The URL can be used to link to this page

Home My WebLink About214-206CAUTION: 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:Stephen Soroka To:Regg, James B (OGC); Wallace, Chris D (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC) Cc:Ryan Thompson; Alaska NS - Wells Integrity Subject:Milne Point, Northstar & Point Thompson July MIT"s Date:Thursday, July 31, 2025 1:26:00 PM Attachments:MIT-IA MPU B-24, B-50 7-20-2025.xlsx MIT-IA MPU B-34 07-16-2025.xlsx MIT-IA MPU E-26 07-21-2025.xlsx MIT-IA MPU R-105 7-4-2025.xlsx MIT-IA NS10, NS32 EPA 07-20-2025.xlsx MIT-IA PTU DW-01 7-20-2025.xlsx All – Attached are recently completed MIT’s performed in July for Milne Point, Northstar and Point Thompson. Well PTD# Comment MPU B-24 1960090 Annual EPA MIT-IA MPU B-34 2161390 Annual EPA MIT-IA/Operable Status change MPU B-50 2042520 Annual EPA MIT-IA MPU E-26 2002060 4-Year MIT-IA MPU R-105 2250170 Initial 4-Year MIT-IA NS-10 2001820 Annual EPA MIT-IA NS-32 2031580 Annual EPA MIT-IA PTU DW-01 2142060 Annual EPA MIT-IA Thank you, Steve Soroka Hilcorp Alaska LLC Field Well Integrity Steve.Soroka@hilcorp.com P: (907) 830-8976 Alt: Chris Casey 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. 3W7KRPVRQ8QLW': 37' 9 PTU DW-01 2142060 Annual EPA MIT-IA Submit to: OOPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 214206 Type Inj I Tubing 1775 1740 1650 1705 Type Test P Packer TVD 5757 BBL Pump 1.1 IA 996 2540 2440 2444 Interval O Test psi 2500 BBL Return 1.1 OA 0 0 0 0 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 MMechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Hilcorp Alaska, LLC Point Thomson/ PTU / Point Thomson Witness waived by Kam St John. Chris Casey 07/20/25 Notes:EPA Class 1 Disposal Well. Annual MIT-IA to 2500 psi per EPA permit AK-1I015-B. *EPA Rep Evan Osborne confirmed Passing test, +4 psi in the last 30 min due to Injection Rate increase from plant. Notes: Notes: Notes: PTU-DW01 Form 10-426 (Revised 01/2017)2025-0720_MIT_PTU_DW-1 99 999 9 9 9 9 -5HJJ 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: 8/13/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240813 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BRU 222-24 50283201800000 22Ϭ043 8/1/2024 AK E-LINE CIBP BRU 222-26 50283201950000 224035 7/21/2024 AK E-LINE Plug BRU 232-04 50283100230000 162037 7/25/2024 AK E-LINE Perf BRU 241-26 50283201970000 224068 7/24/2024 AK E-LINE CBL BRU 241-26 50283201970000 224068 7/31/2024 AK E-LINE CBL BRU 241-34S 50283201980000 224077 7/10/2024 AK E-LINE CBL BRU 241-34S 50283201980000 224077 7/18/2024 AK E-LINE CBL BRU 241-34S 50283201980000 224077 7/23/2024 AK E-LINE CBL BRU 241-34S 50283201980000 224077 7/28/2024 AK E-LINE Hoist IRU 44-36 50283200890000 193022 8/3/2024 AK E-LINE CBL IRU 44-36 50283200890000 193022 7/31/2024 AK E-LINE CIBP IRU 44-36 50283200890000 193022 7/29/2024 AK E-LINE RCT MPU I-01 50029220650000 190090 7/20/2024 AK E-LINE CBL MRU M-02 50733203890000 187061 7/20/2024 AK E-LINE Plug PBU PTM P1-08A 50029223840100 202199 7/23/2024 AK E-LINE CBL PBU V-220 50029233830000 208020 6/28/2024 READ InjectionProfileAnalysis PTU DW-01 50089200320000 214206 7/16/2024 READ CaliperSurvey PTU DW-0ϭ 50089200320000 214206 7/17/2024 READ TemperatureSurvey Please include current contact information if different from above. T39418 T39419 T39420 T39421 T39421 T39422 T39422 T39422 T39422 T39423 T39423 T39423 T39424 T39425 T39426 T39427 T39428 T39428 PTU DW-01 50089200320000 214206 7/16/2024 READ CaliperSurvey PTU DW-0ϭ 50089200320000 214206 7/17/2024 READ TemperatureSurvey Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.08.13 13:58:22 -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: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. 3W7KRPVRQ8QLW': 37' Point Thomson well DW-1 Submit to: OOPERATOR: FIELDD // UNITT // PAD: DATE: OPERATORR REP: AOGCCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2142060 Type Inj I Tubing 1493 1481 1468 1455 1445 Type Test P Packer TVD 5757 BBL Pump 2.3 IA 468 2687 2556 2483 2433 Interval O Test psi 2500 BBL Return 2.3 OA 0 14 12 10 9 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: Hilcorp Alaska, LLC Pt Thomson / PTU / Pt Thomson Tate Syverson 07/17/24 Notes:EPA Class 1 Disposal Well. Annual MIT-IA to 2500 psi per EPA permit AK-1I015-B. EPA witnessed and passed by James Robinson. AOGCC waived witness by Sean (Sully) Sullivan. Notes: Notes: Notes: DW-1 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: Notes: Notes: Form 10-426 (Revised 01/2017)2024-0717_MIT_PTU_DW-1 9 9 9 9 9 9999 9 9 -5HJJ DW-1 EPA Class 1 Disposal Well. Annual MIT-IA to 2500 psi per EPA 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; Tate Syverson; Amy Peloza; Joey Hensley; Stefen Haynes; Martin Mylet; Claire Costello - (C) Subject:MIT-IA for Point Thomson well DW-1 Date:Tuesday, February 27, 2024 11:43:25 AM Attachments:MIT PTU DW-1 2-21-2024.xlsx All, Point Thomson well DW-1 (PTD # 2142060) successfully passed an MIT-IA on February 21, 2024. 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 theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Pt Thomson DW-1 PTD 2142060 Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 2142060 Type Inj I Tubing 1898 1910 1912 1912 Type Test P Packer TVD 5,757'BBL Pump 3.0 IA 19 2600 2477 2440 Interval O Test psi 2500 BBL Return 2.5 OA 0 0 0 0 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 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 Hilcorp Alaska, LLC Pt Thomson / PTU / Pt Thomson Stefen Haynes 02/21/24 Notes:EPA Class 1 disposal well witnessed by EPA's Evan Osborne. Annual MIT-IA required to 2500 psi. AOGCC witness waived by Sean (Sully) Sullivan. Notes: Notes: Notes: Notes: Notes: DW-1 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 Form 10-426 (Revised 01/2017)2024-0221_MIT_PTU_DW-1        J. Regg; 5/10/2024 1 Regg, James B (OGC) From:Brooks, Phoebe L (OGC) Sent:Thursday, March 16, 2023 4:19 PM To:Tate Syverson Cc:Regg, James B (OGC) Subject:RE: Point Thomson Unit DW-1 MIT Results 2/20/2023 Attachments:MIT PTU DW-1 02-20-23 Revised.xlsx Tate, Attached is a revised report rounding the pressure decimals and moving the waived by verbiage to the Notes. 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: Tate Syverson <Tate.Syverson@hilcorp.com> Sent: Thursday, February 23, 2023 4:35 PM To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Jerimiah Galloway <Jerimiah.Galloway@hilcorp.com>; Joey Hensley <jhensley@hilcorp.com>; Stefen Haynes <sthaynes@hilcorp.com>; PB EHS WOA Environmental <PBEHSWOAEnvironmental@hilcorp.com> Subject: Point Thomson Unit DW‐1 MIT Results 2/20/2023 All, Please see the attached results from the DW‐1 MIT conducted on 2/20/2023. Thanks, Tate Syverson Point Thomson Operations Lead Hilcorp Alaska, LLC (907)685‐3505‐O (907) 251-1891-C Positional: alaskans‐pointthomson‐operationsleads@hilcorp.com Alt: Stefen Haynes Some people who received this message don't often get email from tate.syverson@hilcorp.com. Learn why this is important 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. Pt Thomson Unit DW-1PTD 2142060 Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 2142060 Type Inj I Tubing 1893 1910 1918 1921 Type Test P Packer TVD 5,757'BBL Pump 1.6 IA 660 2612 2472 2446 Interval O Test psi 1500 BBL Return 1.5 OA 0 70 67 67 Result P Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj N 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 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 DW-1 Notes:EPA Class 1 DW. Annual MIT-IA required. EPA inspector James Robinson. Waived Witness by Brian Bixby Notes: Notes: Notes: Notes: Notes: Hilcorp Alaska, LLC Pt Thomson / PTU / Pt_Thomson Dean Devaney 02/20/23 Form 10-426 (Revised 01/2017)2023-0220_MIT_PTU_DW-1           J. Regg; 5/2/2023 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 4/14/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL PTU DW-1 (PTD 214-206) Temp 2/22/2022 Log Pass 1, 2, 3 Log Pass 4, 5 214-206 T36481 Meredith Guhl Digitally signed by Meredith Guhl Date: 2022.04.14 15:43:21 -08'00' Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: MFC 2/25/2022 Report Please include current contact information if different from above. From:Stevenson, Kalb /C To:Wallace, Chris D (CED); AOGCC Cust Svc (CED sponsored) Cc:EM Alaska Correspondence /SM Subject:AK1I015-B 3Q2021 UIC Monitoring Report (ER-2021-OUT-180) Date:Wednesday, October 27, 2021 12:16:16 PM Attachments:ER-2021-OUT-180 USEPA UIC DW-1 3Q21 Monitoring Report AK1I015-B cover le....pdf Attachment A - 7520-8 Injection Well Monitoring Report 3Q2021.pdf Dear Chris, Attached please find ExxonMobil Alaska Production Inc.’s submittal of the 3rd Quarterly 2021 Monitoring Report for the UIC well at Point Thomson under USEPA Permit AK1I015-B. 3Q2021 Report Attachments: · Cover Letter · Attachment A - EPA Form 7520-8 I Injection Well Monitoring Report 3Q2021 Thank you for accepting this report electronically; no hard copies will be mailed unless otherwise requested. Please let me know if you have any questions. Thank you, Kalb Stevenson Environmental & Regulatory Advisor ExxonMobil Alaska Production, Inc. 3700 Centerpoint Dr., Suite 600 Anchorage, AK 99503 907-564-3619 work 907-297-9519 cell kalb.stevenson@exxonmobil.com ExxonMobil Upstream Oil & Gas Company Todd Griffith Post Office Box 196601 Point Thomson Asset Manager Anchorage, Alaska 99519 832-624-3256 Telephone 907 202-2728 Cell A Division of Exxon Mobil Corporation October 22, 2021 ER-2021-OUT-180 U.S. Environmental Protection Agency Region 10 Ground Water and Drinking Water Section, UIC Program (19-H16) 1200 Sixth Avenue, Suite 155 Seattle, Washington 98101 Re: Point Thomson UIC Permit No. AK 1I015-B, 3rd Quarter 2021 Monitoring Report Dear Director, In accordance with Condition II.E.1 of Underground Injection Control (UIC) Permit No. AK 1I015-B, ExxonMobil Alaska Production, Inc. hereby submits the quarterly report for 3Q2021. The permit required information is addressed below:  Monthly average, maximum, and minimum values for injection pressure, rate, and volume: See Attachment A.  Graphical plots of continuous injection pressure and rate monitoring: See Attachment B.  Daily monitoring data in an electronic format: See Attachment C.  Physical, chemical, and other relevant characteristics of the injected fluid: See Attachment D.  Any well workover or other significant maintenance of downhole or injection related surface components: No well workover or other significant maintenance was conducted during this reporting period.  Results of all mechanical integrity tests performed since the previous report including any maintenance-related tests and any "practice" tests: No mechanical integrity tests were performed since the previous report.  Any other tests required by the Director: No test requests were received from the Director. If you have any questions, please contact Kalb Stevenson at kalb.stevenson@exxonmobil.com or by phone at (907) 564-3619. “I certify under the penalty of law that this document and all attachments were prepared under my direction or supervision in accordance with a system designed to assure that qualified personnel properly gather and evaluate the information submitted. Based on my inquiry of the DocuSign Envelope ID: E35334F0-D307-46F0-B93D-691FDEAB49FF An ExxonMobil Subsidiary person or persons who manage the system, or those persons directly responsible for gathering the information, the information is, to the best of my knowledge and belief, true, accurate, and complete. I am aware that there are significant penalties for submitting false information, including the possibility of fine and imprisonment for knowing violations.” Sincerely, TG:kts:lo For and On Behalf of ExxonMobil Alaska Production Inc. cc: Timothy Mayers (EPA) Evan Osborne (EPA) Chris Wallace (AOGCC) - Attachment A only Attachments: Attachment A – 3Q21 EPA Form 7520-8 Attachment B – Graphical plots of continuous injection pressure and rate monitoring Attachment C – Daily monitoring data in an electronic format Attachment D – Point Thomson Waste Streams DocuSign Envelope ID: E35334F0-D307-46F0-B93D-691FDEAB49FF OMB No. 2040-0042 Approval Expires 4/30/2022 United States Environmental Protection Agency Quarterly Injection Well Monitoring Report Month/Year Month/Year Month/Year Injection Pressure (PSI) 1. Minimum 2. Average 3. Maximum Injection Rate (Barrels/Day) 1. Minimum 2. Average 3. Maximum Annular Pressure (PSI) 1. Minimum 2. Average 3. Maximum Injection Volume (Barrels) 1. Monthly Total 2. Yearly Cumulative Temperature (F °) - If Specified in UIC Permit 1. Minimum 2. Average 3. Maximum pH - If Specified in UIC Permit 1. Minimum 2. Average 3. Maximum Other Information Specified in the Permit (Attach Pages if Necessary) Permit (or EPA ID) Number API Number Full Well Name 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 imprisonmentt. (Ref. 40 CFR § 144.32) Name and Official Title (Please type or print) Signature Date Signed EPA Form 7520-8 (Rev. 4-19) July/2021 August/2021 September/2021 1179 105 1468 1633 1688 1752 2068 1944 3062 146 224 222 263 258 255 375 279 272 22 270 383 692 586 692 1153 1029 979 8157 8006 7655 29889 37895 45550 69 83 85 94 93 95 104 103 101 AK-1I015-B 50-089-20032-00-00 PTU-DW1 Todd Griffith, Point Thomson Asset Manager DocuSign Envelope ID: E35334F0-D307-46F0-B93D-691FDEAB49FF October 24, 2021 INSTRUCTIONS FOR FORM 7520-8 Use this form to submit quarterly injection well monitoring results. Note: owners or operators of Class II wells should use Form 7520-11 to report monitoring results. Please submit a separate form for each well. On the top row, enter the MONTH and YEAR for each month of the quarter for which monitoring results are being reported. INJECTION PRESSURE: Enter the minimum, average, and maximum injection pressure that occurred during each month, in pounds per square inch (psi). INJECTION RATE: Enter the minimum, average, and maximum injection rate, in barrels per day, that occurred during each month. ANNULAR PRESSURE: Enter the minimum, average, and maximum pressure on the annulus between the tubing and long string casing that occurred during each month, in pounds per square inch (psi). INJECTION VOLUME: Enter the monthly total and yearly cumulative volume (in barrels) that has been injected. TEMPERATURE: If the UIC permit requires monitoring of the temperature of the injectate, provide the minimum, average, and maximum temperature that occurred during each month, in degrees Fahrenheit (F°). pH: If the UIC permit requires monitoring of the pH of the injectate, provide the minimum, average, and maximum values that occurred during each month. OTHER INFORMATION: If the UIC permit requires any other monitoring, provide the minimum, average, and maximum values that occurred during each month, as appropriate. (Attach pages to this form if necessary.) PERMIT OR EPA ID NUMBER: Enter the well identification number or permit number assigned to the injection well by the EPA or the permitting authority. API NUMBER: Enter the number assigned by the local jurisdiction (usually a State Oil and Gas Agency) using the American Petroleum Institute standard numbering system. FULL WELL NAME: Enter the full name of the well or project. CERTIFICATION: This form must be signed and dated by either: a responsible corporate officer for a corporation, by a general partner for a partnership, by the proprietor of a sole proprietorship, or by a principal executive or ranking elected official for a public agency. PAPERWORK REDUCTION ACT NOTICE: The public reporting and recordkeeping burden for this collection of information is estimated to average 24.7 hours per response for operators of Class I hazardous wells, 14.4 hours per response for operators of Class I non-hazardous wells, and 27.9 hours per response 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. DocuSign Envelope ID: E35334F0-D307-46F0-B93D-691FDEAB49FF D UJ ? Regg, James B (CED) From: Brooks, Phoebe L (CED) Sent: Monday, March 1, 2021 4:11 PM �Pf� �jIlI2CTL1 To: Mayfield, Claire C Cc: Regg, James B (CED) Subject: RE: Point Thomson DW -1 MIT 2-26-2021 Attachments: MIT PTU DW -1 02-26-21 Revised.xlsx Claire, Attached is a revised report changing the Type Inj to reflect "I" (industrial wastewater) as this is a Class I well. Please update your copy or let me know if you disagree. Thank you, Phoebe Phoebe Brooks Statistical Technician II Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 Fax: 907-276-7542 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: Mayfield, Claire C <claire.c.mayfield@exxonmobil.com> Sent: Saturday, February 27, 20211:57 PM To: Regg, James B (CED) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay<doa.aogcc.prudhoe. bay@alaska.gov>; Brooks, Phoebe L (CED) <phoebe.brooks@alaska.gov>; Wallace, Chris D (CED) <chris.wallace@alaska.gov> Cc: EM Alaska Correspondence /SM<emalaskacorrespondence@exxonmobil.com> Subject: Point Thomson DW -1 MIT 2-26-2021 Good afternoon, Please see attached MIT results form for Point Thomson water disposal well DW -1 on 2/26/2021. Thank you, Claire Campbell Mayfield Point Thomson Production Engineer ExxonMobil Upstream Oil & Gas Point Thomson Operations 3700 Centerpoint Dr., Suite 600 Anchorage, AK 99503 (907) 564-3651 Office / (713) 443-3631 Mobil STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submitto: -'m read®alaska.Gov'. AOGCCInsoectoreGAalaska.GOY. phoebeblooks0alaskagov OPERATOR: ExxonMobil FIELD/UNIT I PAD: Point Thomson/Central Patl DATE: OPERATOR REP: AOGCC REP: Clare Mayfield chns wallace0alaska dov I �fj 3((J-A2j Well PTU DW -1 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2142060 Type Inj Tubing 1720 1729 1726 1725 • Type Test P Packer TVD 5757 1 BBL Pump 1.5 1 IA 418 2809 - 2680 2651" Interval O Test psi 2500 BBLRelum 17 OA 1 0 21 1 19 19 Result P NNWes: Fluid used'. LVT-200: WHT: 74F{ Well on injection at 4.3 gem Total loss: 158 Mi (5,6%) Loss In last 15 minutes I loss in fire 15 minutes: (32.8%) Annual lest per EPA permb AK-1101SB requirementsI..I... i disposal well. Witnessed by FPA representative Jason 5eli15ch. AOGOC winces waived. ✓ Well Pressures: Pretest Initial 15 Min. Whin. 45 Min. 60 Min. PTD Type Int Tubing I Type Test Packer TVD BBL Pump IA Interval Teslpsi 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 Teslpsi BBL Return OA Result Notes: Well Pressures: Pretest Initial 151it 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi Beturn BL R OA ResuR Names, Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Tesl Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Nates: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type IN Tubing Type Test Paler TVD BBL Pump IA all Interval BBL Retum OA Result Net..: 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 Nates: 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 holes: TYPE INJ C. W=Wider G=Gas 5=Slurry I=Industrial Wassawater N =Nos Injeom, TYPE TEST Codes INTERVAL Codes P=Pressure Test I=Initial Ted O= Geer (dest in Ndes) 4=Four year Cycle V = Rtyutred by Variance O=Oder (deacma In nine.) Form 10426 (Revised 01/2017) MIT PTU Ow -102-36-21 Revised Rssult Codes P=Pace F = Fail I = emncluWe -Pry Y)t4)-( Pl-b z14ziX00 Regg, James B (CED) From: Brooks, Phoebe L (CED) �(�jGfj�Qj Sent: Friday, February 28, 2020 10:53 AM To: Scarlett, Kenley Cc: Regg, James B (CED) Subject: RE: Point Thomson DW -1 MIT (PTD 214-206) Attachments: MIT PTU DW -1 02-26-20.xlsx Kenley, I added the well name to the report and changed the PTD # format to reflect 2142060. Please update your copy. Thank you, Phoebe Phoebe Brooks Statistical Technician II Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 Fax: 907-276-7542 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 nhoebe.brooks@alaska.eov. From: Scarlett, Kenley<kenley.scarlettl@exxonmobil.com> Sent: Thursday, February 27, 2020 3:17 PM To: Regg, James B (CED) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (CED) <phoebe.brooks@alaska.gov>; Wallace, Chris D (CED) <chris.waIlace @alaska.gov> Cc: EM Alaska Correspondence /SM<emalaskacorrespondence@exxonmobil.com> Subject: Point Thomson DW -1 MIT (PTD 214-206) Hi All, Find the DW -1 (PTD 214-206) MIT results attached. The test was waived by the AOGCC and was witnessed by Ryan Gross with the EPA on 2/26/20. Regards, Kenley Scarlett Production Engineer ExxonMobil Alaska Production 3700 Centerpoint Drive, Suite 600 Skype: (907) 564-3606 Cell: (907) 290-1451 ExxonMobil Upstream Oil & Gas Company Post Office Box 196601 Anchorage, Alaska 99519 907 334-2908 Telephone 907 202-2728 Cell October 21, 2019 ER -2019 -OUT -307 -P-ID 214 Zo(Pic) Steve Williams Point Thomson Asset Manager E).&onMobil R��E�VED UIC Manager, Ground Water Protection Unit OCT 251019 200 Environmental Sixth ixth A enue, Suite 155, OCE -101 Seattle, Washington 98101 Re: Annual Injection Data for DW -1 for 2019 Fiscal Year (AK11015-A) Dear UIC Manager, ExxonMobil Alaska Production, Inc. hereby submits the 2019 fiscal year annual injection data for the Point Thomson Unit Disposal Well (DW -1) operated under Permit No. AK 11015-A. Please note that annual cumulative volumes are calculated based on annual calendar year per USEPA guidance. Annual reporting form was edited to include injection rate and injection volume in two different units (GPM, BPD) for ease of comparison between previously submitted reports and new quarterly reporting format. If you have any questions, please contact Sofia (Sonia) Laughland at (907) 564-3604 or via email(sofia.m.laughland@exxonmobil.com). 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. Sincerely, SW/sl/Io For and On Behalf of ExxonMobil Alaska Production Inc. A Division of Exxon Mobil Corporation cc: Timothy Mayers (EPA) Evan Osborne (EPA) Chris Wallace (AOGCC) Attachments: Annual 2019 Injection Data Report § / - °;_°!`!;!°!!l;;;! 4kli !r§§°�;-!!_:!;!~•r�; 421 ;;;!(}�(:!u !§K[ i:z §&\§(((\\(»izl'aas 2z ^{}§))»\�}§Jm - \\(})})))\\\/\/\/) § / ExxonMobil Alaska Production Inc. Post Office Box 196601 Anchorage, Alaska 99519 907 564 3617 Telephone 907 564 3719 Facsimile February 6, 2019 ER -2019 -OUT -027 Mr. Evan Osborne U.S. Environmental Protection Agency, Region X 1200 Sixth Avenue, Suite 900, OCE -082 Seattle, Washington 98101 Re: ExxonMobil Point Thomson MIT Test UIC Class I Disposal Well Permit AK11015-A Dear Mr. Osborne, Brien E. Reep SSH&E Manager P-0) 2A -WD T FEB 1 1 20119 ExxonMobil hereby provides a 30 day notification of our intent to conduct the annual mechanical integrity test for the PTU-DW1 on or around March 12, 2019 pursuant to requirements within Part II C.3.c.(3) of the UIC Permit. If you have any questions or comments please contact Sofia (Sonia) Laughland at (907) 564- 3604 or via email at sofia.m.lauohland(a)exxonmobil.com. Sincerely, 7 BER:sml:lo For and on behalf of ExxonMobil Alaska Production Inc. cc: Chris Wallace (AOGCC) Attachment: ExxonMobil Point Thomson UIC Class I Disposal Well Mechanical Integrity Test Procedure A Division of Exxon Mobil Corporation DocuSign Envelope ID: 20C16CFB-E3DO-49D4-9074-3BFDOAABOE04 E�onMobil ExxonMobil Alaska Production Inc. Point Thomson Disposal Well (PTU-DW1) I POINT THOMSON OPERATIONS Mechanical Integrity Test (MIT) Procedure Prepared:—°°`"s'9^" by: Production Engineer kf' t 5" Date: January 31, 2019 K. Scarlett Reviewed: °°° ^e' °v E&R Advisor S 0-a`Date: Date: January 31, 2019 S. LaughlTliH Endorsed: ° sg aer Operations Technical Manager �aw,u �� Date: January 31, 2019 J. Long Approved: °°^°Si9 by Sr. Field Superintendent C�& CrMLS Date: February 2, 2019 ------eeeFes--- R. Trout/ D. Crooks Revision date: January 2019 DocuSign Envelope ID: 20C16CFB-E3DO-49D4-9D74-3BFDOAABOE04 ExxonMobil This page intentionally blank Revision date: January 2019 Page 2 DocuSign Envelope ID: 20C16CFB-E3DO-49D4-9D74-3BFDOAABOE04 ExxonMobil TABLE OF CONTENTS INTRODUCTION.............................................................................................................4 ProgramScope............................................................................................................4 Regulatory Notifications................................................................................................4 DataRequirements......................................................................................................4 MITPreparation............................................................................................................4 TestCriteria..................................................................................................................5 Reporting......................................................................................................................5 WELLINFORMATION....................................................................................................6 GeneralWell Data........................................................................................................6 Tubing & Casing Information........................................................................................6 Alarms& Shutdowns....................................................................................................6 WellheadStackup........................................................................................................7 WellboreSketch...........................................................................................................8 CONDUCTMIT................................................................................................................9 EquipmentRequired.....................................................................................................9 Preliminary...................................................................................................................9 RigUp........................................................................................................................10 PressureTest IA.........................................................................................................10 RigDown....................................................................................................................11 PostJob.....................................................................................................................11 APPENDIX.....................................................................................................................12 EPAMIT Form............................................................................................................12 Revision date: January 2019 Page 3 DocuSign Envelope ID: 20C16CFB-E3DO-49D4-9D74-3BFDOAABOE04 ExxonMobil INTRODUCTION This program outlines the procedure for conducting a standard annulus pressure test / inner annulus mechanical integrity test (SAPT / MITIA). The SAPT / MITIA will be required annually if DW -1 well is active. Notify EPA at least 30 days in advance of conducting the MIT so that a representative can be present to witness the test. Courtesy notification to AOGCC at least a week in advance is necessary to allow coordination of travel to Point Thomson to witness the test. Formal notice via the AOGCC online form is required at least 48 hours in advance of the test. Data Requirements The following information must be available at the location for review: • Valid approved waivers, if any, relating to the integrity of the tested well. • Current well schematic. • Graph of tubing, inner annulus, and outer annulus pressures for the preceding 90 days. The following guidance is provided with respect to MIT testing: • Document any activity involving pumping into and bleeding pressure from the annuli within 24 hours of the MIT. • The well's annulus should be fluid packed before the Inspector arrives. • 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. • Calibrated pressure gauges or digital transmitters with suitable range and accuracy must be installed on the tubing, inner annulus and outer annuli. • Suitable flow measurement equipment should be available to determine the volume of fluids pumped into and returned from the tested space. • Other equipment (e.g. tanks, lines, bleed trailers, etc.) necessary for the safe pressure testing and suitable for the operating environment should be rigged up prior to Inspector arrival at the location. Revision date: January 2019 Page 4 DocuSign Envelope ID: 20C16CFB-E3DO-49D4-9D74-3BFDOAABOE04 ExxonMobil Relevant MIT requirements under EPA permit AK11015-A are outlined below: • Test pressure for SAPT/MITIA will be at least 2500psi over 30 minutes. • Criteria for a passing MIT: o Pressure may not decline more than 10% during the 30 min test period, and show a stabilizing tendency o Pressure loss in the last 15 mins of the test must be less than one third of its total loss • If the total loss exceeds 10% of if the loss during the second 15 minute period is equal or greater than half the loss during the first 15 minutes, the test may be extended for an additional 30 minutes to demonstrate stabilization (resulting from thermal effects). Reporting Agency reporting will be coordinated by the engineering and SSHE team in Anchorage. Report the results of the MIT to EPA on the provided form within 45 days. Copy AOGCC on the report submission. Also include the MIT results in the next quarterly report to the EPA Director, including any maintenance -related tests and any 'practice' tests. For AOGCC complete MIT Form 10-426, noting the test was witnessed by EPA, and submit electronically no later than the 511 calendar day of the month following the test. date: January 2019 Page 5 DocuSign Envelope ID: 20C16CFB-E3DO-49D4-9D74-3BFDOAABOE04 ExxonMobil Well Name: PTU-DW1 Well Type: Service - Disposal UIC Permit: AK11015-A Field / Location: Point Thomson, North Slope AK — Central Pad Slot 1 Surface Location: Lat: N 700 10'23.30436" Long: W 1460 15'20.05740" Total Depth: 8,800' MD / 6,905' TVD Base Permafrost: 1,832' MD / 1,832' TVD Packer Depth: 7,018' MD / 5,757' TVD Reference Elevation: 33.4' RKB-GL (46.1' RKB-MSL) Wellbore Profile: Build to 50 degrees and hold Last Annulus MIT: 3/26/2018— IA tested to 2500psi (passed) I I High 2600psi Maximum expected surface pressure during normal injection operations (based on well modelling and step rate test results) Wellhead Injection Pressure (PST551001-01) High -High 4-1/2 12.6 lCr-L80 7,100 Vern Top 8,430 7,500 288 288 7 26 1Cr-L80 8,781 TSH 563 7,240 5,410 604 604 9-518 53.5 L80 4,952 Vern Top KX 7,930 6,620 1,244 1,244 34 x 20 129.5 X-52 154 PE Weld N/A N/A 1,978 N/A Alarms & Shutdowns Revision date: January 2019 Page 6 High 2600psi Maximum expected surface pressure during normal injection operations (based on well modelling and step rate test results) Wellhead Injection Pressure (PST551001-01) High -High 5000psi Wellhead working pressure rating and UIC permit limit Shut Down 5000psi High 1200psi 80% of UIC permit limit Tubing x Production Casing 1500psi UIC permit limit (Inner) Annulus Pressure High -High (PST551001-02) Shut Down 1500psi High 200psi Recommended surface annulus trigger pressure Production Casing x Surface Casing (Outer) Annulus Pressure (PST551001-03) High -High 450psi Calculated formation integrity (based on drilling FIT and annulus fluid weight) Shut Down 450psi Revision date: January 2019 Page 6 DocuSign Envelope ID: 20C16CFB-E3DO-49D4-9D74-3BFDOAABOE04 ExxonMobil Wellhead Stackup 159.4 1 ` 4-1/16 API 5K (RX -39) _- r 88 7-1/16 AR 1OK (BX -156) _ 1-13/16 API IN (BX -151) 25.0 -- 537 4 4714MI 2.1 mc 2-1/16 API 5K 42.4 21-1/4" API 2K 20" 129.45# 9-5/8" 53.5# 7" 26# 4-1/2. 12.6# date: January 2019 Page 7 1-13/16 API 10K (BX -151) DocuSign Envelope ID: 20C16CFB-E3DO-49D4-9D74-3BFDOAABOE04 ExxonMobil E;S(onMobil PTU-DW1 (Disposal Well) Insulated Conductor 20" x 34" 129.5# X-52 Welded 154' MD / TVD 12-V4" Hole 9-5/8"53 '# L-80 VAM TOP KX 4,952' MD 14,435' TVD 8-1/2" Hole Upper Conflning Zone F t Surface Location. Point Thomson Central Pad. Slot #1 I I 1 lu I IqInjection Zone I 12 I I" I I 7" 26# 1%Cr L-80 TSH 563 8,781' MD / 6,893' TVD NOTE: All depths RKB Rig Nabors 27E RKB-GL 33.42ft GL -MSL 12.7 ft RKB-MSL 46.12 ft Port Collar: 493' MD 1 TVD Permafrost Base: 1,832' MD I TVD KOP: 1,846' MD i TVD Top of Tail: +1- 3.952' MO 13.756' TVD Top of Lead: +1- 4.905' MD 14,405' TVD TD: 4,960' MD 14.440* TVD 1 1 I I I I I 1 1 of =1 �I fl 1 Smell Packer #2: 5,512' MD 14 795' TVD I 5,534' MD I4810'TVD ' 1 1 I Swell Packer #1: 6,051' MD! 5.140' TVD I 6,055' MD /5,142' TVD Top of Tail. +/_ 6,785' MD / 5,608' TVD I [. 75,'Tsn I L __ I 7.110' MD 15,817' TVD I 1 �1 I-miingency Ped Interval I 1 1 I 1 8.515' MD 16,722' TVD Revision date: January 2019 Page 8 TD: 8,800' MD 16,905' TVD DocuSign Envelope ID: 20C16CFB-E3DO-49D4-9D74-3BFDOAABOE04 ExxonMobil Conduct MIT ui ent Re `ui�'e • Hot oil unit and operator • Minimum 1 00f of rated hose • 10bbls of LVT200 base oil (or equivalent) • Contingency spill kits, drip trays and absorbent matting Caution: Do not use diesel for the inner annulus MIT as the aromatics can break down the freeze protection fluid (Isotherm, a gelled base oil formulation) Isotherm insulating packer fluid (IPF) is LVT-200 base oil with an added polymer that is designed to modify the fluid viscosity. The low thermal conductivity of the IPF helps to insulate the wellbore from the surrounding permafrost. 1. Confirm that all necessary equipment and personnel to perform the MIT are available on site. 2. Fill the hot oil unit with 10bbls of base oil, position near the well house and barricade off the work area. Note: • A spark potential permit and gas test are required to locate the hot oil unit and equipment inside 10ft from the wellhouse, refer to the Work Management Manual for additional equipment spacing and SIMOPS restrictions. 3. Verify that pressure transmitters on the wellhead (PST561001-01), inner annulus (PST551001-02) and outer annulus (PST551001-03) are in calibration and functioning correctly. Note: • The transmitters provide continuous data recording back to the CCR and will be used to monitor the MIT 4. Check the status of the DW -1 disposal well. In normal operation treated waste water is continuously injected at low rates and produced water pumped intermittently as the level in the degassing drum rises. Ensure that process conditions are stable prior to commencing the MIT. 5. If injection to the well is shutdown, treated waste water needs to be diverted for discharge to a tundra pond in accordance with the discharge permit and the upper section of the wellbore freeze protected with 40bbls diesel from the produced water system. Note: • Refer to the Operations procedure for the water disposal system for instructions on freeze protecting. 6. Ensure tubing and annulus pressures are well below the high level maximum allowable. 7. Have CCR temporarily defeat the high -high pressure shutdown (PST551001-02) on the inner annulus pressure transmitter. Note: • The required MIT test pressure is above the normal alarm (1200psi) and shutdown (1500psi) set points. Defeating the shutdown will avoid inadvertently shutting in the well during the test. Revision date: January 2019 Page 9 DocuSign Envelope ID: 20C16CFB-E3DO-49D4-9D74-3BFDOAABOE04 ExxonMobil Rig Up Note: Complete the rig up in advance of the inspector arriving on site. 1. Close the two wellhead manual casing valves on the inner annulus. 2. Bleed downstream of the wellhead to verify the casing valves are holding pressure. 3. Connect a rated hose from the inner annulus back to the hot oil unit. Note: • Include a block valve and check valve with bypass in the rig up to isolate the flow as necessary. 4. Position drip trays at all hot oiler tank and line connections, ensure contingency absorbent matting is available. 5. Pressure test from the hot oil unit against the closed manual casing valves to 500psi low 13000psi high for 10 minutes each. Bleed down test pressure. 6. Open the manual casing valves on the inner annulus. 7. Verify with CCR that tubing, inner annulus and outer annulus pressure transmitters are correctly displaying data. 1. Complete a JSA with all crew. 2. Record the pre-test tubing, inner and outer annulus pressures. 3. Commence pumping at the minimum rate and increase the inner annulus pressure to approximately 500psi. Hold this pressure for 5 minutes to confirm integrity. Note: • Record the volumes pumped to and returned from the annulus at the hot oil unit. 4. Slowly increase inner annulus pressure up to 2800psi and shut down the pump. 5. Allow approximately 20-30 seconds for the annulus pressure to stabilize. Note: The high viscosity of Isotherm at low temperatures creates a delayed response to applied pressure; expect a loss of 100-200psi in the first minute after the pump is shut down while the pressure stabilizes. 6. Ensure starting pressure is above 2500psi, block in the annulus line and hold for 30 minutes to perform MITIA. Note: • The pass criteria are a pressure loss of less than 10% (250psi) over the 30 minute test, and less than one- third of the total loss in the last 15 minutes. • Refer to the test criteria section of the procedure for additional information on MIT requirements. 7. Record tubing, inner and outer annulus pressures initially, after 15 minutes and at 30 minutes. 8. If additional time is required to eliminate thermal effects and for the well to stabilize, extend the MIT by an additional 30 minutes and record all pressures after 45 minutes and 60 minutes. 9. Verify that the MITIA has passed all applicable test criteria. 10. Slowly bleed down pressure from the inner annulus back to the hot oil unit. Revision date: January 2019 Page 10 DocuSign Envelope ID: 20C16CFB-E3D049D4-9D74-3BFDOAABOE04 Rig Down 1. Close the two manual casing valves on the inner annulus to isolate from the hot oil unit. 2. Ensure the line is clean of any residual fluid and disconnect the hot oil unit. 3. Verify that all transmitters are functioning correctly and well pressures are normal. 4. Have CCR reinstate the high -high pressure shutdown on the inner annulus. 5. Contact the field SSHE advisor for disposal of oily wastes. Post Job 1. Complete the MIT form and obtain the necessary site personnel signoff. 2. Provide test documentation to engineering for formal submission to EPA (copying AOGCC). Revision date: January 2019 Page 11 DocuSign Envelope ID: 20C16CFB-E3DO-49D4-9D74-3BFDOAABOE04 ExxonMobil United States Environmental Protection Agency Region 10 1200 Sixth Avenue, Suite 900 Seattle, WA 95101 Evan Osborne: 206.553.1747 e-ttlait osbonne.evat(qlepa.gov MECHANICAL INTEGRITY TEST (MIT) FORM Facility I Well Pernrt No. PTD No. P ,,Wbll-Poit'lho>ffionUnit PTDW-1 AK -11015A 214-206 InjectorM1TTnm Fluid Type(s) used to Test Type Test Datc Class 1 I T X IA Std. Annular Pressure Test (SAPT) Req'd Test Fluid Type(s) used to Packer Depth: Test luterval/Corumerfs Presssure(ps) test MD/TVD 2,500 Base Oil 6990/5733 One Year Cycle Record all Wellhead Presse es be rare and during Test Note whether well is on injection or SI during test. If on injection, note injection rate, injection pressure and injection thud temperature Note volume of diesel pmnped in annulus during test. T E 5 T 1 START TIME: _ T i, PRE MIT TURING INNER ANNULUS OUTER ANNULUS _ LOSS RECORDED PRESSURES (PSI) INITIAL 15MIN 30MIN 45MIN _ fiO MIN _ .I RESULT PASS/ FAIL COMMENTS: G A U G E 5 Manufacturer Type Calibration Date -- TUBING INNER ANNULUS_ OUTER ANNULUS OTHER COMMENTS: OTHER COMMENTS: NOTE: Pressure most show stabilizing tendency: Criteria 1) Total loss most be less than I(1%at the end of a 30 minute test 2) Pressure loss in last 15 ntiades trust be less tlum 33% of total loss Extend test duration to 60 minutes, if necessary, to elintirate thermal effects (on-site decision per Inspector). Revision date: January 2019 EPA Rep: AOGCC Rep: Operator Rep 12 114 - 2 (. ExxonMobil Alaska Production tr. Brien lip Post Office Box 196601 SSH&E Manager Anchorage,Alaska 99519 907 564 3617 Telephone 907 564 3719 Facsimile tr, Y 0 12.1 Ekon obi April 20, 2018 RECEIVED ER-2018-OUT-082 5040403 APR 2 4 2018 UIC Manager, Ground Water Protection Unit U.S. Environmental Protection Agency AOGCC 1200 Sixth Avenue, Suite 155, OCE-101 Seattle, Washington 98101 Re: Point Thomson UIC Permit No. AK 11015-A, 1st Quarter 2018 Monitoring Report Dear UIC Manager, In accordance with Condition II(E)(1) of Underground Injection Control (UIC) Permit No. AK 11015-A, ExxonMobil Alaska Production, Inc. hereby submits the quarterly report for 1Q2018. The permit required information are addressed below: a. Monthly average, maximum, and minimum values for injection pressure, rate, and volume: See Attachment A. b. Graphical plots of continuous injection pressure and rate monitoring: See Attachment B. c. Daily monitoring data in an electronic format: See Attachment C. d. Physical, chemical, and other relevant characteristics of the injected fluid: See Attachment D. e. Any well workover or other significant maintenance of downhole or injection related surface components: No well workover or other significant maintenance was conducted during this reporting period. f. Results of all mechanical integrity tests performed since the previous report including any maintenance-related tests and any"practice" tests: Annual Standard Annulus Pressure Test/ Inner Annulus Mechanical Integrity Test (SAPT/MITIA) as required under Permit AK11015-A Part Il.C.3(b)(1), bi-annual Reservoir Saturation Tool (RST) fluid movement test as required under Part II.C.3(b)(2), and the bi-annual Internal Tubing Inspection as required by Part II.C.3(b)(3) were performed on March 26-30, 2018 with an EPA representative present to witness the tests. Results were submitted to your office on April 20, 2018 (Reference ER-2018- OUT-088). g. Any other tests required by the Director: No test requests were received from the Director. Due to corporate policies on CD read/write access for employees, we were unable to provide daily monitoring data on a CD or flash drive, as was historically done. As agreed with your office on July 26, 2016 over the phone, submittal of the electronic daily monitoring data will be provided by email • • correspondence from Sofia (Sonia) Laughland (sofia.m.laughland@exxonmobil.com) to Evan Osborne (osborne.evan@epa.gov) in April 2018. We appreciate your flexibility and we hope that there will be a long term alternative for future electronic data submittal. If you have any questions, please contact Sofia (Sonia) Laughland at (907) 564-3604 or via email (sofia.m.laughland@exxonmobil.com). 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. Sincerely, For and On Behalf of ExxonMobil Alaska Production Inc. BER:sml:lo cc: Timothy Mayers (EPA) Evan Osborne (EPA) Chris Wallace (AOGCC) -Attachment A only Attachments: Attachment A—4Q EPA Form 7520-8 Attachment B —Graphical plots of continuous injection pressure and rate monitoring Attachment C — Daily monitoring data in an electronic format (emailed) Attachment D —Point Thomson Waste Streams • 1110 Attachment A — EPA Form 7520-8 4,,,,,,, 0 •ERUS Environmental Protection Agency Form 7520-8 Database Template STEP 1.Copy this template in macro-enabled xlsm version using"Save As". Include Well name,Yr and Qtr with current file r STEP 2. Fill in the highlighted cells with relevant information. Do not enter n/a in any cell. Fields(*)are mandatory. STEP 3.Enable macro.Press<Ctrl><Shift><A>to run the macro and check data in Dbtable worksheet.Save file and submit. mportant: Please do not change the position of any cell ~ low.Do not copy/paste cells or inse-` '-lelete row or column. OPERATOR NAME* WELL'S YEAR* PERMIT' Point Thomson Unit PT DW-1 2018 AK-11015-A REPORTING MONTH JAN FEB MAR INJ PRESSURE (MIN), PSI 676 908 0 INJ PRESSURE(AVG), PSI 1110 1385 1301 INJ PRESSURE (MAX), PSI 1732 3786 1770 INJ RATE(MIN),GPM 0 3 0 INJ RATE (AVG),GPM 7 8 6 INJ RATE (MAX),GPM 24 24 24 ANNULAR PRESSURE (MIN), PSI 14 1 21 ANNULAR PRESSURE(AVG), PSI 117 303 277 ANNULAR PRESSURE(MAX), PSI 501 7866 2754 TOTAL INJ VOL(MONTH),GAL 272,349 304,952 273,090 ANNUAL INJ VOL(CUM),GAL 272,349 577,300 850,390 TEMPERATURE(MIN),°F 62 77 51 TEMPERATURE(AVG),°F 82 91 91 TEMPERATURE(MAX),°F 99 106 104 pH (MIN) pH (AVG) pH (MAX) SUBMITTED ON: 4/20/2018 (mm/dd/yyyy) Note: pH not required for Class I well injected fluids when E&P exempt water injected ! ! � taw ` Pm 0(4 0%n Regg, James B (DOA) From: Brooks, Phoebe L(DOA) Sent: Wednesday, March 28, 2018 12:43 PM r To: Scarlett, Kenley C1 3(Z te6 Cc: Regg, James B (DOA) '7 l Subject: RE: 10-426 Form (PTD 214-206) DW-1 Attachments: MIT PTU DW-1 03-26-18 Revised.xlsx Kenley, Attached is a revised report changing the packer TVD to 5757' and the formatting on the PTD#to reflect 2142060. Please update your copy or let me know if you disagree. Thank you, Phoebe Phoebe Brooks Statistical Technician II Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 Fax: 907-276-7542 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: Scarlett, Kenley<kenley.scarlett1@exxonmobil.com> Sent:Tuesday, March 27, 2018 5:32 PM To: Regg,James B (DOA)<jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay<doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L(DOA) <phoebe.brooks@alaska.gov>; Wallace, Chris D (DOA)<chris.wallace@alaska.gov> Cc: Motteram, Luke A<luke.a.motteram@exxonmobil.com>; EM Alaska Correspondence/SM <emalaskacorrespondence@exxonmobil.com> Subject: 10-426 Form (PTD 214-206) DW-1 Hi All, Attached is the 10-426 Mechanical Integrity Test (MIT) form for the MIT performed on the disposal well at Point Thomson.The well is DW-1 and the PTD number is 214-206. Thank you, Kenley Scarlett Site Engineer ExxonMobil Alaska Production 3700 Centerpoint Drive, Suite 600 PT Office: (907) 685-3676 Skype: (907) 564-3606 1 • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: jim.reaaDalaska.aov AOGCC.Inspectors®alaska,aov phoebe,brooksabalaska.aov chris.wallacetRalaska.aov OPERATOR: ExxonMobil Alaska Production Inc. �� 3�2S 1 FIELD I UNIT/PAD: Point Thomson J ` 1 t79 DATE: 03/26/18 • OPERATOR REP: Kenley Scarlett AOGCC REP: Well DW-1 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min, PTD 2142060 Type In) W Tubing 977 ' 995 ' 990 - 988 - Type Test P Packer TVD 5757 - BBL Pump 1.9 - IA 272 ` 2765- 2633 ' 2599 Interval 0 ✓ Test psi 2500 -BBL Return 1.5 ' OA 0 0 0 0 Result P Well Status:On injection at approximately 4.6 gpm at 67.67 Notes: Interval:Annually per permit AK-11015-A r EPA witnessed test for class 1 disposal well OW-1.Waived by Matt Herrera • 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 Ntes: 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 OAResult 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 Retum 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 In) Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result . tes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTO Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Noes: 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 PTU DW-1 03-26-18 Revised • 2 (0 ExxonMobil Production Company Brien E.Reep Post Office Box 196601 SSH&E Manager Anchorage,Alaska 99519 907 564 3617 Telephone 907 564 3719 Facsimile APR 27 20,E EkonMobil swopOctober 30, 2017 RECEIVED ER-2017-OUT-309 NOV 0 1 2017 UIC Manager, Ground Water Protection Unit AOGCC U.S. Environmental Protection Agency, OCE-127 A®GCC 1200 Sixth Avenue, Suite 900 Seattle, Washington 98101 Re: Annual Injection Data for DW-1 for 2017 Fiscal Year(AK11015-A) Dear UIC Manager, ExxonMobil Alaska Production, Inc. hereby submits the 2017 fiscal year annual injection data for the Point Thomson Unit Disposal Well (DW-1) operated under Permit No. AK 11015-A. Please note that annual cumulative volumes are calculated based on annual calendar year per USEPA guidance. If you have any questions, please contact Sofia (Sonia) Laughland at (907) 564-3604 or via email (sofia.m.laughland@exxonmobil.com). 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. Sincerely, BER/sl/lo For and On Behalf of ExxonMobil Alask- -roduction Inc. cc: Timothy Mayers (EPA) Evan Osborne (EPA) Chris Wallace (AOGCC) Attachments: Annual 2017 Injection Data Report A Division of Exxon Mobil Corporation • • f a 2 f a 2 2 a f v'u z a 2 a 0 z Q N Q to iN N 10 I/i m O O °... m O r., DI m N Nt O e m N O N N N m in O lD m ri N ry IO CO0C N N N tel R N ut O to r- 0 Ur a N m In N in Q• O ti in 0 mO m m Omf N 110 NM 011 N N N T N RI TT m S Q m iO O N O C N < N 00 O, ot "' 00 0 N riot H N N T0 ID h IN 0 O co aNp 0 V1 N N t.11 A O m co0CO ON O000 N .�--ii m m LO e ID N. W ID 2 0 n O O m ti W ten rn 011 N 00 0 N N . en O • m 92 A 00 Q W m mn. ttbb 0 '~ m 0 OY N "0 Ci el N m 0 0 N 11 CO 0 m 01 tO N N N I10 w .-, N N O1 ID IL ON N N N N N IO N N W N a 0 a 0 m 0 V1 ‘3. b'CO Qi 1.4 03 N in 01 01 RI Q .1 l el N O 10 m O m O ..n an iri 0 N N Q .O In N m A r1 pppp 1- O W ID N O A A Q m r 0a N on 0 W ._+ O O\ eat ONO m N Ot N m N O. Q n A A .-i ai 0! cn C ` O n m h N in m o m Ili eel C 1 n CC1 a C u1 N 2 m a1 " N eV- `G -mv E E ; t pp N01 N a In 03 IMOIpV toN m O a.0 MOD O. e+' 0 W •'I C u t v yN {Nn = 1 1 Q J f zztn 0- 0. z > ._ z 3 Q > • •W W O u c a G z D W W W O r. p p t0tJ• ¢ w ¢ 2 4 2 Ln N IIn -0 p cr . 2 a 2 u H t W W W W W W O _ I- 1- _ _ _ 4 � ~ In Ln iN/I ILI LA, Q~ ~ a d W > z < K ya O. C O. 2L W C O f E l f C' �_ K ¢ z oc 2 a d 0. CO a O 0. d 6ce 2 2 2 Z � 2 O » Q z W W to e Z z z I- z I" 1- F- c aaa1- a 0 c T,. u 0 z J q-loco • • ExxonMobil Production Company Brien E.Reep Post Office Box 196601 SSH&E Manager Anchorage,Alaska 99519 907 564 3617 Telephone 907 564 3719 Facsimile E7konMobil October 30, 2017 RECEIVED ER-2017-OUT-306 UIC Manager, Ground Water Protection Unit NOV 0 1 2017 U.S. Environmental Protection Agency, OCE-127 A�GvC 1200 Sixth Avenue, Suite 900 Seattle,Washington 98101 Re: Point Thomson UIC Permit No. AK 11015-A, 3"d Quarter 2017 Monitoring Report Dear UIC Manager, In accordance with Condition II(E)(1) of Underground Injection Control (UIC) Permit No. AK 11015-A, ExxonMobil Alaska Production, Inc. hereby submits the quarterly report for 3Q2017. The permit required information are addressed below: a. Monthly average, maximum, and minimum values for injection pressure, rate, and volume: See Attachment A. b. Graphical plots of continuous injection pressure and rate monitoring: See Attachment B. c. Daily monitoring data in an electronic format: See Attachment C. d. Physical, chemical, and other relevant characteristics of the injected fluid: See Attachment D. e. Any well workover or other significant maintenance of downhole or injection related surface components: No well workover or other significant maintenance was conducted during this reporting period. f. Results of all mechanical integrity tests performed since the previous report including any maintenance-related tests and any"practice"tests: Annual Standard Annulus Pressure Test/Inner Annulus Mechanical Integrity Test(SAPT/MITIA) as required under Permit AK11015-A Part II.C.3(b)was performed on August 17, 2017 with an EPA representative present to witness the test. Results were submitted to your office on September 8, 2017 (Reference ER-2017-OUT-256). g. Any other tests required by the Director: No test requests were received from the Director. Due to corporate policies on CD read/write access for employees, we were unable to provide daily monitoring data on a CD or flash drive, as was historically done. As agreed with your office on July 26, 2016 over the phone, submittal of the electronic daily monitoring data will be A Division of Exxon Mobil Corporation • • provided by email correspondence from Sofia (Sonia) Laughland (sofia.m.laughland@exxonmobil.com) to Evan Osborne (osbome.evan@epa.gov) on October 31, 2017. Additionally, a corrected 2Q2017 EPA Form 7520-8 A is attached for your reference. A mathematical error has been corrected for annual cumulative injection volume values. We appreciate your flexibility and we hope that there wiii be a song term alternative for future electronic data submittal. If you have any questions, please contact Sofia (Sonia) Laughland at (907) or via email (sofia.m.laughland@exxonmobil.com). 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. Sincerely, JP" / BER:sml:lo For and On Behalf of ExxonMobil Alaska Production Inc. cc: Timothy Mayers (EPA) Evan Osborne (EPA) Chris Wallace (AOGCC), without Attachments B, C, D Attachments: Attachment A—3Q EPA Form 7520-8 Attachment B—3Q Graphical plots of continuous injection pressure and rate monitoring Attachment C—3Q Daily monitoring data in an electronic format (emailed) Attachment D—3Q Point Thomson Waste Streams Attachment E—corrected 2Q EPA Form 7520-8 • • a; E m c w C • a c 1 I 1 - C 3 E N N as • h 3 NO N a t. C u A tO 1D C to i 111 O N nnu E V a1 fA Y a Q c co d a in 7:- ar \ . YkA Y• t llb O N en tri 4rl en M 1n � 1..1 CO Z . NO Q O e-1 M O tD M O m N 1O 00 13 01 E C CU c h E v aJ '. _ V 00 Ia 01 Q a u R is a C c E c Yc MOCU .47 in 1..) p tO roU al LA VI c 0 > a+ V C .j M cY M Q1 O 1' 0. to to 0r Q H c 12 0 p W D ? O NtIrl O d' esi N 0�0 1p a0 M co c 45 Q 3 a. oo a E N tu a o -,-Li 021 C o•_ m y c .= E E E ._+ u — C s IL LL CU 0 > C C cVI N i to 'p X C 4 ..r p .ri 16 A c a C) w Q a, c r £ tn 0.v1 N lit _ l7 o 0 0 .E d t' H ar ..• = a a a 2 2 2 Z u3n ++ ED zzl � � 02a2z � Z > < E ,I. a Q c O > - ^ ` w w w O u 2 Q 2 0 – u V c Z p Sa 2 `= 2 Z l9 X oC oC w w w Z C7 0 N c V Ip. 1u cs_O CC CC ct CC z CC CC a a Z a s wa ° E m .. p a ' a a a a -, g g Q E II a..CU L Y 4! Q a.'"' tr Z Z z Z Z Z = d Z w W W 7 co • s Ecc Z Z^ Z E•- Z h- I— F- Q a C a O 0 _ C i.' C U ii w c C ca a. <4 !V N1 t W W W C- . H Y~9 LA £ Z Z14 - Z(.0 • • ExxonMobil Production Company Brien E.Reap Post Office Box 196601 SSH&E Manager Anchorage,Alaska 99519 907 564 3617 Telephone 907 564 3719 Facsimile EonMobil scow - September 8, 8ecEiveo , ER-2017-OUT-256 SEP I 4217 UIC Manager, Ground Water Protection Unit AOGGC U.S. Environmental Protection Agency, OCE-127 1200 Sixth Avenue, Suite 900 Seattle, Washington 98101 Re: Point Thomson UIC Permit No. AK 11015-A, Mechanical Integrity Test Submittal Dear UIC Manager, In accordance with Condition II.C.3.(b)of Underground Injection Control (UIC) Permit No. AK 11015-A, ExoconMobil Alaska Production, Inc. hereby submits the report for mechanical integrity testing conducted at the Point Thomson Unit Disposal Well (PTU-DW1) on August 17-18, 2017 on the North Slope of Alaska. An Environmental Protection Agency representative, Justin Selitsch, was on site to witness the mechanical tests. The following mechanical integrity test was conducted: • The Annual Standard Annulus Pressure Test/Inner Annulus Mechanical Integrity Test(SAPT/MITIA) required by Part ILC.3.(b)(1). Pressure data met the permit criteria. in accordance with Condition II.C.3.(c)(2) of Underground Injection Control (UIC) Permit No. AK 11015-A, the following report is enclosed for Annual Standard Annulus Pressure Test/ Inner Annulus Mechanical Integrity Test • Notice of Inspection (1) • MIT Report and Summary Graph (2) Additionally, practice MIT tests were conducted on August 15, 2017 and the corresponding MIT report is attached for your records. A Division of Exxon Mobil Corporation • • If you have any questions, please contact Sofia (Sonia) Laughland at 907-5643604 or via email at (sofia.m.laughland@exxonmobil.com). 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. Sincerely, For and On Behalf of ExxonMobil Production Alaska Inc. BER:sml:lo cc: Timothy Mayers (EPA, Anchorage Office), without enclosures Evan Osborne (EPA, Seattle Office), without enclosures Chris Wallace (AOGCC), without enclosures Enclosed: Notice of Inspection (1) MIT Report and Summary Graph (2) Practice MIT Report (2) ze LI Z( ExxonMobil Production Company Brien E.Reep RECEIVED Post Office Box 196601 SSH&E Manager Anchorage,Alaska 99519-0267 JUL 1 0 2017 907 564 3617 Telephone 907 564 3719 Facsimile AOGCC 3CC E4(onMobil July 6, 2017 ER-2017-OUT-172 Mr. Evan Osborne U.S. Environmental Protection Agency, Region X 1200 Sixth Avenue, Suite 900, OCE-082 Seattle, Washington 98101 Re: ExxonMobil Point Thomson MIT Test UIC Class I Disposal Well Permit AK11015-A Dear Mr. Osborne, ExxonMobil hereby provides a 30 day notification of our intent to conduct the annual mechanical integrity test for the PTU-DW1 on or around August 16, 2017 pursuant to requirements within Part II C.3.c.(3) of the UIC Permit. If you have any questions or comments please contact Sofia (Sonia) Laughland at (907) 564- 3604 or via email at sofia.m.laughlandCayexxonmobil.com. Sincerely, - fe.... /. BER:sml:lo For and on behalf of ExxonMobil Alaska Production Inc. cc: Chris Wallace (AOGCC) Attachment: ExxonMobil Point Thomson UIC Class I Disposal Well Mechanical Integrity Test Procedure A Division of Exxon Mobil Corporation POINT THOMSON a � [ E:, «lithp s OPERATIONS ExxonMobil Alaska Production Inc. Point Thomson Disposal Well (PTU-DW1) • Mechanical Integrity Test(MIT) Procedure Prepared: Production Engineer /L��- Date: b /6 ((-4 L. Motteram Reviewed: EBUR Advisor ,.. .•. aaO ti r Date: /r3/ • S. ='ghlandJ Endorsed: J Operations Technical Manager -_ Date: ftA v t ' / J. Long Approved: Sr. Field Superintendent _ _ Date: 'N 7 D.Crooks /, Revision date:June 2017 ExxonMobil This page intentionally blank Revision date:June 2017 Page 2 ExxonMobil TABLE OF CONTENTS INTRODUCTION 4 Program Scope 4 Regulatory Notifications 4 Data Requirements 4 MIT Preparation 4 Test Criteria 5 Reporting 5 WELL INFORMATION 6 General Well Data 6 Tubing & Casing Information 6 Alarms & Shutdowns 6 Wellhead Stackup 7 Wellbore Sketch 8 CONDUCT MIT 9 Equipment Required 9 Preliminary 9 Rig Up 10 Pressure Test IA 10 Rig Down 11 Post Job 11 APPENDIX 12 EPA MIT Form 12 Revision date:June 2017 Page 3 • ExxonMobil INTRODUCTION Program Scope This program outlines the procedure for conducting a standard annulus pressure test/inner annulus mechanical integrity test(SAPT/MITIA).The SAPT/MITIA will be required annually if DW-1 well is active. Re•ulatoryNotifications Notify EPA at least 30 days in advance of conducting the MIT so that a representative can be present to witness the test. Courtesy notification to AOGCC at least a week in advance is necessaryto allow coordination of travel to Point Thomson to witness the test. Formal notice via the AOGCC online form is required at least 48 hours in advance of the test. Data,Requirements', .f The following information must be available at the location for review: • Valid approved waivers, if any,relating to the integrity of the tested well. • Current well schematic. • Graph of tubing,inner annulus,and outer annulus pressures for the preceding 90 days. MIT Preparation , , The following guidance is provided with respect to MIT testing: • Document any activity involving pumping into and bleeding pressure from the annuli within 24 hours of the MIT. • The well's annulus should be fluid packed before the Inspector arrives. • 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. • Calibrated pressure gauges or digital transmitters with suitable range and accuracy must be installed on the tubing, inner annulus and outer annuli. • Suitable flow measurement equipment should be available to determine the volume of fluids pumped into and returned from the tested space. • Other equipment(e.g.tanks,lines, bleed trailers,etc.)necessary for the safe pressure testing and suitable for the operating environment should be rigged up prior to Inspector arrival at the location. Revision date:June 2017 Page 4 ExxonMobil Test Criteria Relevant MIT requirements under EPA permit AK11015-A are outlined below: • Test pressure for SAPT/MITIA will be at least 2500psi over 30 minutes. • Criteria for a passing MIT: o Pressure may not decline more than 10%during the 30 min test period, and show a stabilizing tendency o Pressure loss in the last 15 mins of the test must be less than one third of its total loss • If the total loss exceeds 10% of if the loss during the second 15 minute period is equal or greater than half the loss during the first 15 minutes,the test may be extended for an additional 30 minutes to demonstrate stabilization (resulting from thermal effects). 7 ; zfvm.a .etit�rl�w..,..