, 2016 • • Milne Point Unit B-034 Drilling Procedure Hilcorp Enmgy Company 13.0 Run 9-5/8" Surface Casing 13.1 R/U and pull 15.375"wear bushing. 13.2 Make a dummy run with the 9-5/8" casing hanger. 13.3 R/U Weatherford 9-5/8" casing running equipment. • Ensure 9-5/8" DWC/C x HT-38 XO on rig floor and M/U to FOSV. • Use BOL 2000 thread compound. Dope pin end only w/paint brush. • Consider R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.75" on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor& model info. 13.4 P/U shoe joint, visually verify no debris inside joint. 13.5 Continue M/U &thread locking shoe track assy consisting of: • (1) Shoe joint w/float shoe bucked on(thread locked). Install (2) centralizers on shoe joint over stop collars 10' from each end. • (1)Joint with float collar bucked on pin end &thread locked. Install (1) centralizer mid tube over a stop collar. • Ensure proper operation of float equipment while picking up. • Ensure to record S/N's of all float equipment and stage tool components. 13.6 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Install (1) centralizer across couplings on each joint. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cmt returns to surface. 9-5/8" 40#L-80 DWC Make Up Torques: Casing OD Min M/U Torque Max M/U Torque 9-5/8" 29,800 ft-lbs 34,800 ft-lbs Page 17 Version 0 Oct, 2016 • • Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 13.7 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 13.8 Slow in and out of slips. 13.9 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at(1) ft intervals to use as a reference when landing the hanger. 13.10 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 13.11 Have emergency slips ready to go in the event we cannot land the hanger. 13.12 R/U circulating equipment and circulate B/U. Reduce YP to <20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. Elevate hanger slightly above hang off point while circulating to avoid plugging the flutes. 13.13 After circulating, lower string and land hanger in wellhead again. Page 18 Version 0 Oct,2016 I • Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company Technical Specifications Connection Type: Size(O.D.): Weight(Wall): Grade: DWC/C Casing 9-518 in 40.00 Ibift(0.395 in) L-80 stancard Material L-80 Grade 80.000 Minimum Yield Strength (psi) 1111111111111111111111111F U SA 95.000 Minimum Ultimate Strength (psi) VAM USA 4424 W.Sam Houston Pkwy.Suite 150 Pipe Dimensions Houston,TX 77041 Phone:713-479-3200 9.625 Nominal Pipe Body O.D. (in) Fax:713-479-323-4 8.835 Nominal Pipe Body I.D.(in) E-ma is VAMUSAseies(82var -usa_com 0.395 Nominal Wall Thickness (in) 40.00 Nominal Weight(Ibsift) 38.97 Plain End Weight(lbs/ft) 11.454 Nominal Pipe Body Area (sq in) Pipe Body Performance Properties 916,000 Minimum Pipe Body Yield Strength (lbs) 3,090 Minimum Collapse Pressure (psi) 5,750 Minimum Internal Yield Pressure (psi) 5.300 Hydrostatic Test Pressure (psi) Connection Dimensions 10.625 Connection O.D. (in) 8.835 Connection I.D. (in) 8.750 Connection Drift Diameter (in) 4.81 Make-up Loss (in) 11.454 Critical Area (sq in) • 100.0 Joint Efficiency (%) Connection Performance Properties 916.000 Joint Strength (lbs) 16,360 Reference String Length (ft) 1.4 Design Factor 947,000 API Joint Strength (lbs) 916.000 Structural Compression Rating (lbs) 3,090 API Collapse Pressure Rating (psi) 5.750 API Internal Pressure Resistance (psi) 19.0 Maximum Uniaxial Bend Rating [degrees/100 ft] 1,, --y- Appoximated Field End Torque Values i 29,800 Minimum Final Torque (ft-lbs) 34,800 Maximum Final Torque (ft-lbs) 39.804` Connection Yield Torque (ft-lbs) Page 19 Version 0 Oct,2016 • Milne Point Unit B-034 Drilling Procedure Hilcorp Enav comnmr 14.0 Cement 9-5/8" Surface Casing 14.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud&water can be delivered to the cmt unit at acceptable rates. • How to handle cmt returns at surface. Ensure vac trucks are on standby and ready to assist. • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. • Positions and expectations of personnel involved with the cmt operation. • Review test reports and ensure pump times are acceptable. • Conduct visual inspection of all iron used to route slurry to rig floor. 14.2 Document efficiency of all possible displacement pumps prior to cement job. 14.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cmt pump or treating iron will not be pumped downhole. 14.4 RAJ cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 14.5 Pump 5 bbls 10.5 ppg tuned spacer. Test surface cmt lines. 14.6 Pump remaining 55 bbls 10.5 ppg tuned spacer. 14.7 Drop bottom plug. Mix and pump cmt per below calculations. 14.8 Cement volume based on annular volume+ 100% open hole excess. Job will consist of lead& tail, TOC brought to surface. Estimated Total Cement Volume: Section: Calculation: Vol(BBLS) Vol(ft3) 12-1/4" OH x 9-5/8"casing: (1800'- 113')x 0.05578 bpf x 2 = 188 bbls 1056 ft3 Conductor x 9-5/8" casing: 113 x 0.26 bpf= 29.5 bbls 165 ft3 -2U Total LEAD: 217.5 bbls 1221 ft3 12-1/4" OH x 9-5/8" casing: (2300'- 1800') x .05578 bpf x 2 = 55.8 bbls 313 ft3 9-5/8" Shoe track: 90 x .0764 bpf = 6.88 bbls 38.6 ft3 Total TAIL: 62.7 bbls 352 ft3 3o3 s,< Page 20 Version 0 Oct,2016 • • Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company Cement Slurry Design: Lead Slurry Tail Slurry System ArcticCEM TM System SwiftCEM TM System Density 10.7 lb/gal 15.8 lb/gal Yield 4.298 ft3/sk 1.16 ft3/sk Mixed 21.13 gal/sk 5.04 gal/sk Water 14.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets "sticky", land the hanger on seat and continue with the cement job. 14.10 After pumping cement, drop top plug and displace cement with spud mud out of mud pits. 14.11 Ensure rig pump is used to displace cmt. Displacement calcs have proven to be very accurate using 0.101 bps for pump output. .0/ 3 14.12 Displacement calculation: d Iaa�r 2210' x .0764 bpf= 169 bbls total ° i4'`Z-44) 14.13 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 14.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Overdisplace by no more than 3 bbls before consulting—with drilling engineer. 14.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 14.16 Be prepared for cement returns to surface. Dump cmt returns in the cellar or open the shaker bypass line to the cuttings tank. Have sacks of sugar available and vac trucks ready to assist. Ensure to flush out any rig components used to route cmt. Page 21 Version 0 Oct, 2016 • • Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 14.17 Flush out BOP, and clean out above hanger. Remove landing joint. 14.18 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 14.19 Lay down landing joint and pack-off running tool. Ensure to report the following on WellEz: • Pre flush type,volume(bbls)&weight(ppg) • Cement slurry type, lead or tail,volume&weight • Pump rate while mixing, bpm,note any shutdown during mixing operations with a duration a. Pump rate while displacing,note whether displacement by pump truck or mud pumps,weight&type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume,whether plug bumped&bump pressure, do floats hold d. Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure e. Note if pre flush or cement returns at surface&volume f. Note time cement in place g. Note calculated top of cement h. Add any comments which would describe the success or problems during the cement job Send final "As-Run" casing tally & casing and cement report to lkeller(a�hilcorp.com and cdinrer@hilcorp.com This will be included with the EOW documentation that roes to the AOGCC. Page 22 Version 0 Oct, 2016 • • 14 Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 15.0 BOP N/U and Test 15.1 N/D the diverter&N/U 11" 5M tubing spool. 15.2 N/U 13-5/8"x 5M BOP as follows: • BOP configuration from Top down: 13-5/8"x 5M annular/ 13-5/8"x 5M Double gate / 13- 5/8"x 5M mud cross/ 13-5/8" Single gate • Double ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in btm cavity. • Single ram should also be dressed with 2-7/8" x 5" VBRs. • N/U bell nipple, install flowline. • Install (1) manual valve & (1) HCR valve on kill side of mud cross. (manual valve closest to mud cross). • Install (1)manual valve on choke side of mud cross. Install an HCR outside of the manual valve. a 15.3 Run 4"BOP test assy,rand out test plug (if not installed previously). • Test BOP to 250/3000—psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Ensure to leave "B" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. • We will need to test on the following sizes: 4" (for 4"DP workstring) 4-1-2" for liner and injection tubing. 15.4 R/D BOP test assy. 15.5 Keep spud mud in pits for intermediate hole section. 15.6 Set 10" ID wearbushing in wellhead. 15.7 Rack back 4" DP in derrick. 15.8 Keep 6" liners in mud pumps. Page 23 Version 0 Oct, 2016 . • • . ; Milne Point Unit B-034 Drilling Procedure = . Hilcorp Encrgy Company 16.0 Drill 8-1/2" Hole Section 16.1 P/U 8-1/2" 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 MWD is R/U and operational. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Install ported float in the BHA. 16.2 8-1/2"Mud Motor Directional Assy (GR and Res LWD): COMPONENT DATA Item OD ID Gauge Weight Top Length Cumulative Description Serial Number (in) (in) (in) (Ibpf) Connection (ft) Length (ft) 1 Tricone 5.000 3.000 8.500 42.83 P 4-1?2"REG 1.00 1.00 2 7'SperryDrill Lobe 7.+8-6.0 stg 7-000 4.952 93.13 B 4-1'2"IF 26.24 27.24 Stabilizer 9.625 3 Integral Blade 6.750 3.000 8.250 97.86 B 4-1.2"IF 7.68 34.92 4 63+4"DGR Collar 6.750 1.920 97.80 B 4-1.2"IF 6.75 41.67 5 6 3+4"EWR-P4 Collar 6.750 2.000 104.30 B NC 50 12.10 53.77 6 6 314' PWD 25KSI 6.750 1.905 96.30 B NC 50 6.44 60.21 7 6 3+'4"HCIM Collar 6.750 1.920 101.70 B NC 50 4.96 65.17 8 6 3''4"DM Collar 6.750 3.125 103.40 B NC 50 9.20 74.38 9 6 3'4"HOC 6.900 3.250 111.1 103.60 B NC 50 10.03 84.41 10 X-Over Sub 6.750 2.250 108.40 B 4"XT39 3.00 87.41 11 3 its 5"X 3' HWDP#49.3- NC50ilF} - 5.000 3.000 49.30 94.50 181.91 12 Jar 6.250 2.250 91.01 B 4"XT39 32.00 213.91 13 5jts 5"X 3' HWDP#49.3-NC50iIF; - 5.000 3.000 49.30 157.50 371.41 371.41 Page 24 Version 0 Oct, 2016 • • 11 Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 16.3 Primary Bit: Hughes Christensen Stylesheet GT Steeltooth Bits 8.5 in. (215.9 mm) GX 1 17 IADC 117 Maximum Penetration Aggressive drilling action because of very large cone . - 4r- t,t1r1 offset and deep intermesh tooth design with good ventilation. 4118 =, GX ST Technology This ST Technology improves the drilling efficiency of the , cutting structure with trimmer pads that remove uncut rock ribs at the cornet.o " ,- the hole,relieved cone steel,aggressive tooth pitches and active shear cutti _,. , gauge compacts. �'� High RPM Drilling Durable steel tooth bit designed for high rotary speeds in v soft formations with low compressive strength. d r ?Ivicer Jet A fourth jet is positioned in the center of the bit and utilized to . " prevent bit balling and the associated reduction in penetration rate. ., 4* 3 Bit SDedfica:ion Features XL,JF,J,CJ Bearing 1 Seal Package Journal/Shrouded 0-ring Inner Row N/A Nozzle Type Standard Heel Row N/A Center Jet Nozzle FF or VF Gauge Trimmers N/A Connection 4-1/2 REG API Gauge Row N/A Makeup Torque 12.0- 16.0 kft-lb(16.3-21.7 kNm) Tooth Hardfacing Endura Approx.Shipping weight 90 lbs(40.8 kg) OD Hardfacing Shirttail Operating Recommendations' rotation Sneed-For Rotary and Motor Applications.Max.Weioht On Bit 17-42 klb(7-18 to or kdaN) Page 25 Version 0 Oct, 2016 • • Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 16.4 8-1/2"hole section mud program summary: • Density: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system(1)ppg above highest anticipated MW. • Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. • Run the centrifuge continuously while drilling the production hole, this will help with solids removal. • MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. System Type: 8.8—9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Depthsensity ) Plastic Viscosity Yield Point LGS MBT HPHT pH Intermediate 8.8-9.5 / 15-25 15-20 <6% <20 <11.0 9-10 •.” Product Concentration Fresh Water 0.905 bbl soda Ash 0.5 ppb AQUAGEL 15 -20 ppb caustic soda 0.1 ppb(8.5—9.0 pH) BARAZAN D+ as needed BAROID 41 as required for 8.8—9.5 ppg PAC-L/DEXTRID LT if required for<10 FL ALDACIDE G 0.1 ppb 16.5 TIH w/ 8-1/2" directional assy. 16.6 Note depth TOC tagged on AM report. I 16.7 R/U and test casing to 2900 psi/30 min. Ensure to record volume/pressure and plot on FIT graph. AOGCC reg is 50% of burst= 5750/2 =—2900 psi. Test pressure for the well is 2900 psi. 16.8 Drill out shoe track and 20' of new formation. Page 26 Version 0 Oct,2016 "/ • ! 1 ti Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company q y 16.9 CBU and condition mud for FIT. ` ` I i(0 q (/z.�- 1) 1c = l-7s 16.10 Conduct FIT to 12.5 ppg EMW. 16.11 Drill 8-1/2"hole section to section TD per Geologist and Drilling Engineer. • Pump at 450-550 gpm. • 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 high viscosity sweeps to aid in hole cleaning. • Keep swab and surge pressures low when tripping. • Make wiper trips if necessary. • Take MWD surveys every stand drld. Surveys can be taken more frequently if deemed necessary. • 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. 16.12 At TD; pump low vis sweeps, CBU at least 3 times at maximum circulation and rotation, and pull a wiper trip back to the casing shoe. If backreaming is necessary: • Circulate at full drill rate (450—550 gpm). • 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 shoe and circ at least a b/u once at the shoe. 16.13 TOH with the drilling assy, L/D or handle BHA as appropriate. 16.14 No open hole wire line logs are planned. Page 27 Version 0 Oct, 2016 Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 17.0 Run 7" Intermediate Casing 17.1 R/U 7" casing running equipment. c. +4 • Ensure 7" DWC/C x HT-38 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. • R/U CRT if available. 17.2 M/U&threadlock shoe track assy consisting of: • (1)Float shoe joint w/float shoe bucked on. Install (2)hinged bow spring centralizers over a stop ring at 10' from each end. • (1)Baker locked joint. Install (1)hinged bow spring centralizer mid tube over a stop ring. • (1)Float collar joint w/float collar bucked on pin end. Install (1)hinged bow spring centralizer mid tube over a stop ring. • Ensure proper operation of float shoe and float collar. 17.3 Run 7" 26# L-80 DWC casing. • Fill casing while running using CRT or fill up line. • Use "BOL 2000"thread compound. Dope pin end only w/paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Install centralizers over couplings on every joint to 2,300' MD. No centralizers required above that. 17.4 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 17.5 Slow in and out of slips. 17.6 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at(1) ft intervals to use as a reference when landing the hanger. 17.7 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 17.8 Have emergency slips ready to go in the event we cannot land the hanger. 17.9 R/U circulating equipment and circulate B/U. Reduce YP to <20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. Elevate hanger slightly above hang off point while circulating to avoid plugging the flutes. Page 28 Version 0 Oct, 2016 • • 11 Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 17.10 After circulating, lower string and land hanger in wellhead again. 7" DWC/C Estimated M/U torques Casing OD Torque (Min) Torque (Max) Torque (Yield) 7" 18300 ft-lbs 21,100 ft-lbs 23,800 ft-lbs Technical Specifications Connection Type: Size(O.D.): Weight(Wall): Grade: DWCIC Casing 7 in 26.00 Ibift(0.362 in) L-80 2012 API Spec 5CT Coupl,ng 0.0. Material L-80 Grade artiOM 80.000 Minimum Yield Strength (psi) 1111111111111111111111111111111U SA 95.000 Minimum Ultimate Strength(psi) VAM USA 4424 W.Sam Houston Pkwy.Suite 15C Pipe Dimensions Houston,TX 77041 Phone:713-479-3200 7.000 Nominal Pipe Body O.D. (in) Fax:713-479-3234 6.276 Nominal Pipe Body I.D.(in) E-mail:V MUSAsaIesttam-usti.cum 0.362 Nominal Wall Thickness(in) 26.00 Nominal Weight (lbs/ft) 25.69 Plain End Weight(lbs/ft) 7.549 Nominal Pipe Body Area(sq in) Pipe Body Performance Properties 604.000 Minimum Pipe Body Yield Strength(lbs) 5.410 Minimum Collapse Pressure(psi) 7.240 Minimum Internal Yield Pressure(psi) 6.600 Hydrostatic Test Pressure (psi) Connection Dimensions 7.875 Connection O.D. (in) 6.276 Connection I.D.(in) 6.151 Connection Drift Diameter(in) 4.50 Make-up Loss(in) 7.549 Critical Area (sq in) 100.0 Joint Efficiency(%) Connection Performance Properties 604.000 Joint Strength (lbs) 16,590 Reference String Length(ft) 1.4 Design Factor 641.000 API Joint Strength(lbs) 302.000 Compression Rating(lbs) 5.410 API Collapse Pressure Rating (psi) 7.240 API Internal Pressure Resistance(psi) 26.2 Maximum Uniaxial Bend Rating(degrees/100 ft] Appoximated Field End Torque Values 18,300 Minimum Final Torque(ft-lbs) 21.100 Maximum Final Torque(ft-lbs) 23.800 Connection Yield Torque(ft-lbs) Page 29 Version 0 Oct, 2016 • • Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 18.0 Cement 7" Intermediate Casing 18.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. • How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Positions and expectations of personnel involved with the cmt operation. • Document efficiency of all possible displacement pumps prior to cement job. 18.2 R/U cmt head (if not already done so). Ensure top and bottom plugs are loaded correctly. 18.3 Pump 5 bbls 10.5 ppg spacer. Close low torque on plug dropping head, test surface cmt lines to 4000 psi. 18.4 Pump remaining 35 bbls 10.5 ppg spacer. 