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Home My WebLink About203-158CAUTION: This email originated from outside the State of Alaska mail system. Do not From:Brooks, Phoebe L (OGC) To:Stephen Soroka Cc:Regg, James B (OGC) Subject:RE: Milne Point, Northstar & Point Thompson July MIT"s Date:Thursday, August 28, 2025 4:02:51 PM Attachments:MIT MPU R-105 07-04-25 Revised.xlsx MIT NS10, NS32 07-19-25.xlsx Steve, Attached is are revised reports as follows: MIT MPU R-105 07-04-25 – the test psi was changed to the default (.25 of packer TVD or 1500 psi, whichever is greater) and the AOGCC Rep was changed to Sully Sullivan MIT NS 10, NS32 07-19-25 – the file naming convention now includes 07-19-25 based on the report date and the Waived by verbiage was moved to the Notes (the AOGCC Rep should be left blank if waived or reflect an inspector’s name if witnessed – this change was made on a total of 4 reports) Please update your copies or let me know if you disagree. Thank you, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 CONFIDENTIALITY NOTICE:This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Stephen Soroka <steve.soroka@hilcorp.com> Sent: Thursday, July 31, 2025 1:26 PM To: Regg, James B (OGC) <jim.regg@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Cc: Ryan Thompson <Ryan.Thompson@hilcorp.com>; Alaska NS - Wells Integrity <AKNSWellsIntegrity@hilcorp.com> Subject: Milne Point, Northstar & Point Thompson July MIT's 1RUWKVWDU16 37' MIT NS 10, NS32 07-19-25 click links or open attachments unless you recognize the sender and know the content is safe. 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. NS-32 2031580 Annual EPA MIT-IA Submit to: OOPERATOR: FIELDD // UNITT // PAD: DATE: OPERATORR REP: AOGCCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2001820 Type Inj I Tubing 469 474 469 465 Type Test P Packer TVD 3987 BBL Pump 1.0 IA 464 1738 1696 1685 Interval O Test psi 1500 BBL Return 1.0 OA 0 0 0 0 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2031580 Type Inj I Tubing 1913 1913 1912 1913 Type Test P Packer TVD 4070 BBL Pump 2.2 IA 1731 3500 3463 3456 Interval O Test psi 1500 BBL Return 2.3 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 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 Northstar/ NSU/ Northstar Chris Casey 07/19/25 Notes:EPA Class 1 Injection well annual MIT-IA to 1500 psi. Witnessed waived by Kam StJohn. Notes: Notes: Notes: NS-10 NS-32 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:EPA Class 1 Injection well annual MIT-IA to 3500 psi. Witness waived by Kam StJohn. Notes: Notes: Form 10-426 (Revised 01/2017)2025-0719_MIT_Northstar_NS-32 9 9 9 9 9 999 9 9 9 9 9 9 -5HJJ NS-32 CAUTION: This email originated from outside the State of Alaska mail system. Do not From:Brooks, Phoebe L (OGC) To:Stephen Soroka Cc:Regg, James B (OGC) Subject:RE: Milne Point, Northstar & Point Thompson July MIT"s Date:Thursday, August 28, 2025 4:02:51 PM Attachments:MIT MPU R-105 07-04-25 Revised.xlsx MIT NS10, NS32 07-19-25.xlsx Steve, Attached is are revised reports as follows: MIT MPU R-105 07-04-25 – the test psi was changed to the default (.25 of packer TVD or 1500 psi, whichever is greater) and the AOGCC Rep was changed to Sully Sullivan MIT NS 10, NS32 07-19-25 – the file naming convention now includes 07-19-25 based on the report date and the Waived by verbiage was moved to the Notes (the AOGCC Rep should be left blank if waived or reflect an inspector’s name if witnessed – this change was made on a total of 4 reports) Please update your copies or let me know if you disagree. Thank you, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 CONFIDENTIALITY NOTICE:This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Stephen Soroka <steve.soroka@hilcorp.com> Sent: Thursday, July 31, 2025 1:26 PM To: Regg, James B (OGC) <jim.regg@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Cc: Ryan Thompson <Ryan.Thompson@hilcorp.com>; Alaska NS - Wells Integrity <AKNSWellsIntegrity@hilcorp.com> Subject: Milne Point, Northstar & Point Thompson July MIT's 1RUWKVWDU16 37' MIT NS 10, NS32 07-19-25 click links or open attachments unless you recognize the sender and know the content is safe. 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. NS-32 2031580 Annual EPA MIT-IA Submit to: OOPERATOR: FIELDD // UNITT // PAD: DATE: OPERATORR REP: AOGCCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2001820 Type Inj I Tubing 469 474 469 465 Type Test P Packer TVD 3987 BBL Pump 1.0 IA 464 1738 1696 1685 Interval O Test psi 1500 BBL Return 1.0 OA 0 0 0 0 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2031580 Type Inj I Tubing 1913 1913 1912 1913 Type Test P Packer TVD 4070 BBL Pump 2.2 IA 1731 3500 3463 3456 Interval O Test psi 1500 BBL Return 2.3 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 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 Northstar/ NSU/ Northstar Chris Casey 07/19/25 Notes:EPA Class 1 Injection well annual MIT-IA to 1500 psi. Witnessed waived by Kam StJohn. Notes: Notes: Notes: NS-10 NS-32 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:EPA Class 1 Injection well annual MIT-IA to 3500 psi. Witness waived by Kam StJohn. Notes: Notes: Form 10-426 (Revised 01/2017)2025-0719_MIT_Northstar_NS-32 9 9 9 9 9 999 9 9 9 9 9 9 -5HJJ NS-32 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: 8/7/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240807 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# END 2-72 50029237810000 224016 6/27/2024 HALLIBURTON COILFLAG END 2-72 50029237810000 224016 7/18/2024 HALLIBURTON RBT END 2-72 50029237810000 224016 7/18/2024 HALLIBURTON TEMP END 2-74 50029237850000 224024 7/20/2024 HALLIBURTON MFC MPU B-24 50029226420000 196009 7/16/2024 HALLIBURTON MFC MPU E-19A 50029227460100 224010 6/22/2024 HALLIBURTON COILFLAG NS-10 50029229850000 200182 7/18/2024 HALLIBURTON MFC NS-10 50029229850000 200182 7/18/2024 HALLIBURTON TEMP NS-32 50029231790000 203158 7/16/2024 HALLIBURTON MFC NS-32 50029231790000 203158 7/15/2024 HALLIBURTON TEMP PBU H-13A 50029205590100 209044 7/23/2024 HALLIBURTON RBT PBU L-246 50029237650000 223078 7/23/2024 HALLIBURTON IPROF PBU R-26B 50029215470100 210025 7/5/2024 HALLIBURTON RBT PBU R-36 50029225220000 194144 6/21/2024 HALLIBURTON RBT PBU V-216 50029232160000 204130 7/11/2024 HALLIBURTON IPROF PBU V-217 50029233340000 206162 7/11/2024 HALLIBURTON IPROF Please include current contact information if different from above. T39365 T39365 T39365 T39366 T39367 T39368 T39369 T39369 T39370 T39370 T39371 T39372 T39373 T39374 T39375 T39376 NS-32 50029231790000 203158 7/16/2024 HALLIBURTON MFC NS-32 50029231790000 203158 7/15/2024 HALLIBURTON TEMP Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.08.07 13:19:30 -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. 1RUWKVWDU16 37' NS-32 Northstar wells Submit to: OOPERATOR: FIELDD // UNITT // PAD: DATE: OPERATORR REP: AOGCCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2001820 Type Inj I Tubing 815 811 794 780 Type Test P Packer TVD 3987 BBL Pump 4.1 IA 1163 1795 1724 1689 Interval O Test psi 1500 BBL Return 1.3 OA 0 0 0 0 Result 3 Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2031580 Type Inj I Tubing 302 302 302 301 Type Test P Packer TVD 4078 BBL Pump 3.2 IA 1043 1750 1718 1710 Interval O Test psi 1500 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 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 MMechanicall Integrityy Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes:EPA Class 1 injection well annual MIT-IA to 1500 psi. AOGCC witness waived by Brian Bixby. Witnessed by EPA's Nick Bruno. Notes: Notes: Hilcorp Alaska, LLC Northstar / NSU / Northstar Barry Bulot 07/25/24 Notes:EPA Class 1 injection well annual MIT-IA to 1500 psi. AOGCC witness waived by Brian Bixby. Witnessed by EPA's Nick Bruno. Notes: Notes: Notes: 16 NS-32 Form 10-426 (Revised 01/2017)2024-0723_MIT_Northstar_NS-32 9 999 9 9 9 9 -5HJJ NS-32 EPA Class 1 injection well annual MIT-IA to 1500 psi 1 Regg, James B (OGC) From:Darci Horner - (C) <dhorner@hilcorp.com> Sent:Tuesday, July 25, 2023 3:53 PM To:Regg, James B (OGC); Brooks, Phoebe L (OGC); Wallace, Chris D (OGC); DOA AOGCC Prudhoe Bay Cc:Ryan Thompson; Brian Glasheen; Brenden Swensen; Alaska NS - Milne - Wells Foreman; Alaska NS - Milne - Wellsite Supervisors; Derek Weglin; Josh McNeal; Alaska NS - Northstar - Field Foreman; Alaska NS - Northstar - Operations Leads; Alaska NS - Environmental Specialist; Chuck Wheat; apeloza; Taylor Wellman; Sara Hannegan; Jess Hall - (C); Matthew Ross; Donald Maxon Subject:MIT-IAs for Milne Point Class 1 injection wells B-24, B-34 and B-50 as well as Northstar Class 1 wells NS-10 and NS-32 Attachments:MIT MPU B-24 07-20-23.xlsx; MIT MPU B-34 and B-50 07-19-23.xlsx; MIT-IA NS-10 and NS-32 7-23-2023.xlsx All, Milne Point wells B‐24 (PTD # 1960090), B‐34 (PTD # 2161390), and B‐50 (PTD # 2042520) successfully passed MIT‐IAs on July 20, and 19, 2023, respecƟvely. Northstar wells NS‐10 (PTD # 2001820) and NS‐32 (PTD # 2031580) also successfully passed MIT‐IAs on July 23, 2023. Please note that EPA indicated in 2021 the required test pressure for the Northstar wells has been reduced from 3500 psi to 1500 psi. All wells are class 1 injecƟon wells requiring annual MITs. Please call myself or Ryan Thompson (907‐301‐1240) with any quesƟons. Regards, Darci Horner Technologist Alaska Islands Team Office: (907) 777‐8406 Cell: (907) 227‐3036 Email: dhorner@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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. Northstar NS-32PTD 2031580 Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 2001820 Type Inj I Tubing 437 438 438 436 Type Test P Packer TVD 3,987'BBL Pump 0.9 IA 729 1982 1914 1903 Interval O Test psi 1500 BBL Return 0.8 OA 3 4 3 3 Result P Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 2031580 Type Inj I Tubing 486 473 467 465 Type Test P Packer TVD 4,078'BBL Pump 1.2 IA 197 1872 1791 1756 Interval O Test psi 1500 BBL Return 1.1 OA 8 7 7 7 Result P Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Annual Class 1 injection well MIT-IA to 1500 psi. AOGCC witness waived due to EPA witness. Notes: Hilcorp Alaska, LLC Northstar / NSU / Northstar Donnie Maxon 07/23/23 Notes: Notes: Notes: Notes: NS-10 NS-32 Notes:Annual Class 1 injection well MIT-IA to 1500 psi. AOGCC witness waived due to EPA witness. Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Form 10-426 (Revised 01/2017)2023-0723_MIT_Northstar_NS-32        J. Regg; 10/12/2023 David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 10/3/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20221003 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 12A 501332053001 214070 8/10/2022 Halliburton CH PPROF BRU 222-34 502832018600 222039 9/15/2022 Halliburton CH RBT BRU 244-27 502832018500 222038 9/13/2022 Halliburton CH RBT END 1-45 500292199100 189124 8/11/2022 Halliburton CH PERF KBU 22-06Y 501332065000 215044 8/22/2022 Halliburton CH PPROF KBU 43-07Y 501332062500 214019 9/7/2022 Halliburton CH PPROF MPU C-24A 500292302001 209134 8/3/2022 Halliburton CH COILFLAG MPU L-46 500292355100 215118 9/10/2022 Halliburton CH MFC24 MPU S-34 500292317100 203130 9/3/2022 Halliburton CH MFC24 NS-10 500292298500 200182 8/18/2022 Halliburton CH WFL- TMD3D NS-32 500292317900 203158 8/17/2022 Halliburton CH WFL- TMD3D PBU 04-30 500292134500 185089 9/17/2022 Halliburton CH RMT3D PBU 05-24A 500292220401 204218 9/12/2022 Halliburton CH CAST PBU 11-16 500292158100 186078 9/10/2022 Halliburton CH PPROF PBU 11-27A 500292163801 222036 8/20/2022 Halliburton CH RBT PBU C-24B 500292081602 212063 8/16/2022 Halliburton CH PPROF PBU E-100A 500292281901 218157 9/20/2022 Halliburton CH LDL PBU S-106 500292299900 201012 9/12/2022 Halliburton CH RBT Please include current contact information if different from above. T37103 T37104 T37105 T37106 T37107 T37108 T37109 T37110 T37111 T37112 T37113 T37114 T37115 T37116 T37117 T37118 T37119 T37120 WFL-NS-32 500292317900 203158 8/17/2022 Halliburton CH TMD3D Kayla Junke Digitally signed by Kayla Junke Date: 2022.10.05 11:39:32 -08'00' David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 09/02/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20220902 Well API #PTD #Log Date Log Company Log Type Notes AOGCC Eset # END 3-11 50029218480000 188087 8/1/2022 Halliburton CALIPER + Report KALOTSA 4 50133206650000 217063 7/18/2022 Halliburton PPROF + Processing KBU 22-06Y 50133206500000 215044 7/14/2022 Halliburton PPROF + Processing KTU 24-06H 50133204900000 199073 7/21/2022 Halliburton PPROF + Processing KU 24-05B 50133206830000 219072 7/20/2022 Halliburton PPROF + Processing MPU C-24A 50029230200100 209134 7/28/2022 Halliburton COIL FLAG MPU I-17 50029232120000 204098 7/19/2022 Halliburton FREEPOINT NS-10 50029229850000 200182 7/23/2022 Halliburton CALIPER + Report NS-32 50029231790000 203158 7/24/2022 Halliburton CALIPER + Report PBU 18-02C 50029207620300 213009 7/14/2022 Halliburton CAST/CBL PBU C-10B 50029203710200 211092 7/15/2022 Halliburton PPROF + Processing PBU L5-03 50029236230000 219033 7/25/2022 Halliburton PPROF + Processing Please include current contact information if different from above. T36973 T36974 T36975 T36976 T36977 T36978 T36979 T36980 T36981 T36982 T36983 T36984 NS-32 50029231790000 203158 7/24/2022 Halliburton CALIPER + Report Kayla Junke Digitally signed by Kayla Junke Date: 2022.09.07 11:00:16 -08'00' 5HJJ-DPHV%2*& )URP'DUFL+RUQHU&GKRUQHU#KLOFRUSFRP! 6HQW0RQGD\-XO\30 7R5HJJ-DPHV%2*&%URRNV3KRHEH/2*&:DOODFH&KULV'2*&'2$$2*&&3UXGKRH%D\ &F-HULPLDK*DOORZD\7RGG6LGRWL%ULDQ*ODVKHHQ$ODVND16:HOOV)RUHPDQ$ODVND160LOQH :HOOVLWH6XSHUYLVRUV'HUHN:HJOLQ-RVK0F1HDO$ODVND161RUWKVWDU)LHOG)RUHPDQ$ODVND16 1RUWKVWDU2SHUDWLRQV/HDGV7UDYLV6SDUNV7RQ\0DQJDQR:LOOLDP'UDNH$ODVND16 (QYLURQPHQWDO6SHFLDOLVW&KXFN:KHDWDSHOR]D'DYLG+DDNLQVRQ7RULQ5RVFKLQJHU 6XEMHFW0,7,$VIRU0LOQH3RLQW&ODVVLQMHFWLRQZHOOV%%DQG%DVZHOODV1RUWKVWDUZHOOV16 DQG16 $WWDFKPHQWV0,7,$16 16[OV[0,7038%[OV[0,7038%[OV[ 0,7038%[OV[ ůů͕ DŝůŶĞWŽŝŶƚǁĞůůƐͲϮϰ;WdηϭϵϲϬϬϵϬͿ͕Ͳϯϰ;WdηϮϭϲϭϯϵϬͿ͕ĂŶĚͲϱϬ;WdηϮϬϰϮϱϮϬͿƐƵĐĐĞƐƐĨƵůůǇƉĂƐƐĞĚD/dͲ/Ɛ ŽŶ:ƵůǇϭϵ͕ϮϬĂŶĚϮϭ͕ϮϬϮϮ͕ƌĞƐƉĞĐƚŝǀĞůǇ͘ EŽƌƚŚƐƚĂƌǁĞůůƐE^ͲϭϬ;WdηϮϬϬϭϴϮϬͿĂŶĚE^ͲϯϮ;WdηϮϬϯϭϱϴϬͿĂůƐŽƐƵĐĐĞƐƐĨƵůůǇƉĂƐƐĞĚD/dͲ/ƐŽŶ:ƵůǇϭϵ͕ϮϬϮϮ͘ WůĞĂƐĞŶŽƚĞƚŚĂƚWŝŶĚŝĐĂƚĞĚůĂƐƚǇĞĂƌƚŚĞƌĞƋƵŝƌĞĚƚĞƐƚƉƌĞƐƐƵƌĞĨŽƌƚŚĞEŽƌƚŚƐƚĂƌǁĞůůƐŚĂƐďĞĞŶƌĞĚƵĐĞĚĨƌŽŵϯϱϬϬ ƉƐŝƚŽϭϱϬϬƉƐŝ͘ ůůǁĞůůƐĂƌĞĐůĂƐƐϭŝŶũĞĐƚŝŽŶǁĞůůƐƌĞƋƵŝƌŝŶŐĂŶŶƵĂůD/dƐ͘ WůĞĂƐĞĐĂůůŵǇƐĞůĨŽƌ:ĞƌŝŵŝĂŚ'ĂůůŽǁĂǇ;ϵϬϳͲϱϲϰͲϱϬϬϱͿǁŝƚŚĂŶǇƋƵĞƐƚŝŽŶƐ͘ ZĞŐĂƌĚƐ͕ DarciHorner Technologist Office:(907)777Ǧ8406 Cell:(907)227Ǧ3036 Email:dhorner@hilcorp.com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ubmit to: OOPERATOR: FIEL DD // UNITT // PAD: DATE: OPERATORR REP: AOGCCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2001820 Type Inj N Tubing 576 577 577 577 Type Test P Packer TVD 3,987'BBL Pump 4.6 IA 1226 2004 1976 1969 Interval O Test psi 1500 BBL Return 1.2 OA 3.2 3.39 3.4 3.39 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2031580 Type Inj W Tubing 1677 1912 1977 1932 Type Test P Packer TVD 4,078'BBL Pump 1.7 IA 36 2610 2433 2367 Interval O Test psi 1500 BBL Return 2.0 OA 8.6 8.9 9 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 TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMec hanicall Integrityy Tes t jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov NS-32 Notes:Annual Class 1 injection well MIT-IA to 1500 psi. Ryan Gross (EPA) witnessed via video conference. Notes: Annual Class 1 injection well MIT-IA to 1500 psi. Ryan Gross (EPA) witnessed via video conference. Notes: Hilcorp Alaska, LLC Northstar / NSU / Northstar Anthony Mangano/Banan Tarr 07/19/22 Notes: Notes: Notes: Notes: NS-10 Form 10-426 (Revised 01/2017)2022-0719_MIT_Northstar_2wells 9 9 9 9 9 9 , -5HJJ MEUNS-32 Annual Class 1 injection well MIT-IA , Samuel Gebert Hilcorp Alaska, LLC GeoTech Assistant 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 10/30/2020 To: Department of Natural Resources Resource Evaluation 550 W 7th Ave, Suite 1100 Anchorage, AK 99501 DATA TRANSMITTAL NS-32 (PTD 203-158) Water Flow Report and TMD3D 08/03/2020 ANALYSIS FIELD DATA Please include current contact information if different from above. PTD: 2031580 E-Set: 34150 Received by the AOGCC 10/30/2020 Abby Bell 10/30/2020 Samuel Gebert Hilcorp Alaska, LLC GeoTech Assistant 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 10/30/2020 To: Department of Natural Resources Resource Evaluation 550 W 7th Ave, Suite 1100 Anchorage, AK 99501 DATA TRANSMITTAL NS-32 (PTD 203-158) Multi Finger Caliper Log 07/31/2020 ANALYSIS FIELD DATA Please include current contact information if different from above. PTD: 2031580 E-Set: 34149 Received by the AOGCC 10/30/2020 Abby Bell 10/30/2020 Samuel Gebert Hilcorp Alaska, LLC GeoTech Assistant 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 09/22/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL NS-32 (203-158) Multi Finger Caliper Log 08/15/2018 ANALYSIS FIELD DATA Please include current contact information if different from above. Received by the AOGCC 09/22/2020 PTD: 2031580 E-Set:33973 Abby Bell 09/22/2020 1gU,4t'!�b'l N S -3z Reqq, James B (CED) From: Darci Horner - (C) <dhorner@hilcorp.com>/�I t Sent: Monday, July 15, 2019 10:52 AM �( To: Regg, James B (CED); Brooks, Phoebe L (CED); DOA AOGCC Prudhoe Bay; Wallace, Chris D (CED) Cc: Wyatt Rivard Subject: Northstar EPA Class 1 Disposal Well MITs 2019 Attachments: MIT NSU NS -10 and NS -32 combined 7-12-2019.xlsx All, Northstar Class 1 disposal wells NS -10 (PTD # 2001820) and NS -32 (PTD # 2031580) successfully passed annual EPA witnessed MIT-IAs on July 12, 2019. Please call myself or Wyatt Rivard (777-8547) with any questions. Regards, Darci Horner (Northern Solutions) Technologist Hilcorp Alaska, LLC 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Office: (907) 777-84o6 Cell: (907) 227-3036 Email: dhorner@hilcorp.com The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Submit to. Iim negg0alaskepov: OPERATOR: FIELD I UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test AOCCC ct0 k phoebebrooks(Malaska.00v Hilcorp Alaska LLC Northstar I NSU / Nornstar Bad Degff nred Jef( Jones waived witness chnswallacenalaska. oov ! �j -7(z41I1j- Well NS -10 INTERVAL Codes Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. V =Required by Variance PTD 2001820 Type lnl I N Tubing 1920 1886 1657 1660 P01V-0712_MIT Nomater NS40 NS -32 Type Test P Packer ND 3,987' BBL Pump 1.6 IA 920 3522 3459 3441 Interval 0 Test psi 3500 I BBL Retum 1 18 OA 0 0 0 0 Result P Notes: Annual Class 1 Injection Well EPA witnessed MIT -IA to 3500 psi. Well NS -32 Pressures'. Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2031580 Type IN I W Tubing 18]9 -1 1892 1879 1891 Type Te#tPPacker ND 4,O7tl BBL Pump 2.0 - IA 760 3502 - 3439 3426 ' InteTest psi 3500 BBLRetum 2.0 OA 0 0 0 0 — Resul[1 Notes: EPA Class l injection well MIT -IA to 3500 psi. Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min, PTD Type lnl Tubing Type Test Packer ND BBL Pump IA Interval Test psi BBL Return OA Recult Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type lnl Tubing Type Test Packer ND 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 ND BBL Pump IA Interval Test psi BBL Return OA Result Nates: Well Pressures. Pretest Initial 15 Min. 30 Min. 45 Min. 50 Min. PTD Type lnjTubing Type Test Packer ND 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 lnl Tubing Type Test Packer TVI BBL Pump IA Interval Test psi BBL Retum OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTDTypa lnj Tubing Type Test Packer ND BBL Pump IA Interval Test psi BBL Return OA Result Notes: TYPE INJ Codes TYPE TEST Codes INTERVAL Codes W=Wider P=Prel Teal 1=tarot Ted G=Gas O= Other(deambe In Nodes) 1=Four Year Cycle S � aw" V =Required by Variance I = Ineild"al Wasle.ter O = Core, (describe in nei N= NOI Injaed g Form 10-426 (Revised 01/2017) P01V-0712_MIT Nomater NS40 NS -32 Result Codes P=Pas F=Fail s 1=lnconcluzrve I Im Hilcorp Alaska, LLC March 18, 2019 Mr. Edward J. Kowalski Director, Office of Compliance and Enforcement U.S. Environmental Protection Agency 1200 Sixth Avenue Seattle, WA 98101 Mr. Chris Wallace Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501-3192 Mr. Marc Bentley Department of Environmental Conservation 555 Cordova St. Anchorage, AK 99501 Zo3.)5g Post Office Box 244027 Anchorage, AK 99524 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Phone: 907/777-8300 Fax: 907/777-8560 MAR 2 7 2019 RE: Mechanical Integrity Test Notifications Northstar Class 1 Injection Wells UIC Permit AK -1I002 -B, General Wastewater, Permit No. 2016DBO01-0020 Milne Point Injection Well UIC Permit AK -1I005 -B, General Wastewater, Permit No. 2016DB001-0001 Liberty Class 1 Injection Well, UIC Permit AK -I I013 -A, General Wastewater, Permit No. 2016DBO01-0025 Dear Sirs: Hilcorp Alaska, LLC (Hilcorp) respectfully submits the following notifications: 1) the annual Mechanical Integrity Test (MIT) and fluid movement tests that are required every two years at the Northstar NS 10 and NS32, Class 1 wells to meet the annual permit requirement in UIC Permit AK -1I002 -B; 2) the annual MIT and fluid movement logs that are required every three years at the Milne Point Class 1 wells, MPB-50, MPB-24 and MPB-34 to meet the permit requirement in UIC Permit AK -1I005 -B; 3) the MIT and fluid movement test that is required at the Liberty Class 1 well to meet the permit requirement in UIC Permit AK -1I013 -A. Mechanical Integrity Test Notification March 18, 2019 Page 2 of 2 By this letter Hilcorp is providing the written notification required by the aforementioned permits. In addition, Hilcorp staff will be coordinating the timeframes for these MITs with Mr. Ryan Gross of the Environmental Protection Agency (EPA) to maximize efficiencies associated with the travel arrangements of the EPA inspector, so that multiple tests of Class 1 wells can be witnessed in one trip to the North Slope. A summary of the proposed annual testing is presented in the attached table. The fluid movement test procedures that require EPA approval will be sent under separate cover or by email. If you have any questions or require additional information please call me at 907-782-7431, or via e-mail at dheebner@hilcorp.com. Sincerely, Deborah Heebner North Slope Environmental Specialist HILCORP ALASKA, LLC Attachment cc: Ryan Gross, EPA Region 10 U.S. Environmental Protection Agency 1200 Sixth Avenue Seattle, WA 98101 Evan Osborne, EPA Region 10 U.S. Environmental Protection Agency 1200 Sixth Avenue Seattle, WA 98101 Kyle Monkelien, BSEE Bureau of Safety And Environmental Enforcement Alaska OCS Region 3801 Centerpoint Drive Ste 500 Anchorage, AK 99503 Jason Seltisch Proposed Schedule for 2019 Mechanical Integrity Testing Class I Well MIT Deadline Proposed MIT test Flexibility in Fluid Movement (s) (May be extended date test date? Logs Planned up to 3 months after MIT? with Director approval) Milne Point By August 9, Approximately July Coordinate with No Fluid movement MPB-24 2019 15 -20, 2019. Northstar test logs are planned as date. they are required for MPB-24 every three years. Previously done on 7/9/2017. Milne Point By August 8, Approximately July Coordinate with Fluid movement MPB-34 2019 15 -20, 2019. Northstar test logs are planned as date. they are required for MPB-34 every three years. Previously done on 4/9/2017. Milne Point By August 9, Approximately July Coordinate with No Fluid movement MPB-50 2019 15 -20, 2019. Northstar test logs are planned as date. they are required for MPB-50 every three years. Previously done on 7/7/2017. Northstar By August 12, Approximately July Coordinate with No Fluid movement NS10 2019 11 -15, 2019. Milne test date. logs are planned as they are required at NS10 every two years. Previously done on 8/13/2018. Northstar By August 13, Approximately July Coordinate with No Fluid,movement NS32 2019 11 -15,2019 Milne test date. logs are planned as they are required at NS32 every two years. Previously done on 8/14/2018. Liberty CRI N/A The Liberty CRI well All logs required to Well will not be drilled in complete the well 2019. would be scheduled with the MIT. Z03 - 6g • - p_ United States Department of the Interior ;- BUREAU OF SAFETY AND ENVIRONMENTAL ENFORCEMENT 4iq � ae9 Alaska OCS Region RCN 3 3801 Centerpoint Drive,Suite 500 Anchorage,Alaska 99503-5823 FEB 2 7 2018 RECEIVED John A. Barnes MAR n1 M1 Senior Vice President and North Slope Asset Team Leader Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 SCANNED Dear Mr. Barnes: During the inspection out-briefing at Northstar Production Island on July 20, 2017, Hilcorp Alaska, LLC (HAK), requested clarification concerning our approach to the inspections of federal wells at Northstar. This topic has come up in various meetings with HAK in recent years. Therefore,this letter provides updated guidance to HAK regarding how we will approach inspections related to the federal wells at Northstar. Our goal here is to provide better clarity for HAK by setting down in writing what we have been relating verbally to HAK since you took over as operator of Northstar in 2014, and by drawing clear distinctions around our inspection parameters where it is practical for us to do so. Please be advised that this letter explicitly supersedes the February 1, 2005 letter from this office to BP Exploration Alaska, Inc. (Jeffrey Walker to Gray Herring). BSEE will conduct inspections related to all North Star federal wells (currently including NS-6, NS-9,NS-12,NS-22,NS-30,NS-32, and NS-34A) according to the following. The federal wells are subject to applicable federal regulations from bottom hole through Safety and Pollution Prevention Equipment(SPPE) and any devices that protect the wellhead. SPPE and devices that protect the wellhead will be generally defined as, but may not be limited to: a. Subsurface Safety Valve (SSSV) and their control system/actuators to include any component in the process stream establishing set points. b. Surface Safety Valve (SSV) and related actuators(e.g. a Pressure Safety High/Low, or PSHL)to include components establishing set points such as: tubing and annular pressures (static and flowing), first flowline segment pressure ratings, and first stage separator vessel pressure ratings. c. Injection Valve. d. Tubing/annular subsurface and surface safety devices. e. Emergency Shut Down (ESD) system and related controls. f. Any Temperature Safety Elements (TSE), Temperature Safety High(TSH) or other heat/fire detector installed at the well related to the actuation of well safety devices. g. Wellhead Injection Lines and Gas Lift Wellhead Injection Lines and related safety devices to include: Pressure Safety Valves (PSV), Flow Safety Valve (FSV), and PSHL. • • This letter sets forth the current BSEE regional policy for conducting federal well inspections at Northstar; however it does not represent a binding statement on the extent of BSEE's jurisdiction over facilities in state waters with wells that reach the OCS. If you have any questions about this guidance please contact Michael Jordan at michael.jordan@bsee.gov or at(907) 334-5300. Sincerely, Kevin J. Pendergast, PE PG Regional Supervisor, Field Operations cc: James Regg, Inspections Supervisor, AOGCC • • Nc�rak , — 3z Regg, James B (DOA) From: Wyatt Rivard <wrivard@hilcorp.com> �� elt (i7 Sent: Monday,July 31, 2017 5:21 PM f To: Wallace, Chris D (DOA); Brooks, Phoebe L (DOA); Regg,James B (DOA); DOA AOGCC Prudhoe Bay Cc: Alaska NS - Northstar- Operations Leads;Alaska NS - Milne -Wellsite Supervisors Subject: EPA Class 1 Disposal Well MITs 20'17 Attachments: MIT NSU NS-10 7-6-17.xlsx; MIT NSU NS-32 7-6-17.xlsx; MIT MPU B-24 7-6-17.xlsx; MIT MPU B-50 7-7-17.xlsx All, The following Class 1 Disposal Wells had passing annual 2017 EPA witnessed MIT-lAs. Please note that the newly completed Class 1 disposal well MPB-34 (PTD#2161640)was previously MIT'd in May 2017. The MIT forms are attached for reference. Well Field PTD MPB-50 Milne Point 2042520 MPB-24 Milne Point 1960090 NS-10 North Star 2001820 ✓� NS-32 North Star 2031580 Thank You, SCANNED AUG f) fl 2017, Wyatt Rivard I Well Integrity Engineer 1 Hilcorp Alaska, LLC 0: (907) 777-8547 I C: (509)670-8001 I wrivard@hilcorp.com 3800 Centerpoint Drive,Suite 1400 l Anchorage,AK 99503 1 • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test • Submit to: jim.rengt alaska.00v AOGCC.Insoectorsaalaska.00v phoebe.brooks(Stalaska.00v chris.wallacecaalaska.00v OPERATOR: Hilcorp Alaska,LLC 1�ee,in . I+l FIELD/UNIT/PAD: Northstar/NSU/Northstar DATE: 07/06/17 OPERATOR REP: Bart Degraffenreid AOGCC REP: Well NS-32 / Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2031580 Type Inj W Tubing 1732 ' 1738 1710 1707 - Type Test P Packer TVD 4,078' - BBL Pump 2.4 - IA 150 3540 • 3420 -- 3400 , Interval 0 Test psi 3500 - BBL Return 2.4 ' OA 15' 15 • 15 - 15 - Result P 1.7 Notes: Annual Class 1 Injection Well EPA witnessed MIT-IA to 3500 psi.Witness waived by AOGCC's Brian Bixby. Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result • Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result • • Notes: Well Pressures: Pretest Initial 15 Min: 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W=Water P=Pressure Test I=Initial Test P=Pass G=Gas 0=Other(describe in Notes) 4=Four Year Cycle F=Fail S=Slurry V=Required by Variance I=Inconclusive I=Industrial Wastewater 0=Other(describe in notes) N=Not Injecting Form 10-426(Revised 01/2017) MIT NSU NS-32 7-6-17 n6-3 - 6C Hilcor Alaska LLC Post Office Box 24402 h , Anchorage,AK 99524 3800 Centerpoint Dr Suite 1400 CERTIFIED MAIL. Anchorage,AK 99503 Phone: 907/777-8300 March 12, 2017 Fax:907/777-8560 Mr. Edward J. Kowalski Director, Office of Compliance and Enforcement RECEIVED MAR g 2017 U.S. Environmental Protection Agency 1200 Sixth Avenue AOGCC Seattle, WA 98101 Mr. Chris Wallace Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501-3192 Mr. Marc Bentley Department of Environmental Conservation 555 Cordova St. Anchorage, AK 99501 RE: Mechanical Integrity Test Notifications Northstar Class 1 Injection Wells, UIC Permit AK-1I002-B, General Wastewater, Permit No. 2005DB001-0020 Milne Point Injection - Well, UIC Permit AK-1I005-B, General Wastewater, Permit No. 2005DB001-0001 Liberty Class 1 Iniection Well. UIC Permit AK-11013-A. General Wastewater. Permit No. 2005DB001-0025 Dear Sirs: Hilcorp Alaska, LLC (Hilcorp)respectfully submits the following notifications: 1) The annual Mechanical Integrity Test (MIT) and fluid movement tests that are required every two years at the Northstar NS 10 and NS32, Class 1 wells to meet the annual permit requirement in UIC Permit AK-1I002-B; 2) The annual MIT and fluid movement logs that are required every three years at the Milne Point Class 1 wells, MPB-50, MPB-24 and MPB-34 to meet the permit requirement in UIC Permit AK-1I005-B; 3) The MIT and fluid movement test that is required at the Liberty Class 1 well to meet the permit requirement in UIC Permit AK-1I013-A. Mechanical Intel"Test Notification • March 12,2017 Page 2 of 2 By this letter Hilcorp is providing the written notification required by the aforementioned permits. In addition, Hilcorp staff will be coordinating the timeframes for these MITs with Mr. Evan Osborne of the Environmental Protection Agency (EPA) to maximize efficiencies associated with the travel arrangements of the EPA inspector, so that multiple tests of Class 1 wells can be witnessed in one trip to the North Slope. A summary of the proposed annual testing is presented in the attached table. The fluid movement test procedures that require EPA approval will be sent under separate cover or by email. If you have any questions or require additional information please call me at 907-782- 7431, or via e-mail at dheebner@hilcorp.com. Sincerely, Q4Ataitec44-14/-- Deborah Heebner North Slope Environmental Specialist HILCORP ALASKA,LLC Attachment cc: Evan Osborne, EPA Region 10 U.S. Environmental Protection Agency 1200 Sixth Avenue Seattle, WA 98101 Kyle Monkelien, BSEE Bureau of Safety and Environmental Enforcement Alaska OCS Region 3801 Centerpoint Drive Ste 500 Anchorage, AK 99503 Kevin Pendergast, BSEE Bureau of Safety and Environmental Enforcement Alaska OCS Region 3801 Centerpoint Drive Ste 500 Anchorage,AK 99503 Timothy Mayers, EPA Region 10 Jason Selitsch, Denali Environmental • • Proposed Schedule for 2017 Mechanical Integrity Testing Class I Well (s) MIT Proposed MIT test Flexibility in Fluid Movement Deadline date test date? Logs Planned after MIT? Northstar NS10 By July 6, Approximately July 5- Coordinate with No Fluid 2017 10, 2017. Milne test date. movement logs are planned as (May be they are required extended up at NS10 every to 3 months two years. with Director Previously done approval) on 7/7/2016. Northstar NS32 By July 8, Approximately July 5- Coordinate with No Fluid 2017 10, 2017 Milne test date. movement logs are planned as (May be they are required extended up at NS32 every to 3 months two years. with Director Previously done approval) on 7/9/2016. Milne Point By July 10, Approximately July 10- Coordinate with Fluid movement MPB-24 2017 15,2017. Northstar test logs are planned date. even though logs were previously done on 7/23/2015. This will get MPB-24 on the same schedule as MPB-50. Milne Point By July 10, Following the Well's Coordinate with The Mechanical MPB-34 2017 Completion Evan Osborne Integrity Testing and Jason and Fluid Selitsch with Movement Logs EPA will be done following the Well's completion Milne Point By July 10, Approximately July 10- Coordinate with Fluid movement MPB-50 2017 15, 2017. Northstar test logs are planned date. as they are required for MPB- 50 every three years. Previously done on 7/24/2014. Liberty CRI Well N/A The Liberty CRI well All logs required will not be drilled in to complete the 2017. well would be scheduled with the MIT. FEBgErEIVED 29 2016 Hilcorp Alaska, LLC A3 Post Office Box 244027 CC Anchorage,AK 99524 3800 Centerpoint Dr Suite 1400 CERTIFIED MAIL#7014 0150 0000 6324 9220 Anchorage,AK 99503 Phone:907/777-8300 Fax: 907/777-8560 February 25, 2016 Mr. Edward J. Kowalski Director, Office of Compliance and Enforcement U.S. Environmental Protection Agency 1200 Sixth Avenue Seattle, WA 98101 Mr. Chris Wallace Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage,AK 99501-3192 Mr. Marc Bentley Department of Environmental Conservation 555 Cordova St. Anchorage,AK 99501 RE: Mechanical Integrity Test Notifications Northstar Class 1 Injection Wells, UIC Permit AK-11002-B, General Wastewater, Permit No. 2005DB001-0020 Milne Point Injection Well, UIC Permit AK-1I005-B, General Wastewater, Permit No. 2005DB001-0001 Liberty Class 1 Injection Well, UIC Permit AK-11013-A, General Wastewater, Permit No. 2005DB001-0025 Dear Sirs: Hilcorp Alaska, LLC (Hilcorp) respectfully submits the following notifications: 1) the annual Mechanical Integrity Test (MIT) and fluid movement tests that are required every two years at the Northstar NS10 and NS32, Class 1 wells to meet the annual permit requirement in UIC Permit AK-1I002-B; 2) the MIT that is required every year at the Milne Point Class 1 wells, MPB-50 and MPB-24 to meet the permit requirement in UIC Permit AK-11005-B; 3) the MIT and fluid movement test that is required at the Liberty Class 1 well to meet the permit requirement in UIC Permit AK-1I013-A. • • Mechanical Integrity Test Notification February 25,2016 Page 2 of 2 By this letter Hilcorp is providing the written notification required by the aforementioned permits. In addition, Hilcorp staff will be coordinating the timeframes for these MITs with Mr. Thor Cutler of the Environmental Protection Agency (EPA) to maximize efficiencies associated with the travel arrangements of the EPA inspector, so that multiple tests of Class 1 wells can be witnessed in one trip to the North Slope. A summary of the proposed annual testing is presented in the attached table. The fluid movement test procedures that require EPA approval will be sent under separate cover or by email. If you have any questions or require additional information please call me at 907-782- 7431,or via e-mail at dheebner@hilcorp.com. Sincerely, Deborah Heebner North Slope Environmental Specialist HILCORP ALASKA, LLC Attachment cc: Thor Cutler,EPA Region 10 Kyle Monkelien, BSEE Kevin Pendergast, BSEE Jason Seltisch • • Proposed Schedule for 2016 Mechanical Integrity Testing Class I Well (s) MIT Proposed MIT test Flexibility in Fluid Deadline date test date? Movement Logs Planned after MIT? Milne Point By July 20, Approximately July 10 - Coordinate with No, fluid MPB-24 2016 15, 2016. Northstar test movement logs date. were done in 2015 and are only required at Milne Point every three years. Milne Point By July 20, Approximately July 10- Coordinate with No, fluid MPB-50 2016 15, 2016. Northstar test movement logs date. were done in 2014 and are only required at Milne Point every three years. Northstar NS10 By July 24, Approximately July 5- Coordinate with Fluid movement 2016 10, 2016. Milne test date. logs are planned as they are (May be required at NS10 extended up every two years. to 3 months Previously done with Director in 2014. approval) Northstar NS32 By July 25, Approximately July 5- Coordinate with Fluid movement 2016 10, 2016 Milne test date. logs are planned as they are (May be required at NS32 extended up every two years. to 3 months Previously done with Director in 2014. approval) Liberty CRI Well N/A The Liberty CRI well All logs required will not be drilled in to complete the 2016. well would be scheduled with the MIT. (JOSS-kms- Ij 2O S 15'80 Regg, James B (DOA) From: Wyatt Rivard <wrivard@hilcorp.com> l Sent: Thursday, July 30, 2015 4:59 PM � '/� �� To: Wallace, Chris D (DOA); Brooks, Phoebe L (DOA); Regg, James B (DOA); DOA AOGCC Prudhoe Bay Cc: Alaska NS - Northstar- Operations Leads;Alaska NS - Milne -Wellsite Supervisors; Taylor Wellman; Stan Porhola Subject: EPA Class 1 Disposal Well MITs Attachments: B-50 EPA MIT Pressure vs Temperature 7-20-15.xls; HAK EPA Class 1 Disposal Well MITs 2015.zip All, The following Class 1 Disposal Wells had passing EPA witnessed MIT-lAs. Please note that MPB-50(PTD#2042520) demonstrated difficult stabilization due to "10degF wellhead temperature swings while injecting at—29000BWPD. Two attempts were required before operations and EPA inspectors were satisfied with stabilization.The attached plot shows the MPB-50 Pressure vs Temperature correlation during the second, passing, test.The MIT forms are attached for reference. Well Field PTD MPB-50 Milne Point 2042520 MPB-24 Milne Point 1960090 NS-10 North Star 2001820 AUG 2 4 2015 NS-32 North Star 2031580 SCANNED Thank You, Wyatt Rivard I Well Integrity Engineer 0: (907) 777-8547 I C: (509)670-8001 I wrivardPhilcorp.conl 3800 Centerpoint Drive,Suite 1400 I Anchorage,AK 99503 f1iir rp LLC 1 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to jim reggaalaska qov doa aoocc prudhoe bavaalaska.gov phoebe brooks@alaska gov OPERATOR: Hilcorp Alaska LLClell(/S FIELD/UNIT/PAD: Northstar/NSU/NS el/ DATE: 07/25/15 OPERATOR REP: Bart DeGraffenreid AOGCC REP: Waived Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well NS-32 ' Type Inj. W " TVD 4,070'. Tubing -1845 '1821 "1816 -1814 Interval p P T D 2031580 - Type test P Test psi -1500 Casing 19 "3,509 '3,461 '3,460 P/F P Notes: Annual Class 1 MIT-IA to 3500 psi Witnessed by OA 19 19 - 19 19 Thor Cutler and Jason Selisch Waived by AOGCC John Crisp 1 bbl to pressure up Well injecting at 12900 BWPD Well Type Inj. TVD Tubing Interval P T D Type test Test psi Casing P/F Notes: OA Well Type Inj TVD Tubing Interval P T D Type test Test psi Casing P/F Notes: OA Well Type Inj TVD __Tubing_ Interval P T D Type test Test psi Casing P/F Notes: OA Well Type Inj TVD Tubing Interval P T D Type test Test psi Casing P/F Notes: OA TYPE INJ Codes TYPE TEST Codes INTERVAL Codes D=Drilling Waste M=Annulus Monitoring I=Initial Test G=Gas P=Standard Pressure Test 4=Four Year Cycle I=Industrial Wastewater R=Internal Radioactive Tracer Survey V=Required by Vanance N=Not Injecting A=Temperature Anomaly Survey 0=Other(describe in notes) W=Water D=Differential Temperature Test Form 10-426(Revised 02/2012) MIT NSU NS-32 7-25-15 xis 7,05 _ v X53' RECEIVA APR 1 6 2015 or ci4 Post Office Box 244027 _Hilcorp Alaska, LLCAOAnchorage,AK 99524 3800 Centerpoint Dr Suite 1400 CERTIFIED MAIL#7014 0150 0000 6239 5461 Anchorage,AK 99503 Phone: 907/777-8300 Fax: 907/777-8560 April 13, 2015 Mr. Edward J. Kowalski Director, Office of Compliance and Enforcement U.S. Environmental Protection Agency 1200 Sixth Avenue Seattle, WA 98101 ,i Mr. Chris Wallace Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501-3192 SCANNED ' Mr. Marc Bentley Department of Environmental Conservation 555 Cordova St. Anchorage, AK 99501 RE: Mechanical Integrity Test Notifications Northstar Class 1 Injection Wells, UIC Permit AK-1I002-B, General Wastewater, Permit No. 2005DB001-0020 Milne Point Injection Well, UIC Permit AK-1I005-B, General Wastewater, Permit No. 2005DB001-0001 Liberty Class 1 Injection Well,UIC Permit AK-1I013-A, General Wastewater, Permit No. 2005DB001-0025 Dear Sirs: Hilcorp Alaska, LLC (Hilcorp) respectfully submits the following notifications: 1) the annual Mechanical Integrity Test (MIT)that is required every year at the Northstar NS 10 and NS32, Class 1_wells to meet the annual permit requirement in UIC Permit AK- 1I002-B; 2) the MIT that is required every year at the Milne Point Class 1 well, MPB-50 to meet the permit requirement in UIC Permit AK-1I005-B; 3) the MIT and fluid movement test that is required at the Liberty Class 1 well to meet the permit requirement in UIC Permit AK-1I013-A. Mechanical Integri est Notification S April 13,2015 Page 2 of 2 4 4 By this letter Hilcorp is providing the written notification required by the aforementioned permits. In addition, Hilcorp staff will be coordinating the timeframes for these MITs with Mr. Thor Cutler of the Environmental Protection Agency (EPA) to maximize efficiencies associated with the travel arrangements of the EPA inspector, so that multiple tests of Class 1 wells can be witnessed in one trip to the North Slope. A summary of the proposed annual testing is presented in the attached table. If you have any questions or require additional information please call me at 907-777- 8452, or via e-mail at dheebne_r@hil_corp.com. Sincerely, t(49,irk Knile-494-1-t Deborah Heebner Environmental Specialist HILCORP ALASKA, LLC Attachment cc: Thor Cutler, EPA Region 10 • Proposed Schedule for 2015 Mechanical IntegrityTesting Class I Well (s) MIT Proposed MIT test Flexibility in Fluid Deadline date test date? Movement Logs Planned after MIT? Milne Point By July 28, Approximately July 22- Coordinate with Fluid movement MPB-50 2015 25, 2015. Northstar test logs were done date. in 2014 and are only required at Milne Point every three years. Northstar NS10 By July 28, Approximately July 25- Coordinate with Fluid movement 2015 29, 2015. Milne test date. logs were done in 2014 and are (May be only required at extended up NS10 every two to 3 months years. with Director approval) Northstar NS32 By July 28, Approximately July 25- Coordinate with Fluid movement 2015 29, 2015 I Milne test date. logs were done in 2014 and are (May be only required at extended up NS32 every two to 3 months years. with Director approval) Liberty CRI Well N/A The Liberty CRI well All logs required will not be drilled in to complete the 2015. well would be scheduled with the MIT. e e Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. J. º ~ - 1 5 <6 Well History File Identifier Organizing (done) o Two-sided 111111/111111111111 o Rescan Needed 11I1111111111111 III RESCAN ~olor Items: o Greyscale Items: DIGITAL DATA ~skettes, No. I o Other, NolType: OVERSIZED (Scannable) o Maps: o Other Items Scannable by a Large Scanner o Poor Quality Originals: o Other: OVERSIZED (Non-Scannable) ~9S of various kinds: Date Ie /710 /r; o Other:: NOTES: BY: ~ 151 tMP Daœ(p/7Jo~ ( () x 30 = I ~ 0 + Date:&' /7/0 (p 1111111111111111111 VVl-P Project Proofing BY: ~ 151 BY: .(Mãriã) It = TOTAL PAGES} 16 L? (Count does not include cover sheet) 'AAf 151 V V I 11111111111111 ""I Scanning Preparation Production Scanning Stage 1 Page Count from Scanned File: I g 5 (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: V YES BY: ~ Date:~/7JO(P Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO 151 \Mf NO BY: Maria Date: 151 1111111111111111111 Scanning is complete at this point unless rescanning is required. ReScanned 11/111111111111111I BY: Maria Date: 151 Comments about this file: Quality Checked 1111111111111111111 10/6/2005 Well History File Cover Page. doc 6 1 zv b� bp Date: 8/30/2012 Y Transmittal Number: 0 0 • BPXA WELL DATA TRANSMITTAL SCANNED JUL 0 3 2010 Enclosed are the materials listed below: If you have any questions, please contact Analisa Steger @ 564 -5439 Delivery Contents Top Bottom SW Name Date Company Run Depth Depth Description Schlumberger Water Flow Injection Log Press/Temp /CCUGR NS32 NS32 07/26/2012 BPXA 1 3850 ft. 8050 ft. 07/26/2012 Schlumberger Water Flow Injection Log Press/Temp /CCUGR NS10 NS10 07/27/2012 BPXA 1 4800 ft. 7950 ft. 07/27/2012 114/ '---/ i r , 2, ),,e 1 ( Please Sign and Return one copy of this transmittal. Thank You, Analisa Steger Petrotechnical Data Center I&Y._ Is. )--."1-"r4-k-. AOGCC Christine Shartzer Murphy Exploration Ignacio Herrera DNR Corazon Manaois Bureau of Ocean Energy Mgt, Reg and Enforcement Kyle Monkelien Petrotechnical Data Center LR2 -1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519 -6612 '2_06-‘5c6 • • 2A bp 30 6 Date: 8/2/2012 03/1130311 7.7 �J �I Transmittal Number: 02 BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below: If you have any questions, please contact Analisa Steger @ 564 -5439 Delivery Contents Top Bottom SW Name Date Company Run Depth Depth Description Schlumberger Water Flow Injection Log Press/Temp /CCL /GR NS32 NS32 07/29/2011 BPXA 1 3700 ft. 8123 ft. 07/29/2011 r! r { Please Sign and Return one copy of this transmittal. Thank You, Analisa Steger Petrotechnical Data Center AOGCC Christine Shartzer Murphy Exploration Ignacio Herrera DNR Corazon Manaois Bureau of Ocean Energy Mgt, Reg and Enforcement Kyle Monkelien Petrotechnical Data Center LR2 -1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519 -6612 • •- NS -32.. Prb ZO3r580 .Regg, James B (DOA) From: AK, D &C Well Integrity Coordinator [AKDCWeIIIntegrityCoordinator @bp.com] Sent: Wednesday, August 01, 2012 7:24 PM To: Regg, James B (DOA); Brooks, Phoebe L (DOA) 3e' 1 l`t / v Cc: AK, D &C Well Integrity Coordinator Subject: July 2012 AOGCC MIT Forms Attachments: July 2012 MIT Forms.zip Jim, Phoebe, SCANNED MAY 0 7 2013 Please find attached MIT forms for July 2012. Sent Previously L -218 (PTD #2051190) sent 7/9/2012 04 -11A (PTD #1931580) sent 7/17/2012 S -112 (PTD #2021350) sent with reclassification notice Enclosed in .zip file END 1- 41/0 -23 (PTD #1870320) END 3- 17F/K -30 (PTD #2032160) NS1 PTD #2001820) EPA Witnessed S32 (PTD #2031580) EPA Witness (C. (asst oat L5 -29 (PTD #1870450) MPB -25 (PTD # 1972330) MPB -50 (PTD #2042520) EPA Witnessed MPC -25A (PTD # 1960210) MPC -42 (PTD #2040280) B -31 (PTD #1910460) 04 -09 (PTD #1760300) Corrected packer depth (original sent 7/30) 04 -13 (PTD #1780310) Corrected packer depth (original sent 7/30) 04 -350 (PTD #2111060) 11 -02 (PTD #1811280) 17 -15A (PTD #1991310) E -100 (PTD #1971880) GC -2E (PTD #1970180) L -111 ( PTD #2020300) LPC -01 (PTD #1860480) V -220 (PTD #2080200) — well is currently on gas and was during test, inspector may have been told it was on water Y -03A (PTD # 2042350) secured for drill by on Y -19 Y -07A (PTD #2071050) Please let me know if I can be of further assistance. Thank you, Gerald Murphy (alt. Mehreen Vazir) Well Integrity Coordinator Office (907) 659 -5102 Cell (907) 752 -0755 Email: AKDCWeIIIntegrityCoordinator (cr�BP.com 1 • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 1 Mechanical Integrity Test f Submit to: jim.read aalaska.gov; doa.aoacc.prudhoe.bav ialaska.00v; phoebe.brooksaalaska.00v; tom.maunder(caalaska.gov OPERATOR: BP Exploration (Alaska), Inc. frt( v FIELD / UNIT / PAD: ACT / North Start / NS 'Rep �� f DATE: 07/26/12 OPERATOR REP: Gerald Murphy AOGCC REP: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well NS10 Type Inj. W TVD 3,98T Tubing 2016 2000 2027 2045 Interval 0 P.T.D. 2001820 Type test P Test psi 3500 Casing 82 3570 3420 3425 P/F P Notes: DW - Annual EPA MIT- IAlwaterflow logging OA 80 80 80 80 Ussed 3 bbl diesel to increase IAP to test pressure. Well NS32 - Type Inj. W ' TVD 4,070' Tubing 1,153 ' 1,053 1,018 ' 1,091 Interval 0 P.T.D. 2031580 / Type test P Test psi - 3500 Casing 48 ' 3,560 ' 3,486 ' 3,457 P/F P s Notes: DW - Annual EPA MIT- IA/waterflow logging OA 0 ' _0 • 0 0 - Ussed 3.6 bbl diesel to increase IAP to test pressure. Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA TYPE INJ Codes TYPE TEST Codes INTERVAL Codes D = Drilling Waste M = Annulus Monitoring I = Initial Test G = Gas P = Standard Pressure Test 4 = Four Year Cycle I = Industrial Wastewater R = Internal Radioactive Tracer Survey V = Required by Variance N = Not Injecting A = Temperature Anomaly Survey T = Test during Workover W = Water D = Differential Temperature Test 0 = Other (descnbe in notes) Form 10 -426 (Revised 06/2010) MIT ACT NS10 & NS32 07 - 25 - 12 • • bp Date: 09 -09 -2011 Transmittal Number: 93209 BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. If you have any questions, please contact Nita Summerhays at (907)564 -4035 Delivery Contents Top Bottom SW Name Date Company Run Depth Depth Description G WATER FLOW INJECTION 10% NS32 07 -29 -2011 BPXA 1 3700 8123 LOG — PAPER AND CD WATER FLOW INJECTION NS10 07 -29 -2011 BPXA 1 4780 7996.6 LOG — PAPER AND CD V Please Sign and Return one copy of this transmittal. Thank You, Nita Summerhays U i . Petrotechnical Data Center �`:y s k AOGCC Christine Shartzer Murphy Exploration Ignacio Herrera DNR Corazon Manaois BOEM Doug Chromanski Petrotechnical Data Center LR2 -1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519 -6612 3 - 158 • • bp Date: 08 -24 -2011 e iveD Transmittal Number: 93205 410 Re w cl $ orission BP , , 6"" TRANSMITTAL Enclosed are the materials listed below. 