+'w` k .2K ia�3wuu z:a. Agency reporting will be coordinated by the engineering and SSHE team in Anchorage. Report the results of the MIT to EPA on the provided form within 45 days. Copy AOGCC on the report submission. Also include the MIT results in the next quarterly report to the EPA Director, including any maintenance-related tests and any'practice'tests. For AOGCC complete MIT Form 10-426, noting the test was witnessed by EPA, and submit electronically no later than the 5th calendar day of the month following the test. Revision date:June 2017 Page 5 ExxonMobil WELL INFORMATION General Well Data '• Well Name: PTU-DW1 Well Type: Service-Disposal UIC Permit: AK11015-A Field/Location: Point Thomson, North Slope AK—Central Pad Slot 1 Surface Location: Lat: N 70°10'23.30436"Long:W 146° 15'20.05740" Total Depth: 8,800'MD/6,905'TVD Base Permafrost: 1,832'MD/1,832'TVD Packer Depth: 7,018'MD/5,757'TVD Reference Elevation: 33.4'RKB-GL(46.1'RKB-MSL) Wellbore Profile: Build to 50 degrees and hold Last Annulus MIT: 8/16/2016—IA tested to 2500psi (passed) Tubing':& Casing Information 4-1/2 12.6 1Cr-L80 7,100 Vam Top 8,430 7,500 288 288 7 26 1Cr-L80 8,781 TSH 563 7,240 5,410 604 604 9-5/8 53.5 L80 4,952 Vam Top KX 7,930 6,620 1,244 1,244 34 x 20 129.5 X-52 154 PE Weld N/A N/A 1,978 N/A Alarms & Shutdowns High 2600psi Maximum expected surface pressure during normal injection operations (based on well modelling and step rate test results) Wellhead Injection Pressure (PST551001-01) High-High 5000psi Wellhead working pressure rating and UIC permit Omit Shut Down 5000psi High 1200psi 80%of UIC permit limit Tubing x Production Casing (Inner)Annulus Pressure High-High 1500psi (PST551001-02) UIC permit Omit Shut Down 1500psi High 200psi Recommended surface annulus trigger pressure Production Casing x Surface Casing (Outer)Annulus Pressure High-High 450psi (PST551001-03) Calculated formation integrity Shut Down 450psi (based on drilling FIT and annulus fluid weight) Revision date:June 2017 Page 6 • ExxonMobil Wellhead Stackup I 53.7 MiMi (...04.1.11t r I� � IIU-1-7- ' N , " s1.2 Ufa i1 4.1,N (ktior A - 1 159,4 4-1/16 APt 5K (RX-39 1111Nasiiiill .--- •`4 ,N 8.8 7-1/16 API 10K (BK-158) ill r I 1 1-13/16 API 10K (ax-151) ,. ": sr 1 13/t6 API 10K (BX 151) .11 -_� III._: _ 11.•__!_ . _-_ 25.0 `,,}1111�� 'II`��r- '.I Al 1IN,-,--,. ,�11J11•, ,s., 47.4 uM1M!<e • 4'4_ -1 N _..._..__ -. 1 .47 11 APi SK (RX-54) I ) rt/•"•1 V i J_ 1 TYP ��' u _ 1 I,k i �� I ' 1 �:' 3 /,. 1,' 2 1/16 AP 5K (Rx-24) 1P 2-1/16 AP 5K(RX-24) • IJ7.,_:,...) Ape I 1 �` '~1,`Lt�I ; 42.4 �� V ��!/ 3 A: Il i ,....._ 43.7 ....; 43 7 A..' N'- ■ iy, 't \\: 3 1i ',.:. 21-1/4" API 2K Mii Mil III' 20" 129.45# CASING um U _ 9-5/8" 53.5# CAS/NG 7" 26# CASING 4 1/2" 12.6# TUBING• _ Revision date:June 2017 Page 7 ExxonMobil Wellbore Sketch EonMobi! Surface Location Rig Nabors 27E Pont Thomson RKB-GL 33 42 ft PTU-DWI (Disposal Well) Central Pad.Slot#1 GL-MSL 12 7 e Insulated Conductor 11: RKB MSL 46 12 R 20"x 34"129.5#X-52 Welded 154'MD/TVD Port Collar:493'MD.'ND Permafrost Base:1,832'MD/ND KOP 1.846'MD ND 12-1'4"Hole Top of TAIL:+l-3.852'MD 3,756 ND fig} 9-5'8"53 50 L-80 VAM TOP KX Top of Lead:+1.4,905'MD/4.405'TVD 4,952'MD/4,435'ND TD:4,960'MD1 4,440'ND a. 8-1/2"Hole Swell Packer#2 5.512'MD 4,795'ND 5,534'MD!4,810'TVD Upper Confining Zone Swell Pecker#1 6,051'MD/5,140'ND 8,055'MD/5,142°ND Top of Tel:+1-6,785'MD/5,608'ND 4.1.7"126#1°oCr L-80 VAM TOP injection Packer.7,018'MD 5,757 ND 7,100'MD!5,810'ND 7,110'MD!5,817'ND Injection Zone :ontingency Pert Interval _ 8,515'MD/6,722'ND Pert Interval:8,516'-8,536'MD!6,722'-6,735'ND 7"26#1%Cr L-80 TSH 563 8,781'MD 16,893'ND TD:8,800'MD l 6,905'ND NOTE:All depths RKB Revision date:June 2017 Page 8 • S ExxonMobil Conduct MIT Equipment Required • Hot oil unit and operator • Minimum 100ft of rated hose • 10bbls of LVT200 base oil(or equivalent) • Contingency spill kits,drip trays and absorbent matting Caution: Do not use diesel for the inner annulus MIT as the aromatics can break down the freeze protection fluid (Isotherm,a gelled base oil formulation) Isotherm insulating packer fluid(IPF)is LVT-200 base oil with an added polymer that is designed to modify the fluid viscosity.The low thermal conductivity of the IPF helps to insulate the wellbore from the surrounding permafrost. Preliminary 1. Confirm that all necessary equipment and personnel to perform the MIT are available on site. 2. Fill the hot oil unit with 10bbls of base oil, position near the well house and barricade off the work area. Note: • A spark potential permit and gas test are required to locate the hot oil unit inside 85ft from the wellhead, refer to the Work Management Manual for additional equipment spacing and SIMOPS restrictions. 3. Verify that pressure transmitters on the wellhead (PST561001-01), inner annulus (PST551001-02) and outer annulus(PST551001-03)are in calibration and functioning correctly. Note: • The transmitters provide continuous data recording back to the CCR and will be used to monitor the MIT. 4. Check the status of the DW-1 disposal well. In normal operation treated waste water is continuously injected at low rates and produced water pumped intermittently as the level in the degassing drum rises. Ensure that process conditions are stable prior to commencing the MIT. 5. If injection to the well is shutdown, treated waste water needs to be diverted for discharge to a tundra pond in accordance with the discharge permit and the upper section of the wellbore freeze protected with 40bbls diesel from the produced water system. Note: • Refer to the Operations procedure for the water disposal system for instructions on freeze protecting. 6. Ensure tubing and annulus pressures are well below the high level maximum allowable. 7. Have CCR temporarily defeat the high-high pressure shutdown on the inner annulus pressure transmitter. Note: • The required MIT test pressure is above the normal alarm(1200psi) and shutdown (1500psi) set points. Defeating the shutdown will avoid inadvertently shutting in the well during the test. Revision date:June 2017 Page 9 • • ExxonMobil Rig Up Note: Complete the rig up in advance of the inspector arriving on site. 1. Close the two wellhead manual casing valves on the inner annulus. 2. Bleed downstream of the wellhead to verify the casing valves are holding pressure. 3. Connect a rated hose from the inner annulus back to the hot oil unit. Note: • Include a block valve and check valve with bypass in the rig up to isolate the flow as necessary. 4. Position drip trays at all hot oiler tank and line connections,ensure contingency absorbent matting Is available. 5. Pressure test from the hot oil unit against the closed manual casing valves to 500psi low 13000psi high for 10 minutes each.Bleed down test pressure. 6. Open the manual casing valves on the inner annulus. 7. Verify with CCR that tubing, inner annulus and outer annulus pressure transmitters are correctly displaying data. Pressure Test IA 1. Complete a JSA with all crew. 2. Record the pre-test tubing, inner and outer annulus pressures. 3. Commence pumping at the minimum rate and increase the inner annulus pressure to approximately 500psi. Hold this pressure for 5 minutes to confirm integrity. Note: • Record the volumes pumped to and returned from the annulus at the hot oil unit. 4. Slowly increase inner annulus pressure up to 2800psi and shut down the pump. 5. Allow 1 minute for the annulus pressure to stabilize. Note: • The high viscosity of Isotherm at low temperatures creates a delayed response to applied pressure; expect a loss of 100-200psi in the first minute after the pump is shut down while the pressure stabilizes. 6. Ensure starting pressure is above 2500psl,block in the annulus line and hold for 30 minutes to perform MITIA. Note: • The pass criteria are a pressure loss of less than 10% (250ps0 over the 30 minute test, and less than one-third of the total loss in the last 15 minutes. • Refer to the test criteria section of the procedure for additional information on MIT requirements. 7. Record tubing, inner and outer annulus pressures initially,after 15 minutes and at 30 minutes. 8. If additional time is required to eliminate thermal effects and for the well to stabilize, extend the MIT by an additional 30 minutes and record all pressures after 45 minutes and 60 minutes. 9. Verify that the MITIA has passed all applicable test criteria. 10. Slowly bleed down pressure from the inner annulus back to the hot oil unit. Revision date:June 2017 Page 10 • • ExxonMobil Rig Down 1. Close the two manual casing valves on the inner annulus to isolate from the hot oil unit. 2. Ensure the line is clean of any residual fluid and disconnect the hot oil unit. 3. Verify that all transmitters are functioning correctly and well pressures are normal. 4. Have CCR reinstate the high-high pressure shutdown on the inner annulus. 5. Contact the field SSHE advisor for disposal of oily wastes. Post Job m >' 1. Complete the MIT form and obtain the necessary site personnel signoff. 2. Provide test documentation to engineering for formal submission to EPA(copying AOGCC). Revision date:June 2017 Page 11 1110 ExxonMobil Appendix EPA MIT Form D1144,4 " United States Environmental Protection Agency •��r� Region 10 1200 Sixth Avenue,Suite 900 Seattle,WA 98101 Evan Osborne:206.553.1747 e-mail:osbome.evan@epa.gov MECHANICAL INTEGRITY TEST(MIT)FORM Facility Well I Permit No. PTD No. ExxonMobil-Point Thomson Unit PT DW-1 AK-11015A 214-206 Injector MIT Type Test Type Test Date Class 1 T X IA Std.Annular Pressure Test(SAPT) Req'd Test Fluid Type(s)used to Packer Depth: Test Interyal/Comments Presssure(psi) test MD/TVD 2,500 Base Oil 6990/5733 One Year Cycle Record all Wellhead Pressures before and during Test.Note whether well is on injection or SI during test. If on injection,note injection rate,injection pressure and injection fluid temperature Note volume of diesel pumped in annulus during test. T START TIME: _ RECORDED PRESSURES(PSI) RESULT E PRE MIT INITIAL 15 MIN 30 MIN 45 MIN 60 MIN S TUBING PASS/ T INNER ANNULUS FAIL OUTER ANNULUS 1 LOSS COMMENTS: G Manufacturer Type Calibration Date A U TUBING G INNER ANNULUS E OUTER ANNULUS S OTHER COMMENTS: OTHER COMMENTS: NOTE:Pressure must show stabilizing tendency: Criteria 1)Total loss must be less than 10%at the end of a 30 minute test 2)Pressure loss in last 15 minutes must be less than 33%of total loss Extend test duration to 60 minutes,if necessary,to eliminate thermal effects(on-site decision per Inspector). EPA Rep: AOGCC Rep: Operator Rep Revision date:June 2017 Page 12 • • ExxonMobil Production Company Brien E. Reep Post Office Box 196601 SSH&E Manager Anchorage,Alaska 99519 907 564 3617 Telephone 907 564 3719 Facsimile ©0 PY E onMobil January 11, 2017 RECEIVED ER-2017-OUT-003 •r G JAN 18 2017 UIC Manager, Ground Water Protection Unit U.S. Environmental Protection Agency, OCE-127 OG CC 1200 Sixth Avenue, Suite 900 Seattle, Washington 98101 Re: Point Thomson UIC Permit No. AK 11015-A, 4th Quarter 2016 Monitoring Report Dear UIC Manager, In accordance with Condition II(E)(1) of Underground Injection Control (UIC) Permit No. AK 11015-A, ExxonMobil Alaska Production, Inc. hereby submits the quarterly report for 4Q2016. The permit required information are addressed below: a. Monthly average, maximum, and minimum values for injection pressure, rate, and volume: See Attachment A. b. Graphical plots of continuous injection pressure and rate monitoring: See Attachment B. c. Daily monitoring data in an electronic format: See Attachment C. d. Physical, chemical, and other relevant characteristics of the injected fluid: See Attachment D. e. Any well workover or other significant maintenance of downhole or injection related surface components: No well workover or other significant maintenance was conducted during this reporting period. f. Results of all mechanical integrity tests performed since the previous report including any maintenance-related tests and any "practice" tests: No Mechanical Integrity Tests performed during this reporting period. g. Any other tests required by the Director: No test requests were received from the Director. Due to corporate policies on CD read/write access for employees, we were unable to provide daily monitoring data on a CD or flash drive, as was historically done. As agreed with your office on July 26, 2016 over the phone, submittal of the electronic daily monitoring data will be provided by email correspondence from Mai Le Vigil (mai.le.vigil@exxonmobil.com) to Evan Osborne (osborne.evan@epa.gov) on January 11, 2017. A Division of Exxon Mobil Corporation i S We appreciate your flexibility and we hope that there will be a long term alternative for future electronic data submittal. If you have any questions, please contact Mai Le Vigil at (907) 564- 3608 or via email (mai.le.vigil@exxonmobil.com). 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. Sincerely, For and On Behalf of ExxonMobi Alaska Production Inc. BER:mlv:lo cc: Timothy Mayers (EPA) Evan Osborne (EPA) Chris Wallace (AOGCC) Attachments: Attachment A— EPA Form 7520-8 Attachment B — Graphical plots of continuous injection pressure and rate monitoring Attachment C — Daily monitoring data in an electronic format (emailed) Attachment D— Point Thomson Waste Streams Attachment A — EPA Form 7520-8 • 11. elk US Environmental Protection Agency Form 7520-8 Database Template STEP 1.Copy this template in macro-enabled xlsm version using"Save As".Include Well name,Yr and Qtr with current file name. STEP 2.Fill in the highlighted cells with relevant information. Do not enter n/a in any cell.Fields(*)are mandatory. STEP 3.Enable macro.Press<Ctri><Shift><A>to run the macro and check data in Dbtable worksheet.Save file and submit. Important:Please do not change the position of any cell below.Do not copy/ aste cells or insert/delete row or column. OPERATOR NAME* WELL* YEAR* PERMIT* Paint Thomson Unit PT DW-1 2016 AK-11015-A REPORTING MONTH OCT NOV DEC INJ PRESSURE(MIN),PSI 635 373 966 INJ PRESSURE(AVG),PSI 1043 989 1447 INJ PRESSURE(MAX),PSI 1578 1747 1827 INJ RATE(MIN),GPM 2 2 0 INJ RATE(AVG),GPM 6 5 7 INJ RATE(MAX),GPM 36 36 37 ANNULAR PRESSURE(MIN),PSI 0 0 4 ANNULAR PRESSURE(AVG),PSI 6 9 236 ANNULAR PRESSURE(MAX),PSI 140 150 973 TOTAL INJ VOL(MONTH),GAL 160,888 161,444 285,716 ANNUAL INJ VOL(CUM),GAL 1,863,975 2,025,419 2,311,135 TEMPERATURE(MIN),°F 67 47 58 TEMPERATURE(AVG),°F 87 79 88 TEMPERATURE(MAX),°F 101 98 108 pH(MIN) pH(AVG) pH(MAX) SUBMITTED ON:' 1/11/2017 (mm/dd/yyyy) Note:pH not required for Class I well injected fluids when E&P exempt water injected • • Attachment B - Graphical Plots of Continuous Injection Pressure and Rate Monitoring . • • _____ _ _______ _ _______ S (utd2)a;ed uop3alul p N d d m nl N N N g m o ! I . $ 7aCF OE • ;3aQ-az • 1` • •• I t 3a0-9Z i 4 Baa-oL 1 • I i 3a4-ZZ i • i 7aQ•Qt ............. .�....... ► ..•:' . 774.8E F`m, 3aQ-9T E ! w.•.. I 7aQ$t 7a0•LT O a� i I 4 A Tao 9 z .c • Q 'F I ei x30-Z Q i O j . a( v m Aolei-oE .Y rit......... AONSL Q i ,::a. n0N-92 Q d. m c , O ,........ +.. a I . nON tZ E ............ noN LL� N 3 '. ( ... AON QZa m E ID ....t:::,...... nON'ST 5 j ii 1. j ....:t555.. •G 4 CO ':: ;... AON9Tt� ^' m noNlaz y Q .0N-Z $ N noNoN_o 'm E eaL ai I fl. nON-9 c c O ` ° • X j I AON't u 1 I : Ao d 3 C .. 4 N } L�O6Z4 -13:-! a Q I ........... ........ .'. .........4.0 iii.r.. {�Q'�L I#O ! • P0-5 Z ...- 0 0• + ....5....- PO-EZ 2 o N i... .i Cr 7............ • PO-T Z 7 v 4•••••...............'• 170'61 `w a 7 i „t 00-Et. H E a } ........., 13011 7Q tt01 a m 3 I .c O cm i} 370-6 v c o 112 0 1 (I m 70-5 I Tv / E. u v ta0•E 0 v : 70-T 0a § g0 YO z z r; (3isd)ainssaid I . • • Attachment C - Daily Monitoring Data in an Electronic Format (Emailed on 1/11/2017 from Mai.Le.Vigil@exxonmobil.com to Osborne.Evan@epa.gov) 0 • Attachment D - Point Thomson Project Waste Streams • • Appendix D Point Thomson Project (PTP) Waste Streams Physical, Chemical and Other Relevant Characteristics of the Injected Fluid 4th Quarter 2016 Exempt Typical Primary Constituents Sampling Conducted or Waste Streams Exempt Sources Generator/Process Knowledge E&P Exempt Wastes • Production Facility Operations Produced Water Generator and process knowledge Non-Exempt Typical Sampling Conducted or Waste Streams Non-Exempt Sources' Primary Constituents Generator/Process Knowledge Treated domestic wastewater and water • Camp domestic waste water treatment plant, Non-RCRA hazardous via generator and treatment plant reject drinking water treatment plant,and fresh Water process knowledge water,and water lakes raw/potable water 1. Note that similar wastes may be RCRA exempt,depending on waste generating process. • ExxonMobil Production Company Cory E.Quarles P.4.Box 196601 Alaska Production Manager RECER Anchorage,Alaska 99519-6601 907-561-5331 Telephone 1 906-564-3677 Facsimile OCT 24 2016 EconMobit. AOGCC CANNE® APR 27 23i October 20, 2016 ER-2016-OUT-481 6(0[16jV UIC Manager, Ground Water Protection Unit U.S. Environmental Protection Agency, OCE-127 1200 Sixth Avenue, Suite 900 Seattle, Washington 98101 Re: Annual Injection Data for DW-1 for 2016 Fiscal Year(AK11015-A) Dear UIC Manager, ExxonMobil Alaska Production, Inc. hereby submits the 2016 fiscal year annual injection data for the Point Thomson Unit Disposal Well (DW-1) operated under Permit No. AK 11015-A. Please note that annual cumulative volumes are calculated based on annual calendar year per USEPA guidance. if you have any questions, please contact Mai Le Vigil at (907) 564-3608 or via email (mai.ie.vigil@exxonmobil.com). 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. Sincerely, 00.4.6( ExxonMobil Alaska Production Inc. CEQ/mlv/Iso/rlr cc: Timothy Mayers (EPA) Evan Osborne (EPA) Chris Wallace (AOGCC)without Attachments B, C and D Attachment: Annual 2016 Injection Data Report A Division of Exxon Mobil Corporation • • Z U' z Vf z to 5 2 Z 0 2a22a � a� t0, u a J Q 0 z CO h Z esi 1111 CO m < � N- N r4 NI O o M. -1 O h N Nan aa ,i O M co .i M h N N 0 IN CO to M O Al O 1.0 111. IN H 1-. AlO O M W O to N m ni A4 11-1 0 O h N H an Al h ei 0 Al N 0 M N N ~ 01 M Al CO D m N N 0 a M O aWI ID N n N 0 M CO m < .i M N .i yl .ti to n CO - QQQQ1 M h t0 h in n - W N 00 0 0 anM N h N :~„1 m n Lel N .0 00 m N N N M rl Z ti M ei S � � Ofef m ~ r- matoM ^ . mto CO m N .i N rl CO 00 N to N to co 2• N H IN9 O .-I M an O N chef C in<- n N ri r CO .4 IA M WI M M d lN0 .N-1 tNel O M m O O m 4 ui In m Q t0 .i N n 0 ~ rl M In CC In Owl h N h O Ohl a N O C ~ Al- In O M M 0 Al CO m N M h N 01 N N 8 01 t7 W a m p O M CO N N O t0 Cn Q m rf LL N N N h N tD "� N t0 CO to CO CO m •-t Q Ln ry Qai O M M N tau < Al rl a h Al .-1 N M V. a C6 ¢ - ; 2 O W O "~'1 a O N COMO1 `o N N CO til p K N O M .r-1 H el n a .h-1 0 6 Q N st AU Nin 1 tj N T app OJ N 0 M m 0 0 0 M N a AI < M 00 Al C a- E a E ; . _ a e a .i E j~j N N O X ▪ 9 N m t0D CO t0 N o O M AZ M 0 N W W 0 N O O O OO .ri .i h m 00 Al M N O, 0 6 3 rl N N N \ 0� E- .ti O w .1 c .0 v 5 a 0 a a Q u 0 a▪ .. e Ut . •F a a a a a , >._ H cL z t7 Q w <• C z z , c� � �? w W Z � - g F o 3 Q c 6 - z z `-' z U' x .n z g w W W 2 ¢ 2 tail ar an-J0 z a41c ¢ a of w o Q 0 co K K M H J 7 O r7 7 r 0 5 L may. N N to Q ~ IQ- S C d O Z K n a c 41 41 LU m o F W o. C C K OC OC K S K 6 Z J• d C d 0 W O O. cc �. a Z 2 Z j j Q Z W W W N 222 - — zzz1' z r r 1- d a ¢ a of Q C I 0. V 1.5 z Zig -IDCp ExxonMobil Production Company Cory E.Quarles P.©.Box 196601 Alaska Production Manager Anchorage,Alaska 99519-6601 RECEIVED E ' 907-561-5331 Telephone 906-564-3677 Facsimile OCT 24 2016 EkonMobii. AOGCC solois October 20, 2016 ER-2016-OUT-475 \ UIC Manager, Ground Water Protection Unit U.S. Environmental Protection Agency, OCE-127 1200 Sixth Avenue, Suite 900 Seattle, Washington 98101 Re: Point Thomson UIC Permit No. AK 11015-A, 3rd Quarter 2016 Monitoring Report Dear UIC Manager, In accordance with Condition II(E)(1) of Underground Injection Control (UIC) Permit No. AK 11015-A, ExxonMobil Alaska Production, Inc. hereby submits the quarterly report for 3Q2016. The permit required information is addressed below: a. Monthly average, maximum, and minimum values for injection pressure, rate, and volume: See Attachment A. b. Graphical plots of continuous injection pressure and rate monitoring: See Attachment B. c. Daily monitoring data in an electronic format: See Attachment C. d. Physical, chemical, and other relevant characteristics of the injected fluid: See Attachment D. e. Any well workover or other significant maintenance of downhole or injection related surface components: No well workover or other significant maintenance was conducted during this reporting period. f. Results of all mechanical integrity tests performed since the previous report including any maintenance-related tests and any"practice"tests: Annual Standard Annulus Pressure Test/ Inner Annulus Mechanical Integrity Test(SAPT/MITIA)as required under Permit AK11015-A Part I I.C.3(b)(1), bi-annual Reservoir Saturation Tool (RST)fluid movement test as required under Part II.C.3(b)(2), and the bi-annual Internal Tubing Inspection as required by Part II.C.3(b)(3)were performed on August 15-17, 2016 with an EPA representative present to witness the tests. Results were submitted to your office on September 9, 2016 (Reference ER-2016-OUT-426). g. Any other tests required by the Director: No test requests were received from the Director. A Division of Exxon Mobil corporation UIC Manager -2- October 20, 2016 During the annual and bi-annual tests referenced above in part f., the inter-annulus pressure exceeded the permitted pressure per testing protocols on August 16, 2016. As part of routine calibrations on equipment, the tubing pressure gauge transmitter device recorded an instantaneous pressure reading higher than the permit on September 14, 2016. During the calibration process, the pressure was simulated therefore the tubing pressure did not exceed permitted limits. The pressure transmitters experienced electrical communication issues with the control panel on July 2 and September 26 for 10 minutes each where data was not logged. Electrical communication back to the control panel has been re-established. There were no issues identified on the pressure gauge devices. Due to corporate policies on CD read/write access for employees, we were unable to provide daily monitoring data on a CD or flash drive, as was historically done. As agreed with your office on July 26, 2016 over the phone, submittal of the electronic daily monitoring data will be provided by email correspondence from Mai Le Vigil (mai.le.vigil@exxonmobil.com) to Evan Osborne(osborne.evan@epa.gov) on October 20, 2016. We appreciate your flexibility for 3Q2016 and we hope that there will be a long term alternative for future electronic data submittal. If you have any questions, please contact Mai Le Vigil at (907) 564-3608 or via email (mai.le.vigil@exxonmobil.com). 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. Sincerely, ExxonMobil Alaska Production Inc. CEQ/mlv/Iso/rlr cc: Timothy Mayers (EPA) Evan Osborne (EPA) Chris Wallace (AOGCC)without Attachments B, C and D Attachments: Attachment A—EPA Form 7520-8 Attachment B—Graphical plots of continuous injection pressure and rate monitoring Attachment C—Daily monitoring data in an electronic format(emailed) Attachment D—Point Thomson Waste Streams Attachment A — EPA Form 7520-8 US Environmental Protection Agency CilfroEFIA Form 7520-8 Database Template STEP 1.Copy this template in macro enabled xlsm version using"Save As".Include Well name,Yr and Qtr with current file name. STEP 2.Fill in the highlighted cells with relevant information. Do not enter n/a in any cell.Fields(')are mandatory. STEP 3.Enable macro.Press<Ctrl><Shift><A>to run the macro and check data in Dbtable worksheet.Save file and submit. Important:Please do not change the position of any cell below.Do not copy/paste cells or insert/delete row or column OPERATOR NAME* WELL YEAR' PERMIT' Point Thomson Unit PT DW-1 2016 , AK-11015-A REPORTING MONTH' 1 JUL AUG SEP INJ PRESSURE(MIN),PSI I 809 30 1 INJ PRESSURE(AVG),PSI 1203 1223 1175 INJ PRESSURE(MAX),PSI 2837 3187 5020 INJ RATE(MIN),GPM 0 _ 0 0 INJ RATE(AVG),GPM 3 4 3 INJ RATE(MAX),GPM 21 35 6 ANNULAR PRESSURE(MIN),PSI 7 0 0 ANNULAR PRESSURE(AVG),PSI 25 46 5 ANNULAR PRESSURE(MAX),PSI 116 2762 20 TOTAL INJ VOL(MONTH),GAL 130,616 175,120 150,186 ANNUAL INJ VOL(CUM),GAL 1,377,781 1,552,901 1,703,087 TEMPERATURE(MIN),°F 65 33 _ 72 TEMPERATURE(AVG),°F 81 81 91 TEMPERATURE(MAX),°F 96 _ 98 106 pH(MIN) pH(AVG) pH(MAX) SUBMITTED ON:* 10/20/2016 (mm/dd/yyyy) Note:pH not required for Class I well injected fluids when E&P exempt wates injected ZLI -Z o(c. ExxonMobil Production Company. Cory E. arles P.O.Box 196601 Alaska Production Manager I V E Anchorage,Alaska 99519-6601 77 907-561-5331 Telephone c m P 1 2 16 906-564-3677 Facsimile E,onMobil AOGCC SCM September 9, 2016 (CD11-:'0 ' ' \if ER-2016-OUT-426 J UIC Manager, Ground Water Protection Unit U.S. Environmental Protection Agency, OCE-127 1200 Sixth Avenue, Suite 900 Seattle, Washington 98101 Re: Point Thomson UIC Permit No. AK 11015-A, Mechanical Integrity Test Submittal Dear UIC Manager: In accordance with Condition II.C.3.(b) of Underground Injection Control (UIC) Permit No. AK 11015-A, ExxonMobil Alaska Production, Inc. hereby submits the data and reports for mechanical integrity testing conducted at the Point Thomson Unit Disposal Well (PTU-DW1) on August 15-17, 2016 on the North Slope of Alaska. An Environmental Protection Agency representative, Justin Selitsch, was on site to witness the mechanical tests. The following mechanical integrity tests were conducted: • The Annual Standard Annulus Pressure Test/ Inner Annulus Mechanical Integrity Test (SAPT/MITIA) required by Part I1.C.3.(b)(1). Pressure data met the permit criteria. • The bi-annual Reservoir Saturation Tool (RST) Fluid movement test required by Part II.C.3.(b)(2)was conducted. The water flow log demonstrated external mechanical integrity behind the pipe and above the injected perforation interval. • The bi-annual Internal tubing inspection required by Part II.C.3.(b)(3)was conducted. The tubing caliper data indicated that there were no possible holes in the tubing and the overall condition of the tubing is good. In accordance with Condition II.C.3.(c)(1) of Underground Injection Control (UIC) Permit No. AK 11015-A, two copies of the logs and two copies of the descriptive interpretive reports of mechanical integrity tests are provided. The enclosed final logs/ reports include the following: a. Annual Standard Annulus Pressure Test/ Inner Annulus Mechanical Integrity Test o EPA Mechanical Integrity Test (MIT)form (1) o MIT Job Report and Summary Graph (2) o MIT Detailed Job Breakdown (2) A Division of Exxon Mobil Corporation • UIC Manager • -2- September 9, 2016 b. RST Fluid movement test o Waterflow Field Plots (2) o Final Waterflow Log (2) o RST Waterflow Interpretation Report (2) c. Internal tubing inspection o Multi-finger Caliper Field Plots (2) o Final Processed Interpretation Multi-Finger Caliper Log (2) o Tubing Evaluation Report (2) If you have any questions, please contact Mai Vigil at (907) 564-3608 or via email (mai.le.vigil@exxonmobil.com). 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. Sincerely, 6414610 ._ ExxonMobil Alaska Production Inc. CEQ/mpl/rlr cc: Timothy Mayers (EPA, Anchorage Office), without enclosures Evan Osborne (EPA, Seattle Office), without enclosures Chris Wallace (AOGCC), without enclosures Attachments: Annual Standard Annulus Pressure Test/ Inner Annulus Mechanical Integrity Test RST Fluid Movement Test Internal Tubing Inspection A Division of Exxon Mobil Corporation • • 2. 1 q - 2 d(Q ExxonMobil Production Company Cory E.Quarles P.O.Box 196601 » Alaska Production Manager Anchorage,Alaska 99519-6601 D 907-561-5331 Telephone 907-564-3677 Facsimile E f(onMobii_ July 26, 2016 ER-2016-OUT-324 SCANNEV UIC Manager, Ground Water Protection Unit U.S. Environmental Protection Agency, OCE-127 1200 Sixth Avenue, Suite 900 Seattle, Washington 98101 Re: Point Thomson UIC Permit No. AK 11015-A, 2nd Quarter 2016 Monitoring Report Dear UIC Manager: In accordance with Condition II(E)(1) of Underground Injection Control (UIC) Permit No. AK 11015-A, ExxonMobil Alaska Production, Inc. hereby submits the quarterly report for 2Q2016. The permit required information is addressed below: a. Monthly average, maximum, and minimum values for injection pressure, rate, and volume: See Attachment A. b. Graphical plots of continuous injection pressure and rate monitoring: See Attachment B. c. Daily monitoring data in an electronic format: See Attachment C. d. Physical, chemical, and other relevant characteristics of the injected fluid: See Attachment D. e. Any well workover or other significant maintenance of downhole or injection related surface components: No well workover or other significant maintenance was conducted during this reporting period. f. Results of all mechanical integrity tests performed since the previous report including any maintenance-related tests and any"practice"tests: No tests were conducted during this reporting period. g. Any other tests required by the Director: No test requests were received from the Director. A Division of Exxon Mobil Corporation • • UIC Manager -2- July 26, 2016 During 2Q2016, continuous inner annulus pressure data was obtained from a back-up analog pressure gauge device for a period of time. From April 8 to May 1, the transmitter for the IA pressure gauge device experienced electrical communication issues with the control panel. The issue was discovered on April 20 and communicated to a USEPA representative, Thor Cutler, on April 21. Operator rounds and visual checks multiple times a day of the back-up analog pressure gauge at the wellhead indicated no exceedance or unusual activity during this time. The electrical communication back to the control panel has been re-established after a period of troubleshooting and parts replacement. There were no issues identified on the pressure gauge devices. As part of commissioning activities in May 2016, treated effluent was recirculated from May 6 to May 24 and produced water was recirculated from May 6 to May 26. Therefore while the flow meters are registering positive flow, this data is not included in the total volumes of fluid injected into PT DW-1. If you have any questions, please contact Mai Le at (907) 564-3608 or via email (mai.p.le@exxonmobil.com). 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. Sincerely, Ocx.4,a Q/AASki&-- Agent and Attorney-in-Fact ExxonMobil Alaska Production Inc. CEQ/m pi/dr cc: Timothy Mayers (EPA) Evan Osborne (EPA) Chris Wallace (AOGCC)without Attachments B, C and D Attachments: Attachment A— EPA Form 7520-8 Attachment B— Graphical plots of continuous injection pressure and rate monitoring Attachment C— Daily monitoring data in an electronic format(CD with data included) Attachment D — Point Thomson Waste Streams A Division of Exxon Mobil Corporation • Attachment A — EPA Form 7520-8 . • • w E C a +a / ( ,—,— +a 3 § � ° a - ° % ° E m 2 2 R o 5 \ c = ¢ 2,� / \ / / / / tti m \ m r / ƒ \ \ \ [ > @ �I<' ^ ^ e aLLI 2 W '< c — M * $ 3 I : . . . , . . . & 13 2 W E . . > o c m � � � / * / \ o y R o m 9 CO 2 e < R 2 > \ > m _v, § % / \ $ \ / TS 71- \ \ _ E c ; M o ■ E ) G / / � 3 2 ' 2 « CO a , . , . . . . — d \ g 4.4 / ° iCU { QJ - e LO m m t.0 / k k 4.7 m k it \ E \ \ ~ / / - rn ® / co m NJ ƒ Ta R � Q o H < / g \ ® m » « g 7c) « m % C > R e { m o u ~ 0 °uo \ c p c / E 2 \ E ' E .c k 0) � § \ \ E - 0 2 ._ $ c CO { o \ 2 t « § - 7 E u u ' k 2 � 2 = < < ¥ c ƒ a - _ : 0 2 w m d y 2 2 2 » » » 7 3 / / k k \ z z 0 \ \ \ k % - > / z \ QS \ u A z § / k k z x cc ± ± f a > z ( x \ — \ 13 CO- b ( $ / ƒ k \ \ \ -I > \ \ \ k % \ _ 22 _ w = z = _ k J 2 § \ / el < \ < CC \ 2 } § } \ \ \ { \ E % o o .g o CC CC CC CC CC CC CC j 2 ± _ _ _ cu o �_ CL _ < < 5 m e tn \ co ■ / \ / \ / \ / / / } \ ƒ Cr _$ Z Z Z / < e ILLI 0- - � 4 8 o = c Q c u = § _ ilk Q § § t 0 (10 a a a a 1- i- 1- 0. 0 v, LA v, I z • • ExxonMobil Development Company Gina M. Dickerson Post Office Box 14(}207 Senior Project Manager RECEIVED Anchorage,Alaska 99519-0267 Point Thomson Project 0 907 561 5331 Telephone MAY 9 2016 907 564 3719 Facsimile AC E7KonMobil April 20, 2016 ER-2016-OUT-222 UIC Manager, Ground Water Protection Unit U.S. Environmental Protection Agency, OCE-127 SCAMS 1200 Sixth Avenue, Suite 900 Seattle,Washington 98101 Re: Point Thomson Project Underground Injection Control Permit No. AK 11015-A 1st Quarter 2016 Monitoring Report Dear UIC Manager, In accordance with Condition II(E)(1) of Underground Injection Control Permit No. AK 11015-A, Exxon Mobil Corporation is hereby submitting the quarterly report for 1Q2016. The required information is as follows: a. Monthly average, maximum, and minimum values for injection pressure, rate, and volume: See Attachment A. Please note that the cumulative injection volumes for the temporary injection skid are based on the manually recorded injection data logs due to increased accuracy associated with manually verifying volume pumped from each holding tank. The temperature and pressure data provided was collected by the continuous monitoring system. With the demobilization of the construction phase temporary injection skid and the hook-up of the production permanent injection modules, the permanent injection monitoring system was used to exclusively collect continuous data following startup production hard piped injection for the period from March 26 through March 31, 2016. b. Graphical plots of continuous injection pressure and rate monitoring: See Attachment B. c. Daily monitoring data in an electronic format: See Attachment C. The spreadsheets include data collected manually and by the continuous injection monitoring systems. Daily spreadsheets provide both manually recorded injection data for all 12 batch injection events and associated continuous injection data for the construction temporary injection skid during the reporting period. Hard-piped continuous monitoring data for the production injection system is provided for the last week of March. These production injection system data are provided in ten-minute intervals and have been reviewed to identify and exclude data anomalies (e.g., no electronic signal). Less than 0.5% of data is excluded (highlighted in the dataset) and data at the next time interval (20 minutes) allows confirmation of the continuous data trend. Continuous injection data is included with Attachment C on a CD. d. Physical, chemical, and other relevant characteristics of the injected fluid: See Attachment D. Relevant waste characterizations for this reporting period are noted in the table. e. Any well workover or other significant maintenance of downhole or injection related surface components: No well workover or other significant maintenance was conducted during the reporting period. An ExxonMobil Subsidiary • UIC Permit No:AK 11015-A Page 2 April 20,2016 Point Thomson Project f. Results of all mechanical integrity tests performed since the previous report including any maintenance-related tests and any "practice"tests: A mechanical integrity test(MIT)/leak test was performed on March 21, 2016 and was witnessed by Thor Cutler of your office as required by Section II.C.3.b. of the permit. Two practice MIT/leak tests were performed on March 20, 2016. See Attachment F. g. Any other tests required by the Director: No other tests were required by the Director. The following batch injection episodes took place in 1Q2016 via the temporary injection skid: • Batch#26: January 2-3 • Batch#27: January 7-8 • Batch#28: January 18 • Batch#29: January 25-26 • Batch#30: January 27 • Batch#31: January 30-31 • Batch#32: February 16 • Batch#33: February 24 • Batch#34: February 29 • Batch#35: March 4 • Batch#36: March 6 • Batch#37: March 9 Hard-piped injection into the well through the permanent injection module started on March 26, 2016. If you have any questions, please contact Ben Wood at (907) 929-4108 or via email (ben.wood@exxonmobil.corn). "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." Sincerely, At'oijn- 6C11-4' Agent and Attorney-in-Fact Exxon Mobil Corporation GMD:bw:bt Enclosures: Attachment A—EPA Form 7520-8 Attachment B—Graphical plots of continuous injection pressure and rate monitoring Attachment C—Daily monitoring data in an electronic format(CD with data included) Attachment D—Point Thomson Project Waste Streams Attachment F—Mechanical Integrity Test Report cc: Thor Cutler(EPA) Chris Wallace (AOGCC) Attachment A — EPA Form 7520-8 • • NO EP/1k US Environmental Protection Agency Form 7520-8 Database Template STEP 1.Copy this template in macro-enabled xlsm version using"Save As".Include Well name,Yr and Qtr with current file name. STEP 2.Fill in the highlighted cells with relevant information. Do not enter n/a in any cell.Fields(`)are mandatory. STEP 3.Enable macro.Press<Ctrl><Shift><A>to run the macro and check data in Dbtable worksheet.Save file and submit. Important:Please do not change,- ition of any cell be, n nnt rnny/paste celiq nr in=artMolotn enu,or rnh,mn. OPERATOR NAME WELL YEAR PERMIT Point Thomson Unit PT DW-1 2016 AK-11015-A REPORTING MONTH JAN FEB MAR INJ PRESSURE(MIN),PSI 5 4 1 INJ PRESSURE(AVG),PSI 1276 1346 1256 INJ PRESSURE(MAX),PSI 1946 2032 3495 INJ RATE(MIN),GPM 0 0 0 INJ RATE(AVG),GPM 3 3 3 INJ RATE(MAX),GPM 5 6 37 ANNULAR PRESSURE(MIN),PSI 2 5 0 ANNULAR PRESSURE(AVG),PSI 68 225 122 ANNULAR PRESSURE(MAX),PSI 458 700 857 TOTAL INJ VOL(MONTH),GAL 451,986 214,957 258,033 ANNUAL INJ VOL(CUM),GAL 451,986 666,942 924,975 TEMPERATURE(MIN),°F 47 47 34 TEMPERATURE(AVG),°F 79 88 72 TEMPERATURE(MAX),°F 101 119 110 pH(MIN) pH(AVG) pH(MAX) SUBMITTED ON: 4/20/2016 (mm/dd/yyyy) Note:pH not required for Class I well injected fluids when E&P exempt wates injected 0 • Attachment B - Graphical Plots of Continuous Injection Pressure and Rate Monitoring I • 0 Tubing/ Inner Annulus Pressure (psi) O 8 8 8 8 8 8 8 8 8 titi a°° ro s I d I F ) 1 titi m n 0 v n III \c., ' (1I o �a� a C I o 0 C uf eD vtiw es ell ti0,\ G . 6s.1" 1\ g: . A IP %� A su < m ti.\".,tc. ± . 0 a I I I t� , - 1 Q1 o D c �acP I/ £t E c3 1 .d. oa m v m t' i m \c, .s\ti ti, e.6.e' 1 . O (nr - N N W W ,p O to O In O (n 8 Flow Rate(GPM) • • Tubing/Inner Annulus Pressure(psi) 1-- I-' N to O Ui 0 O O O O O Ab,41'.(11. L=) , . v 41111/ e1 �f ...........>dllP se. %."4 1'*%17 . D \‘'‘bF., DJ elsA S CU C I DJ 0:1 01 ,04 D zi m cm r+ , -oro c1 fD fD :n ? % c m i .4. V I ‘1"%%1N 1 O N .P 01 00 F+ F+ t+ 0 O O O O O N A O O O Flow Rate(BPM) • • Tubing/Inner Annulus Pressure(psi) 1— I— N In O Ui O O O O C O O O O O 4s4 .moi aNIIP J OO. 4 � -5'."......t atiti �titi p Na co su A 0> -71•11 - \ V" V IU O. 3 1 t .51 C W �� L ' 00 N O N O)•g C1 v-- T — —1 o D * v = z FP ao ,... rD a1ti� ,.) rc J O N is Ol oo O N •P 01 O O O O O O O O O Flow Rate(BPM) • 0 Tubing/Inner Annulus Pressure(psi) N I. N to O Ui 0 0 0 0 0 O O O O O °4 . titin J,a ti - �o .titi - N Do sd r+ A r ? A,• --N. N vc; I CO ya C CU r__ —s U ..., 00 N O F �tiw - -� ya oh _H I I T — � p o D co ro fp vl i 4 Uiii O N A OA Co O N A Oii O O O O O O O O O Flow Rate(BPM) • • Tubing/Inner Annulus Pressure(psi) I-' N N O 0 0 O O • aom --- 313 y ati.' ti - I a .1 ___..r4mm ti - � , N W SU a� el Atiti ? N } 1 lO SU I SU SU,I,` r '<N."1 Ul dn' N f71 d'1A III5 > N ro I S CD � I ' :1 O O O O O N A O O O ! Flow Rate(BPM) S , • • Tubing/Inner Annulus Pressure(psi) 1— I-' N O O O O O 3 ilig x 4,„.... ti; r a°' ...,;&,,...-- 44 is • 1 C7 o�w .1"bO t.-- et A 3 off' O `�a� �...� �� ‘ ‘..- ly 3 !y N O N ; G1 ya ,f D \? gCC y ro c m I I o O N A Ol 00 1-, N N N O O O O O O N A Ol O G O O Flow Rate(BPM) 1 • • Tubing/Inner Annulus Pressure(psi) 1--, N N vi O u1 0 0 0 0 0 O O O O 0 cb�ti o(-5C ya C7 0, __ __:r. A S 11141 a.. 11) C CUW FA a��4) IV A". O N 01 . I 0 ati o— s 73 c7D' C T3 L. 0 t titi ,iv { O N a CII 00 1-, N N N O O O O O O N A 01 O O O O Flow Rate(BPM) 9 • Tubing/Inner Annulus Pressure(psi) Ul o LI, 0 o o o 0 0 o o o 0 ,I•k, , ,A,•• inim. cc.7'. -ft, vommir"" Milm" \I'b . ...............mummom as. CIG li se. . f rfc, liii... .., eo,,,........................... ,.. .... 44 —1 0 . ,- Co I ••• \146CO •• 11111 .... .\,,t;•C> -\ I 40%);°) 411M. N \146 Limmi6" et cr - A46 ..( • - 2\146 1 • I I I • , cY * -D %--• V 1 446 1 To cril el. tfi -0 VI (DC (AD Cn co 1 A A..0 1/4); 446 ____L._ 0 NJ A al 00 1-s 1-‘ 1 b. b b b b o NI b iz) Flow Rate(BPM) • • Tubing/Inner Annulus Pressure(psi) N F+ N VI O Gn 0 O 0 0 O0 !II titin r s'a T v o� N ww y,a Oo A 1 44 W 346 1 -n fD a. , ahr.r .. . a) N .p N Co.' . O I I I E y ..4. ,•C' 7 -0 5.V C ro (D LT, C r P i ap 4 d awco17 .NI4N1%.**N. O N A al co NN O O O O O O O Flow Rate(BPM) i • Tubing/Inner Annulus Pressure(psi) 1--. 1--. N to O cn O O O O O O O O O O cc OW 4111 ....." IIMMMinimpo f moo. o vo as '\\ 3- w .p CD �ti� Cr '4:i ,. ..., �O Dcc Ri ` N O 01 I I I �Do) D Cr 0 moo`' O N A O, coO N A O O O O O O C C Flow Rate(BPM) • • Tubing/Inner Annulus Pressure(psi) F-+ N N vl O In O O O O O O O O O O X06 'S, -I ,..--_ ti "13 �ti —1 � a v i..1 ...,_ 03 ,-.4'`' A I w in 1 .titi 1 17 suA S N O / 1 ya I I al p D c * v a NI4a'V m C g m g I c m lI i L"� ya r O N A cl co 1--‘ F+ N F+ O O O O O O N A Ol O O C C Flow Rate(BPM) 410 • Tubing/Inner Annulus Pressure(psi) Ln O n O 0 0 0 0 0 0 0 0 0 (II 1------. . ,-, ..,..............v 050 v-- i r j _immi , ... t titi k , '0 _,-4 -1_,,....:4'..\„. `'... titi Iy JJa4ti n S W 01 n S � 01 N O cb ON o D E m c 7 a� c 4. r Z ` '0- i''‘6 0-is o N la 01 00 F-. F-. N. F+ O O O O O o N A al O O O O Flow Rate(BPM) 0 • Tubing/Inner Annulus Pressure(psi) F+ F.- N to O to O O O O O O O O O O X00 cb —non) —n — —I 6 XiN Era (D cr) v tic 44e. CO IN el1 S W V _ 4 1 v A S l0 .4 O CSC o� .T r , O N A of W O N O O O O O O O Flow Rate(BPM) • • Attachment D — Point Thomson Project Waste Streams • • Appendix D Point Thomson Project (PTP) Waste Streams Physical, Chemical and Other Relevant Characteristics of the Injected Fluid 1st Quarter 2016 Exempt Typical Primary Constituents Sampling Conducted or Waste Streams Exempt Sources Generator/Process Knowledge Drilling fluids,muds,produced • Drilling rig operations water,and other wastes E&P Exempt Wastes • Production Operations associated with the exploration, Generator and process knowledge development,or production of crude oil or natural gas Non-Exempt Typical Primary Constituents Sampling Conducted or Waste Streams Non-Exempt Sources Generator/Process Knowledge Used glycol/heat . Vehicles&equipment(antifreeze) Glycol(MEG,DEG,TEG, Used Glycol—Sampled on 1/27/16— exchange media propylene) Used glycol was non-RCRA hazardous Spot spill cleanup snow/water—Sampled Non-exempt spill • Fluids recovered from clean-up of non- Water and/or snow with on 2/24/16—Spot clean-up was non- clean-up exempt spills hydrocarbon or chemical RCRA hazardous.SDS's reviewed if • Spill impacted gravel or snow products(SDS reviewed) relevant for listed and/or toxicity characteristics Water with scale remover additive Boiler blowdown—Sampled on 11/6/15 Boiler blowdown • Rig or facility boilers —Non-RCRA hazardous,SDS reviewed (Griffin Bros.AM110) and pH conducted on each batch load • Cement Rinsate generate from cleanup of CaMgCO3(Calcium Magnesium Cement Rinsate—Sampled on 11/6/15 Cement Rinsate cementing operations for Drilling or Carbonate)and water —Non-RCRA hazardous—also, Construction purposes generator knowledge Treated domestic Tested on monthly basis in accordance wastewater and water • Camp domestic waste water treatment plant, with drinking water and water discharge treatment plant reject drinking water treatment plant,and fresh Water permits—Non-RCRA hazardous—also, water,and water lakes raw/potable water generator knowledge 1. Note that similar wastes may be RCRA exempt,depending on waste generating process. 2. Waste streams that were not generated or injected during a particular quarter are not usually sampled • 0 o I ,1:, O • N O O m N O 1 cm C •- N y LU m '02 . CO - O m m �_ W N W m . w ' . m N } C ai co m a.Ea 1:1- (/) m m m + C 2 W U 1I 1 2 ❑ C ❑ a ❑ 6 ❑ m ❑ ❑ ❑ roi r�i �° N L '.. m N O D > �9 a' m N 3 m 3 d L L L m "d co m❑ W H 43 =S H�� i-0- H m H H H NI 0I WI MI = 6 ❑ a o a o a c d o a a a. 0) 0) 0) 0) = O N 9 W 0` N` o N m N N N N J o f 6_• 1 6_1 o I Z m = ma ma. mm CO m@ m E m3 m3 m3 m3 mJ EC u) `m 0 co co co co C - c c Co co co co Ca N N N N N N 0 N 0❑ 0❑ ❑ 0 0 D Q C CO O IL L Lt_c ED ED lL C LL LE LL m W 0> Il Oj IL Oj IL O) • o 7 - N - 2 - C - C - _ _ O - o - 0 - o - 0 ° (n lo N O (/)CID U)co V)m V)m (I)C U) m (1) m (n a In Q (n a (n O- (n a �1 ❑ 1, Q o w ❑ 0 I C I m C m. C CO O C0 O) CO f0 m N m. O) CO c) �0 N CO 0 '.. D .0 of 0C 0c 0E OE 0f0 ❑-i ❑❑ ❑ HI ❑ HI ❑HI ❑HI ❑HI G I o ll ( o m O o o o O COi o c o f O o 0 () 0 CO ', N C L0 .off .o- .CO C Co C .o c .o O .o z o 0 0 0 0 0 0 0 O 0 EL U U 0) in io O I I I I 1 r o V,� o'c o'c oN9 _o No di o No N 0 di N E _UD (JD U= (JD UD A/ y 5 O O O m mF of off wH off Lr< 0 IN CO u) di u) WO> Ed c6 WO6 Ed u_ W2 Ed a. di a_ OD o_ di a_ Ed a_ O 5 w -1 5Q U C 'O 4) 4) 4) 4) 4) Ln LC) L0 L0 0 L0 L0 Om Y > o 0 0 0 0 0 0 0 0 0 0 0 J CO N N N N N N N N N N N N W Ln 0 Lfl co O (O (o (0 O 0 (O 0 (O 0 cc 0 as ry N N N N N N N N N N N N CO O 0 LU CO 0 0 (D 0 0 LU Co (0 Z O ox W w• D Li O V Z o I < CO ' ',. O LU O N C) O C) LU O O O N N 7 V CO (/) V N- co (A co co co co co J a m 1 c Om C o� CO C M N co co to C o Z @ CO� O N L- N c0 N O co 0 L CO (0 c LU coco I� co M N L0 �0 C? (D O N N CO D N co co V R V N N (O O co n N J o E a m (..) r- U E U n Ln J m co QL c ztoczt r 0) R 6 \ U0 15 I. 0 J p 7 2. 2 " I W N m o J f/) mw Cl) o m0 1 o . X ,'! r o 7 0 Q oo I Z CD o 0 o M c E J m -o 0 o Z 7 U v) 2E I ._ CO CO CO m CO CO CO CO co CO CO CO 0 0 -o CO CO CO CO CO CO CO CO CO CO m m Lo i c E 2 0 0 0 0 0 0 0 0 0 0 0 0 CD 7m S m m CO m CO CO m m m m m CO o O) O) _n O) O) _O _m _m _O7 m O) *iT 'iT o 0 Z 0 ` 0 ❑ ❑ O ❑ ❑ ❑ ❑ O ❑ ❑ ❑ (0 J ; Q o) O) O) O 0) O O 0) 0) O 0) O) 0) N ~ H d V (6 O 0) O 0) 0) O 0) 0) W C) co O) O Tr Q Z t C o R 7 LL0 LO0 00 cn LU LO0 LO0 (O0 LO0 0 LO0 (O0 LLC) LOC) N 2 W 0 z N N N N N N N N N N N N N i w Q O m 0 0 £ LL o 0 O .... c rn.o co �_5 z W CD � 2 U 0 0 0 0 0 0 0 0 0 0 0 E Q N -I I C) .t 1- aO) ao d -I ❑ 0 0 0 0 0 0 0 0 0 0 0La 0I1J De w w w w w w w w w w w w III • O O O o O N N O o N O > czt- (.11 (.11 coo co co co co U) co co CO CO U) co co U) co ccT� O ••CU CU coU)co co co co co co co co co co co co co (U co co 'a C!)o L N N N O CO CO coCO O M CO CO7 M N r M O0 Oc a 0)1 m 0I ai 0l hi 0I ti I aI ai ai ai ai I ti ai I ai ati i ai CD ai I Z Eo ER, Eg Eg E0 Eo Ea Ea Ea E ° Ea Ea E0 E00 Ea EN EM Ea Q C a co co co co co co co C ap co (U a, (U a, (U a) C a) (U a) (U co (U C r co co � IS2 12 12 12 12 I o I o la) 1 w 1 0 1 0 1 <0 I 0 1 w 1 0 1 0 1 it ai it a it a it Q it a it a it a it a it Q LL Q it Q it Q it Q it Q it Q it Q LL Q LL Q a a)a a)�1 o 0I a)wI a)�I a)NI a)w1 m C1 o C1 a)Q)1 a)u)1 a)u)1 a)V)1 a)V)1 y CI)I a)u)1 m U)I m CI)I 2 U) cnJ �J coJ �J u)__I u)_J. u)_J. o u)_J. o)_J. u)_J. o co_s u)_s u)__I' u)_s �J > > > > > > ..LL co..a a >a a"co a . U— "o"a CU H co> co> co co> To'> co co> co co> co a co> co To-> (6 N> (U G 0 1 0_1 0_1 0 _1 0_1 0_1 0_1 0_1 0_1 0_1 0_1 0_1 0_i 0_I 0_1 0_I 0 _1 0_1 O (,j U U U U U U U U U U U U> U v U U U U> CL 7 ; C> C> C> 'Es 'Es C> 'Es 'C s Zs C > C > C> C> C> C> C> C> C> a 2 2 01 2 01 2 01 2 01 2 01 o DI 2 01 o DI o 01 2 01 2 01 o DI o 01 0 01 0 01 0 01 o DI o 01 N 0 t5 t5 D '6 D UD 00 Ua 15 a 75 D 75 D UD UD 1:3F �0 i)D �0 a0 �0 )D LL N a_ (U N 0_ coI_ N F N N F N I_ N I_ - I y I- y I- CU F- CU s- N i- N H g 2 wa Wa EJ a Wa Wa Wa u.1a UJ CL UJ EL wa wa Wa ED EL ED EL wa ED a_ wa 0 E Lo to CL o 0 to0 to0 0 0 ic,0 0 0 to0 to0 0 0 0 too toa too W N N N N N N N N N N N N N N N N N N m co CO CO CO CO CO CO CO CO CO CO CO CO CO CO CO CO CO N N N N N N N N N N N N N N N N N N 'CO CO CO CO CO CO CO CO (O CO CO CO CO CO CO CO CO N COZ W K a V x w o ' Z 8 w M M O 1n f� N N OD CO O CO Co I. Q tli N CO CSO CO .O- r co O O CO CSO rto 0 to o o Or o o cp o CO CO CO CO LO CO CO M J ar CL 0 cis c T' Q c r O _a co ON a 01: o CJ o J N Q N OD cs I � Q. = M O 5 G N CON W N 4 C / G Om Q F- O a 15. Q o E 0 Z N U E Z as a) co co co co as co CO CO CD CO co co co co co crs N co co co co co Co (U as @ cc co (U N co as CO CO CO 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 CD 0 @ CO CO CO :V CO CO CO co (U co co co co co co co ca) c» a) rn a) eno) a) 0) CD CD rn o) o) CD G 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o > o) a) a) a) a) a) a) a) a) a) o) a) o) o) rn o) a) co C) 0 o) a) a) 0) co a) co a) rn a) a) rn a) rn a) 0) N a) O o) a) o) a) a) o) o) a) o a) a) W a) O o) O) ct in Lo to in to in to to to to Lo to in to to to to to C74 N N N N N N N N N N N N N N N N N N N .` 0 p w co W U o o o o o o o o o o o o o o o o o E 0 N 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 ¢ a 2 W W W W W W W W W W W W W W W W W W _ _ _ • • o .o o -- O c 0 0 M CO Z m f0 d O } , ' > N . O U •Co CO CO CO CO (0 N N (0 V) N co co V) co N co C ca o D m m m m (0 as m m (0 (0 (0 m m (0 m m (0 N ct co O (A Co : O V N M Ln (Ni O W Co (O n U) E b _ O O O O N O O O MO M O O N N N N U g C m 1 N 161616161616161616 1 N 1 N 1 61616 1 61 C Z ES ECO EN Es ES EC) Eo Eo Eo Eo Eo Eo Es ES Eo Eo ES i- mO mO mO mO mO m0 m� m,- m,- m,_ mNMm mM Mm Dv My mU d C C n C r C n C n Cr, Cr,. Cr, Cr,. C Cr, Cr, Cr, Cr, Cr, Cr, C n Q N 1r I I 12 1 a)I la) la) la) la) la) la) la) la) la) I Lt a LL LL it it Q a Q a it a LL a it a LL a it a it a it a it a LL a it a it a It a 0 1 i F- i F- F- F- I- I- F- I- I- I- I- _1- I- f- 13) O 0 U JI N JI 0_1 I 0 JI 0_1 I W_1 I 0_1 I 0_1 I 0_1 I 0_1 I 0_1 I 0_1 I 0_1 I 0_1 I W_1 I 0 JI 0_1 I d 0 mu- mu- DLL. C L1 mu- COLE mu- �mu- mmu- �mu- CDmu- mmu- (DLL mu- mu- DLL �LL V 'ivy co co co as cs co co m m m C0 m CO m m m °' 0 D 0 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 I EP- 0 • m g U> g_ U_ U_ U_ g_ U_ U_ g_ U_ U_ g_ o_ U_ U_ U_ o N mC C> 'C C> C > C> C C> C > •C •C > > C> C C > Z > C> 'C> 'EU) 0 0 0 0ODO 0ODO 0 O 0 O DODO 0 0 0 O 0ODO 0 0 0 0 0 O 0 O<a y I I I 1 I 1 1 1 I 1 I I I I I I I A/ I_ F- 1_ I- F- I- F- f- F- I- f- F- I- F- I- F- F wg LL co) ,e W a Lu a w a LI a Lu a LTJ a w a E a w a CO a w a lL a W a EJ a W a 0 a w a lL 0 v in Co1.0inLotoLoLoupLoLo O. 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 W N N N N N N (N N N N N N (N N (N N (N N To CO CO co co co co CO co (0 CO co (O co CO co co Co co /�/ N N N N N N N N N N N N N N N N N N Ll r2 CO CO CO c0 CO CO (O CO (0 CO CO CO CO (O CO CO CO CO z W O a V x W ca Z 8 O 0 co co (� O) M MM O co 7 U) co (() ICZ (!) co V P N M V co co V co M co co M — co 41 li O O O O O O CO co O O O O O O O O J a � O U) OM CO C � � N• O a� E 017 U w in 0 M Q0. czt l'' a LOi o 5 G N N M N W v P cu Ci) G as 0 ICC D I- a. oa Q c a Z Eo ' 0iv0 m Z m m m m m m m m m m m m m m m m m m co its m co co co co co co co co co as co co co co co co (n '0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0) CD CD co CD m co co co co co co .co m m m m m m '0) 'O) 'a •a •0 •c •E •a •0 •a •0) E •a E •a) .5 :t_-, .E co D 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o > o) co a) a) a) C) a) a) C) C) C) o) C) C) C) C) C) C) C) C) C) C) C) rn C) rn C) C) C) C) C) C) rn C) C) C) N o) o) o) O) o) O) o) o) O) o) o) o) o) o) o) o) o) co V in U) in in in in in to in in in in in in Lo in in in r N N N N N N N N N N N N N N N N N N N .` 0 D 0 o 00 U co U 0 0 0 0 0 0 0 00 0 0 0 0 0 0 0 0 U E 0 0 0 a• 2 W W W W W W W W W W W W W W W W W W • • o `° o • •• • • o C .O U C • • C • N N N N m * • co co o o o C E EE d • C N N aU N • N N p E O O O > > LL o6 F.L. 2 o J c� 0, U u) O N U'N N N N 'O 'O -o N 0 N o o t� ow 'G O ❑ U U) C U U a) a) a) y V) M N N COU)Q C_ C_ C co c0 co co co co as cc co Ll. ❑ ❑ co _ O J Ln i) 3 co m co N y E-. p c C 4C-') in o m U0 cCV o 0 0 0 0 0 0 m N • c_ c_ Z i- i- co co J of of of 2 2 2 F- F- F- 0 it LEI 0 0 0 ❑ 2 0 0'N 0 0 0 0 0 0 0 0 00 0 0 d IF- F- F- F- F- F-Q F- F- F- I- F-p F- I- I- F- F- E- U) �'O O d d 0 n. n. J a a a a d a a Z.N a a t 0 iii N N N N N N 8 N N N N N N 45 N N Oc" N N W 0 jLL 11 11 I1 m ll it C LL-p it LL it it it C LL IL it J it ll. X C. O co U U U-p O ) O U U 0- U0- U,, U U U,F U U C U"o U N a) CL 0. w O ELL Eo C Ey O N' O 22 O O E O O O a O? O co O a U O a QO• 7t t n ti 15 0 5•E 00 U E ) t) O cc N m a m o o c6 W Wmo Wmo WmJ WmW _mo mo WmJ m W coWJ WmQ Wm o Wm mU) v O Q Ln Ln 10 10 LI) LO 12) 10 10 Ul Ln U) U) CO d d .o J U lio 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Cl. E EN E W m N N N N N N N N N N N N N N N N N N CO 3 co co co co CO CO co CO co c0 co CO CO CO CO CO Ch m N Z /� 0 N N N N N N N N N N N N N N N N Ce r2 U) CO CO CO CO CO CO CO CO (O fO f0 f0 (O CO (D tr) Lo p 4 p•d o.. p. Cl.... O Q 0. 0- O. o- v VX 0 ' W 3 Z N Q a0+ cOre R co co m z 1 co a m IL o co c ca) d r o N 2N O E U Z U Jco I o Qto a 0. tTo o 0 2/� CV (N U W N C rrr 7 N m _ t a) CO V+ 0 co j N a ao al Q O z E 0 0 E U m z @ CO CO CO CO CO CO CO CO CO CO CO CO CO CO CO co m m CO m CO CO CO CO CO CO CO CO as m co co m m Ln 10 0 0 0 0 0 0 0 0 0 0 0 0 00 o ❑ 0 o) a co as Lo co as L6 LO c6 as L6 co c6 as L6 J N c° C o) m m o) o) o) o) D) o) m D) O) o) m m 7 m m !6 C 0 O ❑ 0 0 i5 ❑ 6 ❑ 0 6 ❑ ❑ ❑ 2 ❑ 0 E C m m O O) O) d1 d1 d1 d1 d1 d1 m O) d) w rn rnrn rn 0) rn cN F- Irn rn rn ma' CD rn rn rn rn CD CD CD et 1 L!) up up Ln Lc) LC) to Lc) LO Lc) Lo Lo Lc) Lc) Ln LO Ln Ln j N N N N N N N N N N N N N N N N N N d N 1 a cE E 0▪ oo N z .2 °0 ayi U °O 0 0 U 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 O V • ❑ 0 ❑ 0 0 0 0 0 0 0 0 0 0 0 00 p 00 d Q a 2w w w w w w w w w w w w w w w -J w w j3 • S O C - o MN >. ctl a) V Q ›, N >_ >_ >_ 1 as O 5 co L T b o d N Lo m cj = O < 1 N' z E' p Z M Y. U a m I Q o m 2 PI O a U U V o m c z 1 (0 1 G(-.) .......>_ ce N • m p Ocp `co 7 <0 f6 1 J a < ci) as J Oo W o N Si, Z it co /W a @ a V W• CO E 3 m Z vi 2 N rn Q y p 0 N v> a) o c • m 0J = I o 2 U U a � NoC N I s 1 O ( IV U c LO a> wo J ce >- �\ C 1j aCt0 = £ to V I a. I coI-- 1 C N I f6 • Z' /cam N N E 1 W v o I- E I 1 CO CI co C Z p 1 COO 7 c _ ._ o m ▪ I- LL a) c a Q pp m O 1 Z p N U ( 1 CI E 0 o 2 D m Z = 0 a o o • O N N ›- 10- o N 0 o G \l c 1 .. T N > 1 W m ~ W E o- o d N W 1- NI d re o E m • O O F V w ? c Le 1 d D O F c c Z c m O w 1 p co Q _o p Q o o Q c1 c U O c -'p p° CD a co co w E -.D. O • 0 LL o p £ d E E d a 2 I E 0 a CD H 0 0 0 0 • • Guhl, Meredith D (DOA) From: Podust, Alex V <alex.v.podust@exxonmobil.com> Sent: Monday, May 09, 2016 4:04 PM To: Guhl, Meredith D (DOA); Calder, Steve/C Cc: Schwartz, Guy L(DOA); Quick, Michael J (DOA); Davies, Stephen F (DOA) Subject: RE: PTU-DW1, PTD 214-206, Logs Obtained & Directional Survey Attachments: PTU-DW1 Log Files Delivery Cover Letter.pdf; PTU-DW1_Final Definitive Survey.pdf; PTU-DW1_Final Definitive Survey.xlsx Meredith, Per our records, all DW-1 logs were delivered to AOGCC on 6/25/15 in hard copy as well as electronic format with the attached cover letter.The definitive directional survey is attached in pdf and Excel format. Please let me know if you have any further questions. Kind Regards I Mit freundlichen GruF en, Alex Podust Drilling Engineering Supervisor— US Drilling (Point Thomson) ExxonMobil Development Company 3700 Centerpoint Dr, Ste 600 Anchorage, AK 99503 Office: 832-624-2728 Mobile: 281-782-4639 alex.v.podust(a�exxonmobil.com From: Guhl, Meredith D (DOA) [mailto:meredith.guhl©alaska.gov] Sent: Monday, May 09, 2016 10:00 AM To: Podust, Alex V; Calder, Steve/C Cc: Schwartz, Guy L (DOA); Quick, Michael 3 (DOA); Davies, Stephen F (DOA) Subject: PTU-DW1, PTD 214-206, Logs Obtained & Directional Survey Hello Alex and Steve, During a review of the 10-407 submitted for PTU-DW1, PTD 214-206, I noted that box 22. Logs Obtained,was left blank. Please provide a list of the logs obtained in this well. Also a digital directional survey has not yet been submitted for this well,as required by 20 AAC 25.050(d). Please supply a digital copy of the directional survey, in both PDF and Excel/ASCII/Text format to me,via email. Please supply the list of logs obtained and the digital directional survey by 5/20/2016. If you have any questions, please contact me. Thank you, Meredith Meredith Guhl 1 Petroleum Geology Assistant • • Alaska Oil and Gas Conservation Commission 333 W. 7th Ave,Suite 100,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(n)alaska.gov. 2 • Guhl, Meredith D (DOA) From: Guhl, Meredith D (DOA) Sent: Monday, May 09, 2016 10:00 AM To: 'Podust,Alex V'; Calder, Steve/C Cc: Schwartz, Guy L (DOA); Quick, Michael J (DOA); Davies, Stephen F (DOA) Subject: PTU-DW1, PTD 214-206, Logs Obtained & Directional Survey Hello Alex and Steve, During a review of the 10-407 submitted for PTU-DW1, PTD 214-206, I noted that box 22. Logs Obtained,was left blank. Please provide a list of the logs obtained in this well. Also a digital directional survey has not yet been submitted for this well, as required by 20 AAC 25.050(d). Please supply a digital copy of the directional survey, in both PDF and Excel/ASCII/Text format to me,via email. Please supply the list of logs obtained and the digital directional survey by 5/20/2016. If you have any questions, please contact me. Thank you, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave,Suite 100,Anchorage,AK 99501 meredith.guhlPalaska.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. 1 3 • • Schwartz, Guy L (DOA) From: Podust, Alex V <alex.v.podust@exxonmobil.com> Sent: Wednesday, May 04, 2016 1:50 PM To: Schwartz, Guy L(DOA); Morales, David C Cc: Calder, Steve/C Subject: RE: PTU DW-1 Weekly Report (PTD 214-206) Guy, Upon drilling out the DW 9-5/8" surface casing shoe, we performed multiple FIT attempts to 13.8 ppg EMW to verify integrity to drill ahead. The tests all exhibited similar trends: linear or near linear pressure build-up,followed by a steady pressure decline that did not show a stabilizing value.A tight channel was suspected as root cause and a remedial cement job was performed. The hesitation squeeze job parameters supported evidence of a tight channel. Without breaking down the shoe,we were only able to inject 3.8 Bbl of water based flush and —2 Bbl of remedial cement slurry after a total of sixteen hesitation squeezes.The hesitation squeezes yielded a decreasing pressure decline trend, from 10.1 psi/min initially to 1.4 psi/min following the final squeeze. Because the shoe was set at the bottom of a thin shale section in a predominantly sandy interval, we were concerned that additional footage drilled to perform the post-remediation FIT would expose us to higher seepage losses and potentially complicate the interpretation of the test.Therefore, the decision was made to spot a LCM pill prior to post- squeeze FIT attempt.A 13.8 ppg EMW FIT was performed,this time exhibiting drastically improved pressure fall-off behavior, and was deemed sufficient to drill ahead. Happy to discuss further if you have any additional questions or concerns. Kind Regards I Mit freundlichen Gruf1en, Alex Podust Drilling Engineering Supervisor—US Drilling (Point Thomson) ExxonMobil Development Company 3700 Centerpoint Dr, Ste 600 Anchorage, AK 99503 Office: 832-624-2728 Mobile: 281-782-4639 alex.v.podust(c�exxonmobil.corn From: Schwartz, Guy L(DOA) [mailto:guv.schwartz@alaska.gov] Sent: Wednesday, May 04, 2016 10:54 AM To: Morales, David C Cc: Podust, Alex V; Calder, Steve/C Subject: RE: PTU DW-1 Weekly Report(PTD 214-206) David/Alex, I was reviewing the wellfile 10-407 report for PTU-DW1 and saw something I missed before. When you drilled out to do the second FIT attempt on 4-4-15 you spotted a 50 bbl LCM pill just before the test. I don't recall LCM pill being 1 approved on my end. Do you have.information on that decision and can yoWarify what the events were lead you to using LCM ? 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(Guv.schwartz@alaska.gov). From: Morales, David C fmailto:david.c.morales@lexxonmobil.com] Sent: Friday, April 10, 2015 4:02 PM To: Schwartz, Guy L (DOA) Cc: Podust, Alex V; Calder, Steve/C Subject: PTU DW-1 Weekly Report(PTD 214-206) Guy, Please see the past weeks operations update through 4/10 00:00. 