18.5 Drop bottom plug, Mix and pump slurry per below calculations: Section: Calculation: Vol(BBLS) Vol(ft3) LEAD: 9-5/8" casing x 7" casing: 2300' x 0.02886 bpf= 66 bbls 370 ft3 8-1/2" OH x 7"casing: (4300 - 2300)x 0.02259 bpf x 2 = 90 bbls 505 ft3 Total Lead: 156 bbls 875 ft3 3 Ci 5 TAIL: 8-1/2" OH x 7"casing: (4,800' —4,300') x 0.02259 bpf x 2 22.5 bbls 126 ft3 TAIL: 3.5 bbls 20 ft3 7" Shoe Track: 90' x .038 bpf= Total Tail: 26 bbls 146 ft3 /ZS-5 k 11-716 (g Page 30 Version 0 Oct,2016 • • 14 Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company Slurry Information Lead Slurry Tail Slurry System ExtendaCEM TM System SwiftCEM TM System Density 11.7 lb/gal 15.8 lb/gal Yield 2.375 ft3/sk 1.16 ft3/sk Mixed 11.297 gal/sk 5.04 gal/sk Water 18.7 After pumping cement, drop top plug and displace cement with drilling mud. Use rig pumps for displacement. Ensure to have a good baseline measurement for pump displacement ahead of time. Displacement calcs: • 4,200' x .038 bpf= 1,6_abbls. `/ G5'k 18.8 Monitor returns c1os'ely while displacing cement. Adjust pump rate if necessary. 18.9 Do not overdisplace by more than %2 shoe track volume. Total volume in shoe track is 3.5 bbls 18.10 There should be +/- 50 bbls cmt returns to surface.'Be prepared to handle cmt. 18.11 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. • If this is the case, monitor the pressure on the casing and do not let it exceed 500 psi over the final pump pressure. 141 Page 31 Version 0 Oct, 2016 • Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company Ensure to report the following on wellez: • Pre flush type,volume(bbls)&weight(ppg) • Cement slurry type, lead or tail,volume&weight • Pump rate while mixing,bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing,note whether displacement by pump truck or mud pumps,weight&type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume,whether plug bumped&bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface&volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the success or problems during the cement job Send final "As-Run" casing tally & casing and cement report to lkeller@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 18.12 R/D cement equipment. Flush out wellhead with FW. 18.13 Back out and L/D landing joint, flush out wellhead with FW. 18.14 M/U pack-off running tool and pack-off to bottom of landing joint. Set casing hanger pack-off. Run in lock downs and inject plastic packing element. Test void to 250/4000 psi for 10 min. 18.15 Lay down landing joint and pack-off running tool. 18.16 After sufficient wait time, R/U and run a CBL across 7" casing. Page 32 Version 0 Oct,2016 III/ • Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 19.0 Drill 6-1/8" Hole Section 10. Ve 3, R,4-7,..,- b - 19.1 P/U 6-1/8" 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. Hydraulics calculations and recommended TFA is attached below. • Workstring will be 4" 14# S-135 HT-38 • Install ported float above motor. / 19.2 6-1/8"BHA (Includes GR+Res LWD): �/ COMPONENT DATA MI 1111111111111111111.0 ItemOD ID Gauge Weight Top Length Cumulative # Description - Serial Number (in) (in) (in) (Ibpf) Connection (ft) Length (II) 1 Tricone 4.500 1.500 6.125 48.18 P 3-1.2"REG 0.80 0.80 2 4 3.-4`SperryDnll Lobe 7'8-2.9 stg 4.750 2.901 44-52 B 3-1:2"IF 27.29 28.09 3 Non-Mag Integral Blade 4.750 2.313 5.875 46.07 B 3-1,'2"IF 5.60 33.69 4 Float Sub 4.750 2.250 46.84 B 3-1.2"IF 3.00 36.69 5 4 3.,4'SP4 Resistivity Collar 4.750 1.250 48.20 B NC 38 22.50 59.19 6 4 34"DM Collar 4.750 2.610 47.00 B 3-112"IF 8.56 67.75 7 4 3,4"PWD 4.750 1.250 47.90 B NC 38 9.23 76.98 8 4 1.4"HOC 4.750 2.812 46.10 B NC 38 10.86 87.84 9 NMDC 4.750 ® 46.07 B 3-12"IF 30.00 117 84 10 NMDC 4-750 2.313 46.07 B 3-12"IF 30.00 147.84 11 X-Over Sub 4.750 2.500 MI 43.66 B 4"XT39 1.67 149.51 12 2 its 4"X 2-9116`HWDP#29.7-XT-31. 4.000 2.563 29-70 63.00 212.51 13 4-314"Dailey Hyd Drilling Jar 4.750 2.250 ® 46.84 B 4"XT39 44.00 256.51 14 9 its 4"X 2-9116'HWDP#29.7-XT-3• 4.000 2.563 29.70 283.50 540.01 Total: 540.01 Page 33 Version 0 Oct, 2016 • • 111 Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 19.3 Primary Bit: 6. 125 in. (155.6 mm) TD505S DART Approved The well balanced and experienced Drilling Application Review Team(DART)carefully analyze the application to propose the right solution for your needs.The Network Behind the Solution. StaySharpTM Polished(utter Technology StaySharprM polished cu ar, S tailored to improve abrasion and impact resistance as well as dia degradation mitigation.In addition,the industry's only polished eliminate buildup on the cutter face, enhancing cutting action an removal increasing performance. Enhanced Directional Control Bit profile,gauge configuration,shorte up length and Baker Hughes torque management technology provide stable design platform that mitigates vibration,holds toolface control an. delivers on-plan build-up rates. StayTough" Hardfacng Proprietary metallurgy and application techni+ "`* h' enhance durability and reliability,reducing bit erosion and abrasion in a variety of environments. Bit Specifica::io1-s IADC 5233 Junk Slot Area 10.854 sq.in (70.00 sq.cm) Number of Blades 5 Bit Breaker S Cutter Quantity(Face,Backup) (16, 5) Connection 3-1/2 Reg Pin Primary Cutter Size 0.625 in(15.9 mm) 4 118' Bit Sub 5.2-5.7kft-lb(7.0-7.7kNm) Makeup Torque 4 1t4" Bit Sub 6.3-6.9kft-Ib(8.6-9.4kNm) Number of Nozzles 5 CSP 4 1r2'Bit Sub 7.6-8.4kft-lb(10.3- 11.4kNm) Fixed TFA 0 sq.in(0 sq.mm) Features EC, MB,OP, PT2, Sl, U4 Gauge F Makeup Length 2 in (50.8 mm)1 6.65 in(168.9 mm) Ref.Part Number X20668 Operating Recommendations" Hydraulic flow rate:200-450 gpm(750-1700 1pm).Rotation Speed:For Rotary and Motor Applications.Max.Weight On Bit: 16 klb(7 to or kdaN) Page 34 Version 0 Oct, 2016 • • Milne Point Unit B-034 Drilling Procedure Hilcorp Energy company 19.4 6-1/8"hole mud program summary: • Density: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1)ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg. • PVT System: An electronic PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, and Toolpusher office. • Hydrates: Hydrates have been encountered on"B"pad at 3200' TVD. Be prepared and don't stop to circulate out gas. Control drill when hydrates encountered. • Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. • Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 —9.0 range with caustic soda. Daily additions of ALDACIDE G/X-CIDE 207 MUST be made to control bacterial action. • Casing Running: Reduce system YP with DESCO as required for running casing as allowed(do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP <20 (check with the cementers to see what YP value they have targeted). System Type: 8.8—9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL Temp pH 6-1/8" 8.8-9.5 75-175 20-40 25-45 <10 <70° F 8.5-9.0 Page 35 Version 0 Oct,2016 • • Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company System Formulation: Gel + FW spud mud Product Concentration Fresh Water 0.905 bbl soda Ash 0.5 ppb AQUAGEL 15 -20 ppb caustic soda 0.1 ppb(8.5—9.0 pH) BARAZAN D+ as needed BAROID 41 as required for 8.8—9.5 ppg PAC-L/DEXTRID LT if required for<10 FL ALDACIDE G 0.1 ppb 19.5 TIH w/6-1/8" directional assy to above TOC. Shallow test MWD and LWD on trip in. 19.6 Note depth of TOC on morning report. Circ B/U—ensure to keep bit moving so that we do not wear a hole in the casing. -;</f6 19.7 R/U and test casing to 3,60-0 psi/30 min. Ensure to record volume/pressure and plot on FIT graph. AOGCC reg is 50% of burst. 19.8 Drill out shoe track and 20' of new formation. 1 3 8 q o -r ( 12-.S—`� yy3a 19.9 CBU and condition mud for FIT. 19.10 Conduct FIT to 12.5 ppg EMW. k��� 3' 6-7 jec 19.11 Drill 6-1/8"hole section to section TD per Geologist and Drilling Engineer. • Pump at 250-290 gpm. • 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 water or other low vis sweeps to aid in hole cleaning. • Keep swab and surge pressures low when tripping. • Make wiper trips if necessary. • Take MWD surveys every stand drld. Surveys can be taken more frequently if deemed necessary. • 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. 19.12 At TD; pump hi-vis sweeps, CBU at least 3 times at maximum circulation and rotation, and pull a wiper trip back to the window. If backreaming is necessary: • Circulate at full drill rate (250-290 gpm). • Rotate at maximum rpm that can be sustained. • Limit pulling speed to 5 — 10 min/std(slip to slip time, not including connections). Page 36 Version 0 Oct, 2016 0 • li Milne Point Unit B-034 Drilling Procedure Hilcorp Enemy Company • If backreaming operations are commenced, continue backreaming to the shoe and circ at least a b/u once at the shoe. 19.13 TOH with the drilling assy, stand back BHA if possible. Rabbit DP on TOH. 19.14 No additional logs are planned for the 6-1/8"hole section. Page 37 Version 0 Oct, 2016 • • 111 Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Compmy 20.0 Run 4-1/2" Injection Liner 20.1 Ensure rams have been tested on 4-1/2"test joint prior to running liner. 20.2 M/U liner cement manifold stand and rack back in derrick. Ensure wiper dart loaded correctly. 20.3 Ensure wear bushing is installed in wellhead. 20.4 R/U 4-1/2" casing running equipment. • Ensure 4-1/2"HTTC x HT-38 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. 20.5 Run 4-1/2" injection 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. 4-1/2" VAM HTTC M/U torques Casing OD Minimum Maximum Yield Torque 4.5" 6,910 ft-lbs 9,350 ft-lbs 14,400 ft-lbs 20.5 M/U &threadlock shoe track assy consisting of: • (1) Float shoe joint w/float shoe bucked on. Should have solid body centralizer pre-installed on joint. • (1) Float collar joint w/float collar bucked on pin end. Should have solid body centralizer pre-installed on joint. • (1) Landing collar joint w/landing collar bucked on pin end. Should have solid body centralizer pre-installed on joint. Page 38 Version 0 Oct,2016 • 0 111 Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company Issued on:05 Jun.2015 by Jean-Guillaume Besse -D VIM BATA SED REON SI-PD NFORMATIVE ONLY. Connection Data Sheet BASED ON SI-PD 101156 OD Weight Wall Th. Grade API Drift Connection 4 1/2 in. 13.50 lb/ft 0.290 In. 1.80 3.795 In. VAM®HTTC PIPE PROPERTIES CONNECTION PROPERTIES `,Nominal OD 4.500 in. Connection Type Premium T&C Nominal ID 3.920 in. Connection OD(nom) 4.930 in. Nominal Cross Section Area 3.836 sqin. Connection ID(nom) 3.849 in. Grade Type API SCT Make-Up Loss 4.380 in. Min.Yield Strength 80 ksi Coupling Length 9.917 in. Max.Yield Strength 95 ksi Critical Cross Section 3.836 sqin. Min.Ultimate Tensile Strength 95 ksi Tension Efficiency 100 Mo of pipe Tensile Yield Strength 307 klb Compression Efficiency 100%of pipe Compressive Yield Strength 307 klb Compression Efficiency with Sealability 80 Ma of pipe Internal Yield Pressure 9,020 psi Internal Pressure Efficiency 100%of pipe Collapse pressureyyyy�yy�y--p��-� yy�-:t�55''''�""'yy'YY 8,540 psi External Pressure Efficiency 100%of pipe ii Tensile Yield Strength 307 klb Min.Make-up torque 6,910 R.lb Compression Resistance 307 klb Opti. Make-up torque 8,130 ft.lb Compression with Sealability 246 klb Max.Make-up torque 9,350 ft.lb Internal Yield Pressure 9,020 psi Max.Torque with Sealability 12,350 ft.lb External Pressure Resistance 8,540 psi Max.Torsional Value 14,400 ft.Ib Max.Bending 77°/l00ft Max.Bending with Sealability 33°/100ft Max.Load on Coupling Face 158 klb 00 you need help on this product?-Remember no one knows VAM°like VAM Cana doIvamfieldservice.com ukOvamfieIdservice.com chlnaCIavamfieldservice.com usa I vamfieidservice.corn dubaW vernfieldservice.com bakuI vamfieldservice.com mexico cvamfleldserv/Ce.com nigerla®vamfleldservice.com singaporeipvemheldservice.corn brazilIvamfieldservice.com angolalvamrieldservice.com australiatdvamfieldservice.com Over 140 VAM®Specialists available worldwide 24/7 Por Rig Site Assistance Other Connection Data Sheets are available at www.vamservkes.com 20.6 Ensure to run enough liner to provide for approx 100' overlap inside 7" casing. Ensure hanger/pkr will not be set in a 7" connection and the packer should be above the 7" float collar. 20.7 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. 20.8 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. 20.9 Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 20.10 RIH w/liner on DP no faster than 1-1/2 min/ stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. Page 39 Version 0 Oct, 2016 • • Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 20.11 Fill DP with Top drive every 10 stands or as appropriate. 20.12 Slow in and out of slips. Ensure accurate slack off data is gathered during RII1. Record shoe depth+ SIO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 20.13 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 20.14 If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 20.15 P/U the cmt stand and tag bottom with the liner shoe. P/U 2' off bottom. Note slack-off and pick-up weights. Record rotating torque values at 10, 20, & 30 rpm. 20.16 Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting pressure (1500 psi). Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling fluid by adding water and thinners. 20.17 Reciprocate &rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 40 Version 0 Oct, 2016 • Milne Point Unit B-034 Drilling Procedure Hilcorp EnergY ComP.ny 21.0 Cement 4-1/2" Production Liner 21.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. • How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Positions and expectations of personnel involved with the cmt operation. • Document efficiency of all possible displacement pumps prior to cement job. 21.2 Rotate &reciprocate the liner during cmt operations. This is the most effective method to ensure effective mud and wall cake removal and a good quality cmt bond. 21.3 Pump 5 bbls 10 ppg spacer. 21.4 Test surface cmt lines to 4500 psi. 21.5 Pump remaining 15 bbls 10 ppg spacer. 21.6 Mix and pump 15.8 ppg SwiftCem cmt per below recipe. Ensure cmt is pumped at designed weight. Job is designed to pump 100% OH excess. Section: Calculation: Vol(BBLS) Vol(ft3) 7"x 4"DP Overlap: 200' x 0.022 = 4.4 25 7" x 4-1/2" Liner Overlap: 100' x 0.019 = 1.9 11 6-1/8" OH x 4-1/2" Liner: (5,400'—4,700')x 0.0167 x 2 = 23.4 131 Shoe Track: 90' x 0.014 = 1.3 7 Total Volume: 31 174 j SJ 5k Tail Slurry System SwiftCEM TM System Density 15.8 lb/gal Yield 1.15 ft3/sk Mixed Water 4.99 gal/sk Page 41 Version 0 Oct, 2016 • Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 21.7 Drop DP dart and displace with drilling mud. 21.8 Reduce pump rate to 3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re-zeroed at this point. 21.9 If elevated displacement pressures are encountered,position liner at setting depth and cease reciprocation. Monitor returns &pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 21.10 Bump the plug and pressure up as required by Baker procedure to set the liner hanger(20% above nominal setting pressure. 2500 psi is nominal setting pressure. Pressure up to 3000 psi to confirm hanger setting. 21.11 Slack off total liner weight plus 20k to confirm hanger set. 21.12 Do not overdisplace by more than 1/2 shoe track. Shoe track volume is 1.3 bbls. 21.13 Pressure up to 4200 psi to release the running tool (HRD-E) from the liner. 21.14 Bleed pressure to zero to check float equipment. 21.15 P/U, verify setting tool is released, and expose setting dogs on top of tieback sleeve. 21.16 Rotate slowly and slack off 50k downhole to set the ZXPN liner top packer. 21.17 P/U to P/U weight plus 1 ft. 21.18 Close annular and test 4" DP x 7" annulus to 1500 psi/ 10 min to test liner top packer. 21.19 Bleed off pressure, open up annular. 21.20 Pressure up to 500 psi down DP and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req'd to maintain 500 psi DP pressure while moving pipe until the pressure drops off rapidly, indicating pack-off is above the sealing area(ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 21.21 Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 21.22 Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re-tag the liner top, and circulate the well clean. Page 42 Version 0 Oct,2016 • • Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 21.23 Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 21.24 POOH, verify the liner top packer received the required setting force by inspecting the rotating dog sub. Backup release from liner hanger: 21.25 If the HRD-E tool still does not release hydraulically, left-hand(counterclockwise)torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 21.26 NOTE: Some hole conditions may require movement of the drillpipe to "work"the torque down to the setting tool. 21.27 After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. Ensure to report the following on wellez: • Pre flush type,volume(bbls)&weight(ppg) • Cement slurry type, lead or tail,volume&weight • Pump rate while mixing,bpm,note any shutdown during mixing operations with a duration • Pump rate while displacing,note whether displacement by pump truck or mud pumps,weight&type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume,whether plug bumped&bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface&volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the success or problems during the cement job Send final "As-Run" casing tally & casing and cement report to lkeller@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 43 Version 0 Oct, 2016 Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 22.0 Wellbore Clean Up & Displacement 22.1 M/U casing clean out assy complete with casing scraper assys for each size casing in the hole. • 3.75"bit or mill. • Casing scraper for 4-1/2" 13.5# casing. • +/- 600' 2-7/8"workstring. • PBR Polish Mills • 1 joint of 4" DP. • Casing scraper for 7" 26#casing. • 4" DP to surface. 22.2 TIH & clean out well to landing collar(+/- 5,300' MD). • Circulate as needed on trip in if string begins to take weight. • Circulate hi-vis sweeps as necessary to carry debris out of wellbore. • Ensure 3-3/4"bit does not land out on TOC prior to polish mills landing out on tieback sleeve. • Space out the cleanout BHA so that the bit is 15-30 ft above the landing collar when the polish mills have landed out on tieback sleeve. 22.3 After wellbore has been cleaned out satisfactorily usillg. mud, test casing to Ji/30 min. 4 ) 22.4 Displace drilling fluid in wellbore with a hi-vis pill followed by fresh water. • Consider catching drilling fluid in rain-for-rent tanks for use on a future well if feasible. • Circulate fresh water into wellbore until clean-up is satisfactory. Do not recirculate fluid, • After a couple circulations using FW, short trip the assy to bring the 7" scraper to surface. • RIH again&tag tieback sleeve with polish mills. Continue circulation as necessary until fluid cleans up. Make another short trip if necessary. • Pump a chemical train followed by clean water. 