4 a ' fr ' If you have any questions, please contact Nita Summerhays at (907)564 -4035 Delivery Contents Top Bottom SW Name Date Company Run Depth Depth Description MULTI - FINGER CALIPER 3D NS10 07 -27 -2011 PDS 11 0 8006 DATA & VIEWER — 1CD MULTI - FINGER CALIPER LOG NS10 07 -27 -2011 PDS 11 0 8006 RESULTS SUMMARY 1 MULTI- FINGER CALIPER 3D 06v1 1 NS32 "' 07 -28 -2011 PDS 8 0 8100 DATA & VIEWER — 1CD MULTI - FINGER CALIPER LOG NS32 " 07 -28 -2011 PDS 8 0 8100 RESULTS SUMMARY _______/sit Please Sign and Return one copy of this transmittal. Thank You, Nita Summerhays Petrotechnical Data Center Murphy Exploration Ignacio Herrera BOEM Doug Chromanski DNR Corazon Manaois State of Alaska Christine Shartzer 1 Petrotechnical Data Center LR2 -1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519 -6612 • 1 Memory Multi- Finger Caliper rs Log Results Summary Company: BP Exploration (Alaska), Inc. Well: NS -32 Log Date: July 28, 2011 Field: Northstar Log No.: 6308 State: Alaska Run No.: 8 API No.: 50- 029 - 23179 -00 Pipet Desc.: 4.5 in. 12.6 lb. L -80 IBT -M Top Log Intvll.: Surface Pipet Use: Tubing Bot. Log Intvll.: 8,100 Ft. (MD) ' Inspection Type : Corrosion Monitoring Inspection ' COMMENTS : This caliper data is tied into the WLEG at 8,100 feet (Driller's Depth). ' This log was run to assess the condition of the tubing with respect to changes in corrosive and mechanical damage. The caliper recordings indicate the 4.5 inch tubing appears to be in good condition, with the exception of a ' 20% wall penetration recorded at an isolated pit in joint 33 (1,390 feet). Recorded damage appears in the forms of shallow apparent erosion throughout the log interval and isolated pitting. No other significant wall penetrations, areas of cross- sectional wall loss or I.D. restrictions are recorded. ' This is the eighth time a PDS caliper has been run in this well and the eighth time the 4.5 inch tubing has been logged. A comparison of the current and the previous log (June 11, 2010) indicates no increase in corrosive or erosive damage during the time between logs. A graph illustrating the difference in maximum ' recorded wall penetrations on a joint-by-joint basis between logs is included in this report. A Time to Failure Evaluation graph is included in this report. This graph projects a failure date range based on corrosion rates calculated from changes in the deepest recorded penetration in the entire well over time. The 4.5 inch tubing is projected to fail between 5.75 years and greater than 10 years. ' MAXIMUM RECORDED WALL PENETRATIONS: Isolated Pitting ( 20 %) Jt. 33 @ 1,390 Ft. (MD) ' No other significant wall penetrations (> 19 %) are recorded. MAXIMUM RECORDED CROSS - SECTIONAL METAL LOSS: ' No significant areas of cross - sectional wall loss (> 8 %) are recorded. MAXIMUM RECORDED ID RESTRICTIONS: t No significant I.D. restrictions are recorded. I Field Engineer: D. Cain Analyst: C. Waldrop Witness: B. Rochin ' ProActive Diagnostic Services, Inc. / P.Q. Box 1369, Stafford, Tx 77497 Phone: (281) or (888) 565 -9085 Fax: (281) 565 -1369 E -mail: PDS @memorylog,com Prudhoe Bay Field Office Phone: (907) 659 -2307 Fax: (907) 659 -2314 (1-(7e1 iiii. .. Time to Failure Evaluation - 1111117:0 BP Exploration Alaska p (Alaska), Inc. Northstar Corrosive Trend: Apparent Erosion, Well : NS -32 Isolated Pitting 4.5" 12.6 lb L -80 IBT -M Tubing July 28, 2011 Years Following Most Recent Log 4.5 in. 12.6 lb L -80 IBT -M 0 5 10 Wall Thickness = 271 mill } 1 1 260 — r (Is 1 Wal Thickness s Safety :tor) 7 ' 240 — i tz T 6- 140— — s� i cu 120 — 2011 Maximum Recorded Wall Penetration 'a - r 0.054" = 20% Wall Penetration in Joint 33 @ 1,390' O 100 — — V _ 16- July -07 to 02- May -04 (Completion Date) = 21 MPY c d 80 — 11- August -09 to 02- May -04 (Completion Date) = 14 MPY 12- June -10 to 02 -May -04 (Completion Date) = 12 MPY X i — — 28- July -11 to 02- May -04 (Completion Date) = 9 MPY 60 - r Best Fit = 14 MPY (Bold Dotted Line) • 40 — 2011 vs 2010 Joint -by -Joint Comparison Approx. Corrosion Rate = 0 MPY 20 - - Tubing Failure Projected Between 5.75 and > 10 Years 0 — i 1 t 1 1 1 1 1 1 1 0 5 ' 10 15 Years Since Well Completion 1 • • I Maximum Recorded Penetration Comparison To Previous I Well: NS-32 Survey Date: July 28, 2011 Field: Northstar Prev. Date: June 12, 2010 Company: BP Exploration (Alaska), Inc. Tool: UW MFC 40 No. 213121 I Country: USA Tubing: 4.5" 12.6 Ib L-80 113T-M Overlay Difference 1 Max. Rec. Pen. (mils) Diff. in Max. Pen. (mils) I 0 50 100 150 200 250 -100 -50 0 50 100 1 t 1 9 19 1• 29 29 39 39 49 49 I 56 56 66 66 I 76 = 76 86 86 1 E 96 = 96 I ° Z Z Y = 106 a 106 'o 116 116 123 123 133 133 1 143 - 143 153 I 153 1 163 163 173 I 173 1 183 183 193 193 1 -89 -44 0 44 89 •July 28, 2011 •June 12, 2010 Approx. Corrosion Rate (mpy) 1 1 • Correlation of Recorded Damage to Borehole Profile 1 ■ Pipe 1 4.5 in (50.9' - 8100.1') Well: NS -32 Field: Northstar I Company: Expl (Alaska), Inc. Country: USA BP Survey Date: July 28, 201 oration 1 1 1 ■ Approx. Tool Deviation ■ Approx. Borehole Profile 1 51 25 1056 50 2091 1 75 3144 a 100 4157 Z s 1 0 125 \ 5204 , 150 622 9 I 175 7260 194.4 8100 0 50 100 1 Damage Profile (% wall) / Tool Deviation (degrees) 1 I Bottom of Survey = 194.4 1 • 1 PDS Report Overview C--. Body Region Analysis I Well: NS 32 Survey Date: July 28, 2011 Field: Northstar Tool Type: UW MFC 40 No. 213121 Company: BP Exploration (Alaska), Inc. Tool Size: 2.75 I Country: USA No. of Fingers: 40 Tubing: 4.5 in. 12.6 ppf L -80 IBT -M Analyst: C. Waldrop Tubing: Nom.OD Weight Grade & Thread Nom.ID Nom.Upset Upper len. Lower len. 4.5 in. 12.6 ppf L -80 IBT -M 3.958 in. 4.5 in. 6.0 in. 6.0 in. 1 I Penetration(% wall) D amage Profile (% wall) 200 Penetration body Metal loss body 0 50 100 im 150 _- 100 1 1 50 z 1 49 I 0 to 20% 20 to 40 to over 40% 85% 85% Number of joints analysed (total = 202) I 201 1 0 0 97 I Damage Configuration ( body ) 150 1 100 1 145 50 I Isolated General Line Other Hole / Pitting Corrosion Corrosion Damage Pos. Hole I Number of joints damaged (total = 142) 194 11 0 0 131 0 Bottom of Survey = 194.4 1 1 1 • • 1 PDS REPORT JOINT TABULATION SHEET I Pipe: 4.5 in. 12.6 ppf L-80 IBT -M Well: NS-32 Body Wall: 0.271 in. Field: Northstar I Upset Wall: 0.271 in. Company: Expl (Alaska), Inc. Nominal I.D.: 3.958 in. Country: USA BP Survey Date: July 28, 201 oration 1 I Joint Jt. Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (% wall) (Iris.) (Ins.) % (Ins.) 0 50 100 1 51 () 0.04 14 5 3.93 Shallow Apparent Erosion. 1.1 83 0 0.02 8 2 3.93 Pup 1.2 91 0 0.03 1 1 4 3.95 Pup ■ 2 101 0 0.03 11 3 3.91 ■ 3 140 0 0.03 11 4 3.94 ■ 4 182 0 0.04 14 5 3.93 Shallow Apparent Erosion. II 5 224 0 0.03 10 3 3.92 ■ 6 263 0 0.03 11 4 3.94 ■ 7 304 0 0.05 19 2 3.92 Shallow Pitting. ■ I 8 9 346 0 0.03 11 2 3.92 ■ 388 0 0.03 11 3 3.93 ■ 10 429 0 0.03 11 4 3.93 11 471 0 0.02 8 2 3.92 I 12 513 0 0.04 15 3 3.93 Shallow Pitting. ■ 13 555 0 0.03 10 3 3.90 14 597 0 0.02 9 2 3.91 15 639 0 0.02 9 3 3.93 I 16 680 0 0.03 13 4 3.93 Shallow Apparent Frosion. 17 722 0 0.03 13 3 3.93 Shallow Pitting ■ is 18 764 0 0.03 13 4 3.93 Shallow Pitting. ■ 19 806 0 0.03 11 4 3.93 • 20 848 0 0.04 14 4 3.92 Shallow Pitting. ■ I 21 889 0 0.03 11 4 3.94 ■ 22 931 0 0.04 15 6 3.95 Shallow Apparent Erosion. s 23 973 0 0.05 19 4 3.92 Shallow Pitting. ■ 24 1014 0 0.03 1.3 5 3.94 Shallow Apparent Erosion. ■ I 25 1056 0 0.03 11 4 3.94 ■ 26 1098 0 0.04 16 3 3.94 Shallow Pitting. ■ 27 1138 0 0.05 19 4 3.94 Shallow Pitting ■ 28 1179 0.03 0.04 16 6 3.92 Shallow Apparent Erosion. ■ I 29 1221 0.0 3 0.04 15 5 3.92 Shallow Apparent Erosion. ■ 30 1262 0.0:3 0.05 18 5 3.94 Shallow Apparent Erosion. ■ 31 1304 0 0.03 13 4 3.93 Shallow Apparent Erosion. ■ 32 1345 0.03 0.04 14 6 3.94 Shallow Apparent Erosion. ■ 33 1387 0 0.05 20 4 3.93 Isolated Pitting. ■ I 34 1428 0 0.03 13 4 3.93 Shallow Apparent Erosion. ■ 35 1470 0 0.04 14 4 3.93 Shallow Apparent Erosion. ■ 36 1511 0 0.03 13 4 3.93 Shallow Apparent Erosion. ■ 37 1552 0 0.03 11 5 3.93 i I 38 1594 0 0.04 15 6 3.93 Shallow Apparent Erosion. ■ 39 1636 0.0 0.04 14 5 3.93 Shallow Apparent Erosion. ■ 40 1678 0 0.04 14 6 3.92 Shallow Apparent Erosion. ■ 41 1720 0 0.04 14 5 3.93 Shallow Apparent Erosion. ■ II 42 1762 0.03 0.04 15 4 3.93 Shallow Apparent Erosion. ■ 43 1803 0 0.04 14 4 3.93 Shallow Apparent Erosion. ■ 44 1842 0 0.03 13 3 3.91 Shallow Apparent Erosion. ■ 45 1883 0.04 0.05 19 6 3.94 Shallow Apparent Erosion. ■ 46 1925 0 0.04 14 6 3.92 Shallow Apparent Erosion. ■ I 47 1967 0 0.04 16 5 3.92 Shallow Apparent Erosion. ■ 48 2008 0 0.04 16 7 3.94 ' Shallow Apparent Erosion. Penetration Body I Metal Loss Body Page 1 1 1 • PDS REPORT JOINT TABULATION SHEET I Pipe: 4.5 in. 12.6 ppf L -80 IBT -M Well: NS-32 Body Wall: 0.271 in.. Field: Northstar I Upset Wall: 0.271 in. Company: l (Alaska), Inc. Nominal I.D.: 3.958 in. Country: USA BP Exp Survey Date: July 28, 201 oration 1 I Joint Jt. Depth t'en. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss LD• Comments (% wall) (Ins.) (Ins.) % (Ins.) 0 50 100 I 49 2049 0 0.04 15 6 3.93 Shallow Apparent Erosion. ■ 50 2091 0.03 0.04 15 5 3.92 Shallow Apparent Erosion. ■ 51 2132 0.04 0.04 15 4 3.92 Shallow Apparent Erosion. ■ 51.1 2173 0.04 0.04 16 6 3.95 Pup Shallow Apparent Erosion. 51.2 2183 0 0 0 0 3.81 4.5"X Nipple I 51.3 2184 0 0.04 14 5 3.93 Pup Shallow Apparent Erosion. ■ 52 2194 0.03 0.04 16 6 3.91 Shallow Apparent Erosion. ■ 53 2235 0.04 0.04 14 7 3.92 Shallow Apparent Erosion. ■ 54 2276 0.04 0.04 15 7 3.95 Shallow Apparent Erosion. I 55 2317 0 0.04 16 6 3.93 Shallow Apparent Erosion. ■ 56 2359 0 0.04 16 5 3.90 Shallow Apparent Erosion. ■ 57 2401 0.04 0.04 16 6 3.89 Shallow Apparent Erosion. ■ 58 2442 0 0.04 14 4 3.94 Shallow Apparent Erosion. ■ I 59 2484 0 0.04 15 4 3.94 Shallow Apparent Erosion. ■ 60 2526 0 0.04 14 6 3.93 Shallow Apparent Erosion. ■ 61 2567 0 0.03 11 3 3.93 ■ 62 2608 0.04 0.04 15 6 3.93 Shallow Apparent Erosion. ■ 63 2649 0 0.03 13 5 3.93 Shallow Apparent Erosion. ■ I 64 2690 0 0.03 13 4 3.92 Shallow Apparent Erosion. ■ 65 2731 0 0.03 13 4 3.91 Shallow Apparent Erosion. ■ 66 2773 0 0.04 15 3 3.92 Shallow Apparent Erosion. ■ 67 2814 0 0.04 14 7 3.95 Shallow Apparent Erosion. ■ I 68 2856 0 0.04 14 5 3.93 Shallow Apparent Erosion. ■ 69 2898 0.05 0.04 16 6 3.95 Shallow Apparent Erosion. ■ 70 2939 0.04 0.04 16 7 3.95 Shallow Apparent Erosion. 1 71 2981 0 0.04 14 4 3.93 Shallow Apparent Erosion. ■ I 72 3022 0 0.03 10 4 3.93 ■ 73 3062 0 0.03 11 4 3.93 NI 3103 0 0.05 18 7 3.93 Shallow Apparent Erosion. i 75 3144 0 0.04 14 4 3.92 Shallow Apparent Erosion. ■ I 76 3185 0.04 0.05 19 8 3.93 Shallow Apparent Erosion. i 77 3225 0 0.05 18 8 3.95 Shallow Apparent Erosion. i 78 3266 0 0.03 10 3 3.92 ■ 79 3306 0 0.03 11 4 3.93 ■ 80 3343 0 0.04 14 5 3.93 Shallow Apparent Erosion. ■ I 81 3384 0.04 0.04 14 5 3.94 Shallow Apparent Erosion. ■ 82 3424 0 0.04 15 6 3.94 Shallow Pitting. ■ 83 3463 0.03 0.04 16 8 3.93 Shallow Apparent Erosion. 1 84 3504 0.04 0.04 15 7 3.95 Shallow Apparent Erosion. 1 I 85 3546 0 0.04 16 5 3.94 Shallow Apparent Erosion. ■ 86 3587 0 0.03 13 5 3.91 Shallow Apparent Erosion. ■ 87 3625 0 0.03 13 5 3.93 Shallow Apparent Erosion. ■ 88 3667 0 0.03 10 4 3.94 ■ I 89 3708 0 0.03 13 5 3.90 Shallow Apparent Erosion. ■ 90 3750 0 0.03 13 4 3.93 Shallow Apparent Erosion. ■ 91 3790 0.03 0.04 14 4 3.93 Shallow Apparent Erosion. Ni 92 3830 0 0.03 13 4 3.92 Shallow Apparent Erosion. ■ ' 93 3870 0 0.03 11 4 3.93 ■ 94 3912 0 0.03 13 3 3.91 Shallow Apparent Erosion. ■ 95 3952 0.03 0.04 15 5 3.94 Shallow Apparent Erosion. d I Metal Loss Penetration BoBody y 1 Page 2 1 1 • • PDS REPORT JOINT TABULATION SHEET I Pipe: 4.5 in. 12.6 ppf L -80 IBT -M Well: NS-32 Body Wall: 0.271 in. Field: Northstar I Upset Wall: 0.271 in. Company: (Alaska), Inc. Nominal I.D.: 3.958 in.. Country: BP USA Expl Survey Date: July 28, 201 oration 1 I Joint Jt. Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (% wall) (Ins.) (Ins.) % (Ins.) 0 50 100 I 96 3992 0 0.04 15 4 3.92 Shallow Apparent Erosion. • 97 4033 0 0.03 13 4 3.92 Shallow Apparent Erosion. • ■ 98 4076 0 0.04 14 5 3.92 Shallow Apparent Erosion. • 99 4116 () 0.03 11 5 3.94 • 100 4157 0 0.04 16 7 3.93 Shallow Apparent Erosion. i I 101 4198 0 0.03 13 4 3.94 Shallow Apparent Erosion. • 102 4240 () 0.03 11 5 3.94 ■ 103 4281 0 0.04 14 6 3.90 Shallow Apparent Erosion. • 104 4323 0.04 0.04 16 7 3.95 Shallow Apparent Erosion. 1 I 105 4364 0 0.03 13 5 3.93 Shallow Apparent Erosion. • 106 4406 0 0.03 13 4 3.93 Shallow Apparent Erosion. • 107 4447 0 0.03 11 4 3.93 • 108 4487 0.03 0.04 14 6 3.94 Shallow Apparent Erosion. ■ i 109 4528 0.04 0.04 16 6 3.92 Shallow Apparent Erosion. ■ 110 4569 0 0.04 14 7 3.94 Shallow Apparent Erosion. 111 4610 0 0.04 14 6 3.94 Shallow Apparent Erosion. ■ 11 2 4648 0 0.03 11 5 3.93 ■ 113 4689 0 0.03 13 3 3.90 Shallow Apparent Erosion. • 114 4727 0.03 0.04 15 6 3.94 Shallow Apparent Erosion. 115 4769 0.03 0.04 14 4 3.93 Shallow Apparent Erosion. • 116 4810 0 0.03 13 4 3.93 Shallow Apparent Erosion. • 117 4851 0 0.04 15 5 3.94 Shallow Apparent Erosion. ■ I 118 4893 0 0.04 15 6 3.94 Shallow Apparent Erosion. • 119 4935 0 0.03 10 4 3.93 ■ 120 4976 0 0.03 11 5 3.94 • 121 5017 0 0.03 13 4 3.92 Shallow Apparent Erosion. ■ 122 5058 0 0.03 11 5 3.93 ■ 122.1 5100 0 0.03 1 3 4 3.94 Pup Shallow Apparent Erosion. 122.2 5109 0 0 0 0 3.86 7.625" x 4.5" Baker S -3 Packer 122.3 5114 0 0.04 15 6 3.94 Pup Shallow Apparent Erosion. • I 123 5123 0.03 0.04 15 4 3.92 Shallow Apparent Erosion. • 124 5163 0 0.04 14 6 3.95 Shallow Apparent Erosion. • 125 5204 0.04 0.05 18 8 3.95 Shallow Apparent Erosion. i 126 5245 0 0.03 13 4 3.94 Shallow Apparent Erosion. • 127 5287 0 0.03 13 , 5 3.94 Shallow Apparent Erosion. ■ I 128 5329 0.03 0.04 14 5 3.93 Shallow Apparent Erosion. • 129 5371 0 0.03 11 3 3.91 ■ 130 5409 0 0.04 14 3 3.92 Shallow Apparent Erosion. • 131 5450 0 0.04 15 6 3.93 Shallow Apparent Erosion. • I 132 5491 0.03 0.03 13 4 3.93 Shallow Apparent Erosion. ■ 133 5532 0 0.03 10 6 3.95 ■ 134 5573 0 0.04 16 3 3.93 Shallow Apparent Erosion. 7 135 5614 0 0.02 9 3 3.93 I 136 5655 0 0.03 11 5 3.93 II 5696 0 0.03 13 3 3.93 Shallow Apparent Erosion. ■ 138 5737 0 0.03 13 3 3.91 Shallow Apparent Erosion. ■ 139 5778 0 0.04 15 6 3.93 Shallow Apparent Erosion. • 140 5818 0 0.03 13 5 3.93 Shallow Apparent Erosion. • 141 5858 0 0.03 11 4 3.93 • 142 5899 0 0.03 13 3 3.92 Shallow Apparent Erosion. Penetration Body I Metal Loss Body 1 Page 3 1 • • PDS REPORT JOINT TABULATION SHEET I Pipe: 4.5 in. 12.6 ppf L -80 IBT -M Well: NS-32 Body Wall: 0.271 in. Field: Northstar I Upset Wall: 0.271 in. Company: Exploration (Alaska), Inc. Nominal I.D.: 3.958 in. Country: USA BP Survey Date: July 28, 2011 I Joint Jt. Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (% wall) (Ins.) (Ins.) % (Ins.) 0 50 100 I 143 5940 0 0.04 14 5 3.93 Shallow Apparent Erosion. ■ 144 5981 0.04 0.05 18 7 3.95 Shallow Apparent Erosion. ■ 145 6023 0 0.03 10 4 3.92 ■ 146 6064 0.01 0.03 13 5 3.92 Shallow Apparent Erosion. 147 6105 0 0.02 9 3 3.92 I 148 6146 0.03 0.04 14 5 3.93 Shallow Apparent Erosion. • 149 6187 0 0.03 10 3 3.93 ■ 150 6229 0.03 0.04 14 4 3.93 Shallow Apparent Erosion. • 151 6270 0 0.04 15 4 3.93 Shallow Apparent Erosion. • I 152 6311 0 0.03 10 4 3.94 • 153 6352 0 0.03 10 3 3.93 ■ 154 6394 0 0.03 13 6 3.95 Shallow Apparent Erosion. ■ 155 6435 0 0.04 14 5 3.94 Shallow Apparent Erosion. ■ I 156 6477 0 0.03 13 3 3.93 Shallow Apparent Erosion. • 157 6518 0 0.03 13 4 3.93 Shallow Apparent Erosion. • ■ 158 6559 0 0.03 11 2 3.90 ■ 159 6601 0 0.03 11 4 3.92 • I 160 6642 0.03 0.04 14 6 3.92 Shallow Apparent Erosion. ■ 161 6683 0 0.03 11 4 3.94 ■ 162 6724 0.04 0.04 14 6 3.95 Shallow Apparent Erosion. 1 163 6765 0 0.02 8 2 3.91 164 6806 0 0.04 14 5 3.95 Shallow Apparent Erosion. ■ I 165 6846 166 6888 0 0.03 11 4 3.94 ■ 0 0.03 11 4 3.92 ■ 167 6929 0 0.03 11 4 3.94 • 168 6970 0 0.04 14 5 3.94 Shallow Apparent Erosion. • I 169 7011 0 0.04 14 5 3.95 Shallow Apparent Erosion. ■ 170 7053 0 0.03 10 4 3.90 • ■ 171 7095 0 0.03 11 4 3.93 g 172 7136 0 0.02 8 2 3.91 I 173 7178 0 0.03 13 5 3.93 Shallow Apparent Erosion. • 174 7219 0 0.03 11 4 3.94 ■ 175 7260 0 0.03 10 2 3.89 • 176 7300 0.03 0.03 13 4 3.93 Shallow Apparent Erosion. • 177 7341 0 0.03 13 5 3.93 Shallow Apparent Erosion. ■ I 178 7383 0 0.03 11 4 3.93 • 179 7424 0 0.03 10 3 3.93 ■ 180 7465 0 0.03 11 4 3.94 • 181 7506 0 0.03 11 5 3.94 11 I 182 7546 183 7588 0 0.03 13 5 3.94 Shallow Apparent Erosion. ■ 0 0.03 13 5 3.95 Shallow Apparent Erosion. ■ 184 7630 0 0.03 13 4 3.93 Shallow Apparent Erosion. • 185 7671 0.04 0.04 16 7 3.94 Shallow Apparent Erosion. 1 I 186 7711 0 0.03 13 4 3.92 Shallow Apparent Erosion. 187 7753 0 0.02 8 2 3.92 188 7792 0 0.04 14 6 3.95 Shallow Apparent Erosion. ii 189 7833 0 0.03 13 5 3.90 Shallow Apparent Erosion. • I 190 7875 0 0.03 11 3 3.93 ■ 191 7916 0 0.03 13 4 3.93 Shallow Apparent Erosion. • ■ 192 7958 0 0.03 13 6 3.95 Shallow Apparent Erosion. Penetration Body I Page 4 'Metal Loss Body 1 1 • 1 • PDS REPORT JOINT TABULATION SHEET ' Pipe: 4.5 in. 12.6 ppf L -80 IBT -M Well: NS-32 Body Wall: 0.271 in. Field: Northstar ' Upset Wall: 0.271 in. Company: BP Exploration (Alaska), Inc. Nominal I.D.: 3.958 in. Country: USA .Survey Date: July 28, 2011 Joint Jt. Depth Peen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) l pset Body % Loss I.D. Comments (% wall) (Ins.) (Ins.) % (Ins.) 0 50 100 193 8000 0 0.03 10 3 3.93 194 8041 0 0.03 13 1 3.90 Shallow Pitting. 194.1 8080 0 0.03 13 4 3.95 Pup Shallow Apparent Erosion. 194.2 8089 0 0 0 0 3.74 4.5" HES XN Nipple ' 194.3 8090 0 0.04 14 5 3.93 Pup Shallow Apparent Erosion. 194.4 8100 0 0 0 0 6.01 4.5" WLEG 0 Penetration Body Metal Loss Body 1 1 1 1 1 1 1 1 1 1 Page 5 1 1 1 PDS Report Cross Sections I Well: NS32 Survey Date: Tool Type: July 28, 2011 Field: Northstar UW MFC 40 No. 213121 Company: BP Exploration (Alaska), Inc. Tool Size: 2.75 Country: USA No. of Fingers: 40 I Tubing: 4.5 in. 12.6 ppf L -80 IBT -M Analyst: C. Waldrop 1 1 Cross Section for Joint 33 at depth 1390.330 ft Tool speed = 58 Nominal ID = 3.958 I Norninal OD = 4.5 Remaining wall area = 96% s---,...\ Tool deviation = 21° N 1 1 1 1 1 1 1 Finger = 1 Penetration = 0.051 in. Isolated Pitting 0.05 in. = 20% Wall Penetration HIGH SIDE = UP 1 1 1 1 1 TREE= ABB-VGI 5 -1/8" 5KSI • SAFETY N.: HANGER= 4" BPV /TWC I I WELLHEAD = ABB -VGI 11" MULTBOWL 5KSI ACTUATOR = BAKER KB. ELEV = 55.9' I BF. ELEV = 40.05' (CB 15.9') NS32 KOP = — --- --- — 50 .(41 [ Max Angle = 47° @ 3122' , Datum MD = 12958' I Datum TV D = 10500' SS ■ o 120" CONDUCTOR, 169#, X -56 H 200' ' o I 2097' H HEAT TRACE, STARTING AT ?? I Minimum ID = 2.625" @ 2169' ' , I 2169' H4 -1/2" X NP, D - 3.813" I ' 4 -1/2" X NIPPLE w /PROTECTIVE SLEEVE 110 -3/4" CSG, 45.5 #, L -80 BTC, ID = 9.95 "? H 3964' I--- , 1 I 5102' H7-5/8" x4-1/2" BKR S-3 PKR, D= 3.875" I t I 1 ' 8088' H4 -1/2" HES XN NB, D = 3.725" ' I 4 -1/2" TBG, 12.6 #, L -80 BT -M, u 8100' .0152 bpf, D = 3.958" I / \�� 8100' , H4 -1/2" WLEG, D= ?. ? ? ?" I 17-5/8" CSG, 29.7 #, L -80 BTC, ID = 6.875 "? H 810T I I ) I H ELMD TT NOT LOGGED? ( 16-3/4" OPEN HOLE TD H 8321' I I I I I DATE REV BY COMMENTS DATE REV BY COMMENTS NORTHSTAR 12/14/03 INITIAL DRILL WELL: NS32 05/02/04 JAS ORIGINAL COMPLETION PERMIT No: 8 2031580 11/11/05 TLH NEW FORMAT API No: 50- 029 - 23179 -00 I 07/04/06 WRR/PAG MIN D CORRECTION (05/12/04) SEC 11, T13N, R13E, 1359' FSL & 649' Fa 11/27/07 WRRlPJC Wfl LHD/LOCATION CORRECTIONS I BP Exploration (Alaska) I NS10 (PTD #2001820) & NS32 (PTD #2031580) Disposal Wells Compliance Testing Page 1 of 2 • Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Friday, June 17, 2011 10:33 AM To: 'Vazir, Mehreen' Cc: Regg, James B (DOA) Subject: RE: NS10 (PTD #2001820) & NS32 (PTD #2031580) Disposal Wells Compliance Testing Mehreen, If the EPA will have representative(s) there, we will not be sending an Inspector. Tom Maunder, PE AOGCC From: Maunder, Thomas E (DOA) Sent: Friday, June 17, 2011 8:14 AM To: 'Vazir, Mehreen; Regg, James B (DOA) Subject: RE: NS10 (PTD #2001820) & NS32 (PTD #2031580) Disposal Wells Compliance Testing Sorry about that. The annual MIT schedule is at EPA's direction. Their increased schedule meets our minimum requirements of 2 -years for a slurry well and 4 -years for a liquid disposal well. Tom From: Vazir, Mehreen [mailto:Mehreen.Vazir @bp.com] Sent: Friday, June 17, 2011 8:06 AM To: Maunder, Thomas E (DOA); Regg, James B (DOA) Subject: RE: NS10 (PTD #2001820) & NS32 (PTD #2031580) Disposal Wells Compliance Testing Hi Tom, The last MIT -IA was completed on 6/18/2010 and based on the 12 month testing frequency we are currently due for our annual MIT -IA by 6/18/2011. However, EPA has made an inspector available to us 7/29 - 8/1/2011 which will put us beyond 12 months from the last successful MIT -IA. EPA has agreed to extend our current test due date to 8/30/2011 in order to accomodate this delay. I want to confirm that AOGCC will find it acceptable to provide a similar extension. Thank you, Mehreen U is ` From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Friday, June 17, 2011 7:52 AM To: Vazir, Mehreen; Regg, James B (DOA) Subject: RE: NS10 (PTD #2001820) & NS32 (PTD #2031580) Disposal Wells Compliance Testing Mehreen, I am not clear here. You say the MIT-lAs have been done. Is the testing planned for the end of July logging types? Tom Maunder, PE AOGCC 6/17/2011 NS10 (PTD #2001820) & NS32 (PTD #2031580) Disposal Wells Compliance Testing Page 2 of 2 From: Vazir, Mehreen [mailto:Mehreen.Vazir @bp.com] Sent: Thursday, June 16, 2011 4:39 PM To: Maunder, Thomas E (DOA); Regg, James B (DOA) Subject: NS10 (PTD #2001820) & NS32 (PTD #2031580) Disposal Wells Compliance Testing Hello Tom /Jim, North Star disposal wells NS10 (PTD #2001820) and NS32 (PTD #2031580) had successful MIT-lAs completed on 6/18/2010 witnessed by the EPA. Both wells are on a 12 month testing frequency. In order to facilitate completion of multiple tests at a time and save travel for EPA representatives to the Slope, the EPA will be available to witness these tests during the period of July 29 - August 1, 2011. Our current plan is to invite the Slope AOGCC inspector to witness these same tests and submit the test results to AOGCC after completion. Please let me know if this is unsatisfactory to the AOGCC. Thank you, Mehreen Vazir (Alternate: Gerald Murphy) Well Integrity Coordinator BP Alaska Drilling & Wells Well Integrity Office: 907.659.5102 Email: AKDCWelllntegrityCoordinator @BP.com 6/17/2011 r by ~ ~ r 1 Arlene Chow BP Ex loration (Alaska) Inc. Area Operations Manager -North 900 East Benson Boulevard BPXA PO Box 196612 \ ~ ~ Anchorage, AK 99519-6612 (907) 564-5111 July 21, 2010 `.', SS 1 ,'~~~5 ~h~ 5 ~ 6 ~ ~ ~ Phone: (907) 564-4101 Cv,,..~ ~ r ~L~~ ~~ ti '1' Cl~- ~ _ ceu: (so7) sot-2ao7 ~t,w. c/ t~ \ Email Arlene.chowo~bp.com lb p ~""` \ ~V ~ Vj~~ S Web: www.bp.com r Mr. Peter Contreras ~~yl'~`l ~ C ~°~ UIC Manager, Ground Water Protection Unit VIA CERTIFIED MAIL U.S. Environmental Protection Agency (OCE-127) 1200 Sixth Avenue Suite 900 Seattle, Washington 98101 ~~~~ ~ ~~ Mr. Thor Cutler U.S. Environmental Protection Agency (EPA) a~t1(~ f1 1F 2010 1200 Sixth Avenue ~N~Sk~ ~ G~ ~~g, ~~1ttNSSian Seattle, WA 98101 ~,~cl~~rage ao3- ~ s~ Re: NS32 -Report on Annual Demonstration of Mechanical Integrity Dear Mr. Contreras and Mr. Cutler: ~~\\ ~~®~-~,,,~ ~ 5~~~~~ ~`\~ Please find enclosed the Report on Annual Demonstration of Mechanical Integrity for the NS32 well, Permit No. AK-11002-A Part II.C.3.b.(1) and Part I I.C.3.c.(1), As stipulated by the permit, two (2) copies of the logs and two (2) copies of the descriptive and interpretive report are being sent to the EPA to your attention. 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. If you have any questions please call Mark Sauve at 907-564-4660. Sincerely, Arlene Chow x ; F,, I Attachments • by NS32 C~ EPA UIC Class IPermit AK-11002-A Part II.C.3.b (2): Report on Annual Demonstration of Mechanical Integrity July 23, 2010 C~ Executive Summary: • Annual surveillance on the NS32 EPA UIC Class I disposal well was performed June 12t", 13t" and 18t", 2010. The scope of work included a Water Flow Log (WFL) aMulti-Finger Caliper Log and a Mechanical Integrity Test (MIT). The MIT, pressure tested to 3500 psi, demonstrated mechanical integrity of the casing, tubing and packer. The test was witnessed by EPA representative Talib Syed. The multi-finger caliper tubing inspection log indicates the tubing is in good condition. A maximum wall penetration of 21 % was recorded in joint 7 (324'). The damage appears to be in the form of isolated pitting. No significant areas of cross-sectional metal loss or I.D. restrictions are recorded. The WFL results indicate there is good vertical containment of injected fluids in the permitted interval.. Nine WFL stops were made starting just above the intermediate casing shoe and stopping above surface casing shoe. Fluid movement was not detected on any of these stops. The test was witnessed by EPA Representative Talib Syed. Attachments include the well bore diagram (attachment 1), MIT documentation (attachments 2-4), the Schlumberger RST-WL log (attachment 5) and the PDS Memory Multi-Finger Caliper log (attachment 6). ® • • Discussion Mechanical Integrity Test of Inner Annulus (MIT-IA): On June 18t , 2010 aMIT-IA was performed on NS32. The inner annulus (4-1/2" x 7-5/8" casing annulus) was pressurized to 3500 psi with 3 barrels of diesel. During the first 15 minutes of the test pressure dropped 80 psi and in the second 15 minutes of the test pressure held constant. This pressure decline of 2.3% during the allotted 30 minute test period test indicates there is good tubing and casing mechanical integrity. The test was witnessed by EPA representative Talib Syed. The MIT results are summarized attachment 2, the pressure chart recorded during this test is shown in attachment 3 and the well service report for this work is included in attachment 4. Fluid Movement Logs fWater Flow Log (WFL) and Temperature Log] On June 18th, a Schlumberger Reservoir Saturation Tool Water Flow Log (WFL) was run in well NS32. The purpose of the log was to detect movement of any fluids in vertical channels adjacent to the wellbore and to determine that the confining zone is not fractured. The log was conducted with injection pressures of approximately 2005 - 2046 psi. The injection rates were approximately 18,500 BPD of produced water. The WFL bombards water with neutrons and detects gamma rays from the resulting interactions. The tool has a neutron generator and three gamma ray detectors. For this job, the tool was configured to detect the upward movement of water. The neutron generator was placed below the three gamma ray detectors. To detect the movement of water behind pipe, the tool is positioned at the desired depth and the neutron generator. is turned on briefly. If there is upward movement of water (e.g. channels behind the casing), the gamma ray detectors see the energized water as it moves up past them. Nine WFL stops were made in NS32. The depths were 8050', 8000', 7950', 7900', 7850', 6300', 5400', 5050', and 3850'. The intermediate casing shoe in this open hole completion is at 8107', the packer is set at 5102' and the surface casing shoe is at 3964' MD. No water movement was detected at any of the stops. The WFL results indicate there is good vertical containment of injected fluids in the permitted interval. The test was witnessed by EPA representative Talib Syed. The detailed report for the RST Water-flow log is attachment 5 and the well service report for this work is included in attachment 4. i '~ ~ Tubing Inspection Caliper Log ProActive Diagnostic Services (PDS) was retained to provide a 1-11/16", 40 finger memory caliper tool and interpretation of the results. This tool was run on Schlumberger slickline from the tubing tail back to surface on June 13, 2010. This tool digitally records the internal diameter of the tubing, which is used to determine pipe thickness, and hence metal loss. The multi-finger caliper tubing inspection log indicates the tubing is in good condition. A maximum wall penetration of 21% was recorded in joint 7 (324' MD). The damage appears to be in the form of isolated pitting. No significant areas of cross-sectional metal loss or I.D. restrictionsare recorded. The detailed report from PDS is attachment 6 and the well service report for this work is included in attachment 4. 3 i f ~ ~ 1 ~ ' I LOW INJECTION LOG ESS /TEMP / GR / CCL -2010 wa ~ ~ 1358.81' FSL & 648.97' FEL Elev.: K.B. 55.90 ft o ¢ ~ c~ AT SURFACE G.L. 16.00 ft 2 ~ T ii z O D.F. Q ~ ~ ~ U Permanent Datum: MSL Elev.: 0.00 ft r0 O ~ m a z z .- z m O ~ Log Measured From: KB 55.90 ft above Perm. Datum o ~ Drilling Measured From: KB v ~ - E API Serial No. Section Township Range ' m° ii J ~ U 50-029-23179-00 11 13N 13E Lo in Date 18-Jun-2010 Run Number ONE ' De th Driller 8321 ft Schlumber er Depth TD NOT TAGGED ' Bottom Log Interval 8060 ft Top Log Interval 3800 ft Casing Fluid T pe INJECTED PRODUCED WATER Salinit Dens' Fluid Level BITJCASING/TUBING STRING Bit Size 6.750 in From 8107 ft To 8321 ft Casin /Tubin Size 7.625 in Wei ht 29.71bm/ft Grade L-80 From 0 ft • To 8107 ft Maximum Recorded Temperatures 167 degF Logger On Bottom Time 18-Jun-2010 11:43 Unit Number Location 4101 PRUDHOE BAY Recorded B DECKERT/LOBBY/CLARK/RIVAR i Witnessed By BRACKETT / ROCHIN a 7 ~ ~~, ;. 1 AOGCC MITIA Forms END1-OS (18060), END1-15 (1930560), NS-10 (2020), NS-32 (20... Page 1 of 2 }Regg, James B (DOA) From: Brooks, Phoebe L (DOA) ~~ ~ ~ /~ Q Sent: Tuesday, July 06, 2010 10:46 AM ~7 To: AK, D&C Well Integrity Coordinator I v 5 Cc: Regg, James B (DOA) (~1 Subject: RE: AOGCC MITIA Forms END1-05 (1861060), END1-15 (1930560), NS-10 (2001820), NS-32 (2031580), MPF-42 (1970200), MPJ-17 (1972080), MPS-11 (2021130), MPS-31 (2020140) Attachments: MIT ACT NS-10 NS-32 06-18-10 Revised.xls; MIT MPU J-17 06-05-10.x1s JerryfTorin, Our database only allow numeric data for the Pretest, Initial, 15 Min., and 30 Min. data so I've removed the verbiage from report MIT ACT NS-10 NS-32 06-18-10, well NS-10 PTD #2001820 that was included far the Pretest Casing data and included "VAC" in the notes. I've also removed the NAs {OA data) for MIT MPU 5-115-3106-OS-10 and MIT MPU J-17 06-05-10 and include OA-NA in the notes as well. Well MPJ- 20 PTD #2001850 did not include any data (as the well was shut in) so I removed this well from report MIT MPU J-17 J-20 06-05-10. Also, can you please verify the Packer TVD for well MPU 5-31 PTD #2020140 (we have 3857')? Thank you, Phoebe Phoebe Brooks < Statistical Technician II ~"~~°~~~~~" ~(~~ "` ~~~~~ Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 Fax: 907-276-7542 From: AK, D&C Well Integrity Coordinator [mailto:AKDCWeIIIntegrityCoordinator@bp.com] Sent: Thursday, July 01, 2010 4:13 PM To: AK, D&C Well Integrity Coordinator; Regg, James B (DOA); Brooks, Phoebe L (DOA); Maunder, Thomas E (DOA) Subject: AOGCC MITIA Forms END1-05 (1861060), END1-15 (1930560), NS-10 (2001820), NS-32 (2031580), MPF-42 (1970200), MPJ-17 (1972080), MPS-11 (2021130), MPS-31 (2020140) Jim, Tom and Phoebe, Please find the attached AOGCC MITIA forms for the following wells: END1-05 (PTD #1861060) END1-15 ( PTD #1930560) NS-10 (PTD #2001820) NS-32 (PTD #2031580) MPF-42 (PTD #1970200) MPJ-17 (PTD #1972080) MPS-11 (PTD #2021130) MPS-31 (PTD #2020140) «June 2010 MIT Forms END-NS-MPU.zip» 7/12/2010 AOGCC MITIA Forms END1-OS (18060), END1-15 (1930560), NS-10 (2020), NS-32 (20... Page 2 of 2 Thank you, Gerald Murphy (alt. Torin Roschinger) Well Integrity Coordinator Office (907) 659-5102 Cell (907) 752-0755 Pager (907) 659-5100 Ext. 1154 7/12/2010 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Email to:jim.regg@alaska.gov; phoebe brooks@alaska.gov; tom.maunder@alaska.gov; doa.aogcc.prudhoe.bay@alaska.gov OPERATOR: BP Exploration (Alaska), Inc. FIELD /UNIT /PAD: Prudhoe Bay /ACT / NS DATE: 06/18/10 OPERATOR REP: Torin Roschinger AOGCC REP: Packer Depth Pretest Initial 15 Min. 30 Min. Well NS-10 Type Inj. I TVD 3,987' Tubing 520 520 520 515 Interval O P.T.D. 2001820 Type test P Test psi 3500 Casing VAC 3,500 3,360 3,320 P/F P Notes: Annual MIT--A for Class I disposal regulatory OA 50 50 50 50 compliance. Well NS-32 Type Inj. W TVD 4,070' Tubing 2,000 2,010 2,005 2,008 Interval O P.T.D. 2031580 Type test P Test psi 3500 Casing 20 3,500 3,420 3,420 P/F P Notes: Annual MIT-IA for Class I disposal regulatory OA compliance. Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubin Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type In'. TVD Tubin Interval P.T.D. Type test Test psi Casing P/F Notes: OA TYPE INJ Codes D =Drilling Waste G=Gas I =Industrial Wastewater N =Not Injecting W =Water TYPE TEST Codes M =Annulus Monitoring P =Standard Pressure Test R =Internal Radioactive Tracer Survey A =Temperature Anomaly Survey D =Differential Temperature Test INTERVAL Codes I =Initial Test 4 =Four Year Cycle V =Required by Variance T =Test during Workover O =Other (describe in notes) MIT Report Form BFL 11/27/07 MIT ACT NS-10 NS-32 06-18-10.x1s • by ~~-°°,~ 2 BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. If you have anv questions, please contact Joe Lastufka at (907)564-4091 Date: 07-01-2010 Transmittal Number: 93149 Delive Contents Bottom SW Name Date Contractor Run Top De th De th Descri tion WATERFLOW INJECTION LOG WITH NS10 06-17-2010 SCH 1 4780 7960 PRESS/TEMP/GR/CCL CD-ROM - WATERFLOW INJECTION LOG WITH NS10 06-17-2010 SCH PRESS/TEMP/GR/CCL WATERFLOW INJECTION LOG WITH NS32 06-18-2010 SCH 1 3800 8060 PRESS/TEMP/GR/CCL CD-ROM - WATERFLOW INJECTION LOG WITH NS32 06-18-2010 SCH PRESS/TEMP/GR/CCL base Sign and Return one copy of this transmittal. Thank You, Joe Lastuflca Petrotechnical Data Center ~: ~. BPXA AOGCC DNR Murphy Exploration MMS ~o -~ ~ 2 1 ~ ~ ~~ David Fair Christine Mahnken Corazon Manaois Ignacio Herrera Doug Chromanski :. ~ <- ~y .__ ~_~ti~ a 1.C .J ~ .k~ 33.s~,~ppeqq ~a~i: JJ~' .. • Petrotechnical Data Center LR2-1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519-6612 • by BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. if vnu have anv auesti~ns_ please contact Jae i,astufka at (9071564-4091 Date: 06-28-2010 Transmittal Number: 93148 Delivery Contents Bottom SW Name Date Contractor Run To De th De th Descri tion MEMORY MULTI-FINGER CALIPER LOG RESULTS NS32 06-12-2010 PDS 7 0 8100 SUMMARY CD-ROM -MEMORY MULTI- FINGER CALIPER LOG NS32 06-12-2010 PDS RESULTS SUMMARY MEMORY MULTI-FINGER CALIPER LOG RESULTS NS10 06-12-2010 PDS 10 0 8006 SUMMARY CD-ROM -MEMORY MULTI- FINGER CALIPER LOG NS10 06-12-2010 PDS RESULTS SUMMARY C PI~e Sign and Return one copy of this transmittal. Thank You, Joe Lastuflca Petrotechnical Data Center BPXA AOGCC Murphy Exploration MMS DNR ~~_t~a ,_ ~ ~ ,'' ~r ~~ ~. ~~~ 7~~9~5- ~3 _ .~~~ l ~~ ~ ~ Petrotechnical Data Center LR2-1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 995 1 9-66 1 2 ~~ ~, ' 'mow' ~'~ ~~ ~ a David Fair Christine Mahnken Ignacio Herrera Doug Chromanski Corazon Manaois • • Memory Multi-Finger Caliper S Log Results- Summary ,. Company: BP Exploration (Alaska), Inc. Well: NS-32 Log Date: June 12, 2010 Field: Northstar Unit Log No.: 10108 State: Alaska Run No.: 7 API No.: 50-029-23179-00 Pipet Desc.: 4.5" 12.6 Ib. L-80 IBT-M Top Log Intvl1.: Surface Pipet Use: Tubirrg Bat. Log trtit~rtl.: 8,'t00 Ft. (NtETJ Inspection Type : Corrosion Monitoring -nspection cQMMENTS This log is tied into the WLEG @ 8,100' (Driller's Depth). This tog was run to assess the condition of the tubing with respect to changes in corrosive and mechanical damage. The caliper recordings indicate the 4.5" tubing is in good to fair condition, with a maximum recorded wall penetration of 21% recorded at an isolated pit in joint 7 (324'). Recorded damage appears in the forms of apparent erosion throughout the tog interval and isolated pitting. No spgnifrcant areas of cross- sectional wall loss or I.D. restrictions are recorded. ~~ u This is the seventh time a PDS caliper has been run in this welt. A comparison between the current and the previous log (August 11, 2009) indicates no change in erosive damage. A graph illustrating the difference in maximum recorded penetrations on a joint-by joint basis between logs is included in this report. A Time to Failure Evaluation graph is included in this report, which indicates a wall loss trend of -14 mills per year. This corrosive trend is derived from a best fit of the maximum recorded wall penetrations from the last four caliper togs of this wett and assumed undamaged tubing upon initial completion. The projected tubing failure window ranges from as early as 4.75 years to greater than 10 years from the date of the latest caliper log. MAXIMUM RECORDED WALL PENETRATIONS: tsotated Pitting (21°~} Jt. 7 ~ 323 Ft (MD) Isolated Pitting (20%} Jt. 25 @ 1,045 Ft. (MD) Isolated Pitting (20%) Jt. 37 @ 1,579 Ft. (MD) No other significant wall penetrations (> 19%} are recorded ~ -- ° --~° MAXIMUM RECORDED CROSS-SECTtQNAL METAL LOSS: No significant areas of cross-sectional wall loss (> 10%) are recorded. MAXIMUM RECORDED ID RESTRICTION: ~~~ ti j~ r ~~.~~ F No significant I.D. restrictions are recorded. Field Engineer: E. Gustin Analyst: HY. Yang Witness: B. Rochin & B.Tilbery ProActive Diagnostic Services, Inc. / P.O. Box 1369, Stafford, TX 77497 Phone: (281) ar {888) 565-9D85 Fax: (281} 565-1369 E-mail; PDS~c~memoryiog,com Prudhoe Bay Field Office Phone: t9D7; 659-23D7 Fax: (9D7) 659-2314 2 03 • ~-~ 5i. Well: NS-32 Field: N orthstar Unit Company: BP Exploration (Alaska), Inc. Country: USA Maximum Recorded Penetration Comparison To Previous Survey Date: June 12, 2010 Prev. Date: August 11, 2009 Tool UW MFC 40 No. 213121 Tubing: 4.5" 12.61b L-801ST-M Overlay Max. Rec. Pe n. (mil s) 0 5 0 10 0 15 0 20 0 25 0 1 9 19 29 39 49 56 66 76 ~ 86 ~ 96 Z S 106 116 123 133 143 153 163 173 183 193 ^ June 12, 2010 ^August 11, 2009 Difference D -100 -5 iff. in Max 0 0 . Pen. (mil 5 s) 0 100 I 9 19 29 i 39 49 56 66 76 i 86 ~ 96 Z ~ • 106 g 116 123 133 143 153 . 163 173 183 193 1 I i -120 -60 0 60 120 Approx. Corrosion Rate (mpy) Time to Failure Evaluation BP Exploration (Alaska), Inc. ~ ~ Northstar Corrosive Trend: Apparent Erosion, Well : NS-32 Isolated Pitting 4.5" 12.s Ib L-80 IBT-M Tubing June 12, 2010 Years following Most Recent. Log 4.5" 12.s Ib L-80 IBT-M 0 5 10 Wall Thickness = 271 mill zso 240 220 ~ `.. 200 ~ 180 , ~s •~.+ a~ 1 s0 C ~ 140 a y 120 O 100 u OC 80 yt s0 ~ 40 20 0 - 1 q8~~r~, ~:~;J~ ~° ;~,~~~.. !~ -~- enactor) -' ' I ~ I ~ ~ ~ ~ / ~ / ~ / ~ ~ 2010 Maximum Recorded Wall Penetration ~ ~' 0.058" = 21% Wall Penetration in Joint 7 @ 323' ~' 16-July-07 to 02-May-04 (Completion Date) = 21 MPY u~~ ~ 11-August-09 to 02-May-04 (Completion Date) = 14 MPY ' ~ 12-June-10 to 02-May-04 (Completion Date) = 12 MPY r I Best Fit = 14 MPY (Bold Dotted Line) I 2010 vs 2009 Joint-by-Joint Comparison Approx. ~ Corrosion Rate = 0 MPY I Tubing Failure Projected Between 4.75 and > 70 Years • 0 5 ~ 1Q 15 Years Since Well Completion • Correlation of Recorded Damag Pipe 1 4.5 in (39.0' - 8100.0') Well: Field: Company: Country: Survey Date: • e to Borehole Profile NS-32 Northstar Unit BP Exploration (Alaska); tnc. USA June 12, 2010 ^ Approx. Tool Deviation ^ Approx. Borehole Profile 1 39 25 1043 50 2077 75 3132 100 4148 ~ v ~ Y C C J ~ ~_ Z c Y ~- ~0 125 5198 °1 D 150 6223 175 7257 194.4 8100 0 50 10II Damage Profile (% wall) /Tool Deviation (degrees) Bottom of Survey = 194.4 • PDS Report Overview ~~~.~ S_.: Body Region Analysis Well: NS-32 Survey Date: June 12, 2010 Field: Northstar Unit Tool Type: UW MFC 40 No. 213121 Company: BP Exploration (Alaska), Inc. Tool Size: 2.75 Country: USA No. of Fingers: 40 Anal st: HY". Yan Tubing: Nom.OD Weight Grade & Thread Nom.ID Nom. Upset Upper len. Lower len. 4.5 ins 13 f L-80 18T-i~t 3.958 ins 4.5 ins 6.0 ins 6.0-ins Penetration and Metal Loss (% wall) w~ penetration body --metal loss body 200 150 100 50 0 0 to 1 to 10 to 20 to 40 to over 1% 10% 20% 40% 85% 85% Number of ~oints anal sed total = 202 pene. 0 TZ 189 T 0 0 loss 4 198 0 0 0 0 Damage Configuration (body ) 200 150 100 50 0 isolated general line nng hole ~ poss pitting corrosion corrosion corrosion ible hole Number of ~oints dama ed total = 190 24 166 0 0 0 Damage Profile (% wall) ~ penetration body rnefal loss body 0 50 100 4 9 1 N4 Bottom. of Survev = 1.94.4 14 Analysis Overview page2 PDS REPORT JOINT TABI. Pipe: 4.5 in 12.6 ppf L-80 IBT-M Well: Body Wall: 0.271 in Field: Upset Wafl: 0.271 in Company: Nominal I.D.: 3.958 in Country: Survey Date: • ~ LATI O N SHEET NS-32 Northstar Unit BP Exploration (Alaska); Inc USA June 12, 2010 Joint No. Jt. Depth (Ft.) Nen. 111~5e: l (In~~.l Pen. Body (Irrs.} Pen. °io Metal I u~~ ";, Min. LD. flns.) Comments Damage Profile (% wall) 0 50 100 1 39 l) 0.05 18 (~ 3.93 Shallow ittin . 1.1 71 t) 0.02 ~) I 3.94 PUP ~ 1.2 79 i) 0.03 13 5 3.95 PUP Shallow a arent errosion_ 2 88 ~~ 0.03 1 :9 1 3.93 Shallow a arent errosion. 3 127 I) 0.03 12 5 3.95 Shal-ow a arent errosion. 4 169 i) 0.04 14 5 3.94 Shallow a arent errosion. 5 210 U 0.03 10 3.93 6 250 i) 0.04 14 t~ 3.95 Shallow ittin . 7 291 i) 0.06 21 i 3.94 Isolated ittin . 8 333 U 0.05 I f9 (, 3.95 Shallow ittin . 9 374 i) 0.05 19 4 3.94 Shallow ittin . 10 416 ~) 0.03 13 4 3.95 Shallow a arent errosion. 11 458 !) 0.03 13 ', 3.93 Shallow ittin . 12 500 i) 0.05 I ~~ 4 3.94 Shallow ittin . 13 542 t: 0.03 1:3 4 3.91 Shallow ittin . 14 584 U 0.04 16 ? 3.92 Shallow ittin . 15 625 ~) 0.04 14 3.94 Shallow ittin . 16 667 ~) 0.04 14 5 3.95 Shallow ittin . 17 709 ~:) 0.03 1 3 3.94 Shallow ittin . 18 751 E~ 0.03 13 r 3.94 Shallow ittin . 19 793 U 0.03 13 4 3.92 Shallow a arent errosion. 20 835 O 0.05 19 4 3.92 Shallow ittin . 21 876 t) 0.04 15 3.94 Shallow ittin . 22 917 c) 0.04 I S 7 3.95 Shallow a arent errosion. 23 59 i) 0.04 16 4 3.9 Shallow a area errosio . 24 1001 ~! 0.04 14 (~ 3.94 Shallow a areal errosion. 25 1043 U 0.05 ZO 5 3.94 Isolated Pittin . 26 1085 a 0.03 1 I 2 3.94 Shallow ittin 27 1125 t) 0.05 18 4 3.94 Shallow ittin . 28 1166 t) 0.05 19 6 3.93 Shallow ittin . 29 1207 t) 0.04 16 6 3.93 Shallow a arent errosion. 30 1248 t) 0.05 18 (, 3.95 Shallow ittin . 31 1290 i; 0.03 1? 4 3.93 Shallow a arent errosion. 32 1332 c! 0.04 13 (~ 3.94 Shallow a arent errosion. 33 1373 ~) 0.04 ) 3 , 3.94 Shallow a arent errosion. 34 1415 !) 0.03 I ? i 3.95 Shallow a arent errosion. - 35 1456 !) 0.03 13 5 3.94 Shallow a arent errosion. 36 1497 O 0.03 12 6 3.94 Shallow a arent errosion. 37 1539 t) 0.05 Zt) ~~ 3.95 Isolated Pittin . 38 1580 t! 0.03 l i - ~ 3.94 Shallow a arent errosion. 39 1622 ) 0.04 14 ~~ 3.94 Shallow a arent errosion. 40 1664 ~) 0.04 14 (, 3.93 Shallow a arent errosion. 41 1706 U 0.03 11 ~ 3.94 Shallow a arent errosion. 42 1748 !) 0.04 I ~ 4 3.93 Shallow a arent errosion. 43 1789 i) 0.04 14 ~-I 3.94 Shallow a arent errosion. 44 1829 t? 0.03 I 1 3.92 Sha{lo~- a arent errosion. 45 1869 U 0.04 I i 3.95 Shallow a arent errosion. - 46 191 1 O 0.04 1 _; 0 3.94 Shallow a arent errosion. 47 1953 ~) 0.04 15 5 3.94 Shallow a arent errosion. 48 1994 U 0.04 14 - 3.95 Shallow a arent errosion. _ Penetration Body Metal Loss Body Page I • PDS REPORT JOINT TABI. Pipe: 4.5 in 12.6 ppf L-80 IBT-M Well: Body Wall: 0.271 in Field: Upset Wall: 0.271 rR Company: Nominal I.D.: 3.958 in Country: Survey Date: • ELATION SHEET NS-32 Northstar Unit BP Exploration (,4laska), Inc USA June 12, 2010 Joint No. Jt. Depth (Ft.) P~~n. Upset (Ins.) Pen. Body (Ins.) Pcn. % .Metal I oss "~~, Min. LD• (Ins.) Comments Damage Profile (% wall) 0 50 100 49 2036 l) Q04 14 i 3.96 Shallowa arenterrosion. 50 2077 O 0.04 14 5 3.94 Shallowa arent errosion. 51 2118 (1 0.04 13 -t 3.94 Shallow a arenterrosion. 51.1 2160 t? 0.04 I t> t 3.96 PUP Shallowa arent errosion. 51.2 2169 O 0 U 3.81 4.5" X Ni le 51.3 2172 U 0.03 i> r, 3.94 PUP Shallowa arent errosion. 5 2180 O 0.05 i ~3 ~3 3.92 Shallowa arenterrosion. 53 2221 i) 0.04 1-1 fi 3.95 Shallowa arenterrosion. 54 2262 ti 0.04 1 i ~~ 3.96 Shallowa arenterrosion. 55 2304 l) 0.04 15 - 3.95 Shallowa arenterrosion. 56 2346 t) 0.04 15 t, 3.93 Shallowa arenterrosion. 57 2388 U 0.04 1 i, t3 3.93 Shallowa arent errosion. 58 2429 O 0.04 15 t, 3.95 Shallowa arenterrosion. 59 2470 (~ 0.04 15 3.96 Shallowa arenterrosion. 60 2512 U 0.04 15 ~ i 3.96 Shallowa arenterrosion. 61 2554 t? 0.03 13 i ~ 3.94 Shallowa arent errosion. 62 2595 t ~ 0.04 14 s 3.94 Shallowa arenterrosion. 63 2636 U 0.04 15 t~ 3.95 Shallowa arenterrosion. 64 2677 ! ~ 0.04 13 i> 3.94 Shallowa arenterrosion. 65 2718 U 0.04 13 (i 3.93 Shallowa arent errosion. 6b 2760 (! 0.03 1 ; i 3.94 Shallowa arenterrosion. 67 2801 O 0.04 16 ~~ 3.96 Shallowa arenterrosion. 68 2843 U 0.03 I i - 3.96 Shallowa arenterrosion. 69 2885 (~ 0.04 I (~ 23 3.95 Shallowa arenterrosion. 70 2927 !) 0.04 I (, Iii 395 Shallowa arenterrosion. 71 2969 (t 0.04 14 3.94 Shallowa arenterrosion. 72 3010 t) 0.03 1 t) 3.95 73 3050 t) Q03 1 Z 5 3.95 Shallowa arent errosion. ' 74 3091 U 0.04 I S I t) 3.96 Shallowa arenterrosion. 75 3132 t) 0.04 14" 3.93 Shallowa arenterrosion. 76 3173 t t 0.05 1 tS 1 i) 3.95 Shallowa arenterrosion. 77 3213 it 0.04 15 395 Shallowa arenterrosion. 78 3254 ~? 0.04 14 3.93 Shallowa arenterrosion. 79 3294 U 0.03 13 -1 3.94 Shallowa arenterrosion. 80 3331 U 0.04 15 ~t 3.93 Shallowa arent errosion. 81 3372 U 0.04 13 -1 3.94 Shallowa arent errosion. 82 3413 l) 0.04 14 5 3.95 Shallowa arenterrosion. 83 3452 U 0.04 14 3.94 Shallowa arent errosion. - 84 3494 t) 0.05 1 7 t; 3.96 Shallow a arenterrosion. - 85 3535 U 0.04 14 (:~ 3.94 Shallowa arenterrosion. ' 86 3576 i 1 0.04 15 ! ~ 3.93 Shallowa arent errosion. 87 3615 ~) 0.03 1 3 +, 3.95 Shallowa arenterrosion. 88 3656 U 0.04 1 t> 3.94 Shallowa arenterrosion. 89 3698 t) 0.04 13 ? 3.94 Shallowa arent errosion. 90 3740 U 0.04 14 ti 3.95 Shallowa arent errosion. 91 3780 t? 0.03 13 i , 3.94 Shallowa arent er onion. 92 3820 U 0.03 1 ;i i, 3.93 Shallowa arenterrosion. 93 3860 ~ 1 0.03 1 a `"i 3.94 Shallowa arenterrosion. _ 94 3902 i ~ 0.03 1 U -1 3.93 95 3942 ~ ~ 0.03 12 t> 3.95 Shallowa arenterrosion. _ Penetration Body Metal Loss Body Page 2 • PDS REPORT JOINT TABI, Pipe: 4.5 in 12.6 ppf L-80 IBT-M Well: Body Wall: 0.271 in Field: Upset Wall: 0.271 in Company: Nominal LD.: 3.958 in Country: Survey Date: • iLATION SHEET NS-32 Northstar Unit BP Exploration (Alaska), Inc. USA June 12, 2010 Joint No. Jt. Depth (Ft) Ncn. Upset (Ins.) Pen. Body (Ins.) Pen. % Metal I~~ss u'u Min. LD• (Irts.) Comments 0 Damage Profile (%wall) 50 100 96 3983 U 0.04 14 5 3.91 Shallow a anent errosion. 97 4024 t) 0.03 12 ~ 3.92 Shallow ittin 98 4066 t) 0.04 14 3.93 Shallow a anent errosion.. 99 4107 t) 0.04 14 (~ 3.95 Shallow a anent errosion. 100 4148 t) 0.04 1(i ~? 3.93 Shallow a anent errosion. 101 4189 l) 0.03 I i i, 3.96 Shallow a anent errosion. 102 4231 U 0.04 I -; v 3.94 Shallow a anent errosion. 103 4272 t) 0.04 1 > 3.92 Shallow a anent errosion. 104 4314 t) 0.04 15 i, 3.94 Shallow a anent errosion. 105 4356 U 0.03 12 3.93 Shallow a anent errosion. 106 4398 U 0.03 13 4 3.93 Shallow a anent errosion. 107 4439 t) 0.04 14 -1 3.94 Shallow a anent errosion. ' 108 4479 t) 0.04 I.4 ~ 3.94 Shallow a anent errosion. 109 4519 i) 0.04 14 t, 3.94 Shallow a anent errosion: - 1 10 4561 i) 0.04 14 7 3.95 Shallow a anent errosion. 111 4602 t? 0.04 1 3 -1 3.93 Shallow a anent errosi n. - 1 12 4640 L) 0.03 1 1 1 3.93 Shallow a anent errosion. 113 4681 i) 0.03 13 ~ 3.92 Shallow ittin . 1 14 4719 O 0.04 1 5 3.96 Shallow a anent errosion. 115 4761 i1 0.04 13 -t 3.93 Shallow a rent errosion. 116 4802 U 0.04 13 4 3.94 St~aHow a arerri errosion. 1 17 4844 t) 0.04 14 G 3.95 Shallow a anent errosion. 1 18 4886 O 0.04 14 ~ 3.96 Shallow a anent errosion. 1 19 4928 U 0.03 12 3.93 Shallow a anent errosion. 120 4969 U 0.03 12 ~' 3.94 Shallow a anent errosion. 121 5010 U 0.04 14 5 3.94 Shallow a anent errosion. 122 5052 0 0.03 13 6 3.93 Shallow a anent errosion. 122.1 5093 tl .0.03 10 3.93 PUP 122.2 5103 t~ 0 0 u 3.88 7.625" X 4.5" BKR S-3 Packer 122.3 5107 t) 0.04 14 - 3.94 PUP Shallow a anent errosion. 123 5116 t) 0.04 15 4 3.93 Shallow a anent errosion. 124 5157 U 0.04 1(~ ~ 3.95 Shallow a anent errosion. 125 5198 t? 0.04 16 ~) 3.95 Shallow a anent errosion. 126 5239 t? 0.04 14 4 3.94 Shallow a anent errosion. 127 5281 l? 0.04 14 i 3.95 Shallow a anent errosion. 128 5323 t) 0.04 15 6 3.93 Shallow a anent errosion. 129 5364 U 0.03 1 Z _' 3.90 Shallow a anent errosion. 130 5403 U 0.03 13 'i 3.91 Shallow a anent errosion. 131 5444 c ~ 0.04 15 3.94 Shallow a anent errosion. 132 5485 t) 0.03 l:> ! 3.92 Shallow a anent errosion. 133 5526 t) 0.03 12 > 3.94 Shallow a anent errosion. 134 5567 t) 0.04 14 -1 3.94 Shallow a anent errosion. 135 5608 t) 0.03 13 ~ 3.93 Shallow a anent errosion. 136 5650 t) 0.03 i ~ ~ 3.93 Shallow a anent errosion. 137 5690 li 0.04 1 E, 4 3.93 Shallow a anent errosion. 138 5731 t) 0.03 I 1 -1 3.91 Shallow a anent errosion. 139 5772 U 0.04 16 1 3.92 Shallow a anent errosion. 140 5812 t) 0.04 14 ?, 3.94 Shallow a anent errosion. 141 5852 U 0.04 14 3.94 Shallow a anent errosion. 