4/3: RIH with 8.5" drilling BHA, drill out cement 4/4: Re-perform FIT to 13.8ppg. Drilled 8.5" hole from 4990'MD to 5990'MD 4/5 (as of report time 4/6 00:00): Drilled 8.5" hole from 5990'MD to 7800'MD 4/6 TD'd 8.5" production hole at 8800'MD 4/7 Performed wiper trip from surface casing shoe to TD, POOH with 8.5" BHA 4/8 Perform open hole sonic/caliper log, RIH in preparation to lay down drill pipe 4/9 (as of report time 4/10 00:00) POOH to surface laying down drill pipe Let me know if you would like to discuss anything further. Regards, David Morales Drilling Engineer ExxonMobil Development Company Pt.Thomson Project Cell (832)993-5269 Office (832)624-8429 2 • • 2.I4-266 0 Regg, James B (DOA) From: Motteram, Luke A <luke.a.motteram@exxonmobil.com> Sent: Friday, March 04, 2016 12:05 PM To: Wallace, Chris D (DOA); Regg,James B (DOA) Cc: EM Alaska Correspondence/SM Subject: ExxonMobil Point Thomson: DW-1 MIT - March 21 Attachments: PTU-DW1 MIT Procedure (Feb 2016).pdf Chris,Jim, A courtesy note to inform you that ExxonMobil intends to complete the annual MIT for Class I UIC well PTU-DW1 on or around 21 March 2016.The EPA has been notified and a representative (Thor Cutler) is planned to be in attendance to witness. Formal notice of at least 48 hours will be provided via the AOGCC online form. A copy of the test procedure is attached for your reference. Regards, Luke Motteram Production Engineer ExxonMobil Alaska Production 3301 C Street, Suite 400 Anchorage, AK 99503 Ph: +1-907-564-3697 1 11110 • EpnMobil ow POINT THOMSON OPERATIONS ExxonMobil Alaska Production Inc. Point Thomson Disposal Well (PTU-DWI) Mechanical Integrity Test (MIT) Procedure Prepared: Production Engineer .eff Date: / 121166 L. Motteram Reviewed: E&R Advisor Date: E. Denman / M. Le Endorsed: -000111.- Operations Technical Manager Date: 3 - J. Long Approved: Sr. Field Superintendent -1 -1 Date: 3 cs, B. Schulze / R. Trout Revision date: February 2016 ExxonMobil Use Only • • ExxonMobil This page intentionally blank • Exxon Mobil TABLE OF CONTENTS INTRODUCTION 4 Program Scope 4 Regulatory Notifications 4 Data Requirements 4 MIT Preparation 4 Test Criteria 5 Reporting 5 WELL INFORMATION 6 General Well Data 6 Tubing & Casing Information 6 Alarms & Shutdowns 6 Wellhead Stackup 7 Wellbore Sketch 8 CONDUCT MIT 9 Equipment Required 9 Preliminary 9 Rig Up 10 Pressure Test IA 11 Rig Down 11 Post Job 11 APPENDIX 12 EPA MIT Form 12 Revision date: February 2016 Page 3 Exxonfilobil Use Only • ExxonMobil INTRODUCTION Pro. rti.E This program outlines the procedure for conducting a standard annulus pressure test/ inner annulus mechanical integrity test (SAPT/MITIA). The SAPT/MITIA will be required annually if DW-1 well is active. Re•mato Notifications Notify EPA at least 30 days in advance of conducting the MIT so that a representative can be present to witness the test. Courtesy notification to AOGCC a week in advance is recommended to allow coordination of travel to Point Thomson to _/ witness the test. Formal notice via the AOGCC online form is required at least 48 hours in advance of the test. Notification to conduct the next MIT on or around 21 March 2016 has been made to EPA. Data Re uire ents The following information must be available at the location for review: • Valid approved waivers, if any, relating to the integrity of the tested well. • Current well schematic. / • Graph of tubing, inner annulus, and outer annulus pressures for the preceding 90 days. , MIT Preparation The following guidance is provided with respect to MIT testing: • Document any activity involving pumping into and bleeding pressure from the annuli within 24 hours of the MIT. • The well's annulus should be fluid packed before the Inspector arrives. • 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. • Calibrated pressure gauges with suitable range and accuracy must be installed on the tubing, inner annulus and outer annuli. • Suitable flow measurement equipment should be available to determine the volume of fluids pumped into and returned from the tested space. • Other equipment (e.g. tanks, lines, bleed trailers, etc.) necessary for the safe pressure testing and suitable for the operating environment should be rigged up prior to Inspector arrival at the location. Revision date: February 2016 Page 4 Exxonrylobil Use Only • ExxonMobil Test Criteria Relevant MIT requirements under EPA permit AK11015-A are outlined below: • Test pressure for SAPT/MITIA will be at least 2500psi over 30 minutes. • Criteria for a passing MIT: o Pressure may not decline more than 10% during the 30 min test period, and show a stabilizing tendency o Pressure loss in the last 15 mins of the test must be less than one third of its total loss • If the total loss exceeds 10% of if the loss during the second 15 minute period is equal or greater than half the loss during the first 15 minutes, the test may be extended for an additional 30 minutes to demonstrate stabilization (resulting from thermal effects). Re•cortin'• Agency reporting will be coordinated by the engineering and SSHE team in Anchorage. Report the results of the MIT to EPA on the provided form within 45 days. Copy AOGCC on the report submission. Also include the MIT results in the next quarterly report to the EPA Director, including any maintenance-related tests and any 'practice' tests. For AOGCC complete MIT Form 10-426, noting the test was witnessed by EPA, and submit electronically no later than the 5`h calendar day of the month following the test. Revision date: February 2016 Page 5 ExxonMobil Use Only • ExxonMobil WELL INFORMATION General Well`Data} Well Name: PTU-DW1 Z 14 ZCc, Well Type: Service- Disposal UIC Permit: AK11015-A Field/ Location: Point Thomson, North Slope AK—Central Pad Slot 1 Surface Location: Lat: N 70° 10' 23.30436" Long: W 146° 15' 20.05740" Total Depth: 8,800' MD/6,905' TVD Base Permafrost: 1,832' MD/ 1,832' TVD Packer Depth: 7,018' MD/5,757' TVD Reference Elevation: 33.4' RKB-GL (46.1' RKB-MSL) Wellbore Profile: Build to 50 degrees and hold Last Annulus MIT: 4/18/2015— IA tested to 3500psi (passed) Tubing &Casin• Information 4-1/2 12.6 1Cr-L80 7,100 Vam Top 8,430 7,500 288 288 7 26 1Cr-L80 8,781 TSH 563 7,240 _ 5,410 604 604 9-5/8 53.5 L80 4,952 Vam Top KX 7,930 - 6,620 1,244 1,244 34 x 20 129.5 X-52 154 PE Weld N/A N/A 1,978 N/A Alarms &Shutdowns High 2600psi Maximum expected surface pressure during normal injection operations (based on well modelling and step rate test results) Wellhead Injection Pressure High-High 5000psi (PST551001-01) Wellhead working pressure rating and UIC permit limit Shut Down 5000psi - High - 1200psi - 80%of UIC permit limit Tubing x Production Casing (Inner)Annulus Pressure High-High 1500psi - (PST551001-02) UIC permit limit Shut Down - 1500psi High 200psi - Recommended surface annulus trigger pressure Production Casing x Surface Casing (Outer)Annulus Pressure High-High - 450psi - (PST551001-03) Calculated formation integrity - Shut Down - 450psi ` (based on drilling FIT and annulus fluid weight) gig Revision date: February 2016 Page 6 ExxonMobil obit Use Only 0 i ExxonMobil Wellhead Stackup 53.7 rl�4 III!II _I ,;, ileal Pillej ti t. } 51,2 ..ai., �tl�i 159.4 , ■ E ., 4-1/16 API 5K (RX-39) ---• _\4 ..„ 16 56) 8.8 7-113/16 10K KPI I(9x 1 151 �_� „a,®. ( ) ,,,�s ems' 46 1-13/16 API 10K (BX-151) • ,,5 r.,' a 11 N. : ! ' T' , -Iail... , 25.0 sgas i 1'rA�i �t 1 III,s, %Fri \1>/ ( 47.4 ?:,f g. `%/✓ 47.4 i! 47 11 API 5K (RX-54) _ '"'u1' :oma ��mm- TYP ��5i u1 �_ ' rot ./l.I%�f ' � �i } r - �'1.;••:::•'..1�, 11.f 4 ,, r.Tii k 2-1/16 API 5K (RX-24) 2-1/16 API 5K (RX-24) • (': t �', r / 1 A.k t• A I 42.4 . / tit RI „Iv� h I r . 'i /' 43.7 = 'Er, bmf �: 21-1/4” API 2K �. ,,,I7 a 20" 129.45# CASING :I •1m 9-5/8" 53,5# CASING 7" 26# CASING 4-1/2" 12.6# TUBING Revision date: February 2016 Page 7 ExxonMobil Use Only • • ExxonMobil . .. . . , Wel I bore Sketch . . . . ' Surface Location: Rig Nabors 27E E,..ig,onfOobil Point Thomson RKB-GL 33.42 ft PTU-DW1 (Disposal Well) Central Pad,Slot#1 GL-MSL 12.7 ft Insulated Conductor RKB-MSL 48.12 ft lar&-., prt. g 20"x 34"129.5#X-52 Welded LiselitiI 154'MD/TVD iefillitifilljtj 1 1 I Port Collar:493'MD'TVD t2 o .1 Permafrost Base:1,832MD!TVD KOP:1.846'MD/TVD 12-1/4"Hole ,-- in., Top o f of Tail:+ 9-5/8"53.5#L-80 VAM TOP KX , 111' jTopLead:II32 4,905'- 95M ' MDD3,756'TVD 14,405'TVD, , 4,952'MD!4,435'TVD ' t j " TD:4,960'MD 4,440'TVD / . i 1 i 1 t w = LU 4 E 8-112"Hole Hi I a. w J o 1-4. Swell Packer#2:5,512'MD/4,795'TVD 5.534'MD/4 810'TVD i ,,-..i.j717V3liiille;1_ TtrOfillitillOati Upper Confining Zone I 1 - ';-•-,;:-,-,--,,,,- ,,..10,18,:,k, q Swell Packer#1:6,051'NID 1 5,140'TVD ........................... . ................,......... ............................... 6,055'MD/5,142'TVD Top of Tail:+1-6,785'MD/5,608'TVD 4 1/2"12.6#"I%Cr O80 VAM TOP 1Injection Packer 7,018'MD/5,757'TVD 7,100'MD 15,810`TVD 7,110'MD/5,817'TVD - iftgjt J* I „wt jtjfi ,;;14 ' , I I ,,,,,,,, "1,.',& Injection Zone I ..!‘t',rj, iiIiI,JI Contingency Perf Interval ; ,,7.",.,',-, 1 k.4. ,,,0 : 8,515'MD/6,722'TVD . ---,JO -- V..,, ' --- - Peri Interval:8,516'-8,5364 MD/6,722'-6.735'TVD 4:44""'" 7"26#1%Cr L-80 TSH 563 ,,l:,,ix :: 8,781'MD/6,893'TVD pe TD:8,800'MD t 6,905'TVD NOTE:All depths RKB Revision date: February 2016 Page 8 ExxonMobil Use Only • • ExxonMobil Conduct MIT E•ut•menf Required • Hot oil trailer and operator • Minimum 100ft of rated hose or hard pipe • l Obbls of LVT200 base oil (or equivalent) • Contingency spill kits, drip trays and absorbent matting _C w rtio n Do not use diesel for the inner annulus MIT as the aromatics can break down the freeze protection fluid (Isotherm, a gelled base oil formulation) Preliminary 1. Confirm that all necessary equipment and personnel to perform the MIT are available on site. 2. Fill the hot oil trailer with 1 Obbls of base oil and position at least 85ft from the wellhead. Note: • Refer to the Work Management Manual for additional equipment spacing and SIMOPS restrictions. 3. Verify that pressure transmitters on the wellhead (PST561001-01), inner annulus (PST551001-02) and outer annulus (PST551001-03) are in calibration and functioning correctly. ✓ Note: • The transmitters provide continuous data recording back to the CCR. Local gauges at the wellhead can also be used to monitor the progress of the MIT. 4. Check the status of the DW-1 disposal well. In normal operation treated waste water is continuously injected at low rates and produced water pumped intermittently as the level in the degassing drum rises. Ensure that process conditions are stable prior to commencing the MIT. 5. If injection to the well is shutdown, treated waste water needs to be diverted for discharge to a tundra pond in accordance with the discharge permit and the upper section of the wellbore freeze protected with 40bbls diesel from the produced water system. Note: • Refer to the Operations procedure for the water disposal system for instructions on freeze protecting. 6. Ensure tubing and annulus pressures are well below the high level maximum allowable. 7. Have CCR temporarily defeat the high-high pressure shutdown on the inner annulus pressure transmitter. ..- Note: • The required MIT test pressure is above the normal alarm (1200psi) and shutdown (1500psi) set points. Defeating the shutdown will avoid inadvertently shutting in the well during the test. Revision date: February 2016 Page 9 ExxonMobil Use Only • • ExxonMobil Ri• U Nog: Complete the rig up in advance of the inspector arriving on site. 1. Close the two wellhead manual casing valves on the inner annulus. - 2. Bleed downstream of the wellhead to verify the casing valves are holding pressure. 3. Remove the pressure gauge from the 2" 1502 fitting on the inner annulus tee. Note: • The tee is downstream of the closed manual casing valves, which provide isolation from the annulus to remove the gauge once any pressure is bled down. 4. Connect rated hose or make up hard pipe from the 2" 1502 inner annulus tee back to the hot oil unit. Include block valves in the rig up to isolate the flow as necessary. Notes: • Do not include a check valve as the pressure will be bled down and test fluid returned to the hot oil trailer after the MIT. • Consider adding a pipe tee with plug near the wellhead connection for flexibility in pumping or blowing clean following the test. 5. Position drip trays at all hot oiler tank inlet and outlet points, hose / pipe connections and ends, and ensure contingency absorbent matting is available. Secondary containment is required for storage of base oil or bleed off fluids. 6. Pressure test from the hot oil unit against the closed manual casing valves to 500psi low / 3000psi high for 10 minutes each. Bleed down test pressure. 7. Isolate the hot oil trailer from the well inner annulus at the pump unit. 8. Open the manual casing valves on the inner annulus. 9. Verify with CCR that tubing, inner annulus and outer annulus pressure transmitters are correctly displaying data. 10. Line up to pump from the hot oil trailer to the inner annulus. Revision date: February 2016 Page 10 ExxonMobil Use Only • • ExxonMobil Pressure Test IA 1. Record the pre-test tubing, inner and outer annulus pressures. 2. Commence pumping at the minimum rate and increase the inner annulus pressure to approximately 500psi. Hold this pressure for 5 minutes to confirm integrity. Note: • Record the volumes pumped to and returned from the annulus at the hot oil trailer. 3. Slowly increase inner annulus pressure up to 2500psi and hold for 30 minutes to perform the required MITIA. — Notes: • The pass criteria are a pressure loss of less than 10% (250psi) over the 30 minute test, and less than one-third of the total loss in the last 15 minutes. • Refer to the test criteria section of the procedure for additional information on MIT requirements. 4. Record tubing, inner and outer annulus pressures initially, after 15 minutes and at 30 minutes. Note: • If the MITIA needs to be extended (to eliminate thermal effects and illustrate stabilizing tendency), also record all pressures after 45 minutes and at 60 minutes. 5. Confirm with the Inspector on site that the MIT has passed and all requirements have been met. 6. Slowly bleed down pressure from the inner annulus to zero. I Down 1. Close the two manual casing valves on the inner annulus to isolate from the hot oil trailer. 2. Bleed down the hose or hard line and pump or blow clean of any residual test fluid. 3. Disconnect the hot oil trailer and remove equipment from the wellhead area. Note: • Confirm with engineering whether the annulus line is to remain in place for bleeding down the casing _ when injection is restarted to the well. 4. Verify that all transmitters are functioning correctly and well pressures are normal. 5. Have CCR reinstate the high-high pressure shutdown on the inner annulus. - Post Job! 1. Complete the MIT form and obtain the necessary site personnel signoff. 2. Provide test documentation to engineering for formal submission to EPA (copying AOGCC). Revision date: February 2016 Page 11 ExxonMobll Use Only • • ExxonMobil Appendix EPA MIT Form United States Environmental Protection Agency Region 10 1200 Sixth Avenue,Suite 900 Seattle,WA 98101 Thor Cutler- (206)553-1673 e-mail:cutler.thor@epa.gov MECHANICAL INTEGRITY TEST (MIT) FORM Facility Well Permit No. PTD No. Exxonmobil- Point Thomson Unit PT DW-1 AK-11015-A 214-206 Injector MIT Type Test Type Test Date Class I IA Std.Annular Pressure Test(SAPT) Req'd Test Fluid Type(s)used to Packer Depth(ft, Pressure (psi) test TVD) Test Interval/Comments 2,500 Base Oil 5757 RKB ' One Year Cycle Record all Wellhead Pressures before and during Test.Note whether well is on injection or SI during test. If on injection,note injection rate,injection pressure and injection fluid temperature Note volume of diesel pumped in annulus during test. T START TIME: RECORDED PRESSURES(PSI) RESULT E 5:48 PM PRE MIT INITIAL 15 MIN 30 MIN 45 MIN 60 MIN S TUBING PASS/ T INNER ANNULUS FAIL OUTER ANNULUS 1 COMMENTS: MISC COMMENTS NOTE:Pressure must show stabilizing tendency: 1)Total pressure loss must be less than 10%at end of 30 minute test 2)Pressure loss in last 15 minutes must be less than 33%of total loss Start MIT over if: 1)Total loss exceeds 10% 2)Loss during second 15 minute period=or>50%of loss during first 15 minute period* See below*. For situation#2 above,you may extend test duration to 60 minutes,to eliminate thermal effects and illustrate stabilizing tendency.(on-site decision per Inspector). --E-mail this MIT Test Data Form to EPA Region 10-Thor Cutler EPA Rep: AOGCC Rep: Operator Rep: Revision date: February 2016 Page 12 1xxonV1obi1 Use Only 21 . �cF Tex ... iAN 2 1 2016 tea, /)„( int,^ EyKonMobil January 20, 2016 ER-2016-OUT-041 UIC Manager, Ground Water Protection Unit U.S. Environmental Protection Agency, OCE-127 1200 Sixth Avenue, Suite 900 SCANNED Seattle, Washington 98101 Re: Point Thomson Project Underground Injection Control Permit No. AK 11015-A 4th Quarter 2015 Monitoring Report Dear UIC Manager, In accordance with Condition II(E)(1) of Underground Injection Control Permit No. AK 11015-A, Exxon Mobil Corporation is hereby submitting the quarterly report for 4Q2015. The required information is as follows: a. Monthly average, maximum, and minimum values for injection pressure, rate, and volume: See Attachment A. Please note that the cumulative injection volumes were taken from the manually recorded injection data logs due to increased accuracy associated with manually verifying volume pumped from each holding tank. The temperature and pressure data provided was collected by the continuous monitoring system. b. Graphical plots of continuous injection pressure and rate monitoring: See Attachment B. c. Daily monitoring data in an electronic format: See Attachment C. The spreadsheets include data collected manually and by the continuous injection monitoring system. The daily spreadsheets provide manually recorded injection data for all 11 injection events conducted during the reporting period. The continuous injection monitoring system was fully functional. The continuous injection data is included with Attachment C on a CD. d. Physical, chemical, and other relevant characteristics of the injected fluid: See Attachment D. Relevant waste characterizations for this reporting period are noted in the table. e. Any well workover or other significant maintenance of downhole or injection related surface components: No well workover or other significant maintenance was conducted during the reporting period. f. Results of all mechanical integrity tests performed since the previous report including any maintenance-related tests and any"practice"tests: No An ExxonMobil Subsidiary UIC Permit No:AK 11015-A -2- January 20,2016 Point Thomson Project maintenance-related test, "practice"tests, or mechanical integrity tests were conducted during the reporting period. g. Any other tests required by the Director: No other tests were required by the Director. The following injection episodes took place in 4Q2015: • Batch#16 Part 1: October 9 • Batch#16 Part 2: October 10 • Batch#17: October 22 • Batch#18: October 28-29 • Batch#19: October 29-30 • Batch#20: November 9 • Batch#21: November 11 • Batch#22: November 18-19 • Batch#23: December 1-2 • Batch#24: December 24 • Batch#25: December 30 If you have any questions, please contact Ben Wood at (907) 929-4108 or via email (ben.wood@exxonmobil.com). "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." Sincerely, Agent and Attorney-in-Fact Exxon Mobil Corporation GMD:bw:bt Enclosures: Attachment A—EPA Form 7520-8 Attachment B—Graphical plots of continuous injection pressure and rate monitoring Attachment C—Daily monitoring data in an electronic format(CD with data included) Attachment D—Point Thomson Project Waste Streams cc: Thor Cutler(EPA) Chris Wallace (AOGCC) Attachment A — EPA Form 7520-8 IMP dr& 119FA US Environmental Protection Agency Form 7520-8 Database Template STEP 1.Copy this template in macro-enabled xlsm version using"Save As".Include Well name,Yr and Qtr with current file name. STEP 2.Fill in the highlighted cells with relevant information. Do not enter n/a in any cell.Fields(*)are mandatory. STEP 3.Enable macro.Press<Ctrl><Shift><A>to run the macro and check data in Dbtable worksheet.Save file and submit. Important:Please do not change rhe nncition of any cell below.Rn not rnnvinaste cells c -rt/,rlote row nr rnh,mn. OPERATOR NAME WELL YEAR* PERMIT Point Thomson Unit PT DW-1 2015 AK-11015-A REPORTING MONTH OCT NOV DEC INJ PRESSURE(MIN),PSI 212 320 301 INJ PRESSURE(AVG),PSI 1086 1425 1511 INJ PRESSURE(MAX),PSI 2061 1988 1943 INJ RATE(MIN),GPM 0 0 0 INJ RATE(AVG),GPM 88 120 122 INJ RATE(MAX),GPM 166 170 163 ANNULAR PRESSURE(MIN),PSI 12 3 9 ANNULAR PRESSURE(AVG),PSI 70 167 85 ANNULAR PRESSURE(MAX),PSI 550 459 475 TOTAL INJ VOL(MONTH),GAL 283,194 192,249 175,017 ANNUAL INJ VOL(CUM),GAL 1,211,296 1,403,545 1,578,562 TEMPERATURE(MIN),°F 35 30 35 TEMPERATURE(AVG),°F 76 87 84 TEMPERATURE(MAX),°F 105 104 102 pH(MIN) pH(AVG) pH(MAX) SUBMITTED ON: 1/20/2016 (mm/dd/yyyy) Note:pH not required for Class I well injected fluids Attachment B - Graphical Plots of Continuous Injection Pressure and Rate Monitoring I , I 1 1 , . .! i lI a o. i o o a o • 1 It i a �m f-,0 if m c o a i 1 $ 1 1 $ 1 ON 1 o I .o a '^. Io o 1 i ; i ! 1 1 , 1 E 55 1 1, • 1 j 1 o ' � i 1 , r 1 o ro j 1 . , ' ^ co ' 1 vi a 1 I: I 11,1 1 1 1 1 I ' ; i! { 1 1 . 1 i , oo CO o 1 ! ! 1 12 . 2 .0 m 1 0 3 I { i d c m Iii 1 I 1 ami m CL; 1 oQ w o m w 0.0 o i { 1 cr, 1 < < 1 a lll _ 1 1 1 ' I il l I 1 1 q 0 V II m i W ( 1 f t #( 111 j 11 I1 1 1 ! 1 i i l I i 1 j i..Q I m 1 m P o o t i I m ! ! j 1 } t 1 1 1 I 1 i j , i 1 jj 1 O Q O m 1. } ' �� y 0• i ! 1 "� l 1 1 1 ! 1 N j r in 3 1 1 rnCV CZ) 1 1 1 i 1 L I �� ; , l Q 0 1 I I It " o i h `ry i { ! o< `, j I O , I , { � � � 1 , , , I1 U r-I ! i .of # r ""a CD m 1 i 1 1 1 I 1 , r I i 2 o o o o o o o o o c. ..;._._..a , _._.._ t. ,._ _... ,..._....a.__t-.—._...___ o 0 0 0 0 0 0 0 o m CC a co ^ oi vi v m N . o o o o o 0 0 0 0 0 0 0 o_ 0 0 0 0 0 0 0 0 0 0 0 m _ z 0 0 0 0 0 0 do 0 0 o c a CD o co 2 a oN o co 00 a oN na oE c a r ry .: ti ,4ti ti i- o_ s v £ c U Ca ', It Old • m ° 5, , ' 1, 1 ' !„,,, , , - 1 ._, . ',. i 7 ; ''' ' ! 1 , , , ,i3 ' 5.,' ' ::;' , '•'-'' '4' i-,' : , 7 ' T-., , 73 ; .0 r3; . ; , ,, 1, 1 ' : : 5, ! i 1. ''''; ! ' 1 Is: Pn 0 5, ' , ;- o t:i ' , .., ; 8', i ' ',-, , - , „.. , -,-- :,... - _,. , 1 , , , 1 ! , I I I , , t ' I , I.. 5 '1.' Fs, `•,"., , I , i i-',', , : ,' ! , a I ' ' Y : ;.f, . ,-, • a 46 .: ..-' (9 E `,..° ; - : 1 1-1 0 8 g 0 , I 1 0 , , 0 0 • .. ., 1 '; • ' X'' g',, A 'r, 1 1 - ' 1 1 ,:.• , "-- OA ' :' ''l ' i .1'n'' .21 •-' o , - 0 I-- I ': 1..:5! ' ,'7•. ^ `41 338388E88E3 a_ .._ 1 , .. Jj 4110 ,.., li• CO Wda .., o0 N o 1 m 0 o o 0 'RI vi .1Oi ^+ 0 p06 0 0 111110 1 n N m o $ m o 0 m O CE' '8 ooO h 0 +o vo0 ' m $ o '. g o a o o $ Nm' O m m m mo ^ a m g m m 1. tn4 jm ,, m i m g+ - , 2,q d n wm 4 m �p m v o i b $6 O p m m m • 1 e m O j00 � ( m a t m o m i I O 4 m m a ' O Q O p ooGG =, m y� m m 1. ,O m b 1 0i O m , O O ti 71 M m O m O d 00 M 0, cn 0 trn rvh ri O Pim ry m 8 ti Q 0','=`; O N m °i m N o F, .A .ri G ry O o N I ,��, 1 oy o .4 o m -7I- 8 -o a o $ m Y f I N m 0 � 8 I i�,, ,-� °,_, Lc m o f ^' 0 , � > , 2 rvm g o m m 3 ry m .� 0 O __— 0 0 0 2 4_$ +' t6 mon, r T. 8 o % 09 m d' 6 1 8 on $ o CL $ 1 ',t 1 o $.. I .ati ro ti $ N q of , 1 ; ni o ' 8 8 9 ,1 8 8 a 8 , f I g,, nnT 8 ,o a 8 8 m T . 8 8 2 m 8 °8 ' N 8' o� � O 8 fir'. a y 0 �ti$ o m o v 0 0 N o=ti 8 N 8 10 o m m � , i m m T ' -y8 °4 d $ t o o om 9 0 8 0 S e m 4 a 8 0 O 8 9nn 't a '^ m m �;.,, 1 9$ ti m 1 8 8 8 0 N 0 m 1 O m a . O O 'rv„ N O 8 0 a 0 00 N • _ 0 m M O V O p Np O a ,1 W O nn I $ a 0 2 8 a rci n l N " 1. a ti , o o n, 8 0 m a 8 m N 8 a, om - o8 N 0 8 " 8 O $J $o Q C O m m 0 8 rv0 2 o N ;0 0 O ey $ o0 0 ;$ .ry S N tiw o ff .. o m i N a y0 - m o 0 0 0 0 0 0 0 0 m o 8 8 8 8 8 8 0 n `° m 0 m N 0 O O o 0 8 0 0 0 6 Om $ v01 $ 8 n ry H E 6 n w ; L • Wd8 CO • , , k en'•• 4 . , o a) 0 0 on A < d m m cli ri •• L'< A d oo en t, ' t 6 •cr d , , ! I , e.: 0< • A ' ' • , 8 , on° ; , • . 0 . 1 ; d .;:r d 1 i 0 9 ' A 1 ' '7". !!! 0 2 gi. '':•' 0 " V2 ! ' A ' 0 m. 0 1 I ro i ' .':' i 2 8 "r., 2:7 0 • 1 •cr A ! ; I A I , c.a j"i 1 ,-,-i ; • • 8 P!,! °G., ' ' •",.? 2. I 1 ,,,, .-, 1 j . • cn I ' I 0. A . , r •• 0< to r- A . , 1 4 0, 00 1 IN 1•• od 9 , o 4 ; , .7; ' 1 I ; •,.. co 1 " : o , P , , I , ,' .0 1.' • DI 0 0 { 1 I I 1 I „ 0 . ,,- • , 0 • -4 . I 1 , 1 ,,,.; •• 0< 4 m I 9 m ! d n I 1 , 1 " .` I 8•i 'Y1 .'': . . 0 ret • I A t t A <•.,-. I ! t ' r- I•-, .-4 I•••• I ' % , ' A A , r•en ! I I , I ,r j ; " A t 1 11 , , let •--1 . 141, I (VI vr4 1 • ;A 1 o ; : , ,.. 8 ,.;9.< 4m ; ' I no • / , 0 N N. 1 ; • 1 I 1 t r. .•< 9, m ; ' i , , ' , f•"°2 m d , m ' ' 71 9 m .. m m ' I ' 0 , . 8 I I • ! I I on , i ! 1 ,,,, - A 5" re I o I I I ; I V. ! I 1 i . • ‘' 0, rn ,i 1 ' $ I ; . Ii rn ni •,-1 ro'V , 1 •-• 4 • A 1 , , / 1 Ei 9 o_ 4 4 ; , , • i1 Lr , ! , o ,..,•, on ce, I 1 1 n '''' t' " 1 ! , • / , 8 2 en 9 m ' ' , ' ' ,U ••0_ cl• Lel 0', ' r••••• c,., N • Y-4 9 cri , , I ' -•• o 2 9 r! m . i, c-r-' , I : ; A A '''. 2 ?, • , . p, r••4 „; , , ,-, 1 1 i • -8 ,,,, ., ni I i i , i 1 ' 0 ..a NI r CL ., IN 0 0 ' ; NI NI t • ; 0 ,....: 0... 03 .1 1 • t A A .-• 1 i I ! 9. 8 2 4 9 m , , r, ,,,i ., - (N 1.. o I I I a . , n ..! i-,a m r..• CC ; , ; ro r% I ! A i•• 4 ' CL . , a, . , . :.".', al E ; , , ! , ( 0 I t ; F ; : ! , I cci L'`' ,.? I I M I I I r• m 1 I' 1 LL m ;•• 0 a m m; i 4 1 1 o 0 ,-• o • Li, •—• ; A 1 • ; rl '1 ! 1 s'• i A i 0 0 ,r_II om , ! 1 C, . i i 1 — i . I<- 0 2 A 0,1 ; 1 1 N NI -' t•• °.- •-; n' 0 I I 01 4 w —, ,,,, cr) 1 I 1 '-'• A 1 ! .0,,i ;I ;1 1 ,-; • 1 1 I 1 8•ri. 2 :fi 8 ; f . I ,.,,,,, . •:,- . , 0 1 1 f•A4 1 , rrt. r urt, er-1 ' • Z--1- 'tr! 1 1 1 1 N 0 2 iri n ; . 0 •o•a rn t • o I ; 1 F., 4 m m 1 ! , 6-,! t)g '.4,.' ,,,:,. ! 0 , ; . 0 1 , , .1•!.c ' 1 A tr-i i I 1 'crrl t ; r rs 1 i ! !s! • , cr! 1 om 1 I 0 ' ' 0 ' ! To ' I d I . .-1, .,-• • , on ! • • t ' 1 ‘n.Ini I 1 • 1 j A ^ . , ; 1 ' LI4j! 0 2 ret r 1 I IT, ;•• Oo_ st an I 0 I I (NO n 1 , , 6 90 F,,,, ,,,,, o._ in m , • , ' 4 ! I , -' 8 , • 1,,,,8 2 tt 4 ; no , : ' - rri VI 1 , 1 , 10 I I I d 0 m , , I , r J t, r-t 01 t ! R ; ; ! •-; 0 , 1 d 9 ! rri r ,....„,. 0 . ' 1 1 , • I , n ' • 0 a_ ID 0- ' ; ,-.?, I ! ! 0 R, ; N .1...„ I 1 / i cn • v.... 14") •.,-; , A A , I , 1 I I ! , : I . .m 4 • 0 o_ to 4 • ,,. m IN 1 'I . , 0 ' A 0 co A t i , .,,ttr;N' 8..2 ..,rr-- r, ' rri o CV. n c ; , 1 1 . 0 ' ' , m , ' , (NO .......,, m 0 , I I 1 ' m m I • M m OD --. 4 I I 1 0 o , . <• .-1 . A j , 1 A in •••'' ' ' j I ; • < • I 1 I ' 0 2 eN 9 ' ' 0 o_ cc to : t•I' / ' t I 1 .• . : •• ... . 1.11 A e- ,..4...! • ! 1 . CV • 01 ‘••••4 .1! rf : I i I . . • • . f ! co n 9 I , (N o m , , t s- I ! - 8 ,,- ..-. 0 a) A to Ili •er m ri •••i d 2 LT_ m 0 8 8 8 8 8 8 8. 8 8 0 0 q0 m cc d 0 0 ci 0 0 0 d 6, 6 o c i.71 a cO 8 8 2 .?, 8 8 2 e, '4'. .•-., 11- .- E a 4:t 7, 7 E ts 1 4-. I kI. CO 1 MS • CO • I 0 ' . ' o • c 0 ,r, .,.. -; . , , 0 , , 0 , jj.44 C I 1 / tr i •• N-1 ut, OD ,,,, c • 1 c' 08 a, ,0 0- , cr • , . ; oo o oo m Tr • 1 i - m o • o , .-.4 . 2 A In ,,,, E I I I I g.N. o < Lr. 0 r co .-1 •Ir roe , w , , I , " in or, c M 11'' o 2 m • 1 • -' o Ln 0 e • • - . ; 1 < oc. .; , 2 . . , . .. st 3 .34 1',',',:' o 2 m • no m- • en „ . • . 3 c- 0 co c • 0 m " or • cc) a L.-, • o o c • , m- • o o a, < 3. m cc) • j ' on ''' o < '32 O c m 0 0 • • len 1 . . . . 1 • • s P. ts- °° tal 9 1 .t'o r-, ° ;II W. co rri o trre , 0w cr • m 0 CO co 1 • ' 0 Cr) or, rj'' . • C. 4 < ,s; . 0 ; c, CO CO cc, • . t ' 0° 0 2 ',72; °. m , . m I co' o < • o c O•41 co r 1 ' , , I 1. ,0_1 co <2 Na t.'-' ,_,c I'• co ,'''' • . mr c o . , •• o .-7 O4.1 , 0 • I . °J 44g 0, . CO 0 . 2 1. o 0 co. N • I CO' 0 „, ., CC We. ' ,... - . . 0 cr, I 0° o 2 t•::ttr' 0 co ' m oi Z• o 3 • op o < c co 0 • m c 0 • to) 1 1 cr:o 00 3, . ,, o 2 m • m ai op 0 < c co c c „ a o o , m , 0 • • or, „ . • ' M 74 • ' CO 0 „,c . CO u). ., .. 0 • 0 N , 00 , , N 1 r. , " • ' ; . ' • • a, 3 ; o o < 2 c_9, . , 0 , 0 2 , ..., , , . ,-.,, ...., 1 , S , 1 ....., 1 . ^ co r, m • . • ff,.,3; ; --; o z a, •" m co 0 0 , .1, 1 ' c 8 0 2 0-; -! , ...., , ., ai • ° < 89, 21 0 I I , 0 0 0 0 0 ' 4 I in' 1 I •g a 2 ':0,' '1 , . 009 en 0- • , ; 0 8 ,..- , 1 F,, ,i,' :,,1 cc.r•-•-':: .0° ; cr,a,,,ia‘c' ,.:7-2.,-°5 loo I . CO in 01 '4 0 2 6 • r, N. 0_ i , I ..,r-- 0 o < ,•••• 0 E r' 0. rsj • 4 I • I I 1 ..7-,'9 Lr. . +ft 111 . . 0 r.; . I . •—,, N 4 ‘-r C 0 0 I I 0 0 0 • ; . • N •f I r rr,r' 0 S N. 'r! m I ,,,0+ I 0 ' I 01 °M 0 I 4 1 tj S J I . _ < ..- M 01 0 .ct 0 0 i ' .-, I 0 ' ,..1 co,-, 2 •1• co 0 I ca o i ; I I ; I •s-4 , .La a ,.,, .-, ,... • I ! ,,' I ,.... 0 < 0 C6 M 1 4' . ,-. 1 ' 0 0 •-;'''' -2. o i i 14 o " o ; I „-; 10 1 .R . . „-,•-, . ,-, 0 ., 8 -, 0 0 •r-- -, ,c, , I I , , en 0 0 . • , , I , + 0 c\I , pa II ', 1 rr2 8 'Aa ^ - 0 , .... 0 1 • .. ,M M 0 ; I ,.j., 00 W' 2 2' , ,00 t 1 ,,,,,-, c 2 ui, 0, I o , 00 • 0 c:4 . 0 r, o ,, "--., 0, < CO . , 'M OI 0 I • Co 00 I C • V4444. ' I jK ;' • ,r,0 0 M ,c. • 0 0 0 . 0 ,-.. „. 0 0 Lo 1 ' 2 , I ' N. < 2 -. - I . < J 0 0 ..9`4j 0 2 .4 ‘40 \44... 7 N • 0 0 N 0 0 • ,o 0 . • , • . I h•-• j 0.- NI • ' < I o o MD o "... . 0 . co q 11110 cs) , C\I ...„ I N M 0 at r..3 , o 2 00 • N • . rs O. 0 ; co 0 ..4. . ' ,..,, 0 •, N N 0 0 M • j • 1-s•I ; P,'jjJJ• • ; N ; c•-.3 ..., , r i ?„; ' 3 ; o 2 r•-• LO 0) I ' 74.0° •• o_ ;A 7.0 • ,... uj, .1 . l. N. • j j crl 0 CO , 0 , 0 0 , e . , -,.. . 2 ,-; • 0 ; .1- 0 CN1 ” co: ;.c. ' ; I I ; ..0- o ..+D ,-; o 0- -, -; en ccr, ,a; aa'-', Q u, , I ' I ,011ka, 8 01 0 ?..+"; ' V, 0000 2 i,t '-' 0 0 , oc; ol tri i n; ; ; O.,-, o 2 ; 1 c'''''‘10 ,•;,.. -; 00 W , 0-.' o , o 0 1 . 8 ..,.. -. 0 0 0 0 0 0 0 0 0 0_2 ..-, e 1 o 0- . 000000000 0 0 0 0 0 0 0 0 0 77, CO r: O ..ti mit M en r4 0 0, o 0 8 8 8 0 9 0 0 9 8 0 00 00 . „ „ 0 0 0 0 0 0 0 00 ° c 371 0) o 00 ,70 ,..,. — . 0 0 0 E „ . N 0 00 o < N 3 °- C. < ...- — a_ ..c 2 2 •E - t G.> 131 I I .., co 1 v Aide 03 • • •-r ,., i r•-• . . o o 0 2 ,ncl, Lc, to , , co •,i - m 10. 10 — 10 I 0 0 0 ,LL9 0 m 1 , 1 , , . . ., ' -r•-• ''.1 '. r 1 0 . o •-• . h r < r.• . co ro m 0 m N 1 8 0 03 0 0 " o • • 0 In IIIP 0 0 o 0 0 41.6 2, 1 0 M m 0 m 9 ,t 04 m < •-• rt., 0 , ,, 0 •e_, 2 m ff, 0 „..,„ ,..... ....,.. ,... ,c, N 0 i 11 0 0 110 I I, A—I i ,InI 0 I 0 0 M i l Ai 7 0 1.11 Cil . I • at 0 o , o $ co 0 c^ co o ',21 . • 0, . • CO co 1 co m I 1 1 0 M i t t't 0 0 rn I II 10 I 1 , 10 1 -, -, --, 0 1 ,,,, r, .1 01 01 0 I ").0 4 .4 ' CO 0 04 01 2 „ 0_ m I 01 10 0 . a) - 0 i CPO 310 Loa cn 4., '6 r, CU mi 0 1 CO N 1° N E ' , I , •Ir <I drr I r , m M m , I 1 1 ., 1 1 CO •ct•1 8 co a 1 1 cr•hsm cvd° <2 <"" mr.-c n- , ,., i ft crI o ., , . r, 01 1 N • ,t, > 0, ,0 ,, 111E1 10 1 .;;;;;1 tn N •,5,1, m 1 , '.r•-• 1 10 0 IN 11) 0 ' '-•0 2 a) . co 1 I *3 co N 01 01 m i 0 0 CO 10 o rn o a) . • , ro m 0 ul 0.0 1 0 o co ul 'I N '41 N al I i 0, 03 0 ; 1 I 1 471 N 1 CO 0 < 0.1 01 to 1 , 1 , Ot,0 o 0 0 ' al ' '''' ' ' Lr) , . ,, 2 oo N iO • 1-- i CZ, ' N ' ,,,,s'''' ,,,— , 11 0.1< < CO N m m 4 t-' 0 In CC 0 t-st CO ICI) ' t .t4 1 t CO 0 IN c0 'N. t•o--. , ,_, ml 't,Yt 1 0 1 . . , 10 1 LO 1, 10 , 1 o c, I ff, C , •cr , ,mi mi m co ret, a) 0 N.• 2 c" 0 ll '' m m 0 I I co E , 4.= m , , k i . 0,' •i '', 8 - O 1 , , 0 , r^Iv o 0, o 0 0 o 0 0 0 0 0 > 00 0 CO 0 0 on o O ,- -1---- 1 .1----- 'D I— _j, ,o ,71 oo r, to 0 •,,r co ot., . o Z 0 o o C 0 0 0 0 0 0 0 C a I 0 0 0 0 0 o on c In o 0 o 0 o 0 v, 0 o 0 0 CNI N N .-iL ..-4' < - a a CL. * ili i'L E -C c,. o. I- o .N. . LII Nide m 0 O O O Lo N <y O1-1 i n O Q N N O t0 0 00 m m •v ( i.n.0 QV iD O Q .NN Ln 0 i f • �D V o0 I .y K m O 2 N < ri ON iO a a,, V N o '>] { N m Q1• O 11111 i to o 2 CO0,-, lD O Q O M i 1 V M• I m m Tr m •O COGM x0 T ' 00 Q N M ( i "'81:1 CO , co m i j m } • m m O Q r0i 01 01 rn ` rn rn ' 3+ M 0 I O N M NO ¢ Nm 41 O • , I Ln n N M Q O mtlM ' ,' d, MMo In ' _ ca O� O M .. O { T f O1M MC o', 0 Q N �m vo V Gm 65 r M O • O Vp N I f Ol co Ol• i , V Q N M I ( M ^ M Gl O Oa .N-t m 1 1 1 o m gg. on a O Q .m-1 O 1 M 1 •m SD i N O 2 N n i 0 j M in IA ,^r c o Q , v m i • m ( `n 0 N O ` M O Lro1 M O a .-1 V M i M M . O N In O� N In N, t o o M m • �,ari 1 do (".'. o < ,..+, v 0 0 0 Y CI r: M O Q m 0 .....M o o 0 2 00 M i (00 o 0 0 .m < .-� m ? 1 i j7� `'° dr; .m o t ut1i 40• j 1 oo Cr; 0 I �� O Q , o N .1 0 '0 I a. O 2 0 0 !0 co i O N O • O N N N N .� N i W • O N O N• O G I 1 f N N N 1 1 N 'O O a CO LO ^3, i . ( 1 O N N B N M W 1 1 O g� T Cr; O Ol •.Oi �..+ N N 0as . ' 00 g .y O Q .-I N 1 1 0 : 0 r, N N , t L1 - i M 0 Q _N ^ J t , N N 00 j a.bl CL I} O O •� • O O d , v , co, L6 •N 00 Q N N ( 1 ipp N• N N a i N ~ .-t N 1 I 10 ! N O 0 N O O Q ti N ' .O ` O0 N ol 00. N C } IM I N M • DI ( ti O Q N 1 OOi O m 0o 0 N O < . N ` T 001 Cr; Q ti N O 1 NN N O N C m , 1 M w 000v . '6 o Q .Ni • I rn ! , ! m m `'" '0 c g CD 40 m 11 ; ' CO 1 '� O O O 1 1t m I; m 0 �0 Sc:' .-t N a o- N m 0 m YEN • j n .i 0 d N N 1 001 to poi "1 `gy • m .m0 n1 • , , M , "'1 m O 1+ N .. O 0- .m-I N , Ol •cr m 0 i N� .-t O • , i m M co 0 O , n I 1 M ', m 0 1 I O .-I O S .-I O i Ol ; I .N-1 001 • •0 -',aO m oo E m t r+ 0 4 d . •0 i f m • I I . 0 n-i + j N:'m 0 N N ( , m { m I mo o a .Mr v m , o 0Ol 0 CO 0 ; M ! !) M 0 mCO , � a .� m f rn 1 m m p O N tt �+i m /• O tT �i. 1 N 0 .•• 0_ M • N ' 00i ( i CO m N I O N 4 M ( ' i M 'T ; I O a NI 601 I 3 II r--- 0? in T , I toy{�' O a M N ( I I j 0 `, 3 0 O f 1 `0`n O O 0 }{ I M I ( N O d O i 0 ; f I to al I w I t m0 m o0 O t ; 1 O o , m in O2m O d - O2 1 t 1 C) I 1 i CO O ^1 N `* ; m,nO m ! 1 j 0 i i1i 0 .Tq I VO.n 0 a l0 1 1 al : ; t M on no: i{`C 4000 c 1 1 M • 1 i M. r 0 0. 0 ec, 00 n� O O nO 1 O N 4 L L ^ , • ••op O 0. ti l0 + 1 M ; M O 00 MO O , O 00 0'r O O a) � ' T6 0o a m 5 ~ 0 0 0 0 0 0 0 0 0 0 1 -'— __ rn....... __.._.�� ___ iFt CO00 1� t0 In V COM N N O y Z O 0 0 0 O 0 00 m _ O 0 0 O O C to a 0 0 0 0 o 3 ' E N— Vl O O Ln > Q m (V N N a 1— 0_ Y co 4t v w E C fi IE IN de czm 0 r...... , o0 .. ...: al o 2 ..; • ; 0 o o rt, III 0 0 : ' . !•-• . , ,.... , cl- • • i , A • •11' 0 eet ' r-- u-, , , r-i , . cl; r-i 0 6 a 6 LI' ; 1 : • 4 1 " 0.1<, ,...! 0 .1 N.::41. tr; , i•• 0 < cr m co , , I al nr. , ; 1 ! ei ai; , ; : ' T-i m ,_•„ • !..0 0 ' ,;,-; ,..... , ‘1; • ,cl. '..-• .. 0 M 0 r.'" ...4 0 < < < a r. .1 NI ; I . 1,1 m• 0: t''' .7.. °I- ! ; , a •• 0 < a a a to 0 r6 I oo a r•-: 'I . m I , 0 , .. ,i, < a a • o . . : o ; 0 " .1 , ib rn ni 1 1 . 0., • Ln 0 2 rg 0 i : , -- m'm nic^. , . 0 , . , a ni •• ,.....; 0. . • et . . • no ' ' o rnm ma! IP ; II r........!....a. 94!0.• 0 4 ,.....c!" a‘ nnN ma; ,06.1 N , I nit ' 4 • I cr, m ma; 0 C; ° ; 0 It , r.-.! ';',-.;.. „.., 0• < Lb o 00a I ' o 'Q^I.• o• 2 ..,,"° 0..i''.2 ; i Lc, 1 rn ni tO , ; I On . cm , ' 0 2 ',‘IIIi 0 ni Itt:.LrI o 01. N,., , 0 : Ai < ,,,, ..-, , ! o"'”, ,-. m . nr ; I 0 1 . ; al ' ' 0 0 cr, , . ni. ,;:,• < ; ‘.. . ,.... , .... •:,; ; 0 : , ' 0 ,1- et o N ,, m . ' o f ' h %.0 ' 1 ' r, La r..... ,i ' N • mr....0. .1 •111e , I I g I 0 crk 0 < m a r: • en I 0 et i I , a° el t I I 0 1 o Cr cy;ion I M. . „ 000 ,! 0 41 . ; ; N • I . : 1 I 1,1 1 ; • 0 `n Cli 0 2 krenr 0 2 0 . , , , , , 0 r-v •a'n a i 1 t •• 0 < m eq Oi. : I "I I m o . i o 0 2 Let °I l co . • 0 a ni , In ,, g < (ON a) : Ni ; ' I . 1.D o- 13 i oert : to t i 0 cn , 1.:1•I 1, - r.... o, o cn .-1 t.... , . i -1 T-; 0 < ,.":".1 M. CC M , N ,i I rn r,,, 1 , a, -; 40 1 4 cc O. 0 a_ In ' '', IV <X .1 1,1 .:i•. . 1,1 E , , rn ; , rr; I r4 'ID II IIII I 0 Itil I ,IN °.. oet 111 4 . ah cr' M., mI I ' I- I I .--.-,.--, 0 ,,,,,4 r..°0 ....a. 11 II, , 0,,,,,,I,Yi : iiii . up ccig , 0 )`,,' I I 4II 11 , no 0 4 m 0 " , o kz, t-c I 1 I .•••esi 9. 4 rn oi . en I. 00 - 1. I 4 cr, ,,.; 6 . 1 . ;0 A Ti• 0 g K... , ,.-, ; , 1 ., 1 ,.; ; 0 , 0 .. . .. ,.._ (00 •cr 1 00.: ...;...! .1 01 i M : rn 000 ' '0 in: " * r•-• , ; ! rn o 2 •,:r o o , i - .-1 .. o. 00 tic i 1 cr? rn a, Do .i m .1 . *1 •;10 N 1 I N m . 0 2 , 1.11 I I 0 I 1111 0 1.- N s'; N . .;w;•:1 9. CL. 1,11. ..1 .•.1 .1 m i , a., t, '-' 0 , I ; (ri ; rn ; ...0 N: u) ,-1 o 2 , ,-,1 I s . t•-• ; , '0 0 ; 1 I 0 -; 0 nC, iii1' .! 9. ct ig pi 1 a rri I 4 i I I Lel ni r•-• co ..-1 ,,, I I - 0.0 1 IA ". ; . rn , t . , . , N , .-: ei 9 0_ to oi ; o . : t o I-0 Nw i 1 . . . , ; CA r.r•I , I.11 4 " . rn 1 en V-- . o no ...,6 9 0_ 14, m 0 co CV t,y;, 1 (r:O'.' 1-I .1 ......... . 0) ...., r, , , ,0 .• M. 1.0 nj p III ...... ...., ....... - ,c, co ,.." M Is. I ! t t I ' r-t !" .0 .. , 1 ;Lc 0 2 rli `r•E' . • 01 . - . , . , 1 ' i , \. '', ' m : t r-. a M o , ...o r',. 4 N LD 1,1 LO N Im I , N TY 0 e 0 N . S - 0 n_ cn • o ,r 02:1 oo 0. 0 al ni , - o o_ .d- • <I-0 •cl; 0 Ir••• ; CI. 0;;.....: .,. M 0 ,CNI , , 0 ,a 0 1.1.1 rn••••.... ; c,0^ . • 0 c,_ co • ker 0 0 .1 ''' • , • ; • 0 • IT---- I 00 a, ; , , ... ; r..1 ; , . ; 1 I n- er, rn Lc ; . ' ' i i co I ., . , : , 1 1 . , .71 •t- a o o o o o a . ' • o s- o o o o o I ', ' , GS O 0 0 0 6 o o o o o . • , . I•ID =a r•I 0 L11 0 ko 2 o o 0 o 0 o o o 0 0 > 0 0 r: 0 Lei 4 rei N 0 0 "I'ett2 Z i 0 c ..7 6 E -o CS1 0 < . C's1 1-• — - .... cu 0_ 4:k 2 (^,3 E •E' 6 a 1= il .0 I c..) it • 1 d8 RS 0 0:1 r` m m m o m O ni m Q lD N o M 00 W Crl tD .-I 1- .i • .y • O ul U1 N m Q r\ 1 O In N O 4 o r` ri Q i?) n I ( o mo In co m m { i I .-i m m m co „, V O { 1 m � aam o' po j m ,y00 o 'm o m N l0 0 Q ,_, O1 , j o N O O O FN N oc C ^ n o ' m N Q l0 00 O O 1p Qt ,y 01 01 CO m M M1'; m N. o , g n uo V N _ < Z N. } ' 1 .i m m N 1'S+ ry1 1 1 m 0 o Lo C ti 2 R co V c Q l0 O O O N O N m c j t0 ON Q l' 4 I 01 'y Ol N N 001 O N o m N m R lv 2 M o .p - 1 m ,... m o j p .-� to N kr, o O O M N n Q co ' m to 3 m N 01 o p o m '” Q .t.1 m ! o 0 N h I N. m N. I M #' ., N rn N Olp 2 O N N i.Y Q ce N n o O ( b o o :. N O to 1 co Tr 2 ui co 0 ,,n ,,.,0 1{ti Q y„1 I 0?o m0 }}( IC N o co O N Q o } h .ti 'y r-- ,•-, ' 3 } , t,I4 m n 0 ,my 001 .+ � ,n I M m o o Ai ¢ ,n o u1 N. .i .i n r re' 0 o CO 'n 0 CO ,n C y m c0 O� m m o t 6 m C m rri CO I 0 N < e o a m' CO o co m 4 1 V 2 W N W m e-I M c I oltio_ Y, o � �1 f6 -, 0 �.� 0 o o.0 o m m 2 M n r r i N v I co 1.-- 0_ V W 1 { r C7x O co 41.ti ,4i to 0_ I ro ~ .r 611•O M .m+ i { ! �O..f� o m 1 r d ',L1 1,.. d I E ! , 0 0 I c un i o a o in r 1 o m °° f4'O N 0t 0 m a_ V m fir""-' 1 N 001 Ol 0 o d C I j ni 1 ' m • D m or! 2 M 01 ! j N Opt 1 rn o_ N m 'I .ti m o 3 f 0Ln koio m o ° o ^ ' m ..I °i o 4,'a 2 n O1 a i co p o d' N• 0_ N ' .i en Nm 4 N F I e 0 0 { C { en N Om. a_ t00 N f ! I 1 O 01 O '� • INm 4 N 6 j { { O 0 .i m k i �', V 00 O O - ! '4,O m G N j N aoi 0_ m N m i l N romp CO I,/^) , E 1 a m ,n k p f o d° mrsi °° a l° . } m• • c• Q- 0i co w Coa o° Cr, 4 01 N.i N a 1 + m I, ' m F, ,, �rrl� o .. 2 ry H l ' - LJ N CO 1-01 m O 1 i 0 n p1 T. N • e *rt 01 ^0 tri } o m ,-1 m j f m if) ,V M 60 a °m0 N 0 0 r e+S .-1 " ( t o_ en o N t N a• s ^ p j 0- v rvi -I1 ' ( 0 0 N d1 ',1 O1 ; 0 N 0 _ 0 0 r r, 0 0 0 0 o a a. 0 0 0 0 o t 0 0 0 o o 0 W t EO . O N 0 0 CD 0 O O 0 0 0 0 0 0 0 tL m J 000000000 ', 00 N. 1p V1 � en N. N 0 y CC C 71 CC) a E N .��yy Y Y N lF N W C 0 III' I1 03 Aide 0 CO .. ad 0.5 a; CO . La cri o o 't. 00 00 . 00 00 h CO , rn 0 rt; M 0 0 en 0 2 0000 co 0 o rn CO .- N 00 . 0e, 0 , .-0 Ln . . . 4 • c0 , 0 r...; a, o, a r.... . 2 o o co (40 , . , ',rd. - <4-• > c . ...., .-. . , . . 0 . 2 a a . „,,,...,.” .• 0 . E r„ 0 cr, ' 0 0 1 m 0, , rn • rn , , . { ef, • • ,.' , .0 • a) 0 h 8 , o 4 •, . 0 • . h -a 21--n I 0 4 r.S . o Cri 0- Ln 00 0 rn. rn • z 0, rn 0 • . •, • 0 LDN o a o . ; : o ; o 4; ,,,, 1•••••• 4 0, ; : • in on en 1. : : en • rn M e a , On- rn o T-1 en • 1 0000 4 °- , t. en ..... r, 0 , mew 4 M 1 ' en 0 , , 0000 0 ,S, iff , , Cr o 1-1 2 .4: .- 0000 . er 00) en 0 0 • en 0 N h . o 2 en h h or, m 0 000. h LO rn • 00-1 ,I. CPI 0 • r, N 0 h 0 0 N 00 71: ••• DO oi Cn . 00 00 O. h h rn • h h en . en M In e rn 00 0 en 2 ca 5 on 0 0 ,X, M °- h ih en. rn • en1 h 0 • 4 0 4 0 LO 0 0 00 00 0. , to h • M . . . ro • rel rn .1 . 0 ' 0 ,..i o 2 000 co 0, 0000 ' re; ''”.. h • M . 0 0 0 h 0 0 , 0 h 0 e••••1 . <.. •.• h .1 , h • h h 0- 0 . , . . 0 en . .1 . Nen 0 • h LI h 0 DD LO 0 00 M 4 4h • • h . . . . .-4 Ln h in re; N . 0 0 en 4 h • 4 00 d n., h 0 ,,,,, 0 a °0 8 a 0 0 . 0 2 L,., ul h • in h h a.• 0000 . h ' h h oo . co ,n co a 0 o a ow . o0 000 o . . ko ,. a z h • of . GO .i 0- rn 06 CI) t 00 .0 h . 0- r 0 O. N . , 0 h. Ln CL •0 . h 0 h . . 4 en .e LO 4 h • • . h h 0000 . 4 : el . ,h 0. 0 0 h 2 CIJ o 0 . 0 PA I m M 2 LID 4., h h • LO , h ..i. 0. 4 h a. r•••• ce 0 0 0 0 h h 0 , CO I t • LNn h h_. CII . h ,e.' .02 00 ,r, SO ni , CU LO m ' :-. Q- a1; .; . 100 , 00 h .1 h E . . " 0 0 0 . • 0_ , i 0 CO 0 2 Ln CO Z h : en O. 4 , LO .1 1.0 el . 0 . . 0 , m , h ul Lri '... • 0 00 0 in in re.) at 2 en • ,,,, . •h eh , , Lei i.,, c,. a ,ri C v., , 4 0 . . LO , en :0 0 I m 00 0 i ID .o r.... 0 . • II) ,r, M 2 Ln Ln 1,,,.., h t_r• . Ai a. a .0 .0 .-.i a , .010 a 0 LD tel h W 0 . . • 0 . 2 o r., . IN Ln f 00 On . ,, 00 0. 0000 , 4 4) en ri in '0 0 en ul 0 Co m 0 • en ! •0 . • 0 IN h hD. 4Ai II)4 . Lr., ,-1 .000 0 o o 000 • ..-4 • 6 . rs; N , ,. 4 0C, ..1 < 4 Co • .ei t 0 en 0 . 0, h 0 .4 N ;r.,:j . • ,,.. ,.o rn 2 Ln 0D IN . • h 0 ••-i < 4 d , o O 4 0 tii. -.1. . . . • t r, N . Ln Ln h .0 < ._ 0 0 4 m . .1 en 1 0 ' h . . ,./D Ln 0010 0 ..-, . . , ., . • h o a 0 < 00000 a. 01, m a. m ! 0 e---, . 0 00) 0 , . 0 01 rn .4 *3 :104 h • . . N rn 2 r. Lo LO ' 0 0 < 0000 0 o 0 . r co 01 4 . • O 00 0 • 00 m , ni 4 h • 6 < I,,,' 'eli- : . Le, Ln h in . 2 0 < o a. I, Lei . N . ; 0 • M 0 0 01 h 0 • I, M in d 6 < 0 0 0 0 ;7, 00 en 000)4 0, Lel 0 •,,,, Ln ,00) -, 4 .t. to 4 ; 'D. a 2 m n.. .....: 5 < 0 . , cr, ,,. CM I .....!-. l'..- ., . . . . M ... ILO '''''' h . h 0 .. • ih h 0 < 00 in .co . CV IN ua i • - - M ...-; ..-' .... a 5 < LID a . , h h (NI LO °' 0 ,JJ • N h en ai a Lo a 0 o o 0 0 o o o o 0. cu ri, 00 N Li, ..; 4 rri Ai ,-; 0 o., En 0 0 0 0 . 0 . 0 0 0 0. 12 I 00 0 d 0 a no a 00) a. 0 0 0 0 0 3 0. E Tr , 0 to 0 Le, C•1 h. 1, .-1 .--1. 1- ...- Cl. ..0 CU IN d 9 • 03 NN a1 i o O_ ®00a 00 66ft 0 o 00 10 �mtll • H ^ W N n a N a O _ no m 01 ot of MN O, � a ul Nmo M ^ N LA n O LriN O O E® N N o n a N N Cr, me.1 .-i m 0 0 o n .1 ti •m 09 6' 13 11111a ynq a a vni ti O1 ni d m 0 j N mO o0 O{ ! to o m N °? 2 O .y •y rn o ®® n N `m0. N o m 01 N m i a LO 0 m ry i4°.!01 allo a0 m N® 0 000 f •O o a vni . m 1 ! N 00 II �. 13 Qci, Ln 2 .10-1 c ° ! II tom I m`a N M M 01 CO 01 10 '+a 2 N i1 Ell Nj N;a 0- In N M M ... M ..f••• ! ; N N m CCEl o - i !v, 0 O M a 0- .1O- a M 2 O M Len ' 1- o N o ^ °I' In •a N N N ;- 2 N r! N N N e a n .•1 ^ tll i0 I m l0 O • N h ;O _ n a M uo ' ' N i N O. .-1 N nCO� O 31 00 ` N ,a 2 01 N W M El o- N 0 1M a `" m f0 0 ; � N ON No 0 °M13' 01 O.oo CoCL o I ` N..�._N _�... E O • ® m yCL M El 0® EllO N 4 _ v 11 N 2 N I e+i ^N N i N a ! I O El rt M 10 N M ereI .o I ry a lNO l0 7 i O ti a u., to a m 13 Lo 77 m .i a a '1_". 0!O 0 m O 0 !i UMi ON a .Ni N 0 Ol i1 ' i 1) Q 1 N en a 1 M 113 rei m cri "' a .M. N o In .y m i l a1 0 o Q m O 1 61,m a Vol N i 0 ®_ N I Cr''.n ni ...,°' M N i ' r0 .,i a m In 0 �® N N m .1 m M ~ 1 ( N 0 ."1 0 M n i 1 en.,Li a N ui o co .--1 on `" N m an C ! I i ,-1� ,.1 m rn 0 2 a O1 L 0 01 a ^ { Nria .ni N m 111 Ul ai CO • L0 W N-• 0 N N O m on Len M O 01 .Ni a a.•1 01 M `� ! OSA O ri Ol 0.1 IIII3 r..E m rt o a m ro m ' ®® 4 N Ln i .e1.ti .-1 .-� N Rag a o 0 clog: a M rl Q n N �? N M o a m 3 CO OF M 00 O c:,3 1 CO J 1 CO ,ti 01 01 toi cil L V W N 2 VNfco O co m 13 12 ol I an 3 I a I V..1 a .' 01 o E a,{, m j ; ,b 0 M 4p i 4A.;,� Q N • - 0 0 0 0 0 0 0 0 0 N I 01 Oi O O O O O O O O O H 00 n to u) a m N .1 O CI O O O O O O O O O O O a o O O O O O O O O O O m _ O O O O O O O O O O Oa N O o 0 0 0 0 0 0 0 o . a Nn o CO CO Of N O 00 l0 or N 3 a N ^f .4 .ti .ti .-1 .4" H m 4# w y E .0 a a P RS 4 1 f Wd8 00 Attachment C — Daily Monitoring Data in an Electronic Format Attachment D - Point Thomson Project Waste Streams Appendix D Point Thomson Project (PTP) Waste Streams Physical, Chemical and Other Relevant Characteristics of the Injected Fluid 4th Quarter 2015 Exempt Typical Primary Constituents Sampling Conducted or Waste Streams Exempt Sources Generator/Process Knowledge Drilling fluids,muds,produced water,and other wastes E&P Exempt Wastes • Drilling rig operations associated with the exploration, Generator and process knowledge development,or production of crude oil or natural gas Non-Exempt Typical Primary Constituents Sampling Conducted or Waste Streams Non-Exempt Sources Generator/Process Knowledge • Incidental non-hazardous wastes generated Non-exerrpt sump by construction operations&equipment Water,trace of motor oil, glycol, PTP modules and shop sumps- fluids maintenance diesel,hydraulic fluid Sam pled on 10/1/15 and 11/4/15— • Incidental equipment leaks Sump fluids w ere non-RCRA hazardous. Used glycol/heat • Vehicles&equipment(antifreeze) Glycol(MEG, DEG, TEG, Used Glycol—Sampled on 11/6/15- exchange media propylene) Used glycol w as non-RCRA hazardous; Spot spill cleanup snow/water—Sampled Non-exempt spill • Fluids recovered from cleanup of non- Water,snow,with hydrocarbon or on 11/8/15—Spot cleanup was non- exempt spills chemical products(SDS RCRA hazardous.SDS's reviewed if • Spill impacted gravel or snow reviewed) relevant for listed and/or toxicity characteristics. • Pressure tests on new or non-exemptWater,glycol,possible product Hydro-test Fluids—Sam pled 10/4/15- liydro-test fluid process lines,vessels residual in existing lines,traces of Hydro-test fluids w ere non-RCRA (w ater or glycol only) chlorine or other biocide and/or _ oxygen scavenger hazardous; Boiler blow down—Sam pled on 11/6/15 Boiler blow down • Rig or facility boilers Water with scale remover additive —Non RCRA hazardous,SDS review ed (Griffin Bros.AM110) and pH conducted on each batch load • Internal or external w ashdcwn of skids, modules Water,possible traces of Facility w ash water—Sam pled on Non-exempt facility • Equipment cleaning(using non-hazardous 10/4/15—non RCRA hazardous. w ash water detergents or degreasers) hydrocarbon,chemicals, Generator know ledge and/or MSDS or • Residues removed from RCRA-empty detergent characterization conducted containers 2 • Cement Rinsate generate fromcleanup of Cement Rinsate—Sampled on 11/6/15- Cement Rinsate cementing operations for Drilling or CaMgCO3 (Calcium Magnesium Non RCRA hazardous—also,generator Construction purposes Carbonate)and w ater know ledge 1. Note that sinilar wastes may be RCRA exempt,depending on w aste-generating process. 2. Waste streams that w ere not generated or injected during a particular quarter are not usually sampled Z-1 CCP EmconMobil Development Company Brien E.Reep Post Office Box 190267 55H&E Manager Anchorage,Alaska 99519 Point Thomson Project 907 564 3617 Tel 907 743 9809 Fax ir- § , , E)KonMobil ,‘ f yzinie November 12, 2015 ER-2015-OUT-462 Chris Wallace Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue, Suite 100 SCAB Anchorage, Alaska 99501-3572 Re: Copies of Point Thomson Underground Injection Control Permit No. AK 11015-A 3Q2015 Monitoring Reports Dear Mr. Wallace, As requested during a meeting between ExxonMobil Alaska Production Inc. (EMAP) and the Alaska Oil and Gas Conservation Commission (AOGCC) on October 14, 2015, please find enclosed courtesy copies of the 2Q2015 and 3Q2015 summary reports submitted to the U.S. Environmental Protection Agency (EPA) in accordance with Underground Injection Control Permit No. AK 11015-A. EMAP will copy AOGCC on the future quarterly reports submitted to the EPA. Please note that the courtesy copies will not include the Attachment C daily monitoring data which are submitted to the EPA via CD. If you have any questions or need additional information, please contact Ben Wood at (907) 929-4108 or via email (ben.wood@exxonmobil.com). Sincerely, Itr- Lb/Pie, 77( For :nd on Behalf of Exxon Mobil Corporation BER:bmw:bt Enclosures: 2Q2015 UIC Monitoring Report Excluding Attachment C Daily Monitoring Data 3Q2015 UIC Monitoring Report Excluding Attachment C Daily Monitoring Data An ExxonMobil Subsidiary E2KonMobil October 20, 2015 ER-2015-OUT-424 UIC Manager, Ground Water Protection Unit U.S. Environmental Protection Agency, OCE-127 1200 Sixth Avenue, Suite 900 Seattle, Washington 98101 Re: Point Thomson Project Underground Injection Control Permit No. AK 11015-A 3rd Quarter 2015 Monitoring Report Dear UIC Manager, In accordance with Condition II(E)(1) of Underground Injection Control Permit No. AK 11015-A, Exxon Mobil Corporation is hereby submitting the quarterly report for 3Q2015. The required information is as follows: a. Monthly average, maximum, and minimum values for injection pressure, rate, and volume: See Attachment A. Please note that cumulative injection volumes were taken from the manually recorded injection data logs due to increased accuracy associated with manually verifying volume pumped from each holding tank. Temperature data provided for the months of July and August (exc. Batch#11)was manually collected while data collected for September was by the continuous monitoring system. b. Graphical plots of continuous injection pressure and rate monitoring: See Attachment B. c. Daily monitoring data in an electronic format: See Attachment C. Spreadsheets include data collected manually and by continuous injection monitoring system. Daily spreadsheets represent manually recorded injection data for all 12 injection events conducted during the reporting period. The continuous injection monitoring system became partly functional and was utilized for injection events beginning with the July 6, 2015 (Batch#4) injection event. The temperature sensors for the continuous monitoring system became fully operational on August 31, 2015 (Batch#11). The continuous injection data is included with Attachment C on a CD. d. Physical, chemical, and other relevant characteristics of the injected fluid: See Attachment D. Relevant waste characterizations for this reporting period are noted in the table. e. Any well workover or other significant maintenance of downhole or injection related surface components: No well workover or other significant maintenance was conducted during the reporting period. • UIC Permit No: AK 11015-A Page 2 October 20, 2015 Point Thomson Project f. Results of all mechanical integrity tests performed since the previous report including any maintenance-related tests and any"practice"tests: No maintenance-related test, "practice"tests, or mechanical integrity tests were conducted during the reporting period. g. Any other tests required by the Director: No other tests were required by the Director. The following injection episodes took place in 3Q2015: • Batch#4: July 6 • Batch#5: July 16 • Batch#6: July 17 • Batch#7: July 23 • Batch#8: July 29 • Batch#9: August 9 • Batch#10: August 20 • Batch#11: August 31 • Batch#12: September 7-8 • Batch#13: September 16 • Batch#14: September 22 • Batch #15: September 27 If you have any questions, please contact Ben Wood at (907) 929-4108 or via email (ben.wood@exxonmobil.com). "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." Sincerely, l 1 Agent and Attorney-in-Fact Exxon Mobil Corporation GMD:bw:li Enclosures: Attachment A—EPA Form 7520-8; Attachment B—Graphical plots of continuous injection pressure and rate monitoring; Attachment C—Daily monitoring data in an electronic format; (CD with data included) Attachment D—Point Thomson Project Waste Streams; cc: Thor Cutler Attachment A — EPA Form 7520-8 �� 1 US Environmental Protection Agency Form 7520-8 Database Template STEP 1.Copy this template in macro-enabled xlsm version using"Save As".Include Well name,Yr and Qtr with current file name. STEP 2.Fill in the highlighted cells with relevant information. Do not enter n/a in any cell.Fields(*)are mandatory. STEP 3.Enable macro.Press<Ctrl><Shift><A>to run the macro and check data in Dbtable worksheet.Save file and submit. Important:Please rin not-hance the'position of any cell below no nor op,; ..qlt;or insert/A.=1-: rni“r, OPERATOR NAME WELL YEAR' PERMIT Point Thomson Unit PT DW-1 2015 AK-11015-A REPORTING MONTH JUL AUG SEP INJ PRESSURE(MIN),PSI 168 1 91 INJ PRESSURE(AVG),PSI 1299 1303 1138 INJ PRESSURE(MAX),PSI 1970 1942 1907 INJ RATE(MIN),GPM 0 0 0 INJ RATE(AVG),GPM 125 136 120 INJ RATE(MAX),GPM 204 207 165 ANNULAR PRESSURE(MIN),PSI 9 11 12 ANNULAR PRESSURE(AVG),PSI 168 268 189 ANNULAR PRESSURE(MAX),PSI 1027 750 559 TOTAL INJ VOL(MONTH),GAL 317,992 182,830 266,861 ANNUAL INJ VOL(CUM),GAL 478,411 661,241 928,103 TEMPERATURE(MIN),°F 40 40 42 TEMPERATURE(AVG),°F 77 87 89 TEMPERATURE(MAX),°F 135 110 119 pH(MIN) pH(AVG) pH(MAX) SUBMITTED ON: 10/21/2015 (mm/dd/yyyy) Note:pH not required for Class I well injected fluids Attachment B — Graphical Plots of Continuous Injection Pressure and Rate Monitoring or o 'a o in o w a, 00 m m m m m • , m r. co 01 m 00 00 00 crl Yn M m M "'' ti AD W LO N M LO O M N O N m N mm M M (n u1 of o ,Mr1 ry o .4 r'1 ,.-i..1 u1 - vi V M N m N laN t0 N cn m 01 rn ,1 a un Nry !n N m : N0) m `r m M m M Ln v ,n CO ,n rn m j m .-I in m ti M m M ul Cn 0 01 o men m in d m Lt1 v rsl 41 01 Cr, tN0 t 0 01 LO m : m N M NJin N el - N en co rn 00{ M N M • 0 m N N M ,1 N } r n ^ N . 1{ ' O � N 1--:. N N N ! 3f N I k ' i N N N N + en N"J en , d- , i 00 V' co alla a1 I ( 00 10 M ca in N M NN N N en u1 on F { m M O M M ' N M f � ti t m N M C , N a7 N t O 1 t0 V O O M N M i Om N O tOr1 : } r ii t m m m M N n M ( m M Ol r.1 01 N N ^ m , 4 ry en V ‘.-i V Q7 m N M d- iN N Ocr Q. N lD c-I LO OTrN O CJ 4..1 m m 01 1 t0 Lo cn l0 l0 CC : m '1 M W inti `� 00 WI Ln LI. 0° co 01 0 a W mC71 aLID Q , ' m m . m v m a i i o - i m NJ m i i J o a7 q co 3 ! I M 1 i ' tri Ln d N in a Q. N V a-I Lo .^ AD 0D�r NJ o v C 1 o v1 m ,n m m , Lel n i ' a-I to i 1 i Cel N { tri cri 4� • h .0 N a 14# :. N - O —IO 0° a-I 10 01 m 01 at 00 M M I Ch m - MOi 01 co Wi 00 t0 M 01 l0 I m N Q1 I d VO — v V M - cri co LO i ic0 l001 CO : Q) - .-1 Q1 o 0 v, ( en H M I I N ,moi N N i 111 N3: 01 o ch goo o m mo m m m NJ <-i N M ! m •M 0 , . O N mO 01 41 ,:... Cn Ol 00 1601 n c0 f m M 00 l0 M n ul O 0 in N. M N eJ LO cn --o r' o n o i m ° en 0 0 0 0 n O O oON1 a) 01 u1 cn O l0 r.,.. O E M M ,n o 0 O N c-I M : 01 N Co en m CO ! MM N�7 52 N Ln O *N LC; N l0 Q7 01 i - N i . <-I <-1m m M• toN I tri O (N .I ,mN 0 jN NN N o o O , ( i ir' j E ( , 00 0 O i ? 01 O1 . 1 i N N N p^��1. 0 m o .. . L , �v1 00,--I M CO ,^ ,ef t( .,,__......,.._..,... m •01 CO 1J l0 V1 V m N c-I 0 C CO 0 O O O O O d m • = Oo O O O O O co 1) o o Ln — ooo LEI a_ a N N 1-. I- Q j i Y Y a_ to to N N . It o a ' 0 Wd8 CCS03 m o r` rn a , 00 00 0 °° 00 H ribW Ln WLo N M N H 1 H n H if) L H,..r. Ln { O NtD mo o l Lnu • lDO 0 N N N m m O N' LID O N Ol Ol Cr; LriOl N N N O 4- H Lc, • MLo 0 M L If1 O In N } N cal M 01 LID M OD } cNi PO , M om m Nco 4 N •i d, HH '1' - { m I N• OO r'' O M m O i M N N N in C. M V , mH , V CD� LC) O , • tri CO Lti co M ry M t LLn. H 4 LID 51 l0 Ol o Ol I t O O l0 U0 M N m l0 H H l0 , 2b 01 C l0 O1 4 M N M V 00 m o6 co H ,_, 00 Ln I Ol ON o O ON H O H 1i1 of m ii cc; r`i u N fri M o H m o O H H O o Ln O o 1 `--I Cl H In v m o n m H. m , , N M H N m f -.. H H H H 01 H E rn Lo Lo rn Ln r+ cyjN 00 ,H-1 '� co H W lO0 CO0o Cr m m YYi op m 00 m N m oo H H co H w ..n o co in ( H 0 01 Ln M rn LC) d m v., rri N c7 l0 C l0 H { CO H H m H f f "a ry'1 *f0 N 00 N � cocl) l0 N CO O 777 00 V 00 C $ 1 H V O H Dm i It CO r. m j . , H LID '71- i HmH v g dLn .71- 6 , m r J H co ti • o o O •�14 H H 96 ui m 2 05 ul C n H ri M - Q 0 IN O N 0 N - IHH H 1 p o H O0 O p 1 I t O O I .- _ ( MO Q MO , ,. M tvj '-I H H H , t H 0 Ol LID ( 0 CO � M O M in O 2 M 01 LID " a u; — 4 co H 00 1 O H o � or, o Ln o + Ol v H - 1 m nl a m ^ I - 0 �' ! 0 al o l0 r, O LIDm ocs (,'1 o r g a o 1 H CT 01 ro . 1 ' O 2 N O f M _ M o o tr 0. o M LG M il") 1.D C Qpip IN CO IN ..--. ,y N . 1 0 01 Ol H 00 r. c 7-1_. l00 M Lci M to r�up H C W r•-: fp .,.gym H `'1 C1 m �0Li). p 0 o .ii ' -t M W ,Hi Q CO H N H H r+J - M O m o M co' iai OO,�.v 2 01 co �. i a Ni H O . . Cl r 0 O O 0 .--1 �"� ,--j ni r-I H 01 , , ; oo 00 o o p a, N... IT � N ....,,.,_. _ ......_..._,.........- 0 H CO h. l0 Vl d' CO N H 0 a CO 0 0 O O O O O O 0- CZ CU, ro 0� O d ccO O O O O D cc tt� N N O H HH H - \ Y Y N d a a I= c ..+ Wd9 CU CCI 10 o , o • 0 . , 0 ' • o 6 ' .•. i• t 1 o l' o o o ,),....). 3 m 0 — r•J ,c. N. 0 N. o i r'l 4-1'-' O °- ,i'D N. Lo 0 : N. , o , 0 4O (.0 Lo 0 0 u6 `'n o 2 o • - '•,Li Ln Ln N. <4 en • o ,.....„ ,,-1 ;Ji °- s•- ,_,-) 0 0 0 m rsi N 0 8 2 r. • c-- ON nr, co •-.1 .-1 0 rr:Lr; La •-4. 1 • ct- ,••1 o , re5 . r, 8 0 in: 8 2 'Co' (:•' o on en r•.: Lr; C. •• 0- .4. L° cr; d• C) N 0 0 ,.-1 0 8 ;al_ ....0 2 r,r•-• go. cr) ,to, cr‘ m • P.: 0 o m oi cl en r,.;en ,:i 9 •• o. .-^ — .,-e e-e es1 •-i r•-• czn N. c 0 o.I. at es Cr; •-; ",. 1710. o 2 •zs • m: enM 0 0 0 rel. a, rn. M; cri c‘i n.i 0 •• o_ Ln " s c-I Ln e-i Tr or) r, al m ryi 0 o 0 •-.9 0. a- ,-i`r) eri S M ix, o cr, e-i cn 0 Cr; 0 2 m enni en 0 o o C• al -, 0 c; cr, m m- 2 • en Lc) •-, o n.) co o c‘i co al- o 2 ..cr • 2 :---' ,-1 CO r." 0 co N 2 co • 06 -1 0 ct. N CO en 0 ..40 0 .. Ln ,r ON` m 0 C°•-i , •-I <-1 64; i 0 arl •.-., VI 00 re) Nm ,..%C?n' 0 2 ,•-i -; ,-; •-i .0O3 .-i ,4 0 m °'! IA 0 0 c-i M 01 cn 0)in, 0 2 .-1 • en Nm 4 A co N0 01 •3 Cn en Nm , ....; , NC:3 6O ° EL 4 'r-sl 0 S l rel. ch 00 0 m N cc; C o 0. 0 2 • •''' 0 ..1 csr Ln 0 eN 6d• 2 CL . 1,•.1 nr cr) <-. P Cr;IC 0 2 a • - -o i,-i '-' •ct O m : co 0 . •,t- ,--) • N 00 N CO R 2 Ln c.i a) • 0 a t'Ll ,-I (15 0 ,r; Nen 1 0 a, tei ' oc."." 0 2 cs, • 00 11, 0 Ct. is) c° ce N : --;N •-I •-I , Cn ,, 01 ,i.i. 4..„.,..)).,..."..,,,..)....),...... •••••1 M = CO 0 2 Ln ,,• ,cc•c•-......'"*"r'i - r, 01 0 m <4 r:• t-i N 0 •-I N .at • M •-I eti 'at C 0 2 u-) • § ,t:•-, o 0_ 4 z ,iz: m co c — al en ,-I ryi v;,-.• o c,_ u.) ,_1 ,-;A •-i cn kr, cr, § . •4-4 o o 0,-; . o 0 2 Ln • Ln Ln a,. ,0,5, 0 2 1.tri M n `1,.'! co en es .•••1 cn : •nn 0 Q. L -• § : es! 0 01 M •--i re; L, 011-n. o 2 Ln • (,) . c,.i‘--1 o ci. Lr) m IN a, en •e-e cri , , e-i 0* o 2 •cr • ;9 oro o. u-) m ......,.cr ..1 ce, .-4 0 M e-I)-1 ,, M. , ......i •-ig 0 2 -cs 4 en: . .. 0 0_ in —n-; •-1 ,-, 0 0 , Lean : 8.. ,-, —I 0 ..4c.. .. 0r.,. 0 2 )-I • • ilg ,..., o n_ Ln cA c) . cn . , . .141 •-;if; •••1 0 C 0 2 •cr ni 0 Cn 01 ni - cn CO en. •-i, es' 0 M 0 _0` •-1 ; 0 Lf• o 2 co • 4-••,:i . c4 71 o 0. 0 N Ca N01 ,Q. 0.: 0 m . co • o 0 cL Ln Ci al co )-I • Ln ...-1 un. 43' m P 4. tr.) : en N nr,:r.. 0 2 Ln • . en <4 51. c 0 a Lc) '1 al ; mr, tun . on to •-f.0 en 1,, 0 N Ln 0 2 rs) cn ,.....i Co o ci. 1`, Cr; CO Ln' o 2 m • o^-1 o ... co 1,'" .....•., ...,..., a m 03 0 V-14 ,I . , ..„.. o ...)Li) 0 cr.) __ N. '-^ ..•,:, 0 ,....•,-.........,,C. ......-„,,,,,..„. P....! 0 0o r .2. .4. •t— R;.......-.. —1R 0 2 " 6 >, ....,A4. 30 N ;.0 Ln 71- en N _ -. •tp I ‘71 0:1 cu I 0 0 0 0 0 0 0 0 CD 0 0_ ..-• ra cc, ci0 in 0 O. 0 2 q o. q cio 6o to cc 0, o o o o o o c 'CA 0 V,. o o o o o 0 c-.) 0 :172 °- ct. * o e., LO d- esi 0 c0 1.0 Cr C•1 M < E ---• ''' ''' '" i• 1- • -1-, N. a. a_ }Z.- _ ,N. N 1 i 1 1AI d 8 o 1 m • , oo • o m O N O Q 1- t i O 7 v m °° ( , 1 ; m c-i m co N op m 0 N 0 3 I 0 0 0 M ':' 00 0M m 001 I N N • d O N 7 0 H N ' 0 ifi 00 3 �{1 00 'I N 0 : N • O N W O ci N - N O N N 0 in 0 O . O0 : n n N N e-1 0 .ti N N' ri N U N N ti O O VD 10 l0 N ,-:1 :N (Nr1 '_.1 m In • •N cy l!1 O O gL Ln vi i to M o o N O .01 N .4 N N N : Ill N �..,� U) O ! O 0 0 O O 0 N On : N ,i M N O `i o cr m ". 4 { 00 mm m 0 N • m ,kD i O ( j 0o r. V .-.1 R to s e do oio 0 0 m m qNg I i N O N N tri N M 1.1) 9 Up Is: O•N Ln M _ q • m M O , C oma up mQ : tT O 0 i 1 ry ON N .. 1D esiV1 i 3 N , `-I O - : 0 co 0) N i t 3 0 r-I N O M tri Ni�fj .--� O e-I Illi V) i i N N i..1 N 0 n 01 1 t O lD N . i m _I tri ILI - f i1. "c0v a % d i ii3 t 00, j N o m Cn } o - o M CO CO {[ a Ncr, CU tt (y P i e-1 e-1 41.0 S 1 f } 'Cr 1 m N }:: 1 I 0E. E PI1 ] 1 M 0-1 . M ( -i •� N -en j O of M O j I i M I f4 c-1 N /� ! 4 1 ( oi o� Q 0 1i, o .4 Q �jj o 0 0 0 .^ t i m O.. N I N O 0 }t : I i n'N O N t ,-I ,-.1 N. O N I� O . N r i ; 1 01 c-1 01 II. i, N CO M Nm #( N c-I ,I N 11i CI 0 41 ( 0 : O;0 Q 0 I .-1 : .