22.5 TOH w/clean out assy. LDDP on the trip out. Note any abnormal wear on the clean out assy. Page 44 Version 0 Oct, 2016 ! • Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 23.0 Completion Operations 23.1 R/U e-line unit and run a CBL across the 4-1/2" liner. R/D e-line unit. 23.2 R/U and run 4-1/2" injection tubing assy with GLM, XN profile, and bullet seal assy. • Ensure appropriate well control crossovers on rig floor and ready. • Monitor displacement from wellbore while RIH. 23.3 Run 4-1/2" injection tubing to position seal assy two joints above tieback sleeve. Record up & down weights. 23.4 M/U 4-1/2"to DP crossover. 23.5 M/U stand of DP to string, and M/U top drive. 23.6 Break circulation at 1 bpm and begin lowering string. 23.7 Note seal assy entering tieback sleeve with a pressure increase, Stop pumping and bleed off pressure, leave standpipe bleed off valve open. 23.8 Continue lowering string and land out on no-go. Set down 5 — 10k lbs. Mark the pipe at this depth as "NO-GO DEPTH". 23.9 P/U string& stand back DP stand, L/D XO. Note P/U weight on morning report. 23.10 M/U (or L/D) necessary joints and pup joints to position seal assy 1 ft above"NO-GO DEPTH" when tie-back hanger lands out in wellhead. 23.11 P/U hanger assy and landing joint. 23.12 R/U to circulate down DP. 23.13 Pump following volumes of fluids to freeze protect annulus: • 46.5 bbls diesel • 71 bbls inhibited packer fluid • 35 bbls diesel 23.14 Slack off and land hanger. 23.15 Confirm hanger has seated properly in wellhead. Make note of actual weight on hanger on morning rpt. 23.16 Run in hanger lock downs. Page 45 Version 0 Oct, 2016 • • 11 Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 23.17 Back out landing joint. M/U packoff running tool and install packoff on bottom of landing joint. Set tubing hanger pack off Test void to 3000 psi/ 10 min. 23.18 R/D casing running tools. 23.19 Test 7" x 4-1/2" annulus to 3600 psi/30 min. 23.20 Text 4-1/2"tubing and 4-1/2" liner to 3600 psi/ 30 min. 23.3 Install BPV and N/D BOP. 23.4 N/U tree adapter and tree. Conduct pressure tests of same to 500 psi low/ 5000 psi high for 10 min. 23.5 RDMO drilling rig. 24.0 Well Perforation: 24.1 R/U e-line unit and wireline BOPs. 24.2 Perforate well. 24.3 R/D eline unit and BOPs. Page 46 Version 0 Oct, 2016 • • 11 Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Compmy 25.0 Diverter Schematic rn n a«II / \ I 1 V0 Schaffer 21-114" V 2M Annular \ / NUS NJ 21-114"2M Riser------. /-1 16"Full Opening Knife Valve rue a\ a\a\al Li 41117..v Y Y W Y Y 21.114-2M cip n (3 Diverter"r NN, _ 16"Diverter Line MI NI as eI a.n F i Y as Y IVY 21-1i4"2M------ Spacer M- -Spacer Spool cilia O Cg WIIII 16-314"3M x---- 21-1/4"2M DSA {e Ilii: t ij �vuV Seaboard Casinghead,S-22-AP-8J 16"SOW x 16-314"3M: (2)ea 2-1116"5M studded outlets 20"Casing Page 47 Version 0 Oct, 2016 • S Milne Point Unit B-034 Drilling Procedure Hilcorp Enema Company 26.0 BOP Schematic I / \ 5 Hydril GK z Annular BOP 13-518"x 5M / Lell MI Mk +_ II .DU13-518" x 5M 00 g__. 0 El 6%.: II .... _ oe ' I n�� 1 �3"x 5M HCR ■ /, /k, ■ I"Ili �i 1 i i :' !if 1•i ``--Choke Line Kill Line ' ' � Cens L'...--s----3"x 5M Manual Gate Valve Y y —1;-1 13-518"x 5M _ a— 1 E I °Oeo 9 I .0111111.1 .---11"x5M di, i ob -2-1116"x 5M -1 f,i,jllial,j r 9-5/8"DBL IPS--.N.... "10" 10 2-1/16"x 5M III�� 1111,11 do ii 13-518"x 5M Casing Hanger -I I w 3 j(• 31 16-314"NOM I 13-518"x 9-5/8" 2-1116"x 5M 20"Casing 9-5/8"Casing Page 48 Version 0 Oct, 2016 I • II Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 27.0 Wellhead Schematic 31HILCORP ALASKA B-34 G&L - -� MQ-385 ICD47.3 • , r °.11 EST . 4-1/t6 }V - A.� ' . 4-1/16 5M 1 103.7 :r• /r, •� 1f •l1' _\10.i•i i EST --■:• ta•\..4• i! I. �•�,/ .'�i' I. •• 4-1/16 5M J . ,••, 4-1/16 5M--- •0• HYDRAULIC • • ACTUATED • • 28.4 ^G ,., EST 56.4 EST 4-1/16 5M_.. '•04 180.5 EST ill W Lre ADAPTER. SM-E-N E■rIIII CI-11 SM X 4-1/16 5M 11 5M TUBING HANGER ' o_ 0 b. SM-E-2 1 • la 17.2 11 X 4-1/2 ."r I I /� EST 0 CASING HANGER 11 11 S l- SMB-22_.., ,,LL,1J - 2-1/16 5M 11 X 7 J ,- -I W/SEAL ASSEMBLY 0 EST a:Ia inn 40:7411,7':' tai. 76.8 EST III MI 1. 2-.1/16 5M 9-5/8 DBL IPS ._,..,, ., �qI F. .t 13-5/8 5M CASING HANGER S-22 1 4 1 ul 13-5/8 X 9-5/8 31.5 ■. Xi I .:...r4f.k as PT :jEST4� / 2-1/16 Su f I REF LAYOUT 00-000619 26 CASING— 9-5/8 CASING—. MN 7 CASING -- 2 5.000 PSI YrELLHEAO ASSEMBLY t&1E 4-1/2 TUBING - 20 X 9-5/8 X 7 X 4-1/2 OmENSICNS SHOWN CN T14S CRANK ARE ... .. ...... ESTIMATES ONLY AND CAN VARY SENHCANTLY RESTRICTED CONFIDENTIAL DOCUMENT-- - - WOOING ON RAW WIIERUL LENGTHS. M". *r...1.1•11..0,110....r..w.8 r" RPL 10" 1:13 1."040CT16 .rV 14:04TNO GUARANTEE Or STACKUP GHT IS IMPLIED. r.. no .w. ... on 0 IMMO .ww r.. on _...... zanO a�• ors cr,. ..w rjrm.. g.� COMM MO. DIMENSIONS SNOW SNOiAO BE CONSKIEREO �w eoraO°C�°`"'.wa w w..,.,.•,,..a..r FOR REFERENCE PURPOSES CN.Y. l.:10.1r=0...• """'.MI rw"'•nm Ll� Q... P—21544 2 Page 49 Version 0 Oct, 2016 • Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 28.0 Days Vs Depth Days Vs Depth 0 gonso8-034 -8-28 -8-29 2000 4000 -- 6000 n- a v 3 ar 8000 10000 12000 14000 0 5 10 15 20 25 Days Page 50 Version 0 Oct, 2016 • II Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 29.0 Formation Description GE ERALIZED GEOLOGICAL R CAS __. SS GEOLOGICAL TVD LITH DESCRIPTION SUGGESTED Mtn)WT. I All GeoL °•° 8.5 910 9) f 5 1Q_0 10.5 Depths Gubik . . Unconsolidated coarse to medium TVL I I a ' . Tolerant600 .. -. . a sand and small gravel with minor SS MUD PPG +r_ion , '' ,- a.. siltstone. Note: This is " . .. - Heavy gravel conglomerate to 1400'. — ,a generic mud ,000' E ry Wood fragments throughout t00 weight chart. a • permafrost zone. See individual 4 4, welt plan for 1700' .° Base permafrost specific mud • weights. 2,000' C • 2000 Sagavahirktok L ' 9.2 to 9.3 ppg Predominantly clay to +1-3000' with A • interbeds of sand. clays and silt- - stones with occasional shows of coal 9.4 • ■ _▪ � around 2700'. Pebbley gravel(up to pg down to 2700'. 1 3,0001 Continued interbeds of sand,clays and r � siltstones with heavy coal sections 309" 2800-3200. KA: 3800-3900 K-sands UGNU: Series of coarsening upward (-A,B.C,D) UGNU L-sands sands which are made up of: (from top MA: i-A,B) to bottom)coarse sand, fine sand, silty 4070- M-sands shale and some coal. Better developed 4140 t-A,B,C) = intervening shales as you progress into the L and M (deeper). ' y- 4,000' Possible hydrocarbon bearing sands 4000 I NA: Schrader Bluff Sands 4300- N-Sands Continued layered coarsening upward sands as 4600 °. i-A,B,C.D, above except more condensed. Possible E.F( hydrocarbon bearing and potentially productive OA: 0-Sands in the"0"and "N"s7.-,,-I- Tend to be water wet 4550- more than a mile to the east. 4800 ' 0,E,F) C D,E,F) . 9. . . 1 Primarily clay with some silty sandstone below SchraderBluff(+1-4550)to +1-460°- 4600- Top of — -. +t-5200 where sandstone begins making t 4700' 1 1 Page 51 Version 0 Oct, 2016 Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 30.0 Anticipated Drilling Hazards Surface Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section efficiently—control ROP and avoid loading the hole with gas. Minimize gas belching by reducing flow rate if necessary. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud cut weight. Add 1.0—2.0 ppb DRILTREAT to the system to help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: There are a number of adjacent wells in the vicinity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations btwn surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. Page 52 Version 0 Oct, 2016 Milne Point Unit B-034 111 Drilling Procedure Hilcorp Energy Company 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic I-12S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Intermediate & Production Hole Sections: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of> 500 gpm. Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There are no known faults in either hole section. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on"B"pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: There are no abnormal pressures or temperatures expected while drilling this well. Page 53 Version 0 Oct, 2016 • • Itir Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 31.0 Doyon 14 Rig Layout a) N VINTDIESEL STOWE TN. [.. I'd7111"2 ... �0 2 I I CA I. I 1 1 i l la '1 f 1 1 1� ��I � 71 1 'i F7 I In: _ III! Pil 61 PPE lb=Tit III Pi N Or -. 1 ( IJ 1 Cp. iatiswilice it -7---.1 Ai L I IIIME 8 I ® 1 I oy �"1 ,I1 11 4I ,+1 p .,1 1 I,I,,:,,';,4 a 45 ".1:t I- l 1-01.- 11 l iiI 11 fg 1 Page 54 Version 0 Oct, 2016 • • II Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 32.0 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 55 Version 0 Oct,2016 _ i • n Milne Point Unit B-034 ," Drilling Procedure t f,. ; Hilcorp Energy Company 33.0 Choke Manifold Schematic - Y F-,?� z o d : 4► r v 4<3 w d n l lir 0 < < C = n —�LTA o l� /rTi C) co ., __ Wn �, N N zm z . Z NN N. nH N o , O T . di _A... . . u = y 0 no N w1r w (D _ m .t c, `v , W P 9D C O a ii5 vi In fp W fprD n< un ei 3 2 N o - Xi M c CT n Imo. w EOo t 0 3 CI D- nyax- wm - ° a mak )1) 4C .. ..,(11/ 0 4171•11 A CI MUM 0, r ...,. 0 rc. .. 0.4 \r . "%V 0 A it Atio kV i irk—i Do n o , PO ‘ e ,,..., w rs ..,.. _....,,,, 1 ..., C. Cil Page 56 Version 0 Oct,2016 s • Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 34.0 Casing Design Information Calculation & Casing Design Factors Milne Point Unit DATE: 10-5-2016 WELL: MPU B-034 DESIGN BY:Luke Keller Design Criteria: Hole Size 12-1J4' Mud Density: 9.5 Hole Size 8-1!2" Mud Density: 9.5 Hole Size 6-1/8" Mud Density: 9.5 Drilling Mode MASP(6-1/8"): 1496 psi(see attached MASP determination&calculation) Production Mode MASP: 1496 psi(see attached MASP determination &calculation) Collapse Calculation: Section Calculation 1, 2, 3 Max MW gradient external stress and the casing evacuated for the internal stress Casing Section Calculation/Specification 1 2 3 Casing OD 9-518" 7" 4-1/2" Top(MD) 0 0 4,700 Top(TVD) 0 0 3.805 Bottom (MD) 2,300 4,800 5,356 Bottom (TVD) 1,969 3.892 4,427 Length 2,300 4.800 656 Weight(ppf) 40 26 13.5 Grade L-80 L-80 L-80 Connection DWC DWC VAM HTTC Weight wfo Bouyancy Factor(lbs) 92,000 124,800 8,856 Tension at Top of Section (lbs) 92,000 124.800 8,856 Min strength Tension (1000 lbs) 916 604 307 Worst Case Safety Factor(Tension) 9.96 4.84 34.67 Collapse Pressure at bottom (Psi) 985 1.946 2,258 Collapse Resistance w/o tension (Psi) 3,090 5.410 8,540 Worst Case Safety Factor(Collapse) 3.14 2.78 3.78 MASP(psi) 1,181 1.496 1,496 Minimum Yield (psi) 5,750 7.240 9,020 Worst case safety factor(Burst) 4.87 4.84 6.03 Page 57 Version 0 Oct, 2016 0 • II Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 35.0 8-1/2" Hole Section MASP II Maximum Anticipated Surface Pressure Calculation 8-1/2"Hole Section Hilcor MPU B-034 Milne Point MD ND Planned Top: 2300 1969 Planned TD: 4800 3892 Anticipated Formations and Pressures: Formation ND Est Pressure Oil/Gas/Wet PPG Grad Sagavanirktok(top) 1,700 743 Wet 8.4 0.437 Ugnu 3,800 1661 Wet 8.4 0.437 Offset Well Mud Densities Well MW range Top(ND) Bottom(ND) Date MPB- 11 9.5-9.6 Surface 4,500 1985 MPB- 12 9.0-9.8 Surface 4,500 1985 MPB- 13 9.5-9.6 Surface 4,500 1985 MPB- 14 9.1-9.4 Surface 4,500 1985 MPB- 15 8.6-9.8 Surface 4,500 1985 MPB- 16 8.9-9.6 Surface 4,500 1985 MPB- 17 8.6-9.7 Surface 4,500 1985 MPB-19 9.2-9.7 Surface 4,500 1985 MPB-21 9.3- 10.1 Surface 4,500 1986 MPB-25 8.3-9.4 Surface 4,500 1997 MPB-28 9.0-9.4 Surface 4,435 2016 MPB-29 8.8-9.2 Surface 4,400 2016 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 9.5 ppg. 3. Calculations assume Ugnu 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: 1969(ft)x 0.7(psi/ft)= 1378 psi 1378(psi)-[0.1(psi/ft)*1969(ft))= Drilling Mode MASP MASP from pore pressure(wellbore completely evacuated to gas) 3892(ft)x 0.437(psi/ft)= 1700 psi 1700(psi)-[0.1(psi/ft)*3892(ft)j= 1311 psi Summary: 1. MASP while drilling 8-1/2" Intermediate hole is governed by 9-5/8"casing shoe integrity. Page 58 Version 0 Oct, 2016 • Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 36.0 6-1/8" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 6.125" Hole Section f#ilcorp MPU B-034 Milne Point MD TVD Planned Top: 4800 3892 Planned TD: 5356 4427 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Ugnu 3,800 1661 Wet 8.4 ./ 0.437 Offset Well Mud Densities Well MW range Top(TVD) Bottom (TVD) Date MPB- 11 9.5-9.6 Surface 4,500 1985 MPB- 12 9.0-9.8 Surface 4,500 1985 MPB- 13 9.5-9.6 Surface 4,500 1985 MPB- 14 9.1-9.4 Surface 4,500 1985 MPB- 15 8.6-9.8 Surface 4,500 1985 MPB- 16 8.9-9.6 Surface 4,500 1985 MPB-17 8.6-9.7 Surface 4,500 1985 MPB-19 9.2-9.7 Surface 4,500 1985 MPB-21 9.3-10.1 Surface 4,500 1986 MPB-25 8.3-9.4 Surface 4,500 1997 MPB-28 9.0-9.4 Surface 4,435 2016 MPB-29 8.8-9.2 Surface 4,400 2016 Assumptions: 1. Fracture gradient at shoe is estimated at 0,8 psi/ft based on field test data. 2. Maximum planned mud density for the 6-1/8" hole section is 9.5 ppg. 3. Calculations assume Ugnu contains 100%gas(worst case). 4. Calculations assume worst case event is complete evacuation of wellbore to gas. Fracture Pressure at 7"shoe considering a full column of gas from shoe to surface: 3892(ft)x 0.8(psi/ft)= 3114 psi 3114(psi)-(0.1(psi/ft)*3892(ft))= 2725 psi Drilling Mode MASP MASP from pore pressure(wellbore completely evacuated to gas) 4427(ft)x 0.437(psi/ft)= 1935 psi ' 1935(psi)-[0.1(psi/ft)*4427(ft)J= 1496 psi Summary: 1. MASP while drilling 6-1/8" Intermediate hole is governed by wellbore completely evacuated to gas from the Ugnu. Page 59 Version 0 Oct, 2016 S • 111 Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 37.0 Spider Plot (NAD 27) (Governmental Sections) ' B,:9 / • / .\\ / 1 1 • ' MPB-34 BHL \ / 4 ,, `, ti . MPB-34 TPH ,� \ • 0 — / , C &12 ` 0, , /' , 0 o% • • O 1 0 \ \ • 0 1 Sec'3 0 1 � 18 o 1 (630) , O 1 B , 0 O 1 , 0 1 // , °oI / , , 0 1 , / , 0 , 0 ' /, • 4 \ 0 i v, OI /,f/ ` • o I , /, C 1 / II • \ 0' / MILNE POINT UNIT, oi '' MPB-34 SHL ADL047437 U013N010E \ - U013N01 tE\!A -, :;,.. ' • rr • I•\ '' ADL047438 SII ` , — I , \ / , - _ I 1 / 5 "'IA... `�• // 1 I // II '/' /// '4 i ea ' \\\\ / I 1 i Sec.19 \ Sec 24 I I C... (633) v Legend , I I `; , 4 ' \ MPB-34 SHL Other Surface Holes(SHL) t I \ 1 \ ' MPB-34 TPH • Other Bottom Holes(BHL) 0420 t I / ! \ t I / I\ \ MPB-34_BHL - - Other Well Paths I II ,, / \\ \\\ • Oil and Gas Unit Boundary �,.,, ----It -_r --', \\ \ 111111 \ \ / j \ itir Milne Point Unit MPB-34 Well 0 50o i,000 Map Date:10/572016 Feet Page 60 Version 0 Oct, 2016 • •- Milne Point Unit B-034 II Drilling Procedure Hilcorp Energy Company 38.0 Surface Plat (As Built) (NAD 27) . , _,... i N 2900+ k to i oo 14 1 13 t 18 ,c, _ z c� a /N g c it? 17F16 PROJECT-- 0 • 20• ■21 • 181 19 •A-PAD I 't3-PAD T24 8-34 8• 112 I 2• f Is 24 .'[� 19 7• •14 . -'• '• •t3 L / TO GRAVEL SITE i• = 11 a 9• .16 _.� CFP 1 �f-PAD 10• 115 k„,••---. ' �, 23• 2'6 1 l 5 `0 3;■ 22 VICINITY MAP J2• •5A N.T.S. a LEGENQi • •3 ! SEC 25: I c 18 `` AS-BUILT CONDUCTOR 2288 •50 • EXISTING CONDUCTOR 10 •4 § ``ON%11111 t � 11 I -._.._...._� .._-- +N 1000 % ` OF A&Ai ,' •`.\p:�••• '•:t I �o B-PAD = ; 4 i • •/ •• • L. ... y *3 1., f othy F. Banhort ,f• . 1".% 10200 .. / NOTES; tttnisi sicca MOO 1. ALASKA SATE PLANE COORDINATES ARE ZONE 4 NAD27. 2. GEODETIC COORDINATES ARE NAO77. SURVEYOR'S CERTIFICATE 3. HORIZONTAL AND VERTICAL CONTROL. ARE BASED ON HP B-PAD I HEREBY CERTIFY THAT AM PROPERLY REGISTERED AND LICENSED OPERATOR MONUMENTS 13-1 AND B-2. TO PRACTICE LAND SURVEYING IN 4. ELEVATIONS ARE MP B-PAD DATUM, MEAN SEA LEVEL (M.S.L). THE STATE OF ALASKA AND THAT THIS AS-BUILT REPRESENTS A SURVEY 5. MEAN PAD SCALE FACTOR IS: 0.999905887 MADE BY ME OR UNDER MY DIRECT 6. DALE OF SURVEY: SEPTEMBER 27-28, 2016. SUPERVISION AND THAT ALL DIMENSIONS AND OTHER DETAILS ARE 7. REFERENCE FIELD BOOK: HC16-03, PGS. 24-33. CORRECT AS OF SEPTEMBER 28, 2016. LOCATED WITHIN PROTRACTED SEC. 18, T. 13 N., R. 11 E., UMIAT MERIDIAN, ALASKA WELL A.S.P. PLANT GEODETIC GEODETIC TOP OF SECTION BASE FLANGE NO. COORDINATES COORDINATES POSITION(DMS) POSIT1ON(D.DD) GRAVEL PAD OFFSETS ELEVATION Y=6,023,979.35 N 2,300.01 70'28'32.874" 70.4757984' 856' FSL B-34 X= 571,983.88 E 814.62 149'24'43.080" 149.4119666' 23'7 4.296' FEL NA DRAMA, KLEM aE .40065 . CjHilcorp Alaska 0.1L 10/3/16 Doll MO O9F"8'9 'P9 Q7 MILNE POINSKJ T B—PAD `1 Scat:---- AS—BUILT CONDUCTOR LOCATION 9010/3/1045x6 roa.saaaona oN 6a . r-400* WELL B-34 1 OF 1 NO lair of V9fri._. ry KOK Page 61 Version 0 Oct, 2016 III • II Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 39.0 Offset MW vs TVD Chart 0 -- —B-21 (1986) -B-25 (1997) -B-12(1985) 1000 \ 1 , — - B-11 (1985) t —B-15 (1985) \I —B-14(1985) 2000 fillpilr PIP —B-13 (1985) -B-17(1985) B-191985 ( ) 3000 -B-16(1985) i I 71 0 4000 t gik, NOW 01111"."