142 5893 ~' 0.04 14 3.93 Shallow a anent errosion. _ Penetration Body Metal Loss Body Page 3 • PDS REPORT JOINT TABI, Pipe: 4.5 in 12.6 ppf L-80 IBT-M Well: Body Wall: 0.271 in Field: Upset Wall: 0.271 in Company: Nominal LD.: 3.958 in Country: Survey Date: • ELATION SHEET NS-32 Northstar Unit BP Exploration (Alaska), Inc. USA June 12, 2010 Joint No. Jt. Depth (Ft) i'r~n. UI>s~~l {In>.) Pen. Body (Ins.) I'r~n. `~'~ ~tiic~,.rl Less "~ Min. LD• flns.) Comments Damage Profile (%wall) 0 50 100 143 5934 l) Q04 i 4 (~ 3.95 Shallowa arenterrosion. 144 5976 ±! 0.04 i 5 ~3 3.94 Shallowa arenterrosion. 145 6018 ~! Q03 I ; ~' 3.93 Shallowa . anent errosion. 146 6058 i i 0.03 I s 3.92 Shal ow a arenterrosion. 147 6099 ~ ? 0.03 1 U -1 3.94 148 6140 l1 0.03 I ; ~ 3.93 Shallowa arenterrosion. 149 6182 +~ 0.03 1 "; -l 3.94 Sha[tow a anent errosion. 150 6223 c? 0.04 I ~ ~ ~ 3.94 Shallowa arenterrosion. 151 6264 ~_! 0.04 I ~ -t 3.94 Shallowa arenterrosion. 152 6305 ~! 0.03 12 ~ 3.94 Shallowa anent errosion. 153 6347 ~? 0.03 11 -! 3.95 Shallow ittin . 154 6389 ~? 0.04 13 <; 3.95 Shallowa arenterrosion. 155 6430 t? 0.04 1 ; E ~ 3.94 Shallowa anent errosion. 156 6472 ~ i 0.03 I ~ -! 3.93 Shallowa anent errosion. 157 6513 i! 0.04 14 t~ 3.93 Shallowa arenterrosion. 158 6554 i1 0.03 1 1 1 3.91 Shallowa arenterrosion. 159 6596 t? 0.04 1 ; t 3.93 Shallowa arenterrosion. 160 6637 U 0.04 1 5 ~ 3.92 Shallowa arenterrosion. 161 6678 +) 0.03 I ; ~t 3.93 Shallowa arenterrosion. 162 6719 i i 0.04 i 3 ' ~ 3.95 Shallowa arenterrosion. 163 6761 U 0.03 ~t 3.90 164 6801 t? 0.04 1(~ (~ 3.95 Shallowa arenterrosion. - 165 6842 U 0.04 13 ~ 3.95 Shallowa anent errosion. 166 6884 U 0.03 I l 5 3.92 Shallowa arenterrosion. 167 6925 i 1 0.04 1.3 3.94 Shallowa arenterrosion. 168 6965 U 0.04 16 (~ 3.94 Shallowa arenterrosion. 169 7007 i) 0.04 15 - 3.95 Shallowa arenterrosion. 170 7048 U 0.03 1 "; 5 3.90 Shallow a rent errosion. 171 7090 (? 0.04 14 ; 3.93 Shallowa arenterrosion. 172 7132 U 0.03 10 ; 390 173 7174 U 0.04 14 6 3.94 Shallowa arenterrosion. 174 7215 t1 0.04 1 ~ 6 3.93 Shallowa arenterrosion. 175 7257 ti 0.02 9 I 3.90 176 7297 l? 0.03 1 i ~ 3.94 Shallowa arenterrosion. 177 7338 U 0.04 13 - 3.94 Shallowa arenterrosion. 178 7380 U 0.03 13 4 3.93 Shallowa arenterrosion. 179 7421 li 0.03 I 1 ? 3.93 Shallow a ~ anent errosion. 180 7461 U 0.04 14 5 3.95 Shallowa arenterrosion. 181 7502 a 0.04 1 ~1 ~ 3.94 Shallowa anent errosion. 182 7543 !! 0.03 1 S i, 3.94 Shallowa arenterrosion. 183 7584 tl 0.03 I Z ~ 3.94 Shallowa arenterrosion. 184 7626 t) 0.04 15 -+ 3.93 Shallowa anent errosion. 185 7668 U 0.04 15 ti 3.95 Shallowa arenterrosion. 186 7708 i) 0.03 13 3.93 Shallowa arenterrosion. 187 7750 (~ 0.02 ~) ? 3.91 188 7789 U 0.04 I a i 3.95 Shallowa wrent errosion. 189 7830 ! 1 0.03 12 ii 3.92 Shallowa arenterrosion. 190 7872 t1 0.03 1 1 3.93 Shallowa arenterrosion. 191 7913 U 0.04 13 -; 3.92 Shallowa arenterrosion. 192 7955 U 0.04 1 ~ '~ 3.94 Shallow a ~ arenterrosion. _ Penetration Body Metal Loss Body Page 4 • PDS REPORT JOINT TABI, Pipe: 4.5 in 12.6 ppf L-80 IBT-M Well: Body Wall: 0.271 in Field: Upset Wall: 0.271 in Company: Nominal I.D.: 3.958 in Country: Survey Date: • iLATION SHEET NS-32 Northstar Unit BP Exploration (Alaska}, Inc. USA )une 12, 2010 Joint No. Jt. Depth (Ft.) i'c~n. Ill~,el (Ins.) Pen. Body flns.) Pen. °~ titet,~l lens `~:~ Min. LD• (lrrs.} Comments Damage Profile (%wall) 0 50 1-00 193 7997 ; ~ 0.03 1 ~) 3.93 194 8039 i? 0.03 1 tt 3.92 194.1 8077 tt 0.03 1 Z i 3.94 PUP Shallow a arent ermsion. 194.2 8087 i? 0 0 +~ 3.73 4.5" HES XN Ni le 194.3 8093 ~ 0.03 i ' 3.91 PUP Shallow a arent errosion. 194.4 8100 0 N'A 4.5" WLEG _ Penetration Body ~'vletal Loss Body Page 5 PDS Report Cross Sections Well: NS-32 Survey Date: June 12, 2010 Field: Northstar Unit Tool Type: UW MFC 40 No. 213121 Company: BP Exploration (AlaskaJ, Inc. Tool Size: 2.75 Country: USA No. of Fingers: 40 Tubin ; 4.5 ins 13 f L-80 IBT-M Anal st; HY. Yan Cross Section for Joint 7 at depth 322.79 ft Tool speed = 43 Nominal ID = 3.958 Nominal OD = 4.500 Remaining wall area = 98 Tool deviation = 5 ° Finger 28 Penetration = 0.058 ins Isolated Pitting 0.06 ins = 21 % Wall Penetration HIGH SIDE = UP • • Cross Sections page 1 -~ PDS Report Cross Sections ~s~-~~~ ~~ .~ Well: NS-32 Survey Date: June 12, 2010 Field: Northstar Unit Tool Type: UW MFC 40 No. 213121 Company: BP Exploration (Alaska), Inc. Tool Size: 2.75 Country: USA No. of Fingers: 40 Tubin 4.5 ins 13 f L-8D IBT-M Anal st: HY. Yan Cross Section for Joint 25 at depth 1044.62 ft Tool speed = 43 Nominal ID = 3.958 Nominal OD = 4.500 Remaining wall area = 97 Tool deviation = 11 ° Finger 30 Penetration = 0.054 ins Isolated Pitting 0.05 ins = 20% Wall Penetration HIGH SIDE = UP r1 L_J r~ ~~ Cross Sections page 2 TRff * AHErYGI 5-118' SKSI 'AYH-Lt~1tD - R8&ilGl f 1° I~tli-TIE!CA41 SK81 Ati.,TL'AT~~R a KB.aR' - 5545° KIP - ,..,.. NFex A; icj~ . .. . __. .. L3efimMG° . ~nt,n:Ta~D- _ $AFETYNt31ES: HlWfi9t=d"BRVFIINC 14-i12 R NF: ID- 3,813' I 141~I1It11Ut11 IQ = 3.725" $~8$` 4-112" XN NIPPLE 5102' 7-518' X d-L'Z" EKR 3~3 PKR tI}- 3.875' ~ 81aa' i--la-,rz-~,i~~, ~~ ~ , - ~ x 1 v rr war . ~~~.'r GtTE f1EV BY O7M~iENT3 D(tTf R8/ BY CQRidEtJrS 1211e!.~13 ~rru~tax~t fl5.U2.V~ JAS OItIGfftALC~fPt.ETI~t f 1.'1 1,E15 lt_H fa6Y RSRAAT K7?~Rf'tBTAR tiN~1. riB32 F~ratR rib.. ~c43158l1 A A riw.. 54929-23139-06 tiP l3cp location ~A teak a) i ~.- I _~... ~ t. .... -- J~~'C~STAT~s UNITED STATES ENVIRONMENTAL PROTECTION AGENCY REGION 10 ~,~ ~ `~ ~~d~ ~~ ~ rW 1200 Sixth Avenue, Suite 900 i ~ Q Seattle, WA 98101-3140 ., _'" `~ ~~ ~. `'~~ ~~A<PRO'~G~\ I!~n"Y - ~ ~.J OFFICE OF COMPLIANCE AND ENFORCEMENT Reply To: OCE-082 CERTIFIED MAIL -RETURN RECEIPT REQUESTED Ms. Arlene Chow North Area Operations Manager BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, Alaska 99519 ~~: ~"~;"`t'~~~" ~ ~' ~~~ s' `' ~~~~~~` Re: Issuance of Underground Injection Control (UIC) Permit No. AK1I002-B Northstar Unit, North Slope, Alaska Dear Ms. Chow: The U. S. Environmental Protection Agency, Region 10, (EPA) is re-issuing an Underground Injection Control permit for BP Exploration (Alaska) Inc. (BPXA), Northstar Unit (NU), North Slope, Alaska. The enclosed document authorizes the facility to continue to inject non-hazardous industrial waste utilizing up to two Class I injection wells at the Northstar Unit. The operator is authorized to continue Class I injection activities on August 5, 2010, until midnight August 4, 2020, per the ten year permit. This letter serves as 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 maybe obtained on-line at epa.gov/eab or by contacting the Clerk of the Environmental Appeals Board at (202) 233-0122. Sincerel _._~ Edwar .Kowalski Director Enclosures cc w/enc: Shawn Stokes, ADEC Division of Water/Wastewater Discharge Permits Dan Seamount, Commissioner, AOGCC ~ ~-~,; ij Printed on Recycled Paper • • Page 1 of 24 ISSUANCE DATE AND SIGNATURE PAGE U.S. ENVIRONMENTAL PROTECTION AGENCY UNDERGROUND INJECTION CONTROL PERMIT: CLASS I Permit Number AK-1I002-B In compliance with provisions of the Safe Drinking Water Act (SDWA), as amended, (42 U.S.C. 300f-304j-9), and attendant regulations incorporated by the U.S. Environmental Protection Agency (EPA) under Title 40 of the Code of Federal Regulations, BP Exploration (Alaska) Inc. (BPXA) (Pennittee) is authorized to inject non-hazardous industrial waste utilizing up to two (2) Class I injection wells at the Northstar Unit (located northwest of Prudhoe Bay, in the Beaufort Sea off the North Slope of Alaska), into the Schrader Bluff, Prince Creek/Ugriu and lower Sagavanirktok Formations, in accordance with conditions set forth herein. The current waste disposal system at the Northstar facility utilizes two (2) Class I wells (NS 10 and NS32) both injecting into the Schrader Bluff/Ugnu formation below approximately 8,000 feet measured depth (MD) (approximately 6,500 feet true vertical depth subsea (TVDss)). Northstar is the first joint (State and Federal) offshore Arctic development with surface production facilities situated on an existing gravel island six miles offshore in the Beaufort Sea. Class I injection is critical to the Northstar area development because it is located offshore, remote and isolated from other North Slope infrastructure. With no year-round connecting road, waste storage and transportation is prohibitively expensive and introduces the added potential for spills on the fragile Arctic tundra. Permit Number AK-1I002-A was originally issued by EPA on August 4, 2000, and expires on August 4, 2010. Injection began in January 2001 in well NS10 and the second injection well, NS32, was completed on May 2, 2004. Total volume of non- hazardous fluids including drill cuttings/muds injected in NS10 and NS32 since start-up in January 2001 is approximately 32 million barrels (MMB). The wells have consistently demonstrated sound mechanical integrity (both internal and external) on an annual basis with the testing witnessed by EPA representatives. Well NS 10 was worked over in January 2006 to replace tubing and install new packer. There are no reported underground sources of drinking water (USDWs) at this location. Injection of hazardous waste as defined under the Resource Conservation and Recovery Act (RCRA), as amended, (42 U.S.C: 6901) or radioactive wastes (other than naturally occurring radioactive material (NORM)) are not authorized under this permit. Injection shall not commence until the Permittee has received written authorization from EPA Region 10 Director of the Office of Compliance and Enforcement (Director) to inject. 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 the Northstar Development Project Underground Injection Control (UIC) Class I Permit Renewal Application dated February 2, 2010, (and original Permit Application and related material submitted by the Permittee in August 1997 and March, 2000). • • Page 2 of 24 This permit renewal shall become effective on August 5, 2010, in accordance with 40 C.F.R. 124.15. This permit and the authorization to inject expire at midnight, August 4, 2020, unless terminated. Signed this ~ day of May, 2010. Director and Enforcement U.S. Enronmental Protection Agency Region 10 (OCE-164) - 1200 Sixth Avenue, Suite 900 Seattle, Washington 98101 i • Page 3 of 24 TABLE OF CONTENTS ISSUANCE DATE AND SIGNATURE PAGE 1 PART I GENERAL PERMIT CONDITIONS 5 EFFECT OF PERMIT 5 PERMIT ACTIONS 5 Modification, Reissuance, or Termination 5 Transfer of Permits 6 SEVERABILITY 6 CONFIDENTIALITY 6 GENERAL DUTIES AND REQUIREMENTS 6 Duty to Comply 6 Penalties for Violations of Permit Conditions ~ Duty to Reapply ~ Need to Halt or Reduce Activity Not a Defense '7 Duty to Mitigate ~ Proper Operation and Maintenance '7 Duty to Provide Information '7 Inspection and Entry g Records g Reporting Requirements 10 Anticipated Noncompliance 10 Twenty-Four Hour Reporting 10 Other Noncompliance 11 Reporting Corrections 11 Signatory Requirements 11 PLUGGING AND ABANDONMENT 12 Notice of Plugging and Abandonment 12 Plugging and Abandonment Report 12 Cessation Limitation 12 Cost Estimate for Plugging and Abandonment 13 FINANCIAL RESPONSIBILITY 13 PART II WELL SPECIFIC CONDITIONS CONSTRUCTION Casing and Cementing Tubing and Packer Specifications New Wells in the Area of Review CORRECTIVE ACTION WELL OPERATION Prior to Commencing Injection During Injection Mechanical Integrity Injection Zone Waivers to UIC Program Requirements Injection Pressure Annulus Pressure Injection Fluid Limitation MONITORING Monitoring Requirements Continuous Monitoring Devices Monitoring Direct Waste Injection Alarms and Operational Modifications REPORTING REQUIREMENTS Quarterly Reports Annual Reports Report Certification REPORTING FORMS r~ L Page 4 of 24 14 14 14 14 14 15 15 15 16 17 19 20 21 21 21 21 21 21 22 22 22 22 24 23 24 U Page 5 of 24 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 permit renewal application submitted by BPXA on February 2, 2010. Additional materials that were reviewed included the data submitted prior to issuing the original Permit No. AK-1I002-A by EPA in August 2000. B. PERMIT ACTIONS Modification; Reissuance, or Termination This permit may be modified, revoked and reissued, or terminated for cause as specified in 40 C.F.R. §§ 144.39 and 144.40. In addition, the permit can undergo minor modifications for cause as specified in 40 C.F.R. § 144.41. The filing of a request for a permit modification, revocation and reissuance, or termination, or the notification of planned changes, or anticipated noncompliance on the part of the Permittee does not stay the applicability or enforceability of any permit condition. • Page 6 of 24 2. Transfer of Permits This permit is not transferable to any person except after notice to the Director on APPLICATION TO TRANSFER PERMIT (EPA Form 7520-7) and in accordance with 40 C.F.R. § 144.38._ The Director may require modification or revocation and reissuance of the permit to change the name of the Permittee and incorporate such other requirements as may be necessary under the SDWA. C. SEVERABILITY The 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 maybe 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: The name and address of the Permittee. 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. Page 7 of24 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 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 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. 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 Page 8 of 24 compliance with this permit. The Permittee shall also provide to the Director, upon request, copies of records required to be kept by this permit. 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, otherwise, authorized by the 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 (or electronic data) for continuous monitoring instrumentation, copies of all reports required by this permit and records of all data used to complete this permit application for a period of at least three years from the date of the sample, measurement, report or application. These periods may be extended by request of the Director at any time. b. 'The Permittee shall retain records concerning the nature and composition of all injected fluids until .three years after the completion of plugging and abandonment. At the conclusion of the retention period, if the Director so requests, the Permittee shall deliver the records to the Director. The Permittee shall continue to retain the records after the three-year retention period unless he delivers the records to the Director or obtains written approval from the Director to discard the records. i • Page 9 of 24 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; (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. 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 waste analysis plan (WAP). The WAP must include the critical elements needed to satisfy EPA's quality assurance project plan (QAPP) requirement. The WAP must describe the procedures to be carried out to obtain detailed chemical and physical analysis of representative samples of the waste including the quality assurance procedures used including the following: (1) The parameters for which the waste will be analyzed and the rationale for the selection of these parameters; (2) The test methods that will be used to test for these parameters; and (3) The sampling method that will be used to obtain a representative sample of the waste to be analyzed. This permit covers active Class I wells that have been in operation since January 2001. The WAP from the permit application maybe incorporated by reference to satisfy the WAP plan submittal requirements. Page 10 of 24 g. For waste streams that are not hard piped and continuous, the Permittee shall complete a written manifest for each batch load of waste received. 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 provide for continuous, recorded measurement of the discharge rate. h. Dates of the 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. • Page 11 of 24 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 E.12.b. 14. Reporting Corrections When the Permittee becomes aware that he/she failed to submit any relevant facts in the permit application or submitted incorrect information in a permit application or in any report to the Director, the Permittee shall promptly submit such facts or corrected information. 15. Si~natory Requirements a. All permit submittals required by this permit and other information requested by the Director shall be signed by a principal executive officer of at least the level ofvice-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 ofvice-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 Page 12 of 24 the overall operation of the facility, a new authorization satisfying the requirements of paragraph 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." F. PLUGGING AND ABANDONMENT Notice of Plugging and Abandonment The Permittee shall notify the Director no later than 45 days before conversion or abandonment of any Class I well(s). 2. Plugging and Abandonment Report The Permittee shall plug and abandon the well as provided in the Well Abandonment portion (Section 1.3 and Exhibit 1-7C/EPA Form 7520-14 of the February 2, 2010, permit application), which is hereby incorporated as a part of this permit or an updated plan approved by the Director or EPA representative. Abandonment plans will be implemented in accordance with AOGCC and EPA regulatory requirements, as well as utilizing current technology applicable to the condition of the well at the time. 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 cessation of facility 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; • Page 13 of 24 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 wells NS 10 and NS32 to be approximately one million dollars per well. The Permittee must submit financial assurance and a revised plugging and abandonment estimate prior to April each year. The estimate shall be made in accord with 40 C.F.R. § 144.62. b. The Permittee must keep at the facility at Northstar or at the Permittee's central files in Anchorage during the operating life of the facility the latest plugging and abandonment cost estimate. c. When the cost estimate changes, the documentation submitted under 40 C.F.R. § 144.63(f) shall be amended to ensure that appropriate financial assurance for plugging and abandonment is maintained continuously. d. 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 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 in writing. The Permittee shall not substitute an alternative demonstration of financial responsibility for that which the Director has approved, unless it has previously submitted evidence of that alternative demonstration to the Director and the Director notifies him that the alternative demonstration of financial responsibility is acceptable. Page 14 of 24 PART II WELL SPECIFIC CONDITIONS A. CONSTRUCTION 1. Casing and Cementing of Existing Sidetrack and/or Replacement Wells The Permittee shall case and cement the well(s) to prevent the movement of fluids into strata other than the authorized injection interval (see II.C.3, 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 will also follow the State of Alaska/AOGCC Regulations (20 AAC 25.412 and 20 AAC 25.252). For any other future Class I wells to be drilled at this location (including replacement/sidetracks), in addition to the above requirements, the Permittee shall provide not less than ten days advance notice to the Director or EPA authorized representative to witness all cementing operations. If primary cement returns to surface are not observed for the surface casing cementing procedure, the Director or an 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. Note: Since these are existing Class I wells NS10 and NS32 drilled, cemented and completed as per EPA and AOGCC regulations in 2001 and 2004 respectively, EPA is accepting the current well casing and cementing configuration as meeting the requirements of this section. 2. Tubing and Packer Specifications The well shall inject fluids through tubing with a packer. The current tubing and packer locations for well and NS32 are approved. In future sidetracks, replacement wells and workovers to install new tubing, the tubing and packer shall be installed in the casing with the packer set not more than 100 feet MD from the'top of the permitted injection zone/interval (based on well testing and reservoir/log analysis) and confirmed by tubing tally. In the event that the packer needs to be re-set at a revised depth at a later date, the Permittee will submit the necessary data and obtain authorization from EPA, prior to resumption of continued injection activities. New Wells in the Area of Review New wells within the Area of Review (AOR) shall be'constructed in accordance with the EPA and AOGCC Regulations Title 20, Chapter 25. Further, all wells that penetrate the injection intervals within the area of review shall have casing • C~ Page 15 of 24 cemented to the formation throughout the entire section from at least the top of the lower confining zone (Colville/Seabee CM3 Formation Marker underlying the Schrader Bluff injection interval) to at least 100 feet TVD above the top of the permitted secondary Sagavanirktok injection interval SV2 (from approximately 6,784 feet TVDss to the SV2 marker at 4,042 feet TVDss) based on NS32 completion logs. B. CORRECTNE ACTION The applicant has identified two wells within the areas of review for-wells NS10 and NS32 at the Northstar project site. 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 Prior to Commencing Injection Under This Permit in Existing. Sidetrack or Replacement Wells Injection operations pursuant to this permit shall 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 b, 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 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 days of receiving the COMPLETION REPORT in which case prior inspection or review is waived and the Permittee may commence injection; and The Permittee demonstrates that the well has mechanical integrity as described in Part II.C.3. 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 four weeks prior to conducting this initial test so that an EPA representative may be present. Note• Since these wells NS 10 and NS32 have been on infection since • Page 16 of 24 January 2001 and May 2004 respectively and with mechanical integrity successfully demonstrated on an annual basis since 2001 the requirements of C. l .a. and C.7.b. from above have been met. However, the requirements under Part II. C. 3. -Mechanical Integrity remain in force for wells NS10 and NS32; and ' d. The Permittee has conducted astep-rate injection test (SRT) and submitted a preliminary report to EPA that summarizes the results. A SRT. was conducted in April 1999 and the results were submitted to EPA. Therefore, the Permittee is not required to conduct another SRT prior to resumption of Class I injection activities upon renewal. 2. During Injection Recording and non-recording inj ection pressure gauges, inner annulus (IA) and outer annulus (OA) gauges, injection rate gauges, and temperature gauges will be maintained. Out-of--limit Alarms and shut-off systems will be maintained and the injection facility plant shall be manned by trained and qualified operators during injection. Visual and automatic monitoring of the IA and tubing pressures will occur routinely with pre-set, out-of--limit alarms to inform supervisory personnel. 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/casing annulus must be pressure tested to at least 3,500 pounds per square inch gauge (psig) for not less than thirty minutes. Pressure shall show a stabilizing tendency. That is, the pressure may not decline more than 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 five 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 - Page 17 of 24 additional 30 minutes to demonstrate stabilization. Since these wells have been on injection since January 2001 and May 2004 respectively and have successfully demonstrated their mechanical integrity (both internal and external) on an annual basis (with the tests being witnessed by EPA representatives), the wells are approved to continue injection upon approval of this permit renewal. The SAPT will be required annually if the well(s) is active and once every two years if the well(s) are inactive. The SAPT due dates maybe 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 (inner annulus mechanical integrity test) data, the frequency for demonstrating internal mechanical integrity (no leaks in the tubing-casing annulus or in the tubing-packer assembly) may be revised (either increase or decrease in frequency) as specified and approved by the Director or authorized 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 initially upon completion of the new or replacement or sidetrack well and prior to initiation of injection at start-up. After acquiring this baseline data, the fluid movement/confinement logs will be required every two years while the well(s) are active until expiration of the ten year permit period. The test due dates maybe 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 that penetrates the confining zone) and utilizing alternative diagnostic techniques, may be revised (either increase • Page 18 of 24 or decrease in frequency) as specified and approved by the Director or authorized representative. (3) Tubing inspection logs (pipe analysis logs, caliper logs, or other equivalent logs) shall be run once every two years while the well(s) are active, or at the Director or authorized representative's discretion, to monitor condition, thickness and integrity of the downhole tubing. A three month grace period is granted to the test due dates. Any exposed section of the injection casing previously located behind the tubing tail must be logged during any scheduled workover for tubing change-out. In the event that (1) surveillance determines tubing above the packer wall losses or casing above the packer wall losses exceed 80% of the wall thickness or (2) for other reasons, EPA or Permittee believe the downhole tubular integrity maybe compromised, surveillance logs and other information shall be reviewed by EPA and Permittee to determine if additional surveillance or remedial activities are necessary. EPA reserves the right to have the Permittee shut in the well pending diagnostics or well repair, or until a successful tubing/casing annulus pressure test under Part II C.3.b(1). Copies of the logs shall be accompanied by a descriptive and interpretive report. c. Terms and Reporting (1) Two copies of the log(s) and two copies of a descriptive and interpretive report of the mechanical integrity tests identified in C.3.b shall be submitted within 45 days of completion of the testing and logging. (2) Mechanical integrity shall also be demonstrated by the pressure test in Part II C.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 thirteen days of receipt of the results of the mechanical integrity tests. Injection operations may continue during this thirteen day review period. If the • Page 19 of 24 Director does not respond within thirteen days, injection may continue. (5) In the event that the well fails to demonstrate mechanical integrity during a test or a loss of mechanical integrity occurs during operation, the Permittee shall halt operation immediately and shall not resume operation until the Director or EPA authorized representative gives approval to resume injection. (6) The Director may, by written notice, require the Permittee to demonstrate mechanical integrity at any time. 4: Infection Zone Injection shall be limited to the Schrader Bluff/Ugnu (current primary injection interval) and Sagavanirktok (future secondary injection interval for use if needed) Formations, below the top of the Sagavanirktok SV2 formation marker at approximately 4,042 feet TVDss as depicted on the NS32 electric logs. The permitted injection zone extends to the CM3 marker estimated at 6784 feet TVDss in NS32. 5. Waivers to UIC Pro~am Requirements As a result of the "no USDW" ruling for Class I injection granted by EPA in 2000 when the original permit was issued, EPA is granting three 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 data (utilized in the fracture model studies) and successful injection practices at Northstar since January 2001, EPA waives 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. Infection 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 successful ten year performance history at NS10 and NS32 and the fracture modeling data submitted by BPXA • C~ Page 20 of 24 which confirms that the injection fluids are contained within the injection zone, the EPA permit waives this prohibition. In no case shall injection pressures initiate fractures in the upper and lower confining intervals. c. Ambient Monitorine Above the Confining Zone (40 C F R ~ 146 13(a))• There are no USDWs (between the base of the permafrost at approximately 1,519 feet TVDss and the top of the injection zone at approximately 4,042 feet TVDss) (based on NS32 electric logs) in this area, no transmissive faults within % mile of the current injection wells, the formations are thick and laterally extensive, and the possibility of any waste migration above the upper confining zone is extremely low (fracture height contained within the injection zone). Also, the only two wells within the AOR are adequately cemented and therefore do not require any corrective action. Therefore, 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. (See Part II C.3.b(2)). 6. Injection Pressure Injection pressure shall not initiate new fractures or propagate existing fractures in the upper confining zone as that stratigraphic interval (SV6 marker at approximately 3,047 feet TVDss and a base at 3305 feet TVDss) described in the NS32 electric logs. 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 to provide additional security. 7. Annulus Pressure The annulus between the tubing and the long string casing shall be filled with a corrosion inhibited non-freezing solution. To accommodate swings in wellbore temperatures and tubing thermal expansion, a positive surface pressure up to 1500 psig is authorized for the inner annulus (tubing x long string injection casing). Since the tubing-casing annulus 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 EPA authorized representative. • Page 21 of 24 Note: The authorization of up to 1500 psig 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 IA x OA), resulting in a potential sustained casing pressure (SCP) 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. Ini ection 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, maybe disposed in a Class I non-hazardous injection well. De-characterized waste generated during remedial well workovers or well construction operations maybe appropriately disposed in aClass Inon-hazardous well (refer to 40 C.F.R. § 148.4(d)). NOTE: Neither hazardous waste as defined in 40 C.F.R. § 261 nor radioactive wastes other than naturally occurring radioactive material (NORM) from pipe scale shall be injected for disposal. D. MONITORING 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 ofnon-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. • • Page 22 of 24 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 pressures. These alarms must be of sufficient placement and urgency to alert operators in the control room. b. The Permittee shall install and maintain an emergency shutdown system to respond to losses of internal mechanical integrity as evidenced by deviations in the annular fluid pressures. c. Plans and specifications for the alarms shall be submitted to the Director or authorized representative prior to the initiation of injection. Since Wells NS 10 and NS32 are existing_Class I wells and have been on injection since January 2001 and current information was submitted in the February 2, 2010, permit application, the monitoring and alarm systems in place for Wells NS 10 and NS32 are hereby approved as meeting the requirements of this section. E. REPORTING REQUIREMENTS 1. Quarterlyports The Permittee shall submit quarterly reports to the Director containing the following information: a. Monthly average, maximum, and minimum values for injection pressure, rate, and volume shall be reported on INJECTION WELL MONITORING REPORT (EPA Form 7520-8). b. Graphical plots of continuous injection pressure and rate monitoring. c. Raw monitoring data in an electronic format. d. Physical, chemical, and other relevant characteristics of the injected fluid. • Page 23 of 24 e. Any well workover or other significant maintenance of downhole or injection-related surface components. £ 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: Director, Office of Compliance and Enforcement U.S. Environmental Protection Agency (OCE-164) 1200 Sixth Avenue, Suite 900 Seattle, Washington 98101 Any notification to an EPA authorized representative maybe submitted to the following address: UIC Manager, Ground Water Unit U.S. Environmental Protection Agency (OCE-082) 1200 Sixth Avenue, Suite 900 Seattle, Washington 98101 Page 24 of 24 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 OMB No. 2040-0042 Aooroval Ezeiras 12/3t/2011 United States Environmental Protection Agency ~/EPA Washington, DC 20460 Application To Transfer Permit Name arid Address bf Existing Permittee " - ' - " -" Name and Address of Surface Owner I i I ~ ( i i Locate Wail a.^.d Qut!ine U.^.it on Section Plat - 640 Acres W 7-r7- 7-r-7 - --F - ~ ~ - ~ f -+ - ~ --t- - I ~ ~ ~ ~ _ T r--T I I I _~rT( T I I 1 --~ - ~ ~- - I ---h - ~ ---~ - and Address(es) of New Permit Number ' s Surface Location Description x__,'1/4 of~ ii 114 of r ~ 1/4 of ~ 1/4 of Section ` !Township `_~ Range r Locate wall in two directions from nearest lines of quarter section and drilling unit Surface Location 4 ift. frm (N!S)'_1 Line of quarter section and ~,~!ft. from (E/W)!,,,,,•Line of quarter section. Well Activity Well Status ;_,,,4 Class I ~ ~ Class II ~r ^~ Brine Disposal - Enhanced Recovery _, l~ Hydrocarbon Storage ' !Gass III ~ Other Lease Number ~_ (Operating !^ Modification/Conversion Proposed Type of Permit Ilndividual `Area Number of Wells Well .Number j t j Name and Address of New Operator i i 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 frnancial responsibility by the submission of a surety bond, or otheradequafe 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 ern rortn rnzo•r ireev. iz-ual PAPERWORK REDUCTION ACT The public reporting and record keeping burden forthis collection ofinformation is estimated to average 5 hours per response. Burden means the totattime-effort,~orfinanciat 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 reviewthe collection ofinformation; and, transmitorotherwisedisclosethe information.An agencymay not conduct or sponsor, and a person is not required to respond to, a collection ofinformation 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. Weil Class and Type Code Class 1 Wells used to inject waste below the deepest underground source of drinking water. Type "1" Nonhazardous industrial disposal well "M" Nonhazardous municipal disposal well "W" Hazardous waste disposal well injecting below USDWs "X" Other Class I wells (not included in Type "I," "M," or "W") Class II Oil and gas production and storage related injection wells. Type "D"' Produced fluid disposal well "R" Enhanced recovery well "H" Hydrocarbon storage well (excluding natural gas) "X" Other Class II wells (not included in Type "D," "R," or "H") Class III Special process injection wells. Type "G" Solution mining well "S" Sulfur mining well by Frasch process "U" 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, III, or V EPA Form 7520-7 (12-08) Reverse OMB No. 2040-0042 Approval Expires 12/31!2011 United States Environmental Protection Agency ~~EPA Washington, DC 20468 ,Injection Well Monitoring Report ------_ . _ ......_.._ Year';--- -- - -- -_. _.. _ _. .._ ... -- Month---._ _ _._... _....._ ._ ._. ..__ Manth' _ _ - - ...._ __ _ Month .. __ . _ _ Injection Pressure (PSI) ! i -- ~ 1. Minimum i ( r ( , ~~ ~ 2. Average ~ i i i i i 3. Maximum 1 j Injection Rate (GaI1Min) ~ i ~ ---; ~ i 1. Minimum t ) ~ ~ ~ t 2. Average ( ~ ~s i _ I 3. Maximum I ~ ) ~ ! ~ Annular Pressure (PSI) ~ ~ ? # i 1. Minimum ` } i , e I 2. Average ~ ; I i i i 3. Maximum l 3 r ~ { Injection Volume (Gal) i ~ ~ i i ' ... 1. Monthly Total . ! ! ) 2. Yearly Cumulative ~ ~ ~ ) ~ Temperature (F °) ~ _.._~ € i s ~---- L - 1. Minimum j ~ ( i----- ~ i 2. Average ; f i I ; I ) 3. Maximum ~ i ~ ~ ~ i pH + ~ ( t ~ w. ~..w I 1. Minimum ~ I t ~ E i j ` 2. Average i ~ ~ I 3. Maximum ~ ; ~--~ Other ~ ; i i j I 4 ) L ~ i = ; ~ . l .. `` i t I { Name and Address of Permittea I Permit Number I_____ ------ Name and Official Title Please type or riot ~_ Signature Date Signed EPA Form 7520-8 (Rev. 12-08) OMB No. 2040-0042 Approval Expires 12/31/2011 United States Environmental Protection Agency EPA Washington, DC 20460 ~ ~ Completion Form For Injection Weiis ___. _.... Administrative-lnionrnatiort -_ _ _ ...__ ....;. 1. Permittee t i t j 's Address (Permanent Mailing Address) (Street, City, and LP Code) i i I I ~ i 2. Operator I I ~ i Address (Street, City, State and ZIP Cade) e f ~ 3, Facility Name Telephone Number I ,. E i , I i Address (Street, City, State and Z1P Code) I F j i ~I ~ ; 4. Surface Location Description of Injection Well(s) State Count ~ ~ I y I i Surface Location Description li/4 ofd !1/4 of ~-.114 of; !114 of Section%! Township_ Ranged ~ Locate well in two directions from nearest lines of quarter section and drilling unit Surface ~-~ t~-^^ Loeationi i ft. frm (Nt5) I f Line of quarter section I and Eft: from (E/W). . '1 Llna of quarter section. Walt Activity WeII Status Type of Permit [- Class I f !! y Individual .Operating - f ~ Class II ~ Modification/Conversion _ Area :Number of Wells _ ~, Brine Disposal ~ proposed ~? Enhanced Recovery Hydrocarbon Storage ~_ Class III ~~ Other i Lease Number! Well Number I t Submit with this Completion Form the attachments listed in Attachments for Completion Form. Certification 1 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 helieve 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 f ~.~ EPA Form 7520-9 (Rev. 12-08) PAPERWORK REDUCTION ACT The public reporting and record keeping burden for this collection of information is estimated to average 49 hours per response fora Class I hazardous facility, and 47 hours per response for aClass Inon-hazardous facility. Burden means the total time, effort, or financial resource expended by persons to generate, maintain, retain, or disclose or provide information to orfor 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; comprete and review the collection of information, and; transmiror etherrrise disclose- the informatiort:.An agency may notconduct 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 StrategiesDivision, U.S. Environmental Protection Agency (2822), 1200 Pennsylvania Ave., NW, Washington, D.C. 20460. Include the OMB control number in any correspondence. Do not send the completed fo~~ss t0 this addi eSS. Attachments to be submitted with the Completion report: I. Geologic Information 1. Lithology and Stratigraphy A. Provide a geologic description of the rock units pene- trated by name, age, depth, thickness, and lithology of each rock unit penetrated. B. Provide a description of the injection unit. (1) Name (2) Depth (drilled) (3) Thickness (4) Formation fluid pressure (5) Age of unit (6) Porosity (avg.) (7) Permeability (8) Bottom hole temperature (9) Lithology (10) Bottom hold pressure (11)Fracture pressure C. Provide chemical characteristics of formation fluid (attach chemical analysis): D. Provide a description of freshwater aquifers. (1) Depth to base of fresh water (less than 10,000 mg/I TDS). (2) Provide a geologic description of aquifer units with name, age, depth, thickness, lithology, and average total dissolved solids. II. Well Design and Construction 1. Provide data on surface, intermediate, and long string casing and tubing. Data must include material, size, weight, grade, and depth set. 2. Provide data on the well cement, such as type/class, additives, amount, and method of emplacement. 3. Provide packer data on the packer (if used) such as type, name and model, setting depth, and type of annular fluid used. 4. Provide data on centralizers to include number, type and depth. 5. Provide data on bottom hole completions. 6. Provide data on well stimulation used. tll. Description of Surface Equipment 1. Provide data and a sketch of holding tanks, flow lines, filters, and injection pump, IV. Monitoring Systems 1. Provide data on recording and nonrecording injection pressure gauges, casing-tubing annulus pressure gauges, injection rate meters, temperature meters, and other meters or gauges. 2. Provide data on constructed monitor wells such as location, depth, casing diameter, method of cementing, etc. V. Logging and Testing Results Provide a descriptive report interpreting the results of . geophysical logs and other tests. Include a description and data on deviation checks run during drilling. VI. Provide an as-built diagrammatic sketch of the injec- tionwell(s) showing casing, cement, tubing, packer, etc., with proper setting depths. The sketch should include well head and gauges. VII. Provide data demonstrating mechanical integrity pursuant to 40 CFR 146.08. VIII. Report on the compatibility of injected wastes with fluids and minerals in both the injection zone and the confining zone. IX. Report the status of corrective action on defective wells in the area of review. 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 utilize technology and systems for the purposes of collecting, validating, and verifying information, processing and maintaining information, and disclosing and providing information; adjust the existing ways to comply with.any previously applicable instructions and requirements; train personnel to be able to respond to the collection of information; search data sources; complete and review the collection of information; and, transmit or otherwise disclose the information. An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. Send comments on the Agency's need for this information, the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden, including the use of automated collection techniques to Director, Collection Strategies Division, U.S. Environmental Protection Agency (2822), 1200 Pennsylvania Ave., NW., Washington, D.C. 20460. Include the OMB control number in any correspondence. Do not send the completed forms to this address. EPA Form 7520-3 Reverse • BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator, PRB-20 Post Office Box 196612 Anchorage, Alaska 99519-6612 April 21, 2010 Mr. Tom Maunder Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Corrosion Inhibitor Treatments of Northstar Dear Mr. Maunder, by R~C~I~/EQ ~A~a.~201~ DA~t~s!' Andx~rs ~5~a~ Enclosed please find a spreadsheet with a list of wells from Northstar that were treated with corrosion inhibitor in the surface casing by conductor annulus. The corrosion inhibitor is engineered to prevent water from entering the annular space and causing external corrosion that could result in a surface casing leak to atmosphere. The attached spreadsheet represents the well name, top of cement depth prior to filling and volumes of corrosion inhibitor used in each conductor. As per previous agreement with the AOGCC, this letter and spreadsheet serve as notification that the treatments took place and meet the requirements of form 10-404, Report of Sundry Operations. If you require any additional information, please contact me or my alternate, Jerry Murphy, at 659-5102. Sincerely, Torin Roschinger BPXA, Well Integrity Coordinator • BP Exploration (Alaska) Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off Report of Sundry Operations (10-404) i~ Date Northstar a/~n/~n1 n Well Name PTD # API # Initial top of cement Vol. of cement um ed Final top of cement Cement top off date Corrosion inhibitor Corrosion inhibitor/ sealant date ft bbls ft na al NS05 2050090 50029232440000 1.7 na 1.7 na 10 4/30/2009 NSO6 2021010 50029230880000 0.5 na 0.5 na 1.7 4/30/2009 NS07 2020770 5002J230810000 1.1 na 1.1 na 5.3 4/30/2009 NS08 2020210 50029230680000 0.75 na 0.75 na 3.6 4/30/2009 NS09 2012190 50029230520000 1.2 na 1.2 na 3.4 4/30/2009 NS10 2001820 50029229850000 0.25 na 0.25 na 3 4/30/2009 NS11 2060360 50029233030000 0.75 na 0.75 na 5.1 5/1/2009 NS12 2021100 50029230910000 1.2 na 1.2 na 3.2 5/1/2009 NS13 2010860 50029230170000 1.7 na 1.7 na 6.8 5/1/2009 NS14A 2052020 50029230260100 0.9 na 0.9 na 2.8 5/1/2009 NS16A 2061410 50029230960100 1.3 na 1.3 na 5.8 5/1/2009 NS17 2021690 50029231130000 1.2 na 1.2 na 2.6 5/1/2009 NS18 2021410 50029231020000 1.5 na 1.5 na 7.3 5/1/2009 NS19 2022070 50029231220000 1.5 na 1.5 na 10.2 5/2/2009 NS20 2021880 50029231180000 1.4 na 1.4 na 8.5 5/2/2009 NS21 2022180 50029231260000 1.7 na 1.7 na 4.3 5/2/2009 NS22 2022230 50029231280000 1.6 na 1.6 na 10.2 5/2/2009 NS23 2030500 50029231460000 0.75 na 0.75 na 3 5/2/2009 NS24 2021640 50029231110000 0.75 na 0.75 na 2.6 5/2/2009 NS25 2031660 50029231810000 na na 2.6 5/2/2009 NS-26 2002110 50029229960000 at surface na na na na na NS27 2010270 50029230030000 0.6 na 0.6 na 1 5/3/2009 NS28 2050160 50029232480000 1.5 na 1.5 na 8.1 5/3/2009 NS30 2052070 50029232930000 0 na 0 na 4.3 5/3/2009 NS32 2031580 50029231790000 na na 1.7 5/3/2009 NS33A 2081890 50029233250100 Sealed conductor na na na na NS34A 2080170 50029233010100 0 na 0 na 2.2 5/3/2009 "Not measured due to rig proximity. • • Proposed Schedule for 2010 Mechanical Integrity Testing Class 1 Well (s) MIT Deadline Proposed MIT Flexibility Fluid Movement test date in test Logs Planned after date? MIT? Milne Point By April 6, 2010 Late March/Early Fluid movement logs MPB-50 April 2010 are not required till -~ ~ _ L7 2011. Badami 61-01 By September Late July 2010 Weather Fluid movement logs 15, 2010 permitting are required in 2010 because of the scheduled drilling program and are planned during the ~~'..1 ~, 5 ~ summer barge season. Northstar NS10 By August 12, Late July 2010 The Water Flow Logs 2010 will be conducted during the summer a~®'° ~~~ bar a season. Northstar NS32 By August 12, Late July 2010 The Water Flow Logs 2010 will be conducted during the summer O~-~~ bar e season. Libe y Well N/A September 2010 All logs required to complete the well will ~®~- ~ ~(, ~~ ~ ~ ~- be scheduled with the MIT. Pad 3 - NW, SE, By September Late September Yes Borax-RST logs for and SW 26, 2010 for SE /Early October, each well, scheduled `®'C7 °` a ~ ~ and NW wells 2010 with MIT's. and by Caliper logs in ~~ ~ November 7, summer/fall 2010. ~a`t ~ 2010 for SW well (Can be 3 months later with Director discretion Grind and Inject By October 25, Late September Yes Shut -In Temperature -GNI-02A, GNI- 2010 for GNI- /Early October, Logs and/or Water 03 ,and GNI-04 02A, GNI-03 and 2010 Flow Logs planned for ~~~- i i~ GNI-04. summer 2010. Caliper logs in 1 ``t " ~ ~ summer/fall 2010. ~~~~ by • Alison D. Cooke Environmental Advisor, Air Quality CERTIFIED MAIL # 7008 1830 0001 2703 7263 February 23, 2010 Mr. Edward J. Kowalski Director, Office of Compliance and Enforcement U.S. Environmental Protection Agency 1200 Sixth Avenue Seattle, WA 98101 Mr. Jim Regg Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501-3192 Mr. Shawn Stokes Department of Environmental Conservation 555 Cordova St. Anchorage, AK 99501 .;, ~~ -~ BP Explora on (Alaska) Inc. P. 0. Box 196612 900 E. Benson Boulevard Anchorage, AK 99519f612 Direct 907 561 5111 Phone: (9071564-4838 Email: Alison.Cooke~bp.com Web: www.bp.com FED ~ 4 20ir. ~'assrda ~! & l~l„ ~n RE: Mechanical Integrity Test Notifications Badami Class 1 Iniection WeN~ UIC Permit AK-11001-A, Disposal Iniection Order No. 12 General Wastewater Permit No. 2005DB001-0010 Northstar Class 1 Iniection Wells. UIC Permit AK-11002-A General Wastewater, Permit No. 2005DB001-0020 Milne Point Iniection Well. UIC Permit AK-11005-A General Wastewater Permit No. 2005D6001-0001 Pad 3 Iniection Wells, UIC Permit AK-11004-A Wastewater Disposal Permit No. 2005DB0001-0021 Grind and Inject Injection Wells. UIC Permit AK-11008-A Area Iniection Order No. 4E General Wastewater Permit No. 2005DB001-0012 Liberty Class 1 Iniection Well, UIC Permit AK-11013-A General Wastewater Permit No. 2005DB001-0025 Mechanical Integr~est Notification = February 23, 2010 Page 2 Dear Sirs: BP Exploration (Alaska) Inc. (BPXA) respectfully submits the following notifications: 11 the annual Mechanical Integrity Test (MIT) and fluid movemert test that is required every other year at the Badami Class 1 well to meet the permit requirement in UIC Permit AK-11001-A; 2) the MIT and fluid movement tests at the Northstar NS10 and NS32, Class 1 wells to meet the annual permit requirement in UIC Permit AK-11002-A; 3) the MIT and fluid movement test that is required every three years at the Milne Point Class 1 well to meet the permit requirement in UIC Permit AK-11005-A; 4) the MIT and fluid movement tests at the Pad 3 Class 1 wells in the Prudhoe Bay Unit to meet the annual permit requirement in UIC Permit AK 11004-A; 5) the MIT and fluid movement tests at the Grind and Inject Facility, in the Prudhoe Bay Unit to meet the annual permit requirement in UIC Permit AK-11008-A; and 6) the MIT and fluid movement test that is required at the Liberty Class 1 well to meet the permit requirement in UIC Permit AK-11013-A. By this letter BPXA is providing the written notification required by the aforementioned permits. In addition, BPXA staff will be coordinating the timeframes for these MIT and fluid movement tests with Mr. Thor Cutler of the Environmental Protection Agency (EPA) to maximize efficiencies associated with the travel arrangements of the EPA inspector, so that multiple tests of Class 1 wells can be witnessed in one trip to the North Slope. A summary of the proposed annual testing is presented in the attached table. The fluid movement test procedures that require EPA approval have been or will be sent under separate cover or by a-mail. If you have any questions, please contact me at (907) 564-4838. Sincerely, ~• ~ Alison Cooke Environmental Advisor Attachment cc: Thor Cutler, EPA Region 10 Talib Syed, EPA Consultant by Tom V. Marshall Head of Operations Alaska Consolidated Team (ACT) Sent via F+c1dEx February 2, 2010 UIC Manager, Ground Water Protection Unit U.S. Environmental Protection Agency (OCE-127) 1200 Sixth Avenue Suite 900 Seattle, Washington 98101 RE: Renewal Application for UIC Permit AK-11002A Dear UIC Manager: BP Exploration (Alaska) Inc. P. 0. Box 196612 900 E. Benson Boulevard Anchorage, AK 99519612 Direct 907 561 5111 Phone: (907) 564-5006 Fax: 1907) 564-4441 Email: MarshaTV~bp.com Web: www.bp.com ~GV~p ~/ E~ FEB 0 3 2010 ~I~ska Oil ~ bas Cons. Commission Anchorage The Northstar UIC permit AK-11002A will expire on August 4, 2010. By this letter and submittal of the attached application, BP Exploration (Alaska) Inc. requests the Environmental Protection Agency renew the permit for another 10 year term. The two Class I disposal wells at the Northstar facility have successfully injected approximately 32 million barrels of waste. I certify under 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. If you need any clarification or additional information concerting this application, please contact Alison Cooke, at (907) 564-4838 or Alison.Cooke~bp.com. Sincerely, ~S° ~ ~ ~~ -~~~ Tom V. Marshall ~ ~ ~ ~~~~ F' ~ `E Attachments cc: Thor Cutler, EPA Region 10 (hard copy w/application) Talib Syed, PE/Talib Syed and Associates (hard copy w/application) Dan Seamount, AOGCC (hard copy w/o application) Shawn Stokes, ADEC (hard copy w/o application) OM8 No. 2040-0042 Approval Expires 1213112011 United States Environmental Protection Agency .. p set fv)rP,A 1D lluMbeR', .."r '?; ~ ~ Underground Injection Control TIA c ~-iEPA Permit Application (Collected under the authority of the Safe Drinking Water Aet. Sections 1421, 1422, 40 CFR 144) U I i ~ i u ~ Read Attached Instructions Before Starting For Official Use Only Application approved mo day year Date received mo day year Permit Number Well ID FINDS Number ~ ~ ~ ~ ~ ~~ ~ ~ I s 'A ~it,QsrtlerHameapdAddfstEa ~ r~ `s1 J At;;QderatiDrNBma-and~Adtlres~~ ;~, . _ ~lIIIR._ BP Exploration (Alaska) Inc. ~ Owner Name BP Exploration (Alaska) Inc. Street Address Phon Number Street Address ~- Phone Number _°--°~~ ~~~~~ I Benson Blvd 900 E 907 561-5111 ~ 900 E. Benson Blvd. 907 561-511 I . . ( Ci State ZIP CODE Cit~ --~ State DE __ ZIP CO ty ,.