--I N Cr/ ?i N m M N Cco 40 { 1 , , N ci W M N }f '� ei N k: 3 01 0 01 O , j i o m 0 ON i c-1 c1 . 106 o w ca 7 N 4. j �. N..--I ci N j 01 W 01 j s O • r-1 r-1 Q } I o o 0 0 `n t" n 4 m .-1 eqM 001 n • N I N M a 0i 9 -t f 0 m 0 ~O M 0 Q .-i N m n m LO aj l0 d ,il0 01 al I CM N o n o N m i ro .n-1 m co m m _ ,I r1 0 0o Q o r i i m o.4 0 m m m m >1 j o 0 0 0 0 N 0 , m m o m 3 #.. Lb '. ' m I co .4 j i N •• O „, 113 O { M N �,:d .-i N ti N .--I 4 ' { CO N ''� W .-1 • ,1ri C.) ( ` p ' �, l .._.._L_ _ ._.. _.._ ..__._ V' ._...- —0_r-I 0 M n 10 N 0 m N .-i p ko m CuDi a w 0 0 0 0 0 0 o a 0 0 0 0 0 0 0 'c. 0 0 0 0 0 0 0 0 o c 7) a o 0 0 0 0 0 0 0 n a coO ,J- N O W i0 V N 7 Q 7 ,-IN r- i.--i ,--i H — a • \ m w CO ti a i= _ IIAid8 a rMv 2 E m i 0 -4- CCI Lno p { j 3 N l a ma Q1 fV Ol E Tu V1 01 I N , i i 0 O O ri d Q p ( ^ io o_ v a ° o v °' I 0 ,�-1 { N O .-1 O O r-„.: 2 O urns rn --1 io a ' , o a ° CO o i o { 0 i o� ( o o O , w ( o f �� o or-INo g °�' on 4 1 ICI a s ,� o id 0_ m y •o { i m ,1 m 0 UD Ln N �--I N 3 t g O O O N LIY N rn ti v N �"1 al in cr, M m M I m o A ° y m COLn cn a ,n CO , D 3 w Ln ey N N N 00 0 o 00 o ; m o a 4-+ rn to M 2 N Ln- 'M La — f0 _3 aY-.TN cr, M cL• N c 0 t0 0 rn V G N H `"1 rn Lo 1 ,i"` N 0 t CO aY-. m rn ii 0_ rn 3 N i 0 v c rn I N o N O frn m 4 g v v ' ,n a 3 cc ,., m a rn rn LD rsi o O. m ° y c.i • . O O c N M 3 w Ln In G t0 f r { .M-1 r-I - d N N t '0 O N L N rn Y 0 0 N m 0 ' n a 3 m c L ,1 a N N { rn i O C -. ,o aY-. rn o , m IM a o 3� m i 7t a o ,1 o f 1 0_ Q.a Ni a to 1 OM N 'a' a In N M { N ' CY G m d N l_no �, o { rn { m g E Y rn a1 N a ..-1 ..-1 { S CO a d LO Y CO rd o cc CO 0 + fjf cc v .11 N C] G cm N 3 $ CO e1 G Y Cl glel e-I Clg E Cr rn � ° m ° N V m 0_ N a M 4 0_ O Y m Q., ,-i .1 c-1 A a I 0 dp' O c ..:,- tri m '.rn g E Y on tD m G v tG M 0_ L � m M ° rsia r" o N a) 0 i O Y V Li-1 o i rn Y rn it '..� M C I .m • M O_ LO Y v CO } in b ee-1 m .N-1 N V o Q •1 rn .1 2 E y m NpO, o rn E o i CO „, a 0 CO '1 Vl M 0_ e1 V1 p ,-4o O O O S s C a)• d a M , v-+ ~ ti N ••--. al E Y rn n o N 0 -0 c ,,..+1 0 m _N a ° +° M O N W CO { p N N O N C) ir,v 2 E Y on 0 .1 ,-I N ^ N N N ,{ M Al d p CO wi ^ m g CO n 1 IN rn N d O co { d 0 R . Y rn co Ql O rn COiti i • N 0' o N m 1 0 'ti 2 c-1 t0 m EQ Esc ko ° cLoo Np,'1 m Q ° ✓ tki mr� oo „n Al) Otv o_ O o Cl 8 2 -a c - Lc'00 ...1 i im N C ° Y m N A-I 01 I0 Ch - a N on E Y rn a ° a m o • mti ti m CO ° :° 0 ,-'A2 .0' ki 1 eN , Mrn mo2 EY on M •i omN 0Y CO rN N N NN CO ni OYm 4111 O c1 I rn rn O a) L C m{ � �No COo Ho M ti Nf N .-i p ppO CO EC" $ Em ri m 1 Y tD H o_ Mal ti i coQc rn tY g H • M xl 4 r.i 0, l0 N 0 N en .1m g ti .-i e.4 d 3 Y L() 11111 n'.i o mLn M v _ 0 O o en O j CO N C d m e1 w--1 Ln ,M-I 1 N ,_ ..n CO CO CL/ .__ �..r. O N O O ^O O N O^ O `- N` ,1 .'qr ,1 _ ^N-1 CO CO I- 0 0l a CO N ,1 0 a CO o o 0 0 0 0 0 o 0 o a v o o 0 0 0 0 0 0 0 o m O O O O O O O O O O 0 N cc o 0o o pN o COp0 a pN 9 0- Ea. N O .-1 .--i .--1 ~ a _ IP MCO (SI N a a i= — (B LAI d8 03 n O m ., p m 01 hi O hi O O a 0 O .y m .11, M, N O "i O v a. o 2 m O n m m s O O N • ci O ry m p i 0 0 m o m N M O m O i01„hi m .a. '^ '.. oa M 0 o v1 0 m co m n ^hi 0.i .N. m oN 00 : 0 N e m n m 'r' g N m m N m oo M a_ o m m m uo 4 o N T 0 ry m O p 2 N 0 00o o • a0 m M NO M o M N ti o D a, • 0 W ¢ m • N 0 co o in ni tiN N M 8 0 O oo 0 a W m rym m om cd N o d m ra m ry O a ry m m m m o m ry gg o 0 01 Oo O p ry m N M Ro a N bcn m m o o N ,,,I, m ., m uo o N H ry O O a C ry O, c0 m O O 6 R m ry .nn N hi Orv. o 0- ry oma. d m m V1 N M N CA h0 CV ,. N v m o 0 a o co m0 f0 at m o m W P O 00 m CO DO : .n. �_.n, 0- o O O a O O E in O1 n N /� M O MI N d m il No m 1 o0 0 L71 0 n"! •oo ,Q1„ .ar Cn ,ig I„¢ o uo c m o . .'M m o m M oo o o g m m '.N m ro. w i.,¢ r pro m 1. O O I N o 0 -1 to 0' m M O m : Fd 8'2,0 m o m o m baa 'az,' mem m co m m m 0 `.-;1' m m i � � y m uoi co m W,O ¢ n W O. N n M m'.�, N CO n al to 2 ,,,i N m p • O¢ ry a a ry V',o on r In m t 0 CI 00 ✓ c o¢ nco o N 2 o ^e c m m mm ¢ 0rn ,`c ¢ 0 .a- ma, n ro O M 6 LO MC. m •, o d¢ o ma! O m . n ai o O 0 0 0 m ry M ., ni N .y to , o oo n a m o f • -5 0 J 0 0 0 0 0 0 0 0 0 o ,7,- 0-. m O 0 0 0 0 0 0 o d g 6 := 8 m . .4 . 8 2 8 c a oc N .-I• .-1 rl .. J ¢ Q E CO a E N £ 6 V CO was 03 co N • N On 6• LO O O O ,i '...0 M CO .v T d T ^ O O N ri O O CD m mm M d N M 0no 3-o ti M tD ti m N M m N n O (. 01 d M O Si N o ;3.11no N m 111 M ,d N O I. F O O O O P. cmn Q m nu to 2 O m a o m o0 8 0N o • P 0 o 00m ' N .N N N a a mo o o N 3 ti 00 O I oa o ON o ppj 01 o o m O m N m • M • N a to m M No m O, .N-i N ° .N-1 m o a q N ( 2 N o 04 o m CO• rvi m O N nd O N O W oa CO to v N .O m m N N w m 00} po d $ o m ` o^ 8 oN N " ' I { { 8 '"' 2 o Nin o a o '1mOt 0. O `N p N N SS ti N 8 a o S o i N �� m .o co O. N CO I( t ao Im• Mmo h ^ N " N m m `. i i °' • NN0 CO N 3• m m 0.o wM ( .. M 0 0, o a m , V .Ni ti O Q ` 0 N • 0N N M N mJ 0 N N m 0 • b N ( ti p .moi .4. M 8 2 Q o O m coo to No p ^ No co co I� oo 8 r•-, ‹0 8 ,r o N m m o 44 un 2o 0 o S < q .n m r,'i m:p .y m m m 9 .W-. m O g c o m S 03i nI a of 1; I -,oCO el I . I2 3-Q o 0 t i ; smo N O , 1 t i i N o N co M o I O N ^ In CO 03 1 � ` I o mrN mS 1 pin m.-i 01 ft � i oo l0 W .-, 00 e9 0 cum O 0 En Q � N 8 O O 8 8 8 o 8 8 p m OOOOOO O OO OO 0vOOOOOOO m o° n O to V m N - O Y K ct- o m o v No ro (0 v nN N f <N . . .- .y E a E a a I, V R ICU Wd9 CO no N4 1 # M .j O O Oro a :O N O .-I ,e`;'''''.."'" Om O~ ~ :mwe. ~ o ' W S a 0 00 t O O O tO ON .-I IO • O Om ti m .a. I� . m '. O a M m i N N N 0 m M W M !tY f/1 6 N 1 � (o N O O O a 1 <y M h 00 m N m I .. : M M N m '8 , a m m 0 N 0 W • N m N T M N ,, a v v M O S a g o m o m M • a V n �' .. IA oo a 24 o t , s .0 � i f'...: o I{ ? ' o a m co+ a. a, • ''', rn . V ti f ? a a IN v �' M m . m o m M a a C o O O N O W a 00 N m Ot • M i T m O V N O N 01 ! [NI tO N N yW,�nO {�{ o a m .. m O I .O N 0 t0 N M 1.0 .. . N N N , a I°. O Ol ti i N ~ , N • N N co• I . 1 j ! o' d 4'i I-I m m 1 N.. N rl N ? m ? .D a Cl b r m co Of A , v In d •v ^'+ S 1 �' o $ O d j a a a CO ° � m O ' , I {' .-. f O C .ti j {{{ � � ai no 1 3 O t N tD .�. 0M hl , , 1 p O 1 1 ff O m Ol II N a n d M i ' C m N o C m a m - 1 a. 2 n N i N i 10 ..acl to m i j 00 sr ? _I f ai °p : " ns .1111? 1.. N . N N i 1 M ' ti a o - m ti m I . 2 1. N M .. a to nit m O1 N 1 7 i # 1." ' `,f,' N O 2 ,,,.4: r1 m M a N V m 20 CT uit a M .i O O : t b. : O o] N en CO T o m g rel 0 I ' , i 114 3 ?-1‘-14 Q a !L.6 i m I I 1. 0 0 ID 0 00 0 m N m I i c C I ; ;en a O .N. M Ili , j, o O j „...( , o m N o °i tD n 00 m m I ? tO 0 N. 1 : a O N a m M : 0 m' 1 e 00 00 O i � , ( a $ p ri m 1 o cto a aus i ? .. 0,1 O O 0 0rS m Oo m i na'M O `.{ t . j1-1 N.0 0 N In rg ' m , Q m m M C M i t , 1 .N, o .N, cv y I ? 0 n W N O , , 0 ? . , O N m O O O ii ?,.. j .. 0 i , f 3 i N' 1 t j y oti N .m. ." `'____.!____._........,...}_._...,.�...:......A.:....,.......L_ _L...._ ...._ I 0 M _... .. I-- r _. ...j '. 0 0 0 0 0 0 0 0 0 a p p -gip-- ? ^— 0 0 0 0 0 0 0 0 0 ,n 8 0 0 o O O 8 o 0 o o 17 a .c v o o 0 o 0 0 0 0 0 no 0 o c In z C o m tO v oN o a ID a oN m ¢ a III a 4# w w E S a a F _ as ! Wd8 I Ca • CO , Ln Or •0 Cr E co "i. 0 Lo. W Or • .1 , CO NN : •N : or N . 0 .4 0 CO 06 Or. 2 0 oti 0 rn 0 el- • 0 • oo ',...p O. LD CO . Zr . , . ,-,al .. 0 . .r o Lo ',' o o o, , . o r, o 110 . LO . ' -4, , : ; ,-.rs, a+ . . , , ',' 4 r, 0 0 . no 2 4 4 ci, c‘ 0 cr . 1N .1 Z CO 4 : ' • • • o < • . m oo o n n I oi N 0 0 0 0 r...: 0, 4 I,r6 a. 4 on! . in . 4 on . no 0 o , I..r. 2 r), cr; : ; 01 ; • 01 0 CO • : Ifsf: . 0 N , I 6.; O. N 0 . , • • . 0 A 0 1 • . . 1-..: . n 10 . : CO : : , : N 1 • • , , : . ‘,_.,- : • : . . ca t•;51. c 0 oo . Lri , • ea • 0 Lr, . m t • a. Lo. on . I , to.r 1 Ln .-r•'esr • ! ' ' I I to o . 0 PS 0 • , . . ; < , 0 09 2 RI: l . e , O on. ' ; • o . n n ;,sri a. al N N NI I N N , ' 0 , : . Le, 1.r, I Lel ., ni .1 0 N0 , . .,,i A-I 2 01 N ' , rn N 0 , 6.; D. el. .1 , N o to cr) o• a- a) .4 ; - , ; ,t0 oo 0 cri x ep 1 o , t ryt 0 , t PO N 1•:r 5 N N. 0 0 4 0. o LID 0 . .1 . 1 : 0.., 0 0 0 0 N 0 0 , , 0, -,i Let 1 t-, 0 ! . . , I , ; . , • . 0 z r,i . N ,y, < . 0 10 LD NO oi N no • ..,-. Li , . os. n N " o . 0 on • . . N o ' ! • 1-4 2 n 4 ' rri ; , ,......'', 0 0 0 I . 8- 6 ,..7' , • . ,.: , N .. . ! - , .... N . . , .1 , 0 I o o o , , I o 4 '' co cn o) ,.. • 4! „! co ,0 2 NOD ,,,i n1 , ct 1 . IN 1 ..0 . . ' 0 00 0 4 ° 0 ° 0 0 g..... or 1 Of 2 o a o o , . .1 N I. N 0 0 1.1., 0 10 Ln 0 r..% Q., V) . .1 re,r • t , . • - NNN ra m . ro to, 1•• 0. N0 , et N I , • 0 0 ' t , . NO , d 0 N c.=1 I PI N "' : . o 0 . . en r-; , .cr rn NO 0 , on I . , rn. • ,N 0 ....: 1 , . co n o.ni d C11 : 1 ' ' . 1 , . 0 . ? CO . 61 co ' : , Or • • • • • , . . . • • LO2 vi ca 10 , o o I' m •:r 2 . cr,. . . , a . t , . ; . .,.. 1 . . , n a. a. n 03 , , t „ .1.n, t CO Or 0 00 aj t 0 .. ,..,v....:...,'"i...;;;:".'''••'.."1.."..t.C":"."f.7.•'..'1.1Z.:: tt....<"PI 0 . . . c rtr 0 •le, ..!'''',,,F tt,''trial.''';'''',,,t"ttat.";',",',..,...;'tttr- t",,,tei • . . 0 Li N N • ,,.; 5 u-i vi 1,.; o 0_ , . . E ,,,,.., i ,, 0. ul..., „..1 0 Lni Ln Lel Z 5 1 rn . , ;Lel '. "r'n er rel •LID ,, a- . N CL, , . , i n• •,,, n, rn ch ..,,o o oo . 01 , • Ln . , . , i 0 • , , P1 co ni C . I , . , .. rn tO ' O. W h .. rn N . N en 0 0 N -o00 ,1 Ln 4 o I . ' N , . , , 0 0 : , , ! . a . d • ‘Li a. m co I , . ! . , 0 . . 0 ' . ,',';''':''-.,.'.., . • N C° ey; I . . N , . Ln 1 o 5 ,..., .i, a. m co co .-, m c., C LID 0 I . 0 ''' Co 2 .-. csi 0. el. N . ,I. . en 0 ._ 0 ,...... , . m• 0 I • , • 00 . ID m , N O. N f O , . . PI 0 0 Or 1 1 CO CO Cr 0 Pi • 0 0 .1 ci, co rri err n cr, t o '71 Ni 2 n . , ..1 0- NW Or 0 n .-1 .1 N N 01 PI 0 0 o01 . • 4 o . I , , ' a La ND. 4 n o o 61 NI cr, i H 0 00 0 : .1 r„i 0 ' .; CS 0 0 ;S. 2 ca ° , : o o) o a. ,O•4 a. r., O 0. a) r.-r r.... i S 0 0 rs, 0 N MI r,1 CO 1. 2 0 co Sm 0 ei ..1 < IN 4 0 .40 1 ; ! n no o ,. . o 0 co 00 ° ,_, m.. . m m . r_ o on 1 r!,, i a. :<:.. CO ' 0 4 < N OS 0 . ; N I N'.1 . ril 10 00 a) ,,,i N o o 4 0 0 . 01 INN rri en 0 , 1-.. . n Ltil.....1 < m Lci. o ca M CO , N.0 0.1 N IN 0 LO 0 . 0 0 : 1Ao , ., o , o o :, i : 1.6 < ..""' .."' . , 00 0 0., cl. 40.; ni C\I . i , ''''0.4; .' ' : ,' 0 0, NN rn en , t , . , LA -........ , o , , • N ei 1 0, :. . -,,, • ' ! . $ . t re; N CNi 0 co ' • , , . ! . .4. . .. . , ai a, , i . : 0 • 0 , Ni •• m eni ; , ; o o -,• . . . ° ° = F 5 1 ;o . 0 o 4,, ai. • .... ! 2. ! :4 ! . . . Cfl Ln . 0 0 0 0 0 0 0 0 0 p. . • Q o o o o o o o o o o o d d d d d d d d d d 0 0. OD C 71 ..— o cc. LO el. N 0 CO LID et• e-, . < E ... INda CO 03 3n., o a o m Q O N' N ':'4 m d O 04 (m M 0 p ry t ( trt o o o o v o a o 0 0 4 ny �..�'' '�"*� i a u, 0 0 � �� o m - it o, R#5}} C p O R O , k m o o d {p m do a s Mr! 9 m a M n 0 0 co CPV O mO , mS 0 1 m o m o o 8 i # m m W l 0 0 m mo 0) v O m n m m m o i N ro n. 8 m iri N "' o pp I t N m O '''3' O U O : :p m o m S0 m N N m N M O - O O 8 O W m N N ry oo m fiV ,r.',•, m O : N C s,,;' ,; N OI t,, m n N a 8 8 : O m : N 'V N a) m N m N ! o v (6 of ry Si N m ON , O OCL O m ' N 3 j : m d m N m 1 i N y ^' m 1 N O tO O .-1 p, ON N H N N OnNO ON 2.. N 8. 1 N m I p p ry O i N O W O -.moi O O ti 8S t I '. o t ori oi I ry Fit 't e o m N M m m m non o ti m n I.m-t m Sri • n n 0 o 8 w .s' . v o o 2 m uu o m m g,", "' o ry rn m m P m D O O m OS m 8- nc. ori ma a 9 n 8 7i v m'7,3. . Lo $ m N m N m r 0) sn' i r?) a !:2 c EvN �mmmH L p Oo Q G O N M _a a m a) 'Ioo O O CI- N� .N.Q t a• 4) U) o o a o 0 0 w` O O 8 8 8 8Ow N o 0 0 0 0 0 0 o m wt: Sn v N N .-1 0 wL4 N y1 It a' 6 V (II !Aida in 0 O' o 0 o m h 0 o o o c N 00 a a N 0 a `r N N .--i O V }O o a M m O `Y a LL 7 N .i7 Ory O o `i m `' a ''^ '4' 0 ,MC 0 0 n o n 000 o M ., a0 0 0 n o N o m a m uoi "' .� .-00 co .1 m m co co o M 0 M a- M Ln IC a .-1 a .-iW O o 00 OO O N k m en 0 to N 01 m.a m m a O m N M 0 0 0 0 0 0 lT N • .., .i a N N a 1 m ~ 0 O M 0 Cr,ON 001 P'1 eui-, m o LO 71 M M co a N 71 a LD 00 N• 00 CO `0 0t N N N 2 O N • M 0 0 N a .10 00 M' I de N O O N 001 O 401 0 Cr; • G .•1 O1 M M M • w o M N 71 M • O 0 a N o Cl 01 0 0 0 co 00 N O_ 01 CO M N M .moi 7 en .1 en N I Ii in i 'O 0 1• � 001 CO OOi 0- 0 M N 0 N MI .-1 m M a tT n .Ni • m 601 N 0m1 m on V 7 M f M ti m CO I ( t0 CO N N CO1t 0tD 00i YiY ' 0 O e 00 � t M M M .1 en com a m 3 9 in m K o 0 ro- • .1 .1 ",i M "•1 .1 M o O co 1 N 0) F Af] m b O1 ( - M M o.co• • m m m m' i m o0 1 m N m N I .0... 1 N ro 71 m rt1 M • N 0 0 N o 001 N co0 00 I O S M N co m N 0_ N M NV N .-1 N 0 N N O V1 : 001 y .1 001 IiI .y O N a t M 1 N M i m N 0. N N i p 71 N .D� 0 0 N 0 O o o a) 01 00 • 00 lT 0 O W O M en fa j m - •a co m f f o�,-, .i .1 .1 0 O I O? • o 0, d? _ f 1 3 O k I� 00 CL 1 . i ~ co I m=om ,4� a e1 m 0 00 0 1 co 1 � 00 .~-I Q .NmI n • • o ! g o C m Loon O { co:..-1 a b N V V �_� ti0 0 `-' t ` 10 °01 M { o m o ni m I : N . 1 61 xi kIn g r.N m ` 155 0 0 ++ i {Lrl N Cl t Cr,. i:_ to t I a l0 N M •r m O Q N ro o"6 i 1 o I M o M M „1 nl m ti 1,6 01 00 i O a en e 0 0 01 M Ol 0 m I m 0 00 M ni {{ N 00 01 Q N a t ++ 01 7110 0' M+O 0' M M co c N j'..o a 'n INn o 0 '4 71 H Cl CO N. N 0 00 2 vi 0 0 0' O o i eei Oe of O X, 2 O 00 a a m a a s i o O • .1 01 m 0 0 0 m M it `�'00 O v.6i°' Q a c o 0 0 .1 CO co m o a 0 m {i{ en M. O N;..-1G O N 000 m a h { O 00 0 O I tri m f 00 m Q 00 00 { O O mM -, M : o N 0) 0 { S O� O t 1,4 M v; 1 �'no 00 Q Vit N S O O O . o M M fffSSS555 O O ° Si LO O m oi m Q • a al O C\p v0 1 i ! m j m N I a m 0m CD 0) g- i I io ri ; en 00 O Ja 0 0= !a) i { r O m M j „ } .NSI^ a oo H 1n .1 1n 0 ~ 1 I S k 00 ' 0 O CD I O __ � ^ 4 a ' 0 0 0 0 0 0 0 0 o m a i 'r._. { _}- _ ., --_ -i....___..�_.___ 00 1: ID IA 00 tri N .-I O y 411111 1 0 0 0 0 0 0 0 0 0 0 o a 0 0 0 0 0 0 0 0 0 0 o m c`Ic c o 0 0 0 o ci ci o 0 o c In v. Ch o 0 0 0 0 0 0 0 0 0 _ O W b a O co LD a N 3 a 7 0- It N .-I N N 1-- TT11 a Y Y 01 s e � a a H m H I Vide o o . o . 0 o e" o • o a; , o m 2 a' • ,....., drd IN 0 di o p N : °- to N 1.0 N di N 1•4 to rib 0 , 0 0 f--I 0 .id di aft c, o 0 to o „,-, •4 CL l0 0 di Idi di < 0 I 00 • 'roa N cr o m 0 N ro tr ,•0 o I to 2 NI• • cc IA fd I id tcr , • o o mi p Cri. 0 di o to o , o o • o r- co 1 4 2 r•-: a r-. eel o t- o t.ti °- to. in , • m 4, 01 , 0'' (-I 111 en :0 0 0 0 0 0 0 Ill CO rd 2 LO 0 , Co o o N 0 N 11 •411 ..- 111 Ld 111en id di 1.11 0 00 0 • 0 0 Lri 2 m o . co ,•-; 0- tr, a) rri 0 00 o . •-o o 2 o ,,..6 ,-. .-. oet o o 0 co • m c:i 0- to N M rn ,.o ,. 6 „ o o o , , . =xi . , - 0 ,, od• mat 1. . •1. CI 0 0 0 , 0 , un .,. 4 0 , . or,0 m 0 • co en , & °- to toto , . < em ta cs' . , o o • o - 4; o f:,..1 „?r, T:•.4 `'''') 0 < di ta , • o."• o o o i • • • m m ni • • e, 1 m I rt. • • I.III-Io N °- r. o • m ' ,o • • Ln m o , o • o o o 2 4 • c., o n., en 410 to m m < (-I 0 to° o IPr 2 .5 a a, m al IN • 1, d 1, di cti 4r1 ,i C.- m to co di dr di d 0 CtooO• o 0o •,•11tL.0.1i .°Z,-. 00(uaA)t 00,tmo..., o 'CNI.O1. Mo00crt di , 1, di d N d •tr N m < m to N m o N ''•ja:'. : u i,0‘-I-a'Oc' Nc7dr....''. 0 1••/'...I'D ,,,C''.'iC9. C N 01 , , • , m 6 M , ' I co o to ,r1 (.0 01 ' 0 0 o o o , ,.-. o cr tr, co , . • M , . . <0 N ' dl 0 N 0. , 0 , ; t I t--, ( to (0" to to , . , . . c. ..,...• . . . 1 -..:., --i ;MI 2 • • , NJ di N 0. % 04. OW Of I 0 • , I t 0 0 0 0 ,• ' ' • , ' N 0 t d t • ' I i 141 tta to to. • . • o o •to 0 0 . , •" 5 •• - ui 4 2 , . < O- . , a.. rst ill N • ' On . U1 d 1.11 d• g 0 rrim , , , : 4:xi ,-,i i° 2 • • . J1 , ill di 'd , ; ; o tot Lil d• 4, • i 0 , 0 C3 0 0 CD i i I 0 0 1.0 0 0 • . !'''.. 2 • - Ce M. 1,0 (.0 1.11 M Om • 0 , , • • I c , • , • 0) ,,t, 'r..1 2 cr.;° ,60 E , i CL ora • , • o ' o o cri mc n: 0 too cri • I I r-t. I, I, id . • i • m m , o : a o Iv, ,0 • • en i I a, 0,,,, ' < l0 IN , 000 . I ' 0.• Id ,. 01 CO 0 Cri 0 0 0 0 ,0 0 di m• 01 1 t ' 0 0 , 0 0 ' mi , . 0 71 0) to - 2 • • • O .4 I co m m m o , al ni to 0 a, • o ,o o o • m o o m 2 R 0 en en • . 001c, , 001 , • 01co , 0) 00 N IS NN 0 .:I. ch o a, 0 0 00 \ , 0 0 ' 2 00 M ''i M a; enCO ' • • • , to 0 ° < co to m 0 o N N N N to to 0 I i • • 0 0 0 00 di to no ° o o M M o to . < o . cn , m oo to N 0)N. 1-•-• NJI 0 0 0 0 , ri • , cr. en V) 0 0 +0 ,`' ''.. 2 ON 01 < di NI 0 o co • r, CON ' a, m cr, 0 0 00 I n'i ,-I ni 0 0 i 00 <tr- n 4 a, to a; < al a, oo N to N .Ni c, 0 0, ,-. • o 00 m m Cl o ,..... , o o to tfl ' 6 to • 10 a o et < to to N. m 01 co01 ON M M N to Or'. o ' 2 6 6 o o N m 00 N r, a.; < N to o o N m N m or• oa a, o o 00 to en 0 0 0 ,• 00 P, '.1- C' '. 04 4 0 , a .Eri < o .-1 0 ON .0 n en mN to o to 0 M M 6 , '°' ''• 0 • , ' to°6 < N L; N0° to al o m o ,m . m o o ,-,- m 2 oi LI C, m • < o o co .... ,..„ a, o a", at at •' . en 8 , 0N ,..„, (z) I . a),-, 2 g cri U•) . . , .-1 I 0 cn .0 cn a ••••„, . 0 I • • C\I , 0 • I I ' N. 0N M M CNI . ., , (\I • t I ! i • . N c, 2 N: NJ N - < N. i 0 0 , ••• N,.... , , , CO 1.0 di 0 Csi 0) ,-, , . , . r" i .-1 o ci Csi o ' Cl o ; at at , • 1 ' 1,1I i tI, to , • , • • . m tcr 2 ."; cc.' 6. to , rn•• < c° m o o NN • cr, N ot a) : „,....., , . , . . --, di i id MI ma V•4 ci, • f . ' , t , d 0 0 , '•-!d 2 .i ,-., o o F. ' ; , . a 'h < co , r^ i h ,-, h di 6 .6 .,-1, , t di • 0 • I ; ' ! 0. • t.0 : • , ° t r--N 2 • l't: 2 Q. ' , , . 1 ,c) ; • 0•• 4 ° IN ‘-' 0 0 0 0 0 0 0 0 0 p. a) 1-- , , 'Jo', , . . g -, 0 0 0 0 0 0 0 0 0 (I) 0- i . 't.71. CO N in to to en ...I M 6 . I Cr 0 0 0 0 0 0 0 0 0 0 o 0 0 0 0 0 0 0 0 0 0 o 0 6 6 6 6 0 0 6 6 6 0 0 0 o o o o o o 0 o : 0 co to to N o co to to N ._ 27, Co -ca•- C. to D. E . A- rs mi Ms M•• mt M - a- 4t _,e tu o N I, L 1 4-. al i i f 11/11d9 Ca en 30 0 ena 0 . a in m : 1:.ti .-I m a, m rn M a N a01 C f : ~ c0 : I N 0 a O o ri a o m • v. : - vi a ti o !ri m CO m N a1 M O T 0 • CI ^ a M O m .-I `., m ;m t° °I o o0 0 O m O O O Q N ' e1 rPri as .a, ti .o ai 1O m `n m a: of �,M -w..m.... M - m rn " La at m a o : m ro ut c i a 6 M• o 2 0 rn tai, m rn M M rc, 2 ',o m m m e-I • a la N M M 0 r;,..: ri cn ~ O O rn a. O ~ ;M 2 O N (Y1 m co • . O a ~ co m oo o o • "6. i N O a tM�O Qi M O ^ ^ KC! l O O M ''O 2 V1 N M• O • M cn Or 01 " a to en N N M .--I N 0.1 F-- o R N 001. 001 o N a a Ci: M : N m C ^ .-1 N ce 1 0 PP 06 en00 m a a0 amt' rri 01 C 00 •r' a N 00 ( 0 0 Cc ^ ':.O W N 01• N • 01 LO to N i " a co ...1 m M 0 N e al CC 4 e M xr t3 N L a M M N a ,_,I,4 N-1 T, O N N ON, 0 O 00 ( • M ON co N a .N-1 .4i tt •O , m m CP N 2 in N , m jkk UM-I e1 a m n N N co N G ^ Ol N • D 7 G v. M 2 M `. a O 01 m 0 m - en d 0 0 o m I'' m w m Ot N m `�,' co ;m 2 N .-4 m m m " a '-I 01 y - 00 mco j °° M }+ O o co NN ..n N N N(� M N • O, O N a V O Ce M V 00 i O CO 8j m ''-' •.-I M CL 0 0 U1 —, Lri 'n 2 V O L M M O a .0. e a m m e m I { - 01 M m .e a a1 M m � MC m � m 0 7 O a, V N. , o N a T O I w m t CO m m m nct ti �. U1 V1 O, Jt m '^' 2 N o m I ( 2v LD ti a tn to N N O 0 n. 0 o, IN m m ti N en N t 3$ n N N a N N 0 0 I m ':.v1 co N 0'i Hi O ' t —1 a N N 0 �. 0 0 N f • 1 N Ln Q O 4 M "{ M jj! ti 1� N 001 co m t , 1 m !1n co M M no 0 'y Q n 0 .N-I 0 N 2 • • o � ¢ � .- m V1 V to i �-4 co• a N :O 2 W N m ^ m "t I• Ot . 01 • m W O p. l0 m m 0 2 ^ o ^ O Q a N Zit m I m 0 ':to no W m I N1 Li, o 2 vi 1n Q1 O ¢ N T : O O { o a1 en m 0t a m g o a } `tO O Q 00 � 00 ^ 0 Mt0''N M 0 ni ni a 000 o Q m 000 .. m,r, co m j o o m cv o '-i o m m 00 N . com.o ¢ co a a O 0 M CP 1.. N� N • M M rjr'N al i ` W Ol Q a1 0 0 e V co N • M • MO N Nm N N a 42 a 4 m ¢ N n o N r- o I 0, m 01 N••• : Ca o �� m m M N 2 LA m ni , Q N N I O N O W try N m M '0 NoCCr oo n E CI :'•?:: : .y ¢ .Ni ( ! ' , 000 m W .^ m wMw##N M M .. f i.f. O N'ca 0•• C 0 N ~ �/� a _..�..._.._., , _ M ..._..._._.. M N 0 0 0 0 0 0 0 0 0 m V! CoTo N l0 N R M N ti O ,+ • O O O O O O O O O O a00CC LO O O O O O C G C G O C in a 0W o tto a N O CO l00 o V N Q E .-i• .4 .-1 N - 1— — a ID E c .0 a a (C 1 �e Wd9 03 Attachment D - Point Thomson Project Waste Streams E onMobil July 22, 2015 ER-2015-OUT-335 UIC Manager, Ground Water Protection Unit U.S. Environmental Protection Agency, OCE-127 1200 Sixth Avenue, Suite 900 Seattle, Washington 98101 Re: Point Thomson Project, Underground Injection Control Permit No. AK 11015-A, 2nd Quarter 2015 Monitoring Report Dear UIC Manager, In accordance with Condition il(E)(1) of Underground Injection Control Permit No. AK 11015-A, Exxon Mobil Corporation is hereby submitting the quarterly report for the second quarter of 2015. The required information is as follows: a. Monthly average, maximum, and minimum values for injection pressure, rate, and volume. See Attachment A—EPA Form 7520-8. b. Graphical plots of continuous injection pressure and rate monitoring. See Attachment B —"Injection Logs" and tab that has"graph only". c. Daily monitoring data in an electronic format. See Attachment C—QA/QC of the electronic monitoring data that Canrig gathered for the first three injection episodes was performed and it was determined that the data was corrupted due to several factors. The attached is the manually recorded injection report spreadsheets that also have the accompanying graphs. Please note that Point Thomson Project is still working to establish the continuous injection system monitoring. We anticipate having the electronic monitoring system fully functional for the next quarterly UIC report. d. Physical, chemical, and other relevant characteristics of the injected fluid. See Attachment D—description of the wastes injected to date. e. Any well workover or other significant maintenance of downhole or injection related surface components. No well workover or other significant maintenance was conducted during the reporting period. f. Results of all mechanical integrity tests (MIT) performed since the previous report including any maintenance-related tests and any"practice"tests. The well commissioning MIT was conducted as part of the well drilling and completion activities. The MIT results and data were submitted to the EPA on May 29, 2015 as part of the UIC Well Completion Report(Reference No. ER-2015-OUT-250). g. Any other tests required by the Director. No other tests were required by the Director during this reporting period. If you have any questions, please contact Ben Wood at (907) 929-4108 or via email (ben.wood@exxonmobil.corn). An ExxonMobil Subsidiary "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." Sincerely, bl'CLZ—• Senior Project Manager Agent and Attorney-in-Fact for and On Behalf of Exxon Mobil Corporation Enclosures: Attachment A–EPA Form 7520-8 Attachment B–Graphical Plots of Continuous Injection Pressure and Rate Monitoring Attachment C –Daily Monitoring Data in an Electronic Format Attachment D–Point Thomson Project Waste Streams cc: Thor Cutler, EPA Attachment A US Environmental Protection Agency Form 7520-8 Database Template STEP 1.Copy this template in macro-enabled xlsm version using"Save As".Include Well name,Yr and Qtr with current file name. STEP 2.Fill in the highlighted cells with relevant information. Do not enter n/a in any cell.Fields(*)are mandatory. STEP 3.Enable macro.Press<CtrI><Shift><A>to run the macro and check data in Dbtable worksheet.Save file and submit. Important:Please do not change the position of any cell below.Do not copy/paste cells or insert/delete row or column, OPERATOR NAME` WELL' YEAR' PERMIT Point Thomson Unit PT DW-1 2015 AK-11015-A REPORTING MONTH APR MAY JUN INJ PRESSURE(MIN),PSI 0 INJ PRESSURE(AVG),PSI 1321 IN!PRESSURE(MAX),PSI 1983 INJ RATE(MIN),GPM 0 INJ RATE(AVG),GPM 129.4 INJ RATE(MAX),GPM 210 ANNULAR PRESSURE(MIN),PSI 0.8 ANNULAR PRESSURE(AVG),PSI 355.1 ANNULAR PRESSURE(MAX),PSI 1385 TOTAL INJ VOL(MONTH),GAL 160,419 ANNUAL INJ VOL(CUM),GAL 160,419 TEMPERATURE(MIN),°F 39 TEMPERATURE(AVG),°F 85.5 TEMPERATURE(MAX),°F 112 pH(MIN) pH(AVG) pH(MAX) SUBMITTED ON: 7/22/2015 (mm/dd/yyyy) Note:Injection operations started in June 2015 Note:pH not required for Class I well injected fluids Attachment B Appendix D Point Thomson Project (PTP) Waste Streams Physical, Chemical and Other Relevant Characteristics of the Injected Fluid Exempt Typical Primary Constituents Sampling Conducted or Waste Streams Exempt Sources Generator/Process Knowledge Drilling fluids,muds,produced • Drilling rig operations water,and other wastes E&P Exempt Wastes • Primary processing facilities and production associated with the exploration, Generator/Process Knowledge operations. development,or production of crude oil or natural gas Non-Exempt Typical Primary Constituents Sampling Conducted or Waste Streams Non-Exempt Sources Generator/Process Knowledge Used glycol/heat . Vehicles&equipment(antifreeze) Glycol(MEG,DEG,TEG, Glycol—Sampled on 6/29/15-Used exchange media propylene) glycol was non-hazardous; • Fluids recovered from cleanup of non- Water,snow,with hydrocarbon or Spot spill cleanup snow/water—Sampled Non-exempt spill on 3/16/15—Spot cleanup was non- exemptexempt spills chemical products(SDS clean-up • Spill impacted gravel or snow reviewed) hazardous.SDS's review if relevant for listed and/or toxicity characteristics. • Pressure test new or non-exempt process Water,glycol,possible product Hydro-test fluid lines,vessels residual in existing lines,traces of Hydro-test Fluids—Sampled 6/2/15- (water or glycol only) chlorine or other biocide and/or Hydro-test fluids were non-hazardous; oxygen scavenger Boiler blowdown—Sampled on 1/20/15 Boiler blowdown • Rig or facility boilers Water with scale remover additive—Non-hazardous,SDS reviewed and pH (Griffin Bros.AM110) conducted on each batch load Contained snow and Water(Secondary • Outdoor containment around fuel and Water,possible traces of Secondary containment water Containments/ponded chemical storage tanks hydrocarbon or chemicals if there Sampled on 6/2/15-non-hazardous water)—light sheen • Depressions on or between pads&roads have been spills present Ponded • Outdoor containment around fuel and Storm water,snow melt and Clean storm water/containment water— water/stormwater— chemical storage tanks contained water with no visible or Sampled on 6/28/13; (Visible no sheen present • Depressions on or between pads&roads perceived contaminants inspection/Generator knowledge) • Cement Rinsate generate from cleanup of CaMgCO3(Calcium Magnesium Cement Rinsate—Sampled on 6/2/15- Cement Rinsate cementing operations for Drilling or Carbonate)and water non-hazardous—Generator Knowledge Construction purposes 1. Note that similar wastes may be RCRA exempt,depending on waste-generating process. 2. Waste streams that were not generated or injected during a particular quarter are not usually sampled 110 s �� DStgr. UNITED STATES ENVIRONMENTAL PROTECTION AGENCY J 4' REGION 10 1200 Sixth Avenue, Suite 900 % ''ryeof a Seattle,Washington 98101-3140 off` '• IL sRoS- ` OFFICE OF COMPLIANCE AND ENFORCEMENT Reply to: OCE-101 CERTIFIED MAIL- RETURN RECEIPT REQUESTED Mr. Alex V. Podust Drilling Engineering Supervisor RECEIVED ExxonMobil CompanyAUG P. O. Box 190267 SCANNED taFr` 1,1' 48 0 2015 Anchorage, Alaska 99519.0267 AOGCC Re: Underground Injection Control (UIC) Program Class I Well PTDW1 under Permit Number AK-11015-A Final Approval to Inject into UIC Class I Well PTDW I Point Thomson Unit, North Slope Alaska Dear Mr. Podust: The U.S. Environmental Protection Agency, Region 10 (EPA),has received and reviewed the Completion Report plus witnessed the well construction, and mechanical integrity tests (MIT) conducted on ExxonMobil Class I Well PTDW I. Based on the review, plus on-site observations of the MIT, the EPA grants final approval to ExxonMobil under EPA UIC Permit number AIS-I I015-A to commence injection activities at Point Thomson Well PTDWI. The EPA looks forward to receiving the quarterly and annual reports required by the permit. We appreciate the cooperation of your staff during the well construction process. If you should have any questions. please do not hesitate to contact Thor Cutler of my staff at 206-553-1673 or at cutler.thor.cccpa.gov. ''nay., x r� w dw and J. Kowalski Director cc: Marc Bentley ADEC Division of Water/Wastewater Discharge Permits Chris Wallace j AOGCC i/ 1 4106 Exxon Mobil Development Com. Brier E.Reep ^ Post Office Box 190267 SSH&E Manager L Anchorage,Alaska 99519 Point Thomson Project 907 564 3617 Tel 907 743 9809 Fax DATA LOGGED S EonMobil v K BENDER June 25, 2015 ER-2015-OUT-290 e� Cathy Foerster, Chair ` Alaska Oil & Gas Conservation Commission 333 West Seventh Avenue, Suite 100 Anchorage, Alaska 99501-3572 RE: Log Files for PTU-DW1, Point Thomson Dear Commissioner Foerster: ExxonMobil hereby provides the following log files for PTU-DW1 pursuant to 20 AAC 25.071. Included in this package is (1) hard copy as well as PDF and LAS electronic files provided on CD for each open hole and cased hole log that was run on PTU-DW1. • Recorded Mode LWD (MD Based; 5"/100' Scale) • Recorded Mode LWD (TVD Based; 5"/100' Scale) • Formation Log (MD Based; 2"/100' Scale) • Formation Log (TVD Based; 2"/100' Scale) • 8-1/2" Sonic Scanner(MD Based) • 8-1/2" Sonic Scanner(TVD Based) • 8-1/2" Borehole Profile • 9-5/8" Cement Bond Log • 9-5/8" Isolation Scanner • 7" Sonic Scanner • 7" Ultrasonic • Water Flow Log/Temperature Log If you have any questions or require additional information, please contact Steve Calder at (907) 564-3787 or via email at (steve.calder@exxonmobil.com). Sincerely, •• ' ' For and On Behalf of ExxonMobil Alaska Production Inc. BER:sc:bt An ExxonMobil Subsidiary t , • • E*onMobil • POINT THOMSON Development . PRoI6 Nabors 27E 13-5/8" 10K BOPE Test Drain BOP stack, remove wear bushing and wash out stack and wellhead. Make up and RIH with 5 stands of HWDP below BOP test plug. Ensure wellhead annular access valves are open. BOP Tests will be conducted at a low pressure test of 200 psi and a high pressure test of 10,000 psi (PTU- DW1 High pressure test will be to 5,000 psi). The duration of each test will be 5 minutes. Upon initial rig-up and testing,the annular will be tested to 10,000 psi and will be tested in place of the Upper Pipe Rams on Test#5. For all subsequent tests,the annular will be tested to 7,500 psi along with the standpipe on Test#1. The gray valve and additional TIW valves will be tested offline. Test#1: Close the Annular and Choke&Kill manual valves. Open TIW, Lower,and Upper IBOP in top drive. Close the(3)4"valves on high pressure mud line. Note:Test to 7,500 psi on high pressure test. Do not test to 10,000 psi. Perform pressure test. Bleed off pressure. Open Annular and (3)4"valves on high pressure mud line. Test#2: Close Upper IBOP and Middle Pipe Rams. Perform pressure test to 10,000 psi. Bleed off pressure and open Upper IBOP and Middle Pipe Rams. Test#3: Close Lower IBOP and Master(Bottom) Pipe Rams. Test. Bleed off pressure and open Lower IBOP and Master(Bottom) Pipe Rams. Test#4: Close TIW and Upper Pipe Rams. Perform pressure test to 10,000 psi. (Choke & Kill manual valves remain closed from test#1.) Bleed off pressure and open Choke & Kill manual valves. Test#5: Close Choke & Kill HCV. (On initial rig up and test, close Annular and leave Upper Pipe Rams open.*) Perform pressure test to 10,000 psi. Bleed off pressure. Open Choke HCV,Annular, and Close Upper Pipe Rams.* • • E)KonMobil POINT THOMSON (� PROJECT Development- Test evelopmentTest#6: Close choke manifold valves 12, 16, 17, 18, and 19. Open remaining choke manifold valves. Perform pressure test to 10,000 psi. Bleed off pressure and open choke manifold valves 12, 16, 17,and 18. Test#7: Close choke manifold valves 5,6, 8, 11, 13, 14, and 15. Open remaining choke manifold valves. Perform pressure test to 10,000 psi. Bleed off pressure and open choke manifold valves 5, 6,8, 11, 13, 14, and 15. Test#8 Close 12, both manual chokes,and single superchoke. Open remaining choke manifold valves. This is a low pressure test of 200 psi only. Do not conduct a high pressure test. Perform pressure test to 200 psi. Bleed off pressure and open 12, both manual chokes, and single superchoke. Test#9 Close 4, 6,7,8,9, 10,and 11. Open remaining choke manifold valves. Perform pressure test to 10,000 psi. Bleed off pressure.And open 6, 7,8, 9, 10,and 11. Test#10:(Blind Ram Test) Unscrew test joint from test plug and pull test joint leaving the test plug in the wellhead. Close Blind Rams and valves 1, 2, 3,and 4. Perform Pressure Test to 10,000 psi through the kill line. Bleed off pressure and Open Blind Rams. Screw test joint back into test plug in wellhead and pull the test plug out of the wellhead section. Drain fluid from manifold and setup for a hard shut-in. RIH with wear bushing and prepare for next operation. Complete accumulator volume and pump capacity tests using ExxonMobil worksheets. • 0 ® I 7 3 To trip tank 13 (?8 18 Power 0 6 17 14 Choke 19 9 ® --> I ® 0 ® I --> From BOP 8 ® 2 To gas buster --0-----0-1 > 12 5 4 To flare 16 ® ® 11 15 Il II 10 1 To flow box ExxonMobil Development Come B .Reep RECEIVED Post Office Box 190267 SS Manager G Anchorage,Alaska 99519 Point Thomson Project 907 564 3617 Tel JUN 01 2015 907 743 9809 Fax AOGCC EonMobil May 29, 2015 ER-2015-OUT-251 Cathy Foerster, Chair Alaska Oil & Gas Conservation Commission 333 West Seventh Avenue, Suite 100 Anchorage, Alaska 99501-3572 RE: Well Completion Report and Log (Form 10-407) for ExxonMobil's UIC Class I Disposal Well PTU-DW1, Point Thomson Unit (PTD 214-206) Dear Commissioner Foerster: In accordance with 20 AAC 25.070(3) please find attached the Well Completion Report and Log, and accompanying attachments for PTU-DW1, Point Thomson Unit. Applicable electronic data and logs as specified in item 22 will be submitted by July 29. If you have any questions, please contact Steve Calder at (907) 564-3787 or via email at (steve.calder@exxonmobil.com), or Alex Podust at (907) 334-2978 or via e-mail at (alex.v.podust@exxonmobil.corn). Sincerely, For and On Behalf of ExxonMobil Alaska Production Inc. BER:sc:bt Enclosures: Well Completion Report and Log (Form 10-407) An ExxonMobil Subsidiary • STATE OF ALASKA • ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG la.Well Status: Oil ❑ Gas ❑ SPLUG L 1 Other ❑ Abandoned ❑ Suspended ill lb.Well Class: 20AAC 25.105 20AAC 25.110 Development ❑ Exploratory L_ 1 GINJ ❑ WINJ ❑ WAG ❑ WDSPL❑ No.of Completions: _1 Service U Stratigraphic Test ] _] 2.Operator Name: 6.Date Comp.,Susp.,or 14. Permit to Drill Number/ Sundry: ExxonMobil Alaska Production Inc. (EMAP) Aband.: 4/22/2015 214-206 3.Address: 7.Date Spudded: 15.API Number: P.O. Box 196601,Anchorage Alaska 99519-6601 3/10/2015 50-089-20032-00-00 4a. Location of Well(Governmental Section): 8. Date TD Reached: 16.Well Name and Number: Surface: 950'FSL, 1055 FEL,Sec.34,T 10N R 23E, UM 4/6/2015 PTU-DW1 . 0 Top of Productive Interval: 9. KB(ft above MSL): 46.1 • 17. Field/Pool(s): // �33'�G 1047 FNL,2202 FWL,Sec.3,T 9N R 23E,UM GL(ft above MSL): 12.7 . Point Thomson Unit ;_.-1.'tc1 .4. wfp>P 'Z"7 Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: :,,tl5% I 2337'FNL, 1405 FWL,Sec.3,T 9N R 23E, UM N/A SHL ADL 047559; BHL ADLSIA-7.57 D 4b. Location of Well(State Base Plane Coordinates,NAD 27): 11.Total Depth MD/TVD: 19. Land Use Permit: Surface: x- 46V49.01 . y- 5912922.90 ' Zone- 3 • 8800'/6905' - LO/NS 12-002 I b TPI: x- 466192.23 y- 5910515.59 Zone- 3 12.SSSV Depth MD/TVD: 20.Thickness of Permafrost MD/TVD: Total Depth: x- 465137.86 - y- 5909546.65 - Zone- 3 N/A 1799'/1799' 5.Directional or Inclination Survey: Yes Dttached) No Li 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 cjQ.c-. cew4C -0 le-WC4r. eiF 67251s -Gi 4 RECEIVED /U-6, 3//o/16 JUN 0 1 2015 23. CASING, LINER AND CEMENTING RECORD AOGCC WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD FT PULLED 20"x34" 129.5 X-52 34' 154' 34' 154' 42" 664 sx Arctic Grout N/A 9-5/8" 53.5 L-80 33' 4952' 33' 4435' 12-1/4" 2386 sx Arctic LiteCRETE; N/A 460 sx Class G 7" 26 1Cr L-80 30' 8781' 30' 6893' 8-1/2" 186 sx LiteCRETE HP; N/A 267 sx Class G 24.Open to production or injection? Yes [� No ❑ 25.TUBING RECORD If Yes,list each interval open(MD/TVD of Top and Bottom;Perforation Size SIZE DEPTH SET(MD) PACKER SET(MD/TVD) and Number): 4-1/2" 7100' 7018'/5757' Peri Top:8516'MD/6722'TVD ' Perf Bottom:8536'MD/6735'TVD __,.... 26.ACID,FRACTURE,CEMENT SQUEEZE, ETC. 2-7/8"Perf Size;6 SPF;60°Phasing; 120 Total Shots a + Was hydraulic fracturing used during completion?i Yes r] Non - Per 20 AAC 25.283(i)(2)attach electronic and printed information _,y DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED ijia N/A 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): 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: i Gas-MCF: Water-Bbl: Oil Gravity-API(corr): rPoWYr10 407 Rcviocd 5/2015 24-Hour Rate ► CONTINUED ON PACE 2 Submit ORIGINAL only je 5-'. RBDMS AUG 2 5 2015 "`j lk /5-r/> 5'-346, • • 28.CORE DATA Conventional Core(s): Yes ❑ No Q • Sidewall Cores: Yes ❑ No ❑✓ • 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 El Permafrost-Top 33' 33' If yes,list intervals and formations tested,briefly summarizing test results. Permafrost-Base 1832' 1832' Attach separate pages to this form,if needed,and submit detailed test OG40-Top 4136' 3891' information,including reports,per 20 AAC 25.071. OG40-Base 4746' 4304' OG75 5020' 4479' Upper Confining Zone-Top 5534' 4810' Upper Confining Zone-Base 6055' 5142' Injection Zone-Top 7110' 5817' Injection Zone-Base 8515' 6722' Formation at total depth:Mikkelsen 8800' 6905' 31. List of Attachments: Daily Operations Reports(Spud through Completion);Final Wellbore Schematic;Final Directional Survey Report Information to be attached includes,but is not limited to:summary of daily operations,wellbore schematic,directional or inclination survey,core analysis, paleontological report,production or well test results,per 20 AAC 25.070. 32. I hereby certify that he foreg ng is true and correct to the best of my knowledge. //�� Contact: / ct Email: /fx,(/ f CW P/.�'A'Oinektel�77C.(�l7NL Printed Name:certify se Title: pri/j' metemetepsy f VLSOI Signature: Mii,(4,14 Phone: "32 62 2721 Date: S/oZq�r INSTRUCTIONS 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 la: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated.Each segregated pool is a completion. Item 1b: Well Class-Service wells:Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection, Observation,or Other. Item 4b: TPI(Top of Producing Interval). Item 9: The Kelly Bushing and Ground Level 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 5/2015 Submit ORIGINAL Only • • EKonlVlobil Surface Location: Rig Nabors 27E Point Thomson RKB-GL 33.42 ft PTU-DW1 (Disposal Well) Central Pad,Slot#1 GL-MSL 12.7 ft RKB-MSL 46.12 ft Insulated Conductor 20"x 34"129.5#X-52 Welded 154'MD/TVD Port Collar:493'MD/TVD W re 1._____k U w J Permafrost Base:1,832'MD/TVD °-. KOP:1,846'MD/TVD 12-1/4"Hole QTop of Tail:+/-3,952'MD/3,756'TVD C9 K�al'.cj d 24 9-5/8"53.5#L-80 VAM TOP KX .mpj Top of Lead:+/-4,905'MD/4,405'TVD 4,952'MD/4,435'TVD 4 TD:4,960'MD/4,440'TVD OG-75:5,020'MD/4,479'TVD a I w °' 8-1/2"Hole w a. a ce o U C" a J Swell Packer#2:5,512'MD/4,795'TVD 5,534'MDI 4,810'TVD Upper Confining Zone Swell Packer#1:6,051'MD/5,140'TVD 6,055'MD/5,142'TVD Top of Tail:+/-6,785'MD/5,608'TVD 4-1/2"12.6#1%Cr L-80 VAM TOP Injection Packer:7,018'MD/5,757'TVD 7,100'MD!5,810'TVD __ 7,110'MD/5,817'TVD I Injection Zone [ Contingency Perf Interval { 8,515'MD/6,722'TVD a._ y Perf Interval:8,516'-8,536'MD/6,722'-6,735'TVD 7"26#1%Cr L-80 TSH 563 8,781'MD/6,893'TVD TD:8,800'MD/6,905'TVD • NOTE:All depths RKB • • ExxonMobil Development Company Brien E.Beep Post Office Box 190267 55H&E Manager Anchorage,Alaska 99519 Point Thomson Project 907 564 3617 Tel 907 743 9809 Fax EonMobil June 25, 2015 ER-2015-OUT-290 5zz Cathy Foerster, Chair 4-0q.S V ,, ` Alaska OH & Gas Conservation Commission J 333 West Seventh Avenue, Suite 100 Anchorage, Alaska 99501-3572 RE: Log Files for PTU-DW1, Point Thomson Dear Commissioner Foerster: ExxonMobil hereby provides the following log files for PTU-DW1 pursuant to 20 AAC 25.071. Included in this package is (1) hard copy as well as PDF and LAS electronic files provided on CD for each open hole and cased hole log that was run on PTU-DW1. • Recorded Mode LWD (MD Based; 5"/100' Scale) • Recorded Mode LWD (TVD Based; 5"/100' Scale) • Formation Log (MD Based; 2"1100' Scale) • Formation Log (TVD Based; 2"1100' Scale) • 8-1/2" Sonic Scanner(MD Based) • 8-1/2" Sonic Scanner(ND Based) • 8-1/2" Borehole Profile • 9-5/8" Cement Bond Log • 9-5/8" Isolation Scanner • 7" Sonic Scanner • 7" Ultrasonic • Water Flow Log/Temperature Log If you have any questions or require additional information, please contact Steve Calder at (907) 564-3787 or via email at(steve.calder@exxonmobil.com). Sincerely, Aar For and On Behalf of ExxonMobil Alaska Production Inc. BER:sc:bt 11110 Partners Report by Day ElanMobil Development Company Report Date/Time: 3/10/2015 00:00 to 3/11/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 258 258 103.60 0 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 0.00 0.00 0.00 34"x20" Insulated Conductor at 154.4' Activity at Report Time Next Activity Circulating hole clean at 130'MD. Wash down to 258'MD,check MWD tools,and drill ahead. Date/Time Density(lb/gal) FV(s/qt) API FL(mL/30min) PV(cP) YP(Ibf/100ft1 3/10/2015 21:00 10.00 202 11.0 23.0 54 Start End Time Time Comments 00:00 01:00 Lubricate the rig,clean and clear the rig floor. 01:00 02:30 Pick up first stand of HWDP.Torque up stand with rig tongs.Verify make-up with iron roughneck and TDS. 02:30 04:30 Circulate mud and wash down HWDP inside conductor. Stage mud pumps up to 400 GPM. a. 15 RPM=2000 ft-lb torque 04:30 12:00 TDS developed a hydraulic leak. a.Attempt to replace 0-ring and tighten same with no success. b.Remove hose from pressure block and test same. i. Found several pin holes just below connection at pressure block. Hose appeared to be crushed. c.Fabricate new hose and test same prior to installing onto TDS.Test good. 12:00 12:30 Circulate mud and hold meeting prior to spudding well. 12:30 16:30 Ream inside conductor from 134'MD to 155'MD.Spud well at 14:30 hrs. Drill ahead from 155'MD to 258'MD. �� a.WOB=10 klb b.RPM=40 c.GPM=410 d.SPP=384 psi 16:30 18:00 POOH from 258'MD to surface to swap out BHA. 18:00 00:00 Pick up measurement tools for BHA#2. Function diverter.Calibrate NOV EDS break system. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Security Type: Drilling_XOM vers 20091208 wv9 Printed: 5/27/2015 Partners Report by Day • ExxI obil Development Company Report Date/Time: 3/11/2015 00:00 to 3/12/2015 00:00 Well Name: PTU-DW 1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 1,452 1,452 1,194.00 1 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 0.00 0.00 0.00 34"x20" Insulated Conductor at 154.4' Activity at Report Time Next Activity Drilling at 1,452'MD. Continue drilling ahead as per directional plan. Date/Time Density(lb/gal) FV(s/qt) API FL(mU3Omin) PV(cP) _ YP(Ibf1100ft') 3/11/2015 21:00 10.00 200 12.4 16.0 67 Start End Time Time Comments 00:00 01:00 TIH to 220'MD. -Take returns back to the trip tank. -Wash from 220'MD to 258'MD.Did not observe fill on bottom. 01:00 06:00 Drill from 258'MD to 490'MD with 12.25"directional BHA#2. WOB: 10 klb RPM: 45 TRQ: 3000 ft-lb GPM: 535 SPP: 840 psi ECD: 10.3 ppge ROP: 46.40 fph(all-in) Lithology at 490' MD: 20%Siltstone/10%Cong./70%Sand Mud Check at 490'MD: 10.0 ppg/185 sec/L FV 06:00 12:00 Drill from 490'MD to 750'MD with 12.25"directional BHA#2. WOB: 10 klb RPM: 50 TRQ: 3000 ft-lb GPM: 535 SPP: 840 psi ECD: 10.8 ppge ROP: 43.33 fph(all-in) Lithology at 750'MD: 10%Siltstone/20%Cong./70%Sand Mud Check at 750'MD: 10.0 ppg/185 sec/L FV 12:00 18:00 Drill from 750'to 1110'with 12.25"directional BHA#2. WOB: 10 klb RPM: 55 TRQ: 3000 ft-lb GPM: 535 SPP: 840 psi ECD: 11.07 ppge ROP: 60.00 fph(all-in) Lithology at 1110' MD: 20%Siltstone/20%Cong./60%Sand Mud Check at 1110'MD:10.0 ppg/188 sec/L FV 18:00 00:00 Drill from 1110'MD to 1452'MD with 12.25"directional BHA#2. WOB: 10 klb RPM: 55 TRQ: 3000 ft-lb GPM: 535 SPP: 840 psi ECD: 11.07 ppge ROP: 54.16 fph(all-in) Lithology at 1435' MD: 10%Siltstone/10%Shale/10%Cong./70%Sand Mud Check at 1435'MD:10.0 ppg/187 sec/L FV Added 10 BPH of water for 1 hr to decrease YP to within programmed range(YP=69). Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 4,322.0 34,516.9 5,062.0 45,672.9 0.0 11,156.0 Water-Fresh-Surface 1 US Gallon 9,786.0 36,708.0 8,022.0 50,862.0 0.0 14,154.0 Water Fuel-Diesel 1 US Gallon 945.0 4,808.0 7.263.0 0.0 2,455.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • E•nMobil Development Company Report Date/Time: 3/12/2015 00:00 to 3/13/2015 00:00 Well Name: PTU-DWI Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 2,500 2,491 1,048.00 2 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 0.00 0.00 0.00 34"x20" Insulated Conductor at 154.4' Activity at Report Time Next Activity Drilling at 2500'MD. Continue drilling ahead as per directional plan. Date/Time Density(Ib/gal) FV(s/qt) API FL(mL/30min) PV(cP) YP(lbf/100ft2) 3/12/2015 03:00 10.00 190 12.6 17.0 50 3/12/2015 09:00 10.00 188 12.4 17.0 50 3/12/2015 14:15 10.10 189 12.4 20.0 48 3/12/2015 21:00 10.10 200 12.0 20.0 60 Start End Time Time Comments 00:00 03:30 Drill from 1452'MD to 1623'MD with 12.25"directional BHA#2. WOB: 15 klb RPM: 55 TRQ: 4000 ft-lb GPM: 555 SPP: 1100 psi ECD: 11.07 ppg ROP: 48.8 fph(all-in) Lithology at 1623' MD: 30%Claystone/10%Siltstone/30%Cong./30%Sand. Mud Check at 1623'MD:In and out 10.1 ppg/189 sec/L FV 03:30 04:00 Service TDS and related equipment. -TDS break system would not engage. -Bleed hydraulics on TDS brake system. -Break held after getting the air out of the system. 04:00 12:00 Drill from 1623'MD to 1940'MD with 12.25"directional BHA#2. WOB: 15 klb RPM: 50 TRQ: 6000 ft-lb GPM: 550 SPP: 1100 psi ECD: 11.08 ppg ROP: 39.6 fph(all-in) Lithology at 1940' MD: 20%Claystone/60%Cong./20%Sand. Mud Check at1940' MD: In and out 10.1 ppg/189 sec/L FV Note: Kicked-off at 1846'MD. 12:00 12:30 Service TDS and drawworks as per Nabors specifications. 12:30 00:00 Drill from 1940'MD to 2500'MD with 12.25"directional BHA#2. WOB: 15 klb RPM: 50 TRQ: 6000 ft-lb GPM: 550 SPP. 1100 psi ECD: 11.08 ppg ROP: 48.6 fph(all-in) Lithology at 2500' MD: 40%Claystone/60%Sand. Mud Check at 2500'MD:10.1 ppg/189 sec/L FV Note:Drill Cool system went down at 16:00 hrs. +Suction and discharge lines froze up. +Change out frozen lines.Trunk heat:thaw unit and plumbing. +Mud temperature in 70.6°and out 70.1°max. +Fabricate a hooch for lines and trunk in ES700 heaters. Last survey:2390'MD, 13.12 Inc.,217.51 Azim. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 4,122.0 38,638.9 4,566.0 50,238.9 0.0 11,600.0 Water-Fresh-Surface 1 US Gallon 11,466.0 48,174.0 11,634.0 62,496.0 0.0 14,322.0 Water Fuel-Diesel 1 US Gallon 860.0 5,668.0 545.0 7,808.0 0.0 2,140.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • ExxSobil Development Company Report Date/Time: 3/13/2015 00:00 to 3/14/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 3,255 3,190 755.00 3 55.83 Average Background Gas Average Connection Gas Average Trip Gas 'Last Casing String 10.00 0.00 0.00 34"x20" Insulated Conductor at 154.4' Activity at Report Time 'Next Activity Drilling at 3255'MD. Continue drilling ahead as per directional plan. Date/Time Density(lb/gal) FV(s/qt) API FL(mL/30min) PV(cP) YP(Ibf/100tt) 3/13/2015 03:00 10.20 215 12.6 21.0 53 3/13/2015 09:00 10.20 208 12.0 24.0 64 3/13/2015 15:00 10.20 218 12.4 18.0 68 3/13/2015 21:00 10.20 245 11.0 20.0 65 Start End Time Time Comments 00:00 11:00 Drill from 2500'MD to 2841'MD with 12.25"directional BHA#2. WOB: 15 klb RPM: 50 TRQ: 5000 ft-lb GPM: 600 SPP: 1350 psi ECD: 11.08 ppg ROP: 31.00 fph(all-in) Lithology at 2841'MD: 10%Claystone/60%Sand/30%Conglomerate Mud Check at 2841'MD:10.1 ppg/189 sec/L FV 11:00 12:00 Service TDS and drawworks as per Nabors specifications. 12:00 13:00 Change out die block in back-up wrench on the TDS. a. No spare/dress die blocks on location.Spares set on order. b.Change out dies in die block. 13:00 00:00 Drill from 2841'MD to 3255'MD with 12.25"directional BHA#2. WOB:20 klb RPM: 50 TRQ: 5000 ft-lb GPM: 600 SPP: 1400 psi ECD: 11.08 ppg ROP: 37.63 fph(all-in) Lithology at 3255' MD: 30%Claystone/40%Sand/10%Conglomerate/20%Siltstone. Mud Check at 3255'MD:10.2 ppg/189 sec/L FV Last directional survey:3139'MD,26.61 Inc.,219.54 Azim. -11'above plan. -0.8'to the right of plan. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 4,639.0 43,277.9 4.565.0 54,803.9 0.0 11,526.0 Water-Fresh-Surface 1 US Gallon 10,500.0 58,674.0 11,298.0 73,794.0 0.0 15,120.0 Water Fuel-Diesel 1 US Gallon 983.0 6,651.0 497.0 8,305.0 0.0 1,654.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • E•nMobil Development Company Report Date/Time: 3/14/2015 00:00 to 3/15/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 3,927 3,738 672.00 4 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 12.00 0.00 0.00 34"x20" Insulated Conductor at 154.4' Activity at Report Time Next Activity Drilling at 3927'MD. Continue drilling ahead as per directional plan. Date/Time Density(lb/gal) FV(s/qt) API FL(mL/30min) PV(cP) YP(Ibf/100ftf) 3/14/2015 00:00 10.20 130 12.2 30.0 52 3/14/2015 03:20 10.10 121 12.0 16.0 55 3/14/2015 07:40 10.10 105 12.0 21.0 42 3/14/2015 15:40 10.10 120 11.5 24.0 44 3/14/2015 21:00 10.20 130 12.2 30.0 52 Start End Time Time Comments 00:00 03:30 Drill from 3255'MD to 3359'MD with 12.25"directional BHA#2. WOB:20 klb RPM: 50 TRQ: 5000 ft-lb GPM: 600 SPP: 1400 psi ECD: 11.08 ppg ROP: 29.71 fph(all-in) Lithology at 3359' MD: 30%Claystone/40%Sand/10%Conglomerate/20%Siltstone. Mud Check at 3359'MD:10.2 ppg/200 sec/L FV 03:30 05:30 Observed 1000 psi loss of pump pressure resulting from packoff of pump suction screens(Mud Pump#3 100%packed-off; Mud Pump#2 25%packed-oft).Clean mud pump suction screens. 05:30 00:00 Drill from 3359'MD to 3927'MD with 12.25"directional BHA#2. WOB:20 klb RPM: 60 TRQ: 6000 ft-lb GPM: 600 SPP: 1500 psi ECD: 11.3 ppg ROP: 37.63 fph(all-in) Lithology at 3927'MD: 40%Sand/30%Claystone/10%Shale/20%Siltstone Mud Check at 3927'MD:10.2 ppg/200 sec/L FV Last directional survey: 3886'MD,40.95 Inc.,217.85 Azim. -15'above plan. -0.3'to the left of plan. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts _ Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 5,319.0 48,596.9 5,467.0 60,270.9 0.0 11,674.0 Water-Fresh-Surface 1 US Gallon 10,122.0 68,796.0 17,472.0 91,266.0 0.0 22,470.0 Water Fuel-Diesel 1 US Gallon 1,037.0 7,688.0 2,234.0 10,539.0 0.0 2,851.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • Exx.obil Development Company Report Date/Time: 3/15/2015 00:00 to 3/16/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors..27E 4,181 3,924 254.00 5 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 9.00 0.00 0.00 34"x20" Insulated Conductor at 154.4'MD. Activity at Report Time Next Activity POOH to change out bit at 1146'MD. POOH to surface, inspect/download tools,change out bit, RIH,and drill ahead. Date/time Density(lb/gal) FV(s/qt) API FL(mLl30min) PV(cP) YP(Ibf/100fr) 3/15/2015 10:15 10.20 108 12.0 18.0 50 3/15/2015 10:15 10.20 87 12.4 22.0 41 3/15/2015 16:00 10.20 119 12.2 20.0 56 3/15/2015 21:00 10.20 121 12.2 22.0 54 Start End Time Time Comments 00:00 03:15 Drill from 3927'MD to 3987'MD with 12.25"directional BHA#2. WOB:25 klb RPM: 60 TRQ: 9000 ft-lb GPM: 600 SPP: 1500 psi ECD: 11.0 ppg ROP: 18.46 fph(all-in) Lithology at 3987' MD: 40%Sand/30%Claystone/10%Shale/20%Siltstone. Mud Check at 3987'MD:10.2 ppg/200 sec/L FV Rocklt system ineffective(sliding ROP= 11.5 fph avg). Observe 600 psi loss of pump pressure at 3987'MD resulting from packoff of mud pump suction screen. 03:15 05:00 Rack back one stand,Circulate and condition mud at reduced rate while working pipe. GPM: 315 SPP. 500 psi Mud pump#3 suction screen packed off from nut plug and cuttings.Clean out suction screen. Install new encoder on TDS for Canrig Rocklt system.Function Rocklt system:ok. 05:00 14:15 Drill from 3987'MD to 4181'MD with 12.25"directional BHA#2. WOB: 25 klb RPM: 60 TRQ: 8000 ft-lb GPM: 600 SPP: 1580 psi ECD: 11.0 ppg ROP: 21.0 fph(all-in) Lithology at 4181' MD: 50%Claystone/30%Shale/10%Siltstone/10%Sand Mud Check at 4181'MD:10.2 ppg/160 sec/L FV Directional Survey at 4181' MD: 45.37°Inc/217.09°Az/5.6'Left/13.8'High Mud Temp at 4181' MD: 57°In/52°Out Rocklt system effective(sliding ROP=20 fph avg). Rocklt system failed-not working after slide. Decision made to POOH to change out bit due to insufficient ROP. 14:15 21:00 Backream out of hole from 4181'MD to 3208'MD with 12.25"directional BHA#2. RPM: 60 TRQ: 6000-12,000 ft-lb GPM: 550 SPP: 1165 psi ECD: 11.26 ppg Mud Check at 3213'MD:10.3+ppg/121 sec/L FV Pump 30 bbl of 11.0 ppg weighted sweep at 4181'MD and circulate out of hole.Work through multiple tight spots.POOH on elevators from 3962'-3767'MD. Encountered tight spot at 3767'MD.Continued backreaming to 3208'MD. Tight Spots/High Torque Spots:4130',4030',4000', 3900',3700',3500',3320'MD. 21:00 00:00 POOH on elevators from 3208'MD to 1146'MD. Hole took 3.73 bbls over calculated volume. Able to work through all tight spots on elevators. Tight Spots:3110',3050',2566',2470',2381',2200',2183', 1860', 1692'MD. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts _ Cum Receipts _ Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 4,587.0 53,183.9 3.625.0 63,895.9 0.0 10,712.0 Water-Fresh-Surface 1 US Gallon 9,702.0 78,498.0 8,022.0 99,288.0 0.0 20,790.0 Water Fuel-Diesel 1 US Gallon 1,283.0 8,971.0 1,850.0 12,389.0 0.0 3,418.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • ElanMobil Development Company Report Date/Time: 3/16/2015 00:00 to 3/17/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors.27E 4,181 3924 0.00 6 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 0.00 0.00 0.00 34"x20" Insulated Conductor at 154.4'MD. Activity at Report Time Next Activity RIH with BHA#3 at 3950'MD. RIH to 4181'MD.Drill ahead in 12.25"surface hole to section TD. Date/Time Density(lb/gal) FV(s/qt) API FL(mL/30min) PV(cP) YP(Ibf/100ftf) 3/16/2015 04:30 10.20 121 12.2 23.0 56 3/16/2015 07:00 10.20 183 12.6 22.0 58 3/16/2015 15:00 10.10 215 12.0 24.0 57 3/16/2015 21:00 10.10 205 12.0 22.0 57 Start End Time Time Comments 00:00 05:15 POOH on elevators racking back from 1146'MD to 190'MD. No tight spots were observed. 05:15 05:30 Pump out of hole to inside conductor shoe from 190'MD to 150'MD.Circulate conductor clean. GPM: 300 SPP: 300 psi RPM: 15 No mud rings or heavy loading at the shakers was observed while circulating inside conductor. 05:30 09:30 POOH on elevators racking back BHA from 190'MD to surface. All stabilizers in gauge but packed with heavy clay and worn on leading edge of blades.Mill tooth bit 1/8"under gauge. 09:30 11:00 Pick up and make up 12.25"BHI VMD-3 bit to mud motor and RIH with directional BHA#3 from surface to 94'MD. 11:00 16:00 Perform rig service on TDS and blocks per Nabors specifications. Change out lube oil and filters on TDS.Trunk in heaters and steam to heat TDS gear case(-15°F prior to oil change). Note:Hole taking 1.71 bph. 16:00 00:00 RIH with 12.25"directional BHA#3 from 94'MD to 3950'MD.Check MWD tools at 2177'MD:ok. Hole returned 4.3 bbls under calculated displacement. Tight Spots: 1850',3780'MD. Able to work through all tight spots on elevators. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 3,647.0 56,830.9 4,979.0 68,874.9 0.0 12,044.0 Water-Fresh-Surface 1 US Gallon 11,130.0 89,628.0 11.592.0 110,880.0 0.0 21,252.0 Water Fuel-Diesel 1 US Gallon 819.0 9,790.0 2,000.0 14,389.0 0.0 4,599.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • Exxlobil Development Company Report Date/Time: 3/17/2015 00:00 to 3/18/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 4,804 4,341 623.00 7 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 12.00 0.00 26.00 34"x20" Insulated Conductor at 154.4'MD. Activity at Report Time Next Activity Drilling at 4804'MD. Drill ahead in 12.25"surface hole to section TD. Date/Time Density(Ib/gal) FV(s/qt) API FL(mL/3omin) PV(cP) YP(Ibf/100ftl 3/17/2015 15:00 10.20 126 11.0 20.0 57 3/17/2015 21:00 10.10 121 9.6 27.0 55 Start End Time Time Comments 00:00 05:00 Wash and ream from 3950'MD to 4181'MD. Note:Performed mad pass correlation log. 05:00 12:00 Drill from 4181'MD to 4369'MD with 12.25"directional BHA#3. WOB:25 klb RPM: 60 TRQ: 8000 ft-lb GPM: 600 SPP: 1500 psi ECD: 11.0 ppg ROP: 26.9 fph(all-in) Lithology at 4369' MD: 80%Conglomerate/20%Sand. Mud Check at 4369'MD: 10.2 ppg/160 sec/L FV Directional Survey at 4369' MD: 46.19°Inc./216.51°Az. Mud Temp at 4369' MD: 55.6°In/63.0°Out 12:00 12:30 Service TDS and drawworks as per Nabors specifications. 12:30 00:00 Drill from 4369'MD to 4804'MD with 12.25"directional BHA#3. WOB:25 klb RPM: 60 TRQ: 11,000 ft-lb GPM: 640 SPP: 1575 psi ECD: 11.0 ppg ROP: 37.8 fph(all-in) Lithology at 4804'MD: 40%Conglomerate/40%Sand/20%Siltstone Mud Check at 4804'MD: 10.2 ppg/160 sec/L FV Directional Survey at 4730' MD: 49.62°Inc./218,33°Az./32.0'Left/6.0'Below. Mud Temp at 4804'MD: 62.3°In/61.6°Out Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns _ Cum Returns Inventory Fuel-Diesel 1 US Gallon 4,735.0 61,565.9 3,551.0 72,425.9 0.0 10,860.0 Water-Fresh-Surface 1 US Gallon 15,330.0 104,958.0 10,416.0 121,296.0 0.0 16,338.0 Water Fuel-Diesel 1 US Gallon 819.0 10,609.0 14,389.0 0.0 3,780.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • nMobil Development Company Report Date/Time: 3/18/2015 00:00 to 3/19/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors.27E 4,960 4,440 156.00 8 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 4.00 0.00 12.00 34"x20" Insulated Conductor at 154.4'MD. Activity at Report Time Next Activity POOH on elevators at 2642'MD. POOH to surface and prepare to run 9 5/8"casing. DatefTime Density(lb/gal) FV(s/qt) API FL(mL/30min) PV(cP) YP(Ibf/100ft0) 3/18/2015 15:00 10.30 79 9.8 17.0 44 3/18/2015 21:00 10.30 8,5 9.4 15.0 49 Start End r, (� Time Time Comments ' 00:00 05:00 Drill.from 4804'MD to TD at 4960'MD/4440'TVD with 12.25"directional BHA#3. "IL./ WOB:25 klb RPM: 50 TRQ: 11,000 ft-lb GPM: 645 SPP: 1650 psi ECD: 11.2 ppg ROP: 31.2 fph(all-in) Lithology at 4960'MD: 30%Claystone/20%Conglomerate Sand/20%Sand/10%Conglomerate/10%Siltstone/10%Shale Mud Check at 4960'MD: 10.2 ppg/160 sec/L FV Directional Survey at 4960'MD: 50.81°Inc./218.41°Az./41.0'Left/4.2'Below Mud Temp at 4960'MD: 58° 05:00 07:30 Circulate and condition wellbore while MR MC WOW from 4960'MD to 4617'MD. RPM: 50 TRQ: 10,000 ft-lb GPM: 650 SPP: 1550 psi 07:30 10:00 POOH on elevators from 4617'MD to 4200'MD wiping through tight spots(45 klb max.overpull encountered). Observed tight spots from 4450'to 4440'MD,4265'to 4258'MD,and 4205'to 4202'MD. 10:00 11:00 EDS power failure. Recalibrate EDS system. 11:00 15:00 Backream from 4200'MD to 3307'MD. RPM: 60 TRQ: 11,000 ft-lb GPM: 650 SPP: 1525 psi Note:Attempt to pull on elevators at 4060'MD and 3619'MD(observed 30 klb overpull). 15:00 16:00 Circulate and condition mud while performing MR MC WOW from 3307'MD to 3115'MD. RPM: 60 TRQ: 6,000 ft-lb GPM: 700 SPP: 1650 psi Note: Reduced parameters to 550 GPM, 1000 psi SPP,20 RPM,and 5,000 ft-lb on down ream. Pull on elevators at 3050'MD:no drag observed. Large amount of cuttings observed over the shakers. 16:00 18:00 RIH from 3115'MD to 4960'MD. Observed minor tight spot at 3810'MD. 18:00 20:30 Circulate and condition mud while performing MR MC WOW from 4960'MD to 4700'MD. RPM: 60 TRQ: 6,000 ft-lb GPM: 700 SPP: 1700 psi Note: Reduced parameters to 550 GPM, 1100 psi SPP,20 RPM,and 5,000 ft-lb on down ream. Large amount of cuttings observed over the shakers. 20:30 21:00 Attempt to POOH from 4700'observed well to be swabbing&surging.RIH from 4700'MD to 4960'MD. 21:00 22:00 Circulate and condition wellbore from 4960'MD to 4899'MD. RPM: 60 TRQ: 6,000 ft-lb GPM: 700 SPP: 1800 psi Note: Reduced parameters to 20 RPM and 5,000 ft-lb during down ream. Pump water at 5 bpm into active pits to thin back mud. 22:00 00:00 POOH on elevators from 4899'MD to 2642'MD at report time. P/U hookload: 150 klb S/O hookload: 140 klb Avg.overpull: 10-15 klb Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • Exxobil Development Company Report Date/Time: 3/19/2015 00:00 to 3/20/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors.27E 4,960 4,440 0.00 9 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 34"x20" Insulated Conductor at 154.4'MD. Activity at Report Time Next Activity Running 9-5/8"casing at 291'MD. RIH with 9-5/8"casing to 4952'MD.Circulate and condition mud for the cement job. Date/Time Density(lb/gal) FV(s/qt) API FL(mU3Omin) PV(cP) YP(Ibf1100ft') 3/19/2015 21:00 10.20 100 11.0 22.0 35 Start End Time Time Comments 00:00 04:00 POOH on elevators from 2562'MD to 221'MD. No tight spots were observed. Note: -P/U hookload: 115 klb;5/0 hookload: 105 klb -Avg.overpull: 10-15 klb -Performed annular function test. 04:00 09:00 Lay down 12-1/4"BHA from 221'MD. Note: -P/U hookload:75 klb;S/O hookload:75 klb -Top stabilizer was 1/16"under gauge. -Middle stabilizer was 1/8"under gauge. -Bottom stabilizer was 1/16"under gauge. -All stabilizers packed with clay/gravel between blades. -Mud motor was 1/8"under gauge. -Bit grade:2,3,WT,A, E, 1, NO,TD 09:00 10:00 Clean and clear rig floor.Removed BHA components and handling equipment. 