- 5000 IIIVIr4 6000 *k\I, 7000 A N 8000 8.0 9.0 10.0 11.0 12.0 Mud Weight(PPG) Page 62 Version 0 Oct,2016 i Milne Point Unit B-034 Drilling Procedure Hilcorp Energy Company 40.0 Drill Pipe Information 4" 14# S-135 HT-38 400204138036211 Weatherford 4" 14.00 Ibfft Internal Coating S-135 WI HT 38 4-718" OD x 2-9/16" ID W/X 7000 Hard Banding Tool Joint DRILL PIPE SPECIFICATIONS Grade S-135 Connection HT 38 Interchangeable With Upset Type IU Internal Coating ! TK 34 XT Nominal Weight per Foot ", 14.00 lbs Adjusted Weight With Tool Joint per Foot d 15.65 lbs TOOL JOINT DATA Outside Diameter 4-7/8" inside Diameter 2-9/16" API Drift 2-7116' Rabbit OD.Suggested 2-3/8" Hard Band X 7000 Minimum Make-up Torque 12,200 ft-lbs Maximum Recommend Make-up Torque 17,700 ft-lbs Torsional Yield Strength 29,500 ft-lbs Tensile Strength 649,200 lbs TUBE DATA New I Premium Outside Diameter 4.000" 3.868' Inside Diameter 3.340" 3.340" Wall Thickness 0.330" 0.264" _ Cross Sectional Area 3.805 sq in 2.989 sq in Maximum Hook Load/Tensile Strength 513.600 lbs 403.500 lbs Slip Crushing (SDXL 431,900 lbs 341.300 lbs _ Burst Pressure 19.500 psi 18,400 psi Collapse Pressure 20.100 psi 13,800 psi Torsional Yield Strength 41,900 ft-lbs 32,800 ft-lbs Capacity W/Tool Joint 0.442 US gal/ft 0.442 US gal/ft_ Displacement W/Tool Joint 0.240 US gal/ft 0.223 US gal/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 63 Version 0 Oct, 2016 u S i Hilcorp Energy Company Milne Point M Pt B Pad Plan: MPB-34 MPB-34 Plan: MPB-34 wp05 Standard Proposal Report 05 October, 2016 HALLIBURTON Sperry Drilling Services HALLIBURTON •FERENCE INFORMATION • t+ Co-ordinate(N/E)Reference: Well Plan:MPB-34,True North ` t C) Vertical(ND)Reference: Plan:As-Built @ 57.40usft(=GL 23.7'+RF 33.6') Sperry Drilling ` Measured Depth Reference: Plan:As-Built @ 57.40usft(=GL 23.7+RF 33.6) Calculation Method: Minimum Curvature Project: Milne Point Hilcorp Energy Company Site: M Pt B Pad WELL DETAILS: Plan:MPB-34 Calculation Method: Minimum Curvature Ground Level: 23.70 Well: Plan:MPB-34 Error System: ISCWSA Wellbore: MPB-34 Scan Method: Closest Approach 3D -N/-S +E/-W Northing Easting Latittude Longitude Error Surface: Elliptical Conic 0.00 0.00 6023979.35 571983.88 70°28'32.874 N 149°24'43.080 W Design: MPB-34 wp05 Warning Method: Error Ratio DDI = 5.473 SECTION DETAILS Sec MD Inc Azi ND +N/-S +E/-W Dleg TFace VSect Target Annotation 1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.00 2 290.00 0.00 0.00 290.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3°/100':290'MD,290'TVD 3 490.00 6.00 15.00 489.63 10.11 2.71 3.00 15.00 9.70 Start Dir 5°/100':490'MD,489.63'TVD 4 782.49 20.00 352.61 774.05 74.83 0.22 5.00 -31.06 74.24 5 1190.76 40.41 352.61 1125.02 277.45 -26.07 5.00 -0.01 278.56 End Dir :1190.76'MD,1125.02'TVD 6 4524.76 40.41 352.61 3663.50 2420.90 -304.21 0.00 0.00 2439.93 Start Dir 5°/100':4524.76'MD,3663.5'TVD 7 5133.03 10.00 352.61 4207.40 2674.79 -337.16 5.00 180.00 2695.94 MPB-34 Ugnu MB End Dir :5133.03'MD,4207.4'ND 8 5356.01 10.00 352.61 4427.00 2713.19 -342.14 0.00 0.00 2734.66 Total Depth:5356.01'MD,4427'TVD SURVEY PROGRAM Date:2016-06-01T00:00:00 Validated:Yes Version: -800 Depth From Depth To Survey/Plan Tool 33.70 650.00 MPB-34 wp05 SRG-SS 650.00 5356.01 MPB-34 wp05 MWD+IFR2+MS+sag -400 - _ FORMATION TOP DETAILS 0- No formation data is available Start Dir 3°/100':290'MD,290'TVD Start Dir 5°/100':490'MD,489.63'TVD 400- -- 500 800- 0 End Dir : 1190.76'MD, 1125.02'TVD CASING DETAILS - 1�0 TVD MD Name Size 4427.00 5356.01 4 1/2" 4-1/2 1200- Pp c_ N co co 0 1600 �O co t 0. c) - 17 2000- X00 To - `L U_ - U) 2400- 7 2800-- 9(')�0 H Start Dir 5°/100':4524.76'MD,3663.5'TVD 3200-{ DSO 0- 3600- �� End Dir :5133.03'MD,4207.4'ND 4000- 6009' MPB-34 Ugnu MB- 5356 Total Depth:5356.01'MD,4427'TVD 4400- 41/2"" MPB-34 wp05 1 0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 Vertical Section at 353.00° (800 usft/in) HALLIBURTV Hilcorp Project: Milne Point • WELL DETAILS: Plan:MPB-34 Site: M Pt B Pad Ground Level: 23.70 Sperry Drilling Well: Plan: MPB-34 +N/-S +E/-W Northing Fasting Latittude Longitude Wellbore: MPB-34 0.00 0.00 6023979.35 571983.88 70°28'32.874 N 149°24'43.080 W Plan: MPB-34 wp05 REFERENCE INFORMATION COMPANY DETAILS: Hilcorp Energy Company Calculation Method: Minimum Curvature Co-ordinateVeical (N/E)Reference:Well Plan:MPB-34,True North (TVD)Reference:Plan:As-Built CO 57.40usft(=GL 23.T+RF 33.6) Error System: ISCWSA Measured Depth Reference:Plan:As-Built 422 57.40055(=GL 23.7'+RF 33.6) Scan Method: Closest Approach 3D Calculation Method:Minimum Curvature Error Surface: Elliptical Conic Warning Method: Error Ratio SURVEY PROGRAM Date:2016-06-01700:00:00 Validated:Yes Version: Depth From Depth To Survey/Plan Tool 33.70 650.00 MPB-34 wp05 SRG-SS 650.00 5356.01 MPB-34 wp05 MWD+IFR2+MS+sag CASING DETAILS – TVD TVDSS MD Size Name – MPB-34, 4427.00 4369.60 5356.01 4-1/2 41/2" 2925— 4 1/2" 1 1 Total Depth:5356.01'MD,4427'TVD 1 / - 2700— 1.145_1 _ 010 0 End Dir:5133.03'MD,4207.4'TVD – I MPB-34 Ugnu MB 2475- 3750 – -Start Dir 5°/100':4524.76'MD,3663.5'TVD 2250— 3500 3250 2025- - 3000 1800- - 800— -2750 7 – O 1575— n – a 2500 1350— 2250 S – r° 1125— 2000 900- - 1750 675- - 1500 75- 1500 End Dir:1190.76'MD,1125.02'TVD 450- 1250 225— Start Dir 5°/100':490'MD,489.63'TVD 1000 4, 50 0— >; -Start Dir 3°/100':290'MD,290'TVD -225 I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I i I I I I I l I I l l l l -1125 -900 -675 -450 -225 0 225 450 675 900 1125 1350 1575 1800 West(-)/East(+)(450 usft/in) Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPB-34 Company: Hilcorp Energy Company TVD Reference: Plan:As-Built @ 57.40usft(=GL 23.7'+RF 33.6') Project Milne Point MD Reference: Plan:As-Built @ 57.40usft(=GL 23.7'+RF 33.6') Site: M Pt B Pad North Reference: True Well: Plan:MPB-34 Survey Calculation Method: Minimum Curvature Wellbore: MPB-34 Design: MPB-34 wp05 Project Milne Point,ACT,MILNE POINT 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 04 Using geodetic scale factor Site M Pt B Pad,TR-13-11 Site Position: Northing: 6,021,548.49 usft Latitude: 70°28'8.986 N From: Map Easting: 571,775.55 usft Longitude: 149°24'49.895 W Position Uncertainty: 0.00 usft Slot Radius: 0" Grid Convergence: 0.55 ° Well Plan:MPB-34 !Well Position +N/-S 0.00 usft Northing: 6,023,979.35 usft Latitude: 70°28'32.874 N +E/-W 0.00 usft Easting: 571,983.88 usft Longitude: 149°24'43.080 W I Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 23.70 usft Wellbore MPB-34 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (0) (0) (nT) BGGM2016 6/1/2016 18.32 81.07 57,569 Design MPB-34 wp05 Audit Notes: Version: Phase: PLAN Tie On Depth: 33.70 Vertical Section: Depth From(TVD) +NI-S +E/-W Direction (usft) (usft) (usft) (0) 33.70 0.00 0.00 353.00 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +NI-S +EI-W Rate Rate Rate Tool Face (usft) (°) (0) (usft) usft (usft) (usft) (°I100usft) (°/100usft) (°/100usft) (°) 33.70 0.00 0.00 33.70 -23.70 0.00 0.00 0.00 0.00 0.00 0.00 290.00 0.00 0.00 290.00 232.60 0.00 0.00 0.00 0.00 0.00 0.00 490.00 6.00 15.00 489.63 432.23 10.11 2.71 3.00 3.00 0.00 15.00 782,49 20.00 352.61 774.05 716.65 74.83 0.22 5.00 4.79 -7.65 -31.06 1,190.76 40.41 352.61 1,125.02 1,067.62 277.45 -26.07 5.00 5.00 0.00 -0.01 4,524.76 40.41 352.61 3,663.50 3,606.10 2,420.90 -304.21 0.00 0.00 0.00 0.00 5,133.03 10.00 352.61 4,207.40 4,150.00 2,674.79 -337.16 5.00 -5.00 0.00 180.00 5,356.01 10.00 352.61 4,427.00 4,369.60 2,713.19 -342.14 0.00 0.00 0.00 0.00 10/5/2016 2:54:26PM Page 2 COMPASS 5000.1 Build 81 • 1 Halliburton HALLI BU RTO N Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPB-34 Company: Hilcorp Energy Company ND Reference: Plan:As-Built @ 57.40usft(=GL 23.7'+RF 33.6') Project: Milne Point MD Reference: Plan:As-Built @ 57.40usft(=GL 23.7'+RF 33.6') Site: M Pt B Pad North Reference: True Well: Plan:MPB-34 Survey Calculation Method: Minimum Curvature Wellbore: MPB-34 Design: MPB-34 wp05 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +E/-W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) -23.70 33.70 0.00 0.00 33.70 -23.70 0.00 0.00 6,023,979.35 571,983.88 0.00 0.00 100.00 0.00 0.00 100.00 42.60 0.00 0.00 6,023,979.35 571,983.88 0.00 0.00 200.00 0.00 0.00 200.00 142.60 0.00 0.00 6,023,979.35 571,983.88 0.00 0.00 290.00 0.00 0.00 290.00 232.60 0.00 0.00 6,023,979.35 571,983.88 0.00 0.00 Start Dir 3°/100':290'MD,290'TVD 300.00 0.30 15.00 300.00 242.60 0.03 0.01 6,023,979.38 571,983.89 3.00 0.02 400.00 3.30 15.00 399.94 342.54 3.06 0.82 6,023,982.42 571,984.67 3.00 2.94 490.00 6.00 15.00 489.63 432.23 10.11 2.71 6,023,989.48 571,986.49 3.00 9.70 Start Dir 5°I100':490'MD,489.6311/D 500.00 6.43 12.70 499.58 442.18 11.16 2.97 6,023,990.53 571,986.74 5.00 10.71 600.00 11.08 0.09 598.39 540.99 26.24 4.21 6,024,005.63 571,987.84 5.00 25.53 700.00 15.94 354.98 695.60 638.20 49.54 3.02 6,024,028.92 571,986.43 5.00 48.80 782.49 20.00 352.61 774.05 716.65 74.83 0.22 6,024,054.17 571,983.37 5.00 74.24 800.00 20.88 352.61 790.46 733.06 80.89 -0.57 6,024,060.22 571,982.53 5.00 80.36 900.00 25.88 352.61 882.22 824.82 120.22 -5.67 6,024,099.50 571,977.05 5.00 120.02 1,000.00 30.88 352.61 970.18 912.78 167.34 -11.78 6,024,146.55 571,970.48 5.00 167.53 1,100.00 35.88 352.61 1,053.66 996.26 221.88 -18.86 6,024,201.01 571,962.88 5.00 222.52 I 1,190.76 40.41 352.61 1,125.02 1,067.62 277.45 -26.07 6,024,256.51 571,955.13 5.00 278.56 End Dir :1190.76'MD,1125.02'ND 1,200.00 40.41 352.61 1,132.06 1,074.66 283.39 -26.84 6,024,262.44 571,954.30 0.00 284.55 1,300.00 40.41 352.61 1,208.19 1,150.79 347.68 -35.19 6,024,326.64 571,945.34 0.00 349.38 1,400.00 40.41 352.61 1,284.33 1,226.93 411.97 -43.53 6,024,390.84 571,936.37 0.00 414.21 1,500.00 40.41 352.61 1,360.47 1,303.07 476.26 -51.87 6,024,455.04 571,927.41 0.00 479.04 1,600.00 40.41 352.61 1,436.61 1,379.21 540.55 -60.21 6,024,519.25 571,918.45 0.00 543.86 1,700.00 40.41 352.61 1,512.75 1,455.35 604.84 -68.56 6,024,583.45 571,909.48 0.00 608.69 1,800.00 40.41 352.61 1,588.89 1,531.49 669.14 -76.90 6,024,647.65 571,900.52 0.00 673.52 1,900.00 40.41 352.61 1,665.03 1,607.63 733.43 -85.24 6,024,711.85 571,891.56 0.00 738.35 2,000.00 40.41 352.61 1,741.17 1,683.77 797.72 -93.58 6,024,776.05 571,882.59 0.00 803.17 2,100.00 40.41 352.61 1,817.31 1,759.91 862.01 -101.93 6,024,840.25 571,873.63 0.00 868.00 2,200.00 40.41 352.61 1,893.45 1,836.05 926.30 -110.27 6,024,904.45 571,864.67 0.00 932.83 2,300.00 40.41 352.61 1,969.58 1,912.18 990.59 -118.61 6,024,968.65 571,855.70 0.00 997.66 2,400.00 40.41 352.61 2,045.72 1,988.32 1,054.88 -126.95 6,025,032.85 571,846.74 0.00 1,062.49 2,500.00 40.41 352.61 2,121.86 2,064.46 1,119.17 -135.30 6,025,097.05 571,837.78 0.00 1,127.31 2,600.00 40.41 352.61 2,198.00 2,140.60 1,183.46 -143.64 6,025,161.25 571,828.81 0.00 1,192.14 I 2,700.00 40.41 352.61 2,274.14 2,216.74 1,247.75 -151.98 6,025,225.45 571,819.85 0.00 1,256.97 2,800.00 40,41 352.61 2,350.28 2,292.88 1,312.04 -160.32 6,025,289.65 571,810.89 0.00 1,321.80 2,900.00 40.41 352.61 2,426.42 2,369.02 1,376.33 -168.67 6,025,353.85 571,801.93 0.00 1,386.63 3,000.00 40.41 352.61 2,502.56 2,445.16 1,440.62 -177.01 6,025,418.06 571,792.96 0.00 1,451.45 3,100.00 40.41 352.61 2,578.70 2,521.30 1,504.91 -185.35 6,025,482.26 571,784.00 0.00 1,516.28 3,200.00 40.41 352.61 2,654.83 2,597.43 1,569.20 -193.69 6,025,546.46 571,775.04 0.00 1,581.11 3,300.00 40.41 352.61 2,730.97 2,673.57 1,633.49 -202.04 6,025,610.66 571,766.07 0.00 1,645.94 3,400.00 40.41 352.61 2,807.11 2,749.71 1,697.78 -210.38 6,025,674.86 571,757.11 0.00 1,710.77 3,500.00 40.41 352.61 2,883.25 2,825.85 1,762.07 -218.72 6,025,739.06 571,748.15 0.00 1,775.59 3,600.00 40.41 352.61 2,959.39 2,901.99 1,826.36 -227.06 6,025,803.26 571,739.18 0.00 1,840.42 3,700.00 40.41 352.61 3,035.53 2,978.13 1,890.65 -235.41 6,025,867.46 571,730.22 0.00 1,905.25 10/5/2016 2:54:26PM Page 3 COMPASS 5000.1 Build 81 • • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPB-34 Company: Hilcorp Energy Company TVD Reference: Plan:As-Built @ 57.40usft(=GL 23.7'+RF 33.6') Project: Milne Point MD Reference: Plan:As-Built @ 57.40usft(=GL 23.7'+RF 33.6') Site: M Pt B Pad North Reference: True Well: Plan:MPB-34 d Survey Calculation Method: Minimum Curvature Wellbore: MPB-34 Design: MPB-34 wp05 Planned Survey ' Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NI-S +E/-W Northing Easting US Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 3,054.27 3,800.00 40.41 352.61 3,111.67 3,054.27 1,954.94 -243.75 6,025,931.66 571,721.26 0.00 1,970.08 3,900.00 40.41 352.61 3,187.81 3,130.41 2,019.23 -252.09 6,025,995.86 571,712.29 0.00 2,034.91 4,000.00 40.41 352.61 3,263.95 3,206.55 2,083.53 -260.44 6,026,060.06 571,703.33 0.00 2,099.73 4,100.00 40.41 352.61 3,340.09 3,282.69 2,147.82 -268.78 6,026,124.26 571,694.37 0.00 2,164.56 4,200.00 40.41 352.61 3,416.22 3,358.82 2,212.11 -277.12 6,026,188.46 571,685.40 0.00 2,229.39 4,300.00 40.41 352.61 3,492.36 3,434.96 2,276.40 -285.46 6,026,252.66 571,676.44 0.00 2,294.22 4,400.00 40.41 352.61 3,568.50 3,511.10 2,340.69 -293.81 6,026,316.87 571,667.48 0.00 2,359.05 4,500.00 40.41 352.61 3,644.64 3,587.24 2,404.98 -302.15 6,026,381.07 571,658,51 0.00 2,423.87 4,524.76 40.41 352.61 3,663.49 3,606.09 2,420.90 -304.21 6,026,396.96 571,656.29 0.00 2,439.93 Start Dir 5°/100':4524.76'MD,3663.5'TVD 4,600.00 36.65 352.61 3,722.34 3,664.94 2,467.37 -310.24 6,026,443.37 571,649.81 5.00 2,486.79 4,700.00 31.65 352.61 3,805.07 3,747.67 2,523.02 -317.47 6,026,498.95 571,642.06 5.00 2,542.91 4,800.00 26.65 352.61 3,892.37 3,834.97 2,571.31 -323.73 6,026,547.17 571,635.32 5.00 2,591.60 4,900.00 21.65 352.61 3,983.59 3,926.19 2,611.88 -328.99 6,026,587.68 571,629.67 5.00 2,632.50 5,000.00 16.65 352.61 4,078.03 4,020.63 2,644.40 -333.21 6,026,620.15 571,625.14 5.00 2,665.30 5,100.00 11.65 352.61 4,174.96 4,117.56 2,668.64 -336.36 6,026,644.36 571,621.76 5.00 2,689.74 5,133.03 10.00 352.61 4,207.40 4,150.00 2,674.79 -337.16 6,026,650.50 571,620.90 5.00 2,695.94 End Dir :5133.03'MD,4207.4'TVD 5,200.00 10.00 352.61 4,273.36 4,215.96 2,686.32 -338.65 6,026,662.02 571,619.29 0.00 2,707.57 5,300.00 10.00 352.61 4,371.84 4,314.44 2,703.54 -340.89 6,026,679.21 571,616.89 0.00 2,724.93 5,356.01 10.00 352.61 4,427.00 4,369.60 2,713.19 -342.14 6,026,688.85 571,615.55 0.00 2,734.66 Total Depth:5356.01'MD,4427'ND-41/2" Targets Target Name -hit/miss target Dip Angle Dip Dir. TVD +NI-S +EI-W Northing Easting -Shape (°) (°) (usft) (usft) (usft) (usft) (usft) MPB-34 Ugnu MB 0.00 0.00 4,207.40 2,674.79 -337.16 6,026,650.50 571,620.90 -plan hits target center -Circle(radius 100.00) J Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (") (") 5,356.01 4,427.00 4 1/2" 4-1/2 6-1/8 10/5/2016 2:54:26PM Page 4 COMPASS 5000.1 Build 81 Halliburton HALLIBU RTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPB-34 Company: Hilcorp Energy Company TVD Reference: Plan:As-Built @ 57.40usft(=GL 23.7'+RF 33.6') Project: Milne Point MD Reference: Plan:As-Built @ 57.40usft(=GL 23.7+RF 33.61 Site: M Pt B Pad North Reference: True Well: Plan:MPB-34 Survey Calculation Method: Minimum Curvature Wellbore: MPB-34 Design: MPB-34 wp05 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +EI-W (usft) (usft) (usft) (usft) Comment 290.00 290.00 0.00 0.00 Start Dir 3°/100':290'MD,290'TVD 490.00 489.63 10.11 2.71 Start Dir 5°/100':490'MD,489.63'TVD 1,190.76 1,125.02 277.45 -26.07 End Dir :1190.76'MD,1125.02'TVD 4,524.76 3,663.49 2,420.90 -304.21 Start Dir 5°/100':4524.76'MD,3663.5'TVD 5,133.03 4,207.40 2,674.79 -337.16 End Dir :5133.03'MD,4207.4'TVD 5,356.01 4,427.00 2,713.19 -342.14 Total Depth:5356.01'MD,4427'ND 10/5/2016 2:54:26PM Page 5 COMPASS 5000.1 Build 81 • • Hilcorp Energy Company Milne Point M Pt B Pad Plan: MPB-34 MPB-34 MPB-34 wp05 Sperry Drilling Services Clearance Summary Anticollision Report 05 October,2016 Closest Approach 3D Proximity Scan on Current Survey Data(Highside Reference) Reference Design: M Pt B Pad-Plan:MPB-34-MPB-34-MPB-34 wp05 Well Coordinates: 6,023,979.35 N,571,983.88 E(70°28'32.87"N,149°24'43.08"W) Datum Height: Plan:As-Built @ 57.40usft(=GL 23.7'+RF 33.6') Scan Range: 0.00 to 5,356.01 usft.Measured Depth. Scan Radius is 732.23 usft.Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Geodetic Scale Factor Applied Version: 5000.1 Build:81 Scan Type: GLOBAL FILTER APPLIED:All welipaths within 200'+100/1000 of reference Scan Type: 25.00 HALLIBURTON Sperry Drilling Services • • HALLIBURTON Project: Milne Point REFERENCE INFORMATION WELL DETAILS:Plan:MPB-34 NAD 1927(NADCON CONUS) Alaska Zone 04 Site: M Pt B Pad Coordinate(NIL)Reference:Wet Plan:MPB34,True North Ground Level: 23.70 Well: Plan:MPB-34 Vertical(TVD)Reference:Plan:As-Buia@57.40u4R(=GL 23.7•RF 33.0) +N/-S +F/-W Northing Lasting LatitaWe Longitude Sperry Drilling Measured Depth Reference Plan:As-Built @ 57.40usa(=01 23.7+RF 33.0) 0.00 0.00 6023979.35 571983.88 70.28'32.874 N 149'24'43.080 W Wellbore: MPB-34 Calculation Method:Minimum Curvature r Plan: MPB-34 wp05 SURVEY PROGRAM GLOBAL FILTER APPLIED:All wellpaths within 2004'100/1000 of reference 33.70 To 5356.01 III I IlIt 111 (t Ladder/S.F. Plots Date:2016-06-011-00:00:00 Validated:Yes Version: Depth Front Depth To Survey/Plan Tool CASING DETAILS 33.70 850.00 MPB-34 wp05 SRG-SS 650.00 5356.01 MPB-34 wp05 MWD+IFR2+MS+sa) TVD TVDSS MD Size Name 4427.00 4369.60 5356.01 4-1/2 4 1/2" 150.00 ▪ - M'/+21 I' II '�8-19 / 0120.00 o //f / a90.00 --M III I R1 _ i, I..°- N 60.00_ /%/ (I�'1 /I PB-21 C ' 1 1 N - / U �.�.r a.n" 2 30.00— - i...tllllYM' 19 -___- _ 4) - c I U - II 0.00 11111111I 1 1 I I I 1 1 1 1 1 1 1 1 1 i 1 1 1 1 l 1 1 1 1 l 1 1 1 1 1 1 1 1 111111111 1 1 1 1 11111111111111 1111 1 1 1 1 Fill1 0 350 700 1050 1400 1750 2100 2450 2800 3150 3500 3850 4200 4550 4900 5250 5600 5950 6300 Measured Depth(700 usft/in) 6.00_ I I U 4.50 - `o - U - ILN - C 0 :_.3.00_ _ _ l0 a - Collision Risk Procedures Req. 1 - C- ollision Avoidance Req. 1.50 ' _- No-Go Zone-Stop Drilling 0.00 1111 1111 1111 1111 1111 1111 1111 1111 11 , 1 ' 1111 11111111111111 1111 1111 1111 1111 1111 0 350 700 1050 1400 1750 2100 2450 2800 3150 3500 3850 4200 4550 4900 5250 5600 5950 630C Measured Depth • • Hilcorp Energy Company HALLIBURTON Milne Point Anticollision Report for Plan: MPB-34-MPB-34 wp05 Closest Approach 3D Proximity Scan on Current Survey Data(Hlghside Reference) Reference Design:M Pt B Pad-Plan:MPB-34-MPB-34-MPB-34 wp05 Scan Range: 0.00 to 5,356.01 usft Measured Depth. Scan Radius is 732.23 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 M Pt B Pad MPB-12-MPB-12-MPB-12 275.00 92.00 275.00 88.67 276.60 27.587 Centre Distance Pass- MPB-12-MPB-12-MPB-12 325.00 92.30 325.00 88.36 326.60 23.373 Ellipse Separation Pass- MPB-12-MPB-12-MPB-12 600.00 118.02 600.00 110.77 600.01 16.275 Clearance Factor Pass- MPB-14-MPB-14-MPB-14 33.70 209.49 33.70 209.05 35.50 472.772 Centre Distance Pass- MPB-14-MPB-14-MPB-14 300.00 209.68 300.00 206.22 301.32 60.741 Ellipse Separation Pass- MPB-14-MPB-14-MPB-14 700.00 258.51 700.00 250.61 696.82 32.719 Clearance Factor Pass- MPB-18-MPB-18-MPB-18 240.66 213.18 240.66 210.68 242.26 85.315 Centre Distance Pass- MPB-18-MPB-18-MPB-18 300.00 213.53 300.00 210.42 299.11 68.634 Ellipse Separation Pass- MPB-18-MPB-18-MPB-18 850.00 253.05 850.00 244.88 830.64 30.957 Clearance Factor Pass- MPB-19-MPB-19-MPB-19 449.55 33.62 449.55 28.41 450.12 6.462 Centre Distance Pass- MPB-19-MPB-19-MPB-19 575.00 34.15 575.00 27.38 574.52 5.048 Ellipse Separation Pass- MPB-19-MPB-19-MPB-19 625.00 35.39 625.00 28.06 623.64 4.828 Clearance Factor Pass- MPB-20-MPB-20-MPB-20 864.41 237.42 864.41 227.92 852.44 24.983 Centre Distance Pass- MPB-20-MPB-20-MPB-20 875.00 237.46 875.00 227.88 862.05 24.780 Ellipse Separation Pass- MPB-20-MPB-20-MPB-20 1,025.00 249.53 1,025.00 238.49 1,006.90 22.608 Clearance Factor Pass- MPB-21-MPB-21-MPB-21 923.45 44.57 923.45 35.72 904.66 5.038 Centre Distance Pass- MPB-21-MPB-21-MPB-21 925.00 44.58 925.00 35.72 905.96 5.032 Clearance Factor Pass- MPB-21-MPB-21PB1-MPB-21PB1 923.45 44.57 923,45 35.72 904.66 5.038 Centre Distance Pass- MPB-21-MPB-21PB1-MPB-21PB1 925.00 44.58 925.00 35.72 905.96 5.032 Clearance Factor Pass- MPB-24-MPB-24-MPB-24 275.77 29.94 275.77 28.23 264.37 17.518 Centre Distance Pass- MPB-24-MPB-24-MPB-24 300.00 29.96 300,00 28.09 288.58 16.020 Ellipse Separation Pass- MPB-24-MPB-24-MPB-24 475.00 37.91 475.00 34.87 463.38 12.466 Clearance Factor Pass- 05 October,2016- 14:08 Page 2 of 5 COMPASS • • Hilcorp Energy Company HALLIBURTON Milne Point Anticollision Report for Plan: MPB-34-MPB-34 wp05 Survey tool aronram From To Survey/Plan Survey Tool (usft) (usft) 33.70 650.00 MPB-34wp05 SRG-SS 650.00 5,356.01 MPB-34 wp05 MWD+IFR2+MS+sag 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. 