~._~_--_ Anchorage ~~ ® ~9950~ 8 ~o _ ~ lLAnchorage ® F '9, 9508 1 IY. Gam~e[tsial faoility Y..9wn6rsMY YJ, ksgal toritp¢t Hli.-'SIC Codes ,;' - , y~ No (~~ Private Federal Other 8 owner Operator ~ SIC Codes 1311 and 2911 ~ i L._,.44 j -;,;. - ,, - ,~ - .. Vgl.lKe1t Status It4t~"'x'7` ~I A Date Started mo day year '~} g, Modification/Conversion ~ C. Proposed Operating 41/26/2001 M_J IX. Type.Qf Perm(t R~ueatea {Mark x" siiSl.specify ~r.eyurredJ ' ~ - t~ Number of Existing Wells Number of Proposed Wells Name(s) of field(s) or project(s) ~".~ A. Individual t=~ B. Area ~2 wells NS 10 and NS32 ~ ~2 wells NS 10 and NS32 i 1 Northstar Unit -Beaufort Sea ~ Offshore Production Island X, Ciass~dd7ype o1 Wetb jsae ieverse) - T e(s) B ' explain If class is "other" or type is code 'x C D. Number of wells per type (if area permit) A. Class(es) (enter code(s)) yp . (enter code(s)) , . ii ~ i (L - Class I (Industrial) _~ XI, Location of`WetA(s) br'Appraxima~ Geater of F1eld or Project X1F, lndlart tantls (ftJprk;'x'1 :` Latitude Longitude Township and Range Yes Deg Min Sec Deg Min Sec Sec T Range 114 Sec Feet From Line Feet From Liner ~ ~ No L7p ~ '2~9 ~ 29 (148 41 ~ 46 1~ N ~ 13E I1 SE 615 E~ 1360 ~ ~~; - XIIF. Attachments - (Complete the following questions on a separate sheet(s) and number accordingly; see Instructions) For Classes I, 11, III, (and other classes) complete and submit on a separate sheet(s) Attachments A-U (pp 2-S) as appropriate. Attach maps where required. List attachments by letter which are applicable and are included with your application. - ~ ~ XIV: Certlfica~n _ ' 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 possiblifty of tine and imprisonment. (Ref. 40 CFR 144.32) A. Name and Title (Type or Print) _ Tom Marshall -Head of era ' s Alaska Co olidated Team ~ B. Phone No. (Area Code and No.) (907) 564-5006 -~ C. Signature D. Date Signed 2 0% EPA~yry/lF~t yt'v(kev. 12.0/ ~ / bp David J. Szabo • __..~ , .. Head of Resource Management ~~ Alaska Consolidated Team (ACT) September 10, 2009 :~~,~~~.~~j:~ t~~>> ~¢a ~ ~oa~ Mr. Peter Contreras UIC Manager, Ground Water Protection Unit U.S. Environmental Protection Agency (OCE-127) 1200 Sixth Avenue Suite 900 Seattle, Washington 98101 ~ BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 Phone: (907) 564-4788 Fax: (907) 564-4440 Email SzaboDJ~bp.com Web: www.bp.com VIA CERTIFIED MAIL r- ~ F . ' ~ ...~. ~ -:. !. ,~. ;~ ~, : , C,;, ~ Mr. Thor Cutler .,; ~~ „~~ . ~.. , . U.S. Environmentai Protection Agency (EPA) 1200 Sixth Avenue O~~ I~~- ~ Seattle, WA 98101 ~ ~ Re: NS32 - Report on Annual Demonstration of Mechanical Integrity Dear Mr. Contreras and Mr. Cutler: Please find enclosed the Report on Annual Demonstration of Mechanical Integrity for the NS32 well, Permit No. AK-11002-A Part II.C.3.b.(1) and Part II.C.3.c.(1), As stipulated by the permit, two (2) copies of the logs and two (2) copies of the descriptive and interpretive report are being sent to the EPA to your attention. R 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. If you have any questions please call Mark Sauve at 907-564-4660. Sincerely, David J. Szabo Attachments NS~ - Report on Annual Demonstration`Sf Mechanical Integrity September 10, 2009 Page 2 cc: Talib Syed, EPA Consuitant Shawn Stokes, ADEC Jim Regg, AOGCC Jeff Walker, MMS Alison Cooke, BPXA File Copy Compliance Matrix Administrator: Matrix ID 8774 • ~~ ~ ~¢ *. w ~ NS32 ~~~ -- ~ ~ ~ CJ EPA UIC Class I Permit AK-11002-A Part II.C.3.b (2): Report on Annual Demonstration of Mechanical Integrity September 4, 2009 bp David J. Szabo ~ Head of Resource Management Alaska Consolidated Team (ACT) September 10, 2009 Mr. Peter Contreras UIC Manager, Ground Water Protection Unit U.S. Environmental Protection Agency (OCE-127) 1200 Sixth Avenue Suite 900 Seattle, Washington 98101 Mr. Thor Cutler U.S. Environmental Protection Agency (EPA) 1200 Sixth Avenue Seattle, WA 98101 ~ BP Exploration (Alaska) inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907)561-5111 Phone: (907) 564-4788 Fax: (907) 564-4440 Email SzaboDJ~bp.com Web: www.bp.com VIA CERTIFIED MAIL - , ~ -.~ ` ~ j r ~~'~ ...M . ;I~~1 f ,_ J`~~~ Re: NS32 - Report on Annual Demonstration of Mechanical Integrity Dear Mr. Contreras and Mr. Cutler: Please find enclosed the Report on Annual Demonstration of Mechanical Integrity for the NS32 well, Permit No. AK-11002-A Part II.C.3.b.(1) and Part II.C.3.c.(1), As stipulated by the permit, two (2) copies of the logs and two (2) copies of the descriptive and interpretive report are being sent to the EPA to your attention. 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. lf you have any questions please call Mark Sauve at 907-564-4660. Sincerely, David J. Szabo Attachments ~ ~ ~ NS32 - Report on Annual Demonstration'Sf Mechanical Integrity ~ September 10, 2009 ~ Page 2 cc: Talib Syed, EPA Consultant Shawn Stokes, ADEC Jim Regg, AOGCC Jeff Walker, MMS Alison Cooke, BPXA File Copy Compliance Matrix Administrator: Matrix ID 8774 ~ 1 ~ ~ ~ ~ ~ ~ ~ ~ ADDRESSES: With Loqs Mr. Peter Contreras Bussell & Mr. Thor Cutler (2 Copies to this address) EPA Region 10 (OW-137) 1200 Sixth Ave Suite 900 Seattle, WA 98101 Mr. Talib Syed, EPA Consultant c/o TSA, Inc. 6551 South Revere Pkwy, Ste 215 Cenfennial, CO 80111 Mr. Jim Regg AK Oil & Gas Conservation Commission 333 W 7th Ave, Ste 100 Anchorage, AK 99501 Mr. Jeff Walker Regional Supervisor, Field Operations US Minerals Management Service 3801 Centerpoint Drive, Suite 500 Anchorage, Alaska 99503-5820 Northstar File Copy c/o David Fair BP Internal Mail M B 4-2 Without loqs: Mr. Shawn Stokes Alaska Department of Environmental Conservation 555 Cordova St. Anchorage, Alaska 99501 Ms. Alison Cooke BP Internal Mail MB 11-6 Northstar Operations Team Lead Northstar Island, Northslope Mark Sauve BP Internal Mail M 6 4-2 Compiance Matrix Administrator: Matrix ID 8774 ~ ~ w ~ ;~' ~ NS32 EPA UIC Class I Permit AK-11002-A Part II.C.3.b (2): Report on Annual Demonstration of Mechanical Integrity September 4, 2009 ~ ~ ~ ~ ~ ~ '~ ~ ~ ~ ~ ~ ~ ~ ~.:~ ,z ,. . , ~~: ~ ~ Executive Summary: Annuai surveiilance on the NS32 EPA UIC Class I disposal well was performed August 10tn _ 12tn, 2009. The scope of work included a Water Flow Log (WFL) a Multi-Finger Caliper Log and a Mechanical Integrity Test (MIT). The MIT, pressure tested to 3540 psi, demonstrated mechanical integrity of the casing, tubing and packer. The test was witnessed by EPA representative Thor Cutler. The multi-finger caliper tubing inspection log indicates the tubing is in good condition. A maximum wall penetration of 28% was recorded in joint 30 (1261'). The damage appears to be in the form of isolated pitting. No significant areas of cross-sectional metal loss or I.D. restrictions are recorded. The WFL results indicate there is good vertical containment of injected fluids in the permitted interval. Eight WFL stops were made starting just above the casing shoe and stopping above the packer. Fluid movement was not detected on any of these stops. The test was witnessed by EPA Representative Thor Cutler. Attachments include the well bore diagram (attachment 1), MIT documentation (attachments 2-4), the Schlumberger RST-WL log (attachment 5) and the PDS Memory Multi-Finger Caliper log (attachment 6). ~ ~ Discussion I~ ~ ~ Mechanical Inteqritv Test of Inner Annulus (MIT-IA): On August 12, 2009 a MIT-IA was performed on NS32. The inner annulus (4- 1/2" x 7-5/8" casing annulus) was pressurized to 3540 psi with 2.7 barrels of diesel. During the first 15 minutes of the test pressure dropped 40 psi and in the second 15 minutes of the test pressure held constant. This pressure decline of 1.1 % during the allotted 30 minute test period test indicates there is good tubing and casing mechanical integrity. The test was witnessed by EPA representative Thor Cutler. The MIT results are summarized attachment 2, the pressure chart recorded during this test is shown in attachment 3 and the well service report for this work is included in attachment 4. Fluid Movement Logs (Water Flow Loq (WFL) and Temperature Loql On August 12, 2009, a Schlumberger Reservoir Saturation Tool Water Flow Log (WFL) was run. The purpose of the log was to detect movement of any fluids in vertical channels adjacent to the wellbore and to determine that the confining zone is not fractured. The log was conducted with injection pressures of approximately 1978 - 1989 psi. The injection rates were approximately 18,400 - 19,300 BWPD of produced water. The WFL bombards water with neutrons and detects gamma rays from the resulting interactions. The tool has a neutron generator and three gamma ray detectors. For this job, the tool was configured to detect the upward movement of water. The neutron generator was placed below the three gamma ray detectors. To detect the movement of water behind pipe, the tool is positioned at the desired depth and the neutron generator is turned on briefly. If there is upward movement of water (e.g. channels behind the casing), the gamma ray detectors see the energized water as it moves up past them. Eight WFL stops were made in NS32. The depths were 8051', 8000', 7950', 7850', 7700', 5150', 5050', and 3850'. The casing shoe in this open hole completion is at 8107' and the packer is set at 5102'. No water movement was detected at any of the stops. The WFL results indicate there is good vertical containment of injected fluids in the permitted interval. The test was witnessed by EPA representative Thor Cutler. The detailed report for the RST Water-flow log is attachment 5 and the well service report for this work is included in attachment 4. ~ ~ Discussion Mechanical Inteqritv Test of Inner Annulus (MIT-IA): On August 12, 2009 a MIT-IA was performed on NS32. The inner annulus (4- 1/2" x 7-5/8" casing annulus) was pressurized to 3540 psi with 2.7 barrels of diesel. During the first 15 minutes of the test pressure dropped 40 psi and in the second 15 minutes of the test pressure held constant. This pressure decline of 1.1 % during the allotted 30 minute test period test indicates there is good tubing and casing mechanical integrity. The test was witnessed by EPA representative Thor Cutler. The MIT results are summarized attachment 2, the pressure chart recorded during this test is shown in attachment 3 and the well service report for this work is included in attachment 4. Fluid Movement Loqs (Water Flow Loq (WFL) and Temperature Loql On August 12, 2009, a Schlumberger Reservoir Saturation Tool Water Flow Log (WFL) was run. The purpose of the log was to detect movement of any fluids in vertical channels adjacent to the wellbore and to determine that the confining zone is not fractured. The log was conducted with injection pressures of approximately 1978 - 1989 psi. The injection rates were approximately 18,400 - 19,300 BWPD of produced water. The WFL bombards water with neutrons and detects gamma rays from the resulting interactions. The tool has a neutron generator and three gamma ray detectors. For this job, the tool was configured to detect the upward movement of water. The neutron generator was placed below the three gamma ray detectors. To detect the movement of water behind pipe, the tool is positioned at the desired depth and the neutron generator is turned on briefly. If there is upward movement of water (e.g. channels behind the casing), the gamma ray detectors see the energized water as it moves up past them. Eight WFL stops were made in NS32. The depths were 8051', 8000', 7950', 7850', 7700', 5150', 5050', and 3850'. The casing shoe in this open hole completion is at 8107' and the packer is set at 5102'. No water movement was detected at any of the stops. The WFL results indicate there is good vertical containment of injected fluids in the permitted interval. The test was witnessed by EPA representative Thor Cutler. The detailed report for the RST Water-flow log is attachment 5 and the well service report for this work is included in attachment 4. ~ ~ Tubinq Inspection Caliper Loq ProActive Diagnostic Services (PDS) was retained to provide a 1-11/16", 40 finger memory caliper tool and interpretation of the results. This tool was run on Schlumberger slickline from the tubing tail back to surface on August 11, 2009. This tool digitally records the internal diameter of the tubing, which is used to determine pipe thickness, and hence metal loss. The multi-finger caliper tubing inspection log indicates the tubing is in good condition. A maximum wall penetration of 28% was recorded in joint 30 (1261' MD). The damage appears to be in the form of isolated pitting. No significant areas of cross-sectional metal loss or I.D. restrictions are recorded. The detailed report from PDS is attachment 6 and the well service report for this work is included in attachment 4. ~ ~ Attachment 1 -~_ ~.~.,~~ ~„~ ~ i1'IIF.•~iGeD - Af#~3,UC~ i 1' MUL7#J'J+/t 9CSi AGTiY\7DR - 6A t~i SLS! = SiJ fiF_ ~LV ~ . . 4~~]S {CFs 16_7} . . KOR ~* . .. . 50( . .____ Mai iinga- . _ _ _ C7'~ 31`22 _ ..-- _ ~ ~~ 6v~tn D,. 1~5(Ki'~5 SAt£tYNCT'P~: •+;EPAGI/~5a~t WSP~f3SAL'IW~,•' HpNCPR m~" BPYJ TW C ~d1E (2EV E~lY fAMdl~7T3 UrlTL RLV 6Y EX7ATc1a"1T5 92'14AD3 i-i7'fA,L~RILL 9d1CNA'1b -YRR+7L iZC+TStYCORRiLT3]NS 05~02~G( dAS OAIt;iHk1..COlAP1£TK?H i1t~r~ ~c r~w€i~ar aa~oaxis ~~a~ e~t~ ae~~t~v (~srt2m~~ i uzafm w~+wc ~~arixr~r~ ~s n~3otire w~rrwc ~wacao~rnr+ tJ~AfHST9.d2 4Vit~: NS32 PF3iM(f E~ 263158~7~ a,~n~ sa.u2a~i~s~a S£C i i @~P ~pioratiua~ {Alaaka~ ~ ~ STATE OF ALfiSKq ALASKA 014 AND GAS CONS~RVATlQN ~plVIMISStON Mechanicaf integritar Test Email loyim.regg(d~alaska gov; iom.maunder@alaska gov;bc,b fieckenste~n{c~alaska gov.doa.aogcc.prudhoe,bay@alaska.gov ~1PERATOR: BP Expbration (Alaska) -nc. FiELD / UNlT ! PAC}: Pnidhoe Bav 1 ACT 1 NS DA7E: q8/12/fl3 OPERAT~DR REP: Tarin Roschin er AOGCC REP: EPA Thar Cutfer ~ f;' ?~ / ' ~l;;,~ ~ 5 '~ ! G: Pack~r Oe th Pretc:st iotGaf 15 Mert 30 fvli~ Wel! NS-10 T P.i'_E}_ 200f$20 T ~IOtBS: 3~ S ~'1 . G Well NS-32 T P.T.O 2031584 7 Nofes: ~ , , ti~ i ; fn e test cs !n test c.~ 1 TVD 3,986' Tutrin ~ P Test si 500 Casin 7'"c ~~ ,~. r-~.~s ~r'C AA W TVD 4,010' Tubin P Test si 500 Casin .' ~ ~ a .~ rc ~ _ •~c.. OA .} a ~ ~~ ~, '~ ~ ~ c~ . C, ` ~~1 ~i ;~~r'; / ; cr~ a Yt~ ~ Q 2~ 1~< .a ~"S l~ t~ ~ ', t,~~ ~' v~ ~ d L~ t Weil T In . TVD Tubin P,T.i7. T test Tesf si Casin Notes: ~A Well T e in'. 7VD Tuhin p~T-~~ T test Test si Casm Notes: OA Weli T e tn . TVO Tubm ~'-T.d- T test T Notes: est si Casin _ _ 'fYPE INJ Codes D = paMing Waste G = Gas t=lndusv~al Waslowater N = No! injesc~ng W = We1e~ TYPE TEST Codus Fvt = Annutus MonUpnng P = Standard Pres~ure Test R= Iniernal Ratl~oachvss Tracer Sun~ey A = ~emperatur[s Mpmaly Survuy I3 = i)+iferanbai Tempecaiure Tes~ O P/F P/F INTERVAL Codes { = Init~ef 78St a = Fa,x vee~ cyae V = Requued by Variance T= l est dunng 4Yorkover O= Other fdescn6e in notes) MIT I~eppM Farrts BFL tt/271p7 M(T ACT NS US-t2-09.xis ~ ~ STATE QF ALASK,q ALASK~t C11L AND GAS CONSERVATION C(?MMIS~SIC?N Mechanical Integrity Test Email lo:jim.reggUd alaska gov; tom.maunder@alaska gov;bob Fleckenstein a~5alaska gov.daa.aogc~ prudhae ba @alaska . . y .gov ~3PERA'fOR: BP ExpbraUon (Alaska), inc FfE~D ! UNI'f ! PAD: Ptudho~ 8sy / AGT I NS DA'fE: 08!12109 •• _ OPERATOR R~P: Tptin Raschinger AOGCC REP: EPA Thor Cutler .. i`~.~~7:/ t Y' .'~vT i~~i ~''l ~4~ f ~ Wel! N&-10 T Packer De th Pretest IniUa! t5 Min 30 Min~ 1n t ' P.T.C}. 2007820 7 TVD 3,986 Tuhin 7- ~ a~ 2~ 1~,~ e test P Test si 5Q0 Casin ~ 5 a ~ y{ " r interval NQtes: 3:~ ~,~ "3 . c~ . ; $ ~ ~ v .~"c s r ,.a .-~s Y~t r-r~ aA ~r ~? -, U 4 s- ~~ P/F Well NS-32 T ' e Ih W TVD 4,p70' Tubin ;~~i '~ { .~~ ~, ~~ , l q~ P. P_D 20315$0 7 c~! a tast P Test si 600 Cas~n ~} ~ 5'a a ~ ~ intervai ., ~ Notes: ~ ~:.5 r., I c,, ~~ s r .u r.5.. .r~ _ Q OA u. L,+ ~~ Well T ln ' P.T.C3 T . te t TVD fubin lnterval s Tesf si Casin Motes: P/F QA Well T e In' P,'f.D. T . tESt T1/D Tu6in iniervaf Notes: Test si Casin P!F ~A We11 T e tn P-T.D. T . iesk fiVD Tubi fnterual 1161E5: Test sl Casin „ , P/~ TfPE !NJ Cosias D = pnll~ng Waste ~ = GBS 1= fndustrial Wast~water N = No! In~ecting YY = Wa1er TYPE l'ES7 Codes M = Rnnuius Morutamg P = Standard PreSSUre T~st R= Inlernal Ratl~oactive Trr~,.er Sucvey A = 7empefa{ure Manaiy Survey D = Differenbai Twnparawre Tesi IMTERYAL Codes t = In~hel Test 4 ~ Fqut Y48t CyGl~r V = Required by Vanance f =~?est dunng Woricave.~ O = Ofher {descnbe in notes) MtT Report Ft,nn B~~ 71~2~147 MIT ACT kS US-; 2 0!~ xls ~ • ~ ~ ~ Attachment #3 MIT Test Chart ~ _R ~-~-+li?.rr.'-~T. ~ -'. ^_~... ~ - - ,-- ---,_ _ ~ 2,~ ~ ~ ,~ ~ ~ ' - `` / j ~!`___ _ _ ~.. ~ _ \ . i ~ i ~~ ~ ~ ~! "`c ~ ~ \ ~ \1 ~ .~-~. _-- ------_ _- // ~~'~` \ ~ y `S~~v',.C -~, \ ~ ~ ~ , ~ 11 /~~ ~~ ---~-----~_ ~ J~ n /,,. ~\ \ ~\ / \ i~ ~~ ~ ~~~, `- ~ ~ ~\ ~ ~~// ~ ~-_-,.r . 4 ^ %~ _ ' ~, . ~ ~l.Q~ ''~ i'~~ '`~ \ ~/~ ~ ,/1 ~ -/`~ ~~~-~~ -J~~~~~ / `~\ / \ ,\~ \\ \\~ ~ ~ . / '1~ ' Y ~ __ _ I _~\ . `\~/ \~ \ ~~ / , /~ ', -3~r~n '~ /' `~ '~ 7 ~ -~--~' , - . ` ~x ••~ . , ~ .\ ~ ~ ' ;/ ~ ' _ ' , \ •` i ~ ~ \ ~ /~ ~/.~ i l~~ ~ , ?CGt.y_ _ ti..\`~\~ \ . ...~~M~ . ` . !/ '1 ~_---'-- ~~ , ~n .~_ ~ ~ ,\ ~ ~ `\ \• ~ ~ % ~ ~.\ .~ . ~`• ~ ~ / 1~`/ , ~ • ~~ ~ ~ ~ ~ \\ ~ / / \ ~ ; --_.----•-1.50~~~_ '~, ~ ~~ ~ . \ \/ ~ ~ ' ~ ~ ~ ' , ~ ~ ~ ~ / 1, ~-J--'00~-i_ ~ ~ ` ~~~,r~, ~ ~C , _ `%` ,\ - -:~' ~ ~c ~ ~ i" ~~ ~,, -, . - ~ _ , `~ , ~i , + p~ ~~' ' _ -~--500-- ~~' . ` '., ~•~ ' ~ '. ~ OO \/ ~! ~~ I I __. _ ~~ ~~~~' '/ , ~ f ' ~ ', 2 ~ , `~ '~ ~ / ,r / ~~ ~'~ ~ ~ ~?~ ~ / , - ^ -i ~ ~ : ; ~ ~ `. ;~, c- ~ ~^ c ~ ` jr~ ~~ \ J . i ~ -.e. J P~A . ~~~ / ' % `~~ i, C~ G I ~ ~ ~ CC'~ G ~ `/~.~ . ~ . i n - .- i cS p G~ ~ -~--'- . a, - \ ~ ;' ~ ' i- p O ~J O _~-J- ~- ~ ,j'~ '' ~ . . ~ = p4~~ . CJ~ G~J ~~~_,~- . '1 . ~ ~ ~r c~~.~ • n' ~ ~ ~ ~5~~ ~~~ ' ~1~ . ' ~ /~ ~ , ~ - ~(s ~~~ 11 ~ L~ / 't~` ~~ ~ ~ , tt ~ ~ ~ i I-_.-~ . Q ~•O 1 '~ ~' 'fj i ~ ~ `-_ ~' . __~~-_~_ ~I _._ ~__~___--~-____; -'~~,_ ~~ i ~ I '--~~-` p``'~ ~ ~ ~ ~ ~ - _,_ ~ __ \ ~ Z7' , i ~ ' + ! `'-`... ~ ~, ~ ~' \.,~ ~. '~ ~ ~~c .~,`j'' (~ '! ~ j 1 ~ ~ ~ ..7 ~ \ . R ,. ,`` j J ~ v+ ~~ ,. " ~ ~ ` ~ ~ _~ j ' j ~ ~ ~ ~ ~ o . ~~ ~~~ ~`O S~ ~ ~ ~~ ~~ ~ 1 ~ ~ ~ ~ v~~ : ~ ~ ft - ~ ; n- ' , ' I ~ cC ~~ ;' ~ ~' .,~` ; ~, ~ '~ _---`-. - ~ ~ .. ` ~ ~~. ~, -.` ~~~ ~.~ / I 2~ . % ~.\~x ~ \ `~~ ~ / '+005~~-~' " ' Q -~ . ,_~, i, ,, `' ,' ~ `~ ' ~ , ~ ~~ ~~ ~ ~ ~ = i~ . ~ . ; / j '~. '~-00~~1-~-~~- _ - ~ ~6~ r\ j/~ I ~ ,~..\ `~ %~ ` ~~` ^'1 _ - . ~7' ~ / . .\~J `% `,~~ / ~' ~ / .,\ -~~ ~~ l~~- ~..\ , ~ ' ! . , ~. . ` i ~~~` • ~ ~ ~~ . ~ ~ ;J ~n~~ ~ --- --° " ' C , -C.~- ~ ~\ r, `\ `\i~ ~- . -~ ~ v .C' , ~ . \ ~ / ~` ~ ~G~' ~ -~-~-i-~- ~ , ~ _, _,- i Xl.. /, \ ~J~ ~,\ ~ ~ ~~~" -~ 7r1~1~ ,r ~_~~% ~` / ' /' _ ~ ~ -~_ ' ~ .~~ '~ ~' / ' )1~~ ~i ' ~ ~ `,, ~ !~' ~J ~ ~ ~ ~ ~ ..-~ , ~ ~ _ ~~~ ~ _ _ / ~ / ~ r , ~ a' - 1 - ; . ~ ` ~~~~- ~' ~ ,~JC' ~ ~ ~ I~ _ `'~Ci< . C~ J Attachment #4 • Well Service Reports WellServiceReport • • WELL SERVICE REPORT Page 1 of 1 WELL JOB SCOPE UNIT NS'.3Z CALIPER SWCP #01 DATE DAILY WORK DAY SUPV 8/10/2009 DRIFT/TAG; CALIPER TUBING; IN PROGRESS ATKINSON COST CODE PLUS KEY PERSON NIGHT SUPV NSFLDWL32-M SWCP-HENRY SPILLER MIN ID DEPTH TTL SIZE 2.625 " 2169 FT 4.5 " DAI *'*WELL S/I ON ARRIVAL"' (pre epa wfl) PULLED PROTECTIVE SLEEVE C~ 2136' SLM/ 2169' MD. TAGGED TD C~ 8100' SLM W/ 3.625" CENT, STICKY BOTTOM. CURRENTLY LOGGING PDS 40 ARM CALIPER FROM 8090' SLM TO SURFACE. ""JOB CONTINUED ON 8/11/09 WSR""* LOG ENTRIES Init Tb IA OA -> 600 0 0 TIME COMMENT 05:00 TRAVEL TO NS 07:30 ON ISLAND, CHECK OUT AND START UP EQ. EQ BLOCKED BY OTHER EQ 09:30 CEMENT HANDS MOVING E(]. PICK PCE OFF OF TRAILER AND STACK ON TO BOOM TRUCK 10:15 SPOT IN CRANE, HAVE RIG MATS PUT DOWN, TURN CRANE AROUND AND PULL CRANE IN 11:45 SPOT IN UNIT, CALL TO HAVE TRAILER, TRI-PLEX AND B/T SPOTTED IT 13:30 CONDUCT PJSM, REVIEW JSAS 13:50 BEGIN RIG UP .125" CARBON 19 TURNS *TS: 1.75" ROPESOCKET, 5' OF 2.625" STEM, OJS, LSS* 14:45 STROKE SSV, BLEED AND POP CAP 17:00 STAB ON, CLOSE RAMS. P/T BELOW RAMS TO 2000#, GOOD TEST. EQ PSI, OPEN RAMS. P/T STACK TO 2000# 17:30 RIH W/ QC, 4-1/2" GS'""W/FIT SKIRT`*`. LATCH SLEEVE ~ 2136' SLM, JAR UP 3 TIMES, COME FREE, POOH. 18:20 OOH W/ PROTECTIVE SLV. SLEEVE IS IN GOOD SHAPE. 18:40 RIH W/ QC, 3' OF 1-3/4" STEM & 3.62" CENT. i9:32 C/O TO MCCAULEY 19:33 CONT. TO RIH W/ 3.62" CENT. 20:10 TAG TD @ 8,100' SLM, STICKY BOTTOM. POOH. 20:35 SIBD. OOH W/ TLS, MAKE UP PDS LOGGING TOOLS. 21:03 STAB ONTO WELL W/ PDS 40 ARM CALIPER 21:15 RIH W/ 17' PDS 40 ARM CALIPER. 22:04 STOP @ 8,090' SLM & WAIT FOR ARMS TO OPEN ON CALIPER. 22:21 BEGIN LOGGING UP W/ CALIPER C~3 50 FPM. 23:59 "'CONTINUE JOB ON 8/11/09 WSR*" Final Tb IA OA -> 600 0 0 JOB COSTS SERVICE COMPANY - SERVICE DAILY COST CUMUL TOTAL ORBIS $2,600 $2,600 SCHLUMBERGER $0 $0 SCHLUMBERGER PLUS 15 PERCENT $0 $0 WAREHOUSE $0 $11,273 LITTLE RED $0 $6,353 TOTAL FIELD ESTIMATE: $2,600 $20,226 httll'~~A7111C7-A~ACkA }111\x/P}l ~'1T1 ('.(11YlIA~E7arc_~x7P~~CPYV1(`P7'Pl'~nrt/r~afaiilt a~„Y~;~t-rr~n~~ne~~o~~nr~cQ oi~i~nno We1lServiceReport ~ • WELL SERVICE REPORT Page 1 of 1 WELL JOB SCOPE UNIT NS'32 CALIPER SWCP #03 DATE DAILY WORK DAY SUPV 8/11/2009 CALIPER TUBING ATKINSON COST CODE PLUS KEY PERSON NIGHT SUPV NSFLDWL32-M SWCP-MCCAULEY SPILLER MIN ID DEPTH TTL SIZE 2.625 " 2169 FT 4.5 " Y "*'JOB CCINTINUED FROM 8/10/09 WSR"' CALIPERED TBG FROM 8,090' SLM TO SURFACE W/ PDS 40 ARM CALIPER, RECEIVED GOOD DATA. RE-SET 4.5" PROTECTIVE SLEEVE C~ 2,136' SLM (OAL= 23", 2.625" I.D.) "'WELL LEFT S/I, JOB COMPLETE**' »>SLEEVE REG~UIRES FIT SKIRT«< LOG ENTRIES Init Tb IA OA -> 600 0 0 TIME COMMENT 00:01 "`*CONT. WSR FROM 08/10/09**' 00:02 CONTINUE LOGGING FROM 8,090' SLM W/ PDS 40 ARM CALIPER 00:44 IN LUB W/ PDS 40 ARM CALIPER WAITING ON ARMS TO CLOSE. 01:18 BREAK OFF TOOLS PDS READING DATA 02:20 PDS REPORTED GOOD DATA, STAB ONTO WELL W/ 4.5" GS PULLING TOOL & 4.5" PROTECTIVE SLV. 03:38 RIH W/ 4.5" GS PULLING TOOL ( FITTED SKIRT) & 4.5" PROTECTIVE SLEEVE (OAL= 23", 2.625" I.D., 2 SETS OF PKG 04:06 S/D @ 2,136' SLM SET 4.5" FRAC SLEEVE OAL- 23" POOH 04:22 BEGIN RIGGING DOWN 05:58 R/D COMPLETE, TREE CAP TESTED, DSO INFORMED OF TREE VALVE POSITIONS. 07:15 RIDE HOVERCRAFT BACK TO WEST DOCK. 07:59 RETURN TO SLB SHOP, END TICKET. Final Tb IA OA -> 600 0 0 JOB COSTS SERVICE COMPANY - SERVICE DAILY COST CUMUL TOTAL ORBIS $2,600 $5,200 PDS $9,671 $9,671 SCHLUMBERGER $0 $0 SCHLUMBERGER PLUS 15 PERCENT $0 $0 WAREHOUSE $0 $11,273 LITTLE RED $0 $6,353 TOTAL FIELD ESTIMATE: $12,271 $32,497 httD://anrn2-ala~ka.hnweh.hn.cnm/awar.c-wPllcervicerennrt/rlPfanlt a.cnx?ir1-7F~.74AF4FRRR42~(1R 9/~/~~f19 We1lServiceReport ~ ~ Page 1 of 2 WELL SERVICE REPORT WELL JOB SCOPE UNIT NS'a~Z WATERFLOW LOG SWCP NS DATE DAILY WORK DAY SUPV 8/12/2009 RST--CARBON / OXYGEN ATKINSON COST CODE PLUS KEY PERSON NIGHT SUPV NSFLDWL32-R SWS-DECKERT SPILLER MIN ID DEPTH TTL SIZE 2.625 " 2169 FT 4.5 " "*'LOG CONTINUED FROM 11-AUG-2009"** (epa wfl) RAN WATER FLOW LOG W/ STOP COUNTS PER PROGRAM AND WITNESSED BY EPA REP (THOR CUTLER) FOUND ZERO UPWARD FLOW AT INJ RATE 19300 BWPD, WHP 1989 PSI, WHT 142 DEGF. CORRELATED TO SWS JEWELRY LOG DATED 14 MAY 2004. FINAL WHP's 1400/0/0 *""JOB COMPLETE, WELL LEFT ON INJECTION'*~ LOG ENTRIES Init Tb IA OA -> 500 0 0 TIME COMMENT 00:00 LOG CONTINUED FROM ii-AUG-2009 00:01 CONTINUE RIG UP E-LINE 02:49 TOOLS MADE UP AT SURFACE. CHECK TOOLS 03:06 TOOLS CHECK GOOD, STAB ONTO WELL 03:46 PRESSURE TEST LUBRICATOR 04:04 PRESSURE TEST GOOD. OPEN SWAB RIH WITH HEAD/PBMS (PRESS/TEMP/GR/CCL) / CENTRALIZER/RST/CENTRALIZER/1-11/16" WEIGHT BAR. TOOL WEIGHT = 220 LBS, MOD = 1-11/16" 04:30 AT 400', TEST MINITRON PRIOR TO RUNNING TO BOTTOM 04:37 MINITRON CHECKS GOOD. CONTINUE TO RIH 06:00 CORRELATE AND CHANGE OUT WITH DAY CREW, PREP TO PUT ON INJECTION 06:30 PAD OP PUTTING WELL ON INJECTION. 07:06 WHP 2100, BHP ~8063' 4266, BHT 126 07:47 CORRELATED AND EPA WITNESS ON LOCATION 07:58 INJ PRESSURE 1989, 19.3 KBWPD 07:59 WFL STOP @8051' 08:10 WFL STOP @8000' 08:20 WFL STOP @7950' 08:36 WFL STOP C~7850' 08:37 INJ PRESSURE 1978, 18.4 KBWPD 08:53 WFL STOP ~7700' 09:05 PUH TO 5150' 09:26 WFL STOP C~5150' 09:45 WFL STOP @5050" 09:54 PUH 10:03 WFL STOP @3850' 10:15 LOG DOWN TO CONFIRM WFL STOPS WITH PRESS/TEMP/GR 10:57 TOOLS AT 8000' INJ PUMP SHUT DOWN 10:58 STOP DOWN LOG 11:05 POOH 12:00 SWAB SHUT 13:00 LUB BLED, BREAK CONNECTION, LAY DOWN TOOLS 14:00 LUB LAYED DOWN, WO MIT IA BEFORE REMOVING WIRELINE VALVES 16:30 MIT FINISHED START RD OF WIRELINE VALVES/CRANE 20:19 ALL E-LINE EQUIPMENT RIGGED DOWN. MOVE EQUIPMENT OVER TO NS-10 FOR NEXT JOB Final Tbg, IA, OA -> 1400 0 0 JOB COSTS SERVICE COMPANY - SERVICE DAILY COST CUMUL TOTAL OR81S SCHLUMBERGER $1,300 $20,225 $1,300 $20,225 http://apUS2-alaska.bpweb.bp.com/awgrs-wellservicerenort/ciefault.asnx?id-C7F3(1C''flA(1FF.T~4fl~AR Ai~i~nnc~ We1lServiceReport ~ ~ Page 2 of 2 SCHLUMBERGER PLUS 15 PERCENT $3,034 $3,034 WAREHOUSE $0 $504 LITTLE RED $0 $6,765 TOTAL FIELD ESTIMATE: $24,559 $31,828 FLUID SUMMARY 1 BBL DIESEL FOR PT /anns2-alaska.bnweb.bn.com/awgr~-wellservicerennrt/rlPfaiilt.a~»x?ici-(''7(~fl~~A~FF.T~4~~9R Ai~i~nn9 ' WellServiceReport • • WELL SERVICE REPORT Page 1 of 1 WELL JOB SCOPE UNiT NS'32 WATERFLOW LOG LRS 38 DATE DAI~Y WORK DAY SUPV 8/12/2009 MIT-IA ATKINSON COST CODE PLUS KEY PERSON NIGHT SUPV NSFLDWL32-R LRS-SCHREIBER SPILLER MIN ID DEPTH iTL SIZE 0" OFT 0" T/I/O = 1910/0/0 Temp = Hot EPA MIT IA PASSED to 3500 psi (EPA Witnessed by T. Cutler) Pumped 2.7 bbis of diesel down IA to achieve test pressure. IA lost 40 psi in the first 15 minutes and 0 psi in the second 15 minutes for a total loss of 40 nsi in the 30 minute test. Bleed IA pressure down to 0 psi. FWHP's = 2010/0/0. ~ nr_ ~niroice Init-> 1,990 0 0 TIME BPM BBLs FLUID TEMP TBG IA OA COMMENTS 00:00 Start ticket. ig:~2 Ri u IA. DHD has chart recorder ri ed u. 14:56 PT surface lines 15:15 0.3 Start Diesel 45"F 1990 0 0 Start into IA 15:25 0.3 2.7 " 1991 3540 0 Reached test ressure, Start MIT 15:40 1989 3500 0 1st 15min ressures 15:55 2010 3500 0 2nd 15min ressures, MIT IA PASSED 15:59 2010 0 0 Bleed IA ressure to 0 16:59 End ticket Final-> 2,010 0 0 JOB COSTS SERVICE COMPANY - SERVICE DAILY COST CUMUL TOTAL LITTLE RED $2,805 $6,765 WAREHOUSE $504 $504 SCHLUMBERGER $0 $20,225 SCHLUMBERGER PLUS 15 PERCENT $0 $3,034 ORBIS $0 $1,300 TOTAL FIELD ESTIMATE: $3,309 $31,828 D ~~ REQUIRED TEST PRESSURE 3,500 TEST TYPE MIT-IA FLUIDS USED TO TEST DIESEL START TIME: 1525 PRE TEST PRESSURES INITIAL PRESSURES 15 MINUTE PRESSURES 30 MINUTE PRESSURES PASS OR FAIL TUBING 1,990 1,991 1,989 2,010 IA 0 3,540 3,500 3,500 PASS OA 0 0 0 0 COMMENTS Bleed IA pressure down to 0 psi }~ttr~•//.~r~c2ol~aclra hn~vah hn rnm/acxrrtrc_u~allcPrvirPrPt~nrt/~Pfat~~t acTlX`~1lj-A4C~R~iFT~AFiF~F.4~nR... 9~Z~`ZnO9 ~ Attachment #5 • Schlumberger RST WFL-Up Flow Mode Log ~ ~ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test ~ ~~r ~ I~l o~S}~ ~' S-3 z Email to:jim.regg@alaska.gov; tom.maunder@alaska.gov;bob.fleckenstein@alaska.gov;doa.aogcc.prudhoe.bay@alaska.gov OPERATOR: BP Exploration (Alaska), Inc. ~"~ FIELD / UNIT / PAD: Prudhoe Bay / ACT / NS ~~ 1~lr ~r¢ (Z~~ DATE: OS/12/09 ~ OPERATOR REP: Torin Roschinger AOGCC REP: Packer Depth Pretest Initial 15 Min. 30 Min. Well NS-10 Type Inj. I~ ND /3,987' Tubing 2,285 2,285 2,281 2,284 Interval O P.T.D. 200182Q T pe test P Test psi 500 Casing 0 ''3,520 '~,440 °3,410 P/F P Notes: EPA witnessed annual MIT-IA for Class I disposal OA 60 70 80 80 regulatory compliance. Well NS-32 ~ Type Inj. W ND ' 4,070' Tubing 1,990 1,991 1,989 2,010 Interval O P.T.D. 2031580 ~ Type test P Test psi ~3500 Casing 0 ~ 3,540 '3,500 ~3,500 P/F P Notes: OA 0 0 0 0 Well Type Inj. ND Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. ND Tubing Interval P.T.D. Type test Test psi Casing P~F Notes: OA Well Type Inj. ND Tubing Interval P.T.D. Type test Test psi Casing P~F Notes: OA TYPE INJ Codes D = Drilling Waste G=Gas I = Industrial Wastewater N = Not Injecting W = Water TYPE TEST Codes M = Annulus Monitoring P = Standard Pressure Test R= Internal Radioactive Tracer Survey A = Temperature Anomaly Survey D = Differential Temperature Test t~~ ~ ~~ru~ .~ ., ~,~ ,.. . t: + ~ INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance T = Test during Workover O = Other (describe in notes) MIT Report Form BFL 11l27/07 MIT ACT NS 08-12-09.x1s ~~ t>~~-i~ /~ S7' ~~ ~3~IS6 l/ ~ ~ BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. If vou have anv auestions_ olease c~ntact .T~e i,astufka at (9n715fi4-4n91 Date: 09-04-2009 Transmittal Number: 93096 Deliver Contents Bottom SW Name Date Contracto Run To De th De th Descri tion WATERFLOW INJECTION NS10 08-13-2009 SCH 1 4760 7950 LOG CD-ROM - WATERFLOW NS1 08-13-2009 SCH INJECTION LOG WATERFLOW INJECTION NS32 08-12-2009 SCH 1 3750 8060 LOG CD-ROM - WATERFLOW NS32 08-12-2009 SCH INJECTION LOG ~~ Please Sign and Return one copy of this transmittal. Thank You, Joe Lastufka Petrotechnical Data Center n ~._ • 1 ~ ,~~~ M ~.N. ~ le uud ,.. .. .. Bl l'L , AOGCC Murphy Exploration DNR MMS Petrotechnical Data Center LR2-1 900 E. Benson Blvd. PO Box 196612 Anchora~e, AK 99~ 19-6612 ~ David Fair Christine Mahnken Ignacio Herrera Corazon Manaois Doug Chromanski . ~~ BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. if vnu have anv auesti~ns_ nlease contact Joe Lastufka at (9071564-4091 Date: 08-25-2009 Transmittal Number: 93090 Deliver Contents SW Name Date Com an Run To De th Bottom De th Descri tion MEMORY MULTI-FINGER CALIPER LOG RESULTS SUMMARY "*REVISED 08-12- NS32 07-09-2008 PDS 5 0 8116 2009"' CD-ROM - MEMORY MULTI- FINGER CALIPER LOG RESULTS SUMMARY NS32 07-09-2008 PDS *`REVISED 08-12-2009""` MEMORY MULTI-FINGER CALIPER LOG RESULTS NS32 08-11-2009 PDS 6 0 8102 SUMMARY CD-ROM - MEMORY MULTI- FINGER CALIPER LOG NS32 08-11-2009 PDS RESULTS SUMMARY ~~/ ` V ~~ Please Sign and Return one copy of this transmittal. Thank You, Joe Lastufka Petrotechnical Data Center d~~v~;,~~~^~; m~,; ~+~ (~ `':~ ~O~i~ BPXA AOGCC Murphy Exploration DNR MMS ~z~ ao3-ls~s i~y~~ 1~y~ • .~ ~~ AUG 2 ~ 2009 ~;~~ka C~il ~ ~~s Cons. Gorn~nission Anchoraqe David Fair Christine Mahnken Ignacio Herrera Corazon Manaois Doug Chromanski Petrotechnical Data Center LR2-1 ~ 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519-6612 Memory Mult%Finger C~liper ~j Log Results Summary ' Company: BP Explaratian (Alaska), Inc. Well: NS-32 ' Log Date: August 11, 2009 Field: Northstat Log No. : 10579 State: Alaska Run No.: 6 API No.: 50-029-231~9-00 Pipe1 Desc.: 4.5" 12.6 Ib. L-80 iBT-M Top Log intvl1.: Surtace Pipe1 Use: 7ubing Bot. Log Intvl1.: 8,102 Ft. (MD) fnspection Type : Corrosion Monitoring lnspection ~OMMENTS : Thfs lag is tied into fhe XN-Nlpp/e ~$,088' (Driller's Depth). This !~ was run to assess the condition of the tubing with respect to changes in corrosive and mechanical damage. The caliper recordings indicate the 4.5" tubing is in good to fair condition, with a maximum wall penetration of 28% recorded at an isolated pit in joint 30 (1,261'). Recorded damage appears in the forms of apparent erosion throughout the log interval and isolated pitting. No significant areas of cross-sedional wall loss or I.D. restrictions are re~rded. ~' This is the sixth time a PDS caliper has been run in this well and the 4.5" tubing has been logged. A comparison between the current and the previous Iog (July 9, 2008) indicates an increase in erosive ' damage, at a rate of -16 mils per year as shown in the inciuded comparison graph illustrating the difiFerence in maximum recorded penetrations on a joint-by joirrt basis. A Time to Failure Evaluation graph is included in this report, which indicates a wall ioss trend of --16 milis per , year. This corrosive trend is derived from a best fit of the maximum recorded wall penetrations from the fast three caliper logs of this well and assumed undamaged tubing upon initiat comptetion. The projected tubing failure window ranges from as early as 5.5 years to 9.75 years from the date of the latest caliper log. ' MAXIMUM RECORDED WALL PENETRATiONS: ' Isolated Pitting ( 28°10} Jt. 30 ~ 1,261 Ft. (MD) Isolated Pitting { 21%) Jt. 12 @ 480 Ft. (MD) lsolated Pitting ( 21°~) Jt. 25 ~ 1,043 Ft. {MD} ~, Apparen# Erosion ( 20%) Jt. 31 ~ 1,274 Ft. (MD) lsolated Pitting ( 20%) Jt. 20 ~ 836 Ft. (MD) MAXIMUM RECORDED CROSS-SECTIONAL METAL LOSS: ' No sign~cant areas of cross-sectionaf waH loss (> 10%) are recorded. ~ MAXIMUAA RECORDED ID RESTRICTIONS: : ~ ..~ i } 4 ,~~ ~ ~ r ~: ~~ ~r~~'~ No significant LD. restrictions are recorded. ~~ `'~~~"~'"~~`~ ~ i ~' Field Engineer. G. Etherfon Analyst: C. Wa/drop Witness: T. Atkinson ProActive Diagnostic Services, Inc. / P.O. Box 1369, Staff~rd, TX 774°7 PP~one: (Z81) or (888) 565-9085 Fax; (281) 565-1369 E-mail: PDS~~memorylog,com Prudhoe Hay Fieid Office Phone: {907) 659-2307 Fax: (~07} 659-23i4 ~ ~ ~~~ C° ~ ~~ --~ ~ ~ ~ ~~~~~~ Maximum Recorded Penetration ~~: ~ Comparison To Previous Well: NS-32 Survey Da[e: August 11, 2009 Field: Northstar Prev. Date: July 9, 2008 Company: BP Exploration (Alask~, Inc TooL UW MFC 40 No. 213120 Country: USA Tubing: 4.S' Y2bih i-i~f~IR1-M C~verlav Max. Rec. Pe n. (mils ) o s o io o is n 20 o zs o i 9 ~ - 19 29 39 49 56 66 76 ~ ~ v ~ ~ 96 z o ~~ 116 123 133 143 153 163 173 183 193 ~ti Au gust 11 , 2009 ^ July 9 , 2008 Difference -100 -5 Diff. in Max. Pen. (mils 0 0 5 ) 0 10 0 ~ 9 . i ~ i 19 29 ~ ; 39 ~ i 49 I 56 ~ i ; i 66 ~ i i 76 ~ d ! 86 Z ~ 96 ~ ~ 0 1 ~ ~ 106 j i 116 123 I I 133 i 143 l 153 i 163 I 173 I 183 193 92 App rox Corro~ion Rate (m py) 9 2 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ Time to Failure Evaluation BP Exploration (Alaska), Inc. ,~ Northstar Corrosive Trend: Apparent Erosion, Wel~ : NS-32 Isolated Pitting 4.5" 12.61b L-80 fBT-M Tubing August 11, 2009 Years Following Most Recent Log 4.5" 12.6 Ib L-80 IBT-M 0 5 10 Wall 260 240 v 220 _ ~ Zoo ,~ 180 ~ ~ 160 a 140 ~ 120 ~ O 100 U oC 80 ~ ~ 60 40 20 0 Th icknes s = 271 mill ~ ~ ~ ~ ~ ~ ~ ~ I - _. i":` , ~~~ ~~~;~ i a ~=a~ ~ . ~,•~~ Saf ty Fac or) ~ ~ ' _ _~, - I -- I ~ ~_ ~ ' _ _ ~~ ~. 1 I -' I l ~ '~ ~~ ; ~ . ~ / ~ ~ ~ .' ~~'~ ~ ~ ~ ~ ~ ~ ~~ ~~ ~ I I I I ~ '/ / ~ ~ '~~~/ I ( I I I ~ ~ ~ ~ ~ ~ ~ ~ ~~ I ~ ~ 2009 Maximum Recorded Wall Penetration ~~ ' 0 076" = 28% Wall Penetration in Joint 30 @ 1 261' ~ ~ . , ( I ~ ~ / / 16-Ju1y-07 to 02-May-04 (Comp(etion Date) = 21 MPY ( I li,. '~~~ ~ I ~ I 11-August-09 to 02-May-04 (Completion Date) = 14 MPY I I I Best Fit =16 MPY (Bold Dotted Line) ' 2009 vs 2008 Joint-by-Joint Comparison Approx. I I I I I Corrosion Rate = 16 MPY ~ I I ~ Tubing Failure Projected Between 5.5 and 9.75 Years ~ , 0 5' 10 Years Since Well Completion 15 Correlation of Recorded Damage to Borehole Profile ~ Pipe 1 4.5 in (12.6' - 8099J') Well: NS-32 Field: Northstar Company: BP Exploration (Alaska), Inc. Country: USA Survey Date: August 11, 2009 - _ 1~~~ru~. lo~~l IJevi,iliun ~,. AE~~~ro~. I~c~rehule Prc~tile , I 1 1i 2 i ~ 1022 50 ' 2060 75 3119 ~ ` 10(1 4138 ~ v ~ `.-' ~ ~ " ~ .c Z t Y ~'d '0 125 5191 °' ~ 150 6220 175 7256 194.4 8100 0 50 100 Damage Profile (% wall ) / Tool Deviation (degrees) Bottom of Survey = 194.4 PDS Report Overview ~ s. Body Region Analysis Well: NS-32 Survey Date: August 11, 2009 Field: Northstar Tool Type: UW MFC 40 No. 213120 Company: BP Exploration (Alaska~, Inc. Tool Size: 2.75 Country: USA No. of Rn~ers: 40 Anal st: C. Waldro Tubing: Nom.OD Weight Grade & Thread Nom.ID Nom. Upset Upper len. Lower len. 45 ins 12.6 f L-80 IBT-M 3.958 ins 45 ins 6.0 ins 6.0 ins Penetration and Metal Loss (% wall) ~ penetration body ~ metal loss body 2 50 200 150 100 50 ~ 0 to 1 to 10 to 20 to 40 m over 1% 10% 20°/ 40% 85% 85% Nurnber of'oints anal sed rotal = 202 pene. 0 5 194 3 0 0 loss 1 201 0 0 0 0 Damage Configuratio~ ( body ) 200 1 i0 100 50 0 isola[ed general Bne ring hole / poss pitting corrosion corrosion cormsion ible hole Number of ~oints dama ed total = 196 13 183 0 0 0 Damage Profile (% wall) ~ penetration body ,,~,.;; metal loss body 0 50 1 49 100 97 194 Bottom of Survey = 194.4 145 Analysis Overview page 2 PDS REPORT JOINT TABI. Pipe: 4.5 in 12.6 ppf L-80 IBT-M Well: Body Wall: 0.271 in Field: Upset Wall: 0.271 in Cornpany: Nominal (.D.: 3.958 in Country: Survey Date: -LATION SHEET NS-32 Nortfistar BP Exploration (Alaska), Inc. USA August 11, 2009 Joint No. Jt. Depth (ft.) Pr~n. tJE~,ci il~~~.) Pen. Body (ins.) NE~n. °4~ ME~t~ai loss °4, Min. LD. (Ins.) Comments Damage Profile (%wall) 0 SO 100 1 13 i) 0.05 1~~ ~ 3.93 Shallow A arent Erosion. 1.1 47 (? 0.03 1 Z t 3.94 PUP Sha low A arenl Erosion. 1.2 55 ~~ 0.04 16 ~ 3.95 PUP Shal ow rent Eros' n. 2 65 i? 0.04 14 i 3.92 Shallow A arent Erosion. 3 103 U 0.04 ~ 3.94 Shallow A arent Erosion. 4 145 U 0.04 I' i> .92 Shallow A arent Erosion. 5 187 ~~ 0.05 1 ti -t 3.92 Shallo A arent Erosion. 6 227 ~) 0.04 17 - 3 96 Shallow A arent Erosion. 7 2 9 l~ 0.05 17 4 3.94 Shallow ittin . 8 311 l) 0.04 15 3.94 Shallow A arent Erosion. 9 352 U 0.05 19 5 393 Shallow ittin . 10 394 l1 0 04 15 5 3.94 Shallow A arent Erosion. 11 436 (~ 0.04 16 4 3.92 Shallow itti 12 478 U 0.06 ~' 1 5 3.93 Isolated ittin . 13 519 t) 0.04 I:i -l 3.90 Shallow A arent Erosion. 14 562 O 0. 4 1(i ~ 3.92 Shallow ittin . 15 604 t) 0.05 1£~ i 3.94 Shallow A arent Erosion. 16 645 t) 0.04 1 7 3.94 Shallow A arent Erosio . 17 687 t) 0.05 I t3 5 3.93 Shallow ittin . 18 730 (1.U~, 0.05 I 7 ~ 3.93 Shallow A arent Erosion 19 771 l) 0.05 1 t9 (> 3.93 Shallo A arent Erosion. 20 813 U 0.05 ~~U 3.91 Isolated ittin . 21 855 U 0.05 1~ 7 3.94 Shallow A arent Erosion. 22 897 ~~ 0.04 1 ~ ') 3.95 Shallow A arent Erosion. 23 93 ~~ 0.04 1 E~ !~ 3.93 Shallow A rent Erosion 24 980 !~ 0.04 I ~ +s 3.94 Shallow A arent Erosion. 25 1022 l) 0.06 ~~ 1 i 3.94 Isol~ ted ittin . 26 1064 ~) 0.05 I t3 > 3.94 Shallow A arent Erosion. 27 1 10 (1 0.05 1 t3 3.94 Shallow A a ent Erosio . 28 1146 (~ 0.05 I ti t9 3.92 Shallow A arent Erosion. 9 1187 t) 0.05 I~) Ft 3.93 Shallow A arent Erosion. 30 1229 ~~ 0.08 28 ~ 3.95 Isolated ittin . 31 1271 ~~ 0.06 2(1 f~ 3.94 A arentErosion. 32 1312 ~? 0.04 1(~ - 3.94 Shallow A arent Erosion. 33 1354 U 0.04 14 ~.~~ 3.94 Shallow A arent Erosion. 34 1395 U 0.04 14 5 3.94 Shallow A arent Erosion. 35 1437 t~ 0.04 16 ' 3.93 Shallow A arent Erosi n. 36 1478 U 0.04 1 i 3.95 Shallow A arent Erosion. 37 1520 U 0.05 1 t3 7 3.94 Shallow A arent Erosion. 38 1562 U 0.05 1') 7 3.94 Shallow A arent Erosion. 39 1604 i~ 0.04 1; i~ 3.94 Shallow A arent Eros~on. 40 1646 l~ 0.05 1 t~ ~, 3.94 Shallow A arent Erosion. 41 1688 ~1 0.04 1~1 i 3.95 hallow A arent Erosion. 42 1730 tl 0.04 14 -1 3.93 Shallow A arent Erosion. 43 1771 c) 0.04 1 i 5 3.93 Shallow A arent rosion. 44 181 1 U 0.04 I:9 , 3.91 Shallow A arent Erosion. 45 1851 t~ 0.04 I 5 3.95 Shallow A arent Erosion. 46 1893 ~? 0.04 1 5 t, 3.93 Shallow A arent Erosion. 4 19 5 !? 0.04 15 (, 3.94 S allow A arent Erosion. 48 1977 i) 0.04 1 5 t; 3.95 Shallow A arent Erosion. Penetration Body Metal Loss Body Page 1 PDS REPORT JOINT TABI, Pipe: 4.5 in 12.6 ppf L-80 IBT-M Well: Body Wall: 0.271 in Field: Upset Wall: 0.271 in Company: Nominal I.D.: 3.958 in Country: Survey Date: ~LATION SHEEf NS-32 Northslar BP Exploration (Alaska), Inc USA August 7 t, 2009 Joint No. Jt. Depth (Ft.) f'c~n. I IE,c~~I {In~.) Pen. Body (InsJ Pc~n. % ~tc~t~if I~»s ~~ Min. I.D. Qns.) Comments Damage Profile (%wa1Q 0 50 100 49 2019 ~! .05 I~) i~ 3.95 Shallo A arent E osi 50 2060 U 0.04 15 4 3.94 Shallow A aren Erosion. 51 2102 ~~ .0 5 a 3.94 h I w A arent Erosion. 51.1 2143 ~~ 0.04 15 ~ 3.96 PUP Shallow A arent Frosion. 51. 2153 U 0 O ~~ 3.81 4.5" X-Ni le 51.3 155 U.US 0. 5 I ti i .9 PUP 5hal ow A arent Er sion. 52 2164 lt 0.05 I T i, 3.92 Sh Ilow A a ent Er sio . 53 2205 t) 0.05 1 tS ~ 3.94 Shallow A arent r si n. 54 2247 ~.1 O.QS 19 E3 .95 Shallow A arent Erosio . 55 2288 ~? 0. 4 1~ E~ 3.94 Shallow A r nt Erosion. 56 330 O 0.04 17 i 3.91 Shall w A rent r si n. 7 372 l) 0.04 I i ~~ 3.92 Shal ow A arent Erosion. 58 413 t) 0.04 I 4 5 .94 Shallow A arent Erosion. 5 2455 t? 0.04 I~3 ~> 3.9 Shallow A rent Erosion. 60 2497 U 0.04 14 3.9 Shallow A arent Frosion. 61 2539 U 0.05 1 f~ ~ 3.93 Shallow A arent Erosion. 62 2580 l) 0.04 I i t, 3.94 Shallow A arent Erosion. 63 2621 U 0.04 14 3.95 Shallow A are t Frosion. 64 2663 U 0.04 14 -~ 3.93 Shallow A are t E osion. 65 704 U 0.04 13 5 3.92 Shallow A arent Ero ion. 66 2746 tl 0.03 1 ~ 5 .94 Shallow A arent Erosion. 67 2787 ~~ 0.05 19 %5 3.96 Shallow A arent Erosion. 68 2829 l1 0.04 1-1 -~ 3.95 Shallow A rent Erosion. 69 2870 U 0.04 1 5 - 3.95 Shallow A arent Erosion. 70 2913 U 0.05 1 ti tS 3.95 Shall w A arent Erosion. 71 2955 U 0.04 15 -1 3.94 Shallow A arent Erosion. 72 2996 U 0.04 14 i 3.94 S iallow A arent Erosion. 73 3036 (~ 0.04 15 -1 3.94 Shallow A arent Erosion. 74 3078 U 0.05 17 ~~ .95 Shallow A arent Erosion. 75 3114 U 0.04 1 S -1 3.93 Shallow A arent Erosion. 76 3160 ~) 0.04 I 7 '~ 3.94 Shallo A arent rosion. 77 3200 i~ 0.05 I tt I~~ 3.95 Shallow A arent Erosion. 78 3241 ~~ 0.04 I 4 -1 3 93 Sliallow A arent Erosion. 79 3281 ~) 0.04 1 5 -1 3.93 Shallow A arent Erosion. 80 3319 ~~ 0.05 I£3 ~ 3.94 Shallow A arent rosi n 81 3360 ~) 0.04 15 7 3.95 Shallow A arent Erosion. 82 3400 O 0.0 18 i .95 Shal ow A aren -rosion. 83 3440 i) 0.05 1 ti 1 ~ 1 3.94 Shallow A arent Erosion. 84 3482 U 0.05 I£3 ~~ 3.97 Sh Ilow A arent Erosio . 85 3523 !) 0.03 I 3 ; 3.95 Shallow A arent Erosior~. 8 3 64 U 0.04 15 ~, 3.93 S allow A are t Er sion. 87 3603 U 0.04 1' - 3.94 Shallow A arent Erosion. 88 3645 l) 0.04 1~1 (~ 3.95 Shallow A ar nt Erosion. 89 3686 U 0.05 1£i E~ 3.93 hallow arent Erosion. 90 728 U 0.05 1~> (~ 3.95 Shallow A arent Erosion. 91 3769 (~ 0.03 12 (> 3.95 Shallow A arent Erosion. 92 3809 l~ 0.04 I i t~ 3.93 Shallow A arent Erosion. 93 3849 U Q.04 1 5 (, 3.93 Shallow A arent Erosion. 94 3891 0.04 ~-' 3.93 Shallow A arent I:rosion. 95 3931 0.04 "3.95 Shallow A arent Frosion. ~ Penetra6on Body Metal Loss Body Page 2 PDS REPORT JOINT TABI, Pipe: 4.5 in 12.6 ppf L-80 IBT-M Well: Body Wall: 0.271 in Field: Upset Wall: 0.271 in Cornpany: Nominal I.D.: 3.958 in Country: Survey Date: -LATION SHEEf NS-32 Northstar BP Exploration (Alaska), inc. USA August 11, 2009 Joint No. )t. Depth (ft.) P~~n. 1 J~,~et (Iri~.} Pen. Body (Ins.) P~~n. % Mc~tal l c~ss `;'~~ Min. I.D. Qns.) Comments Damage Profile (%wall) 0 50 100 96 3972 i> 0.04 15 0 3.9 ShallowA arent rosi n. 97 4014 t ~ 0.04 13 i 3.92 ShaAow A arent Erosion. 98 4056 i~ .05 17 (, 3.92 Shallow A arent E osion. 99 4097 i? 0.04 1-1 i~ 3.94 ShallowA arentErosion. 100 4138 u 0.05 I~> ~s 3.93 Shallow A arent Erosio . 101 4179 U 0.05 I fs t> 3.95 Shall w A arent Erosion. 102 4221 t) 0.04 1-1 (, 3.95 Shallow A arent rosion. 103 4262 t) 0.04 I 5 7 3.93 Shallow A arent Erosion. 104 4 04 U 0.04 15 t~ 3.9 Shallo A ar t Erosi n. 105 4346 U 0.04 14 ~~ .93 ShallowA arentErosi n. ~ 106 4388 U 0.04 15 i 3.93 Shallow A arent Erosion. 107 4429 ~~ 0.04 I~t 4 3.94 Shallow A arent Erosion. 108 447 ~) 0.04 I.~ (~ 3.93 S allow A arent Erosion. 109 4510 l1 0.04 ~-~ ~ 3.94 Shallow A arent Erosion. 110 4552 !~ 0.04 I i~ t, 3.94 Shallow A arent Erosion. 1 1 1 4593 t) 0.04 I 5 i 3.93 Shallow A arent Erosion. 112 4631 U 0.04 1-~ 5 3.93 Shallow arent Erosion. 113 4672 !~ 0.03 1 I ~ 3.91 Shallow A arent Frosion. 114 471 1 t1 0.04 1 ~ - 3.96 Shallow A arent Erosion. 115 47 3 U 0.04 1-1 ~, 3.94 Shallow A arent -rosion. 116 4794 ~1 0.04 1_3 5 3.94 Shallow A arent Erosion. 117 4836 ~~ 0.04 15 - 3.95 Shall w A arent Erosion. 118 79 t~ 0.04 I S ~ 3.95 Shallow A arent Erosion. 119 4921 U 0.04 14 4 3.93 Shallow A arent Erosion. 120 4962 t? 0.04 15 5 3.94 hallow A arent Erosion. 121 5003 t) 0.04 14 4 3.92 Shallow A arent Erosion. 122 5044 ~1 0.04 I S c, 3.94 Shallow A arent Erosion. 122.1 5086 U 0.04 1 ~ ~ 3.93 PUP Shallow A arent Erosion. 122.2 5095 U 0 O t ~ 3.88 7.625" x 4.5" Packer 122.3 5100 U 0.04 1(~ - 3.95 PUP Shallow A arent Erosion. 123 5109 ~) 0.04 1 d ~1 3.93 Shallow A arent Erosion. 124 5150 t I 0.04 1 E, ~ 3.94 Shallow A arent Erosion. 25 5191 (1 0.05 1 t~ ~~ 3.96 Shall w A arent Erosion. 126 5232 O 0.04 14 i 3.95 Shallow A arent Erosion. 127 5 74 U 0.04 I i ~ 3.94 Shallow A arent Erosion. 12 5316 ~) 0.04 15 (~ 3.94 Shallow A arent Erosion. 129 5358 (1 0.03 1t) s 3.91 130 5397 U 0.03 1~' ~ 3.91 Shallow ittin . 131 5438 (~ 0.04 I 5 3.95 Shallow A arent Erosion. 132 5479 1) 0.04 l i ~~ 3.93 Shallow A~~arent Frosion. 133 55 0 ~~ 0.04 14 - 3.95 Shallow A arent Erosion. 134 5561 (~ 0.04 1 i i 3.94 Shallow A arent Erosion. 135 5603 U 0. 4 I t -1 3.93 Shallow A arent rosion. 136 5644 (~ 0.04 15 i 3.94 Shallow A arent Erosion. 137 5685 U 0. 3 1? -1 3.94 Shallow A arent Erosion. 138 5726 ~~ 0.04 13 -1 3.90 Shallow A arent Erosion. 139 5767 ~~ 0.04 I 5 3.94 Shallow A arent Erosion. 140 5807 (~ 0.04 1 5 (~ 3.93 Shallow A arent Erosion. 141 5847 ~~ 0.04 !-~ ~ 3.93 Shallow A arent Erosion. 142 5888 !~ 0.03 ~ i i -1 3.93 ;~ Penetration Body Metal Loss Body Page 3 PDS REPORT JOINT TABI, Pipe: 4.5 in 12.6 ppf L-80 IBT-M Well: Body Wall: 0.271 in Field: Upset Wall: 0.271 in Company: Nominal I.D.: 3.958 in Couniry: Survey Date: ~LATION SHEEf NS-32 Northstar BP Exploration (Alaska), Inc. USA August 11, 2009 Joint No. Jt. Depth (Ft.) I'c~n. UF~sct (In~.} Pen. 6ody (Ins.) F'en. % ~tet~il Ic~.S °~~~ Min. I.D. (InsJ Comments Damage Profile (%wall) 0 50 100 143 5929 u 0.04 14 ~> .94 Sh Ilow A arent ro ion 144 5971 ~> 0.04 17 i 3.94 Shall w A arent Ero ion. 145 6013 ~~ .04 l i -1 3.94 Shall w A are Erosion. 146 6054 t~ 0.04 1 5 i, 3.92 Shallow A arent Frosion. 147 6095 U 0.04 I 5 a 3.92 Shallow A arent Erosion. 14 6137 O 0.04 1 1 - 3.93 Shallow A arent Erosion. 149 6178 O 0.03 1 1 s 3.94 Shallow ittin . 150 62 0 ~) 0.03 1 i -i 3.92 Shallow arent Erosion. 151 6261 O 0.04 17 6 3.93 Shallow A arent Eros'on. 152 6302 ~) 0.04 I i (, 3.94 Shallow A arent Erosion. 153 6344 ~~ 0.04 14 ~ 3.94 Sh II w A arent Erosion. 154 6386 (t 0.04 I d 3 95 Sha low A arent Erosi n. 155 6427 l~ 0.04 I-~ !~ 3.94 hallow A arent Erosion. 156 6469 U 0.0 I; a 3.92 hallow A r nt rosion. 157 651 1 f? 0.04 I~1 3.93 Shallow A rent Erosion. 158 65 tt 0.03 I,? 3.91 Shallow A aren Erosion. 159 6594 U 0.04 14 -1 3.93 Shallow A arent Erosi n. 60 6635 c~ 0.04 14 - 3.92 hallow A arent Erosion. 16 6676 ~~ 0.04 1_i 5 3.94 Shallow arent Erosion. 162 6717 ~~ 0.05 1£3 3.96 Shallow A arent Erosion. 163 6759 ~~ 0.03 1(1 ~ 3.91 164 6800 i~ 0.04 15 7 3.95 Shallow A arent Erosi n. 165 6841 U .04 14 (~ 3.94 Shallow A arent Erosion. 166 6883 l) 0.03 13 -t 3.94 Shallow A arent Erosion. 167 69 4 i) 0.03 1? ~~ 3.95 Shallo A a ent Er ion. 168 69 4 c~ 0.04 1 i 3.96 Shallow A arent Erosion. 169 7006 U 0.05 1 tt ' 3.95 Shallow A arent Erosion. 170 7048 (~ 0.04 14 (, 3.91 Shallow A arent Erosion. 171 7090 I? 0.04 1`> 5 3.94 Shallow A a~ent Erosion. 172 7132 i~ 0.03 1? 3.91 Shallow A rent Erosion. 173 7174 U 0.04 1> 3.93 Shall w A arent rosion. 174 7215 ~~ 0.04 1 5 5 3.94 Shallow A arent Erosion. 175 7256 U 0.03 11 ~ 3. 1 Shallow i tin . 176 7297 U 0.04 15 4 3.94 Shallow A arent Erosion. 