10:00 19:00 Rig up Tesco casing equipment. Held PJSM with all personnel involved in rigging up casing equipment.Rig down elevators and bails. Rig up Tesco CRT,running tool service loop,and torque turn equipment. Note: -Primary hydraulic casing slips failed;rig up back up slips. -Stage centralizers on rig floor and beaver slide. 19:00 20:45 Begin running 9-5/8"casing. Note: -Held PJSM with all personnel involved in casing running operations. -Performed torque test at 10, 15 and 20 klb with TDS and torque turn to verify accuracy. -Make up shoe track and baker lok joints. 20:45 23:30 Troubleshoot Tesco torque turn equipment.Torque turn not reading turns while trying to make up pipe. Rig down torque encoder and reset drive wheel.Test and verify torque encoder reading properly. Note: -TDS gripper box came in contact with Tesco torque encoder while making up previous joint. -Circulated through floats and verified function. 23:30 00:00 Continue running 9-5/8"casing at 291'MD at report time. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day . AinMobil Development Company Report Date/Time: 3/20/2015 00:00 to 3/21/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors.27E 4,960 4,440 0.00 10 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 34"x20" Insulated Conductor at 154.4'MD. Activity at Report Time Next Activity Holding PJSM to rig down Tesco CRT equipment. Cement 9 5/8"surface casing. Date/Time Density(lb/gal) FV(s/qt) API FL(mL/30min) PV(cP) YP(Ibf/100ft') 3/20/2015 21:00 10.20 96 11.0 20.0 17 Start End Time Time Comments 00:00 17:00 Run 9-5/8"surface casino from 291'MD to 4952'MD. -Fill on the fly;top off every 15 joints -3903'MD:S/O 147 klbs, P/U 240 klbs -4570'MD:S/0 165 klbs, P/U 285 klbs -4850'MD:S/0 160 klbs, P/U 320 klbs -4945'MD:S/O 185 klbs, P/U 310 klbs -Tagged bottom with 10 klb WOB at 16:00 hrs Note: -Installed bow spring centralizers on joints 1-71 (1842'MD to 4827'MD). -No centralizers across permafrost zone. -Installed rigid positive centralizer inside conductor(joint 113),which required removal of Tesco casing slips. 17:00 00:00 Circulate and condition mud for 9 5/8"cement job. Note: -Reciprocate casing 10'up and down(S/O 190 klb, P/U 300 klb). -7 units methane gas circulated out on first bottoms up. -18:30 hrs:70%conglomerate sand, 10%siltstone,20%clay -20:30 hrs:shakers clean of cuttings Concurrent operations: -Fill rig tanks with fresh water. -Empty cellar. -Build 10.7 ppg MudPush spacer. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day S Exxobil Development Company Report Date/Time: 3/21/2015 00:00 to 3/22/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 2 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors.27E 4,960 4.440 0.00 11 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 9 5/8"Surface Casing at 4,952'MD. Activity at Report Time Next Activity N/D diverter line. N/D diverter system. Date/Time Density(lb/gal) FV(s/qt) API FL(mL/30min) PV(cP) YP(Ibf/100ftZ) 3/21/2015 15:00 10.10 90 11.7 21.0 18 3/21/2015 21:00 10.10 90 11.6 21.0 16 Start End Time Time Comments 00:00 01:00 Circulate and condition wellbore for cement operations. -GPM:500,SPP:250 psi -Reciprocating pipe 10' -S/0: 190 klb, P/U:300 klb -MW: 10.1 ppg, PV:20 cp,YP: 17 lbf/100 ft2,6 RPM: 11,Solids Volume:9% Concurrent operations: -Held PJSM for R/D of Tesco CRT. 01:00 03:00 Rig down CRT equipment. -Blow down standpipe. -R/D Tesco CRT. -Install bails and 150 ton elevators. Note: -Attempted to pick up pipe after rigging down CRT equipment:unable to reciprocate pipe due to 150 ton elevators. Concurrent operations: -Monitor well on trip tank. -Continue to mix MudPush spacer. 03:00 04:30 Rig up cement head and lines. -Make up crossover and install Schlumberger cement head. -Pump air through lines to cement unit to verify no obstructions. 04:30 09:00 Circulate through cement head. -Attempt to reciprocate pipe while circulating:unable to reciprocate pipe. Concurrent operations -Finished building MudPush spacer. -Finished transferring fluid to auxiliary mud pits. -Rig up back-up cement unit and tie-in. -Held PJSM with all personnel involved in cementing operations and fluid handling at surface. 09:00 10:00 Line-up cement unit and break circulation with 10 bbls fresh water.Attempt to pressure test cement lines to 3,500 psi:unsuccessful. Found cement coflex leaking from connection at gooseneck in derrick.Also observed leaking flange in suitcase. Swap over to kill line and pressure test same to 3,500 psi for 5 minutes-good test. vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • ESnMobil Development Company Report Date/Time: 3/21/2015 00:00 to 3/22/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 2 of 2 Start End Time Time Comments 10:00 15:00 Cement 9-5/8"surface casing. -Pump 150 bbl of 10.7 ppg MudPush cement spacer. SPM: 20 SPP:310 psi Drop bottom plug(witnessed by EM Drilling Supervisor). S/ Zi -Pump 786 bbl of Arctic LiteCRETE lead cement slurry,,. // ,1x'Q Density: 11.27 ppg Temp:68.1°F g) v BPM: 5.9 PP:446 psi Note: -Observed bottom plug land after 362.8 bbl.-Observed pressure spike from 425 psi to 1300 psi to rupture pressure disk. -Observed full cement returns to surface at 731.5 bbl(calculated 73 bbls over gauge hole/—28%avg.annular excess/—12-7/8"avg.hole diameter) -EPA representative was present onsite to witness cement returns to surface. ✓ -Pump 94.8 bbl of Class G tail cement slurry. u Density: 15.84 ppg Temp:69.6°F BPM: 5.22 PP:573 psi -Drop top plug(witnessed by EM Drilling Supervisor). -Displace top plug with 10 bbls of fresh water from cement unit.Swap over to rig pumps and pump 330 bbl of 10.1 ppg DrilPlex WBM at—4 BPM,slowing pump rate to 2 BPM at 310 bbl to bump the plug. Bumped top plug at 330 bbl and 760 psi(final circulating pressure).Observed 470 psi pressure spike from 760 psi to 1260 psi. Held 1245 psi surface pressure for 5 minutes:floats held.Bled back 0.5 bbl volume. Note:493 bbls of cement returns to surface. Note:Conductor topped off with cement up to conductor valves. 15:00 00:00 WOC. Concurrent operations: -Flush annular,flow line,pit troughs and shakers. -Blow down cement line. -Clean out suction screens on mud pumps. -Remove bolts on diverter line to N/D. -Rig down vacuum truck cement lines. -Flush and R/D DrillCool lines. -Remove remaining 9-5/8"casing from pipe barn. -Replaced gooseneck on cement line on rig riser. -Replaced ring gasket on suitcase cement line. -Transferred 194 bbls from auxiliary mud pits to active mud pits. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Retums Cum Returns Inventory vers 20091208 yvv9 Security Type: Dnlling_XOM Printed: 5/27/2015 Partners Report by Day S Exxobil Development Company Report Date/Time: 3/22/2015 00:00 to 3/23/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors.27E 4,960 4,440 0.00 12 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 9 5/8"Surface Casing at 4,952'MD. Activity at Report Time Next Activity Prepare to lift diverter to cut 9-5/8" casing. Cut 9-5/8"casing and install A-section wellhead. Date/Time Density(lb/gal) FV(s/qt) API FL(mU3Omin) PV(cP) YP(Ibf/100ft2) 3/22/2015 15:00 10.10 90 11.5 21.0 17 3/22/2015 21:00 10.10 90 11.5 22.0 15 Start End Time Time Comments 00:00 15:00 Continue WOC(24 hours total). Concurrent operations: -N/D diverter line. -Staged directional equipment in pipe barn. -Cleared vacuum lines. -Load,strap,and tally 150 joints of 5.5"DP in pipe barn. -R/U vacuum unit to cuttings box building. -Greased and serviced top drive, blocks,and crown sheaves. -Change out NC unit on#1 centrifuge. -Cleaned out drawworks belly pan. -Installed wind sock mount on auxiliary pit module. -Hauled off 473 bbls of DrilPlex WBM from auxiliary pits for disposal. 15:00 00:00 Nipple down diverter system. -Slack off casing. -RID Tesco hydraulic slips,control panel,and hydraulic unit. -Removed cement head. -Removed riser. -N/D diverter ball valve. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 2,923.0 64,488.9 72,425.9 0.0 7,937.0 Water-Fresh-Surface 1 US Gallon 4,578.0 109,536.0 13,650.0 134,946.0 0.0 25,410.0 Water Fuel-Diesel 1 US Gallon 819.0 11,428.0 14,389.0 0.0 2,961.0 Security Type: Drilling_XOM vers 20091208 wv9 Printed: 5/27/2015 Partners Report by Day ElanMobil Development Company Report Date/Time: 3/23/2015 00:00 to 3/24/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors. 27E 4,960 4,440 0.00 13 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 9 5/8"Surface Casing at 4,952'MD. Activity at Report Time Next Activity N/U mud cross N/U upper Shaffer BOP. Date/Time Density(lb/gal) FV(s/qt) API FL(mLl30min) PV(cP) YP(Ibf/100fr) 3/23/2015 15:00 10.10 90 11.5 21.0 17 3/23/2015 21:00 10.10 90 11.5 21.0 16 Start End Time Time Comments 00:00 05:30 Nipple down diverter system. -Observe cement top 8'below conductor flange. Plan to top out. -Perform rough cut on 9 5/8"surface casing 30"above conductor flange. -Remove diverter annular,diverter"T",and spacer spool. 05:30 00:00 N/U and test A-section wellhead. -Perform final beveled cut on 9 5/8"surface casing 21.5"above conductor flange. -Wait on surveyors from 07:30 to 09:00.Surveyors were notified at 05:30. -Orient wellhead to the injection flowline flange as per procedure. -Test wellhead to 400 psi low for 5 minutes and 5200 psi high for 15 minutes.Witnessed by EM Drilling Supervisor test good. N/U BOP stack. - -N/U DSA. -N/U spacer spool. -N/U T3 double BOP. -N/U mud cross. Concurrent operations: -Service TDS brake. -Test AC unit on#1 centrifuge:test good. -Service drawworks. -R/D side door elevators and long bails. -Install 500T bails and 5.5"500T elevators. -Calibrate and test mud leg sensor. -Plumb in steam lines to auxiliary pits. -Offload 353 bbls of DrilPlex WBM from auxiliary pits. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 2,627.0 67,115.9 5,535.0 77,960.9 0.0 10,845.0 Water-Fresh-Surface 1 US Gallon 3,192.0 112,728.0 134,946.0 0.0 22,218.0 Water Fuel-Diesel 1 US Gallon 630.0 12,058.0 14,389.0 0.0 2,331.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day Exxallobil Development Company Report Date/Time: 3/24/2015 00:00 to 3/25/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors.27E 4,960 4,440 0.00 14 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 9 5/8"Surface Casing at 4,952'MD. Activity at Report Time Next Activity Torque Shaffer double BOP to mud cross. Install control,choke,and kill lines to BOPS. Date/Time Density(lb/gal) FV(s/qt) API FL(mU30min) PV(cP) YP(Ibf/100ft') 3/24/2015 15:00 10.10 90 11.5 21.0 17 3/24/2015 21:00 10.10 90 11.5 21.0 16 Start End Time Time Comments 00:00 00:00 N/U BOP stack and related well control equipment. -N/U 13-5/8"Shaffer double BOP. -N/U kill and choke HCR valves. -N/U 13-5/8"Shaffer spherical annular. -Install hammer seal. -Install bell nipple. Concurrent operations: -Clean auxiliary pits: Pits#1,2,5,8 ready for NAF. -Install and function test VFD on drag chain-good test. -Stage 5-1/2"and 7"test assembly components on rig floor and in pipe barn. -Haul off 287 bbls of DrilPlex WBM from active system for disposal. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts _ Returns Cum Returns Inventory Fuel-Diesel 1.US Gallon 3,145.0 70,260.9 - 77,960.9 0.0 7,700.0 Water-Fresh-Surface 1 US Gallon 8,862.0 121,590.0 134,946.0 0.0 13,356.0 Water Fuel-Diesel 1 US Gallon 441.0 12,499.0 14,389.0 0.0 1,890.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • E•nMobil Development Company Report Date/Time: 3/25/2015 00:00 to 3/26/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 4,960 4,440 0.00 15 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 9 5/8"Surface Casing at 4,952'MD. Activity at Report Time Next Activity Making up 5.5"BOP test assembly. Perform shell test on BOP. Date/Time Density(lb/gal) FV(s/qt) API FL(mL/30min) PV(cP) YP(Ibf/100ftZ) 3/25/2015 21:00 10.10 90 11.5 21.0 16 3/25/2015 21:00 10.10 90 11.5 21.0 16 Start End Time Time Comments 00:00 23:00 N/U BOP stack. -Check torque on mud cross and Shaffer double BOP. -Install 2"kill line hose. -Install 4"choke line hose. -Install Shaffer LFS rams. -Verify T3 and Shaffer VBRs. -Install whip checks on choke and kill line hoses. -Function test BOP from accumulator. Concurrent operations: -Auxiliary pits ready for NAF. -Cleaned active pit#8 and filled with fresh water for BOP test. -Disposed of 706 bbls of DrilPlex WBM and residual solids. Note:AOGCC conducted PVT/trip tank gain-loss calibration and complete rig gas alarm tests. 23:00 00:00 Make up 5.5"BOP test assembly. -TIH with 5 stands of 5.5"HWDP. -Make up DS55 x 4.5"IF crossover. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 3,682.0 73,942.9 2.664.0 80,624.9 0.0 6,682.0 Water-Fresh-Surface 1 US Gallon 13,104.0 134,694.0 15,120.0 150,066.0 0.0 15,372.0 Water Fuel-Diesel 1 US Gallon 430.0 12,929.0 1,865.0 16,254.0 0.0 3,325.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • Exxobil Development Company Report Date/Time: 3/26/2015 00:00 to 3/27/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 2 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 4,960 4,440 0.00 16 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 9 5/8"Surface Casing at 4,952'MD. Activity at Report Time Next Activity Rigging up wireline. RIH with wireline to perform Isolation Scanner log. Date/Time Density(lb/gal) FV(s/qt) API FL(mL30min) PV(cP) YP(Ibf/100ft') 3/26/2015 21:00 10.10 90` 11.0 20.0 21 3/26/2015 21:00 10.10 90 11.5 21.0 16 Start End Time Time Comments 00:00 05:00 Prepare to test BOPs. -TIH with 5 stands of HWDP. -M/U test assembly. -Fill BOP stack and choke manifold with water. Concurrent operations: -Offload DrilPlex WBM from active pits. 05:00 11:30 Perform initial BOP shell test. -Hold PJSM on testing BOPS and exclusion zones. -Observe leaks at block Ts,test hose fitting,and superchoke tattle tell. -Fix leaks and re-test:test good. Perform additional BOP test: -Annular -Top rams -Manual inside kill/choke valve -Upper IBOP -Middle rams -HCR outside kill/choke -Low TQ on kill line -Master rams -Floor TIW valve -Choke manifold -Inside grey valve -Lower TIW +Low pressure:200 psi;High pressure:5,000 psi. +5 minutes each test. +Tests good. 11:30 13:00 Prepare to re-test BOP and well control equipment. -Hold PJSM with oncoming team. -Repair high pressure nipple at HCR mud cross body. 13:00 17:30 Re-test BOP per AOGCC representative request. -Annular -Top rams -Manual inside kill/choke valve -Middle rams -HCR outside kill/choke -Lower TIW -Low TQ on kill line -Master rams -Floor TIW valve -Choke manifold -Blind/shear LFS rams-Inside grey valve (� +Low pressure:200 psi;High pressure:5,000 psi. t, +5 minutes each test. +Tests good. Concurrent operations: -Receive 12.1 ppg NAF drilling fluid in auxiliary pits. 17:30 18:30 Perform 7"test on annular and 4-1/2"x 7-5/8"VBR. -Low pressure:200 psi;High pressure:5,000 psi. -5 minutes each test. -Tests good. 18:30 19:30 Perform accumulator volume test and pump capacity test. Accumulator volume test -Start pressure:3,000 psi -Final pressure: 1,700 psi Pump capacity test -1:45 seconds to close annular/open HCR and achieve 1200 psi on manifold with electric pump#1. -1:48 seconds to close annular/open HCR and achieve 1200 psi on manifold with electric pump#2. 19:30 23:00 R/D and L/D BOP testing assembly. -Pull test plug. -R/B 5 stands of 5.5"HWDP. -Install wear bushing. -Set 2 lock-down pins 180°apart. vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 AliPartners Report by Day • nMobil Development Company Report Date/Time: 3/26/2015 00:00 to 3/27/2015 0 0:0 0 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 2 of 2 Start End Time Time Comments 23:00 00:00 Prepare for wireline logs. -Hold PJSM with all personnel involved in R/U and logging operations. -Rig up shieve wheels on rig floor at report time. Sales Unit Cum Item Size Sales Unit _ Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 2,521.0 76,463.9 3.270.0 83,894.9 0.0 7,431.0 Water-Fresh-Surface 1 US Gallon 9,534.0 144.228.0 11,760.0 161,826.0 0.0 17,598.0 Water Fuel-Diesel 1 US Gallon 315.0 13,244.0 16,254.0 0.0 3,010.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • ExxSobil Development Company Report Date/Time: 3/27/2015 00:00 to 3/28/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Eley: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 4,960 4,440 0.00 17 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 9 5/8"Surface Casing at 4,952'MD. Activity at Report Time Next Activity L/D logging tools. Perform rig service. Date/Time Density(lb/gal) FV(s/qt) API FL(mL/30min) PV(cP) YP(Ibf/100ft') 3/27/2015 15:00 10.10 90 11.5 21.0 16 3/27/2015 21:00 10.10 90 11.0 20.0 21 Start End Time Time Comments 00:00 04:00 R/U wireline logging equipment. -Hold PJSM prior to R/U. Concurrent operations: -Offload drilling fluids from active pits. -Clean and condition active pits for NAF. -Receive NAF drilling fluid in auxiliary pits. Note:Adjust middle sheave above beaver slide to prevent wireline from rubbing on beaver slide and kelly hose. 04:00 09:30 Perform Isolation Scanner log on wireline. -RIH from surface to 4820'WLM. -3,100 lb of tension at 4820'WLM -Average logging speed—1,600 fph \ \ Concurrent operations. -Top off conductor with cement to 21-1/4"diverter flange face. Note:EPA representative witnessed logging run. 09:30 14:30 Wait on results from Isolation Scanner log. Concurrent operations: -Grease choke lines and line up for drilling operations. -Replace derrick mule winch. -C/0 roughneck head. -Install cuttings slide and 3 suction hoses on South side cuttings tank. -Begin to blind off water lines to pits in preparation for NAF. -Hold tentative PJSM for R/D of wireline. 14:30 23:00 Performed secondary Isolation Scanner log run. -Change out transducers on logging equipment. -RIH with wireline from surface to 4820'WLM. -3,200 lb of tension at 4820'WLM -Average logging speed—1,000 fph 23:00 00:00 R/D wireline equiment. -Hold PJSM prior to R/D. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 2,716.0 79,179.9 1,784.0 85,678.9 0.0 6,499.0 Water-Fresh-Surface 1 US Gallon 8,484.0 152,712.0 24,864.0 186,690.0 0.0 33,978.0 Water Fuel-Diesel 1 US Gallon 378.0 13,622.0 16,254.0 0.0 2,632.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • E•nMobil Development Company Report Date/Time: 3/28/2015 00:00 to 3/29/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 4,960 4,440 0.00 18 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 9 5/8"Surface Casing at 4,952'MD. Activity at Report Time Next Activity Preparing to pressure test 9-5/8"casing. Pressure test 9-5/8"casing. Date/Time Density(Ib/gal) FV(s/qt) API FL(mL13Omin) PV(cP) YP(Ibf/100fti 3/28/2015 15:00 12.20 52 22.0 9 3/28/2015 21:00 12.20 52 22.0 10 Start End Time Time Comments 00:00 01:00 R/D wireline. -Rig down sheaves and logging tools. 01:00 02:15 Install stabbing guide on TD. -Tighten bolts and wire tie. 02:15 02:45 Service rig. -Lubricate top drive and blocks. 02:45 03:45 Adjust brake linkage on drawworks. 03:45 11:45 M/U 8 1/2"directional BHA as per SLB DD. -TIH with BHA and 5.5"HWDP. 11:45 14:15 TIH from 950'MD to 1500'MD. -P/U 5.5"DP from pipe shed. 14:15 15:15 Conduct shallow pulse test. -GPM:550 -SPP: 1300 psi -Good test. 15:15 17:45 TIH from 1500'MD to 3940'MD. -P/U 5.5"DP from pipe shed. 17:45 21:15 TIH from 3940'MD to 4827'MD using 5.5"DP from derrick. -Tag float collar at 4847'MD with 20 klb. Note:TOC at 4827'MD Concurrent operations: -Mix and condition displacement spacer. 21:15 22:15 Circulate and condition mud for casing test. -6 BPM at 1650 psi. Concurrent operations: -Hold PJSM for casing pressure test. 22:15 00:00 Prepare to pressure test 9-5/8"casing. ' -R/U pump-in sub. -Blow air through water and mud lines to verify no obstructions. -Pressure test lines to 4,500 psi. Sales Unit ' Cum Item Size • Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 2,937.0 82,116.9 4,745.0 90,423.9 0.0 8,307.0 Water-Fresh-Surface 1 US Gallon 8,400.0 161,112.0 0.0 186,690.0 0.0 25,578.0 Water Fuel-Diesel 1 US Gallon 378.0 14,000.0 1.801.0 18,055.0 0.0 4,055.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • Exxalobit Development Company Report Date/Time: 3/29/2015 00:00 to 3/30/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 2 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 4,960 4,440 0.00 19 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 9 5/8"Surface Casing at 4,952'MD. Activity at Report Time Next Activity Drilling out shoetrack. Drill 20'of new formation and perform FIT. Date/Time Density(lb/gal) FV(s/qt) API FL(mL/30min) PV(cP) YP(Ibf/100ftl 3/29/2015 15:00 12.20 52 22.0 9 3/29/2015 21:00 12.20 62 25.0 11 Start End Time Time Comments 00:00 02:30 Perform 9-5/8"casing pressure test. -Test pressure:4,000 psi -Test duration: 15 min -Test good p R/D pressure test equipment. -Blow down mud,water,and kill lines. 02:30 08:00 Displace wellbore to 12.1 ppg NAF. -Conduct PJSM prior to displacing with NAF. -Pump 77 bbl of DeepClean spacer. -Pump 52 bbl of VersaClean NAF. -GPM: 251 -SPM:60 -SPP: 644 psi -RPM:20 -TRQ:7.5 kft-lb Note: Drilling fluid backing up in catch pan.Check for blockage. Route flow to auxiliary bypass.Continue pumping at 6 BPM. -GPM: 284 -SPM:60 -SPP: 550 psi -RPM:20 -TRQ:7.0 kft-Ib 08:00 09:00 Prepare to slip and cut drill line. 09:00 09:30 Perform Polar Bear Drill on Central Pad. 09:30 15:30 Slip and cut drill line. -Cut 96'of drill line. -Calibrate MWD, NOV,Canrig drawworks primary and secondary system,and crown saver/floor saver. Concurrent operations: -Clean active pit#9 for VersaClean NAF. 15:30 16:30 Service top drive. -Add gear oil. -Re-crimp 3 ground lugs. Concurrent operations: -Clean trip tanks. 16:30 19:00 Circulate and condition wellbore. -GPM: 391 -SPP: 1230 psi Concurrent operations: -Perform Fire and Emergency Evacuation Drill. Note:record slow pump rates with all mud pumps at 20.30,and 40 SPM. 19:00 20:30 Perform Power Choke Drill prior to drilling out shoetrack and float equipment. -Blow down choke manifold and line up for drilling. 20:30 00:00 Drill out shoetrack from 4827'MD to 4950'MD. -P/U Hookload: 170 klb -S/0 Hookload: 150 klb -WOB:5-10 klb -RPM: 40 -GPM: 200-400 -SPP on btm: 1400 psi -SPP off btm: 1300 psi -TRQ on btm: 5-10 kft-lb-TRQ off btm:5 kft-Ib Firm cement returns observed over shakers. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 2,945.0 85,061.9 3,718.0 94,141.9 0.0 9,080.0 Water-Fresh-Surface 1 US Gallon 15,876.0 176,988.0 31,962.0 218,652.0 0.0 41,664.0 Water vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • E•nMobil Development Company Report Date/Time: 3/29/2015 00:00 to 3/30/2015 00:00 Well Name: PTU-DW 1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 2 of 2 Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 378.0 14,378.0 761.0- 18,816.0 0.0- 4,438.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • ExxSl obil Development Company Report Date/Time: 3/30/2015 00:00 to 3/31/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors.27E 4,980 4,453 20.00 20 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 9 5/8"Surface Casing at 4,952'MD. Activity at Report Time Next Activity POOH at 2200'MD. Perform cement squeeze on 9-5/8"casing shoe. Date/Time Density(lb/gal) FV(s/qt) API FL(mL/30min) PV(cP) YP(Ibf/100ft2) 3/30/2015 15:00 12.20 62 25.0 12 3/30/2015 21:00 12.20 62 25.0 11 Start End Time Time Comments 00:00 00:30 Drill cement from 4950'MD to 4952'MD. -P/U Hookload: 170 klb -S/0 Hookload: 150 klb-ROT Hookload: 160 klb -WOB: 5-8 klb -RPM: 40 -GPM:200-400 -SPP on btm: 1300 psi -SPP off btm: 1290 psi -TRQ on btm:5-7 kft-lb -TRQ off btm:4 kft-lb Note:no firm cement observed below shoe from 4952'to 4960'MD. 00:30 01:00 Drill new formation from 4960'MD to 4980'MD. -WOB: 5-8 klb -RPM: 40 -GPM:400 -SPP on btm: 1300 psi -SPP off btm: 1290 psi -TRQ on btm: 5-7 kft-lb -TRQ off btm:4 kft-Ib 01:00 03:30 Circulate well clean. Lithology at 4980'MD: -Sand:40% -Clay:30% -Silt 30% Cycle MWD tools to reset for upcoming FIT. Pump and spot 50 bbl LCM pill v -5 ppb CaCO3. Cycle MWD after spotting pill in place. / 5't ) 7 03:30 18:30 Perform FIT to 13.8 ppge. -Hold PJSM with all personnel involved in performing FIT. -Blow down lines to cement unit. -Transfer VersaClean NAF to cement unit. -Pressure test lines to 1000 psi:bad test. -Leak found at kill valve#7. � J -Leak found at cement line goose neck. Attempt 9 FITs on new formation. -Unable to hold required FIT surface pressure of 393 psi. (1.2 -Last FIT performed:surface pressure bled off from 348 psi to 69 psi after 15 min. 18:30 20:30 Monitor well on trip tank. -Blow down cement lines,choke and kill lines, choke manifold,and mud/water lines to cement unit. -Build slug for upcoming trip out of hole. Note:trip tank static. 20:30 21:00 Pump 20 bbl of 14.0 ppg slug in preparation for trip out of hole. 21:00 00:00 POOH on elevators from 4980'MD to 2200'MD. -Hold PJSM for tripping pipe. Displacement: -P/U Hookload: 170 klb -Theoretical displacement:3.4 bbls per 5 stands -Actual displacement:4.2 bbls per 5 stands Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 'US Gallon 3,441.0 88,502.9 94,141.9 0.0 5,639.0 Water-Fresh-Surface 1 US Gallon 4,368.0 181,356.0 11,340.0 229,992.0 0.0 48,636.0 Water Fuel-Diesel 1 US Gallon 14,378.0 441.0 19,257.0 0.0 4,879.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • EllinMobil Development Company Report Date/Time: 3/31/2015 00:00 to 4/1/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors.27E 4,980 4,453 0.00 21 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 1.00 9 5/8"Surface Casing at 4,952'MD. Activity at Report Time Next Activity Hold PJSM for cement squeeze job. Perform cement squeeze on 9-5/8"casing shoe. Date/Time Density(lb/gal) FV(s/qt) API FL(mL/30min) PV(cP) YP(Ibf/100ft') 3/31/2015 15:00 12.20 62 25.0 12 3/31/2015 21:00 12.20 68 26.0 11 Start End Time Time Comments 00:00 02:00 POOH on elevators from 2500'MD to 954'MD. -Displacements consistent across trip. 02:00 06:00 R/B 8-1/2"BHA. -Remove radioactive source from MWD/LWD tools. -Clear rig floor of non-essential personnel. -Bit in good condition. -Download MWD/LWD data. 06:00 07:00 P/U 4"DP handling equipment. -Clean and clear floor. 07:00 18:00 RIH from surface to 4875'MD. -Hold PJSM prior to tripping operations. -C/O top drive elevators to 4". -Ready iron roughneck and other handling tools. -M/U 10 stands of 4"DP stinger and RIH. -RIH with 5.5"DP. -Displacement consistent across trip. -Conduct BOP drill. -Critical ResponseTime: 0:45 sec Concurrent operations: -Mix mud push spacer. Note: Notified AOGCC of intent to perform BOP test. 18:00 00:00 Circulate and condition wellbore for cement squeeze on 9-5/8"casino shoe. , -GPM: 210 -SPP:250 psi Concurrent operations: -Dispose of surfactant pill. -Clean mud pit#9. -Build mud push spacer in pit#9. -Change out seal on cement line gooseneck. -Blow down lines to cement unit.Verify clear. -Blow down standpipe. -Prepare for cement squeeze. Sales Unit Cum Item Size Sales Unit _ Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 3,248.0 91,750.9 3.671.0 97,812.9 0.0 6,062.0 Water-Fresh-Surface 1 US Gallon 14,196.0 195,552.0 229,992.0 0.0 34,440.0 Water Fuel-Diesel 1 US Gallon 346.0 14,724.0 19,257.0 0.0 4,533.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • ExxSl obil Development Company Report Date/Time: 4/1/2015 00:00 to 4/2/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 2 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 4,980 4,453 0.00 22 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 9 5/8"Surface Casing at 4,952'MD. Activity at Report Time Next Activity Hold final squeeze pressure on cement. POOH from 4240'MD to surface. Date/Time Density(lb/gal) FV(s/qt) API FL(mL/30min) PV(cP) YP(Ibf/100f1') 4/1/2015 15,00 12.20 68 26.0 11 4/1/2015 21:00 12.20 66 26.0 12 Start End Time Time Comments 00:00 02:00 Circulate and condition mud at 4975'MD. -GPM: 180 -SPP:350 psi Concurrent operations: -Continue preparing 14.0 ppg MudPush spacer. -Hold PJSM focusing on communication and understanding each individual task. 02:00 02:30 Spot MudPush spacer. -Pump 10 bbl of 6.8 ppg base oil. -Pump 60 bbl of 14.0 ppg MudPush spacer. -Pump 10 bbl of 6.8 ppg base oil. -Displace with 49.3 bbl of 12.1 ppg NAF. -GPM:230 -SPP:480 psi 02:30 06:45 Attempt to perform 5 injection tests. -Close upper VBR rams. -BPM: 0.5 -SPP:550-801 psi(14.4-15.5 ppg EMW) -Total volume pumped from cement unit: 3.8 bbl -Monitor pressure for 10-20 min after each test. -Unable to inject at applied surface pressure. -Test#1:Pressure up to 750 psi(15.3 ppg EMW), bled off to 291 psi(13.3 ppg EMW)after 16 min(28.7 psi/min loss rate). 1.4 bbl pumped. -Test#2:Pressure up to 613 psi(14.7 ppg EMW),bled off to 313 psi(13.4 ppg EMW)after 20 min(15.0 psi/min loss rate).0.5 bbl pumped. -Test#3: Pressure up to 550 psi(14.4 ppg EMW), bled off to 345 psi(13.5 ppg EMW)after 15 min(13.7 psi/min loss rate).0.2 bbl pumped. -Test#4: Pressure up to 750 psi(15.3 ppg EMW), bled off to 347 psi(13.5 ppg EMW)after 20 min(20.2 psi/min loss rate).0.7 bbl pumped. -Test#5:Pressure up to 801 psi(15.5 ppg EMW), bled off to 397 psi(13.7 ppg EMW)after 20 min(20.2 psi/min loss rate). 1.0 bbl pumped. 06:45 07:45 Circulate out remaining 6.8 ppg base oil and 14.0 ppg MudPush spacer. -GPM: 293 -SPP:795 psi -Disposed of 92 bbl of MudPush spacer in cuttings box. 07:45 12:00 Circulate and condition wellbore. -GPM: 205 -SPP:270 psi -Record slow pump rates. -Hold PJSM prior to squeeze operations. vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • EllinMobil Development Company Report Date/Time: 4/1/2015 00:00 to 4/2/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 2 of 2 Start End Time Time Comments 12:00 18:30 Perform 9-5/8"casing shoe squeeze. -Pump 33.4 bbl of 14.0 ppg MudPush spacer with rig pumps. Pressure test cement lines to 2,500 psi.Test good. �/� �/ -Pump 40 bbl of 15.8 ppq cement at 4.5 BPM. at" I'_"S_1 -Displace cement with 16.1 bbl of 14.0 ppg MudPush spacer. l �j -SPP: 200 psi,GPM:230,SPM:54 -Pump 67.2 bbl of 12.1 ppg NAF at 6 BPM. -Pipe slugging. -R/B 8 stands of 5.5"DP,drop two 5"wiper balls,and circulate bottoms-up. (31/ -Observe MudPush spacer and trace amounts of cement slurry across the shakers. Perform 10 hesitation squeezes with cement unit. "l -Test#1: Pressure up to 470 psi (14.4 ppg EMW), bled off to 369 psi(14.0 ppg EMW)after 10 min (10.1 psi/min loss rate). -Test#2: Pressure up to 553 psi(14.8 ppg EMW),bled off to 400 psi(14.1 ppg EMW)after 21 min(7.3 psi/min loss rate). -Test#3: Pressure up to 539 psi(14.7 ppg EMW), bled off to 434 psi(14.3 ppg EMW)after 17 min(6.2 psi/min loss rate). -Test#4: Pressure up to 525 psi(14.7 ppg EMW), bled off to 443 psi(14.3 ppg EMW)after 15 min(5.5 psi/min loss rate).0.9 bbl pumped. -Test#5: Pressure up to 550 psi(14.8 ppg EMW). bled off to 454 psi(14.4 ppg EMW)after 15 min(6.4 psi/min loss rate).0.25 bbl pumped. -Test#6: Pressure up to 550 psi(14.8 ppg EMW). bled off to 456 psi(14.4 ppg EMW)after 16 min(5.9 psi/min loss rate).0.25 bbl pumped. -Test#7: Pressure up to 550 psi(14.8 ppg EMW), bled off to 466 psi(14.4 ppg EMW)after 15 min(5.6 psi/min loss rate).0.1 bbl pumped. -Test#8: Pressure up to 550 psi(14.8 ppg EMW), bled off to 456 psi(14.4 ppg EMW)after 15 min(6.3 psi/min loss rate).0.1 bbl pumped. -Test#9: Pressure up to 535 psi(14.7 ppg EMW), bled off to 429 psi(14.3 ppg EMW)after 29 min(3.7 psi/min loss rate).0.1 bbl pumped. -Test#10: Pressure up to 535 psi(14.7 ppg EMW), bled off to 500 psi(14.6 ppg EMW)after 8 min(4.4 psi/min loss rate).0.1 bbl pumped. 18:30 00:00 Perform 6 hesitation squeezes with rig test pump. -Test#1: Pressure up to 527 psi(14.7 ppg EMW),bled off to 329 psi(13.8 ppg EMW)after 20 min(9.9 psi/min loss rate). -Test#2:Pressure up to 535 psi(14.7 ppg EMW),bled off to 356 psi(13.9 ppg EMW)after 20 min(9.0 psi/min loss rate). -Test#3: Pressure up to 548 psi(14.8 ppg EMW),bled off to 512 psi(14.6 ppg EMW)after 20 min(1.8 psi/min loss rate). -Test#4: Pressure up to 558 psi(14.8 ppg EMW),bled off to 530 psi(14.7 ppg EMW)after 20 min(1.4 psi/min loss rate). -Test#5: Pressure up to 553 psi(14.8 ppg EMW),bled off to 526 psi(14.7 ppg EMW)after 20 min(1.4 psi/min loss rate). -Test#6: Pressure up to 558 psi(14.8 ppg EMW),bled off to 530 psi(14.7 ppg EMW)after 20 min(1.4 psi/min loss rate). Concurrent operations: -Clean cement unit. -Service drawworks and Iron Roughneck. -Perform monthly inspections on SCBAs,fire extinguishers,eyewash stations,and lifting gear. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 2,990.0 94,740.9 5,601.0 103,413.9 0.0 8,673.0 Water-Fresh-Surface 1 US Gallon 7,224.0 202,776.0 12,096.0 242,088.0 0.0 39,312.0 Water Fuel-Diesel 1 US Gallon 346.0 15,070.0 19,257.0 0.0 4,187.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • ExxSobil Development Company Report Date/Time: 4/2/2015 00:00 to 4/3/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 4,980 4,453 0.00 23 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 9 5/8"Surface Casing at 4,952'MD. Activity at Report Time Next Activity R/D 5-1/2"BOP test equipment. Perform 7"BOP pressure test. Date/Time Density(lb/gal) FV(s/qt) API FL(mL/30min) PV(cP) YP(Ibf/100ft') 4/2/2015 15:00 12.20 66 27.0 12 4/2/2015 21:00 12.20 67 26.0 13 Start End Time Time Comments 00:00 04:00 Continue 9-5/8"hesitation cement squeeze with the rig test pump. -Continue holding pressure on final cement squeeze from 00:00 hrs(521 psi)to 00:45 hrs(461 psi). -Pressured up to 558 psi(14.8 ppg EMW),bled off to 461 psi(14.4 ppg EMW)after 72 min(1.3 psi/min loss rate). -Release pressure;bled back 1 bbl. -L/D cement squeeze equipment. -Blow down kill and cement lines. 04:00 08:00 POOH from 4240'MD to 964'MD. -Hold PJSM discussing hand placement and zone management during tripping operations. -R/B 35 stands of 5.5"DP. -Displacements consistent across trips. 08:00 10:30 POOH from 964'MD to surface. -L/D 30 joints of 4"DP and mule shoe. -Displacements consistent across trips. 10:30 11:00 Clean and clear rig floor prior to picking up BOP test equipment. 11:00 19:15 P/U BOP test equipment and R/U 5.5"DP handling equipment. -Hold PJSM with all personnel involved in R/U for BOP testing. -Remove wear bushing. -Drain and flush stack. -Fill stack and choke manifold with fresh water. -Blow down standpipe and kelly hose. -M/U 5.5"BOP test assembly. 19:15 00:00 Pressure test BOP equipment against 5.5"test assembly. -Perform 250 psi low and 5.000 psi high test for 5 min each test. -Annular -Upper IBOP -Low TRQ on Kill Line -Choke Manifold -Top Rams ` X -Lower IBOP !/ /✓%` -HCR Outside Kill/Choke -Manual Inside Kill/Choke -Lower Rams -Blind/Shear Rams -IBOP(Grey Valve) -FOSV(TIW) -Middle Rams -Pump Capacity Test: -Electric Pump#1:01:50 sec to close annular,open HCR,and achieve 1200 psi on manifold pressure gauge. -Electric Pump#2:01:48 sec to close annular,open HCR,and achieve 1200 psi on manifold pressure gauge. -Accumulator Volume Test: -Starting pressure:3,000 psi -Ending pressure: 1,610 psi -Add 3 ppb each of SafeCarb 20 and SafeCarb 40 LCM into active system. -L/D 5.5"test joint at report time. Note:AOGCC Representative John Noble waived onsite representation for BOP testing. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 2,715.0 97,455.9 0.0 103,413.9 0.0 5,958.0 Water-Fresh-Surface 1 US Gallon 3,108.0 205,884.0 242,088.0 0.0 36,204.0 Water Fuel-Diesel 1 US Gallon 378.0 15,448.0 19,257.0 0.0 3,809.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day nMobil Development Company Report Date/Time: 4/3/2015 00:00 to 4/4/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors.27E 4,980 4,453 0.00 24 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 9 5/8"Surface Casing at 4,952'MD. Activity at Report Time Next Activity Drilling cement plug at 4781'MD. Perform FIT to 13.8 ppge. Date/Time Density(lb/gal) FV(s/qt) API FL(mL/30min) PV(cP) YP(Ibf/100ftZ) 4/3/2015 15:00 12.10 66 27.0 12 4/3/2015 21:00 12.10 61 18.0 20 Start End Time Time Comments 00:00 05:00 Pressure test 13-5/8"BOPE. -Perform 200 psi low and 5000 psi high tests for 5 min each test on 5-1/2". Make-up 7"test joint assembly. -Perform 200 psi low and 4000 psi high tests for 5 min each test on 7"using annular and 4-1/2"x 7-5/8"VBR. Pressure test rig cement manifold. -Perform 200 psi low and 5000 psi high tests for 5 min each test. -Cement line valves:6,8,9, 10, 11,and 12. -Mud manifold valves: 1,2,3,and 5. Note:AOGCC Representative John Noble waived onsite representation. 05:00 08:00 Rig-down BOP test equipment. -Lay down 7"test joint. -Pull test plug(test plug seal retrieved). -R/B 5 stands of HWDP. -Drain freshwater from stack. 08:00 08:30 Perform rig service. -Lubricate TDS. 08:30 09:30 Rig-down BOP test equipment. -Remove test equipment from rig floor. -Install wear bushing. -L/D wear bushing running tool. 09:30 14:00 Make-up 8-1/2"directional BHA to 947'. -Hold PJSM with all personnel involved in M/U BHA and installing nuclear source. -L/D 10'pony collar and make-up 8-3/8"NM stabilizer. -Load nuclear source into MWD. 14:00 18:30 TIH from 947'to 4,302'MD. -Perform shallow test. 1,586' MD -GPM: 500 -SPP: 1430 psi 3,350' MD -GPM: 500 -SPP: 1700 psi -Tag cement with 15 klb at 4,302'MD. 18:30 00:00 Drill out cement plug from 4,302'to 4,781'MD at report time. -Recorded SPR at 20, 30 and 40 SPM with MP#2 and#3 at 4,292'MD. -P/U Hookload: 155 klb -5/0 Hookload: 142 klb -GPM: 460-500- RPM: 40-60 -Torque: 3-6 kft-lb -WOB: 1-3 klb -SPP: 1500-1858 psi Moderately hard to soft cement cuttings observed over shakers. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 2,637.0 100,092.9 4,302.0 107,715.9 0.0 7,623.0 Water-Fresh-Surface 1 US Gallon 2,604.0 208,488.0 242,088.0 0.0 33,600.0 Water Fuel-Diesel 1 US Gallon 330.0 15,778.0 1,527.0 20,784.0 0.0 5,006.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • ExxSl obil Development Company Report Date/Time: 4/4/2015 00:00 to 4/5/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 2 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 5,990 5,101 1,010.00 25 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 14.00 9 5/8"Surface Casing at 4,952'MD. Activity at Report Time Next Activity Drilling ahead at 5990'MD. Continue to drill 8-1/2"hole section. Date/Time Density(Ib/gal) FV(s/qt) _ API FL(mLl30min) PV(cP) YP(Ibf/100ftl 4/4/2015 15:00 12.10 63 26.0' 24 4/4/2015 21:14 12.00 67 24.0 24 Start End Time Time Comments 00:00 02:30 Drill out cement plug and 10'of new formation. -Drill cement plug from 4781'MD to 4980'MD. -Drill new formation from 4980'MD to 4990'MD. P/U Hookload: 160 klb 5/0 Hookload: 140 klb GPM: 460-500 RPM: 40-60 Torque: 3-9 kft-lb WOB: 1-10 klb SPP: 1500-1850 psi Moderately hard to soft cement cuttings observed over shakers. 02:30 05:00 Circulate hole clean. GPM: 480 SPP: 1550 psi Lithology at 4990'MD:50%Sand/20%Clay/10%Shale/20%Silt Spot 50 bbl LCM Dill(MIX II Fine t 3 ppb)on bottom. , -Clear data on MWD for FIT. 05:00 07:00 Rig-up to perform FIT. -Hold PJSM with all personnel involved in rigging-up and performing FIT. -Make-up test assembly;pump fluid through all lines. -Pressure test cement lines to 1,000 psi. -Troubleshoot pressure drop while testing lines and repair. 07:00 09:00 Perform FIT to 13.8 ppge. -Pressure up to 397 psi with 0.75 bbls pumped at 0.25 BPM. -Pressure up to 397 psi(13.8 ppg EMW), bled off to 278 psi(13.3 ppg EMW)after 15 min(6.7 psi/min loss rate). -Bleed back 0.4 bbls. MWD Equivalent Static Density(ESD)Data: -Minimum: 11.9 ppg ESD -Maximum: 14.0 ppg ESD 09:00 10:00 Rig-down FIT test assembly. -Blow down lines to cement unit. 10:00 16:00 Drill 8-1/2"hole section from 4990'MD to 5343'MD. WOB: 12 klb RPM: 80 TRQ: 8000 ft-lb GPM: 470 SPP: 1750 psi ECD: 14.1 ppg ROP: 58.8 fph Lithology at 5310'MD: 10%Siltstone/60% Sandstone/30%Sand Mud Check at 5266'MD:12.1 ppg/67 sec/L FV 16:00 22:00 Drill 8-1/2"hole section from 5343'MD to 5795'MD. WOB: 10 klb RPM: 100 TRQ: 8300 ft-lb GPM: 460 SPP: 1766 psi ECD: 14.0 ppg ROP: 75.3 fph Lithology at 5760'MD: 10%Siltstone/60%Sandstone/30%Sand Mud Check at 5795'MD:12.05 ppg/69 sec/L FV 22:00 00:00 Drill 8-1/2"hole section from 5795'MD to 5990'MD. WOB: 9 klb RPM: 110 TRQ: 9000 ft-lb GPM: 460 SPP: 1860 psi ECD: 14.2 ppg ROP: 97.5 fph Lithology at 5880'MD: 40%Claystone/30% Sandstone/20% Sand/ 10% Shale Mud Check at 5910'MD:12.0 ppg/69 sec/L FV vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • ElanMobil Development Company Report Date/Time: 4/4/2015 00:00 to 4/5/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 2 of 2 Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 3,755.0 103,847.9 4,347.0 112,062.9 0.0 8,215.0 Water-Fresh-Surface 1 US Gallon 3,612.0 212.100.0 242,088.0 0.0 29,988.0 Water Fuel-Diesel 1 US Gallon 378.0 16,156.0 20,784.0 0.0 4,628.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • ExxSobil Development Company Report Date/Time: 4/5/2015 00:00 to 4/6/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 7,800 6,261 1,810.00 26 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 14.00 9 5/8"Surface Casing at 4,952'MD. Activity at Report Time Next Activity Drilling ahead at 7800'MD. Drill 8-1/2"hole section to TD. Date/Time Density(lb/gal) FV(s/qt) API FL(mL/30min) PV(cP) VP(Ibf/100fti 4/5/2015 15:00 11.90 53 24.0 21 4/5/2015 21:30 11.90 74 25.0 21 Start End Time Time Comments 00:00 06:00 Drill 8-1/2"hole section from 5990'MD to 6459'MD. WOB: 10 klb RPM: 110 TRQ: 8000 ft-lb GPM: 460 SPP: 1860 psi ECD: 14.2 ppg ROP: 78.2 fph Lithology at 6450'MD:20%Claystone/20%Siltstone/20%Sandstone/40%Sand Mud Check at 6391'MD:12.0 ppg/75 sec/L FV 06:00 12:00 Drill 8-1/2"hole section from 6459'MD to 6938'MD. WOB: 15 klb RPM: 100 TRQ: 8000 ft-lb GPM: 460 SPP: 1980 psi ECD: 14.2 ppg ROP: 79.8 fph Lithology at 6930'MD:50%Claystone/30%Siltstone/10%Sandstone/10%Sand Mud Check at 6845'MD:12.0 ppg/71 sec/L FV 12:00 18:00 Drill 8-1/2"hole section from 6938'MD to 7345'MD. WOB:8 klb RPM: 110 TRQ: 8000 ft-lb GPM: 460 SPP: 2050 psi ECD: 14.3 ppg ROP: 67.8 fph Lithology at 7320'MD: 10%Claystone/20%Siltstone/20%Sandstone/50%Sand Mud Check at 7281'MD:12.0 ppg/79 sec/L FV 18:00 00:00 Drill 8-1/2"hole section from 7345'MD to 7800'MD. WOB: 10 klb RPM: 115 TRQ: 10,000 ft-lb GPM: 465 SPP: 2115 psi ECD: 14.3 ppg ROP: 75.8 fph Lithology at 7710'MD: 10%Shale/30%Claystone/30%Siltstone/10%Sandstone/20%Sand Mud Check at 7770'MD:12.0 ppg/75 sec/L FV Concurrent Operations: -Load,drift,and strap 7"casing in pipe shed. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 4,065.0 107,912.9 4,582.0 116,644.9 0.0 8,732.0 Water-Fresh-Surface 1 US Gallon 9,954.0 222,054.0 242,088.0 0.0 20,034.0 Water Fuel-Diesel 1 US Gallon 441.0 16,597.0 20,784.0 0.0 4,187.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • EenMobil Development Company Report Date/Time: 4/6/2015 00:00 to 4/7/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors.27E 8,800 6,905 1,000.00 27 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 15.00 9 5/8"Surface Casing at 4,952'MD. Activity at Report Time Next Activity TIH at 5527'MD. Circulate hole clean for wireline log run. Date/Time Density(lb/gal) FV(s/qt) API FL(mLl30min) PV(cP) YP(Ibf/100ft') 4/6/2015 15:00 11.90 74 24.0 21 4/6/2015 21:00 11.90 72 23.0 20 Start End Time Time Comments 00:00 06:00 Drill 8-1/2"hole section from 7800'MD to 8247'MD. WOB: 18 klb RPM: 110 TRQ: 12,000 ft-lb GPM: 465 SPP: 2115 psi ECD: 14.3 ppg ROP: 74.5 fph ` Lithology at 8220'MD: 10%Shale/40%Claystone/20%Siltstone/10%Sandstone/10%Sand/10%Conglomerate Mud Check at 8100'MD:12.0 ppg/71 sec/L FV 06:00 12:00 Drill 8-1/2"hole section from 8247'MD to 8686'MD. WOB: 18 klb RPM: 130 TRQ: 12,500 ft-lb GPM: 465 SPP: 2180 psi ECD: 14.35 ppg ROP: 73.2 fph Lithology at 8670'MD:50%Claystone/30%Siltstone/20%Sandstone Mud Check at 8620'MD:12.0 ppg/71 sec/L FV 12:00 14:30 Drill 8-1/ " 1• - - •• • ;•;•'14 II • '8.t.8#QQ,M.D—. WOB: 18 klb RPM: 130 TRQ: 12,500 ft-lb GPM: 475 SPP: 2200 psi ECD: 14.3 ppg ROP: 45.6 fph UU��CC✓✓�\ Lithology at 8800'MD:40%Claystone/30%Siltstone/20%Sandstone/10%Sand W) .„. 1 Mud Check at 8755'MD:12.0 ppg/73 sec/L FV Confining Zone. -Top:5534'MD 4718'TVD -Bottom:6055'MD 5142'TVD Well TD—250'MD below base of Injection Zone. 14:30 18:30 Circulate and condition mud. -GPM: 550 SPP: 2700 psi RPM: 150 TRQ: 10,500 ft-lb -R/B a stand every 30 min from 8800'MD to 8340'MD. -No losses observed while circulating. 18:30 22:30 Wiper trip to 9-5/8"casing shoe. -Blow down standpipe and kelly hose. -POOH on elevators from 8340'MD to 4879'MD. -5-10 klb overpull observed throughout trip. -20-30 klb overpull observed at 7,166'MD and from 7069'-7014'MD.Worked pipe through tight spots until pulled free. Displacements consistent throughout trip. 22:30 23:30 Circulate bottoms up at 9-5/8"casing shoe. -GPM: 550 SPP: 2100 psi RPM:40 -Minimal amount of cuttings observed over shakers. -No losses observed while circulating. 23:30 00:00 TIH from 4879'MD to 5527'MD. -Hole giving proper displacements. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 4,315.0 112,227.9 4,020.0 120,664.9 0.0 8,437.0 Water-Fresh-Surface 1 US Gallon 3,612.0 225,666.0 7,728.0 249,816.0 0.0 24,150.0 Water Fuel-Diesel 1 US Gallon 378.0 16,975.0 20.784.0 0.0 3,809.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • Exx•Jlobil Development Company Report Date/Time: 4/7/2015 00:00 to 4/8/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 8,800 6,905 0.00 28 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 9 5/8"Surface Casing at 4,952'MD. Activity at Report Time Next Activity Rigging up wireline. Log 8-1/2"open hole section with sonic/caliper log. Date/Time Density(lb/gal) FV(s/qt) API FL(mL/30min) PV(cP) YP(lbf/100ftZ) 4/7/2015 15:00 11.90 74 24.0 21 Start End Time Time Comments 00:00 03:00 TIH from 5527'MD to 8800'MD. -No tight spots observed. -Hole giving proper displacements throughout trip. 03:00 07:00 Circulate and condition mud. -R/B a stand every 30 min from 8800'MD to 7863'MD. -GPM: 550 SPP:2600 psi -RPM: 120 Torque: 10,000 ft-lbs -No losses observed while circulating. 07:00 10:00 TOOH from 7863'MD to 4882'MD inside 9-5/8"casing. -No tight spots observed. -Hole taking proper displacements. 10:00 10:30 Circulate bottoms up at 4882'MD. -GPM: 500 SPP: 1900 psi -Minimal amount of cuttings observed over shakers. -No losses observed while circulating. 10:30 11:00 Service rig. -Service and grease TDS,drawworks,and Iron Roughneck. -Well static. 11:00 15:00 TOOH from 4882'MD to 954'MD. -Hole taking proper displacements. -Strap pipe in derrick. 15:00 21:30 Break and L/D 8-1/2"directional BHA. -Attempt to download LWD/MWD data from EcoScope/TeleScope while BHA was still made-up. -Unable to download data from EcoScope while made-up to PowerDrive RSS and TeleScope. -L/D LWD/MWD tools and PowerDrive RSS. Bit grade:3-3-CT-A-X-I-NO-TD Well static while L/D BHA. 21:30 22:00 Clean and clear rig floor. -Well static. 22:00 00:00 R/U Schlumberger wireline and logging crew. -Hold PJSM with all personnel involved in rig-up of wireline equipment and tools. -Rig-up sheave wheels on rig floor and beaver slide. Well static while R/U wireline. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 3,252.0 115,479.9 3,766.0 124,430.9 0.0 8,951.0 Water-Fresh-Surface 1 US Gallon 4,536.0 230,202.0 249,816.0 0.0 19,614.0 Water Fuel-Diesel 1 US Gallon 378.0 17,353.0 20 784.0 0.0 3,431.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • EllinMobil Development Company Report Date/Time: 4/8/2015 00:00 to 4/9/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors.27E 8,800 6,905 0.00 29 55.83 Average Background Gas Average Connection Gas Average Trip Gas +Last Casing String 9 5/8"Surface Casing at 4,952'MD. Activity at Report Time Next Activity Tagging bottom at 8800'MD. Circulate and condition mud. Date/Time Density(lb/gal) FV(s/qt) API FL(mLl30min) PV(cP) YP(Ibf/100ft') 4/8/2015 22:00 11.90 75 22.0 24 Start End Time Time Comments 00:00 02:30 Rig-up Schlumberger wireline and logging crew.Make-up MSIP/GPIT/Caliper logging tools. -Hold PJSM with all personnel involved in rig-up of wireline equipment and tools. -Rig-up sheave wheels on rig floor and beaver slide. -Well static while R/U wireline. 02:30 11:00 RIH with MSIP/GPIT/Caliper tools and log well from 4955'to 8803'WLM. POOH and log well from TD to 4955'MD. -Hole in gauge:—4.3%average volumetric washout 11:00 13:30 Rig-down Schlumberger logging tools and wireline equipment. -Hold PJSM with all personnel involved. -Well static while R/D wireline. 13:30 17:30 Pick-up,make-up,and RIH with 8-1/2"directional BHA from surface to 955'MD. L.--. '`.. -P/U Hookload: 100 klb S/0 Hookload: 95 klb -Hole giving correct displacements. 17:30 00:00 RIH with 8-1/2"directional BHA on 5-1/2"drill pipe from 955'to 8800'MD. - P/U Hookload: 220 klb S/0 Hookload: 175 klb -No tight spots while RIH. -Flow check well at 4670'MD:no gain/loss -Fill pipe every 15 stands -Hole returned 11.25 bbls under theoretical displacement. Stage up pumps,wash last stand in hole,and tag bottom with 10 klb:no fill. -GPM: 420 SPP: 1950 psi ECD: 14.49 ppge max.observed Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 3,167.0 118,646.9 5,020.0 129,450.9 0.0 10,804.0 Water-Fresh-Surface 1 US Gallon 9,282.0 239,484.0 11,088.0 260,904.0 0.0 21,420.0 Water Fuel-Diesel 1 US Gallon 406.0 17,759.0 1,007.0 21,791.0 0.0 4,032.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day Exx obil Development Company Report Date/Time: 4/9/2015 00:00 to 4/10/2015 00:00 Well Name: PTU-DW 1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors.27E 8,800 6.905 0.00 30 55.83 Average Background Gas Average Connection Gas Average Trip Gas 'Last Casing String 9 5/8"Surface Casing at 4,952'MD. Activity at Report Time -Next Activity Clean and clear rig floor. Pull wearbushing, rig up and run 7"casing. Date/time _ Density(lb/gal) FV(s/qt) API FL(mLl30min) PV(cP) YP(lbf/100ftr) 4/9/2015 23:00 11.80 75 31.0 19 Start End Time Time Comments 00:00 00:30 Circulate hole clean while working pipe. GPM: 300-525 SPP: 1950-2350 psi RPM: 30- 100 TRQ: 7000-9400 ft-lb ECDmax: 14.49 ppge ECDmin: 14.10 ppge -Gradually increase pump rate and rotary with respect to ECD. -No cavings/cuttings observed at shakers on bottoms up. -Hookloads at 8800'MD(pumps on):220 klb(P/U)/175 klb(S/O)/195 klb(ROT) 00:30 04:00 Circulate and condition mud while staging out of hole from 8800'MD to 8340'MD. GPM: 530 SPP: 2250 psi RPM: 100 TRQ:9400 ft-lb -R/B stands every 30 min. -Add LVT base oil and use SCE to reduce MW from 12.2 ppg to 11.8 ppg. -No cavings observed at shakers while reducing MW. -MWD static density at end of conditioning: 11.8 ppg. -Rheology at end of conditioning: PV=25/YP= 16/6 RPM=15 04:00 04:15 RIH with 8-1/2"directional BHA from 8340'MD to 8800'MD. 1� -No tight spots encountered. Ai 04:15 06:00 Circulate bottoms up and obtain balanced MW in/out of 11.8 ppg at 8800'MD. GPM: 530 SPP: 2200 psi RPM: 100 TRQ:9400 ft-lb -Obtain SPRs on bottom with 11.8 ppg MW. -Reduce pump rate while working pipe in the hole. -Monitor well on trip tank prior to trip:well static. -Slug pipe and install mud dog drill pipe ID wiper dart. 06:00 19:00 POOH on elevators with 8-1/2"directional BHA and L/D drill pipe from 8800'MD to 955'MD. -Hookloads at 8800'MD(pumps off):245 klb(P/U)/190 klb(S/O) -No tight spots encountered. Friction Factor 0.3. -Hole took 7 bbls over theoretical displacement. 19:00 00:00 POOH on elevators with 8-1/2"directional BHA and L/D BHA from 955'to 60'MD. -No additional wear observed on bit or stabilizers. -Close blind/shear rams while breaking out bit. -Flow check well prior to pulling drill collars: no gain/no loss. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 2,935.0 121,581.9 2,935.0 132,385.9 0.0 10,804.0 Water-Fresh-Surface 1 US Gallon 9,618.0 249,102.0 9,114.0 270,018.0 0.0 20,916.0 Water Fuel-Diesel 1 US Gallon 532.0 18,291.0 217.0 22,008.0 0.0 3,717.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day E •nMobil Development Company Report Date/Time: 4/10/2015 00:00 to 4/11/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Bev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 8,800 6,905 0.00 31 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 9 5/8"Surface Casing at 4,952'MD. Activity at Report Time Next Activity RIH with 7"production casing at 5098'MD. Run 7"production casing to 8781'MD,circulate and condition mud,and pump cement job. Date/Time Density(lb/gal) _ FV(s/qt) API FL(mU3Omin) PV(cP) VP(Ibf/100ft') 4/10/2015 22:00 11.80 75 19.0 20 Start End Time Time Comments 00:00 02:00 POOH on elevators with 8-1/2"directional BHA and L/D BHA from 60'MD to surface. -Clean and clear rig floor. -Remove directional tools from pipe shed. -Well losing 1 bph while out of hole. -Mobilize Cameron from camp for wear bushing retrieval operations. 02:00 02:30 Make-up retrieval assembly,drain stack,and remove wear bushing from wellhead per Cameron. -Retrieval assembly:5'DS55 pup, DS55 drill pipe joint,DS55 x 4.5"IF X0,wear bushing puller. -Caliper ID of wear bushing:9-15/16"-no wear. -Begin staging Tesco casing running equipment near beaver slide offline. -Begin prepping shoe track,gathering running tools,and confirm casing tally with TSH thread representative. 02:30 03:30 Make-up wellhead/BOP wash assembly and wash both at 380 GPM. -Wash assembly:5'DS55 pup,DS55 drill pipe joint,DS55 x 4.5"IF X0,5'wash tool. -Conduct BCFT prior to washing wellhead and BOP. -No appreciable cuttings/debris observed at shakers while washing wellhead and BOP stack. 03:30 06:00 L/D wash assembly. Rig-down drilling elevators, bails,and TDS stabbing guide. 06:00 07:00 Rig-up Tesco casino running equjpment,. -Hold PJSM with Tesco,Nabors,and ExxonMobil. -Covered DROPS hazards and performed DROPS inspection of casing equipment. +Install tie wire on anti-rotation bracket;discovered on DROPS inspection. 07:00 09:00 Driller observed low coolant warning on EDS.Troubleshoot problem and found drive coupling between motor and coolant pump had lugs sheared off of coupling.Locate back-up drive coupling and install same. EDS coolant pump working as designed. 09:00 09:30 Service rig per Nabors specifications. c> 09:30 12:00 Finish rig-up of Tesco casing running equipment. G fJX -Hold PJSM with Tesco,Nabors,TSH,and ExxonMobil. (1.4"/"‘-- 12:00 23:00 RIH with 7"production casing from surface to 4930'MD. -Make-up shoetrack and Bakerlok joints per program with TSH representative -Check floats with ExxonMobil witness:ok. -Fill pipe and get PU/SO values every 5 Its. -123 jts out of 206 jts ran. 23:00 23:45 Circulate casing at 4930'MD.Obtain mud check and hookload values. GPM: 220 SPP:785 psi initial-600 psi final -No cuttings seen at bottoms-up. No losses while circulating. -MWin(bottoms up): 11.8+/PV: 19/YP:20/6 RPM: 14 -MWout(bottoms up): 12.0/PV:28/YP. 16/6 RPM: 12 -Hookload(pumps on): 120 klb up/105 klb down -Hookload(pumps off): 148 klb up/135 klb down 23:45 00:00 RIH with 7"production casing from 4930'to 5098'MD. -Fill pipe and get PU/SO hookloads every 5 jts. -127 jts out of 206 jts ran. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 2,482.0 124,063.9 3,000.0 135,385.9 0.0 11,322.0 Water-Fresh-Surface 1 US Gallon 7,812.0 256,914.0 11,424.0 281.442.0 0.0 24,528.0 Water Fuel-Diesel 1 US Gallon 315.0 18,606.0 22,008.0 0.0 3,402.0 vers 20091208 iw9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day ExxSobil Development Company ReportDate/Time: 4/11/2015 00:00 to 4/12/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 2 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 8,800 6.905 0.00 32 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 7"Production Casing at 8,781'MD. Activity at Report Time -Next Activity Waiting on cement;cleaning pits. Install 7"production casing slips and cut casing. Date/Time Density(lb/gal) FV(s/qt) API FL(mL/30min) PV(cP) YP(Ibf/100ftZ) 4/11/2015 23:00 11.80 75 21.0 15 Start End Time Time Comments 00:00 02:30 RIH with 7"production casing from 5098'to 6650'MD. -Fill pipe and get PU/SO hookloads every 5 jts. -165 jts out of 206 jts ran. -Personnel observed kicker on pipe skate not functioning. 02:30 03:30 Troubleshoot non-functioning kicker on pipe skate. Mechanic discovered small hydraulic leak(on pipe shed deck)and determined bad seal on hydraulic operating cylinder for kicker. Retract kicker, blank off hydraulic lines,and plan to repair once off critical path operations. -Circulate and work 7"production casing while repairing kicker(GPM:210/SPP: 1070 psi) 03:30 07:00 RIH with 7"production casing from 6650'to 8724'MD. -Fill pipe and get PU/SO hookloads every 5 jts. -205 jts out of 206 jts ran. 07:00 09:00 Wash in hole with 7"production casing from 8724'to 8781'MD and condition mud. GPM: 210 SPP: 1440 psi initial-1075 psi final -Count pipe-tally good:23 joints,3 pups,and 1 landing joint. -206 jts out of 206 jts ran. -Stage up pumps from 3 bpm to 5 bpm: 1100 psi break over pressure at 3 bpm. +No losses while circulating. -Hookload at 8781'MD(pumps off): PU=220 klb/SO=155 klb -Hookload at 8781'MD(pumps on): PU=160 klb/SO=120 klb -5'stick landing joint in hole,set casing on depth,reciprocate with 10'strokes. -Begin rigging-down Tesco equipment offline. -MWin=11.9 ppg/MWout=12.0+ +Begin adding base oil at 10 bph 09:00 10:30 Rig-down Tesco casing running equipment and rig up cement head. -Hold PJSM with Tesco,Nabors, SLB,and ExxonMobil. +Focus on hand placement,exclusion zones,and SIMOPS. -Set casing on depth prior to rigging-down Tesco. -Rig-up Tesco 16'bails and 200 ton elevators. -Rig-up cement head X0,pre-loaded cement head,cement manifold,and cement hose. -Work string once rigged-up:PU=250 klb/broke over with 30 klb overpull. 10:30 14:30 Circulate and condition mud while reciprocating 7"production casing with 10'strokes. GPM: 336 SPP:2020 psi -Stage up pumps from 3 bpm to 8 bpm:no losses while circulating. -Condition mud to 11.8 ppg IN/OUT and YP= 12-15. -Hookload(pumps on): 140 klb up/110 klb down vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day ElanMobil Development Company Report Date/Time: 4/11/2015 00:00 to 4/12/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 2 of 2 Start End Time Time Comments 14:30 17:30 Perform cementing operations with 7"production casing at 8781'MD. -Hold PJSM with Nabors,SLB,CH2MHill,and ExxonMobil. +Focus on pressure hazards,communication,and fluid movements. - Cement Pumping Details: +Pressure test cement lines to 250/3500 psi for 5 min each test:ok "� �( d++Pump 24 bbls of 12.3 ppq Muf dEush spacer with rig pumps at 5 bpm and 1200 psi. 6d— + Drop bottom plug-confirmed by Exxon Mobil witness. +Mix and pump : .. I ..• • - : --d cement at 5 bpm and 1250 psi max. t-6A� =Consistent density;no issues mixing. P`v +Mix and pump 5.5_bja_atj.E,IUuag_Cdas.s_atail cement at 5 bpm and 1225 psi max. =Consistent density;no issues mixing. +Drop top plug-confirmed by Exxon Mobil witness. +Pump 333 bbls of 9.7 ppg NaCI with cement unit at 7 bpm and 2625 psi max. =Displaced at 7 bpm when cement turned the corner. =Observed bottom plug land and pressure increase on correct volume. =Slowed pumps to 2 bpm prior to bumping plug. -FCP: 1820 psi at 2 bpm. t' -Calculated differential pressure—1100 psi. r.�V -Pumped half of shoe track volume:top plug did not hurttp A. v +Hold pressure for 5 min and check floats:floats holding. +Dry and wet cement samples collected and available for assessment. +Casing reciprocated in 10'strokes throughout cement job until last 5 bbls of displacement. +Full returns during entire cement lob. +Cement in place at 17:22 hrs, 11 April 2015. +EPA inspector onsite to witness cementing operations. 