05 October,2016- 14:08 Page 3 of 5 COMPASS �� �� Bettis, Patricia K (DOA) From: Luke Keller <|he||er@hi|corp.com> Sent: Thursday, November 10, 2016 2:15 PM To: Bettis, Patricia K (DOA) Cc: Cody Dinger;Wyatt Rivard Subject: FW: MPU B-34 Permit to Drill Application (PTD 216'I39) Attachments: UlCPermitAKlIOOSBK4(]Dl.l9.l6.pdf Patricia, Please see attached Class 1 permit for Milne Point. Let me know if you need anything else in your review of MPU B-034. From: Wyatt Rivard Sent: Thursday, November 10, 2016 2:14 PM To: Luke Keller; Cody Dinger Subject: RE: MPU B-34 Permit to Drill Application (PTD 216-139) Luke, We do have a Class 1 Permit at Milne. The most recent version is attached. The permit provides for up to four class 1 wells at Milne, we currently only have MPB-50 and MPB-24 completed. The permit references MPB-51 instead of MPB- 34butthenameandsurfacz |ocationwi|| beupdatxdoncethewe|| iscomp|eted. Thank You, Wyatt Rivard Wel! Integrity Engineer 0: (907) 777-8517 [ [: (SO9)67O'8O0l wrivard@hilcorp.com 3DUUCnueryoix/Drive,Suite l4O0 | Anchorage,AK995O3 � �^ ���m����&NIIHilcorp From: Luke Keller Sent:Thursday, November 10, 2016 2:06 PM To: Cody Dinger<cdinger@hilcorp.com>; Wyatt Rivard <wrivard@hilcorp.com> Subject: FW: MPU B-34 Permit to Drill Application (PTD 216-139) Wyatt, Do we have an EPA Underground Injection Control Permit for Mime Point? From: Bettis, Patricia K (DOA) [moiho:pathcia.bettis@a|aska.gov] Sent: Thursday, November 10, 2016 1:51 PM To: Luke Keller Subject: MPU B-34 Permit to Drill Application (PTD 216-1]9) Good afternoon Luke, Is MPU B-34 going to be a class I or class II disposal well? If the proposed well is a class II disposal well, Hilcorp will need to submit an application for underground disposal of oil waste, 20 AAC 25.252. If it is a class I disposal well, please provide a copy of the EPA Underground Injection Control Permit. 1 Does Hilcorp plan to pre-produce the well; and if so, for what duration. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907)793-1238 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 Patricia Bettis at(907)793-1238 or patricia.bettis@alaska.gov. 2 • oED ST,4). UNITED STATES ENVIRONMENTAL PROTECTION AGENCY `1; irk REGION 10 1200 Sixth Avenue, Suite 900 Seattle, Washington 98101-3140 JLN 1 o 2016 OFFICE OF COMPLIANCE AND ENFORCEMENT Reply To: OCE-101 CERTIFIED MAIL - RETURN RECEIPT REQUESTED Mr. John Barnes Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 100 Anchorage, Alaska 99503 Re: Issuance of Modified Underground Injection Control (UIC) Permit No. AKI1005-B Milne Point Unit. North Slope, Alaska Dear Mr. Barnes: The U. S. Environmental Protection Agency, Region 10, (EPA) is issuing a modified Underground Injection Control permit for Flileorp Alaska, LLC lilcorp), Milne Point Unit (1\,IPU), North Slope. Alaska. The enclosed doctunent authorizes the facility to inject non-hazardous industrial NN iiSte up to four(4) Class I injection wells at the MPU into the naturally saline intervals of the Schrader Bluff (\Vest Sak) and Ugnu (Prince Creek) Formations. No comments were received during the public comment period of December 14, 2015 through January 14, 2016. A public hearing was offered January 14, 2015, in the Federal Building in Anchorage, Alaska; however, due to the absence °fatty specific written requests for the hearing, the hearing was cancelled. This letter constitutes service of notice under 40 C.F.R. 124.19(a). The modified permit will become effective on the date signed as indicated in the permit unless the Environmental Appeals Board receives a timely appeal meeting the requirements (-4'40 C.F.R. 124.19. Information about the administrative appeal process may be obtained on-line at epa.gov/eab or by contacting the Clerk of the Environmental Appeals Board at (202) 233-0122. S. cerely. a.44.,Ped Edward J. Kowalski Director Enclosure: Modified Permit AK11005-B cc w/enc: Marc Bentley, ADEC Division of Water/Wastewater Discharge Permits Chris Wallace, AOGCC • Page 1 or23 ISSUANCE DATE AND SIGNATURE PAGE U.S. ENVIRONMENTAL PROTECTION AGENCY UNDERGROUND INJECTION CONTROL PERMIT: CLASS I Permit Number AK-11005-B In compliance with provisions of the Safe Drinking Water Act(SDWA), as amended, (42 U.S.C. 300f-300j-9), and attendant regulations incorporated by the U.S. Environmental Protection Agency (EPA) under Title 40 of the Code of Federal Regulations, Hilcorp Alaska EEC (Hileorp) (Permittee) is authorized to inject non-hazardous industrial waste utilizing up to four(4) Class I in jection wells at the Milne Point Unit(MPU) located on the Alaskan North Slope (NS). Injection is authorized into the Schrader Bluff(West Sak) and Ugnu (Prince Creek) Formations, in accordance with Title 40 C.F.R. § 144.33 and the conditions set forth herein. The Milne Point oilfield located in the MPU near the Beaufort Sea about 250 miles north of the Arctic Circle and lies west of Prudhoe Bay, on the North Slope of Alaska approximately 25 miles west of Deadhorse. Alaska. The proposed disposal well(s) are in an area where there are no underground sources of drinking water(USDWs) and an aquifer exemption delineated by a cylinder along the well trajectory of the Class I injection well(s) from (below permafrost) 2000 feet true vertical depth (TVD) to 4270 feet TVD. The aquifer exemption was issued by EPA on September 29, 2004 for aquifers between approximately 2001) feet (base of the permafrost) and 4,270 feet true vertical depth subsea (TVDss) and was clarified to include the area delineated by a cylinder of mile radius along the \yell trajectories whose latitudes and longitudes (per NAD83 respectively at the well surface location are latitude 70.472809 and longitude -149.413148 for welt MPB-50, latitude 70.4728 and longitude -149.4131 for well MPB-51, latitude 70.4728 and longitude - 149.4131 for well MPB-52 and latitude 70.475454 and longitude -149.415140 for well MPB-24. (Exact well locations are subject to change or correction.) Injection of hazardous waste as defined under the Resource Conservation and Recovery Act (RCRA), as amended, (42 USC 6901) or radioactive wastes (other than naturally occurring radioactive material — NORM from pipe scale) are not authorized under this permit. All references to Title 40 of the Code of Federal Regulations are to regulations that are in effect on the date that this permit is issued. Figures and appendices are referenced to BP Exploration (Alaska) Inc. (BPXA) BPXA's Renewal Application for Milne Point Unit UIC Permit AK-11005-A dated April 30, 2014. This permit shall become effective on November 3. 2014, in accordance with 40 C.F.R. § 124.15, This permit and the authorization to inject shall expire at midnight. November 2. 2024, unless terminated. Modification signed this 15th day of Janua , 201 No" iff.---"D Edward J. Kowalski. Director Office of Compliance and Enforcement U.S. Environmental Protection Agency Region 10 (OCE-101) 1200 Sixth Avenue Suite 900 Seattle, WA 98101 • S Page 2 of 23 TABLE OF CONTENTS ISSUANCE DATE AND SIGNATURE PAGE 1 PART I GENERAL PERMIT CONDITIONS 4 EFFECT OF PERMIT 4 PERMIT ACTIONS 4 Modification, Reissuance, or Termination 4 Transfer of Permits 5 SEVERABILITY 5 CONFIDENTIALITY 5 GENERAL DUTIES AND REQUIREMENTS 5 Duty to Comply 5 Penalties for Violations of Permit Conditions 6 Duty to Reapply 6 Need to Halt or Reduce Activity Not a Defense 6 Duty to Mitigate 6 Proper Operation and Maintenance 6 Duty to Provide Information 6 Inspection and Entry 7 Records 7 Reporting Requirements 9 Anticipated Noncompliance 9 Twenty-Four Hour Reporting 9 Other Noncompliance 10 Reporting Corrections 10 Signatory Requirements 10 PLUGGING AND ABANDONMENT 11 Notice of Plugging and Abandonment 11 Plugging and Abandonment Report 11 Cessation Limitation 11 Cost Estimate for Plugging and Abandonment 12 FINANCIAL RESPONSIBILITY 12 ID S Page 3 of 23 PART II WELL SPECIFIC CONDITIONS 13 CONSTRUCTION 13 Casing and Cementing 13 Tubing, Packer and Completion Details 13 New Wells in the Area of Review 14 1 CORRECTIVE ACTION 14 WELL OPERATION 14 Prior to Commencing Injection 14 During Injection 15 Mechanical Integrity 15 Injection Zone 18 Waivers to UIC Program Requirements 19 Injection Rate and Pressure 19 Annulus Pressure 20 Injection Fluid Limitation 20 MONITORING 21 Monitoring Requirements 21 Continuous Monitoring Devices 21 Monitoring Direct Waste Injection 21 Alarms and Operational Modifications 21 REPORTING REQUIREMENTS 22 Quarterly Reports 22 Report Certification 22 REPORTING FORMS 23 S Page 4 of 23 PART I GENERAL PERMIT CONDITIONS A. EFFECT OF PERMIT The Permittee is allowed to engage in underground injection in accordance with the conditions of this permit. The Permittee shall not construct, operate, maintain,convert, plug, abandon,or conduct any other activity in a manner that allows the movement of any contaminant into USDWs, except as authorized by 40 CFR Part 146. The underground injection activity, otherwise authorized by this permit shall not allow the movement of fluid containing any contaminant into underground sources of drinking water, if the presence of that contaminant may cause a violation of any primary drinking water regulation under 40 C.F.R. Part 142 or may otherwise adversely affect the health of persons or the environment. Compliance with this permit during its term constitutes compliance for purposes of enforcement with Part C of the Safe Drinking Water Act(SDWA). Such compliance does not constitute a defense to any action brought under Section 1431 of the SDWA,or any other law governing protection of public health or the environment from imminent and substantial endangerment to human health or the environment. This permit may be modified, revoked and reissued, or terminated during its tenn for cause. Issuance)of this permit does not convey property rights or mineral rights of any sort or any exclusive privilege; nor does it authorize any injury to persons or property, any invasion of other private rights, or any infringement of State or local law or regulations. This permit does not authorize any above ground generating, handling, storage, or treatment facilities. This permit is based on the permit application submitted by BP Exploration(Alaska) Inc. 2014, and supplemental material related to the aquifer exemption ruling BPXA on April 30, (BPXA) PPP granted Eily EPA dated September 29, 2004. B. PERMIli ACTIONS 1. Modification, Reissuance. or Termination This permit may be modified, revoked and reissued, or terminated for cause as specified in 40 C.F.R. §§ 144.39 and 144.40. In addition, the permit can undergo minor modifications for cause as specified in 40 C.F.R. § 144.41. The filing of a request for a permit modification, revocation and reissuance,or termination, or the notification of planned changes, or anticipated noncompliance on the part of the Permittee does not stay the applicability or enforceability of any permit condition. Page 5 of 23 2. Transfer of Permits This permit is not transferable to any person except after notice to the Director on APPLICATION TO TRANSFER PERMIT(EPA Form 7520-7)and in accordance with 40 C.F.R. § 144.38. The Director may require modification or revocation and reissuance of the permit to change the name of the Permittee and incorporate such other requirements as may be necessary under the SDWA. C. SEVERABILITY The pro'+isions of this permit are severable, and if any provision of this permit or the application of any provision of this permit to any circumstance is held invalid, the application of such provision to other circumstances, and the remainder of this permit, shall not be affected thereby. D. CONFIDENTIALITY In accordance with 40 C.F.R. Part 2, any information submitted to EPA pursuant to this permit may be claimed as confidential by the submitter. Any such claim must be asserted at the time of submission in the manner prescribed in 40 C.F.R. § 2.203 and on the application form or instructions,or, in the case of other submissions, by stamping the words "confidential" or"confidential business information" on each page containing such information. If no claim is made at the time of submission, EPA may make the information available to the public without further notice. If a claim is asserted, the information will be treated in accordance with the procedures in 40 C.F.R. Part 2 (Public Information). Claims of confidentiality for the following information will be denied: 1. The name and address of the Permittee. 2. Inf rmation that deals with the existence, absence, or level of contaminants in drinking water. E. GENERAL DUTIES AND REQUIREMENTS 1. Duty to Comply The Permittee shall comply with all conditions of this permit. Any permit noncompliance constitutes a violation of the SDWA and is grounds for enforcement action, permit termination, revocation and reissuance, modification, or for denial of a permit renewal application; except that the Permittee need not comply with the provisions of this permit to the extent and for the duration such noncompliance is authorized in an emergency permit under 40 C.F.R. § 144.34. S Page 6 of 23 2. Penalties for Violations of Permit Conditions Any person who violates a permit condition is subject to a civil penalty value calculated on a per day basis of such violation. Any person who willfully or negligently violates permit conditions is subject to a fine calculated on a per day basis of the violation and/or being imprisoned. 3. Duty to Reapply If the Permittee wishes to continue an activity regulated by this permit after the expiration date of this permit, the Permittee must apply for and obtain a new permit. To be timely, a complete application for a new permit must be received at least 180 days before this permit expires. 4. Need to Halt or Reduce Activity Not a Defense It shall not be a defense for a Permittee in an enforcement action that it would have been necessary to halt or reduce the permitted activity in order to maintain compliance with the conditions of this permit. 5. Duty to Mitigate The Permittee shall take all reasonable steps to minimize or correct any adverse impact on the environment resulting from noncompliance with this permit. 6. Proper Operation and Maintenance The Pennittee shall, at all times, properly operate and maintain all facilities and systems of treatment and control (and related appurtenances) which are installed or used by the Permittee to achieve compliance with the conditions of this permit. Proper operation andl,maintenance includes effective performance, adequate funding, adequate operator staffing and training, and adequate laboratory and process controls, including appropriate quality assurance procedures. This provision requires the operation of back-up or auxiliary facilities or similar systems only when necessary to achieve compliance with the conditions of this permit. De-characterized waste may be appropriately disposed in a Class I non-hazardous well [refer to 40 C.F.R. § 148.1(d)]. 7. Duty to Provide Information The Pennittee shall provide to the Director, within a reasonable time, any information that the Director may request to determine whether cause exists for modifying, revoking and reissuing, terminating this permit, or to determine compliance with this pennit. The Permittee shall also provide to the Director, upon request, copies of records required to • • Page 7 of 23 be kept by this permit. 8. Inspection and Entry The Permittee shall allow the Director, or an authorized EPA representative, upon the presentation of credentials and other documents as may be required by law to: a. Enter upon the Permittee's premises where a regulated facility or activity is located or conducted, or where records are kept under the conditions of this permit; b. Have access to and copy, at reasonable times, any records that are kept under the conditions of this permit; c. Inspect at reasonable times any facilities, equipment(including monitoring and control equipment), practices, or operations regulated or required under this permit; and d. Sample or monitor at reasonable times, for the purposes of assuring permit compliance or as otherwise authorized by SDWA, any contaminants or parameters at any location. 