177 7338 (1 0.04 I i 7 3.94 Shallow A arent Erosion. 178 7380 t) 0.04 14 ~ 3.94 Shallow A arent Erosion. 179 7422 ~~ 0.03 12 1 .93 Shallow A arent Erosion. 180 7462 t~ 0.04 14 i, 3.95 Shallow A arent Erosion. 18 7503 t? 0.05 I t~ ~ 3.95 Shallow A arent rosion. 182 7544 U 0.04 1 3 t~ 3.95 Shallow A arent Erosion. 183 7585 U 0.0 I 5 - 3.95 Shaltow A are t Erosi n. 184 7627 U 0.04 17 ~, 3.93 Shaflow A arent Erosion. 185 7669 U 0.04 15 ti 3.95 Shallow A a ent Erosion. 186 7709 ~) 0.04 1 i ~3 3.92 Shallow A arent Erosion. 187 7752 ~~ 0. 3 9 ~ 3.92 188 7790 ~1 0.04 I 3 ~ 3.9b Shallow A arent [rosion. 189 7832 (~ 0.03 12 ~~ 3.91 Shallow A arent Erosion. 190 7874 ~) 0.03 1 1 a 3.94 Shallow A arent Frosion. 191 7915 ~? 0.04 1 d 3.94 Shallow A> arent Erosion. 192 7957 t' 0.04 1;' ~ 3.95 Shallow A~ arent Lrosion. ~Penetration Body Metal Loss Body Page 4 PDS REPORT JOINT TABI. Pipe: 4.5 in 12.6 ppf L-80 IBT-M Well: Body Wall: 0.271 in Field: Upset Wall: 0.271 in Company: Nominal I.D.: 3.958 in Country: Survey Date: ~LATION SHEET NS-32 Nortfistar BP Exploration (Alaska), Inc. USA August 11, 2009 Joint No. Jt. Depth (Ft.) I'c~n. I 1F>.~~~ Iln~.j Pen. $ody (Ins.) Pen. %, Mc~t.~l I c~s. ~~ Min. I.D. Qns.) Cotnments Damage Profile (%wall) 0 50 100 193 7999 tl 00 1O ~ 3.94 194 8041 t1 0.05 ~'U 3.92 Isolated ittin . 194.1 8079 ~) 0.04 1 S -1 3.94 PUP ShallowA aren ro ion. 194.2 8088 ~~ 0 l~ ~~ 3. 73 4.5" X N-Ni le 19 3 8090 ~~ 0.03 I i I 3.91 PUP 194.4 8100 ~~i 0 t~ ~~ N A WLFC ~Penetration Body Metal Loss Body Page 5 ~~ ~S PDS Report Cross Sections Well: NS-32 Survey Date: August 11, 2009 Field: Northstar Tool Type: UW MfC 40 No. 213120 Company: BP Fxplora6on (Alaska), Inc. Tool Size: 1J5 Country: USA ,'~'o. of Fingers: 40 Tubin : 4.5 ins 12.6 f L-80 IBT-M Anal sr. C. Waldro Cross Section for Joint 30 at depth 1260.98 ft Tool speed = 43 Nominal ID = 3.958 Nominal OD = 4.500 Remaining wall area = 93 % Tool deviation = 23 ° Finger 34 Penetra6on = 0.076 ins Isolated pitting 0.08 ins = 28% Wall Penetration HIGH SIDE = UP Cross Sections page 1 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ PDS Report Cross Sections -, ~S , ~, Well: NS-32 Survey Date: August 11, 2009 Field: Northstar Tool Type: UW MFC 40 No. 213120 Company: BP Exploration (Alaska), Inc. Tool Size: 2.75 Country: USA iti'o. of Fingers: 4U Tubin : 4.5 ins 12.6 f L-80 IBT•M Analyst: C. Waldrop Cross Section for Joint 12 at depth 480.17 ft Tool speed = 43 Nominal ID = 3.958 Nominal OD = 4.500 Remaining wall area = 96 % Tool deviation = 4 ° Finger 5 Penetration = 0.058 ins Isolated pitting 0.06 ins = 21% Wall Penetration HIGH 51DE = UP Cross Sections page 2 W~LHEAD = ABB-VGI ACTUATOR = KB. ~EV = 55.9' BF. ~EV = _ 40.05' (CB 15.9') KOP _ 50 Max Rngle - 47° @ 3122' Datum ND = 12958' Datum ND = 10500' SS NS32 SAFETY :*** EPA CLASS 1 DISPOSAL W ELL *** HAf~R=4" BPV/TWC DATE REV BY COMv~VTS QATE t~V BY COMMBVTS 12/14/03 INITIAL DRILL 07/07I0$ WRR/TLH PROT SLV CORRECTIONS 05/02/04 JAS ORIGINAL COMPLETION 11/11/05 TLH NEUV FORMAT 07l04l06 WRRlPAG MIN ~ OORRECTION (05/12/Q4) 11/27/07 VVRRlPJC WELLHD/LOG4TION CORf~CT~ONS 06130108 WRRlPJG ~AWNG CORF~CTIQN PIORTHSTAR WELL: NS32 PERMIT No: 2031580 API No: 50-029-23179-00 SEC 11, T13N, R13E, 1359' FSL & 649' F~ BP 6cpioration (Alaska) ABB-VGI 5-1/8" 5KSI 11" MULTIBOWL 5K BAK • ~ Memor~ Mu1ti~Fing~r Caliper Log R~sul~s Summary ~ (Revised 08-12--E~9~ Company: BP Exploration (Alaska), Inc. Well: NS-32 Log Date: July 9, 2008 F~eid: Northstar Log No. : 8693 State: Alaska Run No.: 5 API No.: 50-029-23'179-00 , Pipe1 Desa: 4.5" 12.6 Ib. L-80 1BT-M Top Log Intvl1.: Surtace I Pipe1 tJse: Tubing Bot. Log Intvl1.: 8,116 Ft. (MD) ~ Inspection Type : Corrosion Monitoring /nspection CQMMENTS : I This /og is tied into the WLEG a~ 8,100' (ELMD). ' This log was run to assess the condition of the tubing with respect to changes in corro5ive and mechanical damage. The caliper recordings indicate the 4.5" fubing is in good tv fair condition, with a maximum waA penetration of 28% recorded at an isofated pit in joint 7(322'). R~corded damage appears in the form of appa~ent erasion throughout the log interval and isolated pitting. No significant areas ofi cross-sectional wall ~ loss or I.D. restrictions are recorded. This is the fifth time a PDS caliper has been run in this well and the 4.5" tubing has been logged. A comparison between the current and the previous log (July 16, 20Q7) indicates a sligh# inerease in erosive , damage during the #ime between logs and no indication of sign~cant change in corrosive pitking during the time between logs. A graph illustrating the difference in maximum recorded penetrations on a joint-by joint basis between the current and previous !og is included in this report. ' A Time to Failure Evaluation is included in this report, which indicates an overall corrosive trend of 18 miAs per year. this corrosive trend is derived from calcul~tions based on the maximum recorded penetration in #he current log compared to undamaged tubing upon initial completion. The projected tubing failure window ranges from as early as 6.5 years to greater than 10 years. ~ The originat report was derived from calculations based on modal analysis, which is unable to difl`erentiate slight erosion from acceptable manufacturing folerances. Th+s revised report is derived from calculations based on APl nominal pipe dimensions, and mar~ accurately reflects uniform wall /oss due to erosion. , MAX(MUM RECORDED WALL PENETRATiONS: lsolated Pitting ( 28%) Jt. 7 @ 322 Ft. (MD) , Isalated Pitting ( 22°r6) Jt. 27 ~ 1,132 Ft. (MD) Isalated Pitting ( 21°~) Jt. 25 @ 1,084 Ft. (MD} Isolated Pitting ( 20°~) Jt. 20 ~ 852 Ft (MD} Isolateci Pitting { 20°~) Jt. 125 @ 5,209 Ft. (MD) ' MAXIMUM RECORDED CROSS-SECT{ONAL METAL. LOSS: ' Na significarrt areas of cross-sectional waN loss (> 8°~) are recorded. MAXtMUM I~ECORDED ID RESTRICTIONS: ~:t~~~~'~~~'~~~ -~:~'~' `~' ~ ~~L~`~ ~ No significant I.D. restrictions are recorded. F~eld Ertgineer. K. MiNer Analyst: C. Waldrop Witness: M. Harris ~ ProActive Diagnostic Services, Inc. /~.G. Box 1369, Stafford, TX 77497 Phone: (281) or (8$8) 565-9085 Fax: (281) 565-1369 E-mail: PDS@memorylog.com Prudhoe Bay Field Office Phone: (907} 659-2307 Fax: (907) 659-2314 I'~ ' ,' ~~ ~ ~~~ -- t ~ ~ 1 ~ ~`~~ • • ~~ PDS Multifinger Caliper 3D Log Plot Company : BP Exploration (Alaska), Inc. Field : Northstar Well : NS-32 Date : July 9, 2008 Description : Detail of Caliper Recordings For The 5-1/8" 5 KSI Tree. • • ti .~ Well: NS-32 Field: Northstar Company: BP Exploretion (Alaska), Inc Country: USA Maximum Recorded Penetration Comparison To Previous Survey Date: )uly 9, 2008 Prev. Date: July 76, 2007 Tool: UW MFC 40 No. 210357 I ubing: AS" 12.6 16 1-80 B f-M Overlav Max. Rec. Pe n. (miis ) 0 5 0 10 0 1 50 20 0 25 0 1 9 19 29 39 49 56 66 76 ~ 86 a ~ 9b z 0 106 116 123 133 143 153 163 173 183 193 ^ J uly 9, 2 00s ^ July 16, 2007 n I~P-'Pll ('P -100 -5 Diff. in Mar. Pen. (mils 0 0 5 ) 0 10 0 I ~ ~ 9 19 ? i i 29 1 39 ~ 49 ~ I 5g 6~ I ~ ~ 76 v 86 ~ 96 Z 0 106 116 123 133 ' 143 153 763 773 183 193 ' 102 5 1F~~ 1 0 5 xoti. C~orrnsion Rate (m 1 10 PY) 2 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ Time to Failure Evaluation S BP Exploration (Alaska), Inc. Northstar Corrosive Trend: Apparent Erosion, Well : NS-32 Isolated Pitting 4.5" 12.6 Ib L-80 IBT-M Tubing July 9, 2008 Years Following Most Recent Log 4.5" 12.6 Ib L-80 IBT-M 0 5 10 Wail 260 240 ~ 220 ... ~ 200 ,~ 180 ~ ~ 160 ~ 140 y 120 ~ O 100 u c~C 80 ~ 60 ~ 40 20 0 Th ickness = 271 m . ill I ..- I - ~ - - ' . _ ( . I I I 1 d ~ t~~J% '1i3~~ ~h~ k116'!>~; ~~~a ~';! ri4;f~)r} / / ~ ~ I ~ ~ ~ ~ ~ ~ ~ ' .. _ ~ ~ . , _~ I ~ I ~ ~ I ~ ~ ( ~ / ~I ' I ( ~ I ~ / ~ ' I ~ I ~ ~ I 'I ~/ ~~~/ I , ~~ , ~/ 1 ( _ I ~/ ~ ~ ' ~'/I I I I ~ ~ ,- ~ ( ~ ~/ ~' ~// I I I ~ ~ ~~ I I I I ~ '~~~ ~ ~/- r ~/ ( I ~ ~ ~%- ~ .G'~ ~ 2008 Maximum Recorded Wall Penetration , I 1 I ~ ~ 0.077 - 28 ~ Wall Penetration in Joint 7~ 322 I ( - 1 I 09-Ju1y-08 to 16-Ju1y-07 = 11 MPY ~ 16 07 t 1 02 M 04 C l ti D t = 21 MPY J I - I I - u y- o - ( omp e on a e) ay- I 1 09-Ju1y-08 to 02-May-04 (Completion Date) =18 MPY ~ ~ f ~ Tubinq Failure Projected Between 6.5 and >90 Years ~ 1 0 ' S 10 Years Since Well Completion ~ ~ • ~ Correlation of Recorded Damage to Borehole Profile ~ Pipe 1 4.5 in (37.2' - 8100.1') Well: NS-32 Field: Northstar Company: BP Explora6on (Alaska), Inc. Country: USA Survey l~ate: )uly 9, 2008 ~ Approx. Tool DeviaUon ^ Approx. Borehole Profile 1 37 Z ~ 1042 5U 2077 7 ~ 3132 ~ ` 100 4148 ~ m ~ E - ~ ~ Z ~ •- s ' ... c ~0 125 5198 ~ ~- ~ 15U 622 4 175 7257 194.4 8100 0 50 100 Damage Profile (% wall) / Tool Deviation (degrees) Bottom of Survey = 194.4 • • PDS Report Overview ~ ~. Body Region Analysis Well: NS-32 Survey Date: )uly 9, 2008 Field: Northstar Tool Type: UW MFC 40 No. 210357 Company: BP Explorafion (Alaska), Inc. Tool Size: 2.75 Country: USA No. of Fingers: 40 Anal sh C. Waldro Tubing: Nom.OD Weight Grade & Thread Nom.ID Nom. Upset Upper len. l.ower len. 4.5 ins 12.6 f L.-80 IBT-M 3.958 ins 4.5 ins 6.0 ins 6.0 ins Penetretion and Metal Loss (% wall) ~ penetration body ,~ metal foss body 200 150 100 50 ~ 0 to 1 to 1% 10% 10 to 20 to 40 ro over 20`% 40% 85% 85% Number of ~oints anal sed total = 202 pene. 1 56 loss 52 150 142 3 0 0 0 0 0 0 Damage Configuration ( body ) 150 100 50 0 isolateci gencral linc ring hole / poss pitting corrosion corrosion corrosion ible hole Number of ~oints dama ed total = 138 16 122 0 0 0 Damage Profde (°,6 wall) ~ penetration body ~ metal loss body 0 50 100 1 49 97 145 194 Bottom of Survey = 194.4 Analysis Overview page 2 . PDS REPORT JOINT TABI, Pipe: 4.5 in 12.6 ppf L-80 IBT-M Well: Body Wall: 0.271 in Field: Upset Wall: 0.271 in Company: Nominal I.D.: 3.958 in Country: Survey Date: • ~ LATI O N S H EEf NS-32 Northstar BP Exploration (Alaska), Inc. USA )uly 9, 2008 Joint No. Jt Depth (Ft) f'~~n. U~~.E~t Ilns.i Pen. Body (Ins.) Pe~n. % M~~t.il I o„ °~, Min. I.D. (Ins.) Comments Damage Profile (%wall) 0 50 100 1 37 (t 0.03 1 1 > 3.90 Shallow A arent Erosion 1.1 71 U 0.01 ~ u .92 PUP 1.2 78 U 0.03 ~) I 3.93 PUP 2 88 ~1 0.02 tf I 3.92 3 126 u 0.03 ~~ ' 3.9 4 168 U 0.04 1 i -t .92 Shallow A arent Ero ion. 5 210 ~) 0.03 ~) I 3.91 6 249 l~ 0.03 11 _' 3.93 Shallow ittin . 7 290 U 0.08 2ti 1 3.9 Isolat d ittin 8 332 ~? 0.03 13 3 93 hallo ittin . 9 374 U 0.03 11 1 .9 Shallow ittin . 10 416 i~ 0.03 10 ~! 3.93 11 457 !~ 0.02 8 I 3 92 12 499 t~ 0.04 I 4 Z 3.93 Shallow ittin . 13 541 t~ 0.03 1 ~ 1 3.90 14 583 t~ 0.04 15 1 3.92 Shallow ittin . 15 625 U 0.05 14 ' 3.93 Shallow ittin . 16 66 (~ 0.04 15 ; 3.93 Shallow itGn . 17 708 (~ 0.03 1:~ ~ 3.93 Sh Ilow ittin . 18 750 (~ 0.04 14 4 3.93 Shallow ittin . 19 792 !~ 0.04 14 5 3.93 Shallow A arent Erosion. 2U 834 ~~ 0.05 1t) ~1 3.93 Isolated ittin . 21 875 ~? 0.05 1 t3 5 3.94 Shallow A arent rosion. 22 917 t1 0.04 1(~ 3.95 Shallow A arent Erosion. 23 95 U 0. 4 I-3 -I 3.93 Shallow i tin . 24 1001 (~ 0.03 1~ ~> 3.94 Shallow A arent Erosion. 25 1042 O 0.06 _' I `> 3.94 Isolated ittin . 26 1084 U 0.04 16 ~1 3.94 Shallow A arent Erosion. 27 1125 ~~ 0.06 22 (> 3.94 Isolated itUn . 28 1166 u 0.04 15 - 3.93 Shallow A arent Erosion. 29 1207 ~~ 0.04 15 i~ 3.93 ShallowA arent osion. 30 1248 ~~ 0.05 1 ff ~~ 3.96 Shallow ittin . 31 1290 u 0.05 1!3 a 3.93 Shallow ittin . 32 1332 l1 0.04 1-l i~ 3.94 Shallow A arent Erosion. 33 1373 U 0.03 l:i 5 3. 4 Shallow A arent Erosion. 34 1414 ~) 0.03 I~) ~-1 3.94 35 1456 l) 0.03 1:3 i 3.94 Shallow A arent Erosion. 36 1497 U 0.04 15 -l 3.93 Shallow A arent Erosion. 37 1539 U 0.04 I i t, 3.95 Shallow A arent E osion. 38 1580 ~~ 0.03 1,! -1 3.92 Sliallow A arent Erosion. 39 1622 t~ 0.03 1 s 4 3.93 Shallow A arent Erosion. 40 1664 U 0.03 I Z a 3.93 Shallow A arent Erosion. 41 1706 ~~ 0.03 1 Z 3.9 Shallow A arent rosion. 42 1748 ~1 0.03 1 1 s 3.91 Shallow A arent Erosion. 43 1789 U 0.03 13 ' 3.93 Shallow A arent Erosion. 44 182 9 ~~ 0.02 8 1 3.89 45 1869 ~? 0.03 1 1 4 3.93 Shallow A arent Erosion 46 1911 U 0.04 15 4 3.92 Shallow A arent Erosion. 47 1953 i ~ 0.03 1~' -1 3.84 Shallow A arent Erosion. 48 1994 ~? 0.04 I 3 ~ 3.77 Shallow A arent Frosion. ~Penetration Body Metal Loss Body Page 1 ~ PDS REPORT JOINT TABI. Pipe: 4.5 in 12.6 ppf L-80 IBT-M Well: Body Wall: 0.271 in Field: Upset Wali: 0.271 in Company: Nominal I.D.: 3.958 in Country: Survey Date: • ~LATION SHEEf NS-32 Northstar BP Exploration (Alaska), Inc. USA luly 9, 2008 Joint No. )t Depth (Ft) f'c~n. UF~.r~t (lii..j Pen. Body (InsJ Pen. % ~~1et.~l I uss "~~~ Min. I.D. (Ins.) Comments Damage Profile (%wall) 0 SO 100 49 2036 U 0.03 11 -1 3.8 Shallow A arent Erosi n. 50 2077 ~) 0.03 12 ? 3.93 ShallowA arentErosion. 51 2118 ~~ 0.03 1:; S 3.93 Shallow A arent Er si n. 51.1 2159 ~? 0.04 l i b 3.95 PUP Shaliow A arent Erosion. 51.2 2169 ~) 0 ~~ ~~ 3.81 4.5" X-Ni le 51.3 2171 l) 0.03 I 3 ~ 3.94 PUP Shallow A arent Erosion. 52 27 80 l1 0.04 I 4 4 392 Shallow A arent Erosion. 53 2221 u 0.04 15 '> 3.94 Shallow A arent Erosion. 54 26 t~ 0. 3 13 ~ 3.94 Shallo n ar nt Erosion. 55 23 4 U 0.03 13 a 3.89 Tern o aril Im aired Fin ers. 56 2346 !) 0.04 1 S _' 3.89 Tem rar'I I aire Fin ers. 57 2387 l).~~3 0.04 1 i ' 3J5 Tem oraril Im aired Fin ers. 58 2429 t).t)3 0.04 I' ~ 3J" Tem oraril Im aired Fin e. 59 2470 t~ 0.03 I t ~ 3J1 Tem oraril Im aired Fin ers. 60 2512 U 0.03 1> ; 3.93 Shallow A arent Erosion. 61 2554 U 0.01 ~ I 3.92 62 2595 ~~ 0.02 ~> ' 3.92 63 2636 U 0.02 tj _' 3.92 64 2677 O .03 1 t~ ~' 3.92 65 2718 u 0.03 It1 ? 3.89 66 2760 ~~ 0.02 8 1 3.91 67 2801 U 0.03 I s 4 3.94 Shallow n arent Erosion. 68 2843 ~~ 0.03 1U ~~ 3.93 69 2885 c~ 0.03 1 l t 3.93 Shallow A arent Erosion. 70 927 ~~ 0. 4 I; 3.91 Sha low a e t sion 71 2969 ~~ 0.03 I U I 3.91 72 3010 ~~ 0.0 9 1 3.93 73 3050 t) 0.03 1l) 1 3.92 74 3091 ~~ 0.03 13 (~ 3.94 Shallow A arent Erosion. 75 3132 ~~ 0.03 1 Z ' 3.92 Shallow A arent Erosion. 76 3173 +~ 0.04 15 3.92 Shallow A arent rosion. 77 3213 t i 0.04 I 6 i 3.94 Shallow A arent Erosion. 78 3254 ~~ 0.03 9 1 3.92 79 3294 i1 0.03 11 I 3.92 80 3331 u 0.03 1 1 -1 3.93 Sh Ilow A arent Erosion. 81 3372 ~~ 0.04 l:, 4 3.93 Shallow A arent Erosion. 82 3413 U 0.04 1 a -~ 3.9 Shallow A aren Erosion. 83 3453 U 0.03 1 t ~ 3.94 Shaflow !1 arent Erosion. 84 3494 U 0.04 I> - 3.94 Shallow arent Erosion. 85 3535 ~~ 0.04 1=1 3.93 ShallowA~ arentFrosion. 86 3576 ~~ 0.03 12 3.92 Shallow A arent Erosion. 87 3615 i? 0.03 1:i 3.93 Shallow A arent Erosion. 88 3656 ~? 0.03 11 3.92 Shallow A arent Frosion. 89 3698 ~~ 0.04 1 i ~' 3.91 Shallow A arent Erosion. 90 3740 t7 0.03 10 I 3.93 91 3780 t~ 0.03 1(1 1 3.92 92 3820 i? 0.02 8 I 3.90 93 3860 ~? 0.03 ~~ 1 3.89 94 3903 0.04 I~ 3.91 Shallow A arent Erosion. 95 3942 0.03 ! I 3.93 Shallow A arent Frosion. Penetration Body Metal Loss Body Page 2 • PDS REPORT JOINT TABI. Pipe: 4.5 in 12.6 ppf L-80 IBT-M Well: Body Wall: 0.271 in Field: Upset Wall: 0.271 in Company: Nominal I.D.: 3.958 in Country: Survey Date: • iLATION SHEET NS-32 Northstar BP Exploration (Alaska), Inc USA Jufy 9, 2008 Joint No. )t. Depth (Ft) I'~~n. IJ~~sc•i (ins.) Pen, Body (Ins.) I'c~n. °i;~ ~I~~IaI I~~~~s ,~, Min. I.D. (Ins.) Comments Damage Profile (%wall) 0 50 100 96 3983 U Q04 1 3 5 3.90 S low A arent Erosion. 97 4024 ~~ 0.03 1(~ I 3.9 98 4066 i~ 0.03 I U ' 3.91 99 4107 ~~ 0.03 1 1 3.93 Shallow A arent Er sion. 100 4148 U 0.03 I 3 ~i 3.9 Shallow A arent Erosion. 101 4189 ~) 0.02 ~) s 3.93 102 4231 t~ 0.03 1 ~ ~1 3.93 Shallow A arent Erosion. 103 4273 u 0.03 11 ~~ 3.91 104 4314 U .03 1 ~' -1 3.93 Shall w A arent Erosion. 105 4356 u 0.03 1 U ~' 3.92 106 4398 (1 0.03 i l I 3.92 107 4439 U 0.03 9 ? 3.93 108 4479 U 0.04 1 5 5 3.93 Shallow A arent Erosion. 109 4520 tt 0.03 I; ~ .92 Shallow A arent Erosion. 110 4561 ~? 0.04 I 5 (, 3.94 Shallow A~arent f.rosion. 111 4602 t~ 0.04 15 ~l 3.93 Shallow A arent Erosion. 112 4641 U 0.03 I; -i 3.9 Shallow A arent Erosion.. 113 4681 (~ 0.04 I-1 > 3.91 Shallow A arent Erosion. 114 4720 ~? 0.04 1(i tt 3.94 Shallow A arent Erosion. 115 4762 U 0. 3 1 4 3.92 Shallow A arent Erosion. 116 4803 u 0.04 1~~ -l 3.93 Shallow A arent rosio . 117 4845 U 0.05 1 t~ i, 3.94 Sha low A arent Erosion. 118 4887 t~ 0.05 19 (, 3.94 Shallow A ar nt Erosion. 119 4928 t? 0.02 ~) ~ 3.93 120 4969 U 0 03 1 I -l 3.93 hall w A ar t~ro ion. 121 501 1 t~ 0.03 I:~ ~ 3.93 Shallow A arent Erosion. 122 5052 ~~ 0.03 I 3 ; 3.93 Shallow n are t Erosi n. 122.1 5093 U 0.04 16 4 3.93 PUP Shallow A arent Erosion. 122. 5103 U 0 U u 3.88 7.625" x 4.5" Packer 122.3 5107 O 0.04 1-1 ~ 3.94 PUP Shallow A arent Erosion. 12 5116 ~? 0.04 1 5 3.92 Shallow A arent Erosion. 124 5157 t~ 0.04 I(~ 3.94 Shallow A arent Erosion. 125 5198 l) 0.05 1~) t~ 3.94 A arent Erosion. 126 5239 lt 0.03 11 _' 3.93 127 5281 ~1 0.05 17 (~ .93 Shallow A arent E osio . 128 5323 ~~ 0.04 1 ti 4 3.93 Shallow A arent Erosion. 129 365 ~~ . 4 14 4 .91 Shallow A arent E osion. 130 5404 ~~ 0.03 I i I 3.91 Shallow A arent Erosion. 131 5445 ~~ 0.05 I ~ !, 3.93 Shallow A are t Erosion. 132 5486 ~~ 0.05 1' 3.90 Sliallow A arent Erosion. 133 5526 (~ 0.04 1~ ~ 3.93 Shallow A arent r sion. 134 5568 U 0.04 I 4 3.92 Shallow A arent Erosion. 135 5609 U 0.03 I I ,' 3.90 Shallow A rent Erosion. 136 5650 ~~ 0.04 16 ~ 3.88 Shallow A arent Erosion. 137 5691 c) 0.02 8 1 3.89 138 5732 U 0.03 11 O 3.87 139 5772 t) 0.02 ~) 1 3.89 140 5813 U 0.01 5 1 3.89 141 58 3 ~~ 0.04 I~~ I 3.89 Shallow A are t Erosion. 142 5894 0.01 -1 I 3.88 ~Penetration Body Metal Loss Body Page 3 • PDS REPORT JOINT TABI, Pipe: 4.5 in 12.6 ppf L~0 IBT-M Well: Body Wall: 0.271 in Field: Upset Wall: 0.271 in Company: Nominal I.D.: 3.958 in Country: Survey Date: • iLATION SHEET NS32 Northstar BP Exploration (Alaska), Inc. USA july 9, 2008 Joint No. Jt. Depth (Ft.) I'~~n. ~ lF~,~~i Urn.~ Pen. Body (Ins.) Pc~n. % ~tc~l,~l I c,s. °~, Min. I.D. (InsJ Comments Damage Profile (%wall) 0 50 100 143 5 34 ~~ 0.03 1 U I 3.89 144 5977 i~ 0.03 I 9 ? 3.89 S I ow rent rosi n 14 6018 ~ ~ 0.02 3 i ~ 3.89 146 6059 ~ i 0.03 1 i ~ I 3.87 147 6100 i~ .03 I i) I 3.85 148 6142 ~~ 0. 3 I U I 3.89 149 6183 ~~ 0.02 ~i I 3.89 150 6224 ~~ 0.02 t, I 3.89 151 6 65 u 0.03 1 I 1 3.89 Shal o A arent sion 152 6307 ~1 0.03 10 I 3.90 153 6347 U 0.03 I i 4 3.91 hal o A are t rosio . 154 6390 U 0.03 1~ ,' .92 S a lo arent Erosion 155 64 1 ~ t 0.04 1 i 3 3.92 S allow A are t Erosio . 156 6473 u 0.03 1 S , 3.90 Shall w A a nt Ero ion. 157 6514 U 0.04 I s ; 3.91 Sh Ilo A aren Erosion. 158 6555 ~~ 0.02 t; 3.89 159 6597 ~~ 0.03 ( I ; 3.91 160 6638 U 0.04 I s ~ 3.89 Shallow A arent Erosion. 161 6679 0 0.0 I;i ; 3.92 Shallow A arent Erosion. 162 71 u 0.04 14 .93 Sh Ilo A arent Er si n. 163 6761 ~~ .03 11 1 3.88 Shallow A arent Erosion. 164 6802 ct .03 1 1 2 3.90 Shallow A arent Erosion. 165 6843 t~ 0.03 13 _' 3.97 Shallow A arent E osion. 166 6884 u 0.03 ~~ I 3.90 6925 u 0. 3 13 -l 3.92 h 1 A ar n osi 168 6966 U 0.04 14 t, 3.92 Shallow A arent Erosion. 169 7007 U 0.04 I i -l .92 Sh Ilow A arent rosion. 170 7049 (~ 0.03 1 1 s 3.88 Shall w A arent Erosion. 71 7091 ~~ 0. 3 13 , 3.90 Sh Ilow A arent Erosi n. 7 72 713 3 u 0.00 U 1 3.88 173 7175 ~~ 0.04 14 -1 3.91 Shall w A arent Erosion. 174 7216 ~~ 0.03 1 ~! 3.90 Shallow A arent Erosion. 1 5 7257 U 0.02 ~) I 3.87 176 7297 U 0.03 1t) I 3.91 177 7339 1 ~ 0.03 I? -t 3.97 Shal w A arent Er sio . 178 7380 i~ 0.04 I 3 3.90 Shallow A arent Erosion. 179 74 U 0.03 lU ~_' .89 180 7462 U 0.03 l:i s 3.91 Shallow A arent Erosion. 181 7503 u 0.03 1 U 3.90 182 7544 U 0.03 1_' 3.91 Shallow A arent Erosion. 183 7585 (~ 0. 3 I_' ~ 3.91 Shallow A re t Ero i n. 184 7627 ~~ 0.03 1? ? 3.89 ShallowA arentErosion. 185 7669 U 0. 4 14 ~l 3.91 S allow A arent Er sio . 186 7709 t) 0.03 I 1 I 3.89 Shallow A arent Erosion. 187 77 1 t i 0.02 t~ I 3.88 188 7790 t1 0.03 I I s 3.91 Shallow A arent Erosion. 189 7831 U 0.03 ~~ 1 3.87 190 7873 ~~ 0.01 -~ 1 3.90 191 7914 ~~ 0.03 ') 1 3.8 192 7956 n 0.03 11 ~~ 3.90 Penetration Body Metal Loss Body Page 4 ~ PDS REPORT JOINT TABI. Pipe: 4.5 in 12.6 ppf L-80 IBT-M Well: Body Wall: 0.271 in field: Upset Wall: 0.271 in Cornpany: Nominal I.D.: 3.958 in Country: Survey f~ate: • ~LATION SHEEf NS-32 Northstar BP Expioration (Alaska), Inc. U SA )uly 9, 2008 Joint No. )t Depth (Ft.) f'~~n. ~ l~~sc~t (Inti.j Pen. Body (Ins.) Pen. °o :~tc~tal I u~s ~~ Min. I.D. (InsJ Comments Damage Profile (% wall) 0 50 100 193 7998 u 0.01 ~ 1 "3.89 194 8040 U 0.02 8 I 3.88 Lt. De osits. 194.1 8079 t) .03 10 3.90 PU 194.2 8088 u 0 0 ~~ 3.73 4.5" XN-Ni le 1943 8090 ~~ 0.03 12 i, 3.87 PUP Shallow A arent Erosion. 194.4 8100 u 0 i? ~~ N A WLEG Penetra6on Body Metal Loss Body Page 5 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ PDS Report Cross Sections ~--~u - -'~ „ WeN: NS-32 Survey Date: July 9, 2008 Field: Northstar Tool Type: UW MFC 40 No. 210357 Company: BP Exploration (Alaska), Inc. Tool Size: 2.75 Country: USA fv'o. of Fingers: 40 Tubin : 4.5 ins 12.6 f L-80 IBT-M Ana~ st: C. Waldro Cross Section for Joint 7 at depth 322.03 ft Tool speed = 43 Nominai ID = 3.958 Nominal OD = 4.5Q0 Remaining wall area = 99 % Tool deviapon = 1 ° Finger 34 Penetration = 0.077 ins Isolated pitting 0.08 ins = 28% Wall Penetration HIGH 51DE = UP ~ • Cross Sections page 1 ~1 ~~ PDS Report Cross Sections Well: NS-32 Survey Date: July 9, 20Q8 Field: h'orthstar Tool Type: UW MFC 40 No. 210357 Company: BP Explora6on (Alaska), Inc. Tool Size: 2.75 Country: USA No. of Fingers: 40 Tubin : 4.5 ins 12.6 f L-80 IBT- Analyst: C. Waldrop Cross Section for Joint 2 7 at depth 1132.09 ft Tool speed = 43 Nominal ID = 3.958 ' Nominal OD = 4.500 Remaining wall area = 97 % Tool deviation = 18 ° Finger 2 Penetration = 0.06 ins ~solated pitting 0.06 ins = 22°/a Wall Penetration HIGH SIDE = UP ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ i ~ ~ ~ ~ Cross Sections page 2 ~ ~ 1 "`rr - W~LHEAD = ABB-VGI ACTUATOR = BAK KB. ~EV = 55.9' BF. ~EV = 40.05' (CB 15.9') KOP = 50~ Max Angle - 47° @ 3122' Datum ND - 12958' Datum ND = 10500' SS ~ 20" Cbf~tJCTOR, 169#, X-56 ~ ~ Minimum ID = 2.625" @ 2169' ' ~ 4-1/2" X NIPPLE I 10-3/4° CSG, 45.5#, L-&0 BTC, ~_$.95° -~ 396 SAFETY N •*"`* EPA CLASS 7 DIS POSAL W ELL *"* HANGER=4 BPViiWC NS32 2097~ -i HEAT TRACE (2100' TO StR~FAC~ I 2169~ 4-1/2" X NIP, ~= 3.813" w/PROTECTIVE SLV"" ""'USE 4-1/2" F.I.T SIORT TO PULL/SET SLV 5102~ ~ 7-5/8" X 4-1(2" BKR S-3 RCR ~= 3.875" 4-1l2" TBG, 12.6#, L-80 ~T-M, .01b2 bpf, D = 3.958" 7-5/8" CSG, 29J#, L-80 BTC, ~= 6.875" (8114' ELM D CSG SHOE - 05I1 M04) 6-3l4" OPBV HOLE TD ~ 8321 ~ 8088' H4-1/2" r~S XN N~, ~= 3. I 8100' I DATE REV BY COMUIBVTS DATE REV BY COMVIHVTS 12/14/03 INITIAL DRILL 07/07i08 WRRffL PROT SLV CORRECTIONS 05(02/04 JAS ORIGINAL COMPLETION 11/11/05 TLH NEW FORMAT 07l04/06 WRR/PAG NI~1 ~1 CORRECTION {05/12/04) 11/27/07 WRR/PJC WE1LI-~/LOCATION CORRECTIONS 06/30/08 WRR/PJC DRAWNG CQRRECTbN ABB-VGt 5-1J8" 5KSI 11" MULTIBOWL 5KS 4-1l2" WLEG, ~ = 3.958" (8102' Sl6 05/14/04) NORTHSTAR WELL: NS32 PERM(T No: 2031580 API No: 50-029-23179-00 SEC 11, T13N, R13E, 1359' FSL & 649' F~ BP Exploration (Alaska) • • BP Exploration (Alaska) Ina Attn: Well Integrity Coordinator, PRB-20 '~: Post Office Box 196612 '' Anchorage, Alaska 99519-6612 -~, ~ ~ . ¢~a~ ~_~ ~~~' ~~~ May 26, 2009 I~s~~~ I~il ~ ~`~r~.~~ ~~~~n°lission Mr. Tom Maunder Alaska Oil and Gas Conservation Commission ~~ ~ ~' ~'~ 333 West 7t" Avenue .~ Anchorage, Alaska 99501 Subject: Corrosion Inhibitor Treatments of Northstar Dear Mr. Maunder, Enclosed please find a spreadsheet with a list of wells from Northstar that were treated with corrosion inhibitor in the surface casing by conductor annulus. The corrosion inhibitor is engineered to prevent water from entering the annular space and causing external corrosion that could result in a surface casing leak to atmosphere. The attached spreadsheet represents the well name, top of cement depth prior to filling and volumes of corrosion inhibitor used in each conductor. As per previous agreement with the AOGCC, this letter and spreadsheet serve as notification that the treatments took place and meet the requirements of form 10-404, Report of Sundry Operations. If you require any additional information, please contact me or my alternate, Anna Dube, at 659-5102. Sincerely, Andrea Hughes BPXA, Well Integrity Coordinator • BP Exploration (Alaska) Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off Report of Sundry Operations (10-404) ~~ ~~ Date Northstar • 5/26/2009 Well Name PTD # Initial top of cement Vol. of cement um ed Final top of cement Cement top off date Corrosion inhibitor Corrosion inhibitor/ sealant date ft bbls ft na al NS05 2050090 1.7 na 1.7 na 10 4/30/2009 NS06 2021010 0.5 na 0.5 na 1.7 4/30/2009 NS07 2020770 1.1 na 1.1 na 5.3 4/30/2009 NS08 2020210 0.75 na 0.75 na 3.6 4/30/2009 NS09 2012190 1.2 na 1.2 na 3.4 4/30/2009 NS10 2001820 0.25 na 0.25 na 3 4/30/2009 NS11 2060360 0.75 na 0.75 na 5.1 5/1/2009 NS12 2021100 1.2 na 1.2 na 3.2 5/1/2009 NS13 2010860 1.7 na 1.7 na 6.8 5/1/2009 NS14 A 2052020 0.9 na 0.9 na 2.8 5/1/2009 NS16 2061410 1.3 na 1.3 na 5.8 5/1/2009 NS17 2021690 1.2 na 1.2 na 2.6 5/1/2009 NS18 2021410 1.5 na 1.5 na 7.3 5/1/2009 NS19 2022070 1.5 na 1.5 na 10.2 5/2/2009 NS20 2021880 1.4 na 1.4 na 8.5 5/2/2009 NS21 2022180 1.7 na 1.7 na 4.3 5/2/2009 NS22 2022230 1.6 na 1.6 na 10.2 5/2/2009 NS23 2030500 0.75 na 0.75 na 3 5/2/2009 NS24 2021640 0.75 na 0.75 na 2.6 5/2/2009 NS25 2031660 * na * na 2.6 5/2/2009 NS27 2010270 0.6 na 0.6 na 1 5/3/2009 NS28 2050160 1.5 na 1.5 na 8.1 5/3/2009 NS30 2052070 0 na 0 na 4.3 5/3/2009 NS32 2031580 * na na 1.7 5/3/2009 NS34 2080170 0 na 0 na 2.2 5/3/2009 *Not measured due to rig proximity. AFL JuN o ~ 2nos . ~. by • . , Jean A. Celestain Performance Unit Leader -Northstar, Endicott, Bad mi Alaska Consolidated Team (ACT) By Certified Mail # 7000 0520 0014 9272 3826 October 30, 2008 Mr. Michael A. Bussell Director, Office of Compliance and Enforcement U.S. Environmental Protection Agency 1200 Sixth Avenue Seattle WA 98101 RE: Northstar NS32 Class I Injection Well -MIT Report Permit Number AK-11002-A Dear Mr. Bussell: BP,Fxploration {Alaska) Inc. 900 `East Benson Boulevard PO Box 196612 Anchorage, AK 99519-6612 (907) 564-5111 Phone: (907) 564-5107 Fax: (9071564-4441 Email: CelestJ~bp.com Web: www.bp.com ~oZ~ s In order to meet the requirements of the Northstar Class I Injection Well Permit (AK-11002-A) Part II.C.3.b.(1) and Part II.C.3.c.(1), BP Exploration (Alaska) Inc. (BPXA) submits the attached two (2) copies of an interpretive report to the Environmental Protection Agency (EPA). A pressure test of the tubing-casing annulus was performed on the Northstar well NS32 on October 11, 2008. On the day of the test, EPA Representative Talib Syed was present to witness that the pressure test passed. The mechanical integrity of well NS32's tubing, packer, and casing was demonstrated. No communication to the tubing or outer annulus was evident. The field report and an interpretive report~are enclosed. If you have any questions, please call Robert Younger at 907-564-5392. Sincerely, ~~%~~z-' Jean A. Celestain Attachments cc: Talib Syed, EPA Consultant Shawn Stokes, ADEC Jim Regg, AOGCC Jeff Walker, MMS !-~~ Alison Cooke, BPXA Northstar File Copy ~L~~ Compliance Matrix Administrator: Matrix ID 8774 • Northstar NS32 Class 1 Disposal Well Mechanical Integrity Test • Test conducted by pressurizing the Inner Annulus (the casing by tubing annulus.) Inner Annulus Cumulative Outer Tubing Description Time Pressure change in IAP Percentage Annulus Pressure (minutes) (prig) (psi) change in IAP Pressure (psig) (psig) Arrive - 0 - - 0 390 Begin test 0 3520 - - 0 390 15 3400 -120 -3.41 % 0 390 End test 30 3370 -150 -4.26% 0 390 Allowable pressure drop is 5% of 3500 psi, or 175 psi, in 30 minutes. During this test, the total pressure decrease on the IA was 150 psi. EPA Representative, Talib Syed, was present to witness the test. Test conducted on 10/11/2008. "In order to demonstrate there is no significant leak in the casing, tubing or packer, the tubing/casing annulus must be pressure tested to at least 3,500 pounds per square inch gauge (psig) for not less than thirty minutes. Pressure shall show a stabilizing tendency. That is, the pressure may not decline more than 10 percent during the 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 5% or if the loss during the second 15 minute period is equal to or greater than one half the loss during the first 15 minutes, the permittee may extend the test period for an additional 30 minutes to demonstrate stabilization. This pressure test is required at a timer interval of no more than 12 months between tests" EPA Class I Permit AK-11002- A, Part II C 3 b (1 ), Page 12 of 16 We1lServiceReport • Page 1 of 1 WELL SERVICE REPORT WELL JOB SCOPE UNIT NS'3Z ANN-COMM (REG COMPL) LRS 38 DATE DAILY WORK DAY SUPV 10/11/2008 MIT-IA TILBURY COST CODE PLUS KEY PERSON NIGHT SUPV NSFLDWL32-I LRS-ZIMMERMAN UNKNOWN MIN ID DEPTH TTL SIZE 0" OFT 0" T/I/O = 390/0/0 ***EPA Witnessed MITIA PASSED to 3520psi*** Pressured up w/ 6.5bbls diesel. IA lost 120psi 1st 15min, 30osi 2nd 15min. or a total of 150osi in 30min. Bled IA to zero. FWHP's = 390/0/0 LOG ENTRIES Init-> 390 0 0 TIME BPM BBLs FLUID TEMP TBG IA OA COMMENTS 15:30 Start Ticket. Ri u . 15:54 PT to 4000 si. DHD to ri u e ui ment. 16:28 0.5 St Diesel 40*F 390 0 0 Start down IA 16:34 0.5 4.5 390 100 0 Cau ht fluid. Kick in tri lex. 16:40 6.5 390 3520 0 Shut down. Start Test. 16:55 390 3400 0 15min ressures. 17:10 390 3370 0 30min ressures. PASS. Bleed down. Ri down. 23:59 End Ticket Final-> 390 0 0 JOB COSTS SERVICE COMPANY -SERVICE DAILY COST CUMUL TOTAL LITTLE RED $1,530 $1,530 TOTAL FIELD ESTIMATE: $1,530 $1,530 FLUID SUMMARY 6.5bbls diesel #1 REQUIRED TEST PRESSURE 3,520 TEST TYPE MIT-IA FLUIDS USED TO TEST DIESEL START TIME: 16:40 PRE TEST PRESSURES INITIAL PRESSURES 15 MINUTE PRESSURES 30 MINUTE PRESSURES PASS OR FAIL TUBING 390 390 390 390 IA 0 3,520 3,400 3,370 PASS OA 0 0 0 0 COMMENTS EPA WITNESSED BY TALIB SYED. http://apps2-alaska.bpweb.bp.com/awgrs-wellservicereport/default.aspx?ID=4654CSOEF... 10/ 16/2008 ~- ~~__-_+-_- _ 8 ,, -' ~ _- r .--- - - ~~ ~''_ ~ .. - "~---- -= ~_~~ 5000 = -~f ~ ~ _ ~~ ~ 9 / _ --~ ~ ~ ~ ~~ , ~ Z -~ - - --y- -'-- ~ ~ ~~ ~ v~ ~ _ ~ 1 •~ ~ i~ ,; X~/ ~ _ ; =sue 25 0 -~~! ~~ ~ 1\`y~\ \~ \\ ~\ •~'_ ,'\'. \ ~%irl ~ ~ /~~ , ~ ~ '+ 2000 - 7 ~~, ~` ~~ ~~ ` \ '` \ ~\'` ~`~~ ~ ~lkk OQO~ ~~ ~ y j ;~'~ ) • ^ :1000 ~ -/~`,~ ' ~ ~ ~.~ \ \ >C\, ~` \ , \ \ \ ' 1 ~.. Q k y f -f - ~`~ Y • ~ V~ J~ A ~ ~ \ A ~ ~ ~ ~ { ~ v . / (1/~Q~/'~ '//~/ ~-~ / -' 500 '~+~ ~ X-~. /~ ~i`\\ ~\~. \ ~ T\\\ ~', \`~' \`\~\` ' -~ .~{ ~' i ~ ~ ~~".`QO~ rO' '`~ r ~ g C6RQ~q pt\0'1 ~ ' `y \ \ 1 \iO ~ ~~DO 000 ; X00 ~ ~ O ~ ~ 4 0 ~ . 0 1 Q r r ~ a~ yiJF V~, ~, i ~~ 1 ~~ ~ ~ 1~ ~ ~'~ V 1 ~ 1~~1 ~ ~ ~4 ~ _ ~ ~ ~~~ 1, v/~i~~ `, ,,,~~ ;~ ~ f~ij v O O O~ ~ .~ QQ~ ~.: ~c 1 ~ r ~ ~ `.A ~~~~~ON\~ ~~i ' ~ rat' ;QO ~ ~' ~ .-~ ~ ~ ~ ~~',~ \ ~~ >~r.` - ~ C . OA ~ ~ ~ 1 ~ ~ _ ; - - ~ s y .-~ ~ ~ ~ %, v ~~,~;K'c ~~~v ~ ~: ~ 0001 .~ + , y ,1 ~ ~ ~ v i , ~ 1 ,- ,, k'- ~ ,' ~ ~ , - ~ ~ \\ `x 4 _ Y ~~ 1 N Q ,C ~ / l,. _ ~ __ ,. ~~ - _ __ = y:/ _ - 8 ~.. • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Email to:jim.regg@alaska.gov; tom.maunder~ataska.gov;bob.fleckensteinC~3alaska.gov;doa.aogcc.prudhoe.bay~alaska.gov OPERATOR: BP Exploration (Alaska) Inc. FIELD /UNIT /PAD: Northstar / NS / NS DATE: 10/11/08 OPERATOR REP: Andrea Hughes AOGCC REP: Packer De th Pretest Initial 15 Min. 30 Min. Well NS32 T e In'. N TVD 4,070' Tubin 3 3 (> Interval O P.T.D. 2031580 T e test P Test si 500 Casin p rj' P/F Notes: EPA witnessed by Thor Cutler annual MIT•IA OA Q for re ulato com liance. Well T e In'. TVD Tubin Interval P.T.D. T e test Test psi Casin P/F Notes: OA Well T e Iri. TVD Tubin Interval P.T.D. T e test Test si Casin P/F Notes: OA Well T e In'. TVD Tubin Interval P.T.D. T e test Test si Casin P/F Notes: OA Well T e In'. TVD Tubin Interval P.T.D. T e test Test si Casin P/F Notes: OA TYPEINJ Codes D =Drilling Waste G =Gas I =Industrial Wastewater N =Not Injecting W =Water TYPE TEST Codes M =Annulus Monitoring P =Standard Pressure Test R =Internal Radioactive Tracer Survey A =Temperature Anomaly Survey D =Differential Temperature Test ~~- ~Y ~~ INTERVAL Codes I =Initial Test 4 =Four Year Cycle V =Required by Variance T =Test during Workover O =Other (describe in notes} MIT Report Form BFL 11/27/07 MIT ACT NS3210-11-08.x1s r Y . ~ • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Email to:jim.reggC~alaska.gov; tom.maundert~alaska.gov;bob.fleckenstein~alaska.gov;doa.aogcc.prudhoe.bayC~alaska.gov OPERATOR: BP Exploration (Alaska) Inc. FIELD /UNIT /PAD: Northstar / NS / NS DATE: 10/11 /08 OPERATOR REP: Andrea Hughes AOGCC REP: Packer De th Pretest Initial 15 Min. 30 Min. Well NS32 T pe Inj. N TVD 4,070' Tubin 390 390 390 390 Interval O P.T.D. 2031580 T pe test P Test psi 1500 Casin 3,520 3,400 3,370 P/F P Notes: EPA witnessed by Thor Cutler annual MIT-IA OA 0 0 0 0 for re ulato compliance. Well Type In'. TVD Tubin Interval P.T.D. T e test Test psi Casin P/F Notes: OA Well T pe Inj. TVD Tubin Interval P.T.D. T e test Test psi Casin P/F Notes: OA Well T e Inj. TVD Tubin Interval P.T.D. Type test Test si Casin P/F Notes: OA Well T pe Inj. TVD Tubin Interval P.T.D. T e test Test psi Casin P/F Notes: OA TYPEINJ Codes D =Drilling Waste G =Gas I =Industrial Wastewater N =Not Injecting W =Water TYPE TEST Codes M =Annulus Monitoring P =Standard Pressure Test R =Internal Radioactive Tracer Survey A =Temperature Anomaly Survey D =Differential Temperature Test INTERVAL Codes I =Initial Test 4 =Four Year Cycle V =Required by Variance T =Test during Workover O =Other (describe in notes) MIT Report Form BFL 11/27/07 MIT ACT NS32 10-11-OB.xls MIT Forms for EPA Compliance: Northstar, Badami, Pad 3, GNI Page 1 of 1 Regg, James B (DOA)I r !~ `~3.-- 15g, From: NSU, ADW Well Integrity Engineer [NSUADWWeIIlntegrityEngineer@BP.com] Sent: Friday, October 17, 2008 9:45 AM To: Regg, James B (DOA); Maunder, Thomas E (DOA); Fleckenstein, Robert J (DOA) Cc: NSU, ADW Well Integrity Engineer; Younger, Robert O; Bill, Michael L (Natchiq) Subject: MIT Forms for EPA Compliance: Northstar, Badami, Pad 3, GNI Attachments: MIT ACT NS10 10-11-08.x1s; MIT ACT NS32 10-11-08.x1s; MIT BAD B1-01 10-09-08.x1s; MIT PBU GNI-02A, 03, 04 10-07-08.x1s; MIT PBU OWDW-NW, SE, SW 10-08-08.x1s Jim, Tom and Bob, Please see the attached MIT forms for the following wells for annual EPA compliance testing: NS10 (PTD #2001820): MIT-IA witnessed by Thor Cutler. ~QS32 (PTD #2031580): MIT-IA witnessed by Thor Cutler. B1-01 (PTD #1971570): MIT-IA witnessed by Thor Cutler and Talib Syed. GNd-02A (PTD #2061190): MIT-IA witnessed by Thor Cutler and Talib Syed. GNI-03 (PTD #1971890): MIT-IA witnessed by Thor Cutler and Talib Syed. GNI-04 (PTD. #2071170): MIT-IA witnessed by Thor Cutler and Talib Syed. OWDW-NW (PTD #1002400): MIT-IA witnessed by Thor Cutler and Talib Syed. OWDW-SE (PTD #1002390): MIT-IA witnessed by Thor Cutler and Talib Syed. OWDW-SW (PTD #1002380): MIT-IA witnessed by Thor Cutler and Talib Syed. «MIT ACT NS10 10-11-08.x1s» «MIT ACT NS32 10-11-08.x1s» «MIT BAD B1-01 10-09-08.x1s» «MIT PBU GNI-02A, 03, 04 10-07-08.x1s» «MIT PBU OWDW-NW, SE, SW 10-08-08.x1s» Please call with any questions or concerns. Thank you, Andrea Hughes Well Integrity Coordinator Office: (907) 659-5102 Pager: (907) 659-5100 x1154 r; ~. Q(t 10/17/2008 n STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Email to:jim.regg@alaska.gov; tom.maunder@alaska.gov;bob.fleckenstein@alaska.gov;doa.aogcc.prudhoe.bay@alaska.gov OPERATOR: FIELD /UNIT /PAD: DATE: OPERATOR REP: AOGCC REP: BP Exploration (Alaska) Inc. Northstar / NS / NS 10/11/08 Andrea Hughes ,~~~~~ ~~ Packer De Pretest Initial 15 Min. 30 Min. Well NS32 Type Inj. N TVD 4 0' Tubing 390 390 390 390 Interval O P.T.D. 2031580 Type test P Test psi 1500 Casing 3,520 3,400 3,370 P/F P Notes: EPA witnessed by Thor Cutler annual MIT-IA OA 0 0 0 0 for regulatory compliance. Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA TYPE INJ Codes D =Drilling Waste G =Gas I =Industrial Wastewater N =Not Injecting W =Water TYPE TEST Codes M =Annulus Monitoring P =Standard Pressure Test R =Internal Radioactive Tracer Survey A =Temperature Anomaly Survey D =Differential Temperature Test INTERVAL Codes I =Initial Test 4 =Four Year Cycle V =Required by Variance T =Test during Workover O =Other (describe in notes) MIT Report Form BFL 11/27/07 MIT ACT NS32 10-11-08.x1s ~,. ~,. • -. Date C8-1 ; -2CC8 Transmittal 1Vumber:92989 BPXA WELL, DATA TRAlVS1VIITTAI. Enclosed are the materials listed below. Tf von have anv rniectinne_ nlease contact .ine I.astufka at (9071564-4091 Delive Contents SW Name Date Contractor Run To De th Bottom De th Descri tion WATERFLOW INJECTION NS10 07-12-2008 SCH 1 4800 7980 LOG CD-ROM - WATERFLOW NS10 07-12-2008 SCH INJECTION LOG WATERFLOW INJECTION NS32 07-13-2008 SCH 1 3700 8080 LOG CD-ROM - WATERFLOW NS32 07-13-2008 SCH INJECTION LOG Please Sign and Return one copy of this transmittal. Thank You, Joe Lastufka Petrotechnical Data Center ~~~~~ Ai1G ~~ ~~ BPXA AOGCC Murphy Exploration DNR MMS vse ~-`~-a ~/6~ ~~_~ ao3 -~s~ ~«~~ O5~ yam) ~'~ `G rw~ ~1 d~r~ ~J David Fair Christine Mahnken Ignacio Herrera Kristin Dirks Doug Chromanski Petrotechnical Data Center LR2-l 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 995 1 9-66 1 2 ~i • Memory Mufti~inger Gatiper Log Results Summary Company: BP Exploration (Alaska), Inc. Well: NS-32 / WD-02 Log Date: July 9, 2008 Field: Northstar Log No.: 8693 State: Alaska Run No.: 5 API No.: 50-029-23179-00 Pipet Desc.: 4.5" 12.6 Ib. L-80 IBT-M Top Log Intvll.: Surface Pipet Use: Tubing Bot. Log Intvl1.: 8,116 Ft. (MD) ~ Inspection Type : Corrosion Monitoring Inspection COMMENTS This log is tied into the WLEG @ 8,100' (ELMD). This log was run to assess the condition of the tubing wi#h respect to corrosive and mechanical damage. The caliper recordings indicate that the 4.5"tubing is in good condition, with a maximum wall penetration of 25°k recorded in joint 7 (322'). The damage appears in the form of isolated pitting. No significant areas of cross-sectional wall loss (> 6%) or l.D. restrictions are recorded. This is the fifth time a PDS caliper has been run on this well. A comparison between the current and the previous log (July 16, 2007) indicates an increase in corrosive damage, at a general rate of -16 mils per year as shown in the included comparison graph illustrating the difference in maximum recorded penetrations on a joint-by joint basis. A Time to Failure Evaluation graph is included in this report, also indicating a general corrosive trend of 16 mils per year, derived from calculations based on the damage recorded in the current log compared to undamaged tubing upon initial completion. The projected tubing failure window ranges from as early as 8.6 years to greater than 10 years. MAXIMUM RECORDED WALL PENETRATIONS: isolated Pitting (25%) Jt. 7 ~ 322 Ft. (MD) Isolated Pitting (20%) Jt. 15 ~ 643 Ft. (MD) No other significant wall penetrations (> 18°k) are recorded, MAXIMUM RECORDED CROSS-SECTIONAL METAL LOSS: No significant areas of cross-sectional wall loss (> 6%) are recorded. MAXIMUM RECORDED ID RESTRICTIONS: No significant I.D. restrictions are recorded. °~~~'' ~U~ ~' ~ ~~~ Field Engineer: K. Miller Analyst: C. Waldrop Witness: M. Harris ProActive Diagnostic Services, Inc. / P.O. Box 1369, Stafford, TX 77497 Phone: (281) or (888) 565-9085 Fax; (281) 565-1369 E-mail: PDS@memorylog.com Prudhoe Bay Field Ofrice Phone: (907) 659-2307 Fax: (947) 659-2314 • • _~~ PDS Multifinger Caliper 3D Log Plot Company : BP Exploration (Alaska), Inc. Field : Northstar Well : NS-32 Date : July 9, 2008 Description : Detail of Caliper Recordings For The 5-1/8" 5 KSI Tree. • • ~ ~ ~~ Well: NS-32 Field: N orthstar Company: BP Exploration (Alaska), Inc. Country: USA Maximum Recorded Penetration Comparison To Previous Survey Date: July 9, 2008 Prev. Date: July 16, 2007 Tool: UW MfC 40 No. 210357 Tubing: 4.5" 12.61b L~OIBT-M Overlay Max. Rec. Pe n. (mil s) 0 5 0 1 00 1 50 2 00 2 50 1 9 19 29 39 49 56 66 76 86 ~ 96 Z 3 106 116 123 133 143 153 163 173 183 193 ^ Ju ly 9, 20 08 ~ J uty 16, 2007 Difference -2 Dill. in Max 5 0 2 . Pen. (mil 5 5 s) 0 7 5 Z •a I i~ -25 0 25 SO 7> Approx. Corrosion Rate (mpy) ~ 9 19 29 39 49 56 66 76 86 96 106 11.6. 123 t33 143 153 163. 173 183 193 ~ ~ ~ ~ w ~ ~ ~ r ~ ~ ~ ~ ~ r ~ ~ ~ ^~ Time to Failure Evaluation BP Exploration (Alaska), Inc. ~ _ ~~ Northstar Well : NS-32 Corrosive Trend: Isolated Pitting 4.5" 12.6 Ib L-80 IBT-M Tubing July 9, 2008 Years Following Most Recent log 4.5" 12.6 Ib L-801ST-M 0 5 10 Wali 2so 240 n 220 ~ 200 180 e~ ~ 160 a~ a 140 y 120 'o O 100 v o~C 80 ~ 60 40 20 0 Th ickness = 271 m ill ~ - -..__ __ o ~ (85 ~~~ ~-:~i~ .5~~ii kness afety~ ~~...~:~r) ~~ I ~ I ~~~/ I ~ , _ ~ ~ 1 ~ ~ ~ ~ ~ ~ ' ~ Maximum Wall Penetration j ~ ! ' , Recorded in Jt. 7 ~ 322'. ~ I ~ 09-July-08 to 16-July-07 =11 mpy 16-July-07 to 02-May-04 = 18 mpy ~ 09-July-O8 to 02-May-04 I I I I (Completion Date) =16 mpy ~ ~ ' 0 ' S 10 Years Since Well Completion • • • Correlation of Recorded Daman Pipe 1 4.5 in (37.2' - 8100.1') Well: Field: Company: Country: Survey Date: • ;e to Borehole Profile NS-32 Northstar BP Exploration (Alaska), Inc. USA July 9, 2008 ^ Approx. Tool Deviation ^ Approx. Borehde Profile 1 37 25 1042 50 2077 75 3132 O 100 4148 ~ a~ .n .: E `~ ~ .~ Z t ~ '0 125 5198 Q- ~ 150 6224 175 7257 194.4 8100 0 50 100 Damage Profile (% wall) /Tool Deviation (degrees) Bottom of Survey = 194.4 • PDS Report Overview ~--,~,,~--. ~~. Body Region Analysis Well: NS32 Survey Date: July 9, 2008 Field: Northstar Tool Type: UW MFC 40 No. 210357 Company: BP Exploration (Alaska), Inc. Tool Size: 2.75 Country: USA No. of Fingers: 40 Anal st: C. Waldro Tubing: Nom.OD Weight Grade & Thread Nom.ID Nom. Upset Upper len. Lower len. 4.5 ins 12.6 f L-80 IBT-M 3.958 ins 4.5 ins 6.0 ins 6.0 ins Penetration and Metal Loss (% wall) i penetration body , _- metal loss body 200 150 100 50 0 0 to 1 ro 10 to 20 to 40 to over 1 % 10`% 2lr'/o 40% 85% 85% Number of'oints anal sed total = 202 pene. 0 177 24 1 0 0 loss 95 107 0 0 0 0 Damage Configuration (body ) 10 0 isolated general line ring hole /pons pitting corrosion corrosion corrosion ible hole Number of 'oints dama ed total = 2 2 0 0 0 0 Damage Profile (% wall) ~ penetration body :- metal loss body 0 50 100 1 49 97 145 194 Bottom of Survey = 194.4 Analysis Overview page 2 • • PDS REPORT J OINT TABULATION SHEET Pipe: 4.5 in 12.6 ppf L-80 IBT-M Well: NS-32 Body Wall: 0.271 in Field: Northstar Upset Wall: 0.271 in Company: BP Exploration (Alaska), Inc. Nominal I.D.: 3.958 in Country: USA Survey Date: July 9, 2008 Joint No. Jt. Depth (Ft.) I'~~n. Ill~,~~t (Irn.l Pen. Body (Ins.) f'~~n. ",~, Metal logs „~ Min. LD• (Ins.) Comments Damage Profile (%wall) 0 50 100 1 37 ~! 0.01 4 1 3.93 1.1 71 (! 0.01 3 i1 .94 PUP 1. 78 c ~ 0.01 ~ I 3.9 PUP 2 88 (~ 0.01 -1 I 3.94 3 126 ~! 0.01 5 I 3.95 4 168 (! 0.02 3.94 5 210 a 0.01 5 _' 3.94 6 249 ~) 0.02 ti 1 3.95 7 290 a 0.07 Z5 I 3.94 Isolated itti 8 332 U 0.01 -1 I 3.95 9 374 l! 0.02 ~) I 3.95 10 416 a 0.03 I I I 3.95 11 457 ~! 0.01 5 ' 3.95 12 499 ~! 0.03 1 ~' I 3.95 13 541 t! 0.03 1 U I 3.94 14 583 ~! 0.03 13 1 3.94 15 625 t! 0.05 2!! 1 .94 solated ittin . 16 666 (! 0.03 1 U I 3.9 17 708 a 0.03 II I 3.95 18 750 n 0.03 I.' z 3.94 19 792 a 0.01 s I 3.96 20 834 (1 0.04 15 _' 3.96 21 875 O 0.03 11 I 3.97 22 917 0 0.01 4 I 3.96 3 959 (1 0.03 1l) _' 3.94 24 1001 c! 0.01 4 1 3.97 25 1042 a 0.04 15 1 3.96 26 1084 U 0.03 12 1 3 96 7 1125 a 0.05 1 ti 3.97 28 1166 i! 0.02 t~; 3.97 12 7 ~! 05 I:' 3.95 30 1248 ~! 0.03 II I 3.97 1 90 ~t 0. 4 I , I .96 32 133 n 0.01 T 3.95 137 U 0 t3 I 3. 6 34 1414 U 0.01 ~ I 3. 7 35 6 ! ti 3. 5 36 1497 ~! 0.02 ~~ I 3.95 1 3 tt Ifj I 3.9 38 1580 ~! 0.02 is 5 16 ~! 0. ti I 40 1664 ~! 0.02 8 I 3.96 17 ~! .01 I 42 1748 ~! 0.02 ~~ ? 3.94 789 ~! 0.01 4 I 44 1829 n 0.01 '~ 1 3.93 1 (i .O1 ~t I .9 46 1911 ! ~ 0.04 1 ~t ~ 3.95 47 19 3 ~! 4 1 i _' t. f e posit . 48 1994 0.03 I (! 3.80 Lt. L)c~ x~sits. _ Penetration Body Metal Loss Body Page 1 ' Pipe: Body Wall ' Upset Wal Nominal L Joint No. J 49 0 51 51.1 51.2 1. 5 5 54 55 56 57 58 9 60 61 62 63 64 6 66 67 6 69 7 71 72 73 74 75 76 77 8 79 81 8 83 85 87 9 91 93 94 95 • PDS REPORT J OINT TABULATION SHEET Pipe: 4.5 in 12.6 ppf L-80 IBT-M Well: NS-32 Body Wall: 0.271 in Field: Northstar Upset Wall: 0.271 in Company: BP Exploration (Alaska), Inc. Nominal I.D.: 3.958 in Country: USA Survey Date: July 9, 2008 Joint No. Jt. Depth (Ft.) I'en. I )Inca (Irn.) Pen. Body (Ins.) P<~n. °4, ~1ct~~l I vs "~~ Min. LD• (Ins.) Comments Damage Profile (%wall) 0 50 100 96 3983 a 0.02 6 ~> 3.9 97 4024 U 0.01 4 ,' 3.93 98 4066 t) 0.01 ~ 3.93 9 4 07 U 0.0 Itl ! 3.95 00 4148 t I 0.01 ~ 3.93 101 4189 t ~ 0.01 ~' 3.95 10 4231 t~ 0.01 v ~ 3.95 103 4273 t~ 0.0 t _' 3.93 104 4314 U 0.0 I U I 3.96 10 5 43 56 t ~ 0.0 tf I 3.94 10 4 98 t l 0 02 8 I 3.9 1 7 39 t ~ 0.02 t3 1 3.94 108 4479 a 0.02 t3 a 3.96 109 4520 t I 0.01 ri a 3.94 1 4561 t) 0 1 4 -t 3.9 11 1 4602 I t 0 0 5 ~ 3.9 11 4641 U 0.01 5 _' ~ 3.9 1 3 4 81 tl .0 b 3 3. 4 114 4720 U 0.02 V 4 .96 115 4762 t l 0.02 7 ~ 3.95 116 4803 i ~ 0.0 t, 3.95 1 1 4845 t~ 0.01 4 a 3.96 118 4887 n 0.0 c, 3 3.96 119 49 8 t~ 001 -t ; 3.95 1 0 4 9 ~i 0 1 > ; 121 5011 it .0 ti 1 3.96 122 5052 a 0.02 ~~ 3.95 122.1 5093 a .01 4 ~ 9 P 122. 5103 U 0 tl l) 3.8 Baker - P cker 122.3 5107 l~ 0.02 8 I 3.98 PUP 11 U ~ ' 1 4 5157 t i 0.0 ~s -1 3.96 1 8 tl i ~ 7 2 52 9 (~ .01 5 1 7 1 tl 0 13 -1 6 128 5323 tl 0.02 ~~ i 3.96 53 t~ i -1 130 5404 t~ 0.03 10 Z 3.93 1 t~ 0 i 132 5486 a 0.03 13 3 3.93 1 5 6 u 1U ' .9 134 5568 ~ ~ 0.02 ti 3 3.96 5609 t ~ 0 t3 ~ 136 5650 cl .01 4 - 3.92 137 5691 tl 5 138 5732 t~ 0.01 4 I 3.88 C1 U ' 140 5813 ~ ~ 0.01 i 1 3.92 41 5 3 ~.~ 0. ~ I 42 5894 ~ ~ 0.01 "~ I 3.91 Penetration Body Metal Loss Body Page 3 • PDS REPORT J OINT TABULATION SHEET Pipe: 4.5 in 12.6 ppf L-80 IBT-M Well: NS-32 Body Wall: 0.271 in Field: Northstar Upset Wall: 0.271 in Company: BP Exploration (Alaska), Inc. Nominal l.D.: 3.958 in Country: USA Survey Date: )uly 9, 2008 Joint No. Jt. Depth (Ft.) I'E~n. ~ ll„~,i (ln.l Pen. Body (Ins.) I'c~n. °/ total I ~~„ Min. LD• (Ins.) Comments Damage Profile (%wall) 0 50 100 143 5934 U 0.02 (~ I 3.93 144 5977 a 0. 2 ti ~ 3.92 145 6018 ~ ! 0.0 (> 1 3.92 146 6059 ~! 0.01 ~ _' 3.90 14 6100 ~! 0.02 ti 3.88 148 6142 i ! 0.02 t3 ~ 3.92 149 6183 i! 0.03 ~! I 3.9 150 6224 ~! 0.01 1 I .91 151 6265 (! 0.02 2> I 3.92 152 07 ~! 0.01 3.93 153 6347 U 0. 1 3.94 154 6390 U 0.01 -1 ~t 3.95 155 6431 tl 0.01 5 I 3.95 156 6473 ~! 0.01 4 .93 157 6514 t! 0.01 5 _' 3.94 1 8 6555 t! 0.02 ti 1 3.92 159 6597 ~! 0.01 5 3 3.94 60 6 38 a 0.0 1 U ~ 3.92 161 667 U 0.01 4 I 3.95 162 6719 c t .01 4 3.96 163 6761 c! 0.0 7 3.91 164 6802 ~) 0.01 4 3.93 165 6843 ~! 0.01 3 I 3.94 166 6884 U 0.01 5 ~ 3.93 67 6 t! 5 .9 168 6966 ~! 0.03 Ill s .95 169 7007 t! 0.0 t~ 1 3.95 170 7049 ~! 0.0 6 I 3.91 171 7091 ~~ 2 13 I 3.94 172 7133 ~! 0.01 ~ I 3.91 17 71 (! 1 5 s 3.93 174 7216 ~) 0.0 7 _' 3.93 1 7 ~! 3 1 176 7297 ~) 0.01 4 1 3.93 17 7 ! 0 , s 3. 178 7380 ~~ 0.01 4 I 3.93 7 ! -t I 9 180 7462 ~! 0.01 ~ 3.94 1 75 ~'~ .01 `~ I 3 4 1 2 75 ~! 0.0 is 3.95 3 ~! 0. r, ~ 184 7627 ~! 0.01 -i 3.92 1 5 7 U 0. a 186 7709 ~! 0.02 is I 3.91 18 77 ~! 0.01 ! 39 188 77 0 ~! 0.01 '~ 3.94 8 1 ~! I 190 7 73 ~ ! 0.01 ~ 1 3. 2 1 1 7 14 0. 2 1 3.9 ~' 192 7956 0.02 ~ I 3.93 Penetration Body Metal Loss Body Page 4 ~ ~ PDS REPORT JOINT TABULATION SHEEP Pipe: 4.5 in 12.6 ppf L-80 IBT-M Body Wall: 0.271 in Upset Wall: 0.271 in Nominal LD.: 3.958 in Well: NS-32 Field: Northstar Company: BP Exploration (Alaska), Inc. Country: USA Survey Date: July 9, 2008 Joint No. Jt. Depth (Ft.) I'c•n. l11»c~l (Irn.) Pen. Body (Ins.) Pc~n. `% ~~tctal Icm ~~ Min. LD• (Ins.) Comments Damage Profile (%wall) 0 50 100 193 7998 a 0.01 5 I 3.90 194 8040 t ~ 0.01 -1 I 3. 2 194.1 8079 a 0.01 -1 _' 3.9 PUP 194.2 8088 U 0 U ~! 3.73 HES XN-Ni le 194.3 8090 a 0.04 15 _' 3.91 PUP 194.4 8100 n 0 U u 3. 6 WL G ;Penetration Body Metal Loss Body Page 5 s ~ ~ ~ ~ ~ ~ ~ ~ ~ i ~ ~ ~ ~ ~ ~- ~ PDS Report Cross Sections <__ _ ,~'~ Well: NS-32 Survey Date: July 9, 2008 Field: Northstar Tool Type: UW MFC 40 No. 210357 Company: BP Exploration (Alaska), Inc. Tool Size: 2.75 Country: USA No. of Fingers: 40 Tubin 4.5 ins 12.6 f L-80 IBTM _Analyst:________ C. Waldrop Cross Section for Joint 7 at depth 322.01 ft Tool speed = 43 Nominal ID = 3.958 Nominal OD = 4.5 Remaining wall area = 95 Tool deviation = 1 ° Finger 34 Radius = 2.08 ins Isolated pitting 0.07 ins = 25% Wall Penetration HIGH SIDE = UP • • Cross Sections page 1 ~- _ ~ PDS Report Cross Sections ._ Well: NS-32 Survey Date: July 9, 2008 Field: Northstar Tool Type: UW MFC 40 No. 210357 Company: BP Exploration (Alaska), Inc. Tool Size: 2.75 Country: USA No. of Fingers: 40 Tubin 4.5 ins 12.6 f L-80 IBT-M Anal st: C. Waldro Cross Section for Joint 15 at depth 642.66 ft Tool speed = 43 Nominal ID = 3.958 Nominal OD = 4.5 Remaining wall area = 93 °!° Tool deviation = 8 ° Finger 30 Radius = 2.046 ins Isolated pitting 0.05 ins = 20% Wall Penetration HIGH SIDE = UP • • Cross Sections page 2 TREE= ABB-VGI5-718" 1 20" CONDUCTOR, 169#, X-56 200' Minimum ID = 2.625" @ 2169' ' 4-1/2" X NIPPLE wtP'R4TECTIVE SLV ' 14-3t4" CSG, 45.5#, L-80 BTC, ID = 9.95" 3964' ' 4-1/2" TBG, 12.6#, L-80 IBT-M, 8100' .0152 bpf, ID = 3.958" 7-5/8" CSG, 29.7#, L-80 BTC, ~ = 6.875" 8107' (8114' ELM D CSG SHOE - 05!14/04) ' '6-314" OPEN HOLE TD NS32 NOTES: HANGER=4"BPVITWC HEAT TRACE (2100' TO 4-1/2" X NIP.ID - 3.$13" 02' 117-5/8" X 4-1 /2" BKR S-3 PKR ~ = 3.875" 8088' i 8100' I DATE REV BY COMNEVTS DATE REV BY COMMHVTS 12/14/03 INITIAL DRILL 85/02/04 JAS ORIGINAL COMPLETION 11/11/05 TLH NEW FORMAT 07104/06 WRR/PAG MN ID CORRECTION (05/12/04) 11!27!07 WRR/PJC WELLHD/LOCATION CORRECT~NS 06/34!08 WRR/PJC ORAWNG CORRECTION WELLHEAD= . _ ABB-VGI11" MULTIBOWL _~ , ACTUATOR = .-- BAK KB. ELEV . 