17:30 00:00 Wait on surface cement samples to set.Monitor well on trip tank:well static. -Flush out BOP stack with water. -Blow down cement lines to cement unit. -Install new mule winch in derrick. -Gather 4"XT39 casing clean out tools and stage by pipe shed. -Gather XO's and test joints for upcoming BOP test. -Clean active pit#5 for taking on NaCI. -Transfer all 11.8 ppg NAF from active to auxiliary pits. -Prep cellar and gather tools for nippling-down BOP stack. -Repair transfer pump in auxiliary pits. -Consolidate and stage remaining 7"H563 casing and components onsite. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 3,064.0 127,127.9 2,250.0 137,635.9 0.0 10,508.0 Water-Fresh-Surface 1 US Gallon 10,962.0 267,876.0 9,492.0 290,934.0 0.0 23,058.0 Water Fuel-Diesel 1 US Gallon 378.0 18,984.0 22,008.0 0.0 3,024.0 vers 20091208 m9Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • Exxobil Development Company Report Date/Time: 4/12/2015 00:00 to 4/13/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 8,800 6.905 0.00 33 55.83 Average Background Gas Average Connection Gas 'Average Trip Gas Last Casing String 7"Production Casing at 8,781'MD. Activity at Report Time Next Activity Testing CANH seals on'B'section. N/U and test BOPS. Date/Time Density(Ib/gal) FV(s/qt) API FL(mL/30min) PV(cP) YP(Ibf/100ft') 4/12/2015 00:00 11.80 73 21.0 15 Start End Time Time Comments 00:00 04:30 Wait on surface cement samples to set.Monitor well on trip tank:well static. -Service rig from 00:00-00:30 hrs -Troubleshoot grease line leak on drawworks. -Continue cleaning active pits. -Blow down mud lines in pits. -Gather BOP testing equipment. 04:30 12:00 N/D 13 5/8"10K BOPS. -Rig down cement head. -Drain stack and suck out landing joint. -Rig down hydraulic flush mount casing slips and 200 ton elevators. -Bleed down accumulator and remove control hoses. -Split stack,install 7"slips per Cameron,and set 10 klb over string weight on slips. 12:00 00:00 Cut casing and install'B'section of wellhead. -Lift BOP stack and make rough cut on casing at—24"above'A'section flange. -Set BOPS back on stump and remove spacer spool and DSA. -Make final cut on casing at 6.25"above'A'section flange(witnessed by ExxonMobil). -Install CANH seals on stub and install'B'section of wellhead per Cameron. -Orient tree per procedure and notify Projects for surveyor approval. -Fill void with oil and torque wellhead bolts per Cameron. -Test wellhead seals to 300 psi low for 5 min and 4330 psi high for 15 min:test good(witnessed by ExxonMobil). -Clean trip tanks and shaker troughs. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 2,778.0 129,905.9 2,550.0 140,185.9 0.0 10,280.0 Water-Fresh-Surface 1 US Gallon 7,728.0 275,604.0 290,934.0 0.0 15,330.0 Water Fuel-Diesel 1 US Gallon 378.0 19,362.0 22,008.0 0.0 2,646.0 • vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day EenMobil Development Company Report Date/Time: 4/13/2015 00:00 to 4/14/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 8,800 6.905 0.00 34 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 7"Production Casing at 8,781'MD. Activity at Report Time Next Activity Filling BOP stack with water. Test BOPs and perform cement evaluation log. Date/Time Density(lb/gal) FV(s/qt) API FL(mL/30min) PV(cP) YP(lbf/100ft') 4/13/2015 00:00 9.70 Start End Time Time Comments 00:00 02:00 Test both North and South'A'section outer blind flange connections on side outlet valves and chart. -Rig-down Cameron testing equipment. -Clean and clear cellar and prep to N/U BOPs. 02:00 08:00 N/U BOPs on'B'section. r -N/U Weatherford 7-1/16"10K x 13-5/8"10K DSA. Ilii"( -Install new ring gaskets and torque all connections to specification. -Re-install annular control lines. -Tighten turnbuckles and secure stack. -Install hole fill line and install new check valve. -Modify bell nipple riser. -Measure BOPs for new space out. -Install master bushings. 08.00 18:00 Dress TDS and rig floor for 4"XT39 drill pipe. -Change out TDS manual IBOP from DS55 to XT39. -Change out saver sub from DS55 to XT39. -Replace TDS back-up wrench dies with new ones. -Change out TDS stabbing guide. -Install 12'bails and 4"elevators on TDS. -Replace dies in Iron Roughneck with new ones. -Pick-up BOP testing XOs to rig floor. -Load pipe shed with 12 joints of 4"XT39 HWDP. 18:00 19:00 Pick-up,make-up,and RIH with 12 joints of 4"XT39 HWDP. -Begin rigging-up 2 x 4"XT39 FOSV and 2 x 4"XT39 IBOP on NuTec test stump offline. 19:00 00:00 Pressure test 13-5/8" 10K BOP and 4"FOSV/IBOP valves. -Pressure test 2 x 4"XT39 FOSV and 2 x 4"XT39 IBOP offline to 200/5000 psi for 5 min each test:ok. -Make-up remaining test assembly and seat test plug per Cameron. +Remaining test assembly: FOSV,X0,7"test plug,X0, 30'4-1/2"VAM TOP tubing test joint. +Open'B'section side outlet valves per Cameron prior to seating test plug. +Lock down test plug and energize test plug seals. -Begin filling 13-5/8" 10K BOP stack with water. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 1,943.0 131,848.9 1,801.0 141,986.9 0.0 10,138.0 Water-Fresh-Surface 1 US Gallon 19,110.0 294,714.0 22,932.0 313,866.0 0.0 19,152.0 Water Fuel-Diesel 1 US Gallon 322.0 19,684.0 700.0 22,708.0 0.0 3,024.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • Exx•obil Development Company Report Date/Time: 4/14/2015 00:00 to 4/15/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 8,800 6,905 0.00 35 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 7"Production Casing at 8,781'MD. Activity at Report Time Next Activity Rigging-down Baker SBT tool. Rig-up Schlumberger Iso Scanner tool and repeat cement evaluation log. Date/Time Density(lb/gal) FV(s/qt) API FL(mL/30min) PV(cP) YP(Ibf/100ft') 4/14/2015 00:00 9.70 Start End Time Time Comments 00:00 12:00 Pressure test 13-5/8"BOPs on 4.5"and 4"to 200/5000 psi for 5 min each test. -Hold PJSM with all personnel. Focus:good communication,pressure hazards,exclusion zones. -15 of 15 pressure tests conducted with no issues. -Test manual choke A,manual choke B.and super choke to 200 psi:ok. _ -Change out 12"butterfly valves in active pits 1,2,and 8 to viton(ZnBr compatible).Service offline. 12:00 14:00 Pull and lay down 4"testing assembly. -Unseat test plug per Cameron. 14:00 16:30 TIH and seat wear bushing. -Seat and secure wear bushing per Cameron. -Wear bushing:7"OD,6.25"ID, 1.0'long -Assembly:4"XT39 drill pipe,XO,wear bushing running tool,wear bushing -Blow down surface equipment from BOP test. -Fill stack with 9.7 ppg NaCI and put trip tank on hole. 16:30 18:30 Rig-up Schlumberger wireline unit and Baker SBT tool. -Hold PJSM with all personnel. Focus:dropped objects, manual handling,hand placement. -Assembly:CCL,Gamma Ray,Acoustic Digitizer,SBT,SBT VDL,bull nose 18:30 00:00 RIH with Baker SBT tool and log. -RIH at 150 ft/min. -Tagged at 8624'MD(55'high). f?,�` -Uplog with Baker SBT tool to 4000'MD:no good. (a�l� +Major/minor delta T separation too high. eV."- +Gain maxed at 21. 1\ -POOH to 2000'and check tool in vertical hole:ok. -Downlog with Baker SBT tool to 5100'MD:no good. +Major/minor delta T separation increasing in line with hole inclination. +Gain maxed out at 21 around 4500'MD/49°inclination. +Conclusion: Baker SBT tool centralization set-up for vertical hole(2 centralizers). -Decision made to POOH with Baker SBT tool and RIH with Schlumberger Iso Scanner tool. V )1,-(' +Mobilize Gemco centralizers from Baker(Deadhorse)via ExxonMobil hotshot. L't +Prep Schlumberger Iso Scanner logging tools. -Baker SBT tool at rotary table at time of report. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 2,337.0 134,185.9 2,707.0 144,693.9 0.0 10,508.0 Water-Fresh-Surface 1 US Gallon 6,384.0 301,098.0 313,866.0 0.0 12,768.0 Water Fuel-Diesel 1 US Gallon 378.0 20,062.0 22,708.0 0.0 2,646.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • ElanMobil Development Company Report Date/Time: 4/15/2015 00:00 to 4/16/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Eley: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors.27E 8,800 6.905 0.00 36 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 7"Production Casing at 8,781'MD. Activity at Report Time Next Activity TIH at 4100'MD. TIH to 5000'MD and slip&cut drill line. Date/Time Density(lb/gal) FV(s/qt) API FL(mL/30min) PV(cP) YP(lbf/100ft') 4/15/2015 00:00 9.70 Start End Time Time Comments 00:00 03:00 Rig-down Baker SBT logging tools and rig-up Schlumberger Isolation Scanner logging tools. -Hold PJSM with all personnel. Focus:dropped objects,exclusion zones,communication. 03:00 10:00 RIH with Schlumberger Isolation Scanner tool and perform cement evaluation log. -RIH at 90 ft/min. -Tag at 8540'MD. -Uplog to 4230'MD. +Log out of hole 50 fUm5'MD +TOC identified at 4905'MD based on interpretation by Schlumberger technical expert. 10:00 12:00 Rig-down Schlumberger fogging -Hold PJSM with all personnel.Focus:dropped objects,exclusion zones,communication. -Hold AAR for logging operations. -Clean and clear rig floor. Prep for picking-up cleanout assembly. ,. 12:00 14:00 Pick-up and make-up cleanout assembly. L— 4' 7 )` -Hold PJSM with all personnel. Focus:crush points,rigging-up,protecting the hole. ! -Assembly:6.125"mill tooth bit, bit sub w/float,7"multiback combination tool,X0,4"XT39 pup 14:00 16:00 Pressure test 7"production casing to 4000 psi for 30 min:good test. -Hold PJSM with all personnel.Focus:pressure hazards,valve alignments,communication. -Pressure test cement lines to 4000 psi for 5 min:ok. �� .•- -Pump in 3.3 bbls: bleed off 3.3 bbls. -Hold AAR with Schlumberger and Nabors. 16:00 00:00 Pick-up 4"XT39 drill pipe and RIH with cleanout assembly from surface to 4100'MD. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 2,592.0 136,777.9 2,000.0 146.693.9 0.0 9,916.0 Water-Fresh-Surface 1 US Gallon 5,082.0 306,180.0 11,298.0 325,164.0 0.0 18,984.0 Water Fuel-Diesel 1 US Gallon 279.0 20,341.0 720.0 23,428.0 0.0 3,087.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day Exx• obil Development Company Report Date/Time: 4/16/2015 00:00 to 4/17/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 8,800 6,905 0.00 37 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 7"Production Casing at 8,781'MD. Activity at Report Time Next Activity POOH at 1689'MD with cleanout assembly. POOH to surface and L/D cleanout assembly. RIH with 4-1/2"tubing. Date/Time Density(lb/gal) FV(s/qt) API FL(mL/3Omin) PV(cP) YP(Ibf/100ftl 4/16/2015 00:00 9.70 Start End Time Time Comments 00:00 02:30 Pick-up 4"XT39 drill pipe and RIH with cleanout assembly from 4100'to 5054'MD. -Hookloads at 5054'MD: 105 klb up/105 klb down 02:30 08:00 Slip and cut 101'of drill line. -High level LEL audible alarm at floor,pits,and cellar sounded on rig at 04:30 hrs. +Secure well and muster all personnel with full head count in 10 min. +Rig sensor readings: 0%LEL(confirmed with personal monitor) =Determined to be false alarm. +Troubleshoot with electrician. =Found loose connection in Gaitronics speaker box in doghouse. =Power back feed caused voice tone generator alarm to sound. +All clear at 05:30 hrs. 08:00 16:00 Pick-up 4"XT39 drill pipe and RIH with cleanout assembly from 5054'to 8642'MD. -Scrape and circulate per MI Swaco with multiback combination tool from 6878'to 7063'MD. +TNT Halliburton packer setting depth per tally:6978'MD. +GPM: 425 SPP: 1850 psi -Wash in hole with last joint and tag at 8642'MD with 10 klb WOB. + GPM: 425 SPP:2175 psi 16:00 17:00 Pump 50 bbl surfactant sweep and circulate hole clean at 8642'MD. GPM: 700 SPP:3500 psi RPM: 10 TRQ:4000-5000 ft-lb -Shakers clean at bottoms-up and with sweep at surface. -Reciprocate pipe with 90'strokes. -Hookloads at 8642'MD: 155 klb up/130 klb down 17:00 00:00 POOH with cleanout assembly and lay down 4"XT39 drill pipe from 8642'to 1689'MD. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 2,836.0 139,613.9 1,800.0 148,493.9 0.0 8,880.0 Water-Fresh-Surface 1 US Gallon 5,712.0 311,892.0 11,760.0 336,924.0 0.0 25,032.0 Water Fuel-Diesel 1 US Gallon 448.0 20,789.0 700.0 24,128.0 0.0 3,339.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • AinMobil Development Company Report Date/Time: 4/17/2015 00:00 to 4/18/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 8,800 6,905 0.00 38 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 7"Production Casing at 8,781'MD. Activity at Report Time Next Activity Picking-up injection tubing hanger. Land injection tubing hanger. Date/Time Density(lb/gal) FV(s/qt) API FL(mL/30min) PV(cP) _ YP(Ibf/100f11 4/17/2015 00:00 9.70 Start End Time Time Comments 00:00 03:30 POOH with cleanout assembly and lay down 4"XT39 drill pipe and BHA from 1689'to surface. -No abnormal wear observed on multiback combination tool. -Recovered 1.54 lb of metal from cleanout magnet. 03:30 04:30 Retrieve wear bushing per Cameron. 04:30 06:30 Rig-up Tesco 4-1/2"tubing running equipment. -Make-up Tesco power tongs,flush mounted spiders,and CRT. 06:30 07:00 Service rig per Nabors specifications. -Hydraulic leak observed on TDS.Locate source of hydraulic leak. 07:00 08:00 Repair leaking hydraulic fitting on TDS. -0-ring inside fitting that connects hydraulic bank to link tilt hydraulic hose was damaged. 08:00 00:00 RIH with 4-1/2"injection tubing from surface to 7023'MD. -Hold PJSM with all personnel. Focus:communication,exclusion zones,dropped objects. -BakerLok all joints below Halliburton TNT packer. -RIH at 90 ft/min. -Prepping to pick-up injection tubing hanger at time of report. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 2,548.0 142,161.9 3,769.0 152,262.9 0.0 10,101.0 Water-Fresh-Surface 1 US Gallon 4,536.0 316,428.0 336,924.0 0.0 20,496.0 Water Fuel-Diesel 1 US Gallon 315.0 21,104.0 24,128.0 0.0 3,024.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • Exxalobil Development Company Report Date/Time: 4/18/2015 00:00 to 4/19/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: 0TH Page: 1 of 2 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 8,800 6,905 0.00 39 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 4.5"Injection Tubing at 7,060'MD. Activity at Report Time Next Activity Rigging-down from tubing/packer test. Retrieve ball seat with slickline. Date/Time Density(lb/gal) FV(s/qt) API FL(mL/30min) PV(cP) YP(Ibf/100ftr) 4/18/2015 00:00 9.70 Start End Time Time Comments 00:00 02:30 RIH with 4-1/2"injection tubing from 7023'to 7060'MD. -Hookloads: 112 klb up/105 klb down. -Rig-down Tesco flush mounted spiders. Pick-up Cameronhhanger. +Drainnstack through ' 'B'section side outlets. +5'stick-up with tubing hanger in hole and landed out. pfreflo +Center tubing hanger while landing out. +Confirm landed through'B'section side outlets:ok. -Torque hanger lock screws to 300 ft-lb and secure hanger per Cameron. 02 30 05.30 Test tubing hanger from above to 200 psi low/5000 psi high for 30 min each test. -Test against Shaffer 4.5"x 7.625"Upper VBRs. -Test with rig BOP test pump and chart. -Re-torque hanger lock screws to 300 ft-lb per Cameron. +Achieved additional 1/4 to 1/2 turn on lock screws. -Blow down lines from pressure test. 0530 16:00 Reverse circulate 124 bbls of 6.9 ppo Isotherm down 4-1/2"x 7"annulus. -Hold PJSM with all personnel.Focus:valve alignments,hot fluids,communication. -Transfer Isotherm from active module to CH2 vac truck. -Tie CH2 vac truck into LRS hot oil unit and heat up Isotherm to 130°F. -Tie LRS hot oil unit into'B'section side outlet valves. -Pump 124 bbls of Isotherm at 0.3-1.5 bpm with full returns. +Take returns up tubing and back to rig pits. +Final circulating pressure: 1900 psi. -Shut-in annulus pressure:832 psi 16:00 17:30 Drop Halliburton ball/rod assembly,set TNT packer,and pressure test TNT packer._ -Drop ball/rod assembly per Halliburton. (� -Pressure up to 2500 psi with rig pumps for 5 min and set packer. 1\ +Observe packer set at 2280 psi. +Pump 1.3 bbls in and bled 1.4 bbls back to trip tanks. +EPA representatives witnessed packer set. -Pressure test 4-1/2"x 7"annulus and TNT packer top to 3500 psi for 30 min., +Pressure test lines to 3500 psi for 5 min:ok. +Pump 1.90 bbls at 0.25 bpm to pressure up to 3500 psi. +Test Pressures: Tubing (initial): 46 psi Annulus(initial):3615 psi Tubing (final): 41 psi Annulus(final):3327 psi +Bled annulus to 1000 psi and returned 1.50 bbls. +EPA representatives witnessed entire test. +Blow down lines. 17:30 22:00 RIH with Schlumberger slickline and retrieve Halliburton ball/rod assembly. -Hold PJSM with all personnel.Focus:work group interface,suspended loads,communication. / -Rig-up 12'drilling bails to hang slickline sheave. ✓ -Ball/rod assembly retrieved successfully upon first attempt. -Bleed 1000 psi from annulus with cement unit once ball/rod assembly at surface. +0.25 bbls bled back. 22:00 00:00 Pressure test 4-1/2"injection tubing and Halliburton TNT packer with Schlumberger cement unit. A< -Hold PJSM with all personnel.Focus:pressure hazards,valve alignments,communication. •,< -Pressure test lines to 4000 psi for 5 min:ok. -Pressure test tubing and TNT packer bottom to 4000 psi for 30 min:ok. +Pump 1.80 bbls at 0.25 bpm to pressure up to 4000 psi. +Bled back 1.90 bbls at end of test. +Test Pressures: Tubing (initial): 4210 psi Annulus(initial): 500 psi Tubing (final): 4133 psi Annulus(final):450 psi -EPA representatives witnessed entire test. -Chart tubing test pressure and annulus pressure. -Blow down lines and clean out cement unit at time of report. vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • ElanMobil Development Company Report Date/Time: 4/18/2015 00:00 to 4/19/2015 00:00 Well Name: PTU-DW 1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 2 of 2 Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 2,331.0 144,492.9 152,262.9 0.0 7,770.0 Water-Fresh-Surface 1 US Gallon 3,948.0 320,376.0 6,342.0 343,266.0 0.0 22,890.0 Water Fuel-Diesel 1 US Gallon 378.0 21,482.0 24,128.0 0.0 2,646.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • Exxiklobil Development Company Report Date/Time: 4/19/2015 00:00 to 4/20/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 8,800 6,905 0.00 40 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 4.5"Injection Tubing at 7,060'MD. Activity at Report Time Next Activity Rigging-up pert guns. RIH and perforate well. Date/Time Density(lb/gal) FV(s/qt) API FL(mL/30min) PV(cP) YP(lbf/100fti 4/19/2015 00:00 8.34 Start End Time Time Comments 00:00 01:00 Blow down Schlumberger cement unit and lines to rig. -Clean out Isotherm from Schlumberger cement unit. 01:00 02:30 RIH with Schlumberger slickline and retrieve ball seat. -Hold PJSM with all personnel.Focus:exclusion zones,communication,dropped objects. -No damage observed on ball seat at rig floor. 02:30 03:30 Set Cameron type H BPV in tubing hanger on dry rod. -Drain BOP stack down to DSA. -Secure BPV in tubing hanger with 6 left hand turns. 03:30 09:00 N/D 13-5/8"10K BOP and stow back on stump. -Hold PJSM with all personnel. Focus:dropped objects,working at heights,lifting equipment -Blow down hole fill,choke manifold,kill line,choke line,and TDS back to pumps. -N/D 7-1/16"10k x 13-5/8" 10k DSA and store on table for back haul. 09:00 12:00 N/U Cameron 4-1/16"5K production tree. -Projects surveyor onsite to obtain tree survey measurements. 12:00 13:30 Pressure test 4-1/16"5K production tree per Cameron. -Pressure test void to 250 psi low/10,000 psi high for 5/15 min:ok. -Remove BPV and install TWC. -Pressure test tree to 200 psi low/5000 psi high for 30 min each test:ok. 13:30 14:00 Retrieve Cameron type TWC from tubing hanger with dry rod. 14:00 00:00 Rig-up Schlumberger wireline unit, PCE,and lubricator. -Pressure test lubricator to 200 psi low/3500 psi high for 5/10 min:ok. -Prep guns for makeup. -Clear pad around rig and PTU-16 in preparation for rig move. -Hold PJSM for pert run at time of report. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 2,035.0 146,527.9 5,536.0 157,798.9 0.0 11,271.0 Water-Fresh-Surface 1 US Gallon 12,726.0 333,102.0 343,266.0 0.0 10,164.0 Water Fuel-Diesel 1 US Gallon 315.0 21,797.0 24.128.0 0.0 2,331.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • ElanMobil Development Company Report Date/Time: 4/20/2015 00:00 to 4/21/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 2 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 8,800 6,905 0.00 41 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 4.5"Injection Tubing at 7.060'MD. Activity at Report Time Next Activity Conducting WFL. Finish conducting WFL and perform step rate injectivity test. Date/Time Density(lb/gal) FV(s/qt) API FL(mL/30min) PV(cP) YP(Ibf/100ft) Start End Time Time Comments 00:00 03:30 Pick-up Schlumberger perforating guns and make-up lubricator at quick connect test sub. -Test quick connect test sub to 200 psi low/3500 psi high. -Pick-up guns for perforating pipe and RIH to 8550'WLM. -Clear pad around rig and PTU-16 in preparation for rig move. 03:30 05:00 Correlate gamma ray logs,pick-up and set perforating guns on depth,and fire guns. -Pressure up wellbore to 200 psi prior to correlation logging. r'r -Stabilize wellbore pressure and charted through Canrig. v,L -Correlate and perforat@well from 8516' to 8536'WLM -120 shots at 6 shots per foot and 60°phasing. -Pressure dropped from 200 psi to 160 psi after firing guns. 05:00 09:00 POOH with perforating guns and pick-up WFL tools. -Bleed down pressure to 0 psi. -Monitor wellbore on the trip tank. -Inspect and L/D perf guns: 100%fired. -Install chiksan lines on tree wing valve for WFL. 09:00 10:30 Pressure test lines with the cement unit against tree wing valve. -Pressure test 250 psi low/5000 psi high for 5 min each test. -Change out a swing that was leaking. -Swap to kill line due to leak in lower flange to SLB cement unit. 10:30 00:00 Make-up lubricator quick connect test sub and begin performing Schlumberger RST water flow Ing _ -Test lubricator quick connect test sub seal. Clear pad around rig and PTU-16 in preparation for rig move. 3 WFL Test Results: t" W Achieved 3 consecutive stations below injection packer depth(7018'WLM)exhibiting zero upflow to satisfy EPA requirement: 7400'WLM, 7390'WLM,7380'WLM -7400'WLM +Injection Rate:5 BPM +Average BHP:4875 psi +Minimum BHT:71.7 F +Maximum BHT:81.8 F -7390'WLM +Injection Rate:5 BPM +Average BHP:4775 psi +Minimum BHT:69.1 F +Maximum BHT:76.8 F -7380'WLM +Injection Rate: 5 BPM +Average BHP:4660 psi +Minimum BHT:67.0 F +Maximum BHT:68.8 F Achieved 3 consecutive stations above injection packer depth(7018'WLM)exhibiting zero upflow to satisfy EPA requirement:7000'WLM, 6990'WLM,6980'WLM -7000'WLM +Injection Rate:5 BPM +Average BHP:4402 psi +Minimum BHT:53.3 F +Maximum BHT: 54.1 F -6990'WLM +Injection Rate:5 BPM +Average BHP:4388 psi +Minimum BHT:45.3 F +Maximum BHT:54.2 F -6980'WLM +Injection Rate: 5 BPM +Average BHP:4370 psi +Minimum BHT:43.9 F +Maximum BHT:45.0 F vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day Exx. obil Development Company Report Date/Time: 4/20/2015 00:00 to 4/21/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 2 of 2 Sales Unit Cum Item Size Sales Unit Consumption Consumption _ Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 1,636.0 148,163.9 157,798.9 0.0 9,635.0 Water-Fresh-Surface 1 US Gallon 18,144.0 351,246.0 9,450.0 352,716.0 0.0 1,470.0 Water Fuel-Diesel 1 US Gallon 315.0 22,112.0 24,128.0 0.0 2,016.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day I EllinMobil Development Company Report Date/Time: 4/21/2015 00:00 to 4/22/2015 00:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 1 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 8,800 6,905 0.00 42 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 4.5"Injection Tubing at 7,060'MD. Activity at Report Time Next Activity Rigging-down wireline PCE and lubricator. Perform step rate injectivity test. Date/Time Density(lb/gal) FV(s/qt) API FL(mLl30min) PV(cP) YP(Ibf/100ft') Start End Time Time Comments 00:00 05:30 Finish performing Schlumberger RST water flow log. -Clear pad around rig and PTU-16 in preparation for rig move. -Change Swab and liners to 4.5"on#1 mud pump. NOTE: Refer to Report#69 for a summary of WFL test results. 05:30 19:30 Perform Schlumberger temperature log. -Clear pad around rig and PTU-16 in preparation for rig move. -Begin changing Swab and liners to 4.5"on#2 mud pump. 19:30 00:00 Rig-down wireline PCE and lubricator. -Clear pad around rig and PTU-16 in preparation for rig move. -Finish changing Swab and liners to 4.5"on#2 mud pump. Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 1,739.0 149,902.9 157,798.9 0.0 7,896.0 Water-Fresh-Surface 1 US Gallon 126.0 351,372.0 8,610.0 361,326.0 0.0 9,954.0 Water Fuel-Diesel 1 US Gallon 315.0 22,427.0 24,128.0 0.0 1,701.0 vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day ExxSobil Development Company Report Date/Time: 4/22/2015 00:00 to 4/22/2015 12:00 Wel i Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 1 of 2 Current Rig End MD(ftRKB) End Depth(TVD)(ftRKB) Net Depth Progress(ft) Days From Spud(days) AFE Cum Days(days) Nabors,27E 8,800 6,905 0.00 43 55.83 Average Background Gas Average Connection Gas Average Trip Gas Last Casing String 4.5"Injection Tubing at 7,060'MD. Activity at Report Time Next Activity FRR PTU-DW1. Rig-down Nabors 27E. Date/Time Density(lb/gal) FV(s/qt) API FL(mL/30min) PV(cP) VP(Ibf/100ft2) 4/22/2015 00:00 0.00 Start End Time Time Comments 00:00 05:30 Perform step rate injectivity test with Schlumberger cement unit using freshwater. -EPA representatives witnessed entire step rate injectivity test. -Freeze protect well with 40 bbls of 6.8 ppg LVT-200 base oil. Step Rate Test Results: Stage 1 -0.5 BPM Rate +Step Time: 3 min 50 sec +Fluid Density: 8.38 ppg+Volume Pumped: 1.8 bbl +Max.Pressure:677 psi -1.0 BPM Rate +Step Time:4 min 30 sec +Fluid Density: 8.38 ppg+Volume Pumped:4.4 bbl +Max.Pressure: 1249 psi -1.5 BPM Rate +Step Time:3 min 0 sec+ Fluid Density: 8.38 ppg+Volume Pumped:4.2 bbl +Max.Pressure: 1523 psi -Fall-Off +Time: 11 min 20 sec +Pressure: 1349 psi to 146 psi/106 psi/min loss rate Stage 2 -2.0 BPM Rate +Step Time: 3 min 20 sec + Fluid Density: 8.35-8.38 ppg +Volume Pumped:6.3 bbl +Max.Pressure: 1679 psi -2.5 BPM Rate +Step Time: 1 min 50 sec + Fluid Density: 8.35-8.38 ppg +Volume Pumped:4.6 bbl +Max. Pressure: 1775 psi -3.0 BPM Rate +Step Time: 2 min 20 sec + Fluid Density: 8.36-8.38 ppg +Volume Pumped: 7.1 bbl +Max.Pressure: 1867 psi -3.5 BPM Rate +Step Time: 2 min 30 sec + Fluid Density: 8.33-8.36 ppg +Volume Pumped: 8.7 bbl +Max.Pressure: 1935 psi -4.0 BPM Rate +Step Time: 3 min 20 sec +Fluid Density: 8.35-8.38 ppg +Volume Pumped: 13.4 bbl +Max.Pressure:2018 psi -Fall-Off +Time: 19 min 0 sec +Pressure: 1578 psi to 182 psi/73 psi/min loss rate Stage 3 -4.5 BPM Rate +Step Time:4 min 50 sec +Fluid Density: 8.35-8.38 ppg +Volume Pumped: 20.0 bbl +Max.Pressure:2096 psi -4.0 BPM Rate +Step Time: 2 min 10 sec +Fluid Density: 8.35-8.36 ppg +Volume Pumped: 8.9 bbl +Max.Pressure: 1945 psi -3.5 BPM Rate +Step Time:2 min 0 sec+ Fluid Density: 8.35-8.36 ppg +Volume Pumped:6.5 bbl +Max.Pressure: 1835 psi -Fall-Off +Time:22 min 7 sec +Pressure: 1519 psi to 196 psi/60 psi/min loss rate 05:30 10:30 Install Cameron type H BPV with lubricator and install blind flanges on top of tree. -Pressure test blind flanges on tree offline per Cameron. -Blow down lines and rig-down chiksan in cellar. -Begin installing 4.5"liners in mud pump#3. vers 20091208 wv9 Security Type: Drilling_XOM Printed: 5/27/2015 Partners Report by Day • EnMobil Development Company Report Date/Time: 4/22/2015 00:00 to 4/22/2015 12:00 Well Name: PTU-DW1 Job Type: Drilling and Completion Field: Point Thomson Unit Set: US Operator: ExxonMobil Development Company Reference Elev: OTH Page: 2 of 2 Start End Time Time Comments 10:30 12:00 Secure well with Cameron and clean out cellar box. -Finish blowing down rig and removing water from pits. -PTU-DW1 FRR: 12:00 hrs(22 April 2015) -PTU-DW1 Final Well Status: +Cameron type H BPV installed in tubing hanger. +Lower Master(Manual), Upper Master(SSV),Swab(Manual),Inner Wing(Manual),and Outer Wing(Manual)valves closed. +40 bbls of 6.8 ppg LVT-200 base oil freeze protect left in 4-1/2"tubing and tree. +Final Pressures: =4-1/2"Tubing:300 psi =4-1/2"x 7"Annulus:0 psi +Cumulative Volume Injected(To Date):3693 bbls total Sales Unit Cum Item Size Sales Unit Consumption Consumption Receipts Cum Receipts Returns Cum Returns Inventory Fuel-Diesel 1 US Gallon 698.0 150,600.9 157,798.9 7,198.0 7,198.0 0.0 Water-Fresh-Surface 1 US Gallon 336.0 351,708.0 361,326.0 9,618.0 9,618.0 0.0 Water Fuel-Diesel 1 US Gallon 79.0 22,506.0 24,128.0 1,622.0 1,622.0 0.0 • • vers 20091208 v v9 Security Type: Drilling_XOM Printed: 5/27/2015 • 0 F " C)C M 0)0) 22222 CO 0)2 2 M MMM2 O M 0)0) 00 .4-.7N .- CO O)r N r 0.- COMM COO)O) O) N U) m M O cocococo- O o _(0O N M O O)7 61766.- cOoi6 ,76 N d O)O) ,- C)V CM V .1-00 l0 M N 00 -,C. N coILVN N N CO CO M co M co co M co co CO N N \� a V tO /) Q O U)N U) 7 W u1 U)r V V M(O W O W r r -IC ONv- v- v-N MMO NON OO MN V.- N O o Z O O O O O O O O O O O O O O O O O,- r I V ` L . O O O O r (O (0— 0) (0 O CO Mr.-0,f _ _ 00066 CO W N U1 M W N W N.- N N W W O OON r W O C)N NW W N NY N o MMM MMMMM MMMMM MMMM N mo Uc 0] coo J co • L a) E (n J W 7 O m Cn 6 Z d O O0),- r r0) O(0.- O M O W W 7N W ZC N C U) O O O)v-x- M r N N v- N.40.4 V CO.4- N-0U) O d 0 > O C O + N 00�M4 (0O W O O vNC')V([) (Or W W U H O O E N V O T-T- V-V- V- T- r-V- E -22 N L E (• V O H • N ° N 00) ° U7 N 0 ° U) N 1..1 E Ln O@ NC) Or M r "CoN- Z O CO C)) I p 0 Q . CO Ur1- V 3 pd a) e N O Q V v N T- CD (0 W 2 co H O N > T wx OOVNr NM(0 U)CO) O) U)W a) w „ 00,1-N ,- N V M W v- 00)N-NM NOWV O O F N M V CC)CO CO N- Ni r W CO CO CO 0)0),_ co L E c r d d O -65 O c 0 O) ` O ~ O O l0 7 C N ` rL 0 o 0 Q E > w a E rn w d c y -0 .6 c w E � O10 w C -0 _ rnC a) 0 Fo OCcOw -oo27, ILc « 6CZ Z O O 2 O N W r W W m o W W O O W m H O 00 0 d c lL •• 0 Q Co " m m N Z .- OOMv-r NO7 N7 MOr co.O CO(0O W H 2 V C d N •� -0 N d p)A . 0 0— N N C')V u1 CO r W O)O,-M M 4 U)7 a- 0 0 J 0 W E E U( 0 5. 0 0 c 0 O r T 0 fn 0 w w V E rL CO U O V 0 0 8 0 d d v v L w d d U _ d c 5c m V U U O NCL N tq » FFCP2H0H202z0HZ_I CU d 0 EO O co 7 7 r U)O N M N V N-(O N V 0M C Q w O O O v O N V N CO CO V v-W CO V O)N O CD 0 (A OOOOO OOOOO r-N N C')V� V(n N M C) LL c I- 0 In Z m a) Q3 0 O H H 0 E O N UN W O W O)M W 1)O)NM W O 2 0 O CO M dC O C)4 00 O Mr O M r V O V CO N W O 0 MMNN _OOOW WNDD0 ,f .4-MN rn C0,1-0 CO r W W O) 0v-CVM a 060-00 E a N T-V-V- T- T- r r r r 0 .0 u o) H LL o c c0v (n o m a D a O C')O -O 2 ,- 23238,121 O)W V V N W 0) r N r r W O) U) o o O)O)O N N U)O)M.O W W W W CO O N O O O M O O) 46,7:66 C)(')U) O)N O c0 i0 O) H N O) O) M V M V 7(0 U)U) M N W V N E N M M N N M M M M M M M M M M M N N WN 2 O > O C 7 (,O Q 6 a. CO 3- - a > w O O O) CO N. (0 M a V V O O U)7 0 V CO CO Cl M CO a-r N CO N C 0 co W p O c O O r W r W O)W U)CO W W W r W V W(O U) W O M O 66666 00000 O O O O O O O O Q W co o E �° _ _ � '- (� v CONN (n N >> (O L N > > 3 c) ° Q _p 0 7 0 N O C H 0 0 0 O O L o N N O W'81• O r c 3 3 3 5 3 2 • U o O) N g,,, U) H (0 N ) W 0 < W ao aaa naNZZZ Oi O N O O N W W O M 0 7 O)7 COIL-.N- 00 CO- O CO 2 O V U)N U) N N(0 O N 6C0,1- 00) W v r r E Q) O M 4 co CO (+)r O M r V CO N V W N U)O) M M N N O O W W W r CO CDU) .1-.4- M N O w C1 C0,10 (ON-W W 0) O v-N M V 08.00...M R U) Q c- W m w N O C. IIP W N c p) .. (V 7 w O w 0- « u) G O J Z > V L a0 =1 :0 C N C) N M,e. d C d to O LL !0 N CM p 7 o a 2 0 =• c 0 o 'c u c 0 m O t r > > Q '- - 0 (q o E c m o c _ y is To; N E w c Oa) fU d 0 7 7 0 0 0 0 Ct d 0 H O O O U it w 0 0 (A co H U J J U U' > 0 a • LL a^ MM W W J �JJQQ 2Qd--fid Q JQdJ J�JQJ Jo D r J-)�Q'� W W W W W WW 0)N W (D O -007 W�U)0N 0)N- M W 0)W rM M(.0(0r7 M4) N10 U)70)N-0) NM 0 M r�W o)U) r70)W N U) NDN a-7NU(.) '-(0.-MN U)W U)O) .,700a-M.7 M7 W 7r 010 0W N)N O W 7 W U) U)0)6)0)N W O)O 4 N g-646 64.-66 7 0)U) N 7 N 7 NU) N N � W n�f� 0)0)W a-(0 N N N 0 U) N N M N U) M W N W M r W N 7 0 (0 W W 0)O U)W 0a-NOM W W N W 0(.0000 V 7 U) Jx N 01U)NWs- W WU)O7 007),— N-ONW (00.0470. 0)WO0)W NN-W WO '-U)NWs- 0)0 0 O o N v-N N N a-a-a- N N a- N a- N N N N N N O O .-6606 66666 O O a- i w 0) OM W ON). 7-n MM N-NO)W N W W W(NLO O W )U)M'0) I�MOO(+O)WN 00000)00)) 0)0)007 NM 00 0 E W W U)N-N-N W co 7 MN 000 00000 00000) 6)6)0)O)O) 6)0)0)W W 00 O)6)6) O)6) o 0 W W 7 M M NNNNN NNNNN NNNNN N N N N M NNNNN NNNNN NNNNN NNNNN NNNNN NNNNN NNNNN NNNNN NN 01:7' 0 On0W O )NaM N -0 0 O V MU) 0 00 r 7 0 V0 + NNaU .-WON ( 00- poWOW 00 NOW00 0 D 66666 UU7W 000101 0 ,- P0W WUNW6) 00017W 00 .-07 WW( a-Nc)U)W O).-7 N-0 7 WNW 0 W I- M0)W N0) U)N O)W M U)U)N O) W M W U) NO) V �� N NNMM7 7()U)W W N-N W 0)0) 0- NM 77U)W(0 n W WON NN 21 0) Nn NNU) W MNOM U)U)0)W N W U)U)M NU)7N W 7U)U)r M0)M0) W 70 W U) O7 0 M W NNU)U) N W r WO 7'N W N '0)N07 W na--W n W 7.-00 ON- U)0'- N-U)7N-o NM 7 UD U)MN 7 UD N)00)0) 0661,:6 6)N f-M C W I'-h U)U) 7 U)UD 7 7N2.1-U) WWO,-(+) W W M W 0)01 W 07 N- U)0)M n U)07 W hN W a-U)O70) V O) U) 777 7 NNN NMO')Iq vNU)U)W UNN-UDUO U0)0)00 NNNN MM U Q p (I) N C)U)N0)U) 0)N W OU) 0)WN-W 7 Z 010 W W 0 MON-OM NNN M W ONI- NM W 0) U)6) j(0 .-Ommm M 7N W OU) 0),00)0 M 0)W O W ONMO (+)7I)0)0) W NNO)0 U)NN7 W MW r . . . W NM W N 00 ISN a)�NNM W W NO1M (00 W 00 N W NN W C')0Na) 100(01�0) d WWON(0 n NN 7 W N W (00(00 W WNW 0 0010N -(,)COMM 7m 7' " 777 NNN(h MM��(0 (n(Q 471�f` OD W D1mO C"-"NM M77U)0 (") p I- F a_ 0I7 .7 0)0)W W U) (00170)0 W NU)W 7 I-O U)7a- 0)W W 7 W NN W W 0)NU) W U)O U)0) N-0) W U) U)0)W 6)W MMN- MM O W W U)N r-tl)0)0.- WOW 0N- W NOW W W 06)00 U7N0)N)W U)0) p 0) O N h nti 010 N7 W OOMM 6.-666 7N-0 U)0 U)U)N N W 0)0)N 7 W 6666M NU) 0 a-M7 W 7 WNW U) W r M0)W N0) U)N0)W M 0U)U)NO) W M N-U) NO) I- NNMMTF 71)(0(0 W N-N W 0)0) 0,- NM 77 U)W W I-W 0)0)0 d N N N 0) 0 0 ✓ p (0 0)M 7 N N 000.r-03 M 0)U) W W r U) M W 7 0)7 O)W N- W W W O) W U) 01,1: 1 d > , N Mrs W U) 0) .F-V N0)N7� N V W NU) 0)U)7 W W MNMOO MU)U)M0) W NU)W U) N7 . . U)N U)6)7 W 0r0)CO 00 W N W W r W M W.-777 M M N N NNN N O N N a-NN W I�W U)7 01 00 W N M W W M or-Tr.-co 0a-a-(W U)0)r010) (0 N-N W U) M O N N N NNNNN NNN N 0 0 N M M 7 U)W 1 M W M O N N M M 7 U)U) W I f`W W Q 1 O 0 - NNNNN NNNNN N M M M M M M M M M M M M M M 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 U) 0 F C O 0 0 v O Mg2 Z? W OOW W O M W W N 7)ON W 8 N 70) M 0 W h O M W N W(+)N-N. co 6)co W a O 00 6)60) 0)NNNN 6)W W W N- W U)W f- W 06 co N-co W W O)0)N NN N N N yE N N N N N N N N N N N N N N N N N N N N NNNNN NNNNN NNNNN N N N N N N W 0)OON MN-N- M (NU) N W WNW 7 0)0)Oa')W W MOO)(+) W N-W 7 N W U)N W N7 W N W W t` 7 01 ID n W MON-NN.. 0)N-0)U)7 e-W IS O)W n W W 0)0) 0)0)0)00) 7 7 . • M U)f�W�M 7 W rdlN NN NO NCC')W W W t`W Q7 W 00616)0) 66666 OO NNN N N M MMMMM 7 7 7 7 7 7 7 7 7 7 ()(17 7 7 7 7 7 7 U)7 LOM Q 6) 0)N0)M M ON 017 NO,- N. W NN- 0) N7N0)M 701 U)W W NM CO 0)77N7 7O) W WNNN 7f-1'-0)U) NU)U)WN M WMN7 NMN-0 WO)C-NN WU)N-Wh 7 W7 W, 7f- 1� 0)N W W O 7 n O N W W 0)7 N- V (O O 7 N N C')W a N 0 N W W U) O N W O M W I- N a-0 0)0) W N N N W LI)7 C')C')M 0 0 0) W001,-(00 U) C')M N W O O W 6)W N-W W U)7 0) 0 NNM 7U)W N-W 0)O NM aM W N-N- W 6)0 N 017010 W r W W O NM70W N-W • N N N N N NNNNN N M M M M M M M M M (+)C')7 7 7 7 7 7 7 7 7 7 N U)U) U)M U)O U) MN 0 N U) W N U) 01 0 2 0 E m 6) E C O N U J 0 • • 7 0 LL ` Q' p'J J Q'J J Q' C' Joe Q' J J JCC J ce oe a' J J J JW J J c' J Q U) M H U)0)N- 0)M S N M CD 0)CC)CO 7 f- N N. u,0- N U)N- OO 7 M r 2 0 OLO 0 407 (0 r OM7 U) MM�O7(D (O.- 7�S n OU)O,- ON C • 70tH OCn N6)f. U)ON co OOOM U)O7U)CO NCL C 6 u U7 V CO (AT- 6) CO CD,T r N `- r O �CO0) 01 76)n T-0) 00 CO OD 01 coC0 CD > 2 rna U v y _ co _ O U)M 7 N O M 7 0 0 N C) 7 0) O O O)r- (`)O0 0)7 oD M T N 7 N O T- -- _.1 = (O 00 cc (O co r- r- O M r-(0 (Or 7 r-CV CD7 U)7 M(D00 f` 0)CO(O N 7700 O O ❑ C O O O O O O O — 0 0 0 0 0 O O O O O O O O O O —0 0 0 O O O O O t N d \ V 0 7 CO N tO Cr U7U1 O r W 7 CO O O M N r-7 00 Cr O U)O)N M M M 7 7 O) M OD M h r-n N-N O)r U)N 0)(0 Cr M 7 .. ) 0) 0) T-T-T- 7 U)U)(D(O CO(0 CD CO U)U)U) U) y) 6) 6)m O) O)d) O) O O O O O O O O O O O O O O O O 0 0 0 0 0 O O O O o f N N N N N N N N N N N N N N N N N N N N N N N N N -- CNN 'y N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N • Q a) a E- 75 0 0 E 00 O M M N CO O M 7 N CD O U) N O M U)7 O N r r-M 7 N O)0) M N- CO N O H ... O0 N O 00 M s-7 N CD U)OD CO 7 6)7 CC)N-U) U)c- OO 7 r- N-O CO r- U) O)O N 7 T W O N N O W N M O co D) U) U)W C6 O N Ti CO CO W OM Ti O n co O) N N O N-7 CO U)M O T 7 00(D M O h 7 N CO CO M O N-U) N 0)CO CO O n 7 U) N M 7 7 U)(D r N- OO 0)6)O N N M 7 7 U)CO h h CO 0)0)O N N C) 7 7 7 („) N N N N N N N N N N N M M MMMMM M M M M M M (+)777 7 7 7 7 Cl) T 3: _ 2 is Cl) r O0 7 O M CO N M Ur M UO O W N r7 OD M 7 n 0)M ON)r)N Cl) N C C) 111 ... O O O co co(D Ti N O U)U) M N O)CO N- on U)M N,— CO M on 7 on M r d n d V D 7 0)7 O)CO CO CO CO CO 00 N N-N h N(D CD (0 O U)O 7 0) M CO N CO O) E (/) 7 7 U) Cl)(D CO N- N- O0 OO 0)0)O O N N M M 7 7 N U)(D CD CD N- r 00 00 00 (p N TT TT 7 TT TT TT TT 7 TT TT TT TT N N N N N N N N N N N N N N N N N N N N O 6 O) U C_ N 0 ❑ U) CO O)M OO O 7 00 n M r-0 U) 7 CO O N (D N N CD M N-co 7 7 N CO M CO U C j z O N 00 O)U)N r 0) U)N U)N M O U)M U)N r-r M O CD U)U)O M O) U)O M n N ,_• H CCC)O Cl) r- CCOOM N- N on N-M CO COQ)6M) 70))U 6 on Oon on)0 U7 O CO M CD W n N OMD M 0M) 70U) W y v d N.-OD 00 O)O)O O r- x- N N M M Cr 7 U)CO CO N- N-OD OO 0) 6)O CD N M M M 0 TT TT TT TT TT N N N N N N N N N N N N N N N N N N N M M M M M M M (') O 2 ❑ 2D F- CL O Om0 N- COU)O M N 6)O OD 7M CDU)N N MN O)O) M r-CD N (0 Q a u V Nr U)V"ONN- U)7 rN7 a)7U)N-U) U)- 037r- h-.CD CO— U) 0) O N7 0 = ❑ Cl) ON7 (6 W ON 07 (OOU D) N U)W co O N 7OO W O C•)7(O N- co O) T- W It 2D F- 7 OD U)M 0 h 7 00 CO M 0 n 7 N 6) (D M O N U) N O)(O CO O N 7 U) H N M 7 7 U)CO N-N- W 0)0)O N N M 7 7 U)(0 N-h CO O)6)O N N o) 7 7 0 Cl. N N N N N N N N N N N M M M M M M M M M M M M M CM 7 7 Cr 7 7 7 7 W N C a co 0 E D r r o) 1-- ❑ E 13 O(00O 7 N W 7)M N M mO 7 O;7 UO M MM ON- 7 O O O nM W W N O M Cd U) C O O O 6)CO 6 0 D N O DO 6 0 O r- N N M on M Ti M U) 6 UO n M O) U) N-N 00 7 O(D N O) 7 (0 M co U) r M O) U) r M 6) CC) (0 O O) O r- N M M 7 7 U) (O (D n r OD 0)O)0 0 N N M C) 7 U)U)CD (0 T W CO CO NE (1)CO U) U)U)U)U)Cl) U) U)U)on U) U)on U)(D CO O CD(D(D CO O CD CO CD CO CO O(0 (D CV 0 ❑ v L 0 2 H C C a) O -0 0 3 `C _ 0 v OO 0 7 r Cn 6) N00 (O 7 U)M 7 N CO N U) O)M O(D 7 U)0 M(O 00 (O M M 0 •(t ` r, N 6) r-7 U)U) N CO n U )N .- CO 7 N O CO CO O 7 CO N O m 6) h- r- CD U) U) O I- N M M M N N N N M N N N N N N M o)N N O CO 6)M a0 O)a) O) O) o LL E N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N (7.1 CD ❑ y O Q CD U) Q1 ❑ 6 V v 6)N CD N 6) CO 7 O)Cr) N 6) 7 0 (0 0 f` M ao N CO O CO N N 7 + t C 7 CO M M 7 M M N M 7 m O O) O)W CD O 00 N 0)00 CD CO n n O O n N OO O) 6) T O F O0O O O O O O O O6)O6) 6)6)6) 06) 06)6)06) 6)0)6)0O) 6)0)6) 6i N a 7 U)on U) U)CO Cl)CO U7 U) U) U)7 7 7 7 Cl)7 7 7 7 7 ] Cl)U) Cl)U) 7 7 7 7 7 7 j N ct0 0 o z ❑ ^. N (D ON 701 (0 00 0177 0)U)0)N M CO CO 7O 1.....r- CD CO M ON7 O m Cr)U) CO — CD N- M N CO O,- N 6010/01D1 ,- CD N N-U) N r CD— (D N O) N O 7 r Cl)6 N U) M N on 0)M O) Tr CO n(Na) O M CD O)M h O Ti W T- U)CO W O 07)O c- N M 7 U)U) (D CO 00 0)O (D N M V (M (M0 N-CO DO)O Ocn -co M 7 (On(O h a0 U)O CO (0 CD CO CD CO CO CO(D CO r r r n n N- n 0-r r W OD O0 OO O0 OD 00 00 00 a0 C O 0 m a r- u) o N_ 2@m oo ❑ w ° . e a c E o F WO. o E U U N N CC E N C O Cj 0 N N N 0 • V o co 7 7 7 7 7 N < < < < < < d a 0 T 0 >.0 TO >.0 TO T v 3 N 3 N 3 N 3 N 3 N 3 N y ^ H 3 H j H 3 H H H 3La p 0 d � d W P-=.(0d CO d(d O) N O r to7V' o o 0 0 0 0 0 0 H H H H a H a a a a N L . 7 7 L "o .—E 1 >- >- 11 J J 0 z za � O O 0 ., H z 1 O 0 01 N o 0 + 0 � z z o E z 0 O 6 2 2 U• 2 Cu' 0 co-J COU ) l J J CO Cu V) CO -J CO W O O O O 0 O Cl) O 0 0 O O O j O O OO O O U) M M co c7 co co To U cC 0 • 0 0 o 0 O O 0 z 0 0 0 0 0 o a O c0,) O O O O Q cc I- CI_a U E Cl) I c c c c p W ,41L COCO fn CO U) j U U V U U H Q H Q Q Q Q N C a) 0 C) H O E N 8 (OD 0 OM0 d LO u7 In n Cr) O C C- V 4 CU (D 0 Cl) co co co co CO O E co co N- co CO co L H C .O a 7 --- O N O (OD O 2 o in CC) in n CC) E o v v ui C c] co co co co co co N. co a • v AP O C- N- co W N H 4) 0 d E 0 E E o = 0 O RECEIVED ii „ten sr,..17. UNITEDOATES ENVIRONMENTAL PROTECTION AGENCY 0 X'' 0 4 2 015 REGION 10 1200 Sixth Avenue, Suite 900 AOGGC % . I Nor, •.7 Seattle, Washington 98101-3140 pRoISC' APR 29 2015 OFFICE OF COMPLIANCE AND ENFORCEMENT Reply to: OCE-082 CERTIFIED MAIL - RETURN RECEIPT REQUESTED Mr. Alex.V. Podust Drilling Engineering Supervisor ExxonMobil Company P. O. Box 190267 Anchorage, Alaska 99519-0267 NNEV g Re: Under,ground Injection Control (UIC) Program SCA6.141,7 jo _ Class I Well PTDW1 under Permit Number AK-lb 15-A Interim Approval to Inject into UIC Class I Well PTDW I Point Thomson Unit, Alaska Dear Mr. Podust: The U.S. Environmental Protection Agency, Region 10 (EPA), has witnessed portions of the well construction and reviewed tests conducted on ExxonMobil Class I Well PTDW I. Based on the on-site observations and recent results of the tests, the EPA grants interim approval to ExxonIV1obil under EPA UIC Permit number AK-11015-A to commence injection at Point Thomson Well PTIDW1. The EPA looks fonvard to receiving the completion report within 30 days. After all permit requirements are fulfilled including the submittal of the completion information with the -Completion Form For Wells (EPA Form 7520-9)"per permit Part II C.1.), then EPA will review the completion report and make an adequacy determination for final approval for injection into the UIC Class I well at Point Thomson. We appreciate the cooperation of your staff during, the well construction process. If you should have any questions,please do not hesitate to contact Thor Cutler of my staff at 206-553-1673 or at cutler.thor(ibepa.LIOV. Sincere}31, ,-- '--- ..... ..";/../ ' n j".• ..---- ,......-11 , Edward J ',.,owalski Director cc: Marc Bentley ADEC Division of Water/Wastewater Discharge Permits Chis Wallace AOGCC V - _ 2_ Li _ 2,0(o • • RECEIVED UNITED STATES ENVIRONMENTAL PROTECTION AGENCY MAR 0 2 2 015 REGION 10 1200 Sixth Avenue, Suite 900 AOGCC 9 No W. Seattle,Washington 98101-3140 •z• 41. PRO FL . 2 5 20-15 OFFICE OF COMPLIANCE AND ENFORCEMENT Reply to: OCE-082 CERTIFIED MAIL-RETURN RECEIPT REQUESTED Mr. Brian E.Reep Safety,Security,Health and Environmental Manager ExxonMobil Company SCANNEV £ 7 P.O. Box 190267 Anchorage,Alaska 99519-0267 Re: The U. S. Environmental Protection Agency(EPA)Determination: ExxonMobil(EM)fulfillment of the requirements for Financial Assurance(FA) for Well Plugging and Abandonment(P&A)per the 40 Code of Federal Regulation(C.F.R.)§ 144.63 and Part I G of the Underground Injection Control (UIC)Permit AK I I015-A(the UIC Permit), Point Thomson Unit(PTU),Alaska. Dear Mr.Reep: EPA has received FA documents from EM including a surety bond guaranteeing payment into a trust fund and a standby trust agreement for P&A of an UIC Class I non-hazardous disposal well at PTU,Alaska. Based on the receipt of the FA documents and a review of the FA documents by a member of my staff, EPA has determined the requirements per 40 C.F.R. § 144.63 and Part I G(Financial Responsibility)of the UIC Permit are successfully fulfilled. Following well construction, interim approval to commence injection may be attained upon demonstration of well mechanical integrity as described in the UIC Permit. Upon fulfillment of all requirements including the submittal of the well completion information using the "Completion Form For Wells(EPA Form 7520-9)"per Part II C.1. of the UIC Permit,then EPA will make an adequacy determination for final approval to commence injection in the Class I well at PTU,Alaska. If you have any questions or concerns,please feel free to contact Thor Cutler of my staff at(206)553-1673. Sincerel, 0- Ed‘va:/Kowalskilf Director cc: Marc Bentley ADEC Division of Water/Wastewater Discharge Permits 'Chris Wallace AOGCC • 41 L OF 1.4, 0,1** I//j„. tv THE STATE Alaska Oil and Gas �'.. :;; ofALc KA CO2SePVat1®n Commission Witt __ 333 West Seventh Avenue = GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 O''ALASV' Fax: 907.276.7542 www.aogcc.alaska.gov Jason Burdette Drill Team Engineering Manager ExxonMobil Corporation P.O. Box 196601 Anchorage, AK 99519-6601 Re: Point Thomson Field, Sagavanirktok Formation, PTU-DW1 ExxonMobil Corporation Permit No: 214-206 Surface Location: 950' FSL, 1055' FEL, SEC. 34, T1ON, R23E,UM Bottomhole Location: 2337' FNL, 1405' FWL, SEC. 3, T9N, R23E, UM Dear Mr. Burdette: Enclosed is the approved application for permit to drill the above referenced service well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, I� Daniel T. Seamount, Jr. Commissioner DATED this /C+ day of February, 2015. II RECEIVED. 0 • STATE OF ALASKA DEC 16 2014 ALASKA OIL AND GAS CONSERVATION COMMISSION ®�� PERMIT TO DRILL 20 AAC 25.005 la.Type of Work: 1 b.Proposed Well Class: Development-Oil 0 Service- Winj 0 Single Zone 9 • lc.Specify if well is proposed for: Drill 0• Lateral 0 Stratigraphic Test 0 Development-Gas D Service-Supply 0 Multiple Zone L Coalbed Gas Li Gas Hydrates ❑ Redrill❑ Reentry❑ Exploratory ❑ Service- WAG 0 Service P;Or 9 • C/css 1 Geothermal Li Shale Gas ❑ - 2.Operator Name: 5. Bond: Blanket 0 Single Well 0 11.Well Name and Number: Exxon Mobil Corporation Bond No. 8302 42 06 PTU-DW 1 3.Address: 6.Proposed Depth: 12.Field/Pool(s): PO Box 196601,Anchorage AK 99519-6601 MD: 8839'RKB TVD: 6921'RKB ' Point Thomson/Sagavanirktok Formation 4a. Location of Well(Governmental Section): 7.Property Designation(Lease Number): Surface: 950'FSL,1055 FEL,Sec.34,T1ON R 23E,UM • SL:ADL 047559; BHL:ADL 047570 Top of Productive Horizon: 04 l.- 8.Land Use Permit: 13.Approximate Spud Date: 1047'FNL,2202 bEt,Sec.3,T9 N R 23E,UM • LO/NS 12-002 Feb.23,2015 Total Depth: r0iI- 9.Acres in Property: 14.Distance to Nearest Property: 2337'FNL,1405 EL,Sec.3,T9N R 23E,UM 2560 Acres 1,055'W of ADL 047558 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL:-42.0 feet • 15.Distance to Nearest Well Open Surface: x-468248.7 E y-5912923.0 N • Zone-ASP3 • GL Elevation above MSL:-8.6 feet • to Same Pool: None 16.Deviated wells: Kickoff depth: 1825 feet • 17.Maximum Anticipated Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 50 degrees Downhole: -3450 Surface: -2850 18.Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 42" 20"x 34" 129.5# X-52 Welded 120' Surface Surface 155' 155' 664 sx Arctic Grout 12-1/4" 9-5/8" 53.5# L-80 VAM TOP KX 4900' Surface Surface 4900' . 4389' - 3,238 sx Arctic LiteCRETE,441 sx Class G 8-1/2" 7" 26# 1%Cr L-80 TSH 563 8839' Surface Surface 8839' - 6921' ' 283 sx LiteCRETE,291 sx Class G N/A 4-1/2" 12.6# 1%CrL-80 VAM TOP 6990' Surface Surface 6990' 5733' -fKbfot.,:).. N/A 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( Drilling Program 0 Time v.Depth Plot 0 Shallow Hazard Analysis 0 Diverter Sketch0 Seabed Report © Drilling Fluid Program 0 20 AAC 25.050 requirements Q 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct. Contact Email Printed e Jason dett Title US Drill Team Engineering Manager Signature _•f Phone (work)832-624-9170(cell)713-203-3312 Date December 11,2014 Commission Use Only Permit to Dri API Number: Permit Appro I See cover letter for other Number: .z/� 50 J ��a J'� (Date: I I requirements. Conditions of approval: If box is checked,well may not be used to explore for,test,or produce coalbed m}thane,gas hydrates,or gas contained in sha_lee Other: 4 00 D /5, /J r 3Q d �S� Samples req'd: Yes 0 No[d Mud log req'd:❑yes Lye No 34 ~ 5 0 H2S measures: Yes 0 No Ni Directional svy req'd:I�Yes 0 No 7 AO P 36 C yc.-& Spacing exception req'd: Yes❑ No li Inclination-only svy req'd:0 Yes i( No * A/ftrn4 Pa C pAcc.a ...04,,,� ii4J-P /L., ZdA/c- zS. '112 CO '+- U t spo so-t_. /i ectz rnn o oas +o b in accordance to CLasS I yfei'.n ct i't k. T 015 A ` / APPROVED BY Approved by: \---,i. ,/ COMMISSIONER THE COMMISSION Date: i01 ORIGINAL 74 ZZJs „7„,s ,).;sz Submit Form and Form 10-401(Revised 10/2012) This permit is valid for 24 months from the date of approval(20 AAC 25.005(9)) Attachments in Duplicate rniR °I.-It-15 �o°I.-It-15Ii (1-(19(- C-ti J ,2/4-/2o1S' • zit/ - -2.c,(0 • RECEIVED 0.s,, UNITED STATES ENVIRONMENTAL PROTECTION AGENCY JAN 29 2015 $zs,, • T) REGION 10 1200 Sixth Avenue, Suite 900 AOGCC 37 ...a tO, a ''81 rot' Z T Seattle,Washington 98101-3140 so e 4,, • 44.pRolse• JAW 2 6 2015 OFFICE OF COMPLIANCE AND ENFORCEMENT Reply to: OCE-082 CERTIFIED MAIL-RETURN RECEIPT REQUESTED Mr. Brian E. Reep Safety, Security, Health and Environmental Manager ExxonMobil Company SCANNED P.O. Box 190267 Anchorage,Alaska 99519-0267 Re: ExxonMobil(EM)Waste Analysis Plan(WAP)completion determination by the U. S. Environmental Protection Agency(EPA) for Point Thomson Unit(PTU)Waste Injection Facility (WIF) Underground Injection Control (UIC)Class I Permit AKI1015-A,Point Thomson Unit, (PTU),Alaska. Dear Mr, Reep: The U.S.Environmental Protection Agency(EPA) has received your correspondence and reviewed the attachment titled"ExxonMobil Point Thomson Waste Injection Facility Waste Analysis Plan Class I Non- Hazardous Underground Injection Control Disposal Well Waste Analysis Plan"received on January 9, 2015. Based on the information you submitted and a review of the WAP by a member of my staff, EPA has determined the EM WAP fulfills the requirements of Part I.E.9.fof the UIC Permit AK1I015-A. Following the construction of the well,interim approval to commence injection in the Class I injection well may be attained upon fulfilling demonstration of mechanical integrity portion of the permit as described in the permit AK1I015-A Part II C.3, After all well construction steps are complete and permit requirements are fulfilled including the submittal of the completion information with the"Completion Form For Wells(EPA Form 7520-9)"per permit Part 11 CA.). then EPA will make an adequacy determination for final approval for injection into the UIC Class I well at Point Thomson. If you have any questions or concerns,please feel free to contact Thor Cutler of my staff at(206)553-1673. Sincer4f „dr k ,01011'' asod Edward J.,*owalski Director cc: Marc Bentley ADEC Division of Water/Wastewater Discharge Permits V Chris Wallace AOGCC r ExxonMobil Development Cony Brie peep Post Office Box 190267 SSH& ai lager Anchorage,Alaska 99519-0267 � �� Point Thomson Project 907 564 3617 Telephone ED 907 743 9809 Facsimile DEC 16 2014 AOGCC . E onMobil December 16, 2014 Development ER-2014-OUT-460 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Form 10-401 with original signatures for ExxonMobil's Application for Permit to Drill (AOD) PTU-DW1 Dear Commissioner Foerster: Attached please find two copies of Form 10-401 with original signatures for ExxonMobil's Application for Permit to Drill (APD) PTU-DW1 which was couriered to your office Dec. 12, 2014. Please contact Alex Podust (907-334-2978; alex.v.podust@exxonmobil.com) or Steve Calder (907-564-3787; steve.calder@exxomobil.com) if you have any questions. Sincerely, L.._ . � /2ti;&'LeN-- For and On Behalf of Exxon Mobil Corporation BER:sc:li Attachments: Original Signature Form 10-401, Application for Permit to Drill PTU-DW1 (2 Copies) An ExxonMobil Subsidiary • s Schwartz, Guy L (DOA) ori > From: Calder, Steve/C <steve.calder@exxonmobil.com> Sent: Thursday,January 29, 2015 4:08 PM To: Schwartz, Guy L(DOA) Cc: Podust,Alex V; McGovern, Ben T; Morales, David C; Rullman,John D Subject: Supplemental Information for PTU-DW1 APD Attachments: PTU-DW1_Drilling Program_revl.pdf;AOGCC BOP Table.pdf; Nabors 27E Diverter Line Deviation Sketch.pdf; Disposal Well Time v. Depth.pdf;5.5in DP GPDS55.pdf;4in DP XT-39.pdf;AOGCC FIT Procedure.pdf Hello Guy, Attached is the Drilling Program for PTU-DW1; this supersedes the one provided previously. It includes additional information in response to your review of the APD. In addition,also attached per your request are the following: • Detailed FIT Procedure • BOP Table(inc. Ram Configurations) • Sketch of the Nabors 27E Diverter Line Deviation • Updated Time v. Depth Plot • 5-1/2"GPDS-55 Drill Pipe Specs • 4"XT-39 Drill Pipe Specs Note that the 5-1/2" GPDS-55 drill pipe will be used for drilling of the 12-1/4" and 8-1/2" hole sections as well as for the 9-5/8"surface casing cleanout run.The 4"XT-39 drill pipe will be used for the 7" production casing cleanout run. Let us know if there is anything else you need. Regards, Steve Calder Environmental/Regulatory Point Thomson Project Consultant to ExxonMobil Office(907)564-3787 Cell (907)351-4538 steve.calder@exxonmobi I.com 1 • C 0 4-• 1 CO •> a) CIJ 3 o D E to� L CU "0 •__ a IV m 3 o -• �1 r4 -0 v L t cu a1 > u a1 no o L = -. .. f tlntlm e 41 o c --41,7 1..... rr) — 0 t it$.- A 0 _X _ 10110176 -) T) 1it - Il ,..____ . 4-) d .. lEtrir, ,_ �� N S a -Ar- 9 ... / = p a1 v - J L 0 CU L h }' p111 N i aA � � O. a L. N _0 OD Co a O O XI c -C Q CO u CO C .- _ = m Z C 'L 'L c c0 0 j t"-j. � . `- v N .CD L > > a) o0 73 O 0 • I ExxonMobil Development Company Drilling Proposed Drilling Program WELL NAME: PTU-DW1 FIELD: Point Thomson SURFACE LOCATION: x = 468248.7 ft E; y = 5912923.0 ft N; NAD 27 ASP3 PROPOSED BHL: x = 465319.5 ft E; y = 5909532.2 ft N; NAD 27 ASP3 TOTAL DEPTH: 8,839' MD/ 6,921' TVD RKB RIG: Nabors Alaska Rig 27E KB ELEVATION: "'42.0' above MSLi# fr 2/.17GL ELEVATION: "'8.6' above MSL EST. SPUD DATE: —23 February 2015 EST. RIG OPER. DAYS: —56 days OPERATIONAL SUMMARY 1. Access to the wellsite, site preparation, and installation of the cellar and conductor will be completed in advance of the rig move. 2. Skid rig over 20" x 34" conductor in well slot 1. 3. Install 21-1/4" 2000 psi WP diverter system and function/ pressure test in accordance with AOGCC regulations and ExxonMobil well control standards. NOTE:48 hr advance notice is required for the diverter test. Diverter line deviation is approximately 10°as indicated in the supplemental schematic 4. Pick-up 12-1/4" directional drilling assembly. 5. Drill out 20" x 34" conductor shoe with ± 10.0 ppg DrilPlex AR water-based mud system. • • NOTE: DrilPlex AR is a mixed metal oxide(MMO)highly shear thinning water-based mud system supplied by MI Swaco and commonly used in permafrost sections across the North Slope 6. Drill vertically through the Permafrost interval and kick-off directionally at ± 1,825' RKB. Drill to ± 4,900' MD/4,389'ND RKB. 7. Circulate hole clean and wiper trip if dictated by hole conditions. POOH. 8. Run 9-5/8" surface casing to depth. Circulate and condition mud in preparation for cement job. NOTE: Ensure that the casing to drill pipe crossover sub and full opening safety valve(FOSV)are made-up and accessible on the rig floor prior to commencing casing running operations.The FOSV should be in the open position,and the FOSV wrench should also be accessible on the rig floor 9. Pump the planned single stage cement job using a lead/tail slurry system. Wait on cement. 10. Rig-down diverter system and install 11" 5000 psi WP wellhead A-Section (casing spool). 11. Install 13-5/8" 10,000 psi WP BOP stack and choke manifold system. 12. Pressure test BOP stack and choke manifold system in accordance with AOGCC regulations and ExxonMobil well control standards. NOTE:48 hr advance notice is required for all BOP tests. Initial BOP test will be conducted to a test pressure of 5,000 psi(WP rating of A-Section flange).Subsequent BOP tests will also be conducted to a test pressure of 5,000 psi as per ExxonMobil well control standards. Refer to the supplemental BOP table for ram configurations 13. Pick-up cleanout assembly and conduct a dedicated cleanout run inside 9-5/8" casing in preparation for ultrasonic cement evaluation log (USIT or equivalent). 14. Rig-up wireline equipment. Run ultrasonic cement evaluation log (USIT or equivalent) on wireline to confirm adequacy of cement. Rig-down wireline equipment. 15. Pick-up 8-1/2" directional drilling assembly. Run in hole to the top of cement and circulate bottoms-up in preparation for casing test. 16. Pressure test the casing to 4000 psi for 15 min. A�� NOTE:4000 psi represents approximately 50%of the rated internal yield (burst)capacity.The maximum anticipated surface pressure(MASP)while drilling the 8-1/2"hole section is±2,850 psi based on a 14.4 ppge fracture pressure at the 9-5/8"casing shoe(4,389'TVD RKB)and a 0.1 psi/ft methane gradient to surface. By comparison,the maximum anticipated downhole pressure(MADP)is±3,450 psi based on a"high side"pore pressure prediction of 9.6 ppge at planned well TD(6,921'TVD RKB) 17. Displace wellbore to± 12.1 ppg VersaClean non-aqueous mud system. • 18. Drill out shoetrack and clean out rathole. Drill a minimum of 20' of new formation and prepare to conduct a formation integrity test (FIT). Perform FIT to a pre-determined pressure limit of± 14.0 ppge as per the supplemental FIT procedure. NOTE:This test pressure is based on the maximum anticipated equivalent circulating density(ECD)at the 9- 5/8"casing shoe while drilling the 8-1/2"hole section.Note that this test pressure is below the predicted fracture pressure of 14.4 ppge. 19. Directionally drill to ± 8,839' MD/6,921' TVD RKB. 20. Circulate hole clean and wiper trip if dictated by hole conditions. 21. Circulate and condition mud in preparation for wireline logging. POOH. 22. Rig-up wireline equipment and conduct open-hole logging program (Sonic/ Caliper). Rig- down wireline equipment. 23. Change out the upper variable bore ram (VBR) from 3-1/2" x 5-7/8" to 4-1/2" x 7-5/8" for the 7" production casing and pressure test to 5000 psi as per ExxonMobil well control standards. NOTE:48 hr advance notice is required for all BOP tests. Refer to the supplemental BOP table for ram configurations 24. Run 7" production casing to depth. Circulate and condition mud in preparation for cement job. NOTE: Ensure that the casing to drill pipe crossover sub and full opening safety valve(FOSV)are made-up and accessible on the rig floor prior to commencing casing running operations.The FOSV should be in the open position,and the FOSV wrench should also be accessible on the rig floor 25. Pump the planned single stage cement job using a lead /tail slurry system. Wait on cement. 26. Rig-down BOP stack and install 7-1/16" 10,000 psi WP wellhead B-Section (tubing spool). 27. Install 13-5/8" 10,000 psi WP BOP stack and choke manifold system. 28. Pressure test BOP stack and choke manifold system in accordance with AOGCC regulations and ExxonMobil well control standards. NOTE:48 hr advance notice is required for all BOP tests.BOP test will be conducted to a test pressure of 5000 psi as per ExxonMobil well control standards. Refer to the supplemental BOP table for ram configurations • S 29. Pick-up cleanout assembly and conduct a dedicated cleanout run inside casing in preparation for ultrasonic cement evaluation log (USIT or equivalent). Rack-back cleanout assembly. 30. Rig-up wireline equipment. Run ultrasonic cement evaluation log (USIT or equivalent) on wireline to confirm adequacy of cement. Rig-down wireline equipment. 31. Run in hole to bottom with cleanout assembly and displace wellbore to 9.7 ppg NaCI completion brine. NOTE:9.7 ppg NaCI completion brine density is based on a 200 psi overbalance over the"best estimate"pore pressure prediction of 9.1 ppge at the top of perfs(6,793'TVD RKB) 32. Pressure test the casing to 4000 psi for 30 min. POOH. NOTE:4000 psi represents approximately 50%of the rated internal yield(burst)capacity and is also the SAPT /MITIA test pressure requirement stipulated by EPA. 33. Pick-up tailpipe and packer assembly and run in hole on 4-1/2" production tubing to ± 6,990' MD/5,733' TVD RKB (± 50' MD above top of Injection Zone) NOTE: Initial perfs are planned from 8,639'MD/6,793'TVD RKB to 8,659'MD/6,805'TVD RKB 34. Space out and land tubing hanger in wellhead. 35. Reverse circulate insulating packer fluid (IPF) down to packer depth. Shut-in annulus to prevent U-tubing effect due to lightweight packer fluid. NOTE:The planned IPF is ISOTHERM,which is a viscosified non-aqueous fluid system supplied by MI Swaco. The viscosity complex is achieved through a proprietary polymer blend 36. Drop ball/ rod assembly to land out in plug receptacle in tailpipe X profile. 