9. Records a. The Permittee shall retain records and all monitoring information, including all j calibration and maintenance records and all original strip chart recordings for continuous monitoring instrumentation, copies of all reports required by this permit and records of all data used to complete this permit application for a period of at least three years from the date of the sample, measurement, report or application. These periods may be extended by request of the Director at any time. b. The Permittee shall retain records concerning the nature and composition of all injected fluids until three years after the completion of plugging and abandonment. At the conclusion of the retention period, if the Director so requests, the Permittee shall deliver the records to the Director. The Permittee shall continue to retain the records after the three-year retention period unless he delivers the records to the Director or obtains written approval from the Director to discard the records. This permit does not require retention of hard copies or original records. The record keeping requirements of the permit are met by retaining the records in electronic or original hard copy format. The original records are not required to be retained when electronic versions are retained. c. Records of monitoring information shall include: (1) The date, exact place, and time of sampling or measurements; 411 S Page 8 of 23 (2) The name(s) of the individual(s)who performed the sampling or measurements; (3) The date(s) analyses were performed; ' (4) The name(s)of the individual(s) who performed the analyses; (5) The analytical techniques or methods used; and (6) The results of such analyses. d. Monitoring of the nature of injected fluids shall comply with applicable analytical methods cited and described in Table I of 40 C.F.R. § 136.3, in appendix III of 40 C.F.R. Part 261, or in certain circumstances by other methods that have been approved by the Administrator. e. All environmental measurements required by the permit, including, but not limited to measurements of pressure, temperature, mechanical integrity, and chemical analyses shall be done in accordance with EPA's Quality Assurance Program Plan. f. As part of the COMPLETION REPORT, the Permittee must submit a PLAN that describes the procedures to be carried out to obtain detailed chemical and physical analysis of representative samples of the waste including the quality assurance procedures used including the following: (1) The parameters for which the waste will be analyzed and the rationale for the selection of these parameters; (2) The test methods that will be used to test for these parameters; and (3) The sampling method that will be used to obtain a representative sample of the waste to be analyzed. This permit covers four wells, including two active Class I wells(MPB-50 & MPB-24)that have been in operation since 2005 and 2015, respectively plus two additional wells(MPB-51 and MPB-52). An updated Waste Analysis Plan(WAP) was submitted as part of the September 18, 2015 MPB-24 Completion Report. The WAP from the completion report may be incorporated by reference to satisfy the WAP plan submittal requirements. g. The Permittee shall require a written manifest for each batch load of waste received for waste streams that are not hard piped and continuous. The manifest shall contain a description of the nature and composition of all injected fluids, date of • S Page 9 of 23 receipt, source of material received for disposal, name and address of the waste generator, a description of the monitoring performed and the results,a statement stating if the waste is exempt from regulation as hazardous waste as defined by 40 C.F.R. § 261.4,and any information on extraordinary occurrences. For waste streams that are hard-piped continuously from the source to the wellhead, the Permittee shall also provide for continuous, recorded measurement of the discharge rate and shall provide such sampling and testing as may be necessary to provide a description of the nature and composition of all injected fluids, and to support any statements that the waste is exempt from regulation as hazardous waste as defined by 40 CFR § 261.4. h. Dates of most recent calibration or maintenance of gauges and meters used for monitoring required by this permit shall be noted on the gauge or meter. Earlier records shall be available through a computerized maintenance history database. 10. Reporting Requirements The Permittee shall give notice to the Director, as soon as possible, of any planned physical alterations or additions to the pennitted facility or changes in type of injected waste. 11. Anticipated Noncompliance The Pennittee shall give advance notice to the Director of any significant planned changes in the permitted facility or activity that may result in noncompliance with permit requirements. 12. Twenty-Four Hour Reporting a. ' The Permittee shall report to the Director or an authorized EPA representative any noncompliance that may endanger health or the environment. Any information shall be provided orally within 24 hours from the time the Permittee becomes aware of the circumstances. If EPA or the Permittee discovers that fluids have • moved above the upper confining zone along a wellbore within the AOR, then injection shall cease until the fluid movement problem can be diagnosed and corrected. The following shall be included as information that must be reported orally within 24 hours: (1) Any monitoring or other information that indicates that any contaminant may cause an endangerment to an underground source of drinking water. (2) Any noncompliance with a permit condition or malfunction of the injection system. � I • O Page 10 of 23 b. A written submission shall also be provided within five(5)days of the time the Permittee becomes aware of the circumstances. The written submission shall contain a description of the noncompliance and its cause,the period of noncompliance, including exact date and times, and, if the noncompliance has not been corrected, the anticipated time it is expected to continue, and steps taken or planned to reduce, eliminate, and prevent recurrence of the noncompliance. 13. Other Noncompliance The Permittee shall report all other instances of noncompliance not otherwise reported at the time monitoring reports are submitted. The reports shall contain the information listed in Permit Condition Part I E.12.b. 14. Reporting Corrections When the Permittee becomes aware that he/she failed to submit any relevant facts in the permit application or submitted incorrect information in a permit application or in any report to the Director, the Permittee shall promptly submit such facts or information. 15. Signatory Requirements a. All permit applications, reports required by this permit and other information requested by the Director shall be signed by a principal executive officer of at least the level of vice-president, or by a duly authorized representative of that person. A person is a duly authorized representative only if: (1) The authorization is made in writing by a principal executive of at least the level of vice-president. (2) The authorization specifies either an individual or a position having responsibility for the overall operation of the regulated facility or activity. such as the position of plant manager, operator of a well ora well field, superintendent, or position of equivalent responsibility. A duly authorized representative may thus be either a named individual or any individual occupying a named position. (3) The written authorization is submitted to the Director. b. If an authorization under paragraph 15.a. of this section is no longer accurate because a different individual or position has responsibility for the overall operation of the facility, a new authorization satisfying the requirements of paragraph 15.a. of this section must be submitted to the Director prior to or together with any reports, information, or applications to be signed by an authorized « i Page 11 of 23 representative. c. Any person signing a document under paragraph 15.a. of this section shall make the • following certification: "I certify under the penalty of law that I have personally examined and am familiar with the information submitted in this document and all attachments and that, based on my inquiry of those individuals immediately responsible for obtaining the information, I believe that the information is true, accurate,and complete. I am aware that there are significant penalties for submitting false information, including the possibility of fine and imprisonment." F. PLUGGING AND ABANDONMENT 1. Notice of Plugging and Abandonment The Permittee shall notify the Director no later than 45 days before conversion or abandotunent of the well. 2. Plugging and Abandonment Report The Permittee shall plug and abandon the welt as provided in the Final Well Abandonment(Closure)portion(Section 6.5) of the April 30, 2014. Permit Renewal Application for Milne Point UIC Permit AK II005-A(Permit Renewal Application) submitted by the Permittee, which is hereby incorporated as a part of this permit. Within 60 days after plugging any well the Permittee shall submit a report to the Ditlector in accordance with 40 C.F.R. § 144.51(p). EPA reserves the right to change the manner in which the well will be plugged if the well is not proven to be consistent with EPA requirements for construction and mechanical integrity. The Director may ask the Pepiittee to update the estimated plugging cost periodically. 3. Cessation Limitation After a cessation of operations of two years, the Permittee shall plug and abandon the well in accordance with the plan unless he/she: a. Provides notice to the Director; • • b. Demonstrates that the well will be used in the future; or c. Describes actions or procedures, satisfactory to the Director that the Permittee will take to ensure that the well will not endanger underground sources of drinking water during the period of temporary abandonment. These actions and procedures shall include compliance with the technical requirements applicable to active injection wells unless waived by the Director. • Page 12 of 23 4. Cost Estimate for Plugging and Abandonment a. The Permittee estimates the 2014 cost of plugging and abandonment of the permitted Class I well(s) to be approximately$ 300,000/well. Please refer to Section 6.5 and Exhibits 6-3 and 6-4 of the April 30, 2014 Permit Renewal Application. b. The Permittee must submit financial assurance and a revised estimate prior to April of each year. The estimate shall be made in accord with 40 C.F.R. § 144.62. c. The Permittee must keep at the facility or at the Permittee central files in Anchorage during the operating life of the facility the latest plugging and abandonment cost estimate. d. When the cost estimate changes, the documentation submitted under 40 C.F.R. § 144.63(f)shall be amended as well to ensure that appropriate financial assurance for plugging and abandonment is maintained continuously. e. The Permittee must notify the Director by registered mail of the commencement of a voluntary or involuntary proceeding under Title 11 (Bankruptcy), U.S. Code, naming the owner or operator as debtor,within 10 business days after the commencement of the proceeding. G. FINANCIAL RESPONSIBILITY The Permittee shall maintain continuous compliance with the requirement to maintain financial responsibility and resources to close, plug, and abandon the underground injection well. If the financial test and corporate guarantee provided under 40 C.F.R. § 144.63(t) should change, the Permittee shall immediately notify the Director. The Permittee shall not substitute an alternative demonstration of financial responsibility for that which the Director has approved, unless it has previously submitted evidence of that alternative demonstration to the Director and the Director notifies him that the alternative demonstration of financial responsibility is acceptable. Consistent with 40 C.F.R.§144.63 and regarding incapacity of owners or operators, guarantors, or financial institutions, the Permittee must notify the Director by registered mail of the commencement of a voluntary or involuntary proceeding under Title 11 (Bankruptcy), U.S. Code, naniiiig the owner or operator as debtor, within 10 business days after the commencement of the proceeding. Furthermore, an owner or operator must notify the Regional Administrator by certified mail of the commencement of a voluntary or involuntary proceeding under title 11 (Bankruptcy), U.S. Code, naming the owner or operator as debtor, within 10 business days after the commencement of the proceeding. A guarantor of a corporate guarantee as specified in §144.63(f) must make such a notification if he is named as debtor, as required under the terms of the guarantee(§144.70(0). • Page 13 of 23 PART II WELL SPECIFIC CONDITIONS A. CONSTRUCTION 1. Casing and Cementing of Existing Sidetrack and/or Replacement Wells The Permittee shall case and cement the well(s) to prevent the movement of fluids into or between underground sources of drinking water other than the authorized injection interval (see II.C.4, below). Casing and cement shall be installed in accordance with a casing and cement program approved by the Director and in accordance with EPA Class I well construction practices(40 C.F.R. § 146.12) and the State of Alaska/AOGCC Regulations(20 AAC § 25.412 and 20 AAC § 25.252). If primary cement returns to surface are not observed for the (20 inch or other) surface casing cementing procedure, the Director or authorized EPA representative is to be notified as to the nature of the augmented testing proposed to ensure the integrity of the cement bond and adequacy of any Top Job procedure. The Cement Bond/Ultrasonic Imaging(USIT or other) logs and pressure tests (leak off test and/or formation integrity test)will be run for both the(20 inch or other) surface and(9 5/8 inch or other) injection casings to confirm zonal isolation and verify casing integrity. The Permittee shall prqvide not less than fourteen(14)days advance notice to the Director or authorized EPA representative for all cementing operations. Should a change(s) be required to the design casing and cementing program(due to unanticipated conditions), the Director or authorized EPA representative shall be notified as to the nature of the change(s),so that approval is obtained from the Director or authorized EPA representative enabling the well to be drilled and completed in a safe and successful manner. The casing, cementing and well construction data will be in compliance with the procedures outlined in Well Construction portion(Section 6),and the well schematics (EYhibits 6-1, 6-2 and 6-3)of the April 30, 2014 Permit Renewal Application. 2. Tubing, Packer and Completion Details of Existing Sidetrack and/or Replacement Wells The well shall inject fluids through tubing with a packer. Tubing and packer shall be installed in accordance with the procedures in the permit application. The current tubing anc packer locations for well MPB-50 and MPB-24 are approved. In the event that a packer needs to be set or re-set at a revised depth at a later date, and the Permittee will perform a mechanical integrity test prior to resuming injection,submit the necessary data and obtain authorization from EPA prior to resuming injection. The packer will be set'no more than 100 feet MD from the top of the injection zone. I Page 14 of 23 3. New Wells in the Area of Review EPA has set a quarter mile radius as the Area of Review(AOR) for this Class I UIC permit application. New Class I permitted UIC wells shall be installed in accordance with a casing and cement program approved by the Director and in accordance with EPA Class I well construction practices(40 C.F.R. § 146.12) and will also follow the State of Alaska/AOGCC Regulations(20 AAC 25.412 and 20 AAC 25.252). New wells within the AOR shall be constructed in accordance with the Alaska Oil and Gas Conservation Commission Regulations Title 20 Chapter 25. If in the future, any deielopment or service wells are drilled that penetrate the injection intervals within the area of review, these wells shall have casing cemented to the formation throughout the entire section from 200 feet TVD below the proposed injection zone to 200 feet TVD above the injection zone as identified in the April 30, 2014 Permit Renewal Application. i p B. CORRECTIVE ACTION The apOcant has identified no wells in the Area of Review(AOR) which require corrective action in order to prevent fluids from moving above the confining zone. If the applicant later discover that a well or wells within the AOR require(s) corrective action to prevent fluid movement, then the applicant shall inform the EPA upon such discovery and provide a corrective action plan for EPA review and approval. C. WELL QPERATION 1. The existing well (MPB-50) has fulfilled requirements of Part II C.1. Prior to Commencing Injection of New, Existing Sidetrack and/or Replacement Wells Injection operations pursuant to this permit may not commence until: a. Construction is complete and the Permittee has submitted two copies of COMPLETION FORM FOR INJECTION WELLS (EPA Form 7520-9), see APPENDIX A; and (1) The Director or authorized EPA representative has inspected or otherwise reviewed the new, existing,sidetrack or replacement injection well(s) and finds it is in compliance with the conditions of the permit; or (2) The Pennittee has not received notice from the Director or authorized EPA representative of intent to inspect or otherwise review the new, sidetrack or replacement injection well(s)within thirteen(13)days of receiving the COMPLETION REPORT in which case prior inspection or review is waived and the Permittee may commence injection. • • Page 15 of 23 b. The Permittee demonstrates that the well has mechanical integrity as described in Part II.C.3. Mechanical Integrity below and the Permittee has received notice from the Director or authorized EPA representative that such a demonstration is satisfactory. The Permittee shall notify EPA at least two weeks prior to conducting this initial test so that an authorized EPA representative may be present.Note: Since well MPB-50 has been on injection since 2005 and has successfully demonstrated mechanical integrity on an annual basis, the requirements of C.1.a and C.1.b. from above have been met. MPB-24 similarly demonstrated mechanical integrity and met the requirements of C.1.a and C.1.b above following the well's completion in 2015. However, the requirements under Part II.C.3.—Mechanical Integrity remain in force for wells MPB-50 and MPB-24; and c. The Permittee has conducted a step-rate injection test(SRT) and submitted a preliminary report to EPA that summarizes the results. A SRT was conducted on wells MPB-50 and MPB-24 and the results were submitted to the EPA. Therefore, the Permittee is not required to conduct another SRT prior to resumption of Class I injection activities upon permit modification. 