55.9' BF. REV = 40.05' (CB 15.9') KOP = 50~ Mau Angle = 47° @ 3122' Datum MD - 12958' Datum TVD = 10500' SS ~4-1/2" HES XN NIP, ~ = 3.725" 4-112" WLEG, D = 3.958" (8102' SLB 05/14/04) NORTHSTAR WELL: NS32 PERMff No: a2031580 API No: 50-029-23179-00 SC-C 11, T13N, R13E, 1359' FSL &649' F~ BP Exploration (Alaska) MEMORANDUM • TO: Jim Regg ~~,, Q-~Z~/~Y~ P.I. Supervisor FROM: Bob Noble Petroleum Inspector State of Alaska Alaska OiI and Gas Conservation Commis DATE: Tuesday, April Ol, 2008 SUBJECT: Mechanical Integrity Tests BP EXPLORATION (ALASKA) INC NS-32 NORTHSTAR UNI"f NS-32 Src: Inspector NON-CONFIDENTIAL Reviewed By: P.I. SuprY~~~ ~Z'~~' Comm -- Well Name: NORTHSTAR UNIT NS-32 API Well Number: 50-029-23179-00-00 Inspector Name: Bob Noble Insp Num: mitRCN080325080117 Permit Number: 203-158-0 Inspection Date: 3/21/2008 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. ____ --- -- - - _- Well NS 3z Type Inj. ~ w TVD 4070 / IA 20 ~ 3500 3450 3410 -- -__ - __ - -- --- -- p.T i zo3lsso . TypeTest SPT I Test psi 3soo pA o ! o i o 0 - ---- _~ -- _ _- - - ---- _ - _1 - - _~ - } -- -~-- __- - ---- Interval oTrrER p~F P ~ Tubing ~97o i X970 ~ X970 ~ I92o Notes: EPA witnessed, annual MI"h-IA t~~~BIT~' HpF1 ~ LU®a~ Tuesday, April 01, 2008 Page 1 of 1 ~ • ,,,,,_ ----„~ a.`4 .:. .;~,. ~. g' b ~.o MICROFILMED 03/01 /2008 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:1LaserFiche\C~rPgs_Inserts~Microfilm Marker.doc e e bp Date 08-14-2007 Transmittal Number:92897 1 6 Z007 t\nC1îorage BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. If you have any questions, please contact me in the PDC at 564-4091. ::) Log Top SW Name Date Contractor Run Depth Bottom Depth Log Type u:tc... -/1Ja NS10 07-21-2007 SCH 1 4800 7975 WATERFLOW INJECTION :tc!' 0"3-,,,4<- NS32 07 -20-2007 SCH 1 3760 8075 WATERFLOW INJECTION 9- dó"7- NS19 07 -08-2007 SCH 1 13650 13955 PERFORATION RECORD --03(:.. NS11 07 -06-2007 SCH 1 14450 14625 PERFORATION RECORD Ai - rYX(_ NS13 07-14-2007 SCH 1 11 534 11790 MEMORY PPROF - (~ NS24 07 -1 5-2007 SCH 1 11774 12476 STATIC BOTTOM HOLE , è -9~3 NS22 07 -09-2007 SCH 1 12600 12850 PERFORATION RECORD - -b81 NS08 12-23-2005 PDS 1 9006 11406 CORRELATION LOG ö;J ..-al~ NS21 07 -02-2005 PDS 1 21590 22249 DEPTH DETERMINATION -¡:~ -/~c9 NS10 01-01-2006 PDS 1 4497 5497 CORRELATION LOG 8óO () g ~Ö '}o(c h. )JJSL=J ~o )ùd (,) ~oo c.1L-- Please Sign and Return one copy of this transmittal. Thank You, Andy Farmer Petrotechnical Data Center 5CANNED AUG 1 72007 Attn: Doug Chromanski Ignacio Herrera Howard Okland Kristin Dirks Cheryl Ploegstra MMS Murphy Exploration AOGCC DNR BPXA Petrotechnical Data Center LR2-1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519-6612 e e bp Date 08-15-2007 Transmittal Number:92900 BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. If you have any questions, please contact me in the PDC at 564-4091. Log Top SW Name Date Contractor Run Depth Bottom Depth LOQ Type MEMORY CALIPER LOG NS10 07 -17 -2007 PDS 7 0 8006 RESULTS AND CD ROM MEMORY CALIPER LOG NS32 07 -16-2007 PDS 4 0 8103 RESULTS AND CD ROM l~,V~ Please Sign and Return one copy of this transmittal. Thank You, Andy Farmer Petrotechnical Data Center R·...···E...· ¡cr. E¡ \\!FD . '" "f U¥!- ¡\\ '.G 1 6 7.007 j\V -'- Attn: Doug Chromanski Ignacio Herrera Howard Okland Kristin Dirks MMS Murphy Exploration AOGCC DNR - ~"í'\~ cor",misSiO\1 ")~a Ci\ &: Gas ",VI ,¡). i>\J. . Af1\,"h<J,ag6 ~ ,~< i~ AUG 1 72007 u:re. e()ù-Itç; :I: /5"33/ U:r.~ ao'ß - lS"ff 11: tS""3~ Petrotechnical Data Center LR2-1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519-6612 I I I I I I I I I I I I I I I I I I I . . Memory Multi-Finger Caliper Log Results Summary Company: Log Date: Log No. : Run No.: Pipe1Desc.: Pipe1 Use: BP Exploration (Alaska), Inc. July 16, 2007 8609 4 4.5" 12.6 lb. L-80 IBT-M Tubing NS..J2 I WD-02 Northstar Alaska 50-029--23179-00 Surface a,103Ft. (MD) Well: Field: State: API No.: Top Log IntvI1.: Bot. Log I ntvl1.: Inspection Type: Co"osion Monitoring Inspection COMMENTS: This log is tied into the WLEG @ 8,100' (WLEG). This log was run to assess the condition of the tubing with respect to changes in corrosive and mechanical damage. The caliper recordings indicate that the 4.5" tubing is in good condition with respect to corrosive damage. A maximum wall penetration of 21% is recorded in joint 27 (1,120'). The damage appears to be in the form of Isolated/Shallow Pitting. No significant areas of cross-sectional metal loss or 1.0. restrictions are recorded. This is the fourth time a PDS caliper has been run on this well. A comparison between the current log and the previous log run on this well (August 4, 2006) indicates a slight increase in corrosive damage from surface to 1,150' and little, if any increase, from 1,150' to the bottom of the 4.5" tubing. MAXIMUM RECORDED WALL PENETRATIONS: Isolated Pitting @ 1,120 Ft. (MD) ( 21%) Jt. 27 No other significant wall penetrations (> 19%) are recorded. MAXIMUM RECORDED CROSS-SECTIONAL METAL LOSS: No significant areas of cross-sectional wall loss (> 3%) are recorded. MAXIMUM RECORDED ID RESTRICTIONS: No significant 1.0. restrictions are recorded. s~ þ.\JG "1 '2\)\)1 I Field Engineer: K. Miller Analyst: B. Qi Witness: B.Rochin ProActive Diagnostic Services, Iile. ! P.O. Box 1369, Stafford, TX ì7497 Phone: (281) or (888) 565-9085 Fax: (281) 565-1369 E-mail: PDS@memorylog.com Prudhoe Bay Field Office Phone: (907) 659-2307 Fax: (907) 659-2314 U-:I. c.. Qo"3 -( S1r tt tS""33 ~ I Tree Swab Valve Flow Cross I I Surface Valve I I Master Valve I 4-1/2" Tubing I u Detail of Across the 5 KSI Tree I I I I Well: Field: Company: Country: I I I 9 19 29 39 49 56 66 76 (¡¡ 86 ..c E 96 :::J Z ;:: 106 :2. 116 123 133 143 153 163 173 183 193 I I I I I I I I I I I NS-32 N orthstar BP Exploration (Alaska), Ine. USA Overlay o Max. Roc. Pen. (mils) 100 200 Maximum Recorded Survey Date: Prev, Date: Tool: Tubing: July 16, 2007 August 4, 2006 MFC 40 No. 99493 4.5" 12.6 It L-80 IBT-M Dlft in Max. Pen. (mils) -25 50 75 o 25 .8 E :::J Z ;:: :2. -26 0 26 53 79 Approx, Corrosion Rate (mpy) I Damage to Borehole Pipe 1 4.5 in (25.2' - 8100.1') Well: Field: Survey NS-32 Northstar SP Exploration (Alaska), !ne. USA July 16, 2007 I I Approx. Tool Deviation Approx. Borehole Profile 75 25 I 25 1030 I 50 2066 I 3123 I .... 100 4142 () ...Q Lt E :;:¡ c z I .,., c § 125 5194 I 150 6221 175 7256 8100 100 I 194.4 o 50 I Profile (% wall) I Too! Deviation I I Bottom of Su rvey = 194.4 I Wen: Field: Company: Country: NS-32 Northstar BP Exploration (Alaska), Inc. USA Tubing: Nom.OD 4.5 ins Weight 12.6 f Grade & Thread L-80 iBT-M Penetration and Metal loss (% wall) penetration body metal loss body 200 150 100 50 0 o to 1% 1 to 10% 10 to 20 to 40 to over 20% 40% 85"1" 85% I o o Damage Configuration ( body) 10 I I o isolated genera! line ring hole / poss pitting corrosion corrosÎon corrosion ible hole I o PDS Report Overvi Region Analysis Survey Date: Tool Type: Tool Size: No. of Fingers: Anal st: Nom.lD 3.958 ins July 16, 2007 MFC 40 No, 99493 2.75 40 B. Nom. Upset 4.5 ins Upper len. 6.0 ins Damage Profile (% wall) penetration body o 1 metal loss body 50 49 97 145 Bottom of Survey = 194.4 194 Analysis Overview page 2 Lower len. 6.0 ios 100 I JOINT TABULATION SH I Pipe: Body WaJ!: Upset Wall: Nominal I.D.: 4.5 in 12.6 ppf l-80 IBT-M 0.271 in 0.271 in 3.958 in Well: field: Company: Country: Survey Date: N5-32 Norlhstar BP Exploration (Alaska), Inc. USA July 16, 2007 I I I Joint Jt. Depth Pen. Pen. Pen, Melfll Min. .",,,,, No. LD. Comments ("/0 (Ins.) (Ins.) (Ins.) 0 50 100 1 25 1 3.89 TIm 1.1 56 I 3.90 PUP 1.2 64 3.91 PUP 2 73 =it 3 112 0.02 1 4 154 í om 5 ±=ill= 0.03 1 6 om 3.90 <::¡",Un\AJ nitlincr. 7 277 0.05 3.89 ShaJlow nitling:. R 318 9 ShaJlow oitlinQ:. 10 3.89 11 I 3.87 12 486 0 0.03 13 1 I 3.89 Shallow oitlim:!.. 13 h:; 003~ 14 0.05 Shallow nitliml. 15 612 0.04 3.91 ShaJlow nitlil1Q. 16 653 OJB 10 1 3.90 17 695 0.03 *+1 3.89 18 737 0.03 3.90 19 779 0.01 3.90 20 821 0.03 II 3 i 21 862 1 Shallow nitûnQ. 22 ~ I 23 Shallow nitlin\!. 24 988 1 Pi 25 1030 J 1 3.91 26 1072 0 I 3.91 27 1112 3.91 Isolated nittin2" 28 1153 3.89 29 1195 3.90 30 1236 3.91 31 1278 3.89 32 1319 0, ì3 4 3.91 Lt. Deoosits. 33 1361 3.83 It. Denru;Ìts. m2 3.82 Lt. Denosits. 5 444 { 3.88 36 485 { 0.01 \3 3.87 37 7 { 0.02 6 3.89 38 1569 { ! .5 3.89 39 1610 { 3.88 40 1652 I 3.88 41 1695 0.02 I 3.87 42 1737 0.01 1 3.87 43 1778 0.01 I 3,88 44 1818 0.02 :1 3.85 45 1858 0.02 1 3.88 46 1900 0 0.01 I 3.89 47 1942 0 0.01 I 3.88 48 1983 0 0.01 1 3.88 I I I I I I I I I I I I I I Body Metal loss Body Page 1 I PDS JOINT TABU LA TION Pipe: Body Wall: UpsetWaH: Nominal 1.0.: 4.5 in 12.6 ppf l-80 IBT-M 0.271 in 0.271 in 3.958 in Well: fie!d: NS-32 Northstar BP Exploration (Alaska), rnc. USA July 16, 2007 Country: Survey Date: Joint Jt. Depth Pen. Pen. Pen. 1",,1etnl Min. r No. (Ft.) \(::~:f) t Body !.D. Commenls ¡,,;~ .,;;''''~ (Ins.) (Ins. ) 10 \ ,<> vv""'1100 2025 0.01 4 3.89 t I 50 2066 :1 3.85 I 51 2107 t 3.88 51.1 2149 0.02 3.88 PUP IItI 51.2 2159 n 0 t 3.81 X NIP 51.3 2160 0 0.01 3.87 PUP 52 2170 n 3.85 . 3.87 2 'tAl 55 4 () 'UI? 56 n 3.84 57 2377 () 3.81 Lt f)pnn<:ils. 58 , 2419 0.03 11M, U. ne""",ils. 59 2460 3.81 ¡ t Denosils. 60 2502 t I t. Denosils. 61 2544 ( 62 2585 ( T 3.90 63 2626 ( t 3.87 64 2668 ( 0.02 7 I 3.82 Lt. Deoosils. 65 2709 ( Dc:: 389 66 2751 ( 3.90 67 2792 ( 3.93 II 68 2834 3.91 ± 2A76 3.91 291R 3.90 71 2960 om 3.91 72 3001 om I 1R"i 73 3041 0.02 m ,Q, 74 3082 0.02 3.92 . 75 3123 0.02 76 3161) 0.02 73, ) 77 3204 0.02 3. ) 78 3246 0.02 ¡ 1 :¡ 79 3286 0.02 I 3.( 80 3323 0.01 3.91 81 3364 0.01 ( =m 82 3405 0.01 83 3445 0.02 84 3486 0.02 85 3528 0.02 11 3.91 86 3568 0.01 I 7 3.88 87 3608 0.02 1 3.91 88 3649 0.02 3.91 89 3690 0.01 3.88 90 3732 001 3.90 91 3773 0.02 I 3.88 II 92 3813 ti= I ,gO 93 3853 3.90 II! CJ4 3A95 3.89 III! 95 3935 0.01 3.90 II! 2 I I PDS REPORT JOINT TABULATION SHEET Pipe: Body Wall; Upset Wall: Nominal I.D.: 4.5 in 12.6 ppf L-80 IBT-M 0.271 in 0.271 in 3.958 in Well: Field: Company; NS-32 Norlhstar BP Exploration (Alaska), Inc. USA July 16, 2007 Survey I I I Joint Jt. Depth Pen, Pen. Pen, ¡'oAelal Min. Profile No. (Ins.;' Body 1.0. Comments ('Yo wall) (Ins.) (Ins.) 0 50 100 96 3976 97 4017 98 4060 3j:¡9 99 4100 II 101 4183 102 4266 = t !) 103 om (, I" 104 4308 ~ II 105 4350 ! 3.90 106 4392 0.02 I 3.91 107 4433 002 3.90 ~ 3.91 3.90 11 0 4555 ~ - ~1 111 4596 - 7 89 112 4635 I 3.91 113 4676 3.R7 114 3.91 115 4756 0.02 3.91 116 4797 I 0.02 3.90 117 4839 0.02 j 3.91 I" 1'!8 4881 002 ¡ 3.91 'II 119 4923 0.02 I 3.90 I" DO 4964 0.02 3.QO 'II 121 5006 0.02 3.91 'II 122 5047 +=±;= 3.89 I" 122.1 5088 3.91 PUP I" 122.2 5098 j N/A PACKER 122.3 5102 0 om I 3.93 PUP 123 51P I om 2 3.90 124 5153 I om j 3.91 125 5194 I om 3.93 126 5234 0.02 3.91 127 5277 0.02 3.91 128 5319 0 " "'., 3.90 IiI1 129 5360 0 0.ü2 3.89 IiI1 130 5399 0 0.02 j 3.88 II 131 5440 0.02 ! 3.92 II 132 !JAil2 i 1 3.90 III 133 ,),}22 ¡ 3.92 Iii 134 5564 ¡ 3.89 Iii 135 5605 I 3.88 136 5646 0.02 2 ~ ~ 137 'i¡:;R7 ~ I 138 5728 , 139 5769 3.90 140 5809 0.û1 f¡ 141 5849 0.02 142 5890 0 0.01 4. I I I I Body Body 3 I I PDS JOINT ON Pipe: Body Wall: Upset WaD: Nominal J.D.: 4.5 in 12.6 ppf L-80 IST-M 0.271 in 0.271 in 3.958 in Well: Field: Company: Country: Survey Date: NS- 32 Northstar SP (Alaska), Inc. USA July 16, 2007 I I joint jt Depth Pen, Pen. Pen. Melal Min. -v Profile No. (Ft.) 'I Body I.D. Comments wall) (Ins,) (Ins. ) (Ins.) 0 SO 100 143 'i931 \) 0.02 ¡ 3.90 144 'iCJ7i \) 0.02 ¡ 3.91 45 6015 \) :1 0.0: 3.91 4h 6056 \) 3.90 47 ! 6097 \) 3.89 148 6138 fl I 0.01 3.91 149 6179 I 0.02 ¡ ,~ 150 6221 I 0.02 1 'il 6262 ¡ 0.02 152 6303 0.01 153 6344 0,02 I 3.90 154 ~ . 3.91 155 3.91 156 3.90 157 3,89 158 6553 3.86 159 6594 om 2 3.89 160 6635 ¡ 0.02 3.90 ~ 6676 I 0.02 3.91 6717 ( 0.02 3.92 163 6759 ¡ ).02 3.88 164 6800 0 ).02 3.91 165 684-1 ( 1m 3.91 blli= 6883 I 102 3.89 6924 0.02 31:11 6964 0.02 3.90 169 7006 0.Q2 3.90 170 7047 3.86 171 7089 gil 390 172 7131 3.B8 173 7173 3.89 174 7215 0.02 =H! 175 725fi 0.02 176 7296 0.02 177 7337 0.02 3.90 178 7379 0.01 3.90 179 7421 0.Q2 ~~ 180 7461 ~ 2 3 181 7502 2 3. 8 182 7543 2 3.90 183 7585 ,3.90 184- 7627 0.D1 E;= 185 7668 0.02 186 7709 0 0.02 187 7751 0.02 I 188 7789 0.02 3.90 189 7 131 ~ 3.85 190 7 172 3.88 191 7 14 3.89 192 7956 ( 3.89 I I I I I I I I Body Loss Body 4 JOINT PDS Wall: Upset Wall: NominaII.D.: 4.5 in 12.6 ppf L-80 IBT·M 0.271 in 0.271 in 3.958 in We!!: field: Company: Country: Survey Date: Joint No. I I I I Page 5 LATION SH NS-32 Norlhstar BP Exploration (Alaska), Inc. USA July 16, 2007 Comments Profile Body Body - - - - - - Well: Field: Company: Country: Tubin : - - NS-32 Northstar BP Exploration (Alaska), Inc. USA 4.5 ins 12.6 f l-80 IBT-M Tool = 71 Nominal ID = 3.958 Nominal OD = 4.500 Remaining wall area 99 % Tool deviation = 40 0 - - - - - - - PDS Repo S ons Survey Date: Tool Type: Tool Size: No. of Fingers: Anal st: July 16, 2007 MfC 40 No. 99493 2.75 40 B. i 111 7ft Finger 30 Penetration = 0.057 ins Isolated Pitting .06 ins 21 % Wall Penetration HIGH SIDE = UP Cross - - - - I I I I I I TREE = ABB-VGI 5-1/8" . ~NOTES: HANGER = 4" BPVnwC I W8..LHEAD = ABB-VGI11" MULTIBOWL 5 ACTUATOR = KB. B..EV = 55.95" BF. 8..EV = 40.05' (CB 15.9' NS32 KOP= Max Angle = Datum MJ = Datum ND = .. 120" CONDUCTOR, 169#, X-56 I 200' r ,I 2097' HEAT TRACE, STARTING AT?? 1 I · 1 2169' 144-1/2" X NP, D - 3.813" I · 110-3/4" CSG, 45.5#, L-80 BTC, ID = 9.95"? I 3964' 1--4 ... Minimum ID = 3.725" @ 8088' rg ......... 7-5/8" X 4-1/2" BKR 8-3 A<R, ID = 3.875" I ~ 5102' 4-1/2" XN NIPPLE ~ 1\ . · 8Q88' 4-112" HES XN NIP, ID = 3.725" I · ,~ 4-1/2" TBG, 12.6#, L-80 IBT-M, .0152 bpf, ID = 3.958" 81 00' J.... L.---1. 8100'\. H4-1/2"WLEG, D=?,???" I 17-518" CSG, 29.7#, L-80 BTC, ID = 6.875"? 8107 ~ ", \- ... 1 M ELMO TT NOTLOGGBJ? I ) ) I I 16-3/4" ÜP8\I HOLETD H 8321' ~ ) DATE REV BY COl'vtli1ENT8 DATE REV BY COMrvENTS NORfHSTAR 12/14/03 INITIAL DRILL WB..L: NS32 05/02104 JAS ORIGINAL COMPLETION ÆRMIT No: '"2031580 11/11/05 TLH NEW FORMAT Apt No: 50-029-23179-00 BP Exploration (Alaska) I I I I I I I I I I I I I . . STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Email to:Winton_Aubert@admin.state.ak.us;Bob_Fleckenstein@admin.state.ak.us;Jim_Regg@admin.state.ak.us;Tom_Maunder@admin.state.ak.us OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: BP Exploration (Alaska), Inc. Northstar / NS / NS 04/13/07 Anna Dube ;¡P3-ISß Packer Depth Pretest Initial 15Min. 30 Min. WelllNS32 I Type Inj. I W TVD I 4,070' Tubing 1860 1899 1844 1825 Interval I 0 p.T.D.12031580 I Type test I P Test psil 1500 Casing 70 3599 3552 3564 P/FI P Notes: EPA witnessed annual MIT-IA for regulatory OAO 0 0 0 compliance. Weill I Type Inj. I TVD I Tubing Interval! P.T.D.I I Type test I Test psil Casing I P/FI Notes: OA I Weill I Type Inj.1 I TVD I Tubing Interval \ P.T.D.I I Type test I I Test psi! Casing P/F Notes: OA Weill I Type Inj.1 I TVD Tubing I Interval I P.T.D.I I Type test I I Test psi I Casing I P/F Notes: OA \ Weill I Type Inj. I TVD I Tubing Interval I P.TD.I I Type testl I Test psil Casing P/F\ Notes: OA TYPE INJ Codes D = Drilling Waste G=Gas I = Industrial Wastewater N = Not Injecting W = Water MIT Report Form BFL 9/1/05 TYPE TEST Codes M = Annulus Monitoring p = Standard Pressure Test R = Internal Radioactive Tracer Survey A = Temperature Anomaly Survey D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance T = Test during Workover 0= Other (describe in notes) s(;ANNED APR 1 9 2007 MIT NS NS32 04-13-07.xls RE: NS 17 (PTD #2021690) 4-year MITIA for Regulatory Compliance ./ . ~ .).C'!. - ~S<6 The MITs on NS10 and NS32 are just the normal IA pressure tests. Talib is flying to the slope on 4/10. His schedule is to go to Milne Point on 4/11 (MPB-50), Badami on 4/12 (B1-01) and then to head out to North Star on the morning of 4/13 (NS10 and 32). It should.n.ot...~.~n.is.sue.);:.Ç? perform the work on NS17 after the other two wells are complete. Tom, Let me know if I can assist you further. Thanks, Andrea Hughes $~E[) MAR 2; 9 2007 -----Original Message----- From: Thomas Maunder [mailto:tom maunder@admin.state.ak.us] Sent: Thursday, March 29, 2007 9:58 AM To: NSU, ADW Well Integrity Engineer . Subj ect: Re: NS17 (PTD #2021690) 4 -year MITIAfÒ~ ¡(egulaëõry~'CõWlPfiã1ic'ë: Andrea, Further to your request. Is there to be considerable work on NS32 for the MITs or is it just the normal IA pressure test? have a possible schedule of the work? Thanks, Tom NS10 and Do you NSU, ADW Well Integrity Engineer wrote, On 3/29/2007 9:42 AM: Jim and Tom, Currently we are performing coil tubing work on several wells at North Star. Not only does this cause congestion on the island, but it also has tied up the pump truck for several days. An MITIA on NS17 is due on 4/4/07 but we are proposing that we piggy back this work with the MITs for NS10 and NS32 the following week. Is it okay to leave NS17 on injection and perform the MITIA on the same day as the MITs on NS10 and NS32 (scheduled for 4/13 with the EPA)? Thank you, *Andrea Hughes* Well Integrity Coordinator Office: (907) 659-5102 Pager: (907) 659-5100 xl154 1 of I 3/29/2007 10:25 AM bp . al!.ate: 12-14-2006 W'ltansmittal Number:92868 BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. If you have any questions, please contact me in the PDC at 564-4091. xc. ~3 :¡: ~ SW Name Date Contractor LOQ Run T OD Depth Bottom Depth LOQ Type :r~ WATERFLOW INJECTION - J5'?) NS32 08-08-2006 SCH LOG VISION RESISTIVITY C- NS25PB1 01-10-2004 SCH MEASURE DEPTH í3 -( fa'" VISION RESISTIVITY TRUE NS25PB1 01-10-2004 SCH VERTICAL DEPTH c.. VISION RESISTIVITY NS25PB2 01-25-2004 SCH MEASURE DEPTH i3 -/(,(.. VISION RESISTIVITY TRUE NS25PB2 01-25-2004 SCH VERTICAL DEPTH Il..{é?!(.. -( fo~ NS25PB1 01-10-2004 SCH LWDG TIF/PDS DISPLAY CD ---:: c.- I'td'l6 3-fU, NS25PB2 01-25-2004 SCH LWDG TIF/PDS DISPLAY CD (; 03 >¡. '6 :¡: o e ,1L JßJz(i~hM~ /HLl¿"V~'~ Please Sign and Re one copy of this transmittal. Thank You, Andy Farmer Petrotechnical Data Center :~ç4~!i~ft: "') ¡ 'j ,J Attn: Doug Chromanski Howard Okland Tim Ryherd Ignacio Herrera Cheryl Ploegstra (no CD's) U/~ d0"3-{6--~ Petrotechnical Data Center LR2-1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519-6612 --~ ',,-,,' ~8TA~ (.) ~I. PR~cf!' UNITED STATES ENVIRONMENTAL PROTECTION AGENCY REGION 10 1200 Sixth Avenue Seattle, WA 981 01 OCT - 6 20C6 Reply To Attn Of: aCE 127 CERTIFIED MAIL - RETURN RECEIPT REQUESTED Craig L. Wiggs Northstar Perfonnance Unit Leader BP Exploration (Alaska) Inc.(BPXA) 900 East Benson Boulevard --., O.('\T 5\ 1 2005 P.O. Box 196612 SCANNED ¡v" g.b -. Anchorage, Alaska 99519-6612 d.p3"' 15'6 Re: Mechanical Integrity Test, UIC Class I Well Northstar NS-32, Pennit No. AK-1I002-A Dear Mr. Wiggs: The United States Environmental Protection Agency (EP A) RegÏon 10 is in receipt of the annual mechanical integrity test (MIT) results conducted on BPXA's Northstar NS-32 well. This annular testing perfonned on August 8, 2006, fulfills the requirements under the underground injection control (UIC) pennit number AK-1I002-A. We concur with the test results that the Northstar NS-32 well has successfully demonstrated external mechanical integrity based on the Water Flow Log (WFL) and Caliper Log surveys results. If you have any questions or need more infonnation, please call Thor Cutler at (206) 553-1673. sv "- Michael A. Bussell, Director Office of Compliance and Enforcement cc: John Nonnan, AOGCC, Anchorage Shannon Stambaugh, ADEC, Anchorage Anita Frankel, EP A, Seattle Marcia Combes, EP A, Anchorage bp -- . Date: 09-28-2006 Transmittal Number:9283I BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. If you have any questions, please contact me in the PDC at 564-4091. SW Name Date Contractor Lo De th Bottom De th Lo T e MULTI-FINGER CALIPER LOG NS10 08-02-2006 PDS RESUL TS SUMMARY MULTI-FINGER CALIPER LOG 08-04-2006 PDS RESUL TS SUMMARY MULTI-FINGER CALIPER 3D 08-04-2006 PDS DATA VIEWER CD-ROM MULTI-FINGER CALIPER 3D 08-04-2006 PDS DATA VIEWER CD-ROM / f/z r ì6/l lit e fJ1a h '4 ~PÆ'I I Please Sign and Return one copy of this transmittal. Thank You, Andy Farmer Petrotechnical Data Center elL RECEIVED SEP 2 9 2006 ~ on & Gas Cons. eommission Anchorage Attn: Howard Okland Doug Chromanski Kristin Dirks Ignacio Herrera '-·(·~~!N}·~1 : ~.) '-.,)I!.J \,:,,; ~," '"10".....,... f~ ¿.?~ 2DOe :;)úó -/1$';) '*" 1'-1 I 1./ (0 f}66 -/5'15' tt- / t. / J ~/ 7- Petrotechnical Data Center LR2-] 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519-6612 I I I I I I I I I I I I I I I I I I I . . Memory Multi-Finger Caliper Log Results Summary Company: Log Date: Log No. : Run No.: Pipe1 Desc.: Pipe1 Use: BP Exploration (Alaska), Inc. August 4, 2006 7089 3 4.5" 12.6 lb. L-80 IBT-M Tubing NS-32 I WD..o2 Northstar Alaska 50-029-23179-00 Suñace 8,103Ft. (MD) Well: Field: State: API No.: Top Log Intv/1.: Bot. Log Intv/1.: Inspection Type: COMMENTS: Co"osion Monitoring Inspection This log is tied into the WLEG @ 8,100' (ELMD). This Jog was run to assess the condition of the tubing with respect to changes in corrosive and mechanical damage. This is the third time a PDS caliper has been run on this well. The caliper recordings indicate that the 4.5" tubing is in good condition with respect to corrosive damage. No significant wall penetrations or areas of cross-sectional wall loss are recorded. Deposits restrict the 1.0. to 3.63" in joint 48 (2,023'). A comparison between the current log and the previous log run on this well (May 14, 2005) indicates no increase in corrosive damage. The distribution of maximum recorded penetrations is illustrated in the Body Region Analysis Page of this report. MAXIMUM RECORDED WALL PENETRATIONS: No significant wall penetrations (> 9%) are recorded. MAXIMUM RECORDED CROSS-SECTIONAL METAL LOSS: No significant areas of cross-sectional wall loss (> 7%) are recorded. MAXIMUM RECORDED ID RESTRICTIONS: Deposits Minimum 1.0. = 3.63" 48 2,023 Ft. (MD) Jt. @ No other significant 1.0. restrictions are recorded. I Field Engineer: W McCrossan Analyst: M. Lawrence Witness: B. Rochin PC 1369. Stafford, 77497 RECEIVED 565-1369 E-mail: PDS(Ö)mernoryloç¡,co Phone: 659,,2307 Fa';<: (907) 659-2314 ure. {)O":3 -IS-~ %f f4/~/1- SEP 2 9 2006 .I\Iaska 011 & Gas eons. CommisSion Anchorage I I I I Well: Field: Company: Country: I I I 9 19 29 39 49 56 66 76 .. 36 CI ..Q e 96 ::: Z .... ::: 106 .5 116 123 133 143 153 163 173 133 193 I I I I I I I I I NS-32 N orthstar 8P Exploration (Alaska), I nc. USA Overlay o Max. Ree. Pen. (mils) 50 100 150 200 250 [II August 4, 2006 II May 14, 2005 I I I - Maximum Recorded Penetration Comparison To Previous Survey Date: Prevo Date: Tool: Tubing: -50 .. CI ..Q E ::: Z .... ::: ]. -41 August 4, 2006 May 14, 2005 MFC 40 No. 030307 4.5" 12.6 Ib L-80 Difference Diff. in Max. Pen. (mils) -25 o 25 o Appl'Ox. CorrosiOll Rate (mpy) 50 41 I I I Well: Field: Company: Country: NS-32 Northstar BP Exploration (Alaska), Inc. USA I Tubing: Nom.OD 4.5 ins Weight 12.6 f Grade & Thread L-80 I Penetration and Metallo!>!> (% wall) I penetra tion body metal loss body 200 150 100 50 0 o to 1% 10 to 20 to 40 to over 20% 40% 85% 85°1<, I I 1 to 10% I I I Damage Configuration ( body) I I o I isolated general line ring hole / poss píttíng corrosion corrosion corrosion ¡hie hole I I I o o o PDS Report Overview ody Region Analysis Survey Date: Tool Type: Tool Size: No. of Fingers: Anal sl: Nom.ID 3.958 ins August 4, 2006 MFC 40 No. 030807 2.75 40 M. Lawrence Nom. Upset 4.5 ins Upper len. 12 ins Damage Profile (% wall) penetration body o 1 metal loss body 50 49 97 145 194 Bottom of Survey = 194.4 Analysis Overview page 2 I I Lower len. 1.2 ins 100 I I I I I I I I I I I I I I I I I I I PDS REPORT JOINT TABULATION SHEET Pipe: Body Wall: Upset Wall: Nominal I.D.: 4.5 in 12.6 ppf L-80 0.271 in 0.271 in 3.958 in Well: Field: Company: Country: Survey Date: NS-32 Northstar BP Exploration (Alaska), Inc. USA August 4, 2006 Joint Jt. Depth Pe, Pen. Per! I ¡\-Ielal Min. Damage Profile No. (Ft) \::1':';1 Body 1.0. Comments (%wall) (Ins.) (Ins.) 0 50 100 1 24 0 0.01 f 3.89 Ii! 1.1 54 0.01 11 3.91 PUP I 1.2 62 I 0.01 3.90 PUP ~ 2 72 ! 0.01 I 3.89 3 110 0.01 4 I 3.90 4 152 0 0.02 7 3 3.92 IIIí ¡ 5 194 I) 0.00 I 3.90 6 233 n 0.01 ;; 3.90 7 276 0 0.01 ¡ 3.90 8 317 0 0.01 i 3.90 9 359 0 0.02 I ¡ 3.89 10 401 0 0.01 ¡ 3.91 11 443 0 0.01 4. 1 3.90 12 485 0 0.01 ¡ 3.89 13 526 0 0.02 1 3.89 III 14 568 n 0.ü2 1 3.89 II 15 610 Ii 0.01 1 3.91 16 652 11 0.00 3.90 17 694 0 0.01 1 3.90 18 736 0 0.01 4 ) 3.91 19 778 0 0.01 .¡ 3.91 ! 20 820 Ö 0.ü2 3.89 III 21 861 0.01 3.91 22 903 0.02 3.92 III 23 945 0.01 1.90 III 24 987 0.01 3.90 25 1029 I 0.01 ¡ 3.91 26 1071 ( 0.00 1 ¡ 3.90 27 1111 ! 0.01 1. 2 3.91 28 1152 0 0.01 ¿ ) 3.90 29 1193 0 0.01 1 3.91 j 30 1234 n 0.01 ¡ 3.91 31 1277 ( 0.01 i 3.91 32 1318 ( 0.01 2 3.91 33 1359 0 0.01 1 3.91 34 1401 ( 0.01 1 3.91 35 1443 n 0.01 ¡ 3.91 36 1484 0.01 3.92 37 1525 0.01 1 3.92 38 1567 0.01 I 3.92 39 1609 ( 0.02 ~¡ 3.90 III 40 1651 0 0.01 4 1 3.89 , 41 1693 ( 0.01 3 I 3.89 42 1735 0 0.01 4 3.89 43 1777 1) 0.01 3.90 44 1816 (I 0.02 3.88 45 1856 ( 0.01 3.91 46 1898 I 0.01 ¡ :2 3.90 ~ 47 1940 I 0.01 5 4 3.81 Lt. Deoosits. III 48 1982 0.02 (; (; 3.63 Deoosits. Body Metal Loss Body Page 1 I PDS REPORT JOINT TABULATION SHEET I Pipe: Body Wall: Upset Wall: Nominal 1.0.: 4.5 in 12.6 ppf L-80 0.271 in 0.271 in 3.958 in Well: Field: Company: Country: Survey Date: NS-32 Northstar BP Exploration (Alaska), Inc. USA August 4, 2006 I I Joint Jt. Depth Pen. Pen. I ¡vlt·tal Min. Damag e Profile No. (Fl.) Body !.D. Comments (% wall) (Ins) (Ins.) (Ins.) 0 50 100 49 2023 () 0.02 i 3.79 Lt. fJenosits. ífIIì 50 2065 () 0.01 t 3.83 51 2106 () 0.01 I 3.90 " 51.1 2147 0.02 I 1 3.89 PUP III! 51.2 2157 0 0 3.81 X NIP PLE 51.3 2158 I 0.01 3.90 PUP 52 2168 0.02 3.89 53 2209 0.01 3.88 54 2250 I 0.02 ¡ 3.89 55 2292 () 0.01 ) 3.85 56 2334 () 0.01 il 3.82 57 2375 () 0.01 1 3.87 58 2417 () 0.01 4 ) 3.87 59 2459 () 0.01 4 ) 3.83 60 2501 0 0.02 7 3.91 61 2543 0 0.01 3.89 62 2584 0 0.01 ) 3.91 63 2624 0.01 1 3.91 64 2666 () 0.01 2 3.86 65 2707 0.00 ¡ ¡ 3.88 66 2749 I 0.01 4 )1 3.90 67 2790 ! 0.01 3 ) 3.91 68 2832 0.01 1 3.89 69 2874 n 0.01 1 3.91 70 2916 () 0.01 1 3.92 71 2958 I 0.01 I 3.90 72 2999 I 0.01 ) 3.91 73 3039 ( 0.01 1 3.89 74 3080 I 0.02 I 3.91 75 3122 c 0.01 I 3.89 76 3163 n 0.01 ;; 3.89 77 3202 I 0.01 1 3.90 78 3244 I 0.01 ! 3.88 ¡ 79 3284 0.01 4 2 3.88 80 3321 0.00 I 1 3.89 81 3362 0.02 6 t 3.91 82 34D3 0.01 1 3.89 83 3442 () 0.01 1 3.89 84 3484 () 0.02 3.91 85 3526 n 0.Q2 3.89 86 3566 n 0.01 3.89 87 3605 0 0.01 3.92 88 3647 n 0.02 6 3.89 89 3688 n 0.01 1 3.86 90 3730 0 0.02 I I 3.91 91 3771 C 0.01 I 3.89 92 3811 C 0.02 I ) 3.88 ífIIì 93 3851 n 0.01 ¡ 3.90 II 94 3893 0 0.02 B I 3.87 '" 95 3933 n 0.01 4 ) 3.91 I I I I I I I I I I I I I I Body Metal Loss Body Page 2 I I PDS REPORT JOINT TABULATION SH I Pipe: Body Wall: Upset Wall: Nominal 1.0.: 4.5 in 12.6 ppf 1.-80 0.271 in 0.271 in 3.958 in Well: Field: Company: Country: Survey Date: NS-32 Northstar BP Exploration (Alaska), tne. USA August 4, 2006 I I I Joint Jt. Depth Pen Pen. fiE:;;; "I/Ietal Min. Damag e Profile No. (Ft.) Body !.D. Comments (% wall) (Ins) (Ins. ) (Ins.) 0 50 100 96 3974 n 0.01 If t! 3.90 97 4014 0.02 7 ; 3.88 98 4058 0.01 ; 3.88 99 4099 0.02 3.92 100 4140 0.01 I 3.91 101 4181 0.01 I 3.90 102 4223 n 0.01 3.90 103 4264 n 0.01 3.86 104 4306 n 0.01 3.91 105 4348 n 0.01 3.89 106 4390 n 0.01 lli:±90 107 4431 n 0.01 ~ .90 \II 108 4471 n O.O? q ) 3.90 II 109 4512 0 0.01 2 3.89 110 4554 0 0.01 I 3.90 111 4595 n 0.01 1 3.91 112 4633 0.01 I 3.90 113 4674 0.01 I 3.87 114 4712 n 0.01 ) 3.92 115 4754 n 0.01 , ) 3.92 116 4796 n 0.01 ') 3.89 117 4838 n 0.01 I 3.90 118 4879 0.01 I 3.90 119 4921 0.01 4 ) 3.89 120 4962 0.01 S- 'I 3.91 121 5004 0.01 ~ ? 3.92 122 5045 0.01 4 3.89 122.1 5086 I 0.D2 I ; 3.90 PUP 122.2 5096 ( 0 0 N/A PACKER 122.3 5100 0 0.D1 3.92 PUP 123 5110 0 0.01 3.89 124 5150 0 0.D1 ¿¡- 3.91 125 5192 n 0.D1 ¿ 3.93 126 5233 n 0.01 , 2 3.91 127 5275 n 0.D1 2 3.90 128 5317 n 0.D1 3.91 129 5358 n 0.01 3,85 130 5397 0 0.00 3.86 131 5438 ( 0.D1 3.92 132 5480 0.00 1 3.89 133 5520 0.01 if 3.90 134 5562 0.D1 4 I 3.88 135 5602 I 0.D1 ) 3.89 136 5644 ( 0.01 2 3.90 137 5685 ( 0.02 'j 3.90 138 5726 0 0.02 I 3.87 139 5766 n 0.D1 ? 3.89 140 5807 0 0.D1 I 3.90 141 5847 0 0.D1 I 3.89 142 5888 0 0.01 I 3.89 I I I I I I I I I I I I I I Body Metal Loss Body Page 3 I PDS REPORT JOINT TABULATION SHEET I Pipe: BodyWal!: Upset Wall: Nominal 1.0.: 4.5 in 12.6 ppf l-80 0.271 in 0.271 in 3.958 in Well: Field: Company: Country: Survey Date: NS-32 Northstar BP Exploration (Alaska), Inc. USA August 4, 2006 I I I I Joint Jt. Depth p'c Pen. Perl, ;'vle1;JI Min. Damag e Profile No. (Ft.) '1 Body 1.0. Comments (% wall) (Ins,) (Ins.) (Ins.) 0 50 100 143 5929 n 0.01 ¿1 I 3.90 I 144 5971 ~ 3.90 145 6013 3.91 146 6054 0.01 3.90 147 6095 0.02 3.88 It. Denosits. 148 6136 0.ü1 3.89 149 6177 0 0.ü1 3.89 150 6219 0 0.01 3 2 3.89 151 6260 n 0.ü1 3 3.90 152 6302 n 0.02 1 3.90 153 6343 n 0.02 I 3.89 154 6385 n 0.D2 I 3.89 155 6426 () 0.02 1 3.90 156 6468 f 0.ü1 3 3.90 157 6510 0 0.ü1 5 3 3.91 158 6551 () 0.ü1 5 I 3.88 159 6593 n 0.ü1 4 2 3.91 160 6634 n Oiì1 4 3.91 161 6675 0 I 0.02 I 3.91 162 6716 0 I 0.ü1 2 3.91 163 6758 () 0.01 3 3.87 164 6799 () 0.ü1 4 2 3.93 165 6840 () 0.ü1 , 3.93 166 6882 0.ü1 2 3.89 167 6922 I O.ü1 1 3.91 168 6963 I 0.02 I I 3.93 tft¿ 7005 I 0.ü1 7 3.89 7046 () 0.01 I 3.89 171 7089 () 0.ü1 3.91 172 7131 () 0.01 4 3.88 173 7173 0 0.ü1 4 3.90 174 7214 0 0.02 7 3.91 175 72'15 I 0.00 1 I 3.87 176 7295 0.01 3 3.89 177 7337 0.01 2 3.92 178 7378 ¡ 0.ü1 1 3.90 179 7420 ( 0.ü1 2 3.90 180 7461 () 0.01 3 1 3.93 181 7501 0.D2 5 3.92 II 182 7542 0.ü1 1 3~ 183 7584 0.ü1 1 3. 184 7626 0.ü1 2 3. 185 7667 0.01 I 3.92 186 7708 () 0.ü1 4 ¡ 3.88 187 7750 0 0.01 4 3 3.88 188 7789 0 0.ü1 I 3.93 189 7830 0 0.ü1 " 3.88 , 190 7872 0 0.01 ¿I . 3.91 191 7913 0 0.01 3.91 192 7955 () 0.ü1 3.90 I I I I I I I I I I I I I Body Metal Loss Body Page 4 I I Pipe: Body Wall: UpsetWali: Nominal I.D.: I I I I I I I I I I I I I I I I I PDS REPORT JOINT TABULATION SH 4.5 in 12.6 ppf L-80 0.271 in 0.271 in 3.958 in Joint No. 193 194 194.1 194.2 194.3 1 94.4 Well: Field: Company: Country: Survey Date: Min. I.D. (Ins.) 3.90 3.90 3.93 3.73 3.90 3.90 PUP XN NIPPLE PUP WLEG Page 5 NS-32 Northstar BP Exploration (Alaska), Inc. USA August 4, 2006 Comments Damage Profile (%wall) o 50 100 Body Metal Loss Body ------ ------- - - -- - - PDS Report Cross Sections Well: Field: Company: Country: Tubin : NS·32 Northstar BP Exploration (Alaska), Inc USA 4.5 ins 12.6 f L-80 Survey Date: Tool Type: Tool Size: No. of Fingers: Anal st: August 4, 2006 MFC 40 No. 030807 2.75 40 M. Lawrence Cross Section for Joint 48 at depth 2023.06 ft Tool speed = 68 NominallD 3.958 Nominal 00 = 4.500 Remaining wall area = 99 % Tool deviation = 38 0 Finger 5 Projection = -0.308 ins Deposits Minimum 1.0. = 3.63 ins HIGH SIDE = UP Cross Sections page 1 - I I I I I I TREE = ABB-VGI 5-1/8_ Lw:NOTES: HANGER = 4" BPVITWC WB..LHEAD = ABB-VGI11" MUL TIBOWL ACTUA TOR = KB. B..EV = 55.95" BF. B..EV = 40.05' (CB 15.9' NS32 KOP= Max Angle = Datum fill) = Datum ND = ~ 120" CONDUCTOR, 169#, X-56 I 200' r I 2097' HEA T TRACE, STARTING A Tn I - · I 2169' H4-1/2" X NP, 0 - 3.813" I · 110-3/4" CSG, 45.5#, L-80 BTC,ID '" 9.95"? I 3964' µ to. Minimum ID = 3.725" @ 8088' ~ 5102' 47-5/8" X 4-1/2" BKR S-3 A<:R. ID '" 3.875" I 4-1/2" XN NIPPLE ~ ~ I 1\ . · I 8Q88' 4-1/2" HES XN NIP, ID = 3.725" I · \ 4-1/2" TBG, 12.6#, L-80 IBT-M, .0152 bpf, ID = 3.958" 8100' J.... ---t 8100'\. -14-1/2" WLEG, 0 = ????" I " \.- 17-518" CSG, 29.7#, L-80 BTC, ID"' 6.875"? 8107' -¡...--...¡ ~ 1 HELMD IT NOT LOGGBJ? 1 } ) I 16-3/4" 0f'8\ HOLE TO H 8321' ~...... j DATE REV BY COI'vfv1ENTS DATE REV BY COMM3\JTS NORTHSTAR 12/14/03 INITIAL DRILL WB..L: NS32 05/02104 JAS ORIGINAL COMPLETION ÆRMIT No: "2031580 11/11/05 TLH NEW FORMAT API No: 50-029-23179-00 BP Exploration (Alaska) I I I I I I I I I I I I I e e Date: 07-05-2006 Transmittal Number:92794 USe.. bJ()3 ~ l5'i' BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. If you have any questions, please contact me in the PDC at 564-4091. SW Name Date Contractor LOQ Run Top Depth Bottom Depth LOQ T vpe RST W A TERFLOW NS32 07-27-2004 SCH 1 3836 8051 PRESSURE . RST W A TERFLOW - FLOW NS32 05-26-2005 SCH 1 3750 8040 MODE NS20 06-27 -2004 SCH 1 0 18495 PDC JEWELRY LOG NS32 05-14-2004 SCH 1 0 8131 JEWELRY LOG ,/ SLIM CEMENT MAPPING NS30 04-03-2006 SCH 1 50 16228 TOOL - VISION SERVICE - MEASURE NS14A 01-29-2006 SCH 1 10181 14230 DEPTH - VISION SERVICE - TRUE NS14A 01-29-2006 SCH 1 10181 14230 VERTICAL DEPTH ,/ VISION SERVICE - MEASURE NS30 03-17 -2006 SCH 1 200 16398 DEPTH VISION RESISTIVITY - ,/ MEASURE DEPTH WASH NS30 --- 03-17 -2006 SCH 1 16000 16318 DOWN ð VISION SERVICE - TRUE NS30 03-17-2006 SCH 1 200 16398 VERTICAL DEPTH ! NS11 05-29-2006 SCH 1 0 14669 PRIMARY DEPTH CONTROL --- NS14A 01-29-2006 SCH 1 305 1425 LDWG EDIT - CD ROM 4- NS30 03-17-2006 SCH 1 320 16379 LDWG EDIT - CD ROM 1 NS11 05-29-2006 SCH 1 7770 10470 LDWG EDIT - CD ROM !)C;$~ ~N~i) IP f¡::: ~' 1'5 ,., ..¡j;,tJ- ,_ d'_ ,k..'; JJ'l$ -""" JI),,' Petrotechnical Data Center LR2-1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519-6612 -- - BPXA WELL DATA TRANSMITTAL I I I I I Please Sign and Return one copy of this transmittal. Thank You, Andy Farmer Petrotechnical Data Center Attn: Doug Chromanski MMS Tim Ryherd DNR Howard Okland AOGCC Petrotechnical Data Center LR2-1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519-6612 Date: 07-05-2006 Transmittal Number:92794 J.... J~ ~ ~ DATA SUBMITTAL COMPLIANCE REPORT 5/25/2006 Permit to Drill 2031580 MD 8321'/ Well Name/No. NORTHSTAR UNIT NS-32 Operator BP EXPLORATION (ALASKA) INC 5,~ I r P. '" ÀC;)f)j API No. 50-029-23179-00-00 TVD 6684 ......--- Completion Date 5/2/2004 .-- Completion Status WDSP1 REQUIRED INFORMATION Mud Log No Samples No DATA INFORMATION Types Electric or Other Logs Run: MWD, GYRO, RES, AIT, DT\BHC, CNL, LDL, GR, CALIPER, SP, MR Well Log Information: Log/ Data Digital Type Med/Frmt ~ ;4 ~ ÆD C ~~ C Pds ~ C Pds Ä Log ~ )-Óg )..Og .)-og Log 1- .-æ- 0 ...Rpr' @Pt As.- Wid-- Mt Electr Dataset Number Name 1~Report: Final Well R Log Log Scale Media Run No Cement Evaluation 5 Col l). n ~- Report: Final Well R 12573 Gamma Ray 12574 Induction/Resistivity Sonic Gamma Ray Induction/Resistivity 5 Blu 25 Blu 25 Blu 2 2 Induction/Resistivity 25 Blu 2 Induction/Resistivity 25 Blu 2 Gamma Ray Directional Survey Directional Survey Corrosion 25 Blu Corrosion Current Status WDSP1 UIC Y Directional Survey Yes (data taken from Logs Portion of Master Well Data Maint Interval . OH/ Start Stop CH Received Comments 201 8321 Open 5/11/2004 Includes Color MD & TVD Mudlog 500 3858 Case 1/13/2004 Ultra Sonic Imaging Tool with DSLC Cement Bond Log 201 8321 Open 5/11/2004 Digital form of Report 154 8123 Open 4/19/2004 LDWG, MWD, USIT, GRAPHICS 19 April 2004 data replaced 28 Oct 2005 154 8123 Open 4/19/2004 AIT/PEXlGRlBHC/GRAPHI CS, USIT 3440 8028 Case 4/19/2004 USIT,GR,CCL,CTEM, 333 8121 Open 4/19/2004 ~ Replaced 28 Oct 2005 3963 8126 Open 4/19/2004 QUAD COMBO, RHOZ, . NPHI, DT 3963 8126 Open 4/19/2004 SSTVD, QUAD COMBO, RHOZ, NPHI, DT, 3963 8126 Open 4/19/2004 QUAD COMBO, RHOZ, NPHI, DT 333 8121 Open 4/19/2004 -¥Replaced 28 Oct 2005 0 8321 0 8321 0 8111 Case 7/16/2004 MEMORY MULTI-FINGER CALIPER LOG RESULTS SUMMARY 0 8105 Case 7/20/2005 Memory Multi-Finger Caliper Log results Summary DATA SUBMITTAL COMPLIANCE REPORT 5/25/2006 Permit to Drill 2031580 Well Name/No. NORTHSTAR UNIT NS-32 Operator BP EXPLORATION (ALASKA) INC API No. 50-029-23179-00-00 Z 8321 TVD 6684 Completion Date 5/2/2004 Completion Status WDSP1 Current Status WDSP1 UIC Y og Injection Profile 15 Blu 0 8321 Case 1 0/28/2005 Step Rate Injectivity Test w/RST-Waterflow Stop ~ Summary 15 May 2005 Gamma Ray 25 Blu 1 - 5 333 8121 Open 10/28/2005 Composite Gamma Ray Measured Depth Logs Composite Final Replacement Logs for 19 April Delivery ~ Gamma Ray 25 Blu 1 - 5 333 8121 Open 1 0/28/2005 Composite Gamma Ray . Measured Depth Logs Composite Final Replacement logs for 19 April 2005 delivery Well Cores/Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments ADDITIONAL INFORMATION Well Cored? Y ~ Chips Received? ~ Daily History Received? ~N @N Formation Tops Analysis Received? ~ Comments: . , J Compliance Reviewed By: ~ Date: ~/J~}..~ ~ · e STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COM MISSION Mechanical Integrity Test Email to:Winton_Aubert@admin.state.ak.us;Bob_Fleckenstein@admin.state.ak.us;Jim_Regg@admin.state.ak.us; Tom_Maunder@admin.state.ak.us.----¡ \ n ·lDLJ OPERATOR: BP Exploration (Alaska) Inc. \<ilf1 t\ It) . FIELD I UNIT I PAD: Prudhoe Bay I Northstar I Northstar DATE: 04/17/06 OPERATOR REP: Anna Dube AOGCC I EPA REP: Packer Depth Pretest Initial 15 Min. 30 Min. wellNS10 I Type Inj. 0 TVD I 4,023' Tubing 1500 1300 1250 1200 Interval 0 P.T.D. 2001820 Type test P Test psi 1,500 Casing 0 3500 3495 3520 P/F P Notes: Annual EPA witnessed MIT-IA to 3500 psi OA 0 0 0 0 wellNS32 I Type Inj. 1 TVD I 4,014' Tubing 1900 1900 1900 1900 Interval 0 P.T.D. 2031580 Type test P Test psi 1,500 Casing 0 3450 3350 3305 P/F P Notes: Annual EPA witnessed MIT-IA to 3500 psi OA 0 0 0 0 weill Type Inj. I TVD I Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA well Type Inj. I TVD I Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA weill Type Inj. I TVD I Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA TYPE INJ Codes D = Drilling Waste G = Gas I = Industrial Wastewater N = Not Injecting W = Water TYPE TEST Codes M = Annulus Monitoring P = Standard Pressure Test R = Internal Radioactive Tracer Survey A = Temperature Anomaly Survey D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance T = Test during Workover o = Other (describe in notes) MIT Report Form BFL 9/1/05 MIT NS NS-10, NS-32 04-17-06.xls . . Date: 10/25/2005 Transmittal Number:92706 BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. This data supersedes all previously delivered data. Please replace all previously delivered data listed below. If you have any questions, please contact me in the PDC at 564-4091 NS32 Date Contractor Log Run Top Depth Bottom Depth Log Type MEASURED DEPTH 04/29/2004 SCH 1-5 333 8121 COMPOSITE TRUE VERTICAL DEPTH 04/29/2004 SCH 1-5 333 8121 COMPOSITE SW Name NS32 NS32 04/29/2004 SCH 1 154 8322 CD ROM I ;(SI) 01 J, tl",t.. ,'h .....tJL.d, 1iJ ðML Please Sign and Return one copy of this transmittal. Thank You, Andy Farmer Petrotechnical Data Center Attn: Cheryl Ploegstra ACT Data Manager Jim Seccombe BPXA Howard Okland AOGCC Jason Smith Murphy Exploration Kristin Dirks DNR Doug ~~aµ~i, MMS ì\ i,,;: \. ..' " ... (Logs only) (Logs only) (Logs + CD) (Logs + CD) (Logs +CD) (Logs + CD) Petrotechnical Data Center LR2-1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519-6612 ;(\S ) -{'>4 h'/~- . . Date: 10-25-2005 Transmittal Number:92705 BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. This data is being sent separate because of the confidential nature. If you have any questions, please contact me in the PDC at 564-4091 SW Name Date Contractor Log Run Top Depth Bottom Depth Log Type NS21 01/15/2005 SCH 1 21950 22200 PERFORATING RECORD NS17 08/08/2004 SCH 1 17752 18255 PERFORATING RECORD NS31 02/05/2005 SCH 1 3000 10700 FREE POINT RECORD NS21 06/14/2004 SCH 1 22050 22242 PERFORATING RECORD STEP RATE INJECTIVITY NS32 05/15/2004SCH 1 0 8321 TEST WITH RST NS27 07/21/2004 SCH 1 0 11332 INJECTION PROFILE PERFORATION RECORD NS13 01/19/2005 SCH 1 11550 11858 WITH GAMMA RAY J/J oItL' Please Sign and Return one copy of this transmittal. Thank You, Andy Farmer Petrotechnical Data Center Attn: Jim Seccombe (BPXA) Attn: Cheryl Ploegstra (BPXA) Attn: Jason Smith (Murphy Exploration) Attn: Howard Okland (AOGCC) Attn: Kristin Dirks (DNR) Attn: Doug Choromanski (MMS) Petrotechnical Data Center LR2-1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519-6612 ;( I:J 1 - J )-8 Fe! IL . . Date: 07-20-2005 Transmittal Number: #91588NS10,08,32 bp BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. If you have any questions, please contact me in the Petrotechnical Data Center at (907) 564-4091 or by e-mailingtojohftsoih@bp.com Top SW Name Date Contractor Log Run Depth Bottom Depth Log Type rNS19 05-16-2005 PDS 1 13700 14080 PRESSURE BUILDUP; t.;t-¡Û7 NS19 05-16-2005 PDS 1 13700 14080 PRODUCTION PROFILE '- NS10 05-12-2005 PDS 5 0 8007 MEMORY MULTI-FINGER CALIPER ~t. ~- \ 8 ).. NS-08 05-12-2005 PDS 1 0 11374 MEMORY MULTI-FINGER CALIPER ,.',}. - \..;~ t , - h:,-l)-g NS- 05-14-2005 PDS 2 0 8105 MEMORY MULTI-FINGER CALIPER ,2/W 0-02 r /1 / ;' ."'\ i.. ~, j>// / /,: .'( I / .i~~i />ï):¡~ ;" '\/ t " ., please Sign and Return one copy of this transmittal. Thank You, James H. Johnson Petrotechnical Data Center Attn: Esther Fueg MB3-6 Attn: Ken Lemley MB3-6 Attn: Howard Okland (AOGCC) Attn: Jason Smith (Murphy Exploration Alaska), Inc Attn: Kristin Dirks (DNR) Attn: Doug Choromanski (MMS) ~ ~ Petrotechnical Data Center LR2-1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 995 19-6612 It' 'rC"it I Q J- c.~ - ) ~ t"' .. STATE OF ALASKA _ ALASt8rOIL AND GAS CONSERVATION CO~SION Mechanical Integrity Test Email to:Winton_Aubert@admin.state.ak.us;Bob_Fleckenstein@admin.state.ak.us;Jim_Regg@admin.state.ak.us OPERATOR: FIELD I UNIT I PAD: DATE: OPERATOR REP: AOGCC REP: BP Exploration (Alaska) Inc. Prudhoe Bay I NS I NS 04/21/05 Rob Mielke USEPA Talib Syed Packer Depth Pretest Initial 15 Min. 30 Min. wellNS-10 I Type Inj. 1 5 TVD I 4,023' TUbingl 1,1701 1,1501 1,1901 1,16°1 P.T.D. 2001820 Type test P Test psi 3,500 Casing VAC 3,520 3,440 3,430 Notes: EPA required annual pressure test. Witnessed by EPA representative Talib Syed. AOGCC represe!1!ative declined to witness test. WeIINS-32 TYfje Inj. I 5 I TVD I 4,014'1 TUbingl 1,8101 1,8001 1,8101 P.T.D. 2031580 Type test P Test psi 3,500 Casing 10 3,510 3,500 Notes: EPA required annual pressure test. Witnessed by EPA representative Talib Syed. AOGCC representative declined to witness test. weill I Type Inj. I TVD I P.T.D. Type test Test psi Notes: Interval P/F 1 P 1,7701Interval 3,540 P/F 1 P I TUb~ngl Casing Interval P/F weill Type Inj. I TVD I I TUb~ngl II nterval P.T.D. Type test Test psi Casing P/F Notes: weill Type Inj. I TVD I I TUb~ngl Interval P.T.D. Type test Test psi Casing P/F Notes: Test Details: TYPE INJ Codes F = Fresh Water Inj G = Gas Inj S = Salt Water Inj N = Not Injecting TYPE TEST Codes M = Annulus Monitoring P = Standard Pressure Test R = Internal Radioactive Tracer Survey A = Temperature Anomaly Survey D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance T = Test during Workover 0= other (describe in notes) Notes: If the test was not AOGCC witnessed, leave the "AOGCC REP:" box blank. MIT Report Form Revised: 06/19/02 2005-0421_MIT _Northstar_NS-32.xls Northstar NS-32 Class 1 Well Temporary Malfunction of Well Clea... This is a courtesy notification of the temporary malfunction on March 20 of the electronic flow meter which measures flow from the Northstar process facility well clean-out tank to the Northstar NS-32 Class 1 UIC well. The pumping down of the well clean-out tank to the Class 1 injection wells is set for manual activation by the Northstar Control Room Operators. On March 20, in anticipation of flow back fluids from a well workover to be received by the well clean-out tank, Northstar operators tested the clean-out tank meter that records the flow to be injected into NS-32. It was discovered that the meter was not functioning properly and injection was immediately shut-in from the tank. Maintenance was contacted and repair of the meter was carried out on March 20. Injection of the well clean-up tank contents including the flow back fluids was not carried out until the repair was completed. However, as part of the testing, trouble-shooting and repair of the meter, approximately 18 minutes of flow was injected that was not directly measured by the meter. Based on the well clean-out tank volume trending and 500 bbl/24hr injection rate, this would equate to about 10 bbls of flow that was not metered. Please give me a call if you have any questions on this courtesy notification. We will also address this issue in the Northstar Class 1 Wells UIC permit, first quarterly report for 2005. Regards, Pam Pamela Pope/Jim Short N* HSE Advisor 907-670-3507 pþ.1}n ~_t::?-~h.r:;¡"=0_ci..:!~_1?9~~l?E_:_.::::g!.T1 1 of 1 3/24/20058:16 AM · STATE OF ALASKA tit RECEIVED ALASKA 'JIL AND GAS CONSERVATION COMMISSION . WELL COMPLETION OR RECOMPLETION REPORT AND LOG AUG 1 6 2004 AI ¡,Rcwi.s,cLD8/1A/04, Start Injection aha UII ðtl:ias I.;ons. l.;ommfSon 1b. Well CléWfìChorage o Development 0 Exploratory o Stratigraphic ø Service 12. Permit to Drill Number 203-158 303-367 13. API Number 50- 029-23179-00-00 14. Well Name and Number: NS32i 15. Field / Pool(s): Northstar Unit ~ .. No. of Completions 1a. Well Status: 0 Oil 0 Gas 0 Plugged 0 Abandoned 0 Suspended 0 WAG 20AAC 25.105 20AAC 25.110 21. Logs Run: MWD , GYRO, RES, AIT , DnBHC , CNL , LDL , GR , CALIPER, SP , MRES CASING, LINER AND CEMENTING RECORD SettING OEP'I'AMOSET'tINGOEÞtHM \ToÞ BoTTOM BOTtOM Surface 201' Surface 201' 44' 3964' 44' 3253' 43' 8106' 43' 6499' o GINJ 0 WINJ ø WDSPL 2. Operator Name: BP Exploration (Alaska) Inc. 3. Address: P.O. Box 196612, Anchorage, Alaska 99519-6612 4a. Location of Well (Governmental Section): Surface: 1359' NSL, 649' WEL, SEC. 11, T13N, R13E, UM Top of Productive Horizon: 5111' NSL, 3541' WEL, SEC. 12, T13N, R13E, UM Total Depth: 5220' NSL, 3478' WEL, SEC. 12, T13N, R13E, UM 4b. Location of Well (State Base Plane Coordinates): Surface: x- 659821 y- _ 6031131 Zone- ASP4 TPI: x- 662125 y- 6034934 Zone- ASP4 Total Depth: x- 662186 y- 6035044 Zone- ASP4 18. Directional Survey 0 Yes ø No 22. 20" 169# 45.5# 29.7# X-56 L-80 L-80 10-314" 7-5/8" 23. Perforations open to Production (MD + TVD of Top and Bottom Interval, Size and Number; if none, state "none"): 6-3/4" Open Hole Completion MD TVD MD TVD 8106' - 8321' 6499' - 6684' 26. Date First Production: July 19, 2004 Date of Test Hours Tested PRODUCTION FOR TEST PERIOD .. Flow Tubing Casing Pressure CALCULATED ...... Press. 24-HoUR RATE7 One Other Class I Disposal Well 5. Date Comp., Susp., or Aband. 5/212004 6. Date Spudded 11/15/2003 7. Date T.D. Reached 4/29/2004 8. KB Elevation (ft): RKB = 55.90' 9. Plug Back Depth (MD+ TVD) 8321' + 6684' 10. Total Depth (MD+ TVD) 8321' + 6684' 11. Depth where SSSV set (Nipple) 2169' MD 19. Water depth, if offshore 39' MSL Ft Ft 16. Property Designation: Y0181 17. Land Use Permit: LO-N96-006 20. Thickness of Permafrost 1545' (Approx.) 20" Driven 13-1/2" 615 sx PF 'L', 400 sx Class 'G' 9-7/8" 1979sx Class 'G' SIZE 4-1/2", 12.6#, L-80 DEPTH SET (MD) 8100' PACKER SET (MD) 5102' DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED Freeze Protected with 68 Bbls of Diesel PRODUCTION TEST Method of Operation (Flowing, Gas Lift, etc.): Water Injection Oil-Bel GAs-McF WATER-Bel Oil-Bel GAs-McF WATER-Bel CHOKE SIZE I GAS-Oil RATIO Oil GRAVITY-API (CORR) 27. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary). Submit core chips; if none, state "none". None Form 10-407 Revised 12/2003 MJ6 t 7 ?nn~ RBDMS BFL OR\G'NAL CONTINUED ON REVERSE SIDE ,,~ e . 28. 29. GEOLOGIC MARKERS FORMATION TESTS Include and briefly summarize test results. List intervals tested, NAME MD rvD and attach detailed supporting data as necessary. If no tests were conducted, state "None". SV6 3758' 3104' None SV5 4125' 3371' SV4 4576' 3693' RECEIVED SV3 4906' 3929' AUG 1 62004 SV2 5143' 4100' Alaska Oil & Gas Cons. Commission SV1 5731' 4513' Anchorage TMBK 6241' 4876' UG3 6876' 5391' UG1 7423' 5884' WS2 7639' 6078' WS1 8065' 6462' 30, List of Attachments: 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed Title Technical Assistant NS32i Well Number Date Cß - l-<.liJ'-f Prepared By Name/Number: Sondra Stewman, 564-4750 Drilling Engineer: Bob Clump, 564-4672 203-158 303-367 Permit No. I Approval No. INSTRUCTIONS GENERAL: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. IrEM 1a: Classification of Service Wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. 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. IrEM 4b: TPI (Top of Producing Interval). IrEM 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. IrEM 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). IrEM 20: True vertical thickness. IrEM 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. IrEM 23: 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 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-In, or Other (explain). IrEM 27: If no cores taken, indicate "None", ITEM 29: List all test information. If none, state "None". Form 10-407 Revised 1212003 ORIGINAL Submit Original Only _ STATE OF ALASKA I ALAS~L AND GAS CONSERVATION COM~I ~SION~h WELL COMPLETION OR RECOMPLETION REPORT AND LOS' 1a. Well Status: 0 Oil 0 Gas 0 Plugged 0 Abandoned 0 Suspended 0 WAG 20AAC 25.105 20AAC 25.110 21. Logs Run: MWD , GYRO, RES, AIT , DnBHC , CNL , LDL , GR , CALIPER, SP , MRES CASING, LINER AND CEMENTING RECORD SEITIJ\/øDEf'l"HMD SEITING DEPTHTVD ',op BOTTOM Top BOTTOM Surface 201' Surface 201' 44' 3964' 44' 3253' 43' 8106' 43' 6499' o GINJ 0 WINJ aD WDSPL No. of Completions 2. Operator Name: BP Exploration (Alaska) Inc. 3. Address: P.O. Box 196612, Anchorage, Alaska 99519-6612 4a. Location of Well (Governmental Section): Surface: 1359' NSL, 649' WEL, SEC. 11, T13N, R13E, UM Top of Productive Horizon: 5111' NSL, 3541'WEL, SEC. 12, T13N, R13E, UM Total Depth: 5220' NSL, 3478' WEL, SEC. 12, T13N, R13E, UM 4b. Location of Well (State Base Plane Coordinates): Surface: x- 659821 y- 6031131 Zone- ASP4 TPI: x- 662125 y- 6034934 Zone- ASP4 Total Depth: x- 662186 Y- 6035044 Zone- ASP4 18. Directional Survey aD Yes 0 No 22. 