37. Pressure up on ball /rod assembly to 3000 psi to set packer. Bleed off pressure from tubing. 38. Run in hole with slickline to retrieve ball / rod assembly and plug receptacle from tailpipe X profile. POOH. 39. Bleed off pressure from annulus side. 40. Rig-down BOP stack and install 4-1/16" 5000 psi WP tree. 41. Pressure test tree to 5000 psi for 15 min. Rig-down slickline equipment. 42. Pressure test tubing and tubing-casing annulus to 4000 psi and 3500 psi, respectively, for 30 min each test as part of EPA required SAPT/ MITIA. • i NOTE:The pressure chart for the tubing-casing annulus test(3500 psi @ 30 min)will be submitted to AOGCC 43. Rig-up wireline equipment and 2-7/8" perforating guns. NOTE: Perforating gun size may be subject to change 44. Run in hole through tubing to ±8,639' MD/6,793' TVD RKB. Correlate to confirm on depth. 45. Apply 200 psi surface pressure and perforate interval from ±8,639' MD/6,793'TVD RKB to ± 8,659' MD/6,805' TVD RKB. NOTE: Perforation interval is still being evaluated and may be subject to change 46. POOH with spent perforating guns on wireline. 47. Conduct EPA required fluid movement log (RST or equivalent). Rig-down wireline equipment. 48. Conduct EPA required initial step-rate test and pressure fall-off. • • ^0 \ k\ 0 E 2 0 Wf ~ G _ r--- ,- 0� 0 � r o = r 1113 m u, 1� 0 g00 0 \ @ 2F _«2 2 § � �© / no CO � / ƒ 9 \ Ni ui,,.... o �f , m 2 ~ - \ ) k a am 33N � fpup_ [ 0 nsliti - - -� so _ - - ] E e — as co = (13 � \ _ 2D'i C ] § 11111 k \ � \ a } \ / ° 0 0 £ c § & @comm ) 0) C31 C31 Cs1 41 \ 222 & 2 o co U7 N � - - - - a » ° * _ r / c.) 00 00 000 C000C10 ca ■ eeeee oo co C2 7 —= e 2 \ / 4Q | Q // \// 0 - 3E2 ` e $ ° � _ _ Elf . k - _) // j \ )_ \ E © _ y&2E 2 � � � � ) ] \ e Eb - q a2a�� .2 .5. £ \ \ \ � \ 2 \ o ` � ■ 20 - ee - L. % k0- _ _ = e = = k \ = 5 - § a { / \ ) a To/ / / § ! k \ LI / . / - ) ® ; EE 00 § - - } \ $ ) oo � _ § a ! ; 2 i ) © \ c - _ � & ! To ) / \ 2 a § ] > / / � E \ - co | LU0 0 0 LI - � 2 CO E \ _ a ! o 0 \ i § • 0 • • � F 014C 119 o O o e i o Irm !1�/ o 0 0 0 i o '0 1-- 0 O t _0 o '� 2 o O d C o-- 0. 0. O o 'a 2 = s U) L vO . CI is I Cr co Lo V CZ C 0 0 U .a -J 2 - o o �E 00 0 'L O N L O. V M U o .d 0 0 a co .c o Q n O W o • I- I o 0 N W o oN N 3 II r r ee 8 110 Oo 0 . 1- CZ o LL O = A O In 0 U Lo C CI) CO O - t 1 1 • 1 0 • C OOO O O a) O O O ~ 4 a- O O o O O O o O X O o O O O O O O O o O O O o • QO a N o cc O N O 1-• r` .E (sqi) peol ansual pauddv • • N CD O- Q N N E W O CO CO C (015 - M D c0 W .O O In0 o N O E E N O U L c O O CD Oc X O O (0 co 2 2 — • • I oco o c° O u7 Cl)1c v+ 0 O Q r 0 0 • X 00 Q ~ Q Q ti co co �+ F • = V o co O O O O O O O O N- co 0 co 0 0 0 co a Imo co o CO o o 0 0 CL (sgl-}.j) 416ua.gs leuoisaoi 0 i • • • FOR REFERENCE ONLY G- 1450 Lake Robbins Drive Suite 600 The Woodlands,TX 77380 U.S.A. Phone:281-297-8500 `'w• Fax:281-297-4525 Toll Free:800-231-0283 GltlfTi1'''''R s r (..8. i- .)t.. Drin Pipe Per€ormande.Characteristics:Sheet.b : ,::: >: Minimum make=up it based•on shoulder separation:caused by bending • • •••0119.440 and weight-4 1570;IU ...-. I?Ipe Grede:'S-135': • :•::::-:::::::::::::::::.'2.-::::::•:: ........ • ..................... :Range:,2.:::•::>::.:.. . •. .. ... . '.`.. .•... Tool Joint 4 875 X2:5631fT39 Pipe ::.4!'15:7.04.1 Dimensional Data New Premium BoxOD(in) 4.000 3.848 ''� Wall thickness(in) 0.380 0.304 _+ ID(in) 3.240 3.240 Cross sections 4.322 3.385 Cross sections 12.566 11.629 �! Ilaar•dfncing Cross sections 8.245 8.245 III!I Section moduli 3.578 2.782 Box Tong Space Polar section rr 7.157 5.564 umml1 i Performance Data New Premium Elevator Shoulder 1 Feld tine Torsional strength(ft-lbs) 46,500 36,100 Tensile strength (lbs) 583,400 456,900 i I'ipe 80%Torsional strength(ft-lbs) 37,200 28,900 i Pressure capacity(psi) 22,444 20,520 Collapse capacity(psi) 23,213 _ 18,593 1 I :. :'Toal Saint . - :4.875 X 2.503:XT39 ' . j Dimensional Data External Upset OD(in) 4.875 ID(in) 2.563 Internal Upset I Pin tong length(in) 10.0 Box tong length(in) 15.0 ` 'Fool Joint Performance Data Pin'Tong Space Torsional Strength(ft-lbs) 37,000 ``---._--- Max Recommended Make-up Torque(ft-lbs) 22,200 Min Recommended Make-up Torque(ft-lbs) 12,400 Balance OD(in) 4.99 Tensile strength(lbs) 729,700 ! n' li Tool joinUDrill pipe torsional ratio(New pipe) 0.80 - - Tool joinUDrill pipe torsional ratio(Prem pipe) 1.02 : ==-- Min OD for premium class(in) 4.625 • -= F Drill pipe assembly with eXtremeTM:Torqua:#ool.joint • Adjusted weight(lbs/ft)• 17.20 Approximate length(ft) 31.64 Fluid displacement(gal/ft) 0.263 Fluid capacity(gal/ft) 0.412 Drift size(in) 2.438 JC 3/3/2007 • • 0 di Q N C N " ..4 CO. 00 G o0 0i oo N in 0.0 N � >- ~ IOC O O ateco . O -J C > 0 0 al Oi 01 Q O a+ • Lr, O M M M +I v V' W W W oo 0 U 4! Z C O IO G a E Ln OI 4 N c c,- C a Z. N °/ I N N E _ o _ ai u m _ % o o 3 I v `t o v I N W 00't N = `O .- O 3 iv Q '0 n - t a 0 u Ce Q.E O Q ("I o) .-i CO w d = ,x, 00 v3 - / > L) V w N z E CO / E no C / . / N U i^ 0— / O IINes / d co N / co co V\1 / O o, 0. d I N O Ca) s E o � Iu 0 v to !'I t Of O = I o 3 0 cc t .. J D r4 e.: ' . o 0009i 40 o o I ba Cc I YIH O O O O O O O O O O O O O O O m ch in to 0O N co Oi 0 .--i (an-aW I}) 4;daa • • • • SUPPLEMENTAL FIT PROCEDURE 1. Drill a minimum of 20' of new formation with 8-1/2" directional drilling assembly. 2. Pick-up above 9-5/8" casing shoe and circulate with rig pumps until system is clear of cuttings and "In" and "Out" mud densities are uniform to within 0.1 ppg. NOTE: Ensure that a calibrated,pressurized mud balance is used to eliminate possible measurement errors associated with an aerated drilling fluid 3. Rig-up cement unit and surface equipment to pump down drill string. 4. Pressure test surface equipment to 1,000 psi. NOTE: 1,000 psi represents approximately 2X the maximum anticipated test pressure 5. Close annular BOP or pipe ram. 6. Pump downhole at a constant rate of 0.25 BPM. Record and plot pressure vs. volume for every 0.25 bbl pumped. Continue pumping until recorded surface pressure reaches pre- determined pressure limit of± 450 psi.Test is not planned to be conducted to full leak-off. NOTE: 1) If the desired pressure is not achieved,continue to pump at 0.25 BPM to collect an additional three data points(0.75 bbl past deviation from straight line) ' 2)High seepage may complicate interpretation. If this is the case,consider spotting a seepage control pill to manage losses and re-perform the test 3)±14.0 ppge formation integrity at the 9-5/8"casing shoe is needed to the drill the 8-1/2"hole section. 14.0 ppge equates to±3,200 psi bottom-hole pressure(BHP)at the shoe(4,389'TVD RKB).Assuming a continuous hydrostatic column of 12.1 ppg VersaClean non-aqueous mud,this results in a required surface pressure of±450 psi. For comparison,the predicted fracture pressure at the shoe is 14.4 ppge 7. Shut-down cement unit pumps and close pump isolation valve in order to monitor pressure decline. 8. Record initial shut-in pressure (ISIP) 10 seconds after shutting-in pumps. NOTE:The initial vertical drop in pressure occurs due to the loss of pumping friction 9. Record pressure vs. time after ISIP at one minute intervals for a minimum of 10 minutues after shutting-in. • $ NOTE: If the pressure decline continues to be significant after 10 minutes,continue to hold and record pressure until it starts to stabilize.This rarely requires more than 15 minutes 10. Bleed-off remaining pressure. Measure and record return volume. 11. Rig-down cement unit and surface equipment in preparation to drill ahead with rig pumps. NOTE: FIT test pressure is based on current engineering data and may be subject to change o 0 cc cc cL ca co co O ' O o0 > > 00 > > 00 > > (tea N Ln N N in t./) N N in Ln N N L ' U. \ \ ' LL \ \ ' LL \ \ Ln J i ri N J r'I rl N J r•'1 r'I dA X a) Ll) Ll•) X 4J Ln L11 X QJ Ln Lf) C N w X X N 4- X X N w X X 0 -C N N ‘ 1 CO ?Ni N -C N N E m 'A %-I i-1 4 N r l i-1 4 N c-1 -i I L I I L I I ca a) m m a) c n m a) m m r H H C Hrn � H H t s Ln Ln Ln E E E E E E 0- O 0- o 0- 0 0- 0 0- 0 0- o o +• o +, o 4- o +J o � o 4-' LU F' CO ~ m ~ CO ~ m ~ CO m J c E , E I E , E , E I E I CO O < to c ca C CD Ca co u a) cc Cl) cc a) CC (1) CC Cl) CC a) CC CI. 3 7oa, 7oa) .0 a, -T:, .70a) E v co wN( 0 o 0 o 0 o n 0 0 o 0 o J I.L L Q L Q L Q L Q L 0 L 0 Q a) L L CD 4-J L a) L H o- a, 3 a, a. a, 3 a, C- a) 3 a, W = 0- JO p = Q JO 30 D Q —1 0 C D J D J D J LU —I CL O. vl M CD ttO N V c O C .3 0 7 = I— C U C 0 0 C - 0 O u0 U rt) 1:30- L QJ oto a ec a a p - C a s N +� _ N O V) ob E 4 c q,o a) CO LL C U 06 C > 2, Lb.0C III! C3 co V) C m > C 7 ill CC 1- 0 z RECEIVED STATE OF ALASKA DEC 12 2014 ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL AOGCC 20 MC 2..0055 la Type of Work' 1b.Proposed Wet Class: Development-O I 0 Service- Win) 0 Single Zone _ 1.: Specify If wells proposed for. DrIll G Lateral 0 Stratigraphic Test 0 Development-Gas 0 Service-Supp;y 0 Multiple Zone Coe bed Gas':;; Gas Hydrates Li Redr1l47Reentry(? Exploratory 0 Service- WAG 0 Service•Disp 0 GF athermal Shale Gas `L-i 2 Operator Name. 5. Bond: Blanket is Single Well 0 11.Well Name and Number Exxon Mobil Corporation Bond No. 8302 42 06 PTU-DWI 3.Address 6.Proposed Depth: 12.FieldWPool(s) PO Box 196601.Anchorage AK 99519-6601 MD: 8839'RKB TVD:6921'RKB Point Thomson/Sagavan rktok Formatpn 4a Local on of Well(Governmental Section): 7.Properly Designation(Lease Number): ,,- Surface- 950'FSL.1055 FEL,Sec.34,T10N R 23E,UM SL:ADL 047559, BHL:ADL 0475700 r' Top of Productive Horizon: 5B,Land Use Permit 13,Approximate Spud Date. 1047'FNL,2202 FEL.Sec 3.T9 N R 23E,UM LOINS 12-002 Feb.23,2015 Total Depth 9.Acres In Property: 14.Distance to Nearest 6rooertyr 2337'FNL,14u5 FEL,Sec 3.T9N R 23E,UM 2560 Acres 1,055'W of ADL 047558 4b Location of We I(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL:-42.0 feet 15,Distance to Nearest Wef Open Surface x-468248.7 E y-5912923.0 N Zone-ASP3 GL Elevation above MSL:-8 6 feet to Same Pool- None 16 Deviated we s. Kickoff depth: 1825 feet `17.Maximum Anticipated Pressures In psig(see 20 AAC 25.035) Maximum Hole Angle: 50 degrees Downhole -3450 Surface: -2850 18 Casing Program Spec ications Top Setting - t c - � - if q • Bottom Cement Quantity c f or sacks Hole Casing Wuighl Grade Coupiing Length MD TVD MD TVD (including stage data) 42" 20'x34' 129.54 X•52 Welded 120' Surface Surface 155' 4 155' 664 sx Arctic Grout 12.1/4' 9-5/8" 53.54 L-80 VAM TOP KX 4900' . Surface Surface 4900' 4389' 3,238 sx Arctic L IeCRETE,441 sx Class G 8-1/2" r 264 1";CrL-80 . TSH 563 8839' Surface Surface 9' 1 , 6921' 283 sx LIteCRETE 291 sx Class G N/A 4-1,Z' ' 12.64 4 1"r-Cr L-80 ,. VAM TOP 6990' Surface Surface 6990' 573'3' N/A a 1 19 PRESENT WELL CONDITION SUMMARY(Te be completed for Redrill a Re-Entry Operatic/ns) Total Depth MD in): `total Depth TVD(ft): Plugs(measured): Effect epth MD(11); , Effect Depth TVD(It) Junk(measured): -- - Casing Length Size ement Volume MD ND Conductor Surface `� \' / ' Intermediate - a Production r "'sr- Liner Perforation Depth MD(ft): Perforation De•. ND(ft): 20. Attachments: Property Plat Q BOP Sketch) Drilling Progra• Q Time v Depth Plot Q Shallow Hazard Analysis 2 Diverter Sketch Seabed Re'• D Drilling Fluid Program J 20 MC 25.050 requirements E 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing fs true and correct. Contact/ Email Printed I)Isme ason rderi ' Title US Drill Team Engineering Manager Signature ,, -. L---"�. `- )832-624-9170(ceH)713-203-3312 Dale December 11,2014 t Commission Use Only Permit tDX R S/ API Number. -Permit Approval See cover letter for other . Num 50• Date: requirements. Conditions of approval: If box is checked,w I may not be used to explore for,test,or produce coalbed methane,gas hydrates,or gas contained In shales: Samples req'd: Yes Na 0 Mud log req'd: ;'Yes 0 No 10ther H2S measures: Yes P 1 No❑ Directional svy req'd:r)Yes 0 No Spacing exception req'd: Yes G No 0 Inclination only svy req'd: Yes 0 No APPROVED BY Approved by COMMISSIONER THE COMMISSION G;+k ORIGINAL submit Farm and Form 10-401(Revised 102012) This permit is valid for 24 months from the date of approval(20 AAC 25.005(g)) Attachments in Duplicate ExxonMobil Development COany Brie'Reep Post Office Box 190267 SSH&E Manager Anchorage, Alaska 99519-0267 Point Thomson Project 907 564 3617 Telephone 907 743 9809 Facsimile RECEIVED DEC 12 2014 December 12, 2014 EonMobil ER-2014-OUT-444 AOGCC Development Ms. Cathy Foerster, Chairman Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Application for Permit to Drill, PTU-DW1, Point Thomson Disposal Well Dear Commissioner Foerster: ExxonMobil is pleased to submit the attached application for a permit to drill a disposal well (PTU-DW1) at Point Thomson this winter season. The application is being provided with a scanned signature on Form 10-401 to allow review to commence and original signature copies of this form will soon follow. As you know, project construction has been progressing on schedule over the last two years and preparations are now underway for mobilization of the Nabors 27E rig to Point Thomson for a drilling campaign leading to startup of the field. Drilling of the disposal well initiates this drilling campaign which will also include recompletion of PTU- 15 and PTU-16 in 2015, and the drilling of West Pad Well, PTU-17, in 2015-16. We appreciate that AOGCC staff met with us on October 24th and December 10th to discuss the campaign and provide regulatory guidance. Please note, EPA issued UIC permit AK 11015-A for the Class I disposal well (PTU-DW1) and ExxonMobil has been coordinating closely with EPA on the well construction plan and testing procedures for the well. Associated with that permit process, EPA confirmed on February 3, 2003 and reconfirmed on Sept 5, 2009 a determination that there are no sources of underground drinking water (USDW) in the area. We request Commission approval for a waiver to set the packer greater than 200 feet above the injection perforations as shown in the attached program. We would appreciate your confirming,/ this is acceptable to the Commission. This will facilitate later perforating higher in the injection well if necessary Please contact Alex Podust (907-334-2978; alex.v.podust@exxonmobil.com) or Steve Calder (907-564-3787; steve.calder@exxomobil.com) or if you have any questions. An ExxonMobil Subsidiary • Cathy Foerster 2 December 12, 2014 Sincerely, For and On Behalf of Exxon Mobil Corporation BER:sc:li Attachments: Application Permit to Drill, PTU-DW1 (2 copies) UIC Permit for Class 1 Well, AK-1101 Confirmation of No Underground Sources of Drinking Water (USDW) ! i �'s'ATFS UNITED STATES ENVIRONMENTAL PROTECTION AGENCY REGION 10 b 1200 Sixth Avenue, Suite 900 Seattle,Washington 98101-3140 �4C PROZEG MAR '2F 2110 Reply To: OCE-127 CERTIFIED MAIL - RETURN RECEIPT REQUESTED Dale Pittman ExxonMobil Production Company P. O. Box 196601 Anchorage, Alaska 99519-6601 Re: Issuance of Underground Injection Control (UIC) Permit No. AK1 I015-A Point Thomson Field,North Slope,Alaska Dear Mr. Pittman: The U. S. Environmental Protection Agency, Region 10, (EPA) is issuing an Underground Injection Control permit for ExxonMobil Corporation(ExxonMobil) (Permittee), Point Thomson Field (PTF), North Slope, Alaska. The enclosed document authorizes the Permittee to inject non-hazardous industrial waste utilizing up to two (2) Class I injection wells at the PTF into the Sagavanirktok formations at a depth between approximately 5841 to 6716 feet true vertical depth(TVD). The Permittee will submit to EPA a completion report for the proposed Class I well(s) PT DW-l. The Permittee will successfully demonstrate the well(s) has(have)mechanical integrity and all other permit requirements have been met. Initiation of Class I injection activities are not authorized until approval is obtained from the Director of the Office of Compliance and Enforcement or an authorized representative. EPA received no requests for a hearing and no comments on the draft permit during the public comment period. This letter constitutes service of notice under 40 C.F.R. 124.19(a). The permit will become effective on the date indicated in the permit unless the Environmental Appeals Board receives a timely appeal meeting the requirements of 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. Sincerely, Edwar4 ' alski, Director Office of Compliance and Enforcement Enclosures cc w/enc: Shawn Stokes, ADEC Division of Water/Wastewater Discharge Permits Dan Seamount, Commissioner, AOGCC *Printed on Recycled Paper i • Page 1 of 22 ISSUANCE DATE AND SIGNATURE PAGE U.S. ENVIRONMENTAL PROTECTION AGENCY UNDERGROUND INJECTION CONTROL PERMIT: CLASS I Permit Number AK-1I015-A 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,ExxonMobil Corporation(ExxonMobil)(Permittee)is authorized to inject non-hazardous industrial waste utilizing up to two(2) Class I injection wells at the Point Thomson Field(PTF) located on the Alaskan North Slope (NS). Injection is authorized into the Sagavanirktok Formation at a depth between approximately 5841 to 6716 feet true vertical depth(TVD), in accordance with Title 40 C.F.R. § 144.33 and the conditions set forth herein. The Point Thomson oilfield lies approximately 50 miles east of the main Prudhoe Bay development area. The Thomson Sand geologic interval at a depth of approximately 12,500 feet TVD is a large high-pressure gas-condensate reservoir with a thin oil rim and is the second largest discovered gas resource on the North Slope. ExxonMobil is the field operator and major working interest owner at Point Thomson. The proposed disposal well(s)is(are) in an area where there are no underground sources of drinking water(USDWs)and this determination i was confirmed by EPA on February 3, 2003,and re-confirmed on September 25, 2009, for aquifers below approximately 1800 feet TVD (base of the permafrost). 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. Injection shall not commence until the Permittee has received written authorization to inject from EPA Region 10 Director of the Office of Compliance and Enforcement (Director). 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 ExxonMobil's Point Thomson Project Underground Injection Control(UIC) Class I Permit Application dated January 7, 2010. This permit shall become effective on March 10,2010, in accordance with 40 C.F.R. § 124.15. This permit and the authorization to inject shall expire at midnight, March 9,2020, unless terminated. Signed this^o I day of March, 2010. El EdwardJ rwalski, Director Offic• - •`Compliance and Enforcement U.S. Environmental Protection Agency Region 10(OCE-164) 1200 Sixth Avenue, Suite 900 Seattle,WA 98101 i S Page 2 of 22 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 4 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 11 FINANCIAL RESPONSIBILITY 12 PART II WELL SPECIFIC CONDITIONS 13 • Page 3 of 22 CONSTRUCTION 13 Casing and Cementing 13 Tubing,Packer and Completion Details 13 New Wells in the Area of Review 14 CORRECTIVE ACTION 14 WELL OPERATION 14 Prior to Commencing Injection 14 During Injection 15 Mechanical Integrity 15 Injection Zone 17 Waivers to UIC Program Requirements 18 Injection Rate and Pressure 19 Annulus Pressure 19 Injection Fluid Limitation 19 MONITORING 20 Monitoring Requirements 20 Continuous Monitoring Devices 20 Monitoring Direct Waste Injection 20 Alarms and Operational Modifications 20 REPORTING REQUIREMENTS 20 Quarterly Reports 20 Report Certification 21 REPORTING FORMS 22 • • Page 4 of 22 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 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 141 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 term 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 final permit application submitted by the Permittee on January 7, 2010, and supplemental material related to the"no USDW"ruling granted by EPA (dated February 3, 2003, and September 25, 2009). B. PERMIT 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. 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 • • Page 5 of 22 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 provisions 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. Information 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. 2. Penalties for Violations of Permit Conditions Any person who violates a permit condition is subject to a civil penalty not to exceed $37,500 per day of such violation. Any person who willfully or negligently violates • Page 6 of 22 permit conditions is subject to a fine of not more than$37,500 per day of violation and/or being imprisoned for not more than three(3)years. 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 Permittee 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 and 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 generated during remedial well workovers or well construction operations may be appropriately disposed in a Class I non-hazardous well [refer to 40 C.F.R. § 148.4(d)]. 7. Duty to Provide Information The Permittee 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 permit. The Permittee shall also provide to the Director,upon request, copies of records required to be kept by this permit. i Page 7 of 22 8. Inspection and Entry The Permittee shall allow the Director,or an authorized 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 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. Calculated flow rates may be used as a back-up system if the primary continuous injection rate monitoring device malfunctions. 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. c. Records of monitoring information shall include: (1) The date, exact place, and time of sampling or measurements; (2) The name(s) of the individual(s)who performed the sampling or measurements; • • Page 8 of 22 (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. Where applicable,the Waste Analysis Plan (WAP)submitted in association with the permit application may be incorporated by reference. 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 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. • . Page 9 of 22 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 permitted facility or changes in type of injected waste. 11. Anticipated Noncompliance The Permittee 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 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. 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. 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. i • • Page 10 of 22 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 or a 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 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." • • Page 11 of 22 F. PLUGGING AND ABANDONMENT 1. Notice of Plugging and Abandonment The Permittee shall notify the Director no later than 45 days before conversion or abandonment of the well. 2. Plugging and Abandonment Report The Permittee shall plug and abandon the well as provided in the Well Construction and Integrity portion(Section 7.5 and Exhibits 7-5 and 7-6)of the January 7, 2010,permit application,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 Director 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 Permittee 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. 4. Cost Estimate for Plugging and Abandonment a. The Permittee estimates the 2010 cost of plugging and abandonment of the permitted Class I well(s)to be approximately$900,000/well. Please refer to Section 7.5 and Exhibits 7-5 and 7-6 of the January 7,2010,permit 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. I • Page 12 of 22 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 ten(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(f) 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 the Permittee that the alternative demonstration of financial responsibility is acceptable. 4110 Page 13 of 22 PART II WELL SPECIFIC CONDITIONS A. CONSTRUCTION 1. Casing and Cementing The Permittee shall case and cement the well(s)to prevent the movement of fluids into strata 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 AlaskaJAOGCC Regulations(20 AAC § 25.412 and 20 AAC § 25.252). If primary cement returns to surface are not observed for the 9%inch surface casing cementing procedure, the Director or authorized 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) logs and pressure tests(leak off test and/or formation integrity test)will be run for both the 9% inch surface and 7 inch injection casings to confirm zonal isolation and verify casing integrity. The Permittee shall provide not less than ten days advance notice to the Director 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 representative shall be notified as to the nature of the change(s), so that approval is obtained from the Director or authorized representative in a timely manner 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 and Integrity portion(Section 7.0), (including integrity criteria) and the well schematics (Exhibits 7-1, 7-2 and 7-3) of the January 7, 2010, permit application. 2. Tubing, Packer and Completion Details The well shall inject fluids through tubing with a packer. Tubing and packer shall be installed in accordance with the procedures in Well Construction and Integrity portion (Section 7.0)of the January 7, 2010,permit application. The packer will be set no more than 100 feet TVD from the top of the injection zone which is anticipated at approximately 5841 feet TVD in PT DW-1. ! • Page 14 of 22 3. New Wells in the Area of Review EPA has set a half mile radius as the Area of Review(AOR) for this Class I UIC permit application. 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 development 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 Sagavanirktok Formation(proposed injection zone) to 200 feet TVD above the injection zone (reference is Exhibit 6-1 PTU-1 Type Log of the January 7, 2010, permit application). B. CORRECTIVE ACTION The applicant has identified no wells within the %2 mile radius of the planned disposal well(s) at the PTF site. The nearest well to the PT DW-1 disposal location is over one-half mile away as shown in Exhibit 5-2 of the permit application. Also, there are no transmissive faults, open well bores, un-cemented wells or other conduits within 1/2 mile at the proposed well location(s)that require corrective action in order to prevent fluids from moving above the confining zone. If the applicant later discovers that a well or wells within the AOR require(s) corrective action to prevent fluid movement, then the applicant shall inform EPA upon such discovery and provide a corrective action plan for EPA Director or authorized representative review and approval. 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. C. WELL OPERATION 1. Prior to Commencing Injection 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 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 Permittee has not received notice from the Director or authorized representative of intent to inspect or otherwise review the new, sidetrack or replacement injection well(s) within thirteen(13) days of receiving the • Page 15 of 22 COMPLETION REPORT in which case prior inspection or review is waived and the Permittee may commence injection. 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 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 EPA representative may be present. c. The Permittee has conducted an initial step-rate test and pressure fall-off(PFO)(or equivalent static reservoir pressure survey) and submitted a preliminary report to EPA that summarizes the results. 2. During Injection During drilling activities the well injection pressure, inner annulus pressure, injection rate,injection temperature and slurry density(when drill cuttings/solids are injected) will be monitored on a continuous basis. Should there be a need for direct injection at the wellhead, operators will check manifests and visually monitor onsite instrumentation. 3. Mechanical Integrity a. Standards The injection well(s) must have and maintain mechanical integrity pursuant to 40 C.F.R. § 146.8. 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 and tubing-casing annulus(inner annulus)will be pressure tested upon initial completion to 4000 pounds per square inch gauge(psig) and 3500 psig respectively, for not less than thirty minutes. Pressure shall show a stabilizing tendency. That is, the pressure may not decline more than ten percent during the 30-minute test period and shall experience less than one-third of its total loss in the last half of the test period. If the total loss exceeds ten 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 Page 16 of 22 stabilization(resulting from thermal effects). This initial standard annulus pressure test/inner annulus mechanical integrity test(SAPT/MITIA)will be required upon completion of the well and prior to the well first being placed on injection. Subsequently,the required test pressure for the SAPT/MITIA will be at least 2500 psig with the same pass criteria as outlined earlier over the 30-minute test period. The SAPT/MITIA will be required annually if the well is active and once every two years if the well is inactive. The SAPT/MITIA due dates may be extended up to three 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 SAPT/MITIA 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 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. 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 tests 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 representative. Copies of all logs shall be accompanied by a descriptive and interpretive report. Fluid movement/confinement logs will be run after completion of the well but prior to initiation of injection at start-up. After acquiring this baseline data, the fluid movement/confinement logs will be required every two (2) 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 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 representative. (3) Internal tubing inspection logs(pipe analysis logs, caliper logs,or other equivalent logs) shall be run once every two years while the well is active, or at the Director or authorized representative's discretion,to monitor condition,thickness and integrity of the downhole tubing. A three month Page 17 of 22 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. c. Terms and Reporting (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. (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 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 Sagavanirktok Formation(see Exhibit 6-1 Type Log PTU-1 of the January 7, 2010,permit application). ! • Page 18 of 22 5. Waivers to UIC Program Requirements As a result of the "no USDW"ruling for Class I injection within the Point Thomson Unit as defined and granted by EPA on February 3, 2003,and September 25, 2009, EPA is granting three(3)waivers of UIC regulatory program requirements as listed below: a. Compatibility of Formation and Injectate [40 C.F.R. §§ 146.12(e)and 146.14 (a)(8)]: Based upon the applicability of past injection studies,petrophysical logging data and existing rock and fluid samples (utilized in the fracture model studies)and successful injection practices into the same or 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. b. Injection Zone Fracturing[40 C.F.R. § 146.13(a)]: Class I injection wells are prohibited from injection at pressures that would initiate new fractures or propagate existing fractures within the injection zone. Based on the fracture modeling data submitted by ExxonMobil which indicated that under normal operating conditions the injection fluids will be contained within the proposed injection zone, EPA is waiving this prohibition, and instead allowing hydraulic fracturing so long as new fractures are not initiated nor existing ones propagated within the upper and lower confining zone(since solids placement can only take place above the fracture pressure of the receiving formation and there are no USDWs at this location). However,in no case shall injection pressure initiate fractures in the confining intervals above and below the injection zone. Authorized injection in the PTF Class I injection well(s)will be limited to the permitted Injection Zone between approximately 5,882 feet to 6997 feet MD (5881 feet to 7000 feet TVD)based on the Type Log PTU-1 (Exhibit 6-1 of the permit application). c. Ambient Monitoring Above the Confining Zone(40 C.F.R. § 146.13 (b): Since there are no USDWs(below the base of the permafrost at approximately 1805 feet TVD) in this area,no wells and no transmissive faulting within the '/z mile area of review(AOR),the formations are thick and laterally extensive, and the possibility of any waste penetration above the upper confining zone is extremely low, EPA is waiving the requirement to monitor the strata overlying the confining zone for fluid movement. However,external mechanical integrity demonstrations are required,to verify that all injected fluids are exiting the injection interval and that there is no flow behind pipe due to channeling etc. that would penetrate the confining zones [See Part II C.3.b (2)]. • 4 Page 19 of 22 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 Type Log PTU-1 (Exhibit 6-1 of the permit application). Although no surface injection pressure limit is specified in the permit, it should be noted that the wellhead working pressure limit of 5000 psi should not be exceeded at any time. Besides alarms and automatic shutdown controls,the wellhead assembly will include a surface safety valve(SSV) to provide additional safety. However, recognizing that the low pressure sensor(LPS)may trip inadvertently when the well is inactive or on intermittent injection, it is not required for the SSV to be functional at all times. 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 volume 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 representative, at the end of the first year of performance(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 x inner annulus or between the injection casing and surface casing(between the inner annulus x 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. In 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. • Page 20 of 22 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. Monitoring 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 pumping record must be signed by the person in charge. 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. b. Plans and specifications for the alarms shall be submitted to the Director or authorized representative prior to the initiation of injection. E. REPORTING REQUIREMENTS 1. Quarterly Reports The Permittee shall submit quarterly reports to the Director containing the following information: • Page 21 of 22 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. 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. 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 accordance with Part I.E.15., and submitted to the following address: UIC Manager,Ground Water Protection Unit U.S. Environmental Protection Agency(OCE-127) 1200 Sixth Avenue, Suite 900 Seattle, Washington 98101 • • Page 22 of 22 APPENDIX A REPORTING FORMS Enclosed are EPA Forms: 7520-7 APPLICATION TO TRANSFER PERMIT 7520-8 INJECTION WELL MONITORING REPORT 7520-9 COMPLETION FORM FOR INJECTION WELLS 411 • OMB No.2040-0042 Approval Expires 121112011 United States Environmental Protection Agency :.EPA Washington,DC 20450 Application To Transfer Permit Name and Address of Existing Permittee Name and Address of Surface Owner I i State County Permit Number ' Locate Well and Outline Unit on r- Section Plat•640 Acres . i 1 Surface Location Description N I I I 'I 1/4 of_l 1 114 of� 1/4 of� �114 of Section' _! Township''Range' —4-1-4-- —4-1-4— Locate well in two directions from nearest lines of quarter section and drilling unit I I I I I I --7—I-7— —?—r7— Surface _ —4-1-4— —4—I_4— Location i ft.frm(NIS) Line of quarter section I I I I I and_•,, ft.from(E/W) Line of quarter section. W I i I I I i E Well Activity Well Status Type of Permit --4--1—--1-- --4--I----1-- I IClassi (—` I IIndividual I I I I I I Operating . Class II !ModiflcationiConvsrsion —`Area I — — r �Brine Disposal IIII Number of Welts` —.4—1—4— — —1—-� — }..._Proposed — h Enhanced Recovery I I I I I I �I i Hydrocarbon Storage S '-----1 Class III I II Other Lease Number I Well.Number; Name(s)and Address(se)of New Owners) Name and Address of New Operator I , 1 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 to 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. I 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.12-08) • • PAPERWORK REDUCTION ACT The public reporting and record keeping burden for this collection of information is estimated to average5 hours per response. 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 orotherwisedisclosethe 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 thecompleted 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 1/MIP 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 Hydrocarbon storage well(excluding natural gas) Other Class II wells(not Included in Type"D,""R,"or"H") Class III Special process injection wells. Type"G" Solution mining well Sulfur mining well by Frasch process "t)" Uranium mining well "X" Other Class III 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,Ili,or V • EPA Form 7520-7(12-08)Reverse E 0 • , OMB No.2040-0042 Approval Expires 12/31/2011 United States Environmental Protection Agency re EPA Washington,DC 20460 Injection Well Monitoring Report Year I_ - f. Month - - - - - - Month_ . - Month.. .- . ... _ . Month -. Injection Pressure(PSI) ; j ___i 1. Minimum 1 ! 2. Average j I 3. Maximum ; { injection Rate(Gal/Min) I k____ — _________ 1. Minimum 1 2. Average 1 3. Maximum • Annular Pressure(PSI) 1C -- j 1. Minimum I 2. Average I 1 ! 3. Maximum j 1 Injection Volume(Gal) —��j _— i • i 1. Monthly Total I---- 2. Yearly Cumulative 1 I Temperature(F') __ ;I .} i 1. Minimum i S i . -----� 3. Maximum _ _ _ ! I_ 1. Minimum I e I . 2. Average ` ! j I __— 3. Maximum i _ Otherj , 1 _ ________I ' -- ° i _ Z - ' i _ I —_-- ---___1 !___ ....____._—_...___ !__--._.—___ —_J Names and Addr,Is tp rmitteePermit Number Name and Off tial Title (Pleas*type orgrintZ_ Signature Date Signed I 1 EPA Form 75204(Rev.12-08) • • 0MB No.2040-0042 Approval Expires 12/7112011 United States Environmental Protection Agency =y EPA Washington,DC 20460 Completion Form For Injection Wells - Administrative information 1.Permittee Address (Permanent Mailing Address)(Street,City,and ZIP Code) • • 2.Operator _.. _ �— — Address (Street,City,Stats and ZIP Code) 3,Facility Name Telephone Number Address (Street,City,State and ZIP Code) { I 1f i 4.Surface Location Description of injection Miffs) State County Surface Location Description 1/4 of 1/4 of 114 of 1/4 of Section 1_—,�Township' I Range'__ Locate well In two directions from nearest lines of quarter section and drilling unit Surface Location f ft.frm(NIS)1 ;Line of quarter section ands^,,, ft.from(ENW)�Ii Line of quarter section. Well Activity Well Statue Type of Permit i I Class I _Operating _Individual Class II _Area:Number of Wells, Modification/Conversion Brine Disposal Proposed EEnhanced Recovery Hydrocarbon Storage Class III I - Other Lease Number_— Well Number Submit 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 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. (Ref.40 CFR 144.32) Nemo and Official Title (Please type or print) Signature Date Signed EPA Form 7520.4(Rev. 12-06) • • 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 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 riot 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 techniquesto 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. Attachments to be submitted with the Completion report: I.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 tines, (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 • 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 utilise 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 • • "FEB-03-2003 MON 09:31 AMt', U2 Exhibit¢ • 4;st+►na4:,. UNITED STATES ENVICIONMENTAL PROTECTION AGENCY 4% Ti REGION 10 1200 Sixth Avenue Seattle,WA 981 01 t?trnolt!" 1.-T3 r 3 rv 3 «'.fk,L Rc:Zy To . ACM Of: OW-137 A 7003 • Larry D. Harms Point Thomson Unit Regulatory Coordinator L'xxanMobil Production Company Alaska Interest Organization 3301 C Street Suite 400 Anchorage, Alaska 99503 RE: Pt. Thomson Class I Injection Well - Underground Sources of • Drinking Water Bohr: Mr . Harms: This letter confirms that the United States Environmental Protection. Agency (EPA) concurs with your finding that there are no underground sources of drinking water (USDWs) beneath the p :rmafxos t underlying the Class f non-hazardous injection well currently proposed for. the Point Thomson Unit (PTU) on the eastern North Slope of Alaska. The PTU is located immediately west of the canning River and approximately 20 miles east of the nadami_ development. More specifically, EPA agrees with your conclusion that there are no USDWs beneath -the permafrost anywhere within the PTU boundaries as depicted in figure 2-1 of the '"Point Thomson Gas Cycling Project - Environmental Report" prepared by URS (July 1, 2001) (see attachment) . This conclusion is based on the analysis of four (4) drill stem test formation water samples (from wells Alaska State I'-1, Alaska State G-2, Alaska C-1, and Badami #5) and log derived total dissolved solids (PDS) estimates from tho 'four wells nee ost to the proposed Class I well in the PTU (West Staines-1, PTU #1, PTU #3, and Alaska State C-1) described in your letters of October and December, 2002 (ExxonMobil PTU "Athsonce of USW' Correspondence from Larry Harms to Randall Smith, EPA dated 10/18/02 .and 12/13/02) . These analyses and estimates, combined with the facts that the aquifers within the PTU do not supply any public water system and do not currently supply drinking water .for human consumption, indicate that these aquifers do not meet the definition of "underground source of drinking water" found at 40 C .F.R. ;r 144.3 . To confirm this conclusion, EPA requests that ExxonMobil obtain actual formation water samples from potential water- Prtnted on Agcycted Pot FEB-03-2003 ICON 03132 AN FAX NO, • P. 03 2 bearing zones in the interval between the base of the permafrost and the top of the proposed injection interval. If this is not feasible, either due to constraints resulting from well / construction or reservoir mechanics, a minimum suite of open hole geophysical logs should be run so that reliable log--derived. TDS estimates from Resistivity -- Porosity and/or Spontaneous Potential logs can be calculated for the PTU Class I injection well . For any questions, please call Thor Cutler at (206) 553- 1673 . 53- 1613 . Sincerely. (2471q2:140 /' Randall F. Smith Director Office of Water Mrzp Attachment: Figure 2 .1 of the Point Thomson Gas Cycling Project -- Environmental Report prepared by URS (July 1, 2001) . File: 1-67-1N-00001 No-USDW ExxonMobil Pt. Thomson Class 1 cc; Anita Frankel, EPA Oil & Gas Team (w/attachment) Tim Hamlin, GWPU Mgr. (w/attachment) Pete McGee, AAEC, FBS (w/attachment=) Marcia Combes, EPA. A00 (w/attachment) Ted Rockwell, EPA, AOO O/G Team (w/attachment) � \ • • !+ ' �! { •I, : 'V • %�y�. yam,, p , .a' ._., kv; ., :.?a�' • :� r'''1` -(4a [:�: •• : - '''/' „.7 l ;i ',i.;'+i h i:o;;.-,i. ;-4<9 <. r`:r, :r, dJ:N'c;r• .Y:,y i t ' 4C.; Qom• r4r,-1.,.-„,!....0..:-.;.:,.,,._1..:.-.....,., .Y,' •�.I• --.. . �.r<r >s•• � � ., ` tj "'d 6 .`J'1,,,,,,«T I_ - ...-./...-,;:;:f•:• • -.1. Kv l:; , .rya ,'k r, .ju`iJr IT h•a` q t �tv :. 1',-..„•; `...'•0, ?• ',,. J 4 %4::!,,. 1. .4 . 9• `i 'V�! a . <• ,cS,•.::.••i :..........,k..-, !•.— it•„ • : . •, . :, . 't t 3, `;6:1,14, V I • 2M ;'' •:CJ's. Y: '��•.:.,..t.. •tA• .7,; f .•. l •'/ - i. -',•;:„....3i••'i • I1r j�e,r.A. • few�t��n. •�{ c,cr. ' 'lt, f^;. . p7 �;.`h,A'�b•l -fi..) • .t1'.• \ •< �It1L. 1 y >Y -M' ..R :4 •'3 ''l•`,•,w;'• , •i'1�•i;•r• • •-1:'t i' ;,y�” ->w. >. >+ ❑ ! �T;4:r ,•t`•'�` .,r.. ,��4. -t•,;'...::-. � i i;..".::•;:- ,, \,•+.`.,'r t'•+r y as. • <..;.i.•4,1.s .V. `sr_,. . t, wJ,,:. ; t4. <• .. p'.J:• �`,. .,v• �. Y4 %hr., 4411f .a�' N Arr -1..,.. •.:•1..•.<i. a J i.`w�{�`•' 171 t` P•�4f r'^ ,_., aL • - • ' Q No i-+ }+h:X. "y,f. t ; ',r,,! f: fir•-• 0. ...„...t' .' �fi l:3 .;'ti • r - �_.. [„] 1 f.47. -,,,,p..,A37 r`•tir:.¢• 1• l. . . .ft r •• • 4•a; • • slow noks,. UNITED STATES ENVIRONMENTAL PROTECTION AGENCY REGION 10 Vror 1200 Sixth Avenue, Suite 900 Seattle. Washington 98101-3140 44, RECEIVED -kpRoito SEP 2 v‘ 200c SEP 302009 Reply To: OCE-127 Dale Pittman Production Aiaska CERTIFIED MAIL-RETURN RECEIPT REQUESTED Dale Pittman ExxonMobil Production Company P. O. Box 196601 Anchorage,Alaska 99519-6601 Re: Confirmation that the February 3,2003,No Underground Sources of Drinkiiig Water (USDW)determination by the U. S. Environmental Protection Agency(EPA) is still applicable to the Point Thomson Unit Dear Mr. Pittman: This letter is in response to your correspondence sent September 14, 2009, seeking confirmation that EPA's no USDW determination on February 3,2003, is still applicable to the Point Thomson Unit as described, Thank you for providing the map and legal description of the Point Thomson Unit. Based on the review by my staff of the map and legal description of the Point Thomson Unit, EPA hereby confirms that the determination by EPA on February 3, 2003, that there are no USDW's below the permafrost within the Point Thomson Unit is still applicable to the unit area as defined by the legal description and Point Thomson Unit map. If you have any questions or concerns,please feel free to contact Thor Cutler of my staff at(206) 553-1673. Sincerely, ; ---- Edward J. owal- Director Office of Compliance and Enforcement cc: Shawn Stokes,ADEC Division of Water/Wastewater Discharge Permits Dan Seamount, AOGCC OPnnted RecYcled Paper • Information and Attachments to Application for Permit to Drill Table of Contents 1. Well Name 2 2. Location Summary 2 3. Blowout Prevention Equipment Information 5 4. Drilling Hazards Information 7 5. Procedure for Conducting Formation Integrity Test 11 6. Casing and Cementing Program 11 7. Diverter System Information 17 8. Drilling Fluid Program 19 9. Abnormally Pressured Formation Information 24 10. Seismic Analysis 24 11. Seabed Condition Analysis 24 12. Evidence of Bonding 25 13. Drilling Program 25 14. Discussion of Muds and Cuttings Disposal 30 15. Attachments 31 Attachment 1-Well Schematic 32 Attachment 2-Geologic Forecast Log 33 Attachment 3—Planned Directional Survey Data 34 Attachment 3—Planned Directional Survey Data 35 Attachment 4—Wellpath Cross Section View 36 Attachment 5—Wellpath Plan View 37 Attachment 6—Anti-Collision Summary Report 38 Attachment 7—Traveling Cylinder Plot 39 Attachment 8—Wellhead/Tree Schematic 40 1. Well Name Requirements of 20 AAC 25.005(f) This disposal well for Point Thomson is designated PTU-DW1. 2. Location Summary Requirements of 20 AAC 25.005(c)(2) An Application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (2) a plat identifying the property and the property's owner and showing (A) the coordinates of the proposed location of the well at the surface at the top of each objective formation, and at total depth, referenced to governmental section lines. (8) the coordinates of the proposed location of the well at the surface, referenced to the state plane coordinate system for this state as maintained by the National Geodetic Survey in the National Oceanic and Atmospheric Administration; (C) the proposed depth of the well at the top of each objective formation and at total depth; Location at Surface 950'FSL, 1055 FEL, Sec. 34, T10N R 23E, UM • ASP Zone 3 NAD27 RK8 Elevation 42.0 ft. • Northing: 5,912,923.00 Pad Elevation 8.6 ft. . Easting: 468,248.70 - Location at Top of Productive Interval (Sagavanirktok) 1047' FNL, 2202 FEL, Sec. 3,T9 IVR 23E, UM ASP Zone 3 NAD27 Measured Depth, RKB 7040.4 ft Northing: 5,910,574.71 Total Vertical Depth, RKB 5765.0 ft Easting: 466,220.11 Total Vertical Depth, SS 5723.0 ft Location at Total Depth 2337' FNL, 1405 FEL, Sec. 34,T9N R 23E, UM ASP Zone 3 NAD27 Measured Depth, RKB 8839.0 ft • Northing: 5,909,532.19 Total Vertical Depth, RKB 6921.1 ft • Easting: 465,319.52 Total Vertical Depth, SS 6879.1 ft Application for Permit to Drill, PTU-DW1, Point Thomson Unit 2 • • M = c p H ,_ 2 c 0U H w 78 s o W D rx J U O Ll IV a 0 J °' N 3tiZ 21 z o Q _ = 3£Z 21 .. d < J Z 11Z co Hm OJO ElVIII um tect a ~ N Co 20 HUO e. 0 O z_ w co �` O (B o 03 6i E c 'iJ W 0_ Z ito M c 0 — � • om " L> °° a IJ_ _o - ts- _ x0- cr o _ oa' co .QU F' U o p r. � � Je? CO Oom t— O m1X O CO E PC O- -J W O J a s D = aom " c N 0) N W Vms o cu U O J DN C alf o C O U , N Ln (B J o N r , U 1- u_ _ a0E N M �"� �O Q O No 0 I '0L 0 RS 8 _1 m TrmM � � � "C> TY �0 __J2aa 63QomV o CI- m mW 3 03 om no 0 Ch 0 CDO N a) c U t a)^' a 3 as T N Ta o 3 a) of t c N—g Z Z<<t co c 0c- o 0-7 a Q4�-'3 pxw'9ZL Lb LOZ suogeool 118M—ped Ieilue0 l�ld\leld IIaM Iesodsid\pxW\SIJ\stulgps wOJJ 4oafad uoswogL Id I!9oyyuoxx3\f • • ..7„H _ = N 0 I- w 73 LU o o o = J CD cai e. cco = o in `° Mo ,- co Ct CI r- I M m � JMG• a < N I- Tr c> 0e is. 0- Jp oco 0 X °- c >< O Q LU J 0) I— m o a ao00U a ❑ & O 0m. W W 0 Z Q o 2 F. Up w CL m 0 HC ca W W 0.. z J Z W _ U. L0 0 0 a— CO J 2 v- 0 O M a--� 1SJ X056 m 0 LL LLI 0 ^� a. � � ON —I2 LL G1tDNN � 0- r.... CS) (O Z = p1ODU W _ 0) el � � 'Crr Z � 'OS 't- O a+ n w J M o N 0, O J = Q JO d OO TrJ01 � 01 � LL1uj x— (I) o DU_ n1141111 ~. CD_CD � � N Of) 40 -I c" M �1 OM to �� ♦ JM d N N co D co.- so . 0 y0r t 0 Tr J .. i N N onr; u) 1NJ .10176 if7 00 OJ = O M 1 V CV 't J °1 m N in = 1Nd ,LEEZ 0 J LL J LL 0 N U. e O o N. 0 N n to N 0 0 — (.0 c OcoMo N J_ M O 0 J_ M O Tt m M a m M in — J Xa 0 CO 0 03 X X X X w W <''(ii).. 1141111 M M Pxw'9ZL1410Z leld LMO Ped leJlua3 Z6ld\leld IIaM lesodsia\pxW\sIo\S LluZ90s word loefad uoswogi Id IigoJuoxx3\f • • 3. Blowout Prevention Equipment Information Requirements of 20 AAC 25.005(c)(3) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (3) a diagram and description of the blowout prevention equipment (BOPE) as required by 20 AAC 25.035, 20 AAC 25.036, or 20 AAC 25.037, as applicable; See Figure 3- BOP. Figure 8 - Mud System includes details of the choke manifold. An API 13-5/8" 10,000 psi BOP Stack will be utilized to drill and complete the well. Please refer to Figure 3 for a schematic detailing the BOP stack that will be used on Nabors 27E. Design aspects include: - Upgraded BOP shear rams tested to shear and seal on full range of drillpipe, casing, and completion tubulars - 10 ksi 5 preventer BOP stack Application for Permit to Drill, PTU-DW1, Point Thomson Unit 5 W C71 U CO Q '2▪ 2±'o bp 'M=i < o) V mz z �-Eo «sol-v J m=\ co 1--102 mr- v c~n o��m r -- y Z t Hgo5 � }� l�' Z a�,_a f^ .fEoi p� ► b J.6 - _ 1V) V V7 -- O->o-O� vj L..., .-_o...-.._-c...5—o. In (1) ai 7 n z,;,..,0, N N 0] O r-ficg ~0c4 N co _ il c� g I Pl r a AMA =Ii! '�I :,1 r I�I+ O/ o Oco Ln _ I_ �, » 'k « 'k _ Oq f((/ Q oo1 \OJD_ Z�E i w`�V 14111A\`s/�'` r. �1 O , O1 O Moots ¢111 N J _°' _1 = tJ �� t' U. cn�Jo0• M c„, �I' �f 1l�J/I •� �� ■ LL W CV .- !N— o 00 I /op) _,....._ J Q o 0] a Z o z Q w LI w °,'�'m v 0 < w Z co U mE�U O w +i +� +i +i +i M L- vE Z w M lb 2 0 L �� z U O O m � . _ �L O O Cr)te U O LL U • mvmm �i� y U m ❑ UO CO Y r: m CO a t X X W Ol . HELP V 1/ ,F) CO ❑ u. a a . w X X X ,� Q � ((==.1 4 sol LIJ ''^^ CL W W OLLIW Z J ooaamm VJ mZ ❑ QW Z Z (n D O FCO Q U 0 2 Y Q O J Y 0 CO mO �m o J I J Z Q W Qoo CCbocn5� Eo(/) a-Eo(gD (� Qpm W�WfY�(n L� mir)wZ(n UCN _PJ Q�JO m �J CO N.-J2m � WcLc, ixDc)a-000 ❑z(O 0o 0 (00_0 (1)- ao �m (0 L QOM QO❑X�N °o❑ .- 200w� Ch -Q WW W❑Wo�Z= 0❑Z F-LLI W�"Z= ❑.— z to- moHo(J) ZZ� I (0 O0 o z Q�W ��(n 2W J LL W DD(n co W O W 1 2I— OF— QO� E�Y OI— ❑� J cn cn❑ ❑c)o 1_0❑ ❑u.o ❑ ❑(n o Q❑ U O CO YYW YY_ (n❑W YY_ W YY_ W UN a) ooh oo�pu.s�� OOo2� ��(oZf- UU eoeo2 ooeo�criui2 a-000,-=2 o\eo�1-2 JJ LULU- in nv�.-H incnv_ F- ncnv(n� 00 .-,-w A A��w c'• �N�w ��w ¢Q IL ZZ Z l III 11) LO 77 li 1 - AL o ji,\IEL La << ,I Imo` m &) 1 1 • U • ❑ U c S U mw ❑wz AtZoH0 o a_ �:i �..... �� - C� I N L)co �0v ❑ • W �W �O r• ®� ■ ®� I 1 — I OJT O 0 0 1 O U0 0 i V — 1co co 0p ❑ ii -- 0 ca 0 I i ol ivir 0, gZ ,SAA kip is " �0,.i oM m m 0i.() �N ■ ..op to CN N o Zo Oo _ zo LE01 N. M • : • 1 � Ip M (- . . _c�� t 7 c_ ?I 7 Z � Z� CO0 vlii O:00 o O J \ _ 00 '� 0 w _ 1' Ls) i L ►— �► l ' W v N I I I COIlir CO II W 1 o 0 CO Q • • 4. Drilling Hazards Information Requirements of 20 AAC 25.005(c)(4) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (4) information on drilling hazards, including (A) the maximum downhole pressure that may be encountered, criteria used to determine it, and maximum potential surface pressure based on a methane gradient; (B) data on potential gas zones (C) data concerning potential causes of hole problems such as abnormally geo- pressured strata, lost circulation zones, and zones that have a propensity for differential sticking n 6d 017- v ( ,4 (0 . Maximum Anticipated Downhole Pressure: psig (Based on "high-side" pore pressure prediction at well TD). ",2 Maximum Anticipated Surface Pressure:,2rtzu (Based on "best-estimate" fracture gradient prediction at surface casing shoe minus methane gradient to surface). Shallow Drilling Hazard Evaluation (Well Site Survey) Point Thomson Unit, Alaska Location The Point Thomson Unit (PTU) Central Drill Pad is located on the Beaufort Sea coastal mainland west of the Canning/Staines River delta. Data Resources The following technical resources were available for this evaluation: • Offset Drilling Histories and GR/RES logs for: PTU-1, PTU-2, PTU-3, PTU-15, PTU-16 • Proprietary 3D PSDM Seismic data • Proprietary Base of Permafrost Map (constructed from GR/RES top-hole logs) • Proprietary Permafrost Velocity Model cross-section • Proprietary Top-Pab Map (constructed from Well data) • Proprietary Stratigraphic Montage (Brookian Sequence: Canning & Sagavanirktok Formations) • Petroleum Geology of the Northern Part of the Arctic National Wildlife Refuge, Northeastern Alaska, USGS Bulletin 1778 (1987) • The Oil and Gas Resource Potential of the Arctic National Wildlife Refuge 1002 Area, Alaska ANWR Assessment Team, Open-File Report 98-34, USGS (1998) Application for Permit to Drill, PTU-DW1, Point Thomson Unit 7 • s Land-lagoon transition amplitude variation, lack of offset to stack a coherent signal and noise such as ground roll coupled with a complex near-surface velocity with a fast near-surface permafrost layer makes interpretation in the shallow section challenging. In this area offset well control and drilling histories offer the greatest utility for shallow drilling hazard evaluation. Three wells (PTU-15, PTU-16, PTU-03) have been drilled through the shallow section below the Central Pad without encountering shallow hazards. Surficial &Top-Hole Geology Undifferentiated surficial Holocene deposits, associated with the modern Staines & Canning River deltas, consist of silt and fine sand overlying marine silt, clay, and occasional cobbles/boulders. These sediments in turn overly the Pleistocene Gubik Formation, consisting of sand and gravel with a variable thickness of up to 200 feet. Gubik Formation facies are described as glacial outwash, flood plain and river terraces sourced from the southern mountains. Permafrost occurs throughout the region and in the coastal nearshore area is up to 2000 feet - thick. The Gubik formation overlies the Cretaceous through Tertiary Brookian Sequence consisting of the Canning and Sagavanirktok Formations. The Oligocene to Quaternary Sagavanirktok Formation occupies the entire top-hole section at the proposed PTU Drill Pad location and is generally described as a very thick (6000 to 7500feet) clastic and relatively incompetent sequence. It was formed from erosional debris shed by the ancestral Brooks Range that filled local basins adjacent to the range and subsequently migrated to the north and east as a series - of deltaic wedges. The main part of the Sagavanirktok Formation is Eocene through Pliocene in age, and consists of fine grained sandstone and bentonitic shale with minor conglomerate, and rare coal. Sagavanirktok facies are described as alternating shallow marine and non-marine deltaic, • coastal plain, and shelf. The base of the Sagavanirktok Formation is diachronous, older to the south and west, younger to the north and east. Minor disconformities occur throughout the formation which exhibits uniform monoclinal dip to the north and northeast. No through-going faults from reservoir depth to the near-surface are observed. The dominance of permeable sandstone in the Sagavanirktok • Formation limits effective seals for potential stratigraphic traps. No hydrocarbon-bearing reservoir or source rocks are known within the Sagavanirktok Formation. The nearest (unconfirmed) surficial oil seep has been reported as occurring at the mouth of the Canning River approximately 5 to 6 miles southeast of the North Staines 1 well. The top-hole section is near to normally pressured. This well is not expected to penetrate abnormal pore-pressure. Application for Permit to Drill, PTU-DW1, Point Thomson Unit 8 I i Near-Offset Wells Near-offset wells within the vicinity of the proposed PTU Drill Pads include the PTU-1, PTU,-2, PTU-3, PTU-15 and PTU-16 wells. All top-hole sections (<_ 5000 feet subsea) to the 13 3/8" surface casing seats were drilled with 8.7 ppg to 10.5 ppg mud. Reported Leak-Off Tests conducted on the surface casing shoes ranged from13.6 to 14.9 ppg EMW. / No overpressured shallow gas, oil, or gas-hydrate have been encountered by these wells in the t top-hole section. Top-hole problems incurred by these wells (and others in the vicinity) are restricted to minor lost mud returns within the permafrost, tight spots while pulling out of hole, minor lost cement returns during installation of surface casing, and difficulties cleaning gravel from the hole while drilling. On-site Mitigation Measures While overpressured shallow gas is not anticipated at the PTU Central Pad location precautions will be taken at the well site when drilling the top-hole section including: • Weighted spud mud • Gas detection-equipment • Logging While Drilling (LWD) • Annular diverter nippled up on the conductor casing • Kill-weight mud (KWM) available on-site Summary of Findings • There are no reported occurrences of overpressured shallow gas within the PTU. • Gas-hydrate and/or associated free gas is not known to occur at the base of permafrost within the PTU. • 3D seismic data show no direct hydrocarbon indicators in the shallow section (<_ 5000 feet subsea). • Geophysical and geological data demonstrate the absence of structural traps in the top- hole section within the broad vicinity of the proposed Drilling Pads. • The top-hole section is normally pressured (hydrostatic gradient anticipated). • Thick permeable sands dominate the top-hole section limiting opportunities for shallow stratigraphic traps. • Necessary precautions will be employed on-site during the drilling and casing of the top- hole section. Application for Permit to Drill, PTU-DW1, Point Thomson Unit 9 Drilling Hazards and Mitigations Surface Hole Section (12-1/4" hole size & 9-5/8" surface casing) There are no reported occurrences of overpressure and shallow gas within the PTU and within the vicinity of the proposed location. Gas hydrates and/or associated free gas are not known to occur at the base of the Permafrost within the PTU. Shallow gas is not expected at this location. Offset wells have experienced minor losses of mud and cement when drilling the Permafrost. Some difficulties removing gravel out of the hole have occurred in offset wells when drilling the Permafrost. Major lost circulation is not expected in surface hole. Potential drilling issues and mitigation steps for the surface hole section are as follows: 1. Install diverter system, trip tank, flow detection equipment, and gas detection equipment prior to spud. 2. Drill with planned overbalanced mud. Ensure kill-weight fluid (KWF) is on location prior to spud for additional contingency. 3. Control circulation rates and mud temperatures to avoid Permafrost washout and wellbore instability. 4. Maintain mud properties to ensure adequate hole cleaning and control seepage losses across permeable zones. 5. Optimize bit hydraulics to mitigate balling in sticky clays. 6. Manage drilling rates to prevent cuttings overloading in solids control equipment. Production Hole Section (8-1/2" hole size & 7" production casing) Abnormally pressured strata and moveable hydrocarbon bearing zones are not expected to be penetrated in this hole section. Lost circulation is also not expected for this interval. Potential drilling issues and mitigation steps for the production hole section are as follows: i 1. Maintain adequate mud weight to mitigate wellbore instability. 2. Minimize low gravity solids (LGS) content using solids control equipment for ECD management 3. Employ a rotary steerable system drilling assembly to maintain a smooth wellbore to mitigate wellbore tortuosity, drag, and other adverse hole conditions. 4. Properly centralize casing to manage the risk of differential pressure sticking across permeable formations. Application for Permit to Drill, PTU-DW1, Point Thomson Unit 10 • 5. Procedure for Conducting Formation Integrity Test Requirements of 20 AAC 25.005(c)(5) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (5) a description of the procedure for conducting formation integrity tests, as required under 20 AAC 25.0030(f); The formation integrity test procedure is described in items 18-19 of the Operational Summary in section 13, Drilling Program, of this application. 6. Casing and Cementing Program Requirements of 20 AAC 25.005(c)(6) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application; (6) a complete proposed casing and cementing program as required by 20 AAC 25.030, and a description of any slotted liner, pre-perforated liner, or screen to be installed; Tubular Specifications Size Weight Nominal Drift ID Conn. Conn.OD Burst Collapse Tensile MD TVD (in) (PPO ID Conn. ID(in) (in) ID(in) (in) (psi) (psi) (klb) (ft) (ft) 20 x 34 129.5 X-52 Welded 18.750 N/A N/A N/A N/A N/A 1,978 155 155 9-5/8 53.5 L-80 VAM TOP KX 8.535 8.500 8 719 10.520 7,930 6,620 1,244 4,900 4,389 • 7 26 1%Cr L-80 TSH 563 6.276 6.151 6 226 7.656 7,240 5,410 604 8,839 6,921 • 4-1/2 12.6 1%Cr L-80 VAM TOP 3.958 3.833 3.913 4.937 8,430 7,500 288 6,990 5,733 NOTES: 1.All casing and tubing will be in new condition.All casing and tubing threads will be premium connections. 2. The 20"x 34"insulated conductor properties are based on the 20"inner string. 3. Burst(internal yield), collapse, and tensile capacities provided represent nominal ratings. 4. The 9-5/8"surface casing has been manufactured with special bevel (SB)couplings and special (non-API) drift. 5. Premium connection data sheets for the 9-5/8"VAM TOP KX, 7"TSH 563, and 4-1/2"VAM TOP have been provided for reference Application for Permit to Drill, PTU-DW1, Point Thomson Unit 11 Figu4 - 9-5/8" VAM TOP KX Calpection Specs VAM® TOP KX SB Coupling Length 11189 Make Up Loss Box Critical Area 5.589 t 1 0.545 Wall ! I f. Pin \Connection Pipe Critical Connection O.D. Pipe O.D. Area I.D. 10.520 I,D. 9.625 8.719 8.535 O.D. WEIGHT WALL GRADE ''SP DRIFT' 9.625 53.50 0.545 I Cr80 8.500 PIPE BODY PROPERTIES CONNECTION PROPERTIES 1 Material Grade 1Cr80 Connection OD 10.520 in Min. Yield Strength 80 ksi Connection ID 8,719 in Min. Tensile Strength 95 ksi Make up Loss 5.589 in Coupling Length 13.189 in Outside Diameter 9.625 in Box Critical Area 15.876 sq.in. Inside Diameter 8.535 in ',PB Section Area 102.1" Nominal Area 15.546 sq.in. Pin Critical Area 15.546 sq.in. r.�PB Section Area 100.0% Yield Strength 1,244 kips Yield Strength 1,244 kips Ultimate Strength 1,477 kips Parting Load 1,477 kips Min Internal Yield 7,930 psi Min Internal Yield 7,930 psi Collapse 6,620 psi Ext Pressure 6,620 psi Wk Compression 746 kips Max Pure Bending 30 0/100 ft Contact:tech.supportCdvam-usa.com TORQUE DATA It-lb Ref. Drawing: SI-PD 100013 Rev.A t min opt max Date: 24-Jun-14 20,850 23,150 i 25,450 Time: 2:52 PM Max Load on Coupling Face: 335kips Ai!information is provided by VAM uSi or its o ff lutes a t use'-s sole risk,w,thcut b'k y,for foss,damage or injury resulting from the use thereof and on an As ir basis without warranty or.rep resentat,on of an:,Kind,whether express or'moiled,including without limitation any warranty of merchantability,fitness for purpose or completeness. This document and its contents ore subject to change without notice+r no Ilif U SA event shall VAM uS4 or its affiliates be.responsible for any indirect,soecioi,incidental,ounitive,exemplary or consequennal loss or damage (including without limitation,lass of use,loss of bargain,Joss of revenue:profit or anacipoted profitj however caused or arising,and whether such lsc_nrdenmoes mere foreseeable or'VAM.'USA or its offisgtes was atl:•ised&lttre,potsibili{�i f sty. manes 12 •ure 5 - 7" TSH 563 Conne.n Specs DS.Teconsliydni Hytkt1 5,63 Casing-7 000-26 000 LSO 1 Pa?e of 2 March 05 2014 Size: 7..000 in, Waft: 0.362 In. Connection; Wedge 563r" Casing Weight: 26,00 lbs/ft Casing/Tsil)ing: CAS Grade: 180.1 Coupling Option: REGULAR Min, Wall Thickness: 87.5 % PI PF BODY filkir,e• GE NWT Tfi "%Cell an Al ?SAPCI Ofteneek *weir.Drift feternnAl 6.176 ea. ; .1412 11i Oleenehor Ram Eru W*0* Z.I..6411,pilf. .411. body veld 604 100(1 e Strength Collapse 5.411)psi WEDGE SOW*CASU414 CONNECT/00 DATA GE0441FTRY "., Mat:hed St,wig& Connection DO 7.656 7,545 rn. Lorirectrmfl 6.226 In (X) -: Length 9,2504r I. Th,eads per tri 1.19 1 Cilm) r PEPIFORMANCE 604 icor lobular'P?. Terratto Efficterice 100% 1,:.nt vd Screnirth 7240 po lbs Capecey Correliassoan t_ornpletsdon 604 100 40c, Dencheg *1100 ft fAvvortri. ';tivngth 1115 F...tarnalPurt 5410 p.s1 MAKE-LIP NNW jrr A.801) bs citS 10400 I Mar,rmyr 1 OPERATIONAL LUNT TORQUES Operating Torque 26000 ft-tb Tongue nose ft-lbs I UCK-0110 TORQUES Minimum 133100 ft-lo: 1 tr 15000 f-t-lbsI LtLANK1144.- LAPPEOFSIONS hap:livtannamcommecaindaia.tenans_comitsk printrobehWa110.362athStzr=7.0004kliGra_.. 3642014 13 Fre 6 - 4-1/2" VAM TOP CcOection Specs issued on: 06 Mar,2014 °WI tei...171./F1 Connection Data Sheet OD Weight Wall Th. Grade API Drift Connection 4 t/2 in. 12.60 lb/ft 0.271 in. VM 80 11CR 3.833 in. VAM® TOP Tubing PIPE PROPERTIES CONNECTION PROPERTIES Norrinal 00 4,500 in. Connection'Type Premium T&C NorrinallD 3.958 in. Connection OD '„nom) 4.937 in. Norrinal Cross Section Connection ID(nom) 3.913 in. 3.600 sqin. Area . Make-up Loss 3.222 in, Low a'loy steei grades I,Yitl Cr Gr-ade Type Coupling Length 7.44 in, , add ton I Critical Cross Section 3.600 sqin. Mir,.Vild Streesoli 80 ki Tension Efficiency 100%of pipe Ma'. Yie,c1 Strength 95 ksi Compression Efficenc-y 100 %of pipe MM.Ultimate Tensile 95 ksi Strength Internal Pressure Efficiency 100%of pipe E:-.ternal Pressure Ell.cency 100%of pipe CONNECTION PERFORMANCES TORQUE VALUES Tensile Yield Strength 288 kilo Min.Make-up torque 4000 ft.lb Compression Resistance 283 k b aDti. Make-Jp.torque 444(1 ft,IE Intenal Yield Pressure 8430 psi Max.Make-up torque 4880 ft,Ib Extemai pressure resistance 7500 psi Max bending with sealability 30°;100 ft Max Load on Coupling Face 162 k b wAhlE potnnano,TOP(21:1104'440p0,,,") VAN* TOP tubing (2 3/8"-4 '11") is the most used premium tubing connection throughout the world , Prior ...—. 64.4y MAC Tne product line has been extensively tested as per leni 15013679 CAL:V,with more than 60 qualification tests, 4.1***ess on the full pipe body envelope. / it 9 1 ' 141, 1 1114..All',A r 1 ,, sii ion Add Load r.Me ti two....Y..... i..,. -.R.. Do you need help on this p4oduct7-Remember no one knows VANS like VAN caneclaVvarnrieldservice.cein likitvaniffeldseevice.carn chinativerrodeictswirlce.com usa%varneeidservice.carri admit vatneekiservice.com baktrigyametektservice.carn inevicoliPtiamileldseivice,rem legerfailvarrifehleetvice.cem singaparettwareffeldservicexem brrzegvameeldsenticecern regale zrvameetriservicexose austraeatvarnilettaerware.COM Over 140 VAM ki Specialists available worldwide 2417 for Rig Site Assistance Dt-e Cornectior Da:a Sheets are available at wwr,'.varrsiervices.com Vallourec Group 10 vallourec 14 • • Cementing Program 9-5/8" Surface Casing -Annular Excess Assumptions + Inside Conductor(Surface- 155'): 0% + Permafrost Interval (155' - 1797'): 300% + Sub-Permafrost Interval (1797'-4900'): 50% -Drilling Fluid: 10.0-10.2 ppg Drilplex AR WBM -Spacer: 150 bbl of 10.5 ppg MudPush II -Lead Cement: < 1,113 bbl of 11.0 ppg Arctic LiteCRETE + Planned Top of Cement: Surface + Yield: 1.93 ft3/sx; Cement Quantity: 3,238 sx + Additives (dry blended): Antifoam, Dispersant, Salt -Tail Cement: 91 bbl of 15.8 ppg Class G + Planned Top of Cement: 3900' + Yield: 1.16 ft3/sx; Cement Quantity: 441 sx + Additives (dry blended): Antifoam, Dispersant, Fluid Loss,Accelerator - Displacement: 340 bbl of 10.0-10.2 ppg Drilplex AR WBM - Port Collar @ -500' (Contingency Only - Rigid centralizers will be used inside conductor; Bow spring centralizers will be used in open-hole 7" Production Casing -Annular Excess Assumptions + Inside Surface Casing (Surface-4900'): 0% + Open-Hole (4900'-8839'): 50% - Drilling Fluid: 12.1 ppg VersaClean NAF - Spacer: 25 bbl of 12.5 ppg MudPush II -111' � - Lead Cement: f bblbf 13.0 ppg LiteCRETE Q-2')Q-2')+ Planned Top of Cement: 024'_ -1(c)c/ + Yield: 1.45 ft3/sx; Cement uantity: x,83 sx + Additives (dry blended): Antifoam, Dispersant,Fluid Loss, Retarder - Tail Cement:60 bbjbf 15.8 ppg Class G + Planned Top of Cement: 7180' + Yield: 1.16 ft3/sx; Cement Quantity: 291 sx + Additives (dry blended): Antifoam, Dispersant Fluid Loss, Retarder - Displacement: 335 bbl of 12.1 ppg VersaClean NAF - Solid body centralizers will be used NOTES: 1. Cement volumes are based on gauge hole with annular excess assumptions noted above. Actual volumes pumped may vary based on caliper data or other operational insights into hole washout. 2. Port collar will be used strictly as contingency in surface hole in the event cement returns are not observed at surface after the planned job is 15 ! • pumped. If required, port collar will help ensure adequate cement to surface. 3. Planned top of cement and volume for the tail slurry in production hole is still under evaluation and may be subject to change. 4. Final additive concentrations will be determined from cementing provider laboratory testing. 16 • 7. Diverter System Information Requirements of 20 AAC 25.005(c)(7) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (7) a diagram and description of the diverter system as required by 20 AAC 25.035, unless this requirement is waived by the commission under 20 AAC 25.035(h)(2) Application for Permit to Drill, PTU-DW1, Point Thomson Unit 17 oo , 0 • ,, 1 ,--, il .. le .. IN \ g. 1 e.0' v.i4g V. I I g 3L— ,.. 4 1 e fr `. f.,,.. . 4 .. 4_ t , • ; i 41 vt \it i $ E ..t, I tr I B 1T 2 7. i = ka i 1 i s 3.1 Z La cei 0 Cs1:3 IN\ i I i t i i a) -4 i. JO -.I a) . a / • • 413 1 L----1 LLI W 11 1 N- 5 ( Cl) P ' ' r k 7 41 3 7 t I- o i R ig? r—1 - moo _a ., CD 1 Z _..._..._ . ..... .aii•bei. galin SOOMIMMI .11:1 N.. a) '". ,.. 06. = 0) U- c &so° Noizi mu 8. Drilling Fluid Program Requirements of 20 AAC 25.005(c)(8) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (8) a drilling fluid program, including a diagram and description of the drilling fluid system, as required by 20 AAC 25.033; 12-1/4" Surface Hole - Surface Interval: 12-1/4" hole, 9-5/8" casing to -4900' MD/4389' TVD RKB - Drilplex AR Water-Based Mud (mixed metal oxide based system) - Recommended WBM Properties" Spud to Base of Permafrost Base of Permafrost to TD Density(ppg) 10.0- 10.2 10.0- 10.2 Low Shear Yield Point(2 x 3—6 RPM) 30- 70 25-45 Yield Point(Ibf/100 ft') 50- 80 40-60 API Fluid Loss(m1130 min) < 15 < 15 Flowline Temperature(°F) < 65 < 70 pH 10.8- 11.3 10.8 - 11.3 8-1/2" Production Hole - Production Interval: 8-1/2" hole, 7" casing to -8839' MD/6921' TVD RKB -VersaClean Non-Aqueous Fluid (low toxicity mineral oil based system) - Recommended NAF Properties: Surface Casing Shoe to TD Density(ppg) 12.1 Plastic Viscosity(cp) < 28 Yield Point(Ibf/100 ft') 20-25 HTHP Fluid Loss(m1/30 min) < 6.0 Oil to Water Ratio 85:15 Electrical Stability(ml Volts) > 600 Application for Permit to Drill, PTU-DW1, Point Thomson Unit 19 i 0 b C, r —1 �g'a o Ilius a h hk '49. � 1II l!r lit in{ BURN �c i�1 C 14 RYA►4 ., i I1i uII 14 E NN N„, r 6. -1(7) §1 IC) )4 TT I 14 N,--t; % i •(/) li „._— iiig ; : : P p L- 1� = IE Mr a w . . ar: 0 N.. ■ ■ _._ ■ . Ili n ti n N �II ��■A(':is �'. o I ': n 'c C O Ili Itl L Itl II'. ■ ■ �,- ■ ge a 4 pli 4 CZ 111 I Ilt /II ii* , m_ 00 m 4 T t a) e- -; 1 - R 1 it 'g n 1 f g i Z t?' ` ' in'IM: :'�.t �I Yi4 Z� o MS En ■ ./.'''''c-7- 2 7ut Z L J ilT..T,--'1101004i JM "L J 111 111 aa/Rh VI■loafta,Mw]-A+....3-IVYOAs..."1.0.1O • • WELL CONTROL DRILLING FLUID MONITORING SYSTEM A flow rate sensor and a pit volume totalizer (PVT) system will be installed. This drilling fluid monitoring equipment allows the driller to recognize downhole problems and take immediate action when a kick or lost circulation occurs. The flow rate sensor provides a method for indicating and recording flow in the mud return line. The sensor consists of a counterbalanced paddle, located in the mud return line, which reacts to changing flow. The changes in flow transmit a signal, proportional to the paddle angle, indicating the amount of increase or decrease in flow. Limits can be set which activate an audible or visual alarm when exceeded. The recorder and alarm panel are located near the driller's console for convenient visual analysis during drilling or circulating. The flow sensor immediately shows changes in return flow rate and thereby gives the earliest possible warning of kicks, lost circulation, or pump valve failures by comparing mud flow rate, pump rate, and circulating pressure. The driller can detect holes in the drill pipe and/or plugged bit jets. The most reliable indicator of an increase or decrease in the mud system volume is the PVT. The PVT uses a series of spherical floats which rise and fall with the mud level in the tanks. An air or electric calibration system transmits this data to a central totalizer unit. This information is displayed on a continuous chart, as well as on a sensitive visual gauge. It provides warning of downhole problems, such as lost circulation, gas cutting, or kicks, by continuously measuring the volume in the entire surface system. The pit volume totalizer and flow rate sensor systems must be checked every tour by the driller. These checks must be documented and maintained at the rigsite for verification. Monitoring equipment will include the following: Pit Volume Totalizer (required on all mud tanks) 1. Volume monitoring equipment shall be installed in all tanks in the active mud system, with a pit volume totalizer to combine all tank volumes into a single read-out. All floats shall be checked for adequate freedom to move to a full tank position. 2. A recorder and a dial indicator shall be installed at the Driller's console to read and record total pit gain or loss in barrels. 3. Audible and visual alarms are to react upon exceeding a pre-set limit in pit volume (not to exceed +5 barrels) and shall be installed at the Driller's console. A second console may be required as designated by the ExxonMobil Drilling Supervisor. Flow Rate Sensor 1. A flow rate sensor shall be installed in the mud flow line with a recorder and dial indicator placed at the Driller's console. The dial indicator may include a pump stroke counter and a totalizer. 21 • • 2. Audible and visual alarms are to react upon exceeding a pre-set limit in flow rate and shall be installed at the Driller's console and at a second console, if designated by the ExxonMobil Drilling Supervisor. 3. The flow rate sensor shall be installed upstream of the trip tank return line to permit use of the flow rate monitor and alarm system during trips. Mudlogger/Gas Detector • 1. Gas sensors will be located at the rig floor, in the cellar, and on the mud tanks. 2. A mudlogging unit will be rigged-up prior to spud for gas volumetric and compositional analysis. ___ Drilling Fluid System Tankage Description Capacity(bbl) Active Mud System 1480 Reserve Tanks 2500 Pill Tanks 100 Trip Tank 100 22 ` 0 • rn 2 is N COCD I- ry r VJ 2S 1. . 11,4111 11041, t) I— C 114 c 5 o Jit e C_,.=.11011><= 12 D 0 CD Z U C < NE t CU aci w ,7 Al0 a J •i • CU ii: 0084 p C 0. 0) n CU 2 1 CL a) J 1 P Q -- rn a. - I ii.: I_ r —AT- 0,411 I►4II ."* • • ad •• •i C] oV 42 0k g Rg su- G 2 › 0 0 ff Version July 2000 7-3 • 9. Abnormally Pressured Formation Information Requirements of 20 AAC 25.005(c)(9) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application:(9) for an exploratory or stratigraphic test well, a tabulation setting out of the depths of predicted abnormally geo-pressured strata as required by 20 AAC 25.033(f); Not Applicable to a service well. , 10. Seismic Analysis Requirements of 20 AAC 25.005(c)(10) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (10) for an exploratory or stratigraphic test well, a seismic refraction or reflection analysis as required by 20 AAC 25.061(a); Not Applicable to a service well. - 11. Seabed Condition Analysis Requirements of 20 AAC 25.005(c)(11) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (11) for a well drilled from an offshore platform, mobile bottom-founded structure,jack-up rig, or floating drilling vessel, an analysis of seabed conditions as required by 20 AAC 25.061(6); Not Applicable to this onshore drill well. Application for Permit to Drill, PTU-DW1, Point Thomson Unit 24 • • 12. Evidence of Bonding Requirements of 20 AAC 25.005(c)(12) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (12) evidence showing that the requirements of 20 AAC 25.025 {Bonding} have been met; Exxon Mobil Corporation's Evidence of Bonding (# 8302 42 06) is on file with the Commission. 13. Drilling Program Requirements of 20 AAC 25.005(c)(13) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: PTU-DW1 Proposed Drilling Program WELL NAME: PTU-DW1 FIELD: Point Thomson SURFACE LOCATION: x = 468248.7 ft E; y = 5942923.0 ft N; NAD 27 ASP3 PROPOSED BHL: x = 465319.5 ft E; y = 5909532.2 ft N; NAD 27 ASP3 TOTAL DEPTH: 8,839' MD/ ,921' TVD RKB • RIG: Nabor Alaska Rig 27E KB ELEVATION: 74'2.0' above MSL GL ELEVATION: -8.6' above MSL 04. pSIBC EST. SPUD DATE: -23 February 2015 )4, Z EST. RIG OPER. DAYS: -56 days OPERATIONAL SUMMARY 1. Access to the wellsite, site preparation, and installation of the cellar and conductor will be completed in advance of the rig move. 25 • • er 1 p..• i r �5 2. Skid rig over 20" x 34" conductor in well slot 1. 4�,��'6~~ , 1 V' l� p 3. Install 21-1/4" 2000 psi WP diverter system and pressure test in accordance with AOGCC regulations and company standards. 4. Pick-up 12-1/4" directional drilling assembly. 5. Drill out 20" x 34" conductor shoe with freshwater. Displace wellbore to Drilplex AR water- based mud system. 6. Drill vertically through the Permafrost interval and kick-off directionally at —1,825' RKB. Drill to 4,900' MD /4,389' TVD RKB. 7. Circulate hole clean and wiper trip if dictated by hole conditions. POOH. 8. Run 9-5/8" surface casing to depth. Circulate and condition mud in preparation for cement job. i 9. Pump the planned single stage cement job using a lead /tail slurry system. Wait on cement. 10. Conduct dedicated cleanout run inside casing in pre ration for cement evaluation log. - 11. Rig-up wireline equipment. Run cement evaluati n log on wireline to confirm adequacy of cement. Rig-down wireline equipment. 12. Rig-down diverter system and install 11" 5000 psi WP wellhead A-Section. 13. Install 13-5/8" 10,000 psi WP BOP stack nd choke manifold system. 14. Pressure test wellhead, BOP stack, d choke manifold system in accordance with AOGCC regulations and company standards./ 15. Pick-up 8-1/2" directional drillin assembly. Run in hole to the top of cement and circulate bottoms up in preparation for c sing test. (, p.; o,� 16. Pressure test the casing to 0 psi for 15 min. The maximum anticipated surface pressure (MASP) while drilling the 1/2" hole section is —2,750 psi based on a 14.0 ppge fracture pressure at the 9-5/8" ca ing shoe (4,389' TVD RKB) and a 0.1 psi/ft methane gradient to surface. 17. Displace wellbore to VersaClean non-aqueous mud system. • 18. Drill out shoetrack ar}d clean out rathole. Drill 20-30' of new formation and circulate bottoms up in preparation for formation integrity test (FIT). 19. Perform FIT to 3.7 ppge. This test pressure is based on the maximum anticipated equivalent circul4ting density (ECD) at the 9-5/8" casing shoe while drilling the 8-1/2" hole section. Note that this test pressure is above the maximum anticipated wellbore pressure of 13.1 ppge at this depth and below the predicted fracture pressure of 14.0 ppge. 20. Directionally drill to —8,839' MD/6,921' TVD RKB. 21. Circulate hole clean and wiper trip if dictated by hole conditions. 22. Circulate and condition mud in preparation for wireline logging. POOH. ' 26 I • 23. Rig-up wireline equipment and conduct open-hole logging program. Rig-down wireline equipment. l _7'; .911°w7' X G+ ,,,1 f'�se/ 24. Run 7" production casing to depth. Circulate and condition mud in preparation for cement `- job. 25. Pump the planned single stage cement job using a lead /tail slurry system. Wait on cement. 26. Conduct dedicated cleanout run inside casing in preparation for cement evaluation log. 27. Rig-up wireline equipment. Run cement evaluation log on wireline to confirm adequacy of cement. Rig-down wireline equipment. _ 28. Run in hole to bottom and displace wellbore to NCI completion brine. 4' c.5.‘i. i3:cwt f 29. Pressure test the casing to 4000 psi for 30 min. This test pres re is based on the SAPT / MITIA test pressure requirement stipulated by EPA. POOH. 30. Rig-down BOP stack and install 7-1/16" 10,000 psi WP wellhead B-Section. 4 h.\ -;r,_. i 31. Install 13-5/8" 10,000 psi WP BOP stack and choke manifold system. 32. Pressure test wellhead, BOP stack (Figure 3), an choke manifold system (See details in Figure 8) in accordance with AOGCC regulations it company standards. '' I'- 33. Pick-up tailpipe and packer assembly and run in hole on 4-1/2" production tubing to -6,990' ; MD /5,733' TVD RKB (-50' MD above top Injection Zone) Wit'`` ,lam 3 34. Space out and land tubing hanger in well ead. 35. Reverse circulate insulating packer fluid (IPF) down to packer depth. Shut-in annulus to prevent U-tubing effect due to lightweight packer fluid. NOTE: The planned IPF is ISOTHER , which is a viscosified non-aqueous fluid system supplied by MI-Swaco. The viscosit complex is achieved through a proprietary polymer blend. eo 36. Drop ball / rod assembly to I d out in plug receptacle in tailpipe X profile. 37. Pressure up on ball / rod a, sembly to 3000 psi to set packer. Bleed off pressure frpm tubing. l 38. Run in hole with slicklineto retrieve ball / rod assembly and plugdfecept�aCi'e from tailpipe X profile. POOH. '' . 39. Bleed pressure off ap(nulus side. 40. Rig-down BOP stack and install 4-1/16" 5000 psi WP tree. 41. Pressure test tr to 5000 psi for 15 min. Rig-down slickline equipm e -_, 42. Pressure test ubing and tubing-casing annulus to 4000 psi a dry 3500 respectively, for 30 min each test as part of EPA required SAPT/ MITIA. c►,�,t / 5 4 I,, ..( is r,( ( 43. Rig-up wireline equipment and 3-3/8" perforating guns. 44. Run in hole through tubing to -8,639' MD/6,793' TVD RKB. Correlate to confirm on depth. 27 • ! , 45. Apply 200 psi surface presskire and perforate interval from -8,639' MD / 6,793' TVD RKB to 8,659' MD/6,805' TVDK B. NOTE: Perforation interval i still being evaluated and is subject to change. 46. POOH with spent pert 'ating guns on wireline. 47. Conduct EPA requir fluid movement test. Rig-down wireline equipment. 48. Conduct EPA req fired initial step-rate test and pressure fall-off. Following test, displace 2500' of tubing to diesel for freeze protection. 28 • • N O O l0 0 4 - O 0 _ CIL O ^� Q o 1 5 >• 3 - M � F- m o tflc 0 Ci. O 0 O 0 0 0 0 0 0 0 0 0 0 0 0 o m • on o^ C rn o (a H-a J t ) y;daa • Formation Evaluation Program 12-1/4" Surface Hole — Mudlogging: Cuttings Samples (sampling frequency at discretion of wellsite geologist) — LWD: Gamma Ray/ Resistivity • —Wireline: None 8-1/2" Production Hole — Mudlogging: Cuttings Samples (sampling frequency at discretion of wellsite geologist) — LWD: Gamma Ray/ Resistivity/ Density/ Neutron / Caliper (contingency) —Wireline: Sonic/Caliper NOTE: Formation evaluation programs are subject to change based on well objectives and drilling characteristics. Substitution of logging tools may be required due to availability, hole conditions, or changes to formation evaluation objectives. 14. Discussion of Muds and Cuttings Disposal Requirements of 20 AAC 25.005(c)(14) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (14) a general description of how the operator plans to dispose of drilling mud and cuttings and a statement of whether the operator intends to request authorization under 20 AAC 25.080 for an annular disposal operation in the well. ExxonMobil does not intend to request authorization under 20 AAC 25.05(b) for annular disposal operation in the well. ExxonMobil's plan i s to transfer drilling waste from the drilling rig to the final disposal location at the Prudhoe Bay Unit G&I Plant whenever possible. When this is not possible, due to logistical or other considerations, it will be necessary to temporarily store drilling wastes, including WBM solid wastes (fresh water based mud cuttings and fresh water based mud retention on cuttings) and NAF base solid wastes, at Point Thomson prior to ultimate disposal. For drilling the surface hole, the WBM wastes may include fresh water based whole mud, fresh water based contaminated mud interface, fresh water based cement slurry, fresh water/cement slurry rinse from the cement unit, and fresh water from the rig boiler blowdowns if that cannot be used elsewhere in the operation. These water based wastes will be temporarily stored in the onsite cuttings pit as necessary. NAF based wastes from drilling the production hole that cannot be directly transported to Prudhoe Bay will be stored in totes as necessary. The totes will be placed in lined containment areas. . Application for Permit to Drill, PTU-DW1, Point Thomson Unit 30 • • 15. Attachments Attachment 1 -Well Schematic Attachment 2 - Geologic Forecast Log Attachment 3— Planned Directional Survey Data Attachment 4—Wellpath Cross Section View Attachment 5—Wellpath Plan View Attachment 6—Anti-Collision Summary Report Attachment 7 —Traveling Cylinder Plot Attachment 8—Wellhead /Tree Schematic 31 • Attachment 1 - Well Schematic S E7KonMobil Surface Location: Rig Nabors 27E Point Thomson RT-GL 33.4 ft PTU-DW1 (Disposal Well) Central Pad,Slot#1 GL-MSL 8.6 ft Plan 30 RT-MSL 42.0 ft Insulated 20"x 34"129.55#X-52 Welded ±155'MD/TVD O Port Collar:500'MD/TVD(Contingency) Base Permafrost:1,797'MD/TVD KOP: 1,825'MD/TVD,DLS 2.0°/100' 12-1/4"Hole EOB:4,325'MD/4,020'TVD,Inc.50° 9-5/8"53.5#L-80 VAM TOP KX 4,900'MD/4,389'TVD MW 10.0 ppg(WBM) 151 ill (.r OG 75:4,979'MD/4,440'TVD Planned TOC:5,024'MD/4,469'TVD (500'MD above Upper Confining Zone Top) 8-1/2"Hole Max Inc.50° 5,524'MD/4,790'TVD Upper Confining Zone 6,053'MD/5,130'TVD 4-1/2"12.6#1%Cr L-80 VAM TOP Injection Packer:6,960'MD/5,713'TVD 6,990'MD/5,733'TVD __ __ 7,040'MD/5,765'TVD r l f Inc.50°Az.220.6° l � Injection Zone Contingency Perfs 1-1 8,638'MD/6,792'TVD 1 Perfs:8,639'-8,659'MD/6,793'-6,805'TVD 7"26#1%Cr L-80 TSH 563 � 8,839'MD/6,921'TVD I, MW 12.1 ppg(NAF) • NOTE:All depths RKB 32 • • Attachment 2 - Geological Forecast Log EkonMobil Alaska Pt. Thomson Development PTU-DW1 Disposal Well >' CASING Surface Location OSIZE MUD Easting:468248.7 ft US H G FORMATION TOPS OJ WEIGHT Northing:5912923.0 ft US W2 MD/TVDDF ft 0 CRS:NAD27 Alaska State Plane,Zone 03,ft US G '~ I- BIT SIZE DIRECTIONAL j PLAN RT-GL:33.4 ft GL-MSL:8.6 ft RT-MSL:42.0 ft a::Q::0 20"x 34"SET @ CONTRACTORS: .••:Q:ia; +/-155'MD/TVDDF DRILLING RIG:Nabors 27E • .:O.;Q MUDLOGGING:Canrig b0 : ::0 LWD:Schlumberger • WIRELINE LOGGING:Schlumberger c3:':.:::Q WELLSITE GEOLOGY:T8D 1000— ,O:.0.:]Q o::Q::i3 = Q-:o::0 0,: i4 ;0 -Base Permafrost 0: : :A S =1797'MD/1797'TVDDF ••b:0 A KOP@1825'MD 2000' : o O cx y� m . 1::19»' *.. : 10.0 ppg -fi Q•Q. N WBM 4::. :9::.5:> g 3000'-= g 9 m _ 0101101.1411 Lu - imiA:•:•:•:•:•: '67 _0 N 'y lY 4000'. 0 W O v EOB@4325'MD/ 2 Z n 4020'TVDDF a) 3 12-1/4"HOLE FE PROGRAM C C7 LWD:GR-RES(via arcVISION) aa) 5000'.OG-75 9.5/8"@ 4900'MD/ -.4979'MD/4440'TVDDF p 'TVDDF _ J J J { .Top Upper Confining Zone LL 5524'MD/4790'TVDDF ---- 6000'.Base Upper Confining Zone -._---- -- . -•6053'MD/5130'TVDDF - 12.1 ppg - 'isi A NAF w x 7000'.Top Injection Zone =7040'MD/5765'TVDDF 8000'. 8-1/2"HOLE FE PROGRAM LWD:GR-RES-DEN-NEU-Caliper(via EcoScope) - = RSS:GR(via PowerDrive X6) Base Injection Zone Wireline:Sonic-Caliper 8750'.8638'MD/6792'TVDDF � K • v 0 Sand El Permafrost `/ `I PTD @ 8839'MD/6921'TVDDF , 7"@ 8839'MD/6921'TVDDF D Silt n: Clay g Gravel Updated 21 November 2014 33 • • 1 .71"V'y me I. `$,pp`$$p.p$`$p`2,`Lpp�.`pp$`p8`p$,p`chi.`p$,$$,'2p`p$,p`p$, p2p 'p$p`p$ 'pp° : p1po1g1C[.�l 1;-),IcP `°`$�.,popppop$pFIAwSey.Fiul^`r,$Apapm,7 F'J,3 8888NNNNNN 8888NN N N N NNNNNN8r.,;NPIN N Nftti NNNMMrN'iMMNM 3,5;.V V O4 V V Ow,�,,.N..N....ulu'14'104'I... , ...........00.......0.0.....0..., 'Q T" V V V V�V V V F T.",,V V^V V V7OV'V V 77Y V,,•-•r � .D (A(GW , 3 3 3 3 3 3 3 41 222222222222222222 8 2pp3N N N O33al'D 3hS;;y3ry39D 2 q2,2:2 A 233pV 84823p242ONa~1 $yN2MMNNNNM2NM44MM4 N NNMMMNNryryNN4NNNNN4;wwww"wwVwwM"" .5 ............,9,52$2,.2..;_,..,9.9.,,..,9 o 0000000000000000000000000000000000 fO.g!oo9N19-19-to-nO.no OPts-TrOlO h R1P-OP•000IO-F19P•P0-o10-lO- -IO-P•IO-1112,0-P�IO-PiaPP-IO-I--M1 zzzzzzzzzzzzzzzzzz z zzzpzzzzzpz pzzpz�pz lz-zzzzzzzzn pzzzryzzzzzzzznz CN000 O^npoppr,ph rp'I rs:NI Qrl,q'p...,'.pp ( I I-`0(N0(000�.1..-,Ui,lppDohi,V r",,�tcOpp1,.C-mnry'R 003I44, rN-Voo`Oi,m A-7 V�7�rJ NO ry NYcJY NanCl? A v v NNNCl N NOI[Uw V W MOM8 W'8 2(OO`-.2t0 V)N1f1 a V.p r0f N ZV V V V V V V V V V V V V V.1-4.V V et V V Vet el.V V V V V V V V V V V V V V V V V V V V V V V V V V V V (4 p jOpN0p SSSSO0000 oCO SSO o 8 88NNVNW^pp.eOl.�lf-Qu-1^.^y 0f3.f-N0W.TONDOh W ND1V NM NM ui el � � 0. D � 0p r1N } NNry4p 1,-,1.1-1,../Q (yp44NNNCINNN4N 444 �8NNNN)M11N240,NNNNNNNN NOI72 2800N51O1NO(O0NP,2AA,112 (j 8638822T,8282011888228882825188f8225% CD f,RI ppp pp pp p pp op pp pp p o �j pp o a o 0 o Opo 0 a J 4 0 0 0$O S S S 8 0 8 0 0 0 8 0 0 8 $8 8 0 8 8 8$$SSSS$$g S H 8 0 8 8 8 8 8 8 0 0 0 8 8 8 8 u 0_ 00000000000000 000 6 OONPlN Cd NNN NNNN N NCV N N N N NPI N N NN 4 40000 6 O e .... . V $ N = &88888$888888858$8$ 8 88$ P12'.r4.f2:R8,2?N^u.782r S�r] p8p 8 pO NM<R Pt.$MIO-81c M, • ,i �� 6,6 o 6 6,.• y i+r?n",agglaao vn „Xiw,nl 2� 62.v,2.rYy�O1l .C4v^ UO o N `- o ? , ,7NN NV/NN 7haOl uyF.O 0.NT .OpNm o //V Opgp ^, VC0OpaS 2S§ V q 61=O 0 •E 8$8888888�',8$S88$`13, 8 8'81u1-'$,cw1Y(°d,1=�a21° $�11.ao(4.437. INIV••C 1r4129�rr'1. P. }l a. • O 000000000000000000 6 001iiq 0 W OOi1 M O;o V. a 0 Oi �Vp r N p p�t` Q) L .. z ' .'rJof 1-pPIN 8NN 8N fo-7 10 ry4 O:: OW $v ^�w i ,U ase v g 9) E.W g >. 0 b V c 7 G C QE.Y$ "+ y w n a a Gam..Q t, T u UU 0p0p0p0p0p0p00p p p pp ppppp pop�a Q� pp �1 V p O U 00 O y- j V Y.a •• V Q PJ VCV 0 .N Cy O 7 W r$88888S88888`888888 8 8 82X?2,s ,s:11^^1YOlr7 e78O$V r$NBCN^j Pf n�M�M h O O(oD,C-,CO 73 W o V,, C G O N ,4 N d 60 N U ` i 75 y 000000000000000000 p OOON^N N 1^..W Va PCl1 ppOOH�Iw pl.M PJ 1f1 N Net Of�p r101�y OIM 11.) �) q y 9 } Nn OMfp 01Mh NI-NAMOi U1 -fIDN�NOD Il11`7 w-cO.D W `n O!Il!D E C.,0 > O g,0 g 0 2 > , O „--0,0,0‘00.....,,..000-,,,0.a- V ti F V Le.b "1 U _ N C f? 2 R00a I'0 ' c g141A11g1 13 P 2 ^. y '`, upp 000o0o000 8SSp0op.cBr/p1�SVpp4P 8 pOp Rp1Np$ r1h;p1lp1 V y2a0 MM(o".%)., 0�pp7n1CM }$M�pN1r�hOyCMy<pO O r0_ 0 Q ' 18nqW . pN nNi47-7a 3� V ONOyN 'ilpMia°2Ny`� R 2 1CNN INN M M M VVV Va Nro M • -..... a. c^` e+CS$$888888888888888 8 88i,u2i°a'oo,.2ioMi2ru°QWrymc,rioo8m°+°u°Iim 11;-,$v{fv.�i,tlO�3rN82w W ,— , 0000000_ 000 09000009 t- 0N W Of Of 0I-p �p 1 0(0.—V f-wt N r/D_ wl"MtD AMO11-(N(0 V Oi .- X 5{.�SI"r:- 11 I?S 5 `•EwJ3 A�j pfPa1 Vua{ let.i8A`�'§ C.r j POZi � •1a ”'� A.. NCiNNNNNNNCJ.+1.�1�th tlS� �MM� � O V V V V V t 6 U = Sri a_ ,.....-69� CD -1—• R$ 3 8 3i� �5 3i 33 3i�i 33 r 33 3i 3 8 8 3i 3i 3s 8 3i 33 3i 2 i ,71 - o ,0 m • =.G o c. cg--F .y yyypq 8888888888$888888 8 BSu5,J5i,l5'i,5u2i,5144,.,12u� .5, .8 53i u4i,22.8i.5i p$a$p$p$p$ N 4 NOS76 Y. - O IT1 0000000000O0000C1 OO 6 00,1 M Nl-01 r ou1t di f+l n Y1 AN rl A g 4 MV a a s 2 s 1411118 N N t 3 {u}C1 3 o a``q b,. p 0 fV fV r1 rl 17 C q OGoI- s8 r CC 2.82,9."'Pi ai §I(-1a6g -'P,u' 3zz4o ri 2:Z88882S2222188828222 q 888888822288822288888f3,9222.8282.28 m 00 X C 40 L 6 - i4.1 CO ibl 4 44 m Qiie, ' U w 0 A!Jl7UT 6IIti g o' o a a. z o a c c 2 A c gd gQ - s* > >aSxsi2 d £ ""g�1 w 8 8 k. k.O:U W N5.pa ufllll- UJJUU > 0 W4 Y • • 4QN47.92A2 * VRfOIONM 4 410PTONN>ulWI �NNN41gAgifg (`�+ f�'f�ial1*.; v ea4 M .c,at)1Npp�Vppf sV)•)41 e.r, {per(1YV)1VDO 1100 rCDD 11,00 4444444444 W,O4>,DCDD uD(00•G,DD(00 1too ttO t1te.40y sRO • t(001100.D�4DD�1p0 VV:.�tDD 1,DO WWW tVDD �(0 RD(1001(107 4 4 4 4 4'Dd'4 T 4 4 4 4 4 `t ^ 4 4 4 44•7 444 4 4 d 4 4 d?4 O O d+f 3333333 3333333 33333 3333 3 3333333333 3333333333 3333333333333333 333333333333333 3 q8N28Nm 8 pnfyaO k Swg^N1S)01f ;.4. gNW :O&IAp2OQ;AR q DO N , •-rOO01aD p aDh1`400 I( `644'6'`"''''''''°6pVfV)1AMANff1AAAvnAvVV> pSSW 3 .„,...0... p 0 0 0 O 0 p 0 0 0 0 0 0 0 0 0 0 p 0 0)0)of•• D>a O)01 CS 0)OI Cr)01 C)O) 0) C>0>01 0 0 0 0 0 0 0 pn. 0 0 0 0 0 p 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0,- 0 0 0 0 O 0 0 O 0 0 0 0 0 0 0 ZZZZZZZZ Z ZZoZZZ 1Z.� ZZZ ZZZZpZZZ Z ZZZZZZZZZZZZZZZZ Z ZZZ Sphh fl Y 2 Mt•NN8 1+ 0 Q N i''. 3.1;;N v f) C01N z-®: Oia4O 00144 A�01 g '.)01411 ((yy4AAtON4 O U)DA tp ip rp [app �p 888000 S6 {p g-4,.14:_ 04444'044 4 94449 4 444444444 d 4 44444 44 d d d 444 d 44 4 444 4 fl10 MPO M 0� R 0) 1f/ °-31V1;,.))N 0 4 h U) N 01 09 ID 0 0) COV1 4 co pp4,� a�Vp11A tD ) I) SD 1�1{h0�1� 05 l'.42 yp aD,`:,1`.3;8387-'a�pp .- 1h�9 pypy 0't 09 4 V d Vp/V1'1�1Q'y1 SO SOOy SOOy{SR�y `i!�0�' 1gAD1 aO Q� I 2�_j `V O>Pq C010)ON+S W A 4 CO�l CppY��p�� 'S 0 00000180 pp .0000•- SO. §.... > 8OOrn I §8a m $$ u/N ul V>VI VI ul 1A f/1 N 1A N 1!1 g N V1 Vf s V/N W Vl V>VI Ir, N N 1!1 V> 2 N V>V>2 V1 1A 0.2 V5 2 f19 2 V>Vt a >n�, 8888888 8 88888 8 8888888888 8 888 : : 888888888888 888 Q) 0000000 d{ 00000 p 0000000000 p 0000- 0d000000000 p 000 aDo f7fD fnA fa oo9P 8o4 N Ro@y1f�� 4yPry m N s�oo W1,34ap V>10 NufaDN ' S �•.� 0y 1. ,..,').06. f0 Znie 8�!N p • 01 0 1D� Sp fJ•-01 1�(O 4 N 01 R Os 1D V CJ�. h(O 4 N�0)R 1D 4 N 0/0 4 ~ N Z (^{ N N 0i Oi � ap qp �f�n nn h u5 Vi ♦ 2121 1 p�pub ONppyuy9 ,�( pups pp Si 3 4 CI 4014 O) .4 s 4 E. aAD 0s— ®m , , . , •-f. f. Fj r. 0. „ . eA N SO tO SO R SO ,.°) . . '1 4 d 1, P Spy fi FJ J..J J . ."7.r..-; NCiN J N 2(n LI Cf) o a\ w1 p�1�.1/'1Sy 4 p�1^ N O R aD(D d NO p�p ry(y C) N A 2y,09 s 1�N M p�ANN 8 t+1 p IP; .5 r6 1D/D O W A Ol O N 4(O 0 h O! �N h 0V aD 0 CJ 4 1D R T' P1 4 O f0 a0 O f 01 fA A p�N 4 tD a0 YA 4 L aC fV PD V1 f•f f11 fA ul O+ 4 CI IN N1 C 0 CNAIs3 -,m31 m El iagg�'a F X33 ',3Pp *F1' N F133 Q1 U,0)A N N N N N ,-1,..,-,,,-, (.,..::-,,, ,,,,o1 f�f? f7 0? O O ^` y a p aa yy 44 yy11 ((pp((pp appp 0pl/ pp op .p 1�y7 �p ppyy�pp �) c 4�O f0 NaD 4 f19 8V1124 h O1OCl00 V 8g48$7ii 4 P •i": •Pg X S u'i�h MC)1An a.° 0. gi'A A N G 2228 C .j A N1 0 {"1 011-2A2 10 Of(upj(Np SOp>SAp fa4`pI Ol,q�,j f.y Ol N 1pNy 10.)1 fy,j1 1u�D) Y7 SQDO (pQ�p>, A 4 y ,i N ry 13 le )O w IA` m '` h N f74JC•! N i^/l`JR;i`1t+1 O Mf f�f f•1 1'1Al+1t0A'f 82 V.7O O K a 7 4 C `I-Ci N lJ l f' _ 0 I 1 p py p p p 1p 4 0 /i p p� O o ap p 4 p a-F• p 3,1 C)7,1 2 p :--gt.-:4q, - p NP 8M(NO C1 V,4i�O p f`I N ^@ 100,o)NN88f+S 10SI.TV p r•8`.2P— V �p9 R 1��D 4 (*' _ C� 4 (y�p of C1 �� }1 --yr.., t��(lt:4 4 Ph�-�aeO-pvl N to �W O7-.1>e4(1. �i E 0 �Mul- C 4N fn�� 1P�TOSS^OO FY Y22 0 :-6 Y. p00Q 4 4'P 4 7 4 4 4 4 4-'2 N V1 u/1fi N Vf 1 h LA uulIR. SD SO fO tO tO 10 10 45 8 tD 0 S 0 C W W E 24P-8',-)'•'22 ppll pp pp �epp aa pp S(pp p pp�� S1DD oo �fDD aa CCyy ppd. o , 8 r M m 0'Ai(q` p N A 8 A 2 8�4 1M2,0 8 f1 N a40•-4 f0D o)N ffA/OD B f"'i{O C1 •Af p r."21:2 of Q p PF) CD iNN1iO� ' a31s' G `635iR 3E n 33 3ig7i 3I idZE'6' ,, 3'33 2- M$q•yy tl 444 VV74 4 tl CS r }1 yp pp ap ap Qp ap{q aD ap p�0 ap pp�,p m ap pp ap ap ppm qp op qp pp 0 pp ap ap SO pp pp p� ap�D a.... 44 2 IA u1 . h u5 SA N N Vf 2 N N N N 1A V1 fA N N.Vf h Yf N N .1N u1 N Yl N 1!1 fA fA u1 of u1 h u}N. g G- §88* 4 ca o f s 2 8888888 8 88888 8 8888888888 8 888 88888888888 8 888 $S 2S4S 2 2 2$22S S; S2S�SlSiS�$SSS g SSS S2+ SS$1RStSiS?S�S�SR2S g SSS t., re 4 2888888 Qpo 88888 x 8888888888 ; 888::888Q8y�8888888 ',.{ 88Q88 4`2�g'8",)I,,�' h '14802,". 2 88811101§§ , g1-.1—z.o;!-'1:-.,M.0w2m m 2 gm2 g 4 ,. c P P Q yy 2 2 m ~ h[Q p 6 a O a 1 8 a ,..I I'! N A }.a V, 1- Co `. cO 2 0 0 U V P V 7 V y N 8 j jQ c� cQ fn �m /Oachment 5 - Wellpath CrosipectionView • Sclrlumherger Exxon E onMobil BCtrehoFt: ---Wil: ;Field: Structure: PTU-DWI PTU-DW1 ' Point Thomson PTU Central - GravIty�YwuiWS:Panmaura L wlier HAW Alaska Sus&Pfaar.Ions 07.US Ful MSicsleaaoua .. ----- 1........ >•1e {1.171' o4i4 al-Dec-20m tai: 8 T410/IV arr7Nrni: SS1t4lY{U9 am Lode- 4.11M 'vim: Wal 1VDFitt. "I" ( rieSe(aaltaOaeMal 1l.Iltr For te" 9rsMM F1+ 1K283 MAIM in 701414 a0M &WOO 44it46.74V4 04e,Rea 04#000115 Rini PTV{Mn io*i 0 FRE 71137' .,,0 M00 Top -Y Go' 000`Ind 220.SS're R k1a0 9 v4eL +� True Poo-n Tot Cort(11.4sT 20.4621 1350 400010oc(20 424) Grid ccnw{-0.240') KCM 1825 MD1825 Top 000'ind 220.58'x: Dvlac / 47()0el Base Perrn.3frost (1797 TVD; a'+oo,eG.,% CxI00Y Palen MO OKI KIM TVD MSEC 11I.),Sr4 EMPAY,-) OLS RTE 0.01 0.00 220.58 900 4 00 0.00 0.00 &aoe Peons root 1717 CO 9 V) 220 58 1797 00 0 00 0 00 0 0) 0 93 cop 1625.0) 0.00 220 79 1827 00 0 00 0 00 0.00 0.00 EC{ 4325.190 5000 220.59 401956 102)34 -77720 -661 72 200 %r 35,0'Csg 4900.CU 50 DD 220.58 4383 ifi 1463.81 -1117.73 .25Q.76 DCA 00 75 497910 50 00 220 56 4440 00 1.524 40 -1157 75 •991190 0 00 "5 _vir Cod nn02oni Teo 1523 6] 50 00 240 50 4790 OD 7941.57 -1474.54 -1263 CO 0 0] l 4per Coninng2Dne Base 0012.51 5000 ?20 58 513100 2'14 71 -1762.27 -1528 42 000 n]ecfon Zone Top 7040.4.9 5000 220 5.9 570500 1103.:48 -2357 02 -2016 02 0.01 nllcbon Zoos Gaze 853616 5000 22058 678200 473741 328656 3615,13 404 Will TO 0839 Ctl 50 00 220..58 6321 10 4481.26 -3403.41 ;2919.22 000 l'' \ o s., Erre: 0 , 4323 M2 4020 Tvt r.- 5000'ircl 22D 50'az 0) �R°0 1023%lac v 4250 \ Z' _.._.._.._.._.._.._.._ ....._.._. ..--......-- . ..�. ,..........._.. -............_.._- ..........._..W_. .._.........._......................_................_... OG 75(4440 TVD) 9.5.5-ca11 4901 MD 1369 Ty'D 50 00'incl 220 56'a¢ I 1464 v11410 ( ..,,,� 04.0f_000 20M Top 51()0 7040 1.113576'5 TVD UOpo CL0Mfn0 2:one T.54 50 W'loci 720 58 r ac 5524 MD 4790 TLD rr 3103 rat 50 00'00220 58'az 7942 vice i� 1.000E Conking 2000 eau `1i\ 8053 910 5130 Tot) 5050 5000`mei 220.51'ea 2347 esec {{toll TD 6639 MD 4021 TVD N't. 1 0i'id 220 58'az 440101 o vast Ni\I Roo PTU-awl(P30) / NKadlon Zone Brae 8636 M3 6142 7547 r 50 0D'0 cl 201 50'az 4327 vane 7050 0 850 1700 2550 3400 4250 5100 Verlicee Section(0)A,zln-i=220.582'Stole=T 970.0885t41C+€t3E4:10(01)Origin=ON'-S,OIE-W 36 •achment 6 - Wellpath Plaryiew • Scliluinhe 'ger Exxon E. (on Mobil Horehige: — 'Well: Fields-- Stru e; PTU-DWII PTU-0041 Point Thomson PTU Central Cow1t$&PASNide Puamstan NAW Alaska Sena P3. L L00110],US Fast Riecofvrous *NM H1a 01p..41.1TM Ost4 31-Dsc30ta Laua 74 tO 2330 natMe $11124/30412 43441 Cotw 42401. You slat) T W Re. Mos TUFA/ Atom M9f1 71.412' FFa "nasal 0re�nts Flt w1N�9a1. v'lldaaal It 011106 if 0041 640110 461211$410/11Odd.Coos 41849$1144 Rant PTU-OW104118 ot EMO IS)save-1567 7526117419250 -3270 -2800 .2400 -2000 -1800 -1200 -066 -100 8 160 RTE Tme 0MD01VD 4.:$Fi010'nc1220 56'az A., 11=0 E-9 f • 0 True North KDp Tri ow 214-`T 20 4,52*) 1021 MO 1823 ND ,./"- / Me.,)Dec 220 482'. 0.001ec7 22093'az G110 CON,1-02401 N-DE-0 / -400 f Eric fffj,/ 4333 F/01020 T OO 50 OG`nc122050'az ff W-777E=865 4300 9-5+11 Tv019/ /f 389 50001ec722093'ar / N=-1112 E=11'32 +` A200/ z ne / a {f upper Gering Zona Top $Q / 5524 RV 4790 T41 9�. / 1000.Ins1220D9'az i rr 14..1475 E=-1253 -tealt Upper CanfmngZone Elam f 3033 MD 5130'MD 50 PP 01220.50'0 _ N-1782 E--1327 / 4, / -2000 !{ eiectronZone Top 5(40 NE?522ci 195 TeD 2238 5000' 038'x2 _meq / N--2357 E--2019 f f / 2060 I rechan Zone Base 0836 MD 6792 TVD 5000°ind 220.56'az / 41-3207 E--2615 Wel TD 9639 MD 6921 TVD 50.00'wc1220 38°az .3200 _ r _14--M0)E--2915 / PTU-DW1 (P30) c t1ol Fetes Critical Poiret MD INCL AAAA ND VSEL NOMS44 E(.)193f4 DI.S RTE 0.00 0 40 220 56 4.00 0.00 000 000 NHPemirtrasl 1797 CO 000 22056 179704 004 003 OOD 000 KOP 102'00 D 00 22010 1625 DO 0 03 0 DO 0 00 0 90 EOC 4323 09 50.DO 220 38 4018.75 1023 34 .777.28 897.72 2 90 9.5rB-C1g 4509 D0 93 03 22050 43816 1463 91 -111173 652.26 090 00 75 497910 50 00 220 513 4444 04 1524 40 -1157 75 48160 0 00 LIPPerCCnlrirgZaneTop 552300 50 DO 22056 4790 00 11910 52 -147454 -126303 000 Upper Confining Zona Rasa 4002.54 70.00 228 38 7130.DO 2346 71 -1782 27 -172652 0 00 N}1c4ro r Zons Tap 7049 33 50.100 221318 7759 DO 3703.48 -233102 -2918 32 000 iitpattton tate Dace 0418 16 %D3 22056 0792.04 43833.41 -3288 58 -261513 0 00 Well 110 86)9.09 53.00 22056 0921.10 4481 26 -3403 41 -211522 0 00 37 Attment 7 - Anti-Collision SuOnary Report . Sclimbertier EOnMobil. PTU-DW1 (P30) Anti-Collision Summary Report AnOOns43 O31tt0-24ht num. 'ANA.1,61:3 2214-1944 /eWrats N+rn._.s 5270 rna1 P44* C3401t. F4h1r4". R1/441.16.u'taim..0r:1 FTLILWIIP901;3220Plow fain. Platt Timms., Dlsm!nom,tis Etta,1030M4 Dapth,11;. S6uCWrt. PTU 0wtr Runt SilL DMA Ar3Coli son 8Nn vS'J522 &k.A. likal 1 MM Pb. M ISM!7l i n&odittWle.. Wyk. PRLCWI Version I Patch- 28.672.0 Scriheir. PTU-C'w1 DotabasalPagazt heaiha t1tA.LNt'l0.Pwira Therrrpra'n...SOW Inti!DM 2S Sea t MCI WIMP: 0 OM-2834 XS ar4i4+M I.Fria*Masa 4. I-C 95 co0016 00nr ll'{:R 22255 4.0r.11 Mitt 7073200031 Surma StallafiliadSOLOSitia WNM,ad 7Htun•N!ter- Gabel!rite 413549 s n 50402;003!Ewa Dead.*Barwtls-Ddrni1w Ptam-Darr Et.*arerro Mt.1.11 a are rrtAv pars -Al Ramat S 0.013*Am nu De-Swett rt rat it a t.a.cru.-Ai 14;-eta!Purasort r,D."-ul saes in a twat.* 0MutT*alaclimy >ttprrNbnci Alfas Sas. Cunbu41njt RYsrwtatTtalrcrNlr Rssktat* 3,44a Saws MI I EAU PO'Dot.(NS Fara SW* NOIro I TVD It') 4.11 I mow I Mal:w L. ..P t SD 4.( _,1 b' ID'7+( !SS 14 7143 VAS•19 001, 1433 143-29 1113/51 IIIA W Stell lel as tat ea 2301 IMA.to min; !ss ai OMNI ilaalaH3.60.1 tauw stow Itt200 17a1 2414 406-to m!6y masa !mats tIN6-6r ®504 5404 624201 bit 14152 0071.3. 445041 4r01-11i 111101.0.31 arl r ar 1343 301 72 3624 210 I40 S 099 3. 43!0.11 4110.41 0161.031/ 111314 N 14 31311.13 !3!4500 1461* 0511.'10 4514.Zt 420..73 1133444.+63 1=331 Min !2016 44317 IS I'91 to 09,13. 7210.7 4SSIM 01674321 10352.04 30401 maciza tL.4:1 093:57 9.7317.,7 419x41 tM60-61` 120721 12171 1230100 1244am 156.40 09170 523..7 976::14 0131447.61 120344 IMO 12/4425 0^01;3. 106744 Mini tt1.IY4ar ,=.11111.411 ,U..7 ,.o -.CM ow1.4o wa .044661 arian o or 3 y l►'SrAr,"� .3' ' Moo .. 3251 VI;:.=ME 11.13 awl 10 mlm; ma tit 37575 116431 MEW 320! 27 - . 0013 OMS•10 I Ir SSP-'3 MS11 klka; -`. nal I 215 to 61411 4143.1111110/1 792.'1 09.11 ItO.P1.04l3J 3251 234•.: ! MSS O.140016} arab/ 0130: tyi'It i UII an Si 11111EZU 5900 MRe.IA CRI my !an.".3 ratan Moil. .',1'.1 32a1 111111= 222• Mr.C. !40S.1010 Ina r$.B ramal tares MI 1 NI W 20 505313 •G4.•.M:fia 0131.X, 451013 4164 M Mrs-a0-a/ 1011101 14304 10013.30 1W11, =MO 0W1;3. 13S1 4910.27 44•11-12.11' 13370.34 Manz 1382.la 13413.+ 0911:3. 1041 51 573150 M347.q.6r m „maw. rl 03123+00!hi 3 10 11u+61 ,.° ,., n 3251 IMMMEIE Nal Md.Manisa 032 CM. .lily 45001 325! pt 41530 114OS W6.I9 III til! SW 1C., 30'310 atasT4TtCU /alts scat�tqrEE 431 It 4713 W18.la00ltr} !S13.74. 1190.99 01W143.CCU 41.1015 325! 47514 3t.71 13220.19 It Ing #'-00.70 1593.9P tM0.142.00v,S $1105 .3251 m aL 423.25 3636 41At•la It In') ISE 'welt ilasS14.00U slim sum -I It 99 14 22.• 0701 SC 2756 9} 171313. Mt/4U-3r MUM MI .1!.32 +043.® 41311•- WPI 0701.5? 44801 43341 11.11601-043 48413 71'14 413210 SW 114 •3.1 09170 ass c, 4!,2/"13 113413.0.31; 190155 14133 33114111 3504 173 4 091:10 4214.1 4301 53 0!/6061 500461 014r 3211 65 631!1 121 In 091210 ass al 443!.701 01630-61 10715r 1074 33171 @3P313�1771 L 0315D 1=4 451'4 z7 91644]6.6/ .63420 /0073 311471 110 1045' 091:1! 9730) aecv so W./y-5r Gabe! !am SIM73 314:111t= 091-51 5554 8 4121.8 037 MEI Zi 1342 31775.13 32511. 01...0 1 03'1.3. S 4 404.70 601-025/ 10+00.41 17113 11711.41 1031!1 13141 091:50 13.3 3 542710 01►6040r 1101231 1312213 1031343 4'11040 07.40 013150 51121.2 543142 10 1.I1.14.433 Inn!3 I14}psi r1n: I- nei " " .'0' x.31'4 MEM MFr5 r '440-1II 00ln:; t ,3 '47 00 7 IN% :10"aea S VJ 71 :33054 3413113 MAA.l9 CS leek 25715.. Z.415 10 I 52311211 3,:5!EffIrE II=Illtila 46k1•IIIm in? !ale:SD rats•W MrPh 38 , •ttachment 8 - Traveling C . der Plot • Schlumberger Traveling Cylinder of E onMobi! NoGo Region, EOU's based on; Oriented EOU Dimension TRAVELING CYLINDER PLOT Client Exxon NoGo Region Anti-Collision rule used: Minor Risk 4 Field Point Thomson Separation Factor _ Structure PTU Central Well PTU-DW1 North Borehole PTU-DW1 PTU-DWI(PM 1 PTU-NAat Pond 30,41- 360 0 10 Date 28-Jul-2014 340 20 Tnr. Pt i4,ar5Wn lint.3 Gnta 4 Ala? P111.19 s,7� ,. 70 {" 39 R J PTU-1a ,,,,\c„,„..,,----4r— 4 '''''s"...„,,,,, Tru6NOf rth 32�' I ,r 40 Tct Caw 0.1-.T 20 452'y Mag Dec(20462')1 Gnd Corry 1.0240'y 310 ff, N, 50 .....\........,,, 300 � */ t 8O • :+cy BO{ PTU•16 A "s r ,. s , J , . , 290 l � 70 - ff r r;1114:44 . "`I 280 1x \_--- c, ^ 80 I' /II —I— -t.-,-..,:y i "I''' •: .:,-;„6.*-, 0 i 270 _ + t Ilk 90 i "-' 250 -"\ / "4-, "`- .',.•,'' 1 , \. -� PTU-16 , • 250 ',r . __ 110 ,r .� ,,,, av 24011 �"/--... H ` i( '`) 1211 • �`�, - y 230 ,.. ...V 130 220 , 140 219 -±--,- -- 150 200 I 160 190t80 170 Wail Ticks Type, MD on PTU-DW 1 (P30) Calculation Method: Normal Plane Ring Interval 30.00 ft Azimuth Interval: 10.00 deg Start Depth: 0.00 ft End Depth: 8839.00 It Offset Well Count 4 39 1 Attachment 9 - Wellhead/Tree Schematic . 53.7 A I. ... ? rni -. _ .(u1} , • - 1 -irk- 1 tifillk: ; 1 ; • .vx.f4. • D I IIl_ : 1 : _ . _ --0 lir I - i Al. OI 51.2 r ' rml i.� • 159.4 } ' 4-1/16 API 5K (RX-39) 1t/ -__--- • 7-1/16 API 10K (BX-156) \\a�� j — .wii 7....-------- I � . I _J 11-13/16 API 10K u�� ',��"� 1 -13/16 API 10K II � T l r�rT 'I.��u: I'eTN 'I II4-TN 25.0 - .. II ,:--- .:.I�, :I6 17— ;� I.',' - III`.',;, _'_ I - g ' 1N1/ I 1■1 47.4 '` ..J I , ; . ,. 47.4 .47 j 11 API 5K (RX-54) = TYP ----------->- ../F _ --J- r -- - - nu \ ,% — F.,,_ ===. ; ,- ; `1. 'j i r?j��'06 '17 , 11 - 2-1/16 API 5K I.I,�I III� ._. i ...1 l 42 1 �� I II/1J' SIIAi .rir� r . �1 1 ! ii,i` ik0 I IIS- � 1�cJI,��L .� � � �►: 1 .11\• 1�•�1 = 42.4 / 1i1 I. ' 111 I ✓ I 43.7 It_' !I~ PA i, 43.7 F- NVAC .,4:r , 21-1/4" API 2K 11M1 111111' Ii ir • i 20" 94# CASING U i I 9-5/8" 53.5# CASING 7" 26# CASING 4-1/2" 12.6# TUBING I.. ISSUED FOR APPROVAL APPROVED APPROVED WITH COMMENTS 01 REJECTED REV SIGNATURE: Cooper Cameron Corporal Cameron Division CAMERON P.O. Box 1212 DATE: Houston, TX 77251-1212 E XXONMOB I L DO NOT SCALE DRAWN BY DATE POINT THOMSON DISPOSAL WELL C.ELANGOVAN 25 JUN 14 CHECKED °U 20" X 9-5/8" X 7" X 4-1/2" PROGRAM MAREES 26 JUN 14 APPROVED Rio 26 JDATE UN 14 W/ 7-1/16" 10000 'MTB' WELLHEAD SYSTEM INITAL USE B/M 2236000-40-46 1 Sor 6 SD-031115-40-46 40 • • D O n n : v —f CT U) D_ Z in w v co -1 c 0 -P z oi C 0 n m ._. co rF X LA . n -0 , cri 0 N� v , tn i inftt/ (i) C t r-r N ' :4tri D CO 01 if r- D f a D C 0 0 ..3. C4 0 ca 0 CD n 3 m w IV C LA.) - N Ni O N • • Schwartz, Guy L (DOA) From: Calder, Steve/C <steve.calder@exxonmobil.com> 1 Sent: Tuesday, February 03, 2015 4:06 PM r' ' h�C To: Schwartz, Guy L(DOA) Cc: Podust,Alex V; Rullman, John D;Inman, Leilani/C Subject: RE: PTU DW1 (PTD 214-206) Attachments: PTU-DW1_Casing Load Calculations Summary.pdf Guy, Please find attached the casing load calculations summary for PTU-DW1.We've calculated the maximum net loads for burst, collapse, and axial (tension) as well as the corresponding safety factors. In addition,the assumptions are summarized. With respect to AOR, there are three existing wells that have surface locations within one-quarter mile of the PTU- DW-1 well: PTU-15, PTU-16 and Point Thomson Unit#3 wells. All three of these wells are directionally drilled in orientations away from the PTU-DW-1 well and none of them penetrate the interval into which the PTU-DW-1 will inject within one-quarter of a mile of that well. Thanks, Steve Calder Environmental/Regulatory Point Thomson Project Consultant to ExxonMobil Office (907)564-3787 Cell (907)351-4538 steve.calder@exxonmobi I.com From: Schwartz, Guy L (DOA) [mailto:guy.schwartz@alaska.gov] Sent: Monday, February 02, 2015 1:47 PM To: Calder, Steve/C Subject: PTU DW1 (PTD 214-206) Steve, Still need BTC calculations for casing and a statement for 1/4 mile review. (AOR—AREA of Review) Guy Schwartz Senior 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). 1 • SURFACE CASING:9-5/8" 53.5#L-80 VAM TOP KX Burst Load Scenario: Pressure Test Location of Maximum Net Load:Shoe(4,389'TVD) Maximum Net Load:4,445 psi Burst Capacity:7,137 psi Safety Factor: 1.60 Assumptions: • Internal pressure profile=4000 psi surface pressure applied over 10.2 ppg hydrostatic column • External pressure profile="low side"pore pressure prediction of 8.25 ppge @ shoe • Cement in open hole reverts to local pore pressure • Nominal burst capacity of 7,930 psi de-rated by 10%casing wear allowance to 7,137 psi since the string is drilled through (per ExxonMobil standards) Collapse Load Scenario:Cementing Collapse Location of Maximum Net Load:Shoe(4,389'ND) Maximum Net Load:433 psi Collapse Capacity:6,620 psi Safety Factor: 15.28 Assumptions: • Internal pressure profile=10.0 ppg hydrostatic column (displacement MW of casing) • External pressure profile=11.2 ppg permafrost cement slurry from surface to 3,723'ND; 15.8 ppg Class G cement slurry from 3,723'ND to 4,389'ND • Surface casing strings not subject to evacuated collapse load scenario(per ExxonMobil standards) Axial(Tension) Load Scenario:Running with Overpull Location of Maximum Net Load:Surface Maximum Net Load: 298,759 lb Tensile Capacity: 1,244,000 lb(Pipe Body); 1,244,000 lb(Connection) Safety Factor:4.16(Pipe Body);4.16(Connection) Assumptions: • 100,000 lb overpull above buoyed string weight at section TD(4,900' MD) • 10.0 ppg setting MW of casing • Wellbore inclination incorporated through torque&drag simulation using EM Wells ToolPro software • • PRODUCTION CASING: 7"26# 1%Cr L-80 TSH 563 Burst Load Scenario: Pressure Test Location of Maximum Net Load:Shoe(6,921'TVD) Maximum Net Load:4,273 psi Burst Capacity:7,240 psi Safety Factor: 1.69 Assumptions: • Internal pressure profile=4000 psi surface pressure applied over 9.7 ppg hydrostatic column • External pressure profile="low side" pore pressure prediction of 8.94 ppge @ shoe • Cement in open hole reverts to local pore pressure • Nominal burst capacity of 7,930 psi not de-rated by 10%casing wear allowance since the string is not drilled through(per ExxonMobil standards) Collapse Load Scenario: Evacuated Collapse Location of Maximum Net Load:Shoe(6,921'TVD) Maximum Net Load:4,347 psi Collapse Capacity:5,410 psi Safety Factor: 1.24 Assumptions: • Internal pressure profile=0 psi(evacuated) • External pressure profile= 12.1 ppg setting MW of casing • Production casing strings subject to evacuated collapse load scenario(per ExxonMobil standards) Axial (Tension). Load Scenario: Running with Overpull Location of Maximum Net Load:Surface Maximum Net Load:246,666 lb Tensile Capacity:604,000 lb(Pipe Body);604,000 lb(Connection) Safety Factor:2.44(Pipe Body);2.44(Connection) Assumptions: • 100,000 lb overpull above buoyed string weight at well TD(8,839' MD) • 12.1 ppg setting MW of casing • Wellbore inclination incorporated through torque&drag simulation using EM Wells ToolPro software • Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Thursday,January 15, 2015 5:00 PM To: Calder, Steve/C (steve.calder@exxonmobil.com) Cc: Podust, Alex V; 'Davies, Stephen F (DOA) (steve.davies@alaska.gov)' Subject: RE: PTU- DW1 (PTD 214-206) - PTD comments Please disregard second half of comment no.7 below.The IA test is against the 7" casing. Still need to test 9 5/8"to 4000 psi though. Guy Schwartz Senior 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). From: Schwartz, Guy L (DOA) Sent: Thursday, January 15, 2015 4:44 PM To: Calder, Steve/C(steve.calder©exxonmobil.com) Cc: Podust, Alex V; 'Davies, Stephen F(DOA) (steve.davies©alaska.gov)' Subject: PTU- DW1 (PTD 214-206) - PTD comments Steve/Alex: I did a first pass through the PTD application and have some question and comments: 1) On page 29 the Time vs depth plot is blank. Do you have one with data.. not required but would be nice. 2) I need a as built drawing showing the rig on location with routing of the diverter line shown. 3) The 10-401 form shows reservoir pressure as 3450 psi and MASP=2850 psi . in the document on page 7 under drilling hazards the pressure is listed as 3250 and MASP of 2750 psi. I need clarification and more data on the expected pore pressure at TD. 4) What type of Cement evaluation tool are you proposing for the CBL's? 5) Provide an explanation of the BOP ram configuration(VBR range or pipe,etc) for the initial BOPE test in step 13. (page 26) 6) Should be able to grant packer placement variance but need to verify TOC and cement quality with CBL. 7) In step 16 you are testing 9 5/8"to 3000 psi. I bumped to 4000 psi (AOGCC standard is 50%of burst) ....You are also testing IA in step 42 to 3500 psi so you will need higher casing test anyway. 8) I would like to discuss BOPE testing pressures before assigning to PTD. Initial BOP test will likely be 5000 psi (wellhead limit) . Thereafter the BOPE pressure tests can be more in line with MASP for the well. Likely BOPE test pressure will be 4000 psi after first test. For running casing the 7" casing ram test can be lowered to 3500 psi. 9) I don't see a way to test the 13 5/8" BOPE to 10000 psi for initial test so you can shake out any problems with the BOPE before moving to PT-15 and PT-16. The lower flange (casing spool) on the wellhead is only rated to 5000 psi. Could do full 10,000psi pressure test once the 10K tubing spool is in place?Step 30. ( see above ..we can discuss) 10) Make sure you have X-O with FOSV(full opening safety valve) on floor for any casing running operation. 11) What will be the completion brine weight(ppg)? Step 28 1 • • 12) Make sure you give 48 hrs notice to inspectors on all tests. 13) Need drill pipe specs. That's all for now. I will be out on Friday/Monday but will be able to check my email or take cell phone calls. Regards, Guy Schwartz Senior 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.ciov). 2 • • OVERSIZED DOCUMENT INSERT This file contains one or more oversized documents. These materials may be found in the original hard file or check the parent folder to view it in digital format. • • TRANSMITTAL LETTER CHECKLIST WELL NAME: ( �'* _ PTD: PTD: ' ( "l 2--6 LO Development Service Exploratory Stratigraphic Test Non Conventional FIELD: f-74— ilk/1774A 1f POOL: / `.Lt"7,L4 '?'l 'r i z •l' Check Box for Appropriate Letter/ Paragraphs to be Included in Transmittal Letter / CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL The permit is for a new wellbore segment of existing well Permit (If last two digits No. , API No. 50- - - - in API number are Production should continue to be reported as a function of the original between 60-69) API number stated above. In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name Pilot Hole ( 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 Spacing Exception conservation 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 (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application,the following well logs are Well Lo ,n also required for this well: gg g 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 this well. Revised 4/2014 0 • CIC Cl) O) O , a) O_ Cl) N Q p cC L , , , , Loi >. ai E O ' Imo, , a E - O o , 0' , , , , , a°ya v, a 3' �, �, y rn �' . C, N, C, O , a) co U' N , , a . a). ^ , a) , off, , oS a, 0 3, �, N. d 3o U' Ca N w 00, m La 4 U, O, -F2, N, C C? .0 • �, R r; O �, 0 N• N, N. ° O. 3, o, , a 0.,0,,' c70 0 ) _a 4 W, W, W, a) �� ca N, a) 0, W, C °, 4- F', NV, VN J. ' f', t°. c 3. �, N. �y M. m' , cc , a c E D. a co cry, , N. '5• a) O, , a) , a). a), II — -.-.' N -, �, N O rn , a, c, N. c, c, o, 3 , 3, Va), co), 'N, 3' ai. E' 0 a ' a a° C �� o o o, °� Q •m' (a aai' . , ° - v' aci 8 a' co 1 a a) , C, , C, c' p, 'wk ., a U c~o, a' '4 G -° °" O• 4 N•ul C, N �, O, N' uJ a` O, �. (A, �. C, W. U, `, �, y. N. 0. O. O, � �, p 0/ U• �`, t3p • a) O �, C G G c p, O O, a p, �, U U, O, �, m C7 E y. 7-0:1)., N ca. s• �, , 4 O N N' �, II c, co,� N �� Z 0, t 3. 3. 3. ° oa __:(20,' o ; U. ( C, W. • o, W a, c 43Y N 0 ° € -(1-3 ? 0 t� — C C c 0. y "-Ox, 0' �, 0' � 1- °) � 0' N, (0 N' Q� ' co,, O, 0 >LII V O� ° Q ZLLI cn d' O O 0 Z b. N. Z H' m Z Z 2 Z. 2 21 Z Z 2 as W. C a. '0 N LU , , , , (6 U N. N• N, (0 tlD co. N N• N V) N. N, N. CO• (0 (0 N• N N, N. N co, co N' (0 (0 N• < < a), a), 0, a), a), a), a), a), a), a), a), a), <, a), <; a), a; a), o, a), a), a), <; a), a), a), a), a), a), a), 0, a), a), a), a, a, a, E Z Z; }, >- Z }, }. >-, >-, }, }. >-, }, > Z }, Z, >', Z, >- Z >- >- } Z, >-, >-, } }, } >-, >', Z } }, }, Z, Z, Z, to , , , a) N �' TQ CO , , , E , 8 , , , , , , , , , , , , , , , , , , , , , , , , , , , , C , , , , , , , , U , , , o ts, , , , , , , , . N v, , , , , , , , T 9 .N 0 1 c �, p co , , , , � O. , r U Lo , 3. o, can , , O �, �. 2; 0' I W N, ,„ 'C, O. N, U , pa'. N, , U, , .W..+ d. N, N s 0 ( a aE —' '0 �Q r .: N � 47,Z , t, C, � O �p > p. N. Oaw O , 3Oaa, � U7. N. C , —, (a �, � N � M, , N, Z o, cNc a2 w' 'a, Q, Q' 9 o, ° a ' .4 O, ' �' O' w, 3. N' , O' a ) >; a 0, E' a) aO O N u) O ' , ' O , 'C, ? N; N, , a , paC z ' 45. ' c' a , w. N, pDU. E ) m' 0 O 1 a) y ' y. co' O, ; , � E Ea C, C E; N O C C y, F= C O oSI'D' O , . , ) C C _2 CV � p, c � a '_ C@F- 14'QCNO , N .. NO YN, o � ' ' ' m ; ° �' , Z �' ` Qa — L. . N. a, O. as, N y I— o .c EdO' N; 0 �, a CCfa. .cL, a, N, ' Ca a) w, N. ' ap43Q 3' .. 07. a• 0 , • , , a). , ) c E E, , N. a 0 « a. co aN2, C aMNV0 O pONGa) Naam •33; am, , , N' ' � , O4 ° N4 'yN, o -2, as' O LLI O o ° ITI U O a ° maao ' o, oo , v m, @ a cO) , N .d U �, oc, a , No . pn a) N. °, E °, , . Y; if)' o 0' 0' a) °' wOm w NC dO -° dflyaLN ° daaaNU ' L5, 0y . L.6 J UL, 0, . N .13 N a (0 p , , , . ...- ) N' N ' c N, , 0 , c . -p m N, U as, EaOO, N - N' 4 M, y, a . �, C, c a, 7' a) N' a2 _ p, T, -0 2, Cy, a •N, O, O. O .. C5, a a cm .-0 : =a) (Da - ° ° U Z 0 0' aa -0 0 p, .p, o, a t, 0Co '5 o a >, .2 (0 .0 3, a N. ..E, o. ( a, c, (0 c E Z c E m' a; ) uCOp s cc, 3 U m ° N' = , , o' N ' O, 0 C. N, 0, aa , v , -. oo U CO0 0aF. : ° vm NCO, F- 0 °' m' �u '5, �' `' �, p, E v, o ; °'ci, ; r, pE' _ C . o I ,° o uv,cc, O a, , a) Om °; 8' oo3' m7' mva ' ' ca' .2 0)X ° o o ° € Nao _ ; o> , , E, 'Ema; ,, a oa) I- I- F= 'MC' y y > 'c aaoo'. o cE; S, :cis:: -g, cisoa ) m °' m3a a a) a); a') y; , ; a, co aO0OO, r, 5; a) a) caa), o, o o a, J2555co, w; O, Oaa, U. SQ; aUco, UU; UU; a, a , c0 m, U, , 2; a O (/), (/), U, I- O r N M V (() (O a0 O) N M V )1) (D I- DD O) O N co c} ([) (0 F- a0 O) _'. Q r r N CO V (n co N. a0 O) r r f':), N N N N N N N N N M M M M M M M ) O M 1 U U _- v I— o 0 0 Ei w N ap+ O 0 N c U C re O '-ill CD (NO) 0 v 0 co O N W" N co CV E N o'E J N N N 0 Q 0 . J #k a 0 c a (o ° a 0 0 �Ia 4 a c Es a0 0 aU) a W a a