2. During Injection �. During injection, the well injection pressure, tubing-casing(inner) annulus pressure, injection rate, will be monitored on a continuous basis. Out-of-limit alarms and shut-off systems will be installed and the injection facility plant shall be monitored by trained and qualified operators during injection. Visual and automatic monitoring of the tubing- casi ig(inner annulus) and tubing pressures will occur routinely with pre-set,out-of- limit alarms to inform supervisory personnel. The;wellhead, controls, and monitoring instrumentation will be enclosed in an insulated structure. 3. Mechanical Integrity a. Standards The injection well(s) must have and maintain mechanical integrity pursuant to 40 C.F.R. § 146.8. I i Page l6 of 23 b. Prohibition without Demonstration of Mechanical Integrity Injection operations are prohibited after the effective date of this permit unless the Permittee has conducted the following tests and submitted the results to the Director: 1) In order to demonstrate there is no significant leak in the casing, tubing or packer, the tubing/casing annulus must be pressure tested to at least 3,500 pounds per square inch gauge(psig) for not less than thirty minutes. Pressure shall show a stabilizing tendency. That is, the pressure may not decline more than 10 percent during the 30-minute test period and shall experience less than one-third of its total loss in the second(last) half of the 30-minute test period. If the total loss exceeds 10 percent or if the loss during the second 15 minute period is equal to or greater than one-half the loss during the first 15 minutes, the Permittee may extend the test period for an additional 30 minutes to demonstrate stabilization. However, the MIT meets criteria at the completion of the first 30 minute test if the total pressure loss in the 30 minute period is 2% or less and the pressure loss in the first 15 minutes(first time period) is more than the pressure in the second 15 minutes(second time period). The MPB-50 well has been on injection since 2005 and has successfully demonstrated its mechanical integrity(both internal and external) on an annual basis(with the tests being witnessed by EPA representatives). Similarly, MPB-24 successfully demonstrated its mechanical integrity (both internal and external) following the well's completion in 2015 (with the tests being witnessed by EPA representatives). The wells is are approved to continue injection upon approval of this permit modification. After the effective start date of this permit, the SAPT will be required annually until expiration of the ten(10) year permit period. This internal mechanical integrity test(standard annulus pressure test- SAPT) will be required annually if the well is active and once every two(2) years if the well is inactive. The internal mechanical integrity test due dates may be extended up to three(3) months to accommodate constraints resulting from drilling,operational or other logistics related to operating in the Arctic North Slope environment. At the discretion of the Director, and depending on the results of the internal annulus mechanical integrity test data, the frequency for demonstrating internal mechanical integrity(no leaks in the tubing-casing annulus or in the tubing-packer assembly) may be revised(either increase or decrease in frequency) as specified and approved by the Director or authorized EPA representative. (2) To detect movement of fluids in vertical channels adjacent to the well bore and to determine that the confining zone is not fractured,an approved fluid movement test shall be conducted at an injection pressure at least equal to the average continuous injection pressure observed in the previous six months. ! S Page 17 of 23 Approved fluid movement tests include, but are not limited to tracer surveys, temperature logs, noise logs,oxygen activation/water flow logs(WFL), borax pulse neutron logs (PNL), or other equivalent logs. Fluid movement test procedures not previously used to satisfy this requirement must be submitted 30 days in advance and are subject to prior approval by the Director or authorized EPA representative. Copies of all logs shall be accompanied by a descriptive and interpretive report. Fluid movement/confinement logs will be run initially upon completion of a new, existing sidetrack and/or replacement well and prior to initiation of injection at start-up. After acquiring this baseline data, the fluid movement/ confinement logs will be required every three(3) years while the well is active until expiration of the ten(10) year permit period. The test due dates may be extended up to three(3) months to accommodate constraints related to operating in the Arctic North Slope environment. At the discretion of the Director, and depending on the results of the baseline data, the frequency for demonstrating external mechanical integrity(no flow behind pipe and isolation above injection interval) and utilizing alternative diagnostic techniques, may be revised (either increase or decrease in frequency) as specified and approved by the Director or authorized EPA representative. Note: The past well MPB-50 fluid movement logs completed in 2014 are recognized to fulfill this three(3)year requirement. (3) Internal tubing inspection logs (pipe analysis logs, caliper logs, or other equivalent logs) shall be run once every three(3) years while the well is active, or at the Director or authorized EPA representative's discretion, to monitor condition, thickness and integrity of the downhole tubing. A three month grace period is granted to the test due dates. Any exposed section of the injection casing will have to be logged during any scheduled workover for tubing change-out etc. Copies of the logs shall be accompanied by a descriptive and interpretive report.Note: This is a new requirement. The past well MPB-50 internal tubing inspection logs completed in 2014 are recognized to fulfill this three(3)year requirement. c. Terms and Reporting I i (1) Two (2) copies of the log(s)and two (2)copies of a descriptive and interpretive report of the mechanical integrity tests identified in 3.b(2) and 3.b(3)shall be submitted within 45 days of completion of the logging. (2) Mechanical integrity shall also be demonstrated by the pressure test in 3.b. (1) any time the tubing is removed from the well or if a loss of mechanical integrity becomes evident during operation. The Permittee shall report the results of such tests within 45 days of completion of the tests. • • Page 18 of 23 (3) After the initial mechanical integrity demonstration, the Permittee shall notify the Director of intent to demonstrate mechanical integrity at least 30 days prior to subsequent demonstrations. (4) The Director will notify the Permittee of the acceptability of the mechanical integrity demonstration within 13 days of receipt of the results of the mechanical integrity tests. Injection operations may continue during this 13-day review period. If the Director does not respond within 13 days, injection may continue. (5) In the event that the well fails to demonstrate mechanical integrity during a test or a loss of mechanical integrity occurs during operation, the Permittee shall halt operation immediately and shall not resume operation until the Director or authorized EPA representative gives approval to resume injection. (6) The Director may, by written notice, require the Permittee to demonstrate mechanical integrity at any time. 4. Injection Zone Injection shall be limited to the Schrader Bluff(also referred to as the West Sok)and the Ugnu(also referred to as the Prince Creek) Formations.The top of the injection interval will be at the TUZC stratigraphic marker(within the Ugnu Formation) with the base of the'injection interval defined by the base of the Schrader Bluff Formation at the SBA5 marker(see Exhibits 3-2 - Milne Point Well B-02 Type Log and Exhibit 3-3 - Milne Point Area Cross Section Map in the 2004 original permit application). The top of the injection interval is currently at 4080' TVD (9020' MD) and the base of the injection interval is at 4923' TVD (11172' MD) in the MPB-50 reference well location. The top of the injection interval is at 4329' TVD (7366' MD) and the base of the injection interval is at 4920' TVD (9081' MD) in the MPB-24 well location. I ! I � S • Page 19 of 23 5. Waivers to UIC Program Requirements As a result of the subsurface aquifer conditions and the aquifer exemption for Class I injection granted by EPA on September 29, 2004,there are no underground sources of drinking water below the permafrost in the MPU area of the Class I injection wells. Furthermore on July 2, 1987, EPA concurred with Alaska Oil and Gas Conservation Commission on the decision made to exempt aquifers beneath MPU for Class II injection activities, as recorded in AOGCC Area Exemption Order(AEO) two (2). EPA is granting the following waivers of UIC regulatory program requirements as listed below: (i) Compatibility of Formation and Injectate [40 C.F.R. §§ 146.12 (e) and 146.14 (a) (8)1: Based upon the applicability of past injection studies, petrophysical logging data, existing rock and fluid samples plus successful injection practices into the same formation for the initial permit period and similar formations on the North Slope of Alaska, EPA is waiving the above two requirements for any additional sampling and characterization of formation fluids and injection rock matrix in order to determine whether or not they are compatible with the proposed injectate. (ii) Injection Zone Fracturing, Ambient Monitoring and Pressure Buildup [40 C.F.R. § 146.13 (a) (1),and(d) (1) and(2)]: Based on log surveillance results over the initial permit period that consistently verify no significant upward movement of injected fluids in the MPB-50 well, continuity of geologic formations and that transmission through faulting is not likely to transmit fluid above the confining zone, and there are no improperly sealed, completed, or abandoned wellbores in the area of review,EPA is waiving the above three requirements of an ambient monitoring of saline aquifers above the confining zone and a monitoring program including a pressure buildup of the injection zone annually. Also, based on the above, EPA is waiving the prohibition against fracturing the injection interval, and would instead allow fracturing to a minor extent at the injection well confined to the injection zone so long as new fractures are not initiated nor existing ones propagated within the upper and lower confining zone. However, in no case shall injection pressure initiate fractures in the confining intervals above and below the injection zone. Authorized injection in the wells will be limited to the permitted injection zone injection intervals located between 4080' TVD (9020' MD) and 4923' TVD (1 1 172' MD). However. external mechanical integrity demonstrations are required. [See Part II C.3.b(2)]. 6. Injection Rate and Pressure Injection pressures shall not initiate new fractures or propagate existing fractures in the upper confining zone as that stratigraphic interval is described in the Milne Point Unit Well B-02 Type Log, Exhibit 3-2 of the permit application. Neither shall the maximum • • • Page 20 of 23 injection pressure, measured at the wellhead. exceed 3000 pounds per square inch(psig), except as follows. In the event of a plant shut-down or outage, there may be instances where injection pressures exceed 3000 psi (unrelated to fluid injection activities). In such instances, the Permittee shall notify the Director or his designee by telephone or electronic mail within twenty four(24)hours of the initial exceedance of the 3000 psig limitation and shall submit a written incident report not later than ten(10)days thereafter. It should be noted that the wellhead working pressure limit of 5000 psig should not be exceeded at any time. Besides alarms and automatic shutdown controls, the wellhead assembly will include a surface safety valve to provide additional security. 7. Annulus Pressure The annulus between the tubing and the long string casing shall be filled with a corrosion inhibited non-freezing solution. To accommodate swings in wellbore temperatures and tubing thermal expansion, a positive surface pressure up to 1500 psig is authorized for the inner annulus (tubing x long string injection casing). Since the tubing-casing annulus pressure will vary due to temperature changes. the high-low annulus pressure limits can be adjusted, if necessary and upon approval by the Director or authorized EPA representative, (to include both the summer and winter ambient temperature swings). Note: The authorization of up to 1500 psi on the inner annulus is to enable shut-down and alarm systems to be set at appropriate pressure limits, so as not to shut-down the facility from unintended causes not related to direct injection activities, and is not intended to allow the Permittee to continue to maintain the well on injection, in the event of a loss of mechanical integrity or when there is pressure build-up either in the tubing by inner annulus or between the injection casing and surface casing(between the inner annulus by outer annulus), resulting in a potential sustained casing pressure scenario. In the event of a loss of mechanical integrity, then the Permittee has to meet the requirements as outlined in Part II.C.3.c.5 of this permit. 8. Injection Fluid Limitation This permit only authorizes the injection of those fluids identified in the permit documentation. En the event that third party wastes are accepted, the third party must certify that fluids for injection are not hazardous waste or radioactive wastes. Fluids generated from Class I injection well construction and well workover, and fluids generated from the operation and maintenance of Class I injection wells and associated injection well piping, may be disposed in a Class I non-hazardous injection well. De- • • Page 21 of 23 characterized waste may be appropriately disposed in a Class I non-hazardous well (refer to 40 C.F.R. § 148.1(d)). NOTE: Neither hazardous waste as defined in 40 C.F.R. Part 261 nor radioactive wastes other than naturally occurring radioactive material (NORM) from pipe scale shall be injected for disposal. D. MONITORING 1. Moiitoring Requirements Samples and measurements collected for the purpose of monitoring shall be representative of the monitored activity. 2. Continuous Monitoring Devices Continuous monitoring devices shall be installed, maintained, and used to monitor injection pressure and rate for those streams that are hard-piped and continuous, and to monitor the pressure of non-freezing solution in the annulus between the tubing and the long string casing. Calculated flow data are not acceptable except as a back-up system if the primary continuous injection rate device malfunctions. 3. Monitoring Direct Waste Injection Direct waste injection pumping operations at the well site shall be continuously manned and visually monitored. During these pumping operations, a chronological record of the . time of day, a description of the waste pumped, injection rate and pressure,and well annulus pressure observations shall be maintained. The person in charge of the pumping • operations must be identified on the pumping record. 4. Alarms and Operational Modifications a. The Permittee shall install, continuously operate, and maintain alarms to detect excess injection pressures and significant changes in annular fluid pressure. These alarms must be of sufficient placement and urgency to alert operators in the control room. The Permittee shall install and maintain an emergency shutdown system to respond to losses of internal mechanical integrity as evidenced by deviations in the annular fluid pressures. b. Plans and specifications for the alarms shall be submitted to the Director or authorized EPA representative prior to the initiation of injection. Since well MPB- 50 is an existing Class I well, and has been on injection since 2005. and the plans and specifications were submitted in the Completion Report, the monitoring and alarm systems in place for the existing well MPB-50 is hereby approved as meeting • • Page 22 of 23 the requirements of this section. E. REPORTING REQUIREMENTS 1. Quarterly Reports The Permittee shall submit quarterly reports to the Director containing the following information: a. Monthly average, maximum, and minimum values for injection pressure, rate, and volume shall be reported on INJECTION WELL MONITORING REPORT (EPA Form 7520-8). b. ! Graphical plots of continuous injection pressure and rate monitoring. c. Daily monitoring data in an electronic format. d. I Physical, chemical, and other relevant characteristics of the injected fluid. e. Any well workover or other significant maintenance of downhole or injection- related surface components. f. I Results of all mechanical integrity tests performed since the previous report including any maintenance-related tests and any "practice" tests. g. Any other tests required by the Director. 2. Report Certification All reporting and notification required by this permit shall be signed and certified in ac9ordance with Part I.E.15.; electronically stored and maintained at the permittee's facility,or company headquarters; electronically submitted to an electronic (email) address provided by the Director or authorized EPA Representative; and upon request by the Director or authorized EPA representative, submitted as a hard copy to the following address: UIC Manager, Ground Water Unit(OCE- 101) U.S. Environmental Protection Agency Region 10 1200 Sixth Avenue, Suite 900 Seattle, Washington 98101 • S Page 23 of 23 APPENDIX A REPORTING FORMS Enclosed are EPA Forms: 7520-7 APPLICATION TO TRANSFER PERMIT 7520-8 INJECTION WELL MONITORING REPORT 75.0-9 COMPLETION FORM FOR INJECTION WELLS • OMB No.2040-0042 Approval Expiros 11/30/2014 United States Environmental Protection Agency Washington,DC 20460 Application To Transfer Permit Name and Address of Existing Permittee Name and Address of Surface Owner Locate Well and Outline Unit on State County Permit Number Section Plat•640 Acres N Surface Location Description I I I I I II —114 of 114 of 1/4 of,_114 of Section_ Township Range -4-I-.4-- ---t--I-4- Locate well In two directions from nearest lines of quarter section and drilling unit I I I I I I 7771-7- -771-7- Surface - 4-(_-I•- - 4- 4- Location ft.frm(NIS)_Line of quarter section I I I I I I and_It.from(EmW). Line of quarter section. W I I I I I I E Woll Activity Well Status Type of Permit 4`1-4` -4-I-4- Class I individual I I I I I I —,Operating —. T T --f�_ _Class Il Brine Disposal Modification/Conversion —Area 1I I 1 _ Number of Wells - - --h t--+-- ---I- I-4- Proposed -- I I I I I I —Enhanced Recovery _,Hydrocarbon Storage $ —Class III Other Lease Number Well Number Namo(s)and Address(es)of New Owner(s) Name and Address of New Operator • Attach to this application a written agreement between the existing and new permittee containing a specific date for transfer of permit responsibility,coverage,and liability between them. The new permittee must show evidence of financial responsibility by the submission of a surety bond,or other adequate assurance,such as financial statements or other materials acceptable fo the Director. Certification I certify under the penalty of law that I have personally examined and am familiar with the information submitted in this document and all attachments and that, based on my inquiry of those individuals Immediately responsible for obtaining the information, I believe that the information is true,accurate,and complete.)am aware that there are significant penalties for submitting false information,including the possibility of fine and imprisonment (Ref.40 CFR 144,32) Name and Official Title (Please type or print) Signature Date Signed EPA Form 7520.7(Rev. 12.11) • • PAPERWORK REDUCTION ACT The public reporting and record keeping burden forthis collection of information is estimated to average 5 hours per response. Burden means the total time, effort, or financial resource expendedby persons to generate,maintain, retain,or disclose or provide information to or for a FederalAgency.This includes the time needed to review instructions; develop, acquire, install, and utilize technology and systems for the purposes of collecting, validating, and verifying information, processing and maintaining information, and disclosing and providing information; adjust the existing ways to comply with any previously applicable instructions and requirements; train personnel to be able to respond to the collection ofnformation;search data sources;complete and review the collection of information;and,transmit or otherwisedisclosethe information.An agencymay not conduct or sponsor,and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. Send comments on the Agency's need for this information,the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden, including the use of automated collection techniques to Director, Collection Strategies Division,U.S.Environmental Protection Agency(2822), 1200 Pennsylvania Ave., NW,Washington, D.C. 20460. Include the OMB control number in any correspondence. Do not send theompleted forms to this address. Well Class and Type Code Class I Wells used to inject waste below the deepest underground source of drinking water. Type"I" Nonhazardous industrial disposal well "M" Nonhazardous municipal disposal well Hazardous waste disposal well injecting below USDWs Other Class I wells (not included in Type"I,'"M,'or W) Class II Oil and gas production and storage related injection wells. Type"D" Produced fluid disposal well "R" Enhanced recovery well "H" Hydrocarbon storage well (excluding natural gas) Other Class II wells (not included in Type"D,""R,"or"H") Class Ill Special process injection wells, Type"G" Solution mining well Sulfur mining well by Frasch process "U" Uranium mining well Other Class Ill wells(not included in Type'G,""S,"or"U") Other Classes Wells not included in classes above. Class V wells which may be permitted under§ 144.12 Wells not currently classified as Class I, II, Ill, or V EPA Form 7520-7(12-11)Reverse OMB No.2040-0042 Approval Expires 11130/2014 United States Environmental Protection Agency ./EPA Washington,DC 20460 Injection Well Monitoring Report Year Month Month Month injection Pressure(PSI) 1. Minimum 2. Average 3. Maximum Injection Rate(Gal/Min)I 1. Minimum 2. Average 3, Maximum Annular Pressure(PSI) 1. Minimum 2. Average 3. Maximum Injection Volume(Gal) 1. Monthly Total 2. Yearly Cumulative Temperature(F') 1. Minimum 2. Average 3. Maximum pH 1. Minimum 2. Average 3. Maximum Other Name and Address of Permittee Permit Number Name and Official Tlllq (Please type or print) Signature Date Signed EPA Form 7520.8(Rev.:12.11) I S • Paperwork Reduction Act The public reporting and record keeping burden for this collection of information is estimated to average 25 hours per quarter for operators of Class I hazardous wells, 16 hours per quarter for operators of Class I non- hazardous wells, and 30 hours per quarter for operators of Class III wells. Burden means the total time, effort, or financial resource expended by persons to generate, maintain, retain, or disclose or provide information to or for a Federal Agency. This includes the time needed to review instructions; develop, acquire, install, and utilize technology and systems for the purposes of collecting, validating, and verifying information, processing and maintaining information, and disclosing and providing information; adjust the existing ways to comply with any previously applicable instructions and requirements; train personnel to be able to respond to the collection of information; search data sources; complete and review the collection of information; and,transmit or otherwise disclose the information. An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. Send comments on the Agency's need for this information, the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden, including the use of automated collection techniques to Director, Collection Strategies Division, U.S. Environmental Protection Agency(2822), 1200 Pennsylvania Ave., NW., Washington, D.C. 20460. Include the OMB control number in any correspondence. Do not send the completed forms to this address. EPA Form 7520-8 Reverse • • 0MB No.2040.0042 Approval Expires 1113012014 United States EnvironmentalProtection Agency VV EPA Washington,DC 20460 Completion Form For Injection Wells I Administrative Information 1.Permittee i Address (Permanent Mailing Address)(Street,City,and ZIP Code) 2.Operator 1 • Address (Street,City,IState and ZIP Code) 3.Facility Name I Telephone Number Address (Street,City,State and ZIP Code) 4,Surface Location D4cription of Injection Wails) State { County ; Surface Location Desc iption 114 of 114 0 ,_114 of, 114 of Section Township Range Locate well In two directions from nearest lines of quarter section and drilling unit Surface Location^ft.frm(h1S) Line of quarter section and_ft.from(VW) Line of quarter section. Well Activity I Well Status Type of Permit _Class 1 _Operating _individual Class II Modification/Conversion _Area:Number of Wells_ _Brlpe Disposal Proposed , Enhanced Recovery Hyprocarbon Storage _Class III iII Other Lease Number )I Weil Number Sumit with this Completion Form the attachments listed in Attachments for Completion Form. Certification I certify under the penalty of law that I have personally examined and am familiar with the information submitted in this document nd all attachments and that,based on my inquiry of those individuals Immediately responsible for obtaining the I formation,I believe that the information is true,accurate,and complete.I am aware that there are significant pens ties for submitting false information,including the possibility of fine and imprisonment (Ref.40 CFR 144.32) Name and Official Title (Please typo or print) Signature Date Signed EPA Form 7520.9(Rev. 12.11) • • • PAPERWORK REDUCTION ACT The public reporting and record keeping burden for this collection of information is estimated to average 49 hours per response for a Class I hazardous facility, and 47 hours per response for a Class I non-hazardous facility. Burden means the total time,effort, or financial resource expended by persons to generate,maintain,retain,or disclose or provide information to or for a Federal Agency.This includesthe time needed to review instructions;develop, acquire, install, and utilize technology and systems for the purposes of collecting,validating, and verifying information, processing and maintaining information, and disclosing and providing information;adjust the existing ways to comply with any previously applicable instructions and requirements;train personnel to be able to respond to the collection of information;search data sources; complete and review the collection of information;and, transmit or otherwise disclose the information.An agency may not conduct or sponsor, and a person is not required to respond to,a collection of information unless it displays a currently valid OMB control number.Send comments on the Agency's need for this Information, the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden,Including the use of automated collection techniques to Director,Collection StrategiesDivision,U.S.Environmental Protection Agency(2822), 1200 Pennsylvania Ave., NW,Washington.D.C.20460. Include the OMB control number in any correspondence. Do not send the completed forms to this address. Attachments to be submitted with the Completion report: 1.Geologic Information 4.Provide data on centralizers to include number,type and depth. 1.Lithology and Stratigraphy 5.Provide data on bottom hole completions. A.Provide a geologic description of the rock units pene- trated by name,age,depth,thickness,and lithology of 6.Provide data on well stimulation used. each rock unit penetrated. III.Description of Surface Equipment B.Provide a description of the injection unit. 1.Provide data and a sketch of holding tanks,flow lines, (1)Name filters,and injection pump. (2)Depth(drilled) (3)Thickness IV.Monitoring Systems (4)Formation fluid pressure (5)Age of unit 1.Provide data on recording and nonrecording injection (6)Porosity(avg.) pressure gauges,casing-tubing annulus pressure (7)Permeability gauges,injection rate meters,temperature meters,and (8)Bottom hole temperature other meters or gauges. (9)Lithology (10)Bottom hold pressure 2.Provide data on constructed monitor wells such as (11)Fracture pressure location,depth,casing diameter,method of cementing, etc. C.Provide chemical characteristics of formation fluid (attach chemical analysis). V.Logging and Testing Results D.Provide a description of freshwater aquifers. Provide a descriptive report interpreting the results of geophysical logs and other tests.Include a description (1)Depth to base of fresh water(less than 10,000 mg/I and data on deviation checks run during drilling. TDS). (2)Provide a geologic description of aquifer units with VI.Provide an as-built diagrammatic sketch of the injec- name,age,depth,thickness,lithology,and average total tion well(s)showing casing,cement,tubing,packer,etc., dissolved solids. with proper setting depths.The sketch should include well head and gauges. II.Well Design and Construction VII.Provide data demonstrating mechanical integrity 1.Provide data on surface,intermediate,and long string pursuant to 40 CFR 146.08. casing and tubing.Data must include material,size, weight,grade,and depth set. VIII.Report on the compatibility of injected wastes with fluids and minerals in both the injection zone and the 2.Provide data on the well cement,such as type/class, confining zone. additives,amount,and method of emplacement. IX.Report the status of corrective action on defective 3.Provide packer data on the packer(if used)such as wells in the area of review. type,name and model,setting depth,and type of annular fluid used. X.Include the anticipated maximum pressure and flow rate at which injection will operate. EPA Form 7520-9 Reverse • • Bettis, Patricia K (DOA) From: Luke Keller <Ikeller@hilcorp.com> Sent: Thursday, November 10, 2016 2:23 PM To: Bettis, Patricia K (DOA) Cc: Wyatt Rivard; Cody Dinger Subject: RE: MPU B-34 Permit to Drill Application (PTD 216-139) Yes, we have (2) wells currently classified as class 1 wells. MPB-50 and MPU-24. MPB-34 will be the 3rd From: Bettis, Patricia K (DOA) [mailto:patricia.bettis@alaska.gov] Sent: Thursday, November 10, 2016 2:20 PM To: Luke Keller Subject: RE: MPU B-34 Permit to Drill Application (PTD 216-139) Luke, The Class I Permit is for up to 4 wells. So will this permit cover MPU B-34? From: Luke Keller [mailto:lkeller@hilcorp.com] Sent:Thursday, November 10, 2016 2:15 PM To: Bettis, Patricia K(DOA)<patricia.bettis@alaska.gov> Cc: Cody Dinger<cdinger@hilcorp.com>; Wyatt Rivard <wrivard@hilcorp.com> Subject: FW: MPU B-34 Permit to Drill Application (PTD 216-139) Patricia, Please see attached Class 1 permit for Milne Point. Let me know if you need anything else in your review of MPU B-034. From: Wyatt Rivard Sent: Thursday, November 10, 2016 2:14 PM To: Luke Keller; Cody Dinger Subject: RE: MPU B-34 Permit to Drill Application (PTD 216-139) Luke, We do have a Class 1 Permit at Milne. The most recent version is attached. The permit provides for up to four class 1 wells at Milne, we currently only have MPB-50 and MPB-24 completed. The permit references MPB-51 instead of MPB- 34 but the name and surface location will be updated once the well is completed. Thank You, Wyatt Rivard { Well Integrity Engineer 0: (907) 777-8547 1 C: (509)670-80011 wrivard@hilcorp.com 3800 Centerpoint Drive,Suite 140[) 1 Anchorage,A1(99503 11 Hlcorp Alaska From: Luke Keller Sent:Thursday, November 10, 2016 2:06 PM 1 • • To: Cody Dinger<cdinger@hilcorp.com>; Wyatt Rivard <wrivard@hilcorp.com> Subject: FW: MPU B-34 Permit to Drill Application (PTD 216-139) Wyatt, Do we have an EPA Underground Injection Control Permit for Milne Point? From: Bettis, Patricia K (DOA) [mailto:patricia.bettis@alaska.gov] Sent: Thursday, November 10, 2016 1:51 PM To: Luke Keller Subject: MPU B-34 Permit to Drill Application (PTD 216-139) Good afternoon Luke, Is MPU B-34 going to be a class I or class II disposal well? If the proposed well is a class II disposal well, Hilcorp will need to submit an application for underground disposal of oil waste, 20 AAC 25.252. If it is a class I disposal well, please provide a copy of the EPA Underground Injection Control Permit. Does Hilcorp plan to pre-produce the well; and if so, for what duration. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907)793-1238 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 Patricia Bettis at(907)793-1238 or patricia.bettis@alaska.gov. 2 S Bettis, Patricia K (DOA) From: Luke Keller <Ikeller@hilcorp.com> Sent: Thursday, November 10, 2016 2:17 PM To: Bettis, Patricia K (DOA) Subject: RE: MPU B-34 Permit to Drill Application (PTD 216-139) Patricia, We will not pre-produce the well. From: Bettis, Patricia K (DOA) [mailto:patricia.bettis@alaska.gov] Sent: Thursday, November 10, 2016 1:51 PM To: Luke Keller Subject: MPU B-34 Permit to Drill Application (PTD 216-139) Good afternoon Luke, Is MPU B-34 going to be a class I or class II disposal well? If the proposed well is a class II disposal well, Hilcorp will need to submit an application for underground disposal of oil waste, 20 AAC 25.252. If it is a class I disposal well, please provide a copy of the EPA Underground Injection Control Permit. Does Hilcorp plan to pre-produce the well; and if so, for what duration. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907)793-1238 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 Patricia Bettis at(907)793-1238 or patricia.bettis@alaska.gov. 1 • Bettis, Patricia K (DOA) From: Luke Keller <Ikeller@hilcorp.com> Sent: Thursday, November 10, 2016 2:09 PM To: Bettis, Patricia K (DOA) Subject: RE: MPU B-34 Permit to Drill Application (PTD 216-139) Patricia, B-034 will be a class 1 disposal well. I apologize for not specifying on the PTD application. I will track down the EPA Underground Injection Control Permit and send to you ASAP. Thanks! Luke Keller Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 From: Bettis, Patricia K (DOA) [mailto:patricia.bettis@alaska.gov] Sent: Thursday, November 10, 2016 1:51 PM To: Luke Keller Subject: MPU B-34 Permit to Drill Application (PTD 216-139) Good afternoon Luke, Is MPU B-34 going to be a class I or class II disposal well? If the proposed well is a class II disposal well, Hilcorp will need to submit an application for underground disposal of oil waste, 20 AAC 25.252. If it is a class I disposal well, please provide a copy of the EPA Underground Injection Control Permit. Does Hilcorp plan to pre-produce the well; and if so, for what duration. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907)793-1238 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 1 1110 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 Patricia Bettis at(907)793-1238 or patricia.bettis@alaska.gov. 2 • TRANSMITTAL LETTER CHECKLIST WELL NAME: (A, -3 y PTD: 021 (9 -/37 Development /Service Exploratory Stratigraphic Test Non-Conventional FIELD: /►/�/l/1i.:20INA POOL: &/IL ,n� U/'1��Jlnkct l SP Check Box for Appropriate Letter I 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) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - ) 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. (Company 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 Iname 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. In 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 days after completion, suspension or abandonment of thispwell. , /•14 (,0406/C ,`h 9 CGOr015iC' ©1r t nse vh e> oipe- en S 4,D he d Revised 2/2015 EP/1" s s ve s5CQ cu" L (44-)34- c94r ' /OCi.C C 15s✓c-4 C6a/h 1I �U=rrvu 6 0 J 0 a3 o) CO , , , , , . . . . . . . , , , , . , , , , , , 3 NN Co a) O yj. - L`o 0 . . , , , , , , , . . , c. -`o N c C. >. Q L co U' Q_ t . , . . . . . j o O '0, , , v, . . o a). E, c - o ° E. O CL .c N d , , . a CU, t. • O E. `o. d o. 0 a) C O, T o 2 Di co O C W' a) 01 a 3 a) 0. �� �� E 3, 3. w N . No �. �, g. 3. U AMSNCN O. ' • 00 (O. � 0. N 72' d 2.' 0 CO N Q Z iO (ca , �, 3. 4 ao. , , a as O o �c. y° as. 4 o_ O • . a c. dO ° , , a . 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