20" WT. PER FT. 169# 45.5# 29.7# X-56 L-80 L-80 10-3/4" 7-518" 23. Perforations open to Production (MD + TVD of Top and Bottom Interval, Size and Number; if none, state "none"): 6-314" Open Hole Completion MD TVD MD TVD 8106' - 8321' 6499' - 6684' 26. Date First Production: Not on Injection Date of Test Hours Tested PRODUCTION FOR TEST PERIOD .. Flow Tubing Casing Pressure CALCULATED ....... Press. 24-HoUR RATE"'?' One Other Class I Disposal Well 5. Date Comp., Susp., or Aband. 5/2/2004 6. Date Spudded 11/15/2003 7. Date T.o. Reached 4/2912004 8. KB Elevation (ft): RKB = 55.90' 9. Plug Back Depth (MD+ TVD) 8321' + 6684' Ft 10. Total Depth (MD+TVD) 8321' + 6684' Ft 11. Depth where SSSV set (Nipple) 2169' MD 19. Water depth, if offshore 39' MSL 1þ,';II¥~~q.~f)S;. ; o Develo~¡nE:!~t[jË)q)lor~tory o StratigràphicreSf aD Service 12. Permit to Drill Number 203-158 303-367 13. API Number 50- 029-23179-00-00 14. Well Name and Number: NS32i 15. Field I Pool(s): Northstar Unit 16. Property Designation: Y0181 17. Land Use Permit: LO-N96-006 20. Thickness of Permafrost 1545' (Approx.) 20" Driven 13-1/2" 615 sx PF 'L', 400 sx Class 'G' 9-7/8" 1979 sx Class 'G' SIZE 4-1/2", 12.6#, L-80 DEPTH SET (MD) 8100' PACKER SET (MD) 5102' 25. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED Freeze Protected with 68 Bbls of Diesel PRODUCTION TEST Method of Operation (Flowing, Gas Lift, etc.): N/A Oll-Bsl GAs-McF WATER-Bsl CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary). Submit core chips; if none, state "none". 'J.f"ëõMç~'~,¥~ I .. "'¡;i;(M ¡ ;!~: Form 10-407 Revised 12/2003 Oll-Bsl 27. None GAs-McF WATER-Bsl CHOKE SIZE I GAS-Oil RATIO Oil GRAVITY-API (CORR) ORIGINAL AØJiS aft jUt 0 R 7"0\\ CONTINUED ON REVERSE SIDE e,ç G 28. e 29. e GEOLOGIC MARKERS FORMATION TESTS Include and briefly summarize test results. List intervals tested, NAME MD rvD and attach detailed supporting data as necessary. If no tests were conducted, state "None". SV6 3758' 3104' None SV5 4125' 3371' SV4 4576' 3693' SV3 4906' 3929' SV2 5143' 4100' SV1 5731' 4513' TMBK 6241' 4876' UG3 6876' 5391' UG1 7423' 5884' WS2 7639' 6078' WS1 8065' 6462' 30. List of Attachments: Summary of Daily Drilling Reports, Surveys, Wellbore Schematic and a Leak-off Test Summary 31. I hereby certify that the foregoin I Si ed true and correct to the best of my knowledge. Title Technical Assistant DateO~-Zq-c1 NS32i Well Number Prepared By Name/Number: Drilling Engineer: Sandra Stewman, 564-4750 Bob Clump, 564-4672 203-158 303-367 Permit No. I Approval No. INSTRUCTIONS GENERAL: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. ITEM 1a: Classification of Service Wells: Gas Injection, Water Injection, Water-Altemating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. 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 4b: TPI (Top of Producing Interval). ITEM 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. ITEM 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). ITEM 20: True vertical thickness. ITEM 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. ITEM 23: 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 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-In, or Other (explain). ITEM 27: If no cores taken, indicate "None". ITEM 29: List all test information. If none, state "None". Form 10-407 Revised 12/2003 Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: NS32 NS32 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 33E Start: 11/14/2003 Rig Release: Rig Number: 33E Spud Date: 11/15/2003 End: 11/14/2003 00:00 - 00:30 0.50 MOB P PRE - PJSM / ATP for skidding rig to NS-32 w/ rig & Ops personnel. - Released rig from NS-29 RWO @ 00:00 on 11-14-03 00:30 - 04:30 4.00 MOB P PRE - Prepare for skidding rig while Prod. continues bleeding down NS-31 to 0 psi. 04:30 - 06:00 1.50 MOB P PRE - Skid rig towards NS-32 - Moving back into area that was not leveled or brought up to grade with additional gravel this summer due to the rig being stacked out in this area during the summer. - Shimming over flow lines as rig is being moved. 06:00 - 07:00 1.00 MOB P PRE - Shut down rig move while Production personnel C/O. Rig crew to breakfast. - Renew permits 07:00 - 08:00 1.00 MOB P PRE - Skid rig over NS-32. - Accept rig @ 0800 hrs. 08:00 - 12:00 4.00 RIGU P PRE - Shim rig & clean up around NS-29. 12:00 - 20:00 8.00 RIGU P PRE - PJSM - R/U surface riser. (had to modify) - Install drain valves on conductor - Transfer fluid between L pits & pits. - Test lines - Continue mixing spud mud. 20:00 - 21 :30 1.50 RIGU P PRE - PJSM - slip & cut drilling line. 21 :30 - 22:00 0.50 RIGU P PRE - Install iron roughneck track. 22:00 - 22:30 0.50 RIGU P PRE - Calibrate Anadrill block height decoder. 22:30 - 00:00 1.50 RIGU P PRE - PJSM - P/U HWDP from pipeshed & M/U stands & rack back. 11/15/2003 00:00 - 01 :30 1.50 MOB P SURF - P/U HWDP, jars, & stand back in derrick. 01 :30 - 04:00 2.50 MOB P SURF - M/U BHA 04:00 - 05:30 1.50 MOB P SURF - PJSM - RIU Schlumberger for gyro surveys. 05:30 - 06:00 0.50 MOB P SURF - Pre spud meeting w/ Leigh's crew to discuss objectives of well & hazards of hole section. - Reviewed 0-7 drill (shallow gas w/o diverter) Complete items on pre spud list. 06:00 - 07:00 1.00 MOB P SURF - Fill riser w/ sea water - leaking @ drip pan. - Test mud lines to 3800 psi 07:00 - 07:30 0.50 MOB P SURF - B/D all lines 07:30 - 08:00 0.50 MOB N RREP SURF - Stand back BHA. 08:00 - 12:00 4.00 MOB N RREP SURF - PJSM - Drain riser & pull to reseal at drip pan. - Reinstall 12:00 - 13:30 1.50 MOB N RREP SURF - PJSM - Pull riser & remove gasket. Reinstall using sealant w/o gasket. 13:30 - 14:30 1.00 MOB P SURF - Pre spud meeting wI Wood's crew to discuss objectives of well & hazards of hole section. - Reviewed 0-7 drill (shallow gas w/o diverter) 14:30 - 16:00 1.50 DRILL P SURF - Clean out conductor & drill to 218'. 16:00 - 16:30 0.50 DRILL P SURF - Run gyro survey. - Survey at base of conductor indicates AZ of 31.79 deg, which lines up excellent with our proposed AZ of 32.59 deg. 16:30 - 17:30 1.00 DRILL P SURF - Continue drilling 13 1/2" hole to 334'. 17:30 - 18:30 1.00 DRILL P SURF - Condition mud & circulate for trip to change out BHA. 18:30 - 19:00 0.50 DRILL P SURF - POH & UD BHA #1. 19:00 - 20:30 1.50 DRILL P SURF - P/U BHA #2 & RIH. 20:30 - 21 :00 0.50 DRILL P SURF - Continue drilling 13 1/2" hole to 368'. - Pumping red mud sweeps prior to running gyros. 21 :00 - 22:00 1.00 DRILL P SURF - Run gyro survey. Printed: 5/3/2004 9:02:38 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: NS32 NS32 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 33E Start: 11/14/2003 Rig Release: Rig Number: 33E Spud Date: 11/15/2003 End: 11/15/2003 22:00 - 00:00 2.00 DRILL P SURF - Drill & slide from 368' to 728'. 11/16/2003 00:00 - 12:00 12.00 DRILL P SURF - Drill directional in 13 1/2" hole from 723' to 1855' MD. - Pumping red mud sweeps prior to gyros & as needed to aid in hole cleaning. 12:00 - 12:30 0.50 DRILL P SURF - Circulate sweep to prep for gyro. 12:30 - 13:30 1.00 DRILL P SURF - Run gyro & confirm MWD within JORPS. 13:30 - 14:30 1.00 DRILL P SURF - UD gyro & R/D Schlumberger. 14:30 - 00:00 9.50 DRILL P SURF - Drill directional in 131/2" hole from 1855' to 3221' MD. - Last survey Incl. 44.92 deg Az. 34.25 deg 11/17/2003 00:00 - 02:00 2.00 DRILL N RREP SURF Replace pin in pipe grapper on Top Drive. 02:00 - 09:00 7.00 DRILL P SURF Drill ahead in 13 1/2" hole to casing point @ 3,980 ft. 09:00 - 10:30 1.50 DRILL P SURF Sweep hole. Circ & cond mud for logs. 10:30 - 11 :00 0.50 DRILL P SURF Flow check well static. Blow down surface circ system 11 :00 - 19:30 8.50 DRILL P SURF POH w/13 1/2" bit. Work tight hole @ 2170 - 1948 ft. Pump thru 1735 - 1665 ft. Rack BHA in derrick. LD MWD. 19:30 - 20:00 0.50 DRILL P SURF PJSM w/ Schl e line crew 20:00 - 20:30 0.50 DRILL P SURF RU Schl e line, no pressure control equip. 20:30 - 23:00 2.50 DRILL P SURF Schl RIH w/ PEX logging suite. Unable to work past 1,770 ft. POH w/logs. RD Schl. 23:00 - 00:00 1.00 DRILL P SURF MU & RIH w/13 1/2" bit. 11/18/2003 00:00 - 00:30 0.50 DRILL P SURF Surface test MWD. Blow down lines. 00:30 - 04:30 4.00 DRILL P SURF RIH w/13 1/2" bit. Wash thru following area. 1855 - 2042 ft 3833 - 3980 ft 04:30 - 06:00 1.50 DRILL P SURF Circ & cond mud. 8.5 BPM - 1800 psi 06:00 - 06:30 0.50 DRILL P SURF Flow check showing well static. Blow down lines. 06:30 - 09:30 3.00 DRILL P SURF POH w/13 1/2" bit to BHA. Hole fill reflects well stable. 09:30 - 14:00 4.50 DRILL P SURF LD BHA. 14:00 - 14:30 0.50 CASE P SURF PJSM for surface casing. 14:30 - 16:30 2.00 CASE P SURF RU floor for runing 103/4" surface casing. 16:30 - 00:00 7.50 CASE P SURF RIH w/10 3/4" surface casing to 3920 ft. Avg 5800 MU TQ 11/19/2003 00:00 - 00:30 0.50 CASE P SURF - M/U hanger & wash down landing jt @ 3.5 BPM - 450 psi. - Ran a total of 95 jts 103/4" 45.50# buttress casing. - Hole was slick - landed casing w/135K 00:30 - 02:00 1.50 CEMT P SURF - Stage up pump & circulate 1 1/2 BIU prior to cement job. - ICP @ 1.5 BPM 270 psi - FCP @ 6 BPM 288 psi. - Held PJSM for cement job while circulating. 02:00 - 02:45 0.75 CEMT P SURF - R/D Frank's fillup tool & RIU Halliburton cement head & x-over. 02:45 - 03:30 0.75 CEMT P SURF - Continue circulate & condition mud - adding water to thin mud to less than 25 YP. - Add 8 sx bicarb prior to cementing - ICP @ 7 BPM 300 psi - FCP @ 10 BPM 400 psi. 03:30 - 06:30 3.00 CEMT P SURF - Pump 5 bbls sea water & test lines to 3000 psi - Pump 75 bbls. 10.5 ppg weighted spacer & drop plug. - Pump 455 bbls 10.7ppg lead cement (615 sx) - Pump 82 bbls 15.9 ppg tail cement (400 sx) - Drop plug & flush lines wI 25 bbls sea water. 06:30 - 07:30 1.00 CEMT P SURF - Displace cement & bump plug w/ 350 bbls mud @ 95% pump efficiency. Printed: 5/312004 9:02:38 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: NS32 NS32 DRILL +COMPLETE NABORS ALASKA DRILLING I NABORS 33E Start: 11/14/2003 Rig Release: Rig Number: 33E Spud Date: 11/15/2003 End: 11/19/2003 06:30 . 07:30 1.00 CEMT P SURF - Hold 2200 psi for 5 minutes & bleed off. Floats holding. · No losses throughout cement job. 07:30 . 10:00 2.50 CEMT P SURF - R/D cement head · Clean floor · UD Landing jt. - Clear floor - Change bails 10:00 - 12:00 2.00 CEMT P SURF · Service TO . change pin in grabber. 12:00 . 15:30 3.50 CEMT P SURF - Clean pits & weight up brine to 9.8 ppg. 15:30 . 17:30 2.00 CEMT P SURF - Repair TO. Adjust linkage to bails per Canrig Rep. 17:30 - 20:00 2.50 CEMT P SURF · RIH to displace mud to 9.8 ppg brine 20:00 . 20:30 0.50 CEMT P SURF - PJSM - Well displacement 20:30 . 21 :00 0.50 CEMT P SURF - Wash down & tag cement 11' above FC @ 3866'. 21 :00 . 22:30 1.50 CEMT P SURF · Displace well w/ 80 bbls sea water, followed by 50 bbls hi vis spacer, followed by 100 bbls sea water, followed by 400 bbls 9.8 ppg brine. · Rotate (35 RPM) & reciprocate while displacing to brine @ 10 BPM 400 psi. All returns going to G & I via drag chain. 22:30 . 00:00 1.50 CEMT P SURF - POH 11/20/2003 00:00 - 00:30 0.50 CEMT P SURF · POH & break off bit. 00:30 . 00:00 23.50 CEMT N WAIT SURF · Waiting on E-line Ops to complete setting IBP portion of the pre·rig work on NS·27 before US IT log can be run on NS-32. - Performing maintenance on rig as follows: - Remove pulsation dampener bladder in #1 mud pump & C/O. - Clean L pits - C/O ice scraper device on derrick climber. · Work on boiler. - Mix 9.3 brine w/2% KCL for well kill on NS·27 - Make some preparations for rig move. 11/21/2003 00:00·15:00 15.00 CEMT N WAIT SURF Continue waiting for E-line to complete pre rig work on NS-27. - Maintenance on rig while waiting. - Wireline Unit Finish IBP and Rig down from NS27. 15:00 - 16:00 1.00 CEMT P SURF PJSM in pre·tour meeting. Friday Rig Crew Change Out. - Deliver wireline tools & equipment to rig floor. 16:00 . 18:30 2.50 CEMT P SURF Prepare wireline unit of run - C/O spools on E-line unit. 18:30 - 19:30 1.00 CEMT P SURF PJSM . RlU with Schlumberger crews to run USIT logging tools. 19:30 - 23:00 3.50 CEMT N DFAL SURF RIH to 3844' w/ USIT tools. Troubleshoot to detect problem w/ tool string. - Arrange for helicopter to bring out another string of USIT tools. 23:00 - 00:00 1.00 CEMT N DFAL SURF POH & C/O USIT from Run #1. 11/22/2003 00:00 - 00:30 0.50 CEMT N DFAL SURF - Continue swapping out USIT logging tools. 00:30 - 05:00 4.50 CEMT N DFAL SURF · RIH wI US IT log. Unable to log. - Made 4 different runs to various depths with different combinations of transducers & cartridges trying to get log. - Interface between job site & Schlumberger management attempting to troubleshoot problems w/o success. 05:00 . 06:00 1.00 CEMT N DFAL SURF - PJSM - RID E-line crew 06:00 . 08:00 2.00 CEMT P SURF - RIH w/ 5" HWDP & 5" DP & displace brine to leave 350' air gap. - Slick line R/U on NS-27 to complete pre rig work. (Dumping Printed: 5/312004 9:02:38 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: NS32 NS32 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 33E Start: 11/14/2003 Rig Release: Rig Number: 33E Spud Date: 11/15/2003 End: 11/22/2003 06:00 - 08:00 2.00 CEMT P SURF sluggit on top of IBP) 08:00 - 10:00 2.00 CEMT P SURF - PJSM - N/D riser. 10:00 - 11 :30 1.50 CEMT P SURF - PJSM - N/U multi bowl ass'y & test to 2500 psi. 11 :30 - 12:30 1.00 CEMT P SURF - Install 4 1/2" hanger w/ penetrator & test seals to 5000 psi. - Install cover plate & caps on well. 12:30 - 14:30 2.00 CEMT P SURF - Clean cellar & prep for rig move. 14:30 - 18:00 3.50 CEMT N WAIT SURF - Wait while slick line completes pre rig work on NS-27. 3 trips & dumped 5' of sluggit on top of IBP - Slick line RID @ 1800 hrs 18:00 - 00:00 6.00 CEMT N WAIT SURF - P/U lubricator & set BPV on NS-27. - Review ATP's with rig crew, OPS, APC, & AIC. - Remove scaffolding from NS-27. - Remove "S" riser between tree & flow line. - Remove well house, bleed trailer, & other material required for rig move. - Function rig moving equip't. - Lay plywood on mats. - Inspect NS-27 w/ ACS Tech & complete pre drillsite checklist. - Release rig from NS-32 @ 00:00 on 11-23-03 12/3/2003 00:00 - 01 :00 1.00 MOB P PRE Prepare for Rig move. Perform A TP with drilling and ops. 01 :00 - 02:00 1.00 MOB P PRE PJSM -- Rig move and Rig move checklist. 02:00 - 05:00 3.00 MOB P PRE Move rig from NS27 to NS32. 05:00 - 08:00 3.00 MOB P PRE Level rig and Pre-spud checklist. 08:00 - 15:30 7.50 MOB P PRE PJSM -- Nipple up BOPE. 15:30 - 16:00 0.50 MOB P PRE Clean rig floor and inspect equipment. 16:00 - 17:00 1.00 MOB P PRE PJSM. Write procedure for transferring 5" in derrick. 17:00 - 19:00 2.00 MOB P PRE Transfer 5" drillpipe and 5" HWDP to off driller's side. 60 stands total. 19:00 - 20:00 1.00 MOB P PRE PJSM. Change out to 4" handling equipment. 20:00 - 00:00 4.00 MOB P PRE RIH with 4" drillpipe. Joints #1 - #92. 12/4/2003 00:00 - 00:30 0.50 MOB P PRE Continue to PU 4" HT-40 drill pipe üoint #93 - #111). 00:30 - 01 :00 0.50 MOB P PRE POOH with 9 stands of 4" drillpipe and rack back in derrick. 01 :00 - 02:00 1.00 MOB P PRE Continue to PU 4" HT -40 drill pipe üoint #111 - #138). 02:00 - 03:30 1.50 MOB P PRE POOH with 37 stands of 4" drillpipe and rack back in derrick. 03:30 - 06:00 2.50 BOPSUP P PRE PJSM. Change 7" rams to 2-7/8" x 5" variable rams (top rams). 06:00 - 06:30 0.50 BOPSUF P PRE Pull wear ring. 06:30 - 07:00 0.50 BOPSUP P PRE Fill hole with 9.3 ppg brine. 1. 53 bbls total - 550' of 9.3 ppg brine. 07:00 - 07:30 0.50 BOPSUF P PRE PJSM. Rig up to test BOP's. 07:30 - 09:00 1.50 BOPSUF P PRE Attempt to test. Change out seal on the test plug. 09:00 - 09:30 0.50 BOPSUF P PRE Attempt to test BOP. Test plug leak. Change out test plug. 09:30 - 12:00 2.50 BOPSUP P PRE Attempt to test BOP. Test plug not seating. 12:00 - 12:30 0.50 BOPSUF P PRE Install lower test plug. Fill stack. 12:30 - 14:30 2.00 BOPSUP P PRE Test BOP's to 250 psi low and 4800 psi high for 5 min. 14:30 - 15:00 0.50 BOPSUF P PRE Change out test plug. 15:00 - 19:30 4.50 BOPSUF P PRE Test BOP's to 250 psi low and 4800 psi high for 5 min. 19:30 - 20:00 0.50 BOPSUF P PRE Pull test plug and install wear ring. 20:00 - 20:30 0.50 BOPSUF P PRE Blow down choke and kill lines and test pump. 20:30 - 23:30 3.00 BOPSUF P PRE PJSM. Change out upper IBOP. 23:30 - 00:00 0.50 BOPSUP P PRE Rig up and test upper IBOP. 12/5/2003 00:00 - 00:30 0.50 BOPSUF P PRE Continue testing BOP's. 00:30 - 01 :00 0.50 BOPSUF P PRE Rig down from BOP test and blow down lines. Printed: 5/3/2004 9:02:38 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: NS32 NS32 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 33E Start: 11/14/2003 Rig Release: Rig Number: 33E Spud Date: 11/15/2003 End: 12/5/2003 01 :00 - 02:30 1.50 CASE P INT1 PJSM. Test casing to 3500 psi for 30 minutes. 1. The pressure increased at approximately 400 psi / 5 strokes. 2. 47 strokes were pumped to 3600 psi; approximately 4.5 bbls. 3. 6" liners in the pumps 02:30 - 03:00 0.50 DRILL P INT1 PJSM. Blow down mud lines. Change out from 4" tools to 5" tools. 03:00 - 06:00 3.00 DRILL P INT1 PJSM. Make up BHA #5. Drilling assembly for 9.7/8" hole. 06:00 - 06:30 0.50 DRILL P INT1 Function test MWD and motor. Blow down all lines. 06:30 - 07:00 0.50 DRILL P INT1 RIH with HWDP to 834' MD. 07:00 - 07:30 0.50 DRILL P INT1 Island muster drill and 0-1 drill. 07:30 - 08:30 1.00 DRILL P INT1 Continue to RIH with 5" drillpipe to 1,118" MD. 08:30 - 1 0:00 1.50 DRILL P INT1 Slip and cut drilling line. 10:00 - 11 :00 1.00 DRILL P INT1 Service drawworks, crown, and top drive. 11 :00 - 13:00 2.00 DRILL P INT1 Continue to RIH with 5" drillpipe to 3,755' MD. 13:00 - 14:30 1.50 DRILL P INT1 Displace the 9.8 pp brine to seawater while washing down / drilling cement to shoe. 14:30 - 15:30 1.00 DRILL P INT1 Set back a stand. Grease a valve on the mud manifold. Make connection. 15:30 - 16:30 1.00 DRILL P INT1 Wash down to 3,875' MD. No rotation, pumping at 140 SPM. Did not see any cement on top of the plug. 16:30 - 17:30 1.00 DRILL P INT1 Drill out float equipment. 17:30 - 18:30 1.00 DRILL P INT1 Clean out cement down to shoe at 3,959' MD. Displace well to 8.6 ppg seawater polymer mud using a 25 bbl hi-vis spacer. 18:30 - 19:00 0.50 DRILL P INT1 Continue displacement. 19:00 - 19:30 0.50 DRILL P INT1 Drill out shoe and clean out to 3,964' MD. 19:30 - 21 :00 1.50 DRILL P INT1 Circulate & condition mud. 8.6 ppg in / out. Mud at 60 degrees in / out. 1. Pump at 60 spm (6 BPM) with pump #1, 6" liners. 2. Pump 7500 strokes at 192 psi 3. Rotate at 30 rpm, no recprocation. 4. Torque at 8300 ftlbs. 21 :00 - 22:30 1.50 DRILL P INT1 RU. FIT test to 11.5 ppg EMW. Blow down lines. 1. Had difficulty with chart recorder, repeated test. 2. Charted test at 11.5 ppg EMW (490 psi) for 30 minutes. 22:30 - 23:00 0.50 DRILL P INT1 Cleanout rathole and drill from 3,980' MD to 4,000' MD. 23:00 - 23:30 0.50 DRILL P INT1 Circulate bottoms up until 8.6 ppg MW in and out (3600 strokes). 23:30 - 00:00 0.50 DRILL P INT1 RU. FIT test to 11.5 ppg EMW. Blow down lines. 1. Charted test at 11.5 ppg EMW (490 psi) for 30 minutes. 12/6/2003 00:00 - 02:00 2.00 DRILL P INT1 Drill 9-7/8" hole from 4,000' MD to 4,225' MD. 02:00 - 02:30 0.50 DRILL P INT1 Service Rig. Work on drawworks drum. 02:30 - 12:00 9.50 DRILL P INT1 Drill/slide 9-7/8" hole from 4,225' MD to 5,450' MD 1. Rotate 6.2 hours. Slide 0.6 hour. Total on bottom 6.8 hours. 2. Pumping high vis sweeps every 400'. Seeing increase at Printed: 5/312004 9:02:38 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: NS32 NS32 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 33E Start: 11/14/2003 Rig Release: Rig Number: 33E Spud Date: 11/15/2003 End: 12/6/2003 02:30 - 12:00 9.50 DRILL P INT1 shakers. 12:00 - 00:00 12.00 DRILL P INT1 Drilllslide 9-7/8" hole from 5,450' MD to 6,111' MD 1. Rotate 7.6 hours. Slide 1.8 hours. Total on bottom 9.4 hours. 2. Pumping high vis sweeps every 400'. Seeing increase at shakers. 3. Pump walnut sweep during slow drilling. No change. 4. Drilling SV sand/shale sequence. 12/7/2003 00:00 - 12:00 12.00 DRILL P INT1 Drill/slide 9-7/8" hole from 6,111' MD to 6,682' MD 1. Rotate 6.2 hours. Slide 3.8 hours. Total on bottom 10.0 hours. 2. Pumping high vis sweeps every 400'. Seeing increase at shakers. 12:00 - 00:00 12.00 DRILL P INT1 Drill/slide 9-7/8" hole from 6,682' MD to 7,130' MD 1. Rotate 6.1 hours. Slide 3.8 hours. Total on bottom 9.9 hours. 2. Pumping high vis sweeps every 400'. Seeing increase at shakers. 12/8/2003 00:00 - 01 :30 1.50 DRILL P INT1 Drill/slide 9-7/8" hole from 7,130' MD to 7,185' MD. 01 :30 - 02:00 0.50 DRILL C INT1 Service drawworks. 02:00 - 07:00 5.00 DRILL P INT1 Drill/slide 9-7/8" hole from 7,185' MD to 7,349' MD. 07:00 - 07:30 0.50 DRILL N RREP INT1 Check top drive RPM counter and brakes. 07:30 - 08:30 1.00 DRILL P INT1 Service top drive. 08:30 - 09:00 0.50 DRILL N RREP INT1 Change out RPM counter. 09:00 - 09:30 0.50 DRILL P INT1 Island power outage. 09:30 - 10:00 0.50 DRILL N RREP INT1 Continue to work on top drive. 10:00 - 00:00 14.00 DRILL P INT1 Drill/slide 9-7/8" hole from 7,349' MD to 8,110' MD. 1. Rotate 10.8 hours. Slide 0.4 hours. Total on bottom 11.2 hours. 2. Pumping high vis sweeps every 400'. 12/9/2003 00:00 - 01 :00 1.00 DRILL P INT1 Drill/slide 9-7/8" hole from 8,110' MD to 8,121' MD. 01 :00 - 02:30 1.50 DRILL P INT1 Condition mud and circulate. 1. Pump 25 bbl hi-vis sweep at TO. Saw increased cuttings at shakers at bottoms up. 2. Circulated 1.5 hole volumes. 02:30 - 03:00 0.50 DRILL P INT1 POOH first 5 stands wet from 8121' MD to 7730' MD. Good hole fill. 03:00 - 03:30 0.50 DRILL P INT1 Pump 20 bbls of 11.5 ppg dry job. Blow down top drive and mud line. Monitor well for 10 minutes. No flow. 03:30 - 05:30 2.00 DRILL P INT1 POOH from 7730' MD to 3959' MD. Good hole fill. 05:30 - 06:00 0.50 DRILL P INT1 Monitor well at shoe (3959' MD) for 15 minutes. Perform 0-1 drill. 06:00 - 06:30 0.50 DRILL P INT1 Service top drive and drawworks. 06:30 - 09:30 3.00 DRILL P INT1 RIH from 3959' MD to 8121' MD. Ream the last stand to bottom. 09:30 - 13:00 3.50 DRILL P INT1 Circulate and condition mud. Printed: 5/3/2004 9:02:38 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: NS32 NS32 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 33E Start: 11/14/2003 Rig Release: Rig Number: 33E Spud Date: 11/15/2003 End: 12/9/2003 09:30 - 13:00 3.50 DRILL P INT1 1. Pump 50 bbl hi-vis sweep, surface to surface. 2. Circulate 3.5 bottoms up. 13:00 - 17:00 4.00 DRILL P INT1 POOH with driling assembly. No tight spots. 17:00 - 18:00 1.00 DRILL P INT1 Lay down BHA. 18:00 - 20:30 2.50 DRILL P INT1 PJSM. Rig up to run quad-combo wireilne logs. 20:30 - 00:00 3.50 DRILL P INT1 Run quad-combo wireline logs. 12/10/2003 00:00 - 03:00 3.00 DRILL P INT1 Continue to run WL logs. Once at-the shoe, a sufficient density log could not be displayed. Another pass of the hole was made after some parameters were changed in the tool. The second logging pass was successful. 03:00 - 03:30 0.50 DRILL P INT1 PJSM -- Rig down e-line. 03:30 - 05:00 1.50 DRILL P INT1 Load rig floor with casing and drill pipe tools to rig floor. VLE access will be blocked due to Slickline work. 05:00 - 06:00 1.00 DRILL P INT1 Make up BHA #6. 06:00 - 12:00 6.00 DRILL P INT1 RIH from 1017' MD with dril pipe to 8121' MD. Good hole fill. Well bore in good shape. 12:00 - 15:00 3.00 DRILL P INT1 Condition mud and ciruclate. 1. Pump 50 bbl hi-vis sweep, surface to surface. 2. Circulate 3.5 bottoms up. 15:00 - 18:00 3.00 DRILL P INT1 Trip out of hole. No tight spots or overpulls. 18:00 - 20:30 2.50 DRILL P INT1 Lay down BHA. 20:30 - 21 :30 1.00 CASE P INT1 Pull wear bushing. Set test plug. 21 :30 - 22:00 0.50 CASE P INT1 PJSM for changing pipe rams. 22:00 - 23:30 1.50 CASE P INT1 Change upper pipe rams to 7-5/8" rams. 23:30 - 00:00 0.50 CASE P INT1 Test ram body to 3500 psi. 12/11/2003 00:00 - 00:30 0.50 CASE P INT1 LD test jt. Clear rig floor. 00:30 - 02:00 1.50 CASE P INT1 RU for 7 5/8" csg. Chg out bails. 02:00 - 08:00 6.00 CASE P INT1 MU & RIH w/7 5/8" csg as per program to 103/4" shoe @ 3980 ft. 08:00 - 09:00 1.00 CASE P INT1 CBU @ shoe. 9 BPM - 510 psi. PUW 165k, SOW 140k 09:00 - 15:00 6.00 CASE P INT1 Con't RIH w/7 5/8 csg to setting depth. MU hanger, land csg wI FS @ 8105 ft, FC @ 8060 ft, LC @ 8015 ft, ES CMTER @ 6152ft, TAM @ 4135 ft. 15:00 - 16:30 1.50 CASE P INT1 RD Franks tool, MU cmt head. Circ & condition at 10 bpm. 16:30 - 17:00 0.50 CASE P INT1 PJSM on cementing operations. 17:00 - 19:30 2.50 CEMT P INT1 First Stage Cement: 1. Test lines to 3500 psi. 2. Drop 1 st stage bottom plug. 3. Load 1st stage top plug. 4. Pump 45 bbls spacer. 5. Pump 124 bbls of 15.9 ppg cement. 6. Chase with 25 bbls of seawater. 7. Pump 3430 stks to bump plug (96% eff). 8. Hold 1470 psi for 5 minutes and check floats holding. 9. Reciprocated pipe while cement turning corner. 10. Lost 30 bbls of returns during cement job. 19:30 - 21:30 2.00 CEMT P INT1 Second Stage Cement: Printed: 5/3/2004 9:02:38 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: NS32 NS32 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 33E Start: 11/14/2003 Rig Release: Rig Number: 33E Spud Date: 11/15/2003 End: 12/11/2003 19:30 - 21 :30 2.00 CEMT P INT1 1. Load 2nd stage plug. 2. Pressure up to 3400 psi to open ES Cementer. 3. Circulate cement out of hole. Approximately 15 bbls of cement back with a 11.5 ppg weight and 10.8 PH. 21 :30 - 22:30 1.00 CEMT P INT1 Second Stage Cement (Cont.) 1. PJSM for second stage job. 2. Pump 45 bbls. spacer. 3. Pump 43 bbls of 13.1 ppg lead slurry. 4. Pump 57 bbls of 15.9 ppg tail slurry. 5. Drop plug. 6. Pump 25 bbls of seawater. 7. Pump 257 bbl of mud (2560 strokes) with rig pumps (96% eff). 8. Close ES cementer, Confirmed closed. Hold 2200 psi. 22:30 - 23:30 1.00 CEMT P INT1 Lay down cement head. Back out upper part of landing joint. 23:30 - 00:00 0.50 CEMT P INT1 Rig up to run 4" drill pipe to open TAM port collar. 12/12/2003 00:00 - 00:30 0.50 CEMT P INT1 - M/U TAM port collar shifting tool. 00:30 - 02:30 2.00 CEMT P INT1 - RIH wI TAM port collar shifting tool on 4" DP to 4137' MD. 02:30 - 03:00 0.50 CEMT P INT1 - Open TAM port collar - Up wt. 125K, On wt 105K - Pressure up to 1000 psi, then bleed off to 300 psi. 03:00 - 04:00 1.00 CEMT P INT1 - CBU & PJSM for 3rd stage cement job. 04:00 - 06:30 2.50 CEMT P INT1 - Cement & close TAM port collar. - Pump 45 bbls. 10.5 spacer, 136 bbls 10.5 lead slurry, 46 bbls. 15.9 tail slurry. Displaced cement w/45 bbls sea water via Halliburton pump. 06:30 - 07:00 0.50 CEMT P INT1 - R/D cement hose & B/D lines 07:00 - 09:00 2.00 CEMT P INT1 - POH & UD TAM shifting tool. 09:00 - 10:00 1.00 CEMT P INT1 - UD landing jt & C/O elevators from 4" to 5" 10:00 - 11:00 1.00 CEMT P INT1 - M/U packoff ass'y. - RIH & test packoff. (1st attempt failed») 11 :00 - 12:00 1.00 CEMT P INT1 - Install bowl protector & flush BOP stack. 12:00 - 14:30 2.50 CEMT N SFAL INT1 - Packoff failed to test. - Pull bowl protector - Pull packoff. 14:30 - 15:30 1.00 CEMT N SFAL INT1 - Install new packoff & test to 5000 psi - Install bowl protector. 15:30 - 16:30 1.00 CEMT P INT1 - C/O saver sun on Top drive to handle 4" DP 16:30 - 18:00 1.50 CEMT P INT1 - PJSM to cut drilling line - Cut drilling line 18:00 - 19:30 1.50 CEMT P INT1 - PJSM - - PIU BHA # 7 19:30 - 23:00 3.50 CEMT P INT1 - RIH - picking up singles from pipeshed. 23:00 - 23:30 0.50 CEMT P INT1 - Rotate slowly thru TAM collar @ 4135'. - Wash through TAM port collar @ 4135'. - No cement detected in casing @ port collar. - Test casing to 1000 psi for 5 minutes. 23:30 - 00:00 0.50 CEMT P INT1 - Continue RIH. 12/13/2003 00:00 - 01 :30 1.50 CEMT P INT1 - RIH wI 4" DP - P/U singles out of pipeshed. 01 :30 - 02:15 0.75 CEMT P INT1 - Tag cement @ 6060' - 92' above ES Cementer (4 bbls cement) Printed: 5/3/2004 9:02:38 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: NS32 NS32 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 33E Start: 11/14/2003 Rig Release: Rig Number: 33E Spud Date: 11/15/2003 End: 12/13/2003 01:30 - 02:15 0.75 CEMT P INT1 - Wash & rotate through cement. 40 RPM, 8 BPM @ 870 psi. 02:15 - 02:45 0.50 CEMT P INT1 - Drill plugs & ES Cementer - Tag ES Cementer @ 6160' 02:45 - 03:15 0.50 CEMT P INT1 - Pump Hi-vis sweep & circulate - Cement, plug rubber, & ES cementer metal seen at shakers. 03:15 - 03:45 0.50 CEMT P INT1 - Test casing to 1000 psi & hold for 5 min. 03:45 - 04:30 0.75 CEMT P INT1 - Continue RIH w/4" DP from 6240' to 7855'. 04:30 - 07:00 2.50 CEMT P INT1 - Drill cement & LC from 7855' to 8040'. - UC @ 8015' 07:00 - 08:00 1.00 CEMT P INT1 - Pump Hi-vis sweep & circulate. - Test casing to 1000 psi 08:00 - 10:15 2.25 CEMT P INT1 - Displace well to 9.8 ppg brine. - Monitor well & BID lines 10:15 - 12:00 1.75 CEMT P INT1 - POH w/ 4" DP UD singles. 12:00 - 13:00 1.00 CEMT P INT1 - Lubricate rig. 13:00 - 18:30 5.50 CEMT P INT1 - POH w/ 4" DP & BHA. UD singles. - Rack back 16 stands for RIH & displacing brine. (350' air gap) - Clear tools & clean floor. 18:30 - 19:00 0.50 CEMT P INT1 - PJSM - RIU Schlumberger 19:00 - 20:00 1.00 CEMT P INT1 - R/U Schlumberger E-line for USIT log. 20:00 - 00:00 4.00 CEMT P INT1 - RIH w/ USIT log. 12/14/2003 00:00 - 01 :00 1.00 CEMT P INT1 - RID E-liners after completing USIT log. 01 :00 - 02:45 1.75 CEMT P INT1 - Pressure test 7 5/8" casing to 4400 psi & hold for 30 minutes. - B/D lines 02:45 - 03:30 0.75 CEMT P INT1 - RIH wI 4" DP w/ closed TIW valve on bottom & displace fluids leaving 350' air gap for freeze protection. 03:30 - 05:00 1.50 CEMT P INT1 - POH & UD 4" DP. - Installed BPV in NS-27 in preparation for rig move. 05:00 - 06:00 1.00 CEMT P INT1 - Change top rams to 2 7/8" X 5". 06:00 - 07:00 1.00 CEMT P INT1 - Pull bowl protector & install 4 1/2" tubing hanger. 07:00 - 12:00 5.00 CEMT P INT1 - R/D floor & clean under rotary table - R/D Koomey lines & turnbuckles - N/D riser - R/D choke & kill lines - Clean up cellar - N/D BOP & double stud adaptor - CIO saver sub on top drive 12:00 - 14:30 2.50 CEMT P INT1 - Mix spud mud. OP's bleed down NS 31. 14:30 - 15:00 0.50 CEMT P INT1 - P/U & rack back BOP's 15:00 - 16:30 1.50 CEMT P INT1 - Put dry hole tree in cellar & install on NS-32. - Test to 5000 psi 16:30 - 18:00 1.50 CEMT P INT1 - Prepare to skid rig to NS-25 - Released rig from NS-32 @ 1800 hrs. 4/27/2004 09:00 - 17:00 8.00 MOB P PRE PJSM for Rig Move. Move rig from NS21. - SI NS22, 23, 24, 25, 27, 29, and 31 along the way. Bring on wells after wells become exposed while moving rig - NS31 in cellar ...remain SI for Heavy Lift. 17:00 - 19:00 2.00 RIGU P PRE Level and berm rig. Place flooring in cellar. "ACCEPT rig at 1900 hrs on 12/27/04. 19:00 - 19:30 0.50 RIGU P PRE PJSM for NO dry hole tree and Tbg spool. Printed: 5/3/2004 9:02:38 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: NS32 NS32 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 33E Start: 11/14/2003 Rig Release: Rig Number: 33E Spud Date: 11/15/2003 End: 4127/2004 19:30 - 21 :30 2.00 RIGU P PRE NO dry hole tree & production sweep. NO tubing spool. 21 :30 - 23:00 1.50 RIGU P PRE NU spacer spool and new tubing spool (modified for accepting new penetrator). 23:00 - 00:00 1.00 BOPSUF P PRE NU BOP's. - Put NS31 back on injection at 23:30 hrs. Note: AOGCC Rep, John Spaulding waived witnessing test. 4/28/2004 00:00 - 03:30 3.50 CEMT P INT1 Continue NU BOP. - Test ABB-VETCO Gray tubing spool to 5000 psig. 03:30 - 06:00 2.50 CEMT P INT1 Rig up to Test BOP's. 06:00 - 14:30 8.50 CEMT P INT1 Pressure Test BOPE to 2501 4800 psig. - AOGCC Rep, John Spaulding waived witness on 4/27/2004. 14:30 - 15:00 0.50 CEMT P INT1 Remove test and blow down Top Drive and lines. 15:00 - 15:30 0.50 CEMT P INT1 Install wear ring. 15:30 - 17:00 1.50 CEMT P INT1 Pressure test 7-5/8" casing to 4450 psig for 30 mins. 17:00 - 18:00 1.00 CEMT P INT1 MU BHA #8. - 6-3/4" Smith XR+ (3x15's) and 4-3/4" Slimpulse MWD 18:00 - 18:30 0.50 CEMT P INT1 Shallow Test MWD. 18:30 - 20:00 1.50 CEMT P INT1 Single in w/4" HT-40 DP and BHA to 1696' md. 20:00 - 21 :00 1.00 CEMT N RREP INT1 Repair pipe skate. 21 :00 - 00:00 3.00 CEMT P INT1 Continue to single in wI BHA from 1696' to 4884' md. 4/29/2004 00:00 - 03:30 3.50 CEMT P INT1 TIH PU 4" DP from pipeshed and derrick. Wash down and tag TOC at 8040' md. 03:30 - 05:30 2.00 CEMT P INT1 Drill cement and the remainder of float equipment (FC and FS @ 8105'), drill out rathole to 8121' md and drill ahead 20' of new 6-3/4" hole. - Pumped sweep to bit followed by 8.9 ppg NACL brine and recovered 9.8 ppg NACL brine that was left for suspension while drilling ahead. -Circulate out sweep and cement filling L-Pit. - Condition MWin= MWout= 9.0 ppg. 05:30 - 06:30 1.00 CEMT P INT1 Perform LOTto 13.6 ppg EMW. - 9.0 ppg brine in hole with 1570 psi surface pressure. 06:30 - 09:00 2.50 DRILL P PROD1 Drill ahead 6-3/4" hole from 8141' md to TO at 8321' md (6691' tvd rkb). Drilling parameters: - 120 rpm w/ 8-9 K torque - WOB 15 K-Ibs, ROP= 75 fph. - 300 gpm w/1 000 psig 09:00 - 10:30 1.50 DRILL P PROD1 Pump hi vis sweep surface to surface while reciprocating and rotating. - Spot viscosified brine pill in OH, leaving top of pill at 7900' md. 10:30 - 11 :00 0.50 DRILL P PROD1 Monitor well. Pull 5 stands. 11 :00 - 13:00 2.00 DRILL P PROD1 PJSM. Slip and cut drilling line. Service TO and Draw works. 13:00 - 16:00 3.00 DRILL P PROD1 TOH wI BHA#8. 16:00 - 16:30 0.50 DRILL P PROD1 Monitor well and change out elevators. 16:30 - 17:30 1.00 DRILL P PROD1 PJSM. UD BHA #8. - 6-3/4" bit graded 1-1 WT 17:30 - 18:00 0.50 DRILL P PROD1 PJSM. MU BHA#9 (6-3/4" Bit and 7-5/8" scraper). 18:00 - 22:00 4.00 DRILL P PROD1 RIH wI BHA#9 on 4" DP to 7900' md. 22:00 - 00:00 2.00 DRILL P PROD1 PJSM for pumping casing wash pills and sweeps. - Pump 40 bbls caustic. Printed: 5/312004 9:02:38 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: NS32 NS32 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 33E Start: 11/14/2003 Rig Release: Rig Number: 33E Spud Date: 11/15/2003 End: 4/29/2004 22:00 - 00:00 2.00 DRILL P PROD1 - Followed by 25 bbls Dirt Magnet - Followed by 30 bbls of high vis spacer. - Followed by 90 bbls of 8.9 ppg spacer. - Chase spacer with 9.8 ppg brine. 4/30/2004 00:00 - 01 :00 1.00 DRILL P PROD1 Continue to displace well over to 9.8 ppg brine. - Total CBUx4 01 :00 - 01 :30 0.50 DRILL P PROD1 Monitor well. 01 :30 - 08:30 7.00 DRILL P PROD1 POH while laying down 4" DP. 08:30 - 09:00 0.50 DRILL P PROD1 Lay down BHA#9. 09:00 - 09:30 0.50 DRILL P PROD1 Pull wear bushing. 09:30 - 10:30 1.00 RUNCOW COMP PJSM. Rig up to run 4.5" 12.6 ppf, L-80, IBT-M, completion w/ heat trace. 10:30 - 11 :00 0.50 RUNCOIvP COMP Safety meeting for running completion. 11 :00 - 18:00 7.00 RUNCOMP COMP Run completion in the following order: --MU Assembly #1 (WLEG, 'XN' nipple w/ RHC insert) to Jt#10f #193 jts total of 4.5" 12.6 ppf, L-80, IBT-M tubing. - Run 4.5" Tubing Jts #2-72. - MU BOT 7-5/8" x 4-1/2" S-3 Permanent Packer Assembly. - Run 4.5" Tubing Jts #73-143. - MU 4.5" "X" nipple Assembly (protective sleeve not installed). - Run 4.5" Tubing Jts #144-145. 18:00 - 18:30 0.50 RUNCOW COMP PJSM for Rigging Up Floor to Run Tyco-Raychem Heat Trace String. 18:30 - 19:45 1.25 RUNCOW COMP RU floor for running heat trace string: - Hang sheave, Install heat trace string on spooling unit, get banding equipment ready. 19:45 - 20:00 0.25 RUNCOIvP COMP PJSM for running 4.5" completion w/ heater string. 20:00 - 00:00 4.00 RUNCOMP COMP Run 4.5" 12.6 ppf, L-80, IBT-M tubing from Jt #145 to Jt#157 w/ heat trace. Beginning at 2100' MD. - Running heat trace channel covering every foot of heat trace. The channels are 6' long and secured with 3 bands per channel. -Test heat trace string for continuity (8.3 ohms) and resistance (6 G-ohms) at Jt #157. 5/1/2004 00:00 - 11 :00 11.00 RUNCOMP COMP Run 4.5" 12.6 ppf, L-80, IBT-M, tubing from Jt. #158 - Jt# 193 w/ Tyco Heat trace channels (3 bands per channel). Run2 pup jts. 11 :00 - 11 :30 0.50 RUNCOIvP COMP MU ABB VETCO- Gray Tubing Hanger assembly (1.46' x 11 "x 4.5" MB 203 hanger with 4" BPV plus 29.47' tubing pup). MU Landing Jt. 11 :30 - 16:00 4.50 RUNCOW COMP Splice heat trace and terminate. 16:00 - 16:30 0.50 RUNCmtP COMP Land tubing hanger - 118 K-Ibs HWt. -- PU 145k, SO 120k 16:30 - 17:30 1.00 RUNCOW COMP ND Riser. 17:30 - 19:30 2.00 RUNCOIvP COMP PJSM. Open ram doors and clean and remove all rams. Grease body for cold stack. Notify Operations for SI of NS31for heavy lift at 8:30 am. 19:30 - 21 :30 2.00 RUNCOW COMP Prepare to NO BOP's. Wait on Operations to back out gas from Caribou crossing and begin Shut In of NS31 for heavy lift. 21 :30 - 23:00 1.50 RUNCOW COMP Clear rig floor, cellar, and rig while waiting on Operations to Shut In NS31. 23:00 - 00:00 1.00 RUNCOW COMP Operations ready... Lift BOP stack and rack back. Printed: 5/312004 9:02:38 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: NS32 NS32 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 33E Start: 11/14/2003 Rig Release: Rig Number: 33E Spud Date: 11/15/2003 End: 511/2004 23:00 - 00:00 1.00 RUNCOtvP COMP - NO Drilling Adapter Flange. 5/2/2004 00:00 - 01 :00 1.00 RUNCOMP COMP Test heat trace at wellhead. 01 :00 - 02:45 1.75 RUNCOtvP COMP NU tree on NS32. 02:45 - 03:00 0.25 RUNCOMP COMP Pressure test tree adapter to 5K psig. 03:00 - 03:15 0.25 RUNCOtvP COMP Test heat trace at well head. 03: 15 - 03:30 0.25 RUNCOMP COMP Pressure test tree to 5K psig. 03:30 - 04:30 1.00 RUNCOMP COMP Remove TWC. 04:30 - 05:45 1.25 RUNCOMP COMP Rig up manifold for FP and pressure testing. 05:45 - 06:45 1.00 RUNCOtvP COMP Break for lunch and to gather all parties for FP. 06:45 - 07:00 0.25 RUNCOMP COMP Pressure test rig lines & manifold to 4000 psig. 07:00 - 07:30 0.50 RUNCOMP COMP PJSM for pumping corrosion inhibited packer brine and FP. 07:30 - 10:30 3.00 RUNCOMP COMP Reverse circulate down the 7-5/8" x 4-1/2" annulus with the following while taking returns off the tubing (max pump rate 3 bpm around pkr): 1. 155 bbls of 9.8 ppg brine wI corrosion inhibitor 2. Followed by 68 bbls of diesel with corrosion inhibitor. 10:30 - 13:00 2.50 RUNCOMP COMP Bleed off 8 bbls from 7-5/8" x 41/2" annulus to drop the fluid level in tubing to 530'. Fill the 4-1/2" tubing with 7 drums of ESCAID 110 mineral oil. 13:00 - 14:00 1.00 RUNCOMP COMP Drop 1-7/8" ball and rod for packer setting. - Pressure up to 3400 psig on ball and rod to set packer. 14:00 - 14:30 0.50 RUNCOMP COMP Increase pressure and test the tubing to 5000 psig for 30 min. (EPA Representatives Thor Cutler and Talib Syed on location to witness and sign off on test). 14:30 - 15:30 1.00 RUNCOtvP COMP Bleed tubing pressure down to 2900 psig to bleed trailer. - Pressure up to 4500 psgi for initial MIT on packer. Record tubing and casing pressure on chart for 30 mins (EPA Rep, Thor Cutler and Talib Syed, witnessed and sign off on test). 15:30 - 16:30 1.00 RUNCOtvP COMP Bleed off pressure on the annulus and then the tubing to bleed trailer. - RD all lines. 16:30 - 17:30 1.00 RUNCOIvP COMP PJSM for intalling BPV and securing the well. Set BPV and secure the well. 17:30 - 18:00 0.50 RUNCOIvP COMP Safety Standown Meeting with Well Site Leader. - 2-First Aids back to back (one twisted anklel one burn to forearm). Release Rig at 1800 hrs on 51212004. Printed: 5/312004 9:02:38 AM e TREE:ABB-VGI S 1/S" Sksi W ELLHEAD:ABB-VGI 11" Mulitbowl Sksi (Note: Hanger - 4" BPVITWC) 20", 169# X-56 @ 200' MD- 10 3/4", 4S.S#/ft, L-SO, BTC @3964'MD 4.S", 12.6#/ft. L-SO, IBT-MOD TUBING ID: 3.9SS" CAPACITY: 0.01S2 BBUFT NS32 ¡ ,k i g¡ ~'" ~. L1L !c : ~-'~ ¢ - if ,~ ~. 4.S" 'XN' NIPPLE,@SOSS' -=i', .~ 3.72S" ID (HES) "-- 7 S/S", 29.7#/ft . L-SO. BTC-M @S107 'MD TD @S321' MD 66S4' TVD DATE REV. BY JAS JAS RAC COMMENTS Initial Diagram Proposed Completion Completion 5/2/04 6/18/03 1/5/04 5111/04 , / / / / / / , -. õ4... ¿~ ~~.. t·¡¡ ~~ e RKB. ELEV = SS.9S' KB-BF. ELEV = 40.0S' BASE FLANGE ELEV = 1S.9' 7-S/S"x 4-1/2" Annulus Freeze rotected to 2000' TVD w/ 60 bbls of Inhibited Diesel Heat Trace Starting @ 2097' MD 'X' Nipple @ 2169' MD 3.S13" ID I Cement Baker 7-S/S" x 4-1/2" "S-3" PACKER 3.S7S"ID @S102'MD '_ 4.S" WLEG, @S100'MD ,-J¡,. 6 3/4" open hole Northstar WFLL: NS32 API NO: 50-029-23179 BP Exploration (Alaska) Legal Name: NS32 Common Name: NS32 12/5/2003 4/29/2004 FIT LOT 4,000.0 (ft) 8,141.0 (ft) 3,250.0 (ft) 6,512.0 (ft) 1,105.00 (ppg) 9.00 (ppg) 490 (psi) 1,570 (psi) 187,048 (psi) 4,615 (psi) 1,107.90 (ppg) 13.64 (ppg) e - Printed: 5/3/2004 9:02:30 AM ... e e Ò NS32 Survey Report Schlumberger "<" Report Date: 29-Apr-04 Survey I DLS Computation Method: Minimum Curvature 1 Lubinski Client: BP Exploration Alaska Vertical Section Azimuth: 32.590· Field: Northstar Vertical Section Origin: N 0.000 It, E 0.000 ft Structure I Slot: Northstar PF 1 NS32 TVD Reference Datum: Rotary Table Well: NS32 TVO Reference Elevation: 55.95 ft relative to MSL Borehole: NS32 Sea Bed I Ground level Elevation: 15.67 ft relative to MSL UWlIAPI#: 500292317900 Magnetic Declination: 25.560· Survey Name f Date: NS32 1 April 29, 2004 Total Field strength: 57590.226 nT TortI AHD I DDII ERD ratio: 121.094·/4574.61 ftl 5.839 1 0.684 Magnetic Dip: 80.986· Grid Coordinate System: NAD27 Alaska State Planes, Zone 04, US Feet Declination Date: December 01, 2003 Location Lat/Long: N 70.49159610. W 148.69333956 Magnetic Declination Model: BGGM 2003 location Grid HIE V/X: N 6031131.220 flUS, E 659821.460 ftUS North Reference: True North Grid Convergence Angle: +1.23167222· Total Corr Mag North.,. True North: +25.560· Grid Scale Factor: 0.99992902 Local Coordinates Referenced To: Well Head Measured I Inclination I Azimuth I Sub-Sea TVD I TVD Vertical I Along Hole I NS EW I DLS I Build Rate I Walk Rate I Northing Easting Latitude Longitude Depth Section Departure (It) (deg) (dog ) (It) (It) (It) (It) (It) (It) (degI1001t) (dog/1oolt) (degI1001t) (flUS) (ltUS) 0.00 0.00 000 -55.95 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 6031131.22 659821.46 N 70.49159610 W 148.69333956 50.00 0.44 38.47 -5.95 50.00 0.19 0.19 0.15 0.12 0.88 0.88 0.00 6031131.37 659821.58 N 70.49159651 W 148.69333859 100.00 0.59 25.95 44.05 100.00 0.64 0.64 0.53 0.35 0.37 0.30 -25.04 6031131.76 659821.80 N 70.49159755 W 148.69333669 150.00 0.92 35.54 94.04 149.99 1.29 1.30 109 0.70 0.70 0.66 19.18 6031132.32 659822.13 N 70.49159908 W 148.69333386 200.00 0.89 36.13 144.04 199.99 2.08 209 1.73 1.16 0.06 -0.06 1.18 6031132.97 659822.58 N 70.49160083 W 148.69333008 250.00 1.13 36.15 194.03 249.98 2.96 2.97 2.44 1.68 0.48 0.48 0.04 6031133.70 659823.09 N 70.49160277 W 148.69332583 300.00 1.27 37.31 244.02 299.97 4.01 4.02 3.28 2.31 0.28 0.28 2.32 6031134.55 659823.70 N 70.49160506 W 148.69332071 400.00 2.42 28.22 343.96 399.91 7.22 7.23 6.02 3.98 1.18 1.15 -909 6031137.33 659825.31 N 70.49161255 W 148.69330706 500.00 4.97 27.92 443.75 499.70 13.64 13.67 11.71 7.00 2.55 2.55 -0.30 6031143.08 659828.21 N 70.49162809 W 148.69328232 600.00 7.44 32.10 543.16 599.11 24.43 24.48 21.03 12.47 2.51 2.47 4.18 6031152.51 659833.48 N 70.49165354 W 148.69323760 700.00 9.71 31.40 642.03 697.98 39.34 39.38 33.71 20.31 2.27 2.27 -0.70 6031165.36 659841.04 N 70.49168819 W 148.69317356 800.00 11.51 31.23 740.32 796.27 57.75 57.80 49.44 29.88 1.80 1.80 -0.17 6031181.29 659850.26 N 70.49173116 W 148.69309535 900.00 13.75 32.18 837.89 893.84 79.61 79.66 68.03 41.38 2.25 2.24 0.95 6031200.12 659861.36 N 70.49178195 W 148.69300131 1000.00 15.40 34.25 934.67 990.62 104.77 104.82 89.07 55.18 1.73 1.65 2.07 6031221.45 659874.71 N 70.49183942 W 148.69288848 1100.00 16.84 32.74 1030.74 1086.69 132.53 132.58 112.23 70.49 1.50 1.44 -1.51 6031244.93 659889.52 N 70.49190269 W 148.69276334 1200.00 20.54 29.51 1125.45 1181.40 164.54 164.62 139.69 86.97 3.84 3.70 -3.23 6031272.74 659905.40 N 70.49197771 W 148.69262862 1300.00 24.13 30.85 1217.93 1273.88 202.50 202.61 172.52 106.10 3.63 3.59 1.34 6031305.96 659923.82 N 70.49206739 W 148.69247224 1400.00 26.13 35.51 1308.47 1364.42 244.93 245.06 208.00 129.38 2.81 2.00 4.66 6031341.93 659946.33 N 70.49216431 W 148.69228196 1500.00 28.75 35.87 1397.21 1453.16 290.94 291.13 245.42 156.26 2.63 2.62 0.36 6031379.92 659972.40 N 70.49226654 W 148.69206216 1593.00 33.42 42.33 1476.86 1532.81 338.55 339.10 282.51 186.64 6.16 5.02 6.95 6031417.65 660001.97 N 70.49236786 W 148.69181383 1687.00 35.44 37.97 1554.40 1610.35 391.21 392.23 323.14 220.85 3.39 2.15 -4.64 6031459.01 660035.30 N 70.49247886 W 148.69153418 1788.80 37.44 34.57 1636.30 1692.25 451.53 452.68 371.89 256.57 2.79 1.96 -3.34 6031508.52 660069.96 N 70.49261205 W 148.69124214 1877.92 38.89 33.70 1706.37 1762.32 506.58 507.75 417.48 287.47 1.74 1.63 -0.98 6031554.75 660099.87 N 70.49273658 W 148.69098956 1973.57 40.37 32.17 1780.04 1835.99 567.58 568.75 468.68 320.62 1.85 1.55 -1.60 6031606.65 660131.91 N 70.49287646 W 148.69071850 2068.95 43.06 32.11 1851.23 1907.18 631.04 632.21 522.42 354.38 2.82 2.82 -0.06 6031661.10 660164.51 N 70.49302326 W 148.69044249 2165.44 45.01 31.85 1920.59 1976.54 698.11 699.28 579.31 389.90 2.03 2.02 -0.27 6031718.73 660198.79 N 70.49317867 W 148.69015211 2260.93 45.07 35.99 1988.08 2044.03 765.63 766.84 635.36 427.59 3.07 0.06 4.34 6031775.57 660235.27 N 70.49333177 W 148.68984397 2355.54 45.24 28.99 2054.84 2110.79 832.62 833.87 691.87 463.58 5.25 0.18 -7.40 6031832.84 660270.02 N 70.49348615 W 148.68954978 2451.28 44.70 29.18 2122.57 2178.52 900.16 901.54 751.00 496.47 0.58 -0.56 0.20 6031892.66 660301.63 N 70.49364768 W 148.68928086 2548.74 44.42 29.05 2192.02 2247.97 968.42 969.92 810.74 529.74 0.30 -0.29 -0.13 6031953.10 660333.61 N 70.49381089 W 148.68900881 2644.00 44.05 29.44 2260.27 2316.22 1034.76 1036.37 868.73 562.20 0.48 -0.39 0.41 6032011.77 660364.82 N 70.49396928 W 148.68874337 2736.58 43.33 30.12 2327.21 2383.16 1098.63 1100.32 924.23 593.96 0.93 -0.78 0.73 6032067.94 660395.38 N 70.49412091 W 148.68848369 2831.27 45.75 31.07 2394.70 2450.65 1165.00 1166.73 981.39 627.77 2.65 2.56 1.00 6032125.80 660427.95 N 70.49427705 W 148.68820723 2926.69 46.52 31.98 2460.82 2516.77 1233.78 1235.53 1040.03 663.75 1.06 0.81 0.95 6032185.20 660462.65 N 70.49443723 W 148.68791310 3023.07 46.80 31.67 2526.97 2582.92 1303.87 1305.62 1099.59 700.71 0.37 0.29 -0.32 6032245.53 660498.32 N 70.49459993 W 148.68761086 3121.95 47.46 32.54 2594.24 2650.19 1376.34 137809 1160.97 739.23 0.93 0.67 0.88 6032307.73 660535.51 N 70.49476761 W 148.68729591 3216.71 44.98 32.81 2659.80 2715.75 1444.75 1446.50 1218.56 776.16 2.63 -2.62 0.28 6032366.09 660571.19 N 70.49492492 W 148.68699393 3309.14 44.15 32.65 2725.65 2781.60 1509.61 1511.36 1273.12 811.23 0.91 -0.90 -0.17 6032421.39 660605.08 N 70.49507396 W 148.68670717 3403.18 44.47 32.64 2792.94 2848.89 1575.30 1577.05 1328.43 846.66 0.34 0.34 -0.01 6032477.45 660639.31 N 70.49522506 W 148.68841740 3499.30 44.22 32.36 2861.68 2917.63 1642.48 1644.24 1385.10 882.76 0.33 -0.26 -0.29 6032534.87 660674.18 N 70.49537985 W 148.68612221 3594.81 43.82 32.92 2930.37 2986.32 1708.85 1710.61 1440.98 918.56 0.58 -0.42 0.59 6032591.51 660708.77 N 70.49553252 W 148.68582948 3688.34 43.93 32.29 2997.79 3053.74 1773.68 1775.43 1495.59 953.49 0.48 0.12 -0.67 6032646.85 660742.51 N 70.49568169 W 148.68554384 3784.70 44.01 33.16 3067.14 312309 1840.58 1842.33 1551.87 989.65 0.63 0.08 0.90 6032703.89 660777.46 N 70.49583542 W 148.68524808 3878.03 43.59 33.33 3134.50 3190.45 1905.17 1906.93 1605.90 1025.07 0.47 -0.45 0.18 6032758.66 660811.70 N 70.49598300 W 148.68495848 3908.54 43.33 32.67 3156.65 3212.60 1926.16 1927.92 1623.50 1036.50 1.71 -0.85 -2.16 6032776.50 660822.75 N 70.49603108 W 148.68486500 4042.79 42.26 32.99 3255.16 3311.11 2017.36 2019.12 1700.14 1085.94 0.81 -0.80 0.24 6032854.18 660870.53 N 70.49624043 W 148.68446065 4135.87 42.71 35.09 3323.80 3379.75 2080.20 2081.98 1752.22 1121.13 1.60 0.48 2.26 6032907.01 660904.59 N 70.49638270 W 148.68417286 4231.33 42.91 33.84 3393.83 3449.78 2145.03 2146.85 1805.71 1157.84 0.91 0.21 -1.31 6032961 .26 660940.14 N 70.49652879 W 148.68387265 4325.25 44.14 31.95 3461.93 3517.88 2209.70 2211.53 1860.02 1192.95 1.91 1.31 -201 6033016.31 660974.07 N 70.49667715 W 148.68358548 4420.36 46.14 31.14 3529.02 3584.97 2277.10 2278.94 1917.47 1228.22 2.19 2.10 -0.85 6033074.51 661008.09 N 70.49683409 W 148.68329709 4514.00 45.79 30.75 3594.11 3650.06 2344.40 2346.26 1975.21 1262.83 0.48 -0.37 -0.42 6033132.97 661041.45 N 70.49699180 W 148.68301397 4608.46 45.15 30.98 3660.35 3716.30 2411.70 2413.60 2033.01 1297.38 0.70 -0.68 0.24 6033191.50 661074.75 N 70.49714969 W 148.68273142 4701.83 44.64 30.76 3726.49 3782.44 2477.58 2479.50 2089.58 1331.19 0.57 -0.55 -0.24 6033248.77 661107.33 N 70.49730421 W 148.68245486 4796.18 44.30 31.10 3793.82 3849.77 2543.64 2545.60 2146.27 1365.16 0.44 -0.36 0.36 6033306.18 661140.08 N 70.49745908 W 148.68217700 SurveyEditor Ver 3.1 RT-SP3.03-HF4.00 Bld( do31rt-546 ) NS32\NS32\NS32\NS32 Generated 5/6/2004 10:53 AM Page 1 of 2 ~- e e Measufod I Inclination Azimuth I Sub-Sea TVD I TVD Vertical I Along Hole I NS EW I DLS I Build Rate I Walk Rate I Northing Easting Latitude Longitude Depth Section Departure (II) (deg) (deg) (II) (II) (II) (II) (II) (II) (degl100 II) (deg1100 II) (deg/100 II) (IIUS) (IIUS) 4890.94 43.99 31.90 3861.82 3917.77 2609.63 2611.59 2202.54 1399.65 0.67 -0.33 0.84 6033363.18 661173.34 N 70.49761279 W 148.68189496 4985.47 43.63 31.02 393004 3985.99 2675.05 2677.03 2258.36 1433.80 0.75 -0.38 -0.93 6033419.71 661206.28 N 70.49776526 W 148.68161560 5078.76 43.67 30.59 3997.54 4053.49 2739.42 2741.43 2313.67 1466.78 0.32 0.04 -0.46 6033475.71 661238.06 N 70.49791633 W 148.68134586 5173.84 43.55 30.26 4066.38 4122.33 2804.95 2807.01 2370.22 1499.99 0.27 -0.13 -0.35 6033532.96 661270.05 N 70.49807080 W 148.68107421 5267.96 44.75 30.73 4133.92 4189.87 2870.46 2872.57 2426.71 1533.26 1.32 1.27 0.50 6033590.15 661302.09 N 70.49822510 W 148.68080206 5362.31 45.89 31.93 4200.26 4256.21 2937.53 2939.65 2484.01 1568.14 1.51 1.21 1.27 6033648.18 661335.74 N 70.49838161 W 148.68051669 5455.68 45.81 31.33 4265.29 4321.24 3004.52 3006.64 2541.05 1603.28 0.47 -0.09 -0.64 6033705.96 66136963 N 70.49853742 W 148.68022929 5551.25 45.81 30.14 4331.91 4387.86 3073.00 3075.17 2599.95 1638.30 0.89 0.00 -1.25 6033765.59 66140338 N 70.49869830 W 148.67994282 5643.95 46.20 31.99 4396.30 4452.25 3139.66 3141.86 265707 1672.71 1.50 0.42 2.00 6033823.43 661436.55 N 70.49885432 W 148.67966132 5738.05 45.45 32.44 4461.88 4517.83 3207.15 3209.34 2714.17 1708.69 0.87 -0.80 0.48 6033881.29 661471.29 N 70.49901029 W 148.67936702 5832.29 45.55 32.00 4527.93 4583.88 3274.37 3276.56 2771.03 1744.53 0.35 0.11 -0.47 6033938.90 661505.90 N 70.49916561 W 148.67907385 5928.53 45.58 32.44 4595.31 4651.26 3343.08 3345.28 2829.17 1781.16 0.33 0.03 0.46 6033997.81 661541.27 N 70.49932441 W 148.67877412 6023.86 44.92 32.00 4662.42 4718.37 3410.78 3412.98 2886.44 1817.26 077 -0.69 -0.46 6034055.85 661576.13 N 70.49948085 W 148.67847882 6117.78 43.93 32.94 4729.50 4785.45 3476.52 3478.72 2941.91 1852.55 1.27 -1.05 1.00 6034112.05 661610.22 N 70.49963235 W 148.67819013 6213.02 42.40 34.10 4798.96 4854.91 3541.86 3543.87 2996.23 1888.52 1.81 -1.61 1.22 6034167.13 661645.01 N 70.49978072 W 148.67789587 6307.88 40.24 34.39 4870.20 4926.15 3604.27 3606.50 3048.00 1923.76 2.29 -2.28 0.31 6034219.64 661679.12 N 70.49992214 W 148.67760758 6403.61 38.99 34.24 4943.94 4999.89 3665.28 3667.54 3098.42 1958.17 1.31 -1.31 -0.16 6034270.78 661712.44 N 70.50005984 W 148.67732607 6499.20 36.05 34.60 5019.75 5075.70 3723.46 3725.75 3146.44 1991.07 3.08 -3.08 0.38 6034319.50 66174430 N 70.50019100 W 148.67705692 6592.81 34.63 34.63 5096.11 5152.06 3777.57 3779.90 3191.00 2021.83 1.52 -1.52 0.03 6034364.71 661774.09 N 70.50031272 W 148.67680529 6688.03 32.73 32.97 5175.35 5231.30 3830.36 3832.70 3234.86 2051.22 2.22 -2.00 -1.74 6034409.19 661802.52 N 70.50043252 W 148.67656487 6781.57 31.90 32.96 5254.40 5310.35 3880.36 3882.70 3276.82 2078.42 0.89 -0.89 -0.01 6034451.71 661828.82 N 70.50054711 W 148.67634227 6878.86 29.78 33.57 5337.93 5393.88 3930.23 3932.57 3318.52 2105.77 2.20 -2.18 0.63 6034493.99 661855.27 N 70.50086102 W 148.67611852 6975.05 26.79 34.22 5422.62 5478.57 3975.79 3978.15 3356.36 2131.18 3.12 -3.11 0.68 6034532.36 66187985 N 70.50076437 W 148.67591066 7070.33 24.85 33.73 5508.39 5564.34 4017.27 4019.64 3390.77 2154.37 2.05 -2.04 -0.51 6034567.26 661902.30 N 70.50085835 W 148.67572089 7165.95 25.12 32.44 5595.06 5651.01 4057.66 4060.03 3424.61 2176.42 0.64 0.28 -1.35 6034601.56 661923.61 N 70.50095077 W 148.67554053 7260.52 25.07 32.08 5680.70 5736.65 4097.77 4100.14 3458.52 2197.82 0.17 -0.05 -0.38 6034635.93 661944.28 N 70.50104341 W 148.67536537 7355.63 25.37 32.78 5786.75 5822.70 4138.29 4140.66 3492.73 2219.56 0.44 0.32 0.74 6034670.59 661965.27 N 70.50113684 W 148.67518754 7451.05 25.38 32.00 5852.96 5908.91 4179.18 4181.56 3527.26 2241.46 0.35 0.01 -0.82 6034705.58 661986.43 N 70.50123115 W 148.67500832 7546.03 25.71 32.27 5938.66 5994.61 4220.14 4222.51 3561.94 2263.25 0.37 0.35 0.28 6034740.72 662007.46 N 70.50132588 W 148.67483006 7642.73 25.54 31.88 6025.85 6081.80 4261.96 4264.33 3597.37 2285.46 0.25 .-0.18 -0.40 6034776.62 662028.90 N 70.50142266 W 148.67464835 7738.30 25.62 32.04 6112.05 6168.00 4303.22 4305.60 3632.38 2307.30 0.11 0.08 0.17 6034812.09 662049.99 N 70.50151829 W 148.67446962 7833.00 25.70 32.28 6197.41 6253.36 4344.22 4346.61 3667.10 2329.13 0.14 0.08 0.25 6034847.27 662071.06 N 70.50161311 W 148.67429102 7929.99 25.73 32.37 6284.79 6340.74 4386.31 4388.69 3702.66 2351.63 0.05 0.03 0.09 6034883.30 662092.79 N 70.50171024 W 148.67410689 8035.10 25.95 32.15 6379.39 6435.34 4432.12 4434.50 3741.40 2376.08 0.23 0.21 -0.21 6034922.56 662116.41 N 70.50181605 W 148.67390680 8159.36 28.11 31.73 6490.07 6546.02 4488.58 4490.97 3789.32 2405.95 1.75 1.74 -0.34 6034971.11 662145.23 N 70.50194694 W 148.67366241 8254.81 31.89 29.61 6572.72 6628.67 4536.26 4538.68 3830.39 2430.24 4.11 3.96 -2.22 6035012.68 662168.64 N 70.50205909 W 148.67346362 8299.81 33.39 30.48 6610.62 6666.57 4560.51 4562.95 3851.39 2442.40 3.49 3.33 1.93 6035033.94 662180.33 N 70.50211647 W 148.67336415 8321.00 33.39 30.48 6628.31 6684.26 4572.16 4574.61 3861.44 2448.31 0.00 0.00 0.00 6035044.11 662186.03 N 70.50214392 W 148.67331575 Leqal Description: Northinq IYI IftUSl Eastinq IX) IftUSl Surface: 1358 FSL649 FEL S11 T13N R13E UM 6031131.22 659821.46 BHL: 5219 FSL 3478 FEL S12 T13N R13E UM 6035044.11 662186.03 SurveyEditor Ver 3.1 RT-SP3.03-HF4.00 Bld( do31rt-546 ) NS32\NS32\NS32\NS32 Generated 5/6/2004 10:53 AM Page 2 of 2 U..S. Department of the Inte~i_ Submit ORIGINAL plus THRE.ieS, OMB Control Number 1010-0046 Minerals Management Servlc"""MS) with one copy marked "Public Information" OMB. Ap.p ro..v...a. I~Ex ...;...·.I'.es 10/3112005 <,"",\,,~ ... ~",:,.", END OF OPERATIONS REPORT (ReplacesweIlSumma~R~port) 1.g COMPLETION 0 WORKOVER 2. API WELL NO. (12 Digits) 3. PRODUCING 4. OPERATOR NAME and ADDRESS INTERVAL CODE (Submitting OffIce) o ABANDONMENT 0 CORRECTION o OTHER 5. WELL NAME 50-029-23179-00-00 XOl BP Exploration, Alaska PO Box 196612 Anchorage, AI( 99519-6612 6. SIDETRACK NO. 7. BYPASS NO. 8. MMS OPERATOR NO. NS32i STOO BPOO 00113 WELL AT TOTAL DEPTH WELL AT PRODUCING ZONE 9. LEASE NO. 14. LEASE NO. OCS-YOI81 OCS-YOI81 10. AREA NAME 15. AREA NAME Beechy Point Beechy Point 11. BLOCK NO. 16. BLOCK NO. 516 516 12. LAMUDE o NAD 27 (GOM & Pacific) H NAD 83 (Alaska) 13. LONGITUDE o NAD 27 (GOM & Pacific) H NAD 83 (Alaska) 17. LATITUDE o NAD 27 (GOM & Pacific) H NAD 83 (Alaska) 18. LONGITUDE o NAD 27 (GOM & Pacific) H NAD 83 (Alaska) WELL STATUS INFORMATION 19. WELL STATUS 20. TYPE CODE 21. WELL STATUS DATE 22. KOP(MD)STIBP COM IDS 05/02/04 0' PERFORATED INTERVAL(S) THIS COMPLETION 25. BOTTOM (MD) 26. TOP (TVD) 23. TOTAL DEPTH (Sutveyed) MD 8321' TVD 6684' 24. TOP (MD) 27. BOTTOM (TVD) 8106' Open Hole 8321' Open Hole 28. RESERVOIR NAME Ugnu 1 Schrader Bluff 29. NAME(S) OF PRODUCING FORMATlON(S) THIS COMPLETION Ugnu 1 Schrader Bluff 30. PROTECTION PROVIDED DYES g NO SUBSEA COMPLETION 31. BUOY INSTALLED DYES g NO 32. TREE HEIGHT ABOVE MUDUNE N/A 33. INTERVAL NAME N/A HYDROCARBON BEARING INTERVALS 34. TOP (MD) 35. BOTTOM (MD) 36. TYPE OF HYDROCARBON MMS FORM MMS-125 (October 2002 - Supersedes all previous versions of form MMS-125 which may not be used.) Page 1 of2 END OF OPERATIONSal:PORT (Continued) . !IT OF SIGNIFICANT MARKERS PENET~ED 37. NAME 38. TOP (MO) 37. NAME SV4 4576' UG3 38. TOP (MO) 6876' SV3 4906' UG1 5143' WS2 5731' WS1 7423' SV2 7639' SV1 8065' 39. CASING SIZE ABANDONMENT HISTORY OF WELL 40. CASING CUT DATE 41. CASING CUT METHOD 42. CASING CUT DEPTH 43. TYPE OF OBSTRUCTION N/A 44. PROTECTION PROVIDED o YES ~NO 45. BUOY INSTALLED o YES ~NO 46. OBSTRUCTION HEIGHT ABOVE MUDLlNE N/A 47. CONTACT NAME Robert Clump so. AUTHORIZING OFFICIAL (Type or Print Name) Robert Clump 52. AUTHORIZING SIGNATURE n A ~ '-"4"--' 48. CONTACT TELEPHONE NO. 564-4672 49. CONTACT E-MAIL ADDRESS ClumpRC@bp.com 51. TITLE Drilling Engineer 53. DATE ~/Z4 /0+ PAPERWORKREDUC11ON ACT OF 1995 (PRA) STATEMENT: The PRA (44 U.S.C. 3501 m....œ. Requires us to inform )OUthat we c:oIIed \his information to obtain knowledge of equipment and procedures to be used in dtiUing operation$. MMS uses tha infotmation to evaluate and approve or disapprow tha adequacy of tha equipment and/or procedures to safely perform tha proposed drilling operation. Responses are mandatory (43 U.S.C. 1334). Proprietary data are CO\IeAId under 30 CFR 250.196. An agency may not conduGI or sponsor, and a person Is not required to respond to, a ooIIection of information unless . displays a currenlJy valid OMS Control Number. Public reporting butden for \his form Is estimated to average 2% hours per response, including the time tor reviewing instructions, gathering and mainIainIng data, and completing and reviewing the form. Direct oom_ regarding the butden estimate or any other aspect of \his form to the Information Collection Clearance Ofrooer. Mail Stop 4230. Mi'*1IIs Managemant Service. 1849 C Street, N.W., Washington. DC 20240. MMS FORM MMS-125 (October 2002 - Supersedes all previous versions of form MM5-125 which may not be used.) Page 2 of 2 e TREE:ABB-VGI5 1/S· 5ksi WELLHEAD:ABB-VGI11· Mulitbowl5ksi (Note: Hanger - 4" BPV/TWC) 20". 169# X-56 @ 200' MD - 10 3/4·, 45.5#/ft, L-SO, BTC @3964' MD 4.5·. 12.6#/ft, L-SO, IBT-MOD TUBING ID: 3.95S" CAPACITY: 0.0152 BBLlFT 4.5· 'XN' NIPPLE, @ SOSS' 3.725" ID (HES) 7 5/S", 29.7#/ft L-SO, BTC-M @S107 'MD TD @S321' MD 66S4' TVD DATE 6/18/03 1/5104 5/11/04 REV. BY JAS JAS RAC COMMENTS Initial Diagram PropOsed Completion Completion 5/2/04 NS32 í I .. , ~ J~ '''I' e RKB. ELEV = 55.95' KB-BF. ELEV = 40.05' BASE FLANGE ELEV = 15.9' 7-5/S·x 4-1/2· Annulus Freeze rotected to 2000' TVD wi 60 bbls of Inhibited Diesel Heat Trace Starting @ 2097' MD 'X' Nipple @ 2169' MD 3.S13· ID I Cement " ! --r- ~-~ . I j ~ lit,~ - '. 4.5"WLEG,@S100'MD Baker 7-5/S· x 4-1/2· ·S-3· PACKER 3.S75·ID @5102' MD 63/4· open hole Northstar WFU : NS32 API NO: 50-029-23179 BP Exploration (Alaska) e e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: NS32 NS32 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 33E Start: 11/14/2003 Rig Release: Rig Number: 33E Spud Date: 11/15/2003 End: 11/14/2003 00:00 - 00:30 0.50 MOB P PRE - PJSM I ATP for skidding rig to NS-32 wI rig & Ops personnel. - Released rig from NS-29 RWO @ 00:00 on 11-14-03 00:30 - 04:30 4.00 MOB P PRE - Prepare for skidding rig while Prod. continues bleeding down NS-31 to 0 psi. 04:30 - 06:00 1.50 MOB P PRE - Skid rig towards NS-32 - Moving back into area that was not leveled or brought up to grade with additional gravel this summer due to the rig being stacked out in this area during the summer. - Shimming over flow lines as rig is being moved. 06:00 - 07:00 1.00 MOB P PRE - Shut down rig move while Production personnel C/O. Rig crew to breakfast. - Renew permits 07:00 - 08:00 1.00 MOB P PRE - Skid rig over NS-32. - Accept rig @ 0800 hrs. 08:00 - 12:00 4.00 RIGU P PRE - Shim rig & clean up around NS-29. 12:00 - 20:00 8.00 RIGU P PRE - PJSM - RIU surface riser. (had to modify) - Install drain valves on conductor - Transfer fluid between L pits & pits. - Test lines - Continue mixing spud mud. 20:00 - 21 :30 1.50 RIGU P PRE - PJSM - slip & cut drilling line. 21 :30 - 22:00 0.50 RIGU P PRE - Install iron roughneck track. 22:00 - 22:30 0.50 RIGU P PRE - Calibrate Anadrill block height decoder. 22:30 - 00:00 1.50 RIGU P PRE - PJSM - PIU HWDP from pipeshed & MIU stands & rack back. 11/15/2003 00:00 - 01 :30 1.50 MOB P SURF - P/U HWDP, jars, & stand back in derrick. 01 :30 - 04:00 2.50 MOB P SURF - MIU BHA 04:00 - 05:30 1.50 MOB P SURF - PJSM - RIU Schlumberger for gyro surveys. 05:30 - 06:00 0.50 MOB P SURF - Pre spud meeting wI Leigh's crew to discuss objectives of well & hazards of hole section. - Reviewed 0-7 drill (shallow gas wlo diverter) Complete items on pre spud list. 06:00 - 07:00 1.00 MOB P SURF - Fill riser wI sea water - leaking @ drip pan. - Test mud lines to 3800 psi 07:00 - 07:30 0.50 MOB P SURF - B/D all lines 07:30 - 08:00 0.50 MOB N RREP SURF - Stand back BHA. 08:00 - 12:00 4.00 MOB N RREP SURF - PJSM - Drain riser & pull to reseal at drip pan. - Reinstall 12:00 - 13:30 1.50 MOB N RREP SURF - PJSM - Pull riser & remove gasket. Reinstall using sealant wlo gasket. 13:30 - 14:30 1.00 MOB P SURF - Pre spud meeting wI Wood's crew to discuss objectives of well & hazards of hole section. - Reviewed 0-7 drill (shallow gas w/o diverter) 14:30 - 16:00 1.50 DRILL P SURF - Clean out conductor & drill to 218'. 16:00 - 16:30 0.50 DRILL P SURF - Run gyro survey. - Survey at base of conductor indicates AZ of 31.79 deg, which lines up excellent with our proposed AZ of 32.59 deg. 16:30 - 17:30 1.00 DRILL P SURF - Continue drilling 13 1/2" hole to 334'. 17:30 - 18:30 1.00 DRILL P SURF - Condition mud & circulate for trip to change out BHA. 18:30 - 19:00 0.50 DRILL P SURF - POH & UD BHA #1. 19:00 - 20:30 1.50 DRILL P SURF - PIU BHA #2 & RIH. 20:30 - 21:00 0.50 DRILL P SURF - Continue drilling 13 1/2" hole to 368'. - Pumping red mud sweeps prior to running gyros. 21 :00 - 22:00 1.00 DRILL P SURF - Run gyro survey. Printed: 51312004 9:02:38 AM e e BP EXPLORATION '''..,.-'-'",...-. ,. .... .....'......., Operations Summary Report Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: NS32 NS32 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 33E Hours 11/15/2003 22:00 - 00:00 11/16/2003 00:00-12:00 2.00 DRILL P 12.00 DRILL P SURF SURF 12:00 - 12:30 0.50 DRILL P SURF 12:30 - 13:30 1.00 DRILL P SURF 13:30 - 14:30 1.00 DRILL P SURF 14:30 - 00:00 9.50 DRILL P SURF 11/17/2003 00:00 - 02:00 2.00 DRILL N RREP SURF 02:00 - 09:00 7.00 DRILL P SURF 09:00 - 10:30 1.50 DRILL P SURF 10:30 - 11 :00 0.50 DRILL P SURF 11 :00 - 19:30 8.50 DRILL P SURF 19:30 - 20:00 0.50 DRILL P SURF 20:00 - 20:30 0.50 DRILL P SURF 20:30 - 23:00 2.50 DRILL P SURF 23:00 - 00:00 1.00 DRILL P SURF 11/18/2003 00:00 - 00:30 0.50 DRILL P SURF 00:30 - 04:30 4.00 DRILL P SURF 04:30 - 06:00 1.50 DRILL P SURF 06:00 - 06:30 0.50 DRILL P SURF 06:30 - 09:30 3.00 DRILL P SURF 09:30 - 14:00 4.50 DRILL P SURF 14:00 - 14:30 0.50 CASE P SURF 14:30 - 16:30 2.00 CASE P SURF 16:30 - 00:00 7.50 CASE P SURF 11/19/2003 00:00 - 00:30 0.50 CASE P SURF 00:30 - 02:00 1.50 CEMT P SURF 02:00 - 02:45 0.75 CEMT P SURF 02:45 - 03:30 0.75 CEMT P SURF 03:30 - 06:30 3.00 CEMT P SURF 06:30 - 07:30 1.00 CEMT P SURF Start: 11/14/2003 Rig Release: Rig Number: 33E Spud Date: 11/15/2003 End: - Drill & slide from 368' to 728'. - Drill directional in 131/2" hole from 723' to 1855' MD. - Pumping red mud sweeps prior to gyros & as needed to aid in hole cleaning. - Circulate sweep to prep for gyro. - Run gyro & confirm MWD within JORPS. - UD gyro & RID Schlumberger. - Drill directional in 131/2" hole from 1855' to 3221' MD. - Last survey Incl. 44.92 deg Az. 34.25 deg Replace pin in pipe grapper on Top Drive. Drill ahead in 13 1/2" hole to casing point @ 3,980 ft. Sweep hole. Circ & cond mud for logs. Flow check well static. Blow down surface circ system POH w/13 1/2" bit. Work tight hole @ 2170 - 1948 ft. Pump thru 1735 - 1665 ft. Rack BHA in derrick. LD MWD. PJSM w/ Schl e line crew RU Schl e line, no pressure control equip. Schl RIH w/ PEX logging suite. Unable to work past 1,770 ft. POH w/logs. RD Schl. MU & RIH w/13 1/2" bit. Surface test MWD. Blow down lines. RIH w/13 1/2" bit. Wash thru following area. 1855 - 2042 ft 3833 - 3980 ft Circ & cond mud. 8.5 BPM - 1800 psi Flow check showing well static. Blow down lines. POH w/13 1/2" bit to BHA. Hole fill reflects well stable. LD BHA. PJSM for surface casing. RU floor for runing 103/4" surface casing. RIH w/10 3/4" surface casing to 3920 ft. Avg 5800 MU TQ - MIU hanger & wash down landing jt @ 3.5 BPM - 450 psi. - Ran a total of 95 jts 103/4" 45.50# buttress casing. - Hole was slick -landed casing w/135K - Stage up pump & circulate 1 1/2 BIU prior to cement job. - ICP @ 1.5 BPM 270 psi - FCP @ 6 BPM 288 psi. - Held PJSM for cement job while circulating. - RID Frank's fillup tool & RlU Halliburton cement head & x-over. - Continue circulate & condition mud - adding water to thin mud to less than 25 YP. - Add 8 sx bicarb prior to cementing - ICP @ 7 BPM 300 psi - FCP @ 10 BPM 400 psi. - Pump 5 bbls sea water & test lines to 3000 psi - Pump 75 bbls. 10.5 ppg weighted spacer & drop plug. - Pump 455 bbls 10.7ppg lead cement (615 sx) - Pump 82 bbls 15.9 ppg tail cement (400 sx) - Drop plug & flush lines wI 25 bbls sea water. - Displace cement & bump plug wI 350 bbls mud @ 95% pump efficiency. Printed: 51312004 9:02:38 AM -- e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: NS32 NS32 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 33E Start: 11/14/2003 Rig Release: Rig Number: 33E Spud Date: 11/15/2003 End: 11119/2003 06:30 - 07:30 1.00 CEMT P SURF - Hold 2200 psi for 5 minutes & bleed off. Floats holding. - No losses throughout cement job. 07:30 - 10:00 2.50 CEMT P SURF - RID cement head - Clean floor - UD Landing jt. - Clear floor - Change bails 10:00 - 12:00 2.00 CEMT P SURF - Service TO - change pin in grabber. 12:00 - 15:30 3.50 CEMT P SURF - Clean pits & weight up brine to 9.8 ppg. 15:30 - 17:30 2.00 CEMT P SURF - Repair TD. Adjust linkage to bails per Canrig Rep. 17:30 - 20:00 2.50 CEMT P SURF - RIH to displace mud to 9.8 ppg brine 20:00 - 20:30 0.50 CEMT P SURF - PJSM - Well displacement 20:30 - 21 :00 0.50 CEMT P SURF - Wash down & tag cement 11' above FC @ 3866'. 21 :00 - 22:30 1.50 CEMT P SURF - Displace well wI 80 bbls sea water, followed by 50 bbls hi vis spacer, followed by 100 bbls sea water, followed by 400 bbls 9.8 ppg brine. - Rotate (35 RPM) & reciprocate while displacing to brine @ 10 BPM 400 psi. All returns going to G & I via drag chain. 22:30 - 00:00 1.50 CEMT P SURF -POH 11/20/2003 00:00 - 00:30 0.50 CEMT P SURF - POH & break off bit. 00:30 - 00:00 23.50 CEMT N WAIT SURF - Waiting on E-line Ops to complete setting IBP portion of the pre-rig work on NS-27 before USIT log can be run on NS-32. - Performing maintenance on rig as follows: - Remove pulsation dampener bladder in #1 mud pump & C/O. - Clean L pits - CIO ice scraper device on derrick climber. - Work on boiler. - Mix 9.3 brine wI 2% KCL for well kill on NS-27 - Make some preparations for rig move. 11/2112003 00:00 - 15:00 15.00 CEMT N WAIT SURF Continue waiting for E-line to complete pre rig work on NS-27. - Maintenance on rig while waiting. - Wireline Unit Finish IBP and Rig down from NS27. 15:00 - 16:00 1.00 CEMT P SURF PJSM in pre-tour meeting. Friday Rig Crew Change Out. - Deliver wireline tools & equipment to rig floor. 16:00 - 18:30 2.50 CEMT P SURF Prepare wireline unit of run - CIO spools on E-line unit. 18:30 - 19:30 1.00 CEMT P SURF PJSM - RlU with Schlumberger crews to run US IT logging tools. 19:30 - 23:00 3.50 CEMT N DFAL SURF RIH to 3844' wI USIT tools. Troubleshoot to detect problem wI tool string. - Arrange for helicopter to bring out another string of USIT tools. 23:00 - 00:00 1.00 CEMT N DFAL SURF POH & C/O USIT from Run #1. 11/22/2003 00:00 - 00:30 0.50 CEMT N DFAL SURF - Continue swapping out US IT logging tools. 00:30 - 05:00 4.50 CEMT N DFAL SURF - RIH wI US IT log. Unable to log. - Made 4 different runs to various depths with different combinations of transducers & cartridges trying to get log. o Interface between job site & Schlumberger management attempting to troubleshoot problems w/o success. 05:00 - 06:00 1.00 CEMT N DFAL SURF - PJSM - RID E-line crew 06:00 - 08:00 2.00 CEMT P SURF - RIH wI 5" HWDP & 5" DP & displace brine to leave 350' air gap. - Slick line RlU on NS-27 to complete pre rig work. (Dumping Printed: 51312004 9:02:38 AM tit e BP EXPLORATION Summary Report Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: NS32 NS32 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 33E Start: 11/14/2003 Rig Release: Rig Number: 33E Code NPT Phase 11/22/2003 06:00 - 08:00 2.00 CEMT P SURF 08:00 - 10:00 2.00 CEMT P SURF 10:00 - 11 :30 1.50 CEMT P SURF 11:30 - 12:30 1.00 CEMT P SURF 12:30 - 14:30 2.00 CEMT P SURF 14:30 - 18:00 3.50 CEMT N WAIT SURF 18:00 - 00:00 6.00 CEMT N WAIT SURF Spud Date: 11/15/2003 End: sluggit on top of IBP) - PJSM - N/D riser. - PJSM - N/U multi bowl ass'y & test to 2500 psi. - Install 4 1/2' hanger wI penetrator & test seals to 5000 psi. - Install cover plate & caps on well. - Clean cellar & prep for rig move. - Wait while slick line completes pre rig work on NS-27. 3 trips & dumped 5' of sluggit on top of IBP - Slick line RID @ 1800 hrs - PIU lubricator & set BPV on NS-27. - Review ATP's with rig crew, OPS, APC, & AIC. - Remove scaffolding from NS-27. - Remove "S' riser between tree & flow line. - Remove well house, bleed trailer, & other material required for rig move. - Function rig moving equip't. - Lay plywood on mats. - Inspect NS-27 w/ ACS Tech & complete pre drillsite checklist. - Release rig from NS-32 @ 00:00 on 11-23-03 12/3/2003 Prepare for Rig move. Perform A TP with drilling and ops. PJSM -- Rig move and Rig move checklist. Move rig from NS27 to NS32. Level rig and Pre-spud checklist. PJSM -- Nipple up BOPE. Clean rig floor and inspect equipment. PJSM. Write procedure for transferring 5' in derrick. Transfer 5' drill pipe and 5" HWDP to off driller's side. 60 stands total. PJSM. Change out to 4" handling equipment. RIH with 4' drillpipe. Joints #1 - #92. 12/4/2003 Continue to PU 4' HT-40 drill pipe Ooint #93 - #111). POOH with 9 stands of 4' drillpipe and rack back in derrick. Continue to PU 4" HT -40 drill pipe Ooint #111 - #138). POOH with 37 stands of 4' drillpipe and rack back in derrick. PJSM. Change 7" rams to 2-7/8' x 5' variable rams (top rams). Pull wear ring. Fill hole with 9.3 ppg brine. 1. 53 bbls total· 550' of 9.3 ppg brine. PJSM. Rig up to test BOP's. Attempt to test. Change out seal on the test plug. Attempt to test BOP. Test plug leak. Change out test plug. Attempt to test BOP. Test plug not seating. Install lower test plug. Fill stack. Test BOP's to 250 psi low and 4800 psi high for 5 min. Change out test plug. Test BOP's to 250 psi low and 4800 psi high for 5 min. Pull test plug and install wear ring. Blow down choke and kill lines and test pump. PJSM. Change out upper IBOP. Rig up and test upper IBOP. 12/5/2003 Continue testing BOP·s. Rig down from BOP test and blow down lines. 00:00 - 01 :00 1.00 MOB P PRE 01 :00 - 02:00 1.00 MOB P PRE 02:00 - 05:00 3.00 MOB P PRE 05:00 - 08:00 3.00 MOB P PRE 08:00 - 15:30 7.50 MOB P PRE 15:30 - 16:00 0.50 MOB P PRE 16:00 - 17:00 1.00 MOB P PRE 17:00 - 19:00 2.00 MOB P PRE 19:00 - 20:00 1.00 MOB P PRE 20:00 - 00:00 4.00 MOB P PRE 00:00 - 00:30 0.50 MOB P PRE 00:30 - 01 :00 0.50 MOB P PRE 01 :00 - 02:00 1.00 MOB P PRE 02:00 - 03:30 1.50 MOB P PRE 03:30 - 06:00 2.50 BOPSUF P PRE 06:00 - 06:30 0.50 BOPSUF P PRE 06:30 - 07:00 0.50 BOPSUF P PRE 07:00 - 07:30 0.50 BOPSUF P PRE 07:30 - 09:00 1.50 BOPSUF P PRE 09:00 - 09:30 0.50 BOPSUF P PRE 09:30 - 12:00 2.50 BOPSUF P PRE 12:00 - 12:30 0.50 BOPSUF P PRE 12:30 - 14:30 2.00 BOPSUF P PRE 14:30 - 15:00 0.50 BOPSUF P PRE 15:00 - 19:30 4.50 BOPSUP P PRE 19:30 - 20:00 0.50 BOPSUF P PRE 20:00 - 20:30 0.50 BOPSUF P PRE 20:30 - 23:30 3.00 BOPSUF P PRE 23:30 - 00:00 0.50 BOPSUF P PRE 00:00 - 00:30 0.50 BOPSUF P PRE 00:30 - 01:00 0.50 BOPSUF P PRE Printed: 51312004 9:02:38 AM e e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: NS32 NS32 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 33E Start: 11/14/2003 Rig Release: Rig Number: 33E Spud Date: 11/15/2003 End: 12/5/2003 01 :00 - 02:30 1.50 CASE P INT1 PJSM. Test casing to 3500 psi for 30 minutes. 1. The pressure increased at approximately 400 psi I 5 strokes. 2. 47 strokes were pumped to 3600 psi; approximately 4.5 bbls. 3. 6' liners in the pumps 02:30 - 03:00 0.50 DRILL P INT1 PJSM. Blow down mud lines. Change out from 4' tools to 5' tools. 03:00 - 06:00 3.00 DRILL P INT1 PJSM. Make up BHA #5. Drilling assembly for 9.7/8' hole. 06:00 - 06:30 0.50 DRILL P INT1 Function test MWD and motor. Blow down all lines. 06:30 - 07:00 0.50 DRILL P INT1 RIH with HWDP to 834' MD. 07:00 - 07:30 0.50 DRILL P INT1 Island muster drill and 0-1 drill. 07:30 - 08:30 1.00 DRILL P INT1 Continue to RIH with 5' drillpipe to 1,118' MD. 08:30 - 10:00 1.50 DRILL P INT1 Slip and cut drilling line. 10:00 - 11 :00 1.00 DRILL P INT1 Service drawworks, crown, and top drive. 11 :00 - 13:00 2.00 DRILL P INT1 Continue to RIH with 5' drillpipe to 3,755' MD. 13:00 - 14:30 1.50 DRILL P INT1 Displace the 9.8 pp brine to seawater while washing down / drilling cement to shoe. 14:30 - 15:30 1.00 DRILL P INT1 Set back a stand. Grease a valve on the mud manifold. Make connection. 15:30 - 16:30 1.00 DRILL P INT1 Wash down to 3,875' MD. No rotation, pumping at 140 SPM. Did not see any cement on top of the plug. 16:30 - 17:30 1.00 DRILL P INT1 Drill out float equipment. 17:30 - 18:30 1.00 DRILL P INT1 Clean out cement down to shoe at 3,959' MD. Displace well to 8.6 ppg seawater polymer mud using a 25 bbl hi-vis spacer. 18:30 - 19:00 0.50 DRILL P INT1 Continue displacement. 19:00 - 19:30 0.50 DRILL P INT1 Drill out shoe and clean out to 3,964' MD. 19:30 - 21 :00 1.50 DRILL P INT1 Circulate & condition mud. 8.6 ppg in lout. Mud at 60 degrees in lout. 1. Pump at 60 spm (6 BPM) with pump #1, 6' liners. 2. Pump 7500 strokes at 192 psi 3. Rotate at 30 rpm, no recprocation. 4. Torque at 8300 ftlbs. 21 :00 - 22:30 1.50 DRILL P INT1 RU. FIT test to 11.5 ppg EMW. Blow down lines. 1. Had difficulty with chart recorder, repeated test. 2. Charted test at 11.5 ppg EMW (490 psi) for 30 minutes. 22:30 - 23:00 0.50 DRILL P INT1 Cleanout rathole and drill from 3,980' MD to 4,000' MD. 23:00 - 23:30 0.50 DRILL P INT1 Circulate bottoms up until 8.6 ppg MW in and out (3600 strokes). 23:30 - 00:00 0.50 DRILL P INT1 RU. FIT test to 11.5 ppg EMW. Blow down lines. 1. Charted test at 11.5 ppg EMW (490 psi) for 30 minutes. 12/6/2003 00:00 - 02:00 2.00 DRILL P INT1 Drill 9-7/8' hole from 4,000' MD to 4,225' MD. 02:00 - 02:30 0.50 DRILL P INT1 Service Rig. Work on drawworks drum. 02:30 - 12:00 9.50 DRILL P INT1 Drilllslide 9-7/8' hole from 4,225' MD to 5,450' MD 1. Rotate 6.2 hours. Slide 0.6 hour. Total on bottom 6.8 hours. 2. Pumping high vis sweeps every 400'. Seeing increase at Printed: 5/312004 9:02:38 AM It e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: NS32 NS32 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 33E Start: 11/14/2003 Rig Release: Rig Number: 33E Spud Date: 11/15/2003 End: 12/6/2003 02:30 - 12:00 9.50 DRILL P INT1 shakers. 12:00 - 00:00 12.00 DRILL P INT1 Drill/slide 9-7/8" hole from 5,450' MD to 6,111' MD 1. Rotate 7.6 hours. Slide 1.8 hours. Total on bottom 9.4 hours. 2. Pumping high vis sweeps every 400'. Seeing increase at shakers. 3. Pump walnut sweep during slow drilling. No change. 4. Drilling SV sand/shale sequence. 12/7/2003 00:00 - 12:00 12.00 DRILL P INT1 Drill/slide 9-7/8" hole from 6,111' MD to 6,682' MD 1. Rotate 6.2 hours. Slide 3.8 hours. Total on bottom 10.0 hours. 2. Pumping high vis sweeps every 400'. Seeing increase at shakers. 12:00 - 00:00 12.00 DRILL P INT1 Drilllslide 9-7/8" hole from 6,682' MD to 7,130' MD 1. Rotate 6.1 hours. Slide 3.8 hours. Total on bottom 9.9 hours. 2. Pumping high vis sweeps every 400'. Seeing increase at shakers. 12/8/2003 00:00 - 01 :30 1.50 DRILL P INT1 Drill/slide 9-7/8" hole from 7,130' MD to 7,185' MD. 01 :30 - 02:00 0.50 DRILL C INT1 Service drawworks. 02:00 - 07:00 5.00 DRILL P INT1 Drill/slide 9-7/8" hole from 7,185' MD to 7,349' MD. 07:00 - 07:30 0.50 DRILL N RREP INT1 Check top drive RPM counter and brakes. 07:30 - 08:30 1.00 DRILL P INT1 Service top drive. 08:30 - 09:00 0.50 DRILL N RREP INT1 Change out RPM counter. 09:00 - 09:30 0.50 DRILL P INT1 Island power outage. 09:30 - 10:00 0.50 DRILL N RREP INT1 Continue to work on top drive. 10:00 - 00:00 14.00 DRILL P INT1 Drill/slide 9-7/8" hole from 7,349' MD to 8,110' MD. 1. Rotate 10.8 hours. Slide 0.4 hours. Total on bottom 11.2 hours. 2. Pumping high vis sweeps every 400'. 12/9/2003 00:00 - 01 :00 1.00 DRILL P INT1 Drilllslide 9-7/8" hole from 8,110' MD to 8,121' MD. 01 :00 - 02:30 1.50 DRILL P INT1 Condition mud and circulate. 1. Pump 25 bbI hi-vis sweep at TD. Saw increased cuttings at shakers at bottoms up. 2. Circulated 1.5 hole volumes. 02:30 - 03:00 0.50 DRILL P INT1 POOH first 5 stands wet from 8121' MD to 7730' MD. Good hole fill. 03:00 - 03:30 0.50 DRILL P INT1 Pump 20 bbls of 11.5 ppg dry job. Blow down top drive and mud line. Monitor well for 10 minutes. No flow. 03:30 - 05:30 2.00 DRILL P INT1 POOH from 7730' MD to 3959' MD. Good hole fill. 05:30 - 06:00 0.50 DRILL P INT1 Monitor well at shoe (3959' MD) for 15 minutes. Perform 0-1 drill. 06:00 - 06:30 0.50 DRILL P INT1 Service top drive and drawworks. 06:30 - 09:30 3.00 DRILL P INT1 RIH from 3959' MD to 8121' MD. Ream the last stand to bottom. 09:30 - 13:00 3.50 DRILL P INT1 Circulate and condition mud. Printed: 51312004 9:02:38 AM e e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: NS32 NS32 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 33E Start: 11/14/2003 Rig Release: Rig Number: 33E Spud Date: 11/15/2003 End: 12/9/2003 09:30 - 13:00 3.50 DRILL P INT1 1. Pump 50 bbl hi-vis sweep, surface to surface. 2. Circulate 3.5 bottoms up. 13:00 - 17:00 4.00 DRILL P INT1 POOH with driling assembly. No tight spots. 17:00 - 18:00 1.00 DRILL P INT1 Lay down BHA. 18:00 - 20:30 2.50 DRILL P INT1 PJSM. Rig up to run quad-combo wireilne logs. 20:30 - 00:00 3.50 DRILL P INT1 Run quad-combo wireline logs. 12/10/2003 00:00 - 03:00 3.00 DRILL P INT1 Continue to run WL logs. Once at-the shoe, a sufficient density log could not be displayed. Another pass of the hole was made after some parameters were changed in the tool. The second logging pass was successful. 03:00 - 03:30 0.50 DRILL P INT1 PJSM -- Rig down e-line. 03:30 - 05:00 1.50 DRILL P INT1 Load rig floor with casing and drill pipe tools to rig floor. VLE access will be blocked due to Slickline work. 05:00 - 06:00 1.00 DRILL P INT1 Make up BHA #6. 06:00 - 12:00 6.00 DRILL P INT1 RIH from 1017' MD with dril pipe to 8121' MD. Good hole fill. Well bore in good shape. 12:00 - 15:00 3.00 DRILL P INT1 Condition mud and ciruclate. 1. Pump 50 bbl hi-vis sweep, surface to surface. 2. Circulate 3.5 bottoms up. 15:00 -18:00 3.00 DRILL P INT1 Trip out of hole. No tight spots or overpulls. 18:00 - 20:30 2.50 DRILL P INT1 Lay down BHA. 20:30 - 21 :30 1.00 CASE P INT1 Pull wear bushing. Set test plug. 21 :30 - 22:00 0.50 CASE P INT1 PJSM for changing pipe rams. 22:00 - 23:30 1.50 CASE P INT1 Change upper pipe rams to 7-5/8" rams. 23:30 - 00:00 0.50 CASE P INT1 Test ram body to 3500 psi. 12/11/2003 00:00 - 00:30 0.50 CASE P INT1 LD test jt. Clear rig floor. 00:30 - 02:00 1.50 CASE P INT1 RU for 75/8' csg. Chg out bails. 02:00 - 08:00 6.00 CASE P INT1 MU & RIH w/7 5/8' csg as per program to 103/4' shoe @ 3980 ft. 08:00 - 09:00 1.00 CASE P INT1 CBU @ shoe. 9 BPM - 510 psi. PUW 165k, SOW 140k 09:00 - 15:00 6.00 CASE P INT1 Con't RIH w/7 5/8 csg to setting depth. MU hanger, land csg wI FS @ 8105 ft, FC @ 8060 ft, LC @ 8015 ft, ES CMTER @ 6152 ft, TAM @ 4135 ft. 15:00 - 16:30 1.50 CASE P INT1 RD Franks tool, MU cmt head. Circ & condition at 10 bpm. 16:30 - 17:00 0.50 CASE P INT1 PJSM on cementing operations. 17:00 - 19:30 2.50 CEMT P INT1 First Stage Cement: 1. Test lines to 3500 psi. 2. Drop 1 st stage bottom plug. 3. Load 1st stage top plug. 4. Pump 45 bbls spacer. 5. Pump 124 bbls of 15.9 ppg cement. 6. Chase with 25 bbls of seawater. 7. Pump 3430 stks to bump plug (96% eff). 8. Hold 1470 psi for 5 minutes and check floats holding. 9. Reciprocated pipe while cement tuming corner. 10. Lost 30 bbls of returns during cement job. 19:30 - 21 :30 2.00 CEMT P INT1 Second Stage Cement: Printed: 51312004 9:02:36 AM e e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: NS32 NS32 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 33E Start: 11/14/2003 Rig Release: Rig Number: 33E Spud Date: 11/15/2003 End: 12/11/2003 19:30 - 21:30 2.00 CEMT P INT1 1. Load 2nd stage plug. 2. Pressure up to 3400 psi to open ES Cementer. 3. Circulate cement out of hole. Approximately 15 bbls of cement back with a 11.5 ppg weight and 10.8 PH. 21 :30 - 22:30 1.00 CEMT P INT1 Second Stage Cement (Cont.) 1. PJSM for second stage job. 2. Pump 45 bbls. spacer. 3. Pump 43 bbls of 13.1 ppg lead slurry. 4. Pump 57 bbls of 15.9 ppg tail slurry. 5. Drop plug. 6. Pump 25 bbls of seawater. 7. Pump 257 bbl of mud (2560 strokes) with rig pumps (96% eff). 8. Close ES cementer, Confirmed closed. Hold 2200 psi. 22:30 - 23:30 1.00 CEMT P INT1 Lay down cement head. Back out upper part of landing joint. 23:30 - 00:00 0.50 CEMT P INT1 Rig up to run 4· drill pipe to open TAM port collar. 12/12/2003 00:00 - 00:30 0.50 CEMT P INT1 - M/U TAM port collar shifting tool. 00:30 - 02:30 2.00 CEMT P INT1 - RIH wI TAM port collar shifting tool on 4· DP to 4137' MD. 02:30 - 03:00 0.50 CEMT P INT1 - Open TAM port collar - Up wt. 125K, On wt 105K - Pressure up to 1000 psi, then bleed off to 300 psi. 03:00 - 04:00 1.00 CEMT P INT1 - CBU & PJSM for 3rd stage cement job. 04:00 - 06:30 2.50 CEMT P INT1 - Cement & close TAM port collar. - Pump 45 bbls. 10.5 spacer, 136 bbls 10.5 lead slurry, 46 bbls. 15.9 tail slurry. Displaced cement w/45 bbls sea water via Halliburton pump. 06:30 . 07:00 0.50 CEMT P INT1 - RID cement hose & B/D lines 07:00 - 09:00 2.00 CEMT P INT1 - POH & UD TAM shifting tool. 09:00 - 10:00 1.00 CEMT P INT1 - UD landing jt & CIO elevators from 4· to 5· 10:00 - 11:00 1.00 CEMT P INT1 - M/U packoff ass'y. - RIH & test packoff. (1st attempt failed)) 11 :00 - 12:00 1.00 CEMT P INT1 - Install bowl protector & flush BOP stack. 12:00 - 14:30 2.50 CEMT N SFAL INT1 - Packoff failed to test. - Pull bowl protector - Pull packoff. 14:30 - 15:30 1.00 CEMT N SFAL INT1 - Install new packoff & test to 5000 psi - Install bowl protector. 15:30 - 16:30 1.00 CEMT P INT1 - C/O saver sun on Top drive to handle 4· DP 16:30 - 18:00 1.50 CEMT P INT1 - PJSM to cut drilling line - Cut drilling line 18:00 - 19:30 1.50 CEMT P INT1 - PJSM - - P/U BHA # 7 19:30 - 23:00 3.50 CEMT P INT1 - RIH - picking up singles from pipeshed. 23:00 - 23:30 0.50 CEMT P INT1 - Rotate slowly thru TAM collar @ 4135'. - Wash through TAM port collar @ 4135'. - No cement detected in casing @ port collar. - Test casing to 1000 psi for 5 minutes. 23:30 - 00:00 0.50 CEMT P INT1 - Continue RIH. 12/13/2003 00:00 - 01 :30 1.50 CEMT P INT1 - RIH wI 4· DP - P/U singles out of pipeshed. 01:30-02:15 0.75 CEMT P INT1 - Tag cement @ 6060' - 92' above ES Cementer (4 bbls cement) Printed: 51312004 9:02:38 AM e e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: NS32 NS32 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 33E Start: 11/14/2003 Rig Release: Rig Number: 33E Spud Date: 11/15/2003 End: 12/13/2003 01:30 - 02:15 0.75 CEMT P INT1 - Wash & rotate through cement. 40 RPM, 8 BPM @ 870 psi. 02:15 - 02:45 0.50 CEMT P INT1 - Drill plugs & ES Cementer - Tag ES Cementer @ 6160' 02:45 - 03:15 0.50 CEMT P INT1 - Pump Hi-vis sweep & circulate - Cement, plug rubber, & ES cementer metal seen at shakers. 03:15 - 03:45 0.50 CEMT P INT1 - Test casing to 1000 psi & hold for 5 min. 03:45 - 04:30 0.75 CEMT P INT1 - Continue RIH w/4" DP from 6240' to 7855'. 04:30 - 07:00 2.50 CEMT P INT1 - Drill cement & LC from 7855' to 8040'. - UC @ 8015' 07:00 - 08:00 1.00 CEMT P INT1 - Pump Hi-vis sweep & circulate. - Test casing to 1000 psi 08:00 - 10:15 2.25 CEMT P INT1 - Displace well to 9.8 ppg brine. - Monitor well & B/D lines 10:15 - 12:00 1.75 CEMT P INT1 - POH w/4" DP UD singles. 12:00 - 13:00 1.00 CEMT P INT1 - Lubricate rig. 13:00 - 18:30 5.50 CEMT P INT1 - POH w/4" DP & BHA. UD singles. - Rack back 16 stands for RIH & displacing brine. (350' air gap) - Clear tools & clean floor. 18:30 - 19:00 0.50 CEMT P INT1 - PJSM - RlU Schlumberger 19:00 - 20:00 1.00 CEMT P INT1 - RlU Schlumberger E-line for US IT log. 20:00 - 00:00 4.00 CEMT P INT1 - RIH w/ US IT log. 12/14/2003 00:00 - 01 :00 1.00 CEMT P INT1 - RID E-liners after completing US IT log. 01 :00 - 02:45 1.75 CEMT P INT1 - Pressure test 7 5/8" casing to 4400 psi & hold for 30 minutes. - B/D lines 02:45 - 03:30 0.75 CEMT P INT1 - RIH wI 4" DP wI closed TIW valve on bottom & displace fluids leaving 350' air gap for freeze protection. 03:30 - 05:00 1.50 CEMT P INT1 . POH& UD4" DP. - Installed BPV in NS-27 in preparation for rig move. 05:00 - 06:00 1.00 CEMT P INT1 - Change top rams to 2 7/8" X 5". 06:00 - 07:00 1.00 CEMT P INT1 - Pull bowl protector & install 4 1/2" tubing hanger. 07:00 - 12:00 5.00 CEMT P INT1 - RID floor & clean under rotary table - RID Koomey lines & turnbuckles - N/D riser - RID choke & kill lines - Clean up cellar - N/D BOP & double stud adaptor - CIO saver sub on top drive 12:00 - 14:30 2.50 CEMT P INT1 - Mix spud mud. OP's bleed down NS 31. 14:30 - 15:00 0.50 CEMT P INT1 - PIU & rack back BOP's 15:00 - 16:30 1.50 CEMT P INT1 - Put dry hole tree in cellar & install on NS-32. - Test to 5000 psi 16:30 - 18:00 1.50 CEMT P INT1 - Prepare to skid rig to NS-25 - Released rig from NS-32 @ 1800 hrs. 4/27/2004 09:00 - 17:00 8.00 MOB P PRE PJSM for Rig Move. Move rig from NS21. - SI NS22, 23, 24, 25, 27, 29, and 31 along the way. Bring on wells after wells become exposed while moving rig - NS31 in cellar ...remain SI for Heavy Lift. 17:00 - 19:00 2.00 RIGU P PRE Level and berm rig. Place flooring in cellar. ""ACCEPT rig at 1900 hrs on 12/27/04. 19:00 - 19:30 0.50 RIGU P PRE PJSM for ND dry hole tree and Tbg spool. Printed: 51312004 9:02:38 AM e e BP EXPLORATION Operations Summary Report Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date 4/27/2004 4/28/2004 4/29/2004 NS32 NS32 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 33E Start: 11/14/2003 Rig Release: Rig Number: 33E Spud Date: 11/15/2003 End: Code Note: AOGCC Rep, John Spaulding waived witnessing test. Continue NU BOP. · Test ABB-VETCO Gray tubing spool to 5000 psig. Rig up to Test BOP's. Pressure Test BOPE to 250/4800 psig. · AOGCC Rep, John Spaulding waived witness on 4/27/2004. Remove test and blow down Top Drive and lines. Install wear ring. Pressure test 7·5/8" casing to 4450 psig for 30 mins. MU BHA #8. - 6-314" Smith XR+ (3x15's) and 4-314' Slimpulse MWD Shallow Test MWD. Single in w/4' HT-40 DP and BHA to 1696' md. Repair pipe skate. Continue to single in wI BHA from 1696' to 4884' md. TIH PU 4" DP from pipeshed and derrick. Wash down and tag TOC at 8040' md. Drill cement and the remainder of float equipment (FC and FS @ 8105'), drill out rathole to 8121' md and drill ahead 20' of new 6·3/4' hole. - Pumped sweep to bit followed by 8.9 ppg NACL brine and recovered 9.8 ppg NACL brine that was left for suspension while drilling ahead. -Circulate out sweep and cement filling L-Pit. · Condition MWin= MWout= 9.0 ppg. INT1 Perform LOT to 13.6 ppg EMW. - 9.0 ppg brine in hole with 1570 psi surface pressure. PROD1 Drill ahead 6-3/4" hole from 8141' md to TO at 8321' md (6691' tvd rkb). Drilling parameters: - 120 rpm wI 8-9 K torque · WOB 15 K-Ibs, ROP= 75 fph. - 300 gpm w/1 000 psig PROD1 Pump hi vis sweep surface to surface while reciprocating and rotating. · Spot viscosified brine pill in OH, leaving top of pill at 7900' md. Monitor well. Pull 5 stands. PJSM. Slip and cut drilling line. Service TO and Draw works. TOH wI BHA#8. Monitor well and change out elevators. PJSM. UD BHA #8. - 6-314' bit graded 1-1 WT PJSM. MU BHA#9 (6-314' Bit and 7-5/8' scraper). RIH wI BHA#9 on 4' DP to 7900' md. PJSM for pumping casing wash pills and sweeps. - Pump 40 bbls caustic. 19:30 - 21 :30 21 :30 . 23:00 2.00 RIGU P 1.50 RIGU P PRE PRE 23:00 . 00:00 1.00 BOPSUF P PRE 00:00 . 03:30 3.50 CEMT P INT1 03:30 - 06:00 2.50 CEMT P INT1 06:00 - 14:30 8.50 CEMT P INT1 14:30·15:00 0.50 CEMT P INT1 15:00 - 15:30 0.50 CEMT P INT1 15:30 - 17:00 1.50 CEMT P INT1 17:00· 18:00 1.00 CEMT P INT1 18:00 - 18:30 0.50 CEMT P INT1 18:30 - 20:00 1.50 CEMT P INT1 20:00·21 :00 1.00 CEMT N RREP INT1 21 :00· 00:00 3.00 CEMT P INT1 00:00 - 03:30 3.50 CEMT P INT1 03:30 - 05:30 2.00 CEMT P INT1 05:30 - 06:30 1.00 CEMT P 06:30 - 09:00 2.50 DRILL P 09:00 - 10:30 1.50 DRILL P 10:30 - 11 :00 0.50 DRILL P PROD1 11 :00 - 13:00 2.00 DRILL P PROD1 13:00 - 16:00 3.00 DRILL P PROD1 16:00 . 16:30 0.50 DRILL P PROD1 16:30 - 17:30 1.00 DRILL P PROD1 17:30 - 18:00 0.50 DRILL P PROD1 18:00 - 22:00 4.00 DRILL P PROD1 22:00 - 00:00 2.00 DRILL P PROD1 NO dry hole tree & production sweep. NO tubing spool. NU spacer spool and new tubing spool (modified for accepting new penetrator). NU BOP's. - Put NS31 back on injection at 23:30 hrs. Printed: 51312004 9:02:38 AM e e . BP EXPLORATION PROD1 - Followed by 25 bbls Dirt Magnet - Followed by 30 bbls of high vis spacer. - Followed by 90 bbls of 8.9 ppg spacer. - Chase spacer with 9.8 ppg brine. Continue to displace well over to 9.8 ppg brine. - Total CBUx4 Monitor well. POH while laying down 4" DP. Lay down BHA#9. Pull wear bushing. PJSM. Rig up to run 4.5" 12.6 ppf, L-80, IBT-M, completion w/ heat trace. Safety meeting for running completion. Run completion in the following order: --MU Assembly #1 (WLEG, 'XN' nipple w/ RHC insert) to Jt#1 of #193 jts total of 4.5" 12.6 ppf, L-80, IBT-M tubing. - Run 4.5" Tubing Jts #2-72. - MU BOT 7-5/8" x 4-1/2" S-3 Permanent Packer Assembly. - Run 4.5" Tubing Jts #73-143. - MU 4.5" 'X" nipple Assembly (protective sleeve not installed). - Run 4.5" Tubing Jts #144-145. PJSM for Rigging Up Floor to Run Tyco-Raychem Heat Trace String. RU floor for running heat trace string: - Hang sheave, Install heat trace string on spooling unit, get banding equipment ready. PJSM for running 4.5" completion wI heater string. Run 4.5" 12.6 ppf, L-80, IBT-M tubing from Jt #145 to Jt#157 wI heat trace. Beginning at 2100' MD. . Running heat trace channel covering every foot of heat trace. The channels are 6' long and secured with 3 bands per channel. -Test heat trace string for continuity (8.3 ohms) and resistance (6 G-ohms) at Jt #157. Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date NS32 NS32 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 33E Pha$e 4/29/2004 22:00 - 00:00 2.00 DRILL P 4/30/2004 00:00 - 01 :00 1.00 DRILL P PROD1 01 :00 - 01 :30 0.50 DRILL P PROD1 01 :30 - 08:30 7.00 DRILL P PROD1 08:30 - 09:00 0.50 DRILL P PROD1 09:00 - 09:30 0.50 DRILL P PROD1 09:30 - 10:30 1.00 RUNCOIvP COMP 10:30 - 11 :00 0.50 RUNCOIvP COMP 11 :00 - 18:00 7.00 RUNCOIvP COMP 18:00 - 18:30 0.50 RUNCOIvP COMP 18:30 - 19:45 1.25 RUNCOIvP COMP 19:45 - 20:00 0.25 RUNCOIvP COMP 20:00 - 00:00 4.00 RUNCOIvP COMP 5/1/2004 00:00 - 11 :00 11.00 RUNCOIvP COMP 11 :00 - 11 :30 0.50 RUNCOIvP COMP 11 :30 - 16:00 4.50 RUNCOIvP COMP 16:00 - 16:30 0.50 RUNCOIvP COMP 16:30 - 17:30 1.00 RUNCOIvP COMP 17:30 - 19:30 2.00 RUNCOIvP COMP 19:30 - 21 :30 2.00 RUNCOIvP COMP 21 :30 . 23:00 1.50 RUNcmrp COMP 23:00 - 00:00 1.00 RUNCOIvP COMP Start: 11/14/2003 Rig Release: Rig Number: 33E Spud Date: 11/15/2003 End: Run 4.5" 12.6 ppf, L-80, IBT-M, tubing from Jt. #158 - Jt# 193 w/ Tyco Heat trace channels (3 bands per channel). Run 2 pup jts. MU ABB VETCO- Gray Tubing Hanger assembly (1.46' x 11"x 4.5" MB 203 hanger with 4" BPV plus 29.47' tubing pup). MU Landing Jt. Splice heat trace and terminate. Land tubing hanger - 118 K-Ibs HWt. -- PU 145k, SO 120k NO Riser. PJSM. Open ram doors and clean and remove all rams. Grease body for cold stack. Notify Operations for SI of NS31for heavy lift at 8:30 am. Prepare to NO BOP's. Wait on Operations to back out gas from Caribou crossing and begin Shut In of NS31 for heavy lift. Clear rig floor, cellar, and rig while waiting on Operations to Shut In NS31. Operations ready... Lift BOP stack and rack back. Printed: 5/312004 9:02:38 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date 5/1/2004 5/212004 e e NS32 NS32 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 33E Start: 11/14/2003 Rig Release: Rig Number: 33E Spud Date: 11/15/2003 End: 23:00 - 00:00 00:00 - 01 :00 01 :00 - 02:45 02:45 - 03:00 03:00 - 03:15 03:15 - 03:30 03:30 - 04:30 04:30 - 05:45 05:45 - 06:45 06:45 - 07:00 07:00 - 07:30 07:30 - 10:30 1.00 RUNCOM> 1.00 RUNCOM> 1.75 RUNCOM> 0.25 RUNCOM> 0.25 RUNCOM> 0.25 RUNCOM> 1.00 RUNCOM> 1.25 RUNCOM> 1.00 RUNCOM> 0.25 RUNCOM> 0.50 RUNCOM> 3.00 RUNCOI"P COMP COMP COMP COMP COMP COMP COMP COMP COMP COMP COMP COMP 10:30 - 13:00 2.50 RUNCO~P COMP 13:00 - 14:00 1.00 RUNCOM> COMP 14:00 - 14:30 0.50 RUNCOM> COMP 14:30 - 15:30 1.00 RUNCOM> COMP 15:30 - 16:30 16:30 - 17:30 17:30 - 18:00 1.00 RUNCOM> COMP 1.00 RUNCOM> COMP 0.50 RUNCOM> COMP - NO Drilling Adapter Flange. Test heat trace at wellhead. NU tree on NS32. Pressure test tree adapter to 5K psig. Test heat trace at well head. Pressure test tree to 5K psig. Remove TWC. Rig up manifold for FP and pressure testing. Break for lunch and to gather all parties for FP. Pressure test rig lines & manifold to 4000 psig. PJSM for pumping corrosion inhibited packer brine and FP. Reverse circulate down the 7-5/8' x 4-1/2' annulus with the following while taking returns off the tubing (max pump rate 3 bpm around pkr): 1. 155 bbls of 9.8 ppg brine wI corrosion inhibitor 2. Followed by 68 bbls of diesel with corrosion inhibitor. Bleed off 8 bbls from 7-5/8' x 4112' annulus to drop the fluid level in tubing to 530'. Fill the 4-1/2' tubing with 7 drums of ESCAID 110 mineral oil. Drop 1-7/8" ball and rod for packer setting. - Pressure up to 3400 psig on ball and rod to set packer. Increase pressure and test the tubing to 5000 psig for 30 min. (EPA Representatives Thor Cutler and Talib Syed on location to witness and sign off on test). Bleed tubing pressure down to 2900 psig to bleed trailer. - Pressure up to 4500 psgi for initial MIT on packer. Record tubing and casing pressure on chart for 30 mins (EPA Rep, Thor Cutler and Talib Syed, witnessed and sign off on test). Bleed off pressure on the annulus and then the tubing to bleed trailer. - RD all lines. PJSM for intalling BPV and securing the well. Set BPV and secure the well. Safety Standown Meeting with Well Site Leader. - 2-First Aids back to back (one twisted anklel one burn to forearm). Release Rig at 1800 hrs on 5/2/2004. Printed: 51312004 9:02:38 AM Legal Name: NS32 Common Name: NS32 2/5/2003 FIT 4/29/2004 LOT 187,048 (psi) ,107.90 (ppg) 4,615 (psi) 13.64 (ppg) e e Printed: 5/3/2004 9:02:30 AM 490 (psi ,570 (psi ,105.00 (ppg) 9.00 (ppg) 3,250.0 (ft 6,512.0 (ft) 4,000.0 (ft) 8,141.0 (ft · , Date: 05-11-2004 Transmittal Number: #92649 BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. If you have any questions, please contact me in the Petrotechnical Data Center at (907) 564-4091 or by e-mailingtojohnsojh@bp.com Top SW Name Date Contractor Log Run Depth NS32 04-29-2004 SPERRY 3 201 '¡O$-Jr8 J) Ç15"' NS21 04-18-2004 SPERRY ;J. 0.2 -.)/f 11 I ;)')ll/ 6 4179 Bottom Depth Log Type 6685.24 MUDLOG; FORMATION EVALUATION; LITHOLOGY; (2" MD/2" TVD COLOR MUDLOGS;) END OF WELL REPORT; CD ROM INCLUDED; 11206.60 MUDLOG; FORMATION EVALUATION; LITHOLOGY; (2" MD/2" TVD COLOR MUDLOGS;) END OF WELL REPORT; CD ROM INCLUDED; ~. ûW II 11~ Please Sign and Return one copy of this transmittal. / Thank You, James H. Johnson Petrotechnical Data Center ,{ (j ð \.,( Attn: Esther Fueg MB3-6 Attn: Ken Lemley MB3-6 Attn: Howard Okland (AOGCC) Attn: Jason Smith (Murphy Exploration Alaska), Inc Attn: Kristin Dirks (DNR) Attn: Doug Choromanski (MMS) Petrotechnical Data Center LR2-1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519-6612 . . Date: 01-09-2004 Transmittal Number:92634 BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. This data is being sent separate because of the confidential nature. If you have any questions, please contact me in the PDC at 564-4091 SW Name (9Q3...J5t!'JS32 &03'CElJ NS23 (9O)--Q91 NS27 12-02-2003 SCH Log Run Top Depth Bottom Depth Log Type ULTRA SONIC IMAGING 1 500 3858 TOOL; Date Contractor 05-06-2003 SCH 1 10520 13350 CEMENT BOND LOG; 12-01-2003 SCH 1 9996 11107 MEMORY COLLAR LOG; -"'~ . - ~>"" ~~l)J._;y\' D,,-,,· <:Db."O'::!'~ Please Sign a11d Return one copy of this transmittal. Thank You, James H. Johnson Petrotechnical Data Center Attn: Ken Lemley MB3-6 Attn: Ester Fueg MB3-6 Attn: Jason Smith (Murphy Exploration) Attn: Howard Okland (AOGCC) Attn: Kristin Dirks (DNR) Attn: Doug Choromanski (MMS) / RECEIVED J.\N 1 3 2004 Alaska Oil & GasQms. Cornrniaion Anchorage Petrotechnical Data Center LR2-1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519-6612 STATE OF ALASKA ALASKA. AND GAS CONSERVATION CoalSSION REPORT OF SUNDRY WELL OP~TIONS Perforation Depth MD (ft): N/A Perforation Depth TVD (ft): N/A Tubing Size (size, grade, and measured depth): Packers and SSSV (type and measured depth): None ... 1. Type of Request: o Abandon o Alter Casing o Change Approved Program 2. Operator Name: BP Exploration (Alaska) Inc. 3. Address: P.O. Box 196612, Anchorage, Alaska 7. KB Elevation (ft): o Suspend o Repair Well o Pull Tubing Planned RKB = 55.3' 8. Property Designation: Y0181 11. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical 8121' 6512' 8121' 6512' Casing Length Structural Conductor 201' Surface 3920' Intermediate Production 8106' Liner 12. Stimulation or cement squeeze summary: Intervals treated (measured): 99519-6612 o Variance 1m Othel o Time Extension Re-Enter Ops Shutdown o Annular Disposal 5. Permit To Drill Number 203-158 6. API Number: 50-029-23179-00-00 1m Operation Shutdown 0 Perforate o Plug Perforations 0 Stimulate o Perforate New Pool 0 Re-Enter Suspended Well 4. Current Well Class: D Development D Exploratory D Stratigraphic a Service 9. Well Name and Number: NS32i 10. Field 1 Pool(s): Northstar Unit feet feet Plugs (measured) N/A feet Junk (measured) N/A feet Size MD TVD Burst Collapse 20" 201' 201' 4260 2590 10-3/4" 3964' 3255' 5210 2480 7-5/8" 8106' 6499' 6890 4790 N/A N/A N/A None RECEIVl:D JAN 0 8 2004 Treatment description including volumes used and final pressure: 15. Well Class after proposed work: D Exploratory D Development a Service 16. Well Status after proposed work: DOil DGas DWAG DGINJ DWINJ aWDSPL 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. I Sundry Number or N/A if C.O~}... E mpt: Contact Allen Sherritt, 564-5204 . 303 - 267 ~ 'J / Title Senior Drilling Engineer --- / /'? ~ Prepared By Name/Number: P; 1 .2'. 5~04 Date f 1 o-y Sondra Stewman, 564-4750 RØYMS 8fl 13. Prior to well operation: Subsequent to operation: 14. Attachments: D Copies of Logs and Surveys run D Daily Report of Well Operations Oil-Bbl Alaska Oil & Gas Cons. Commission Anchoraae Representative Daily Average Production or Injection Data Gas-Met Water-Bbl CasinQ Pressure TubinQ Pressure ~ TREE:ABB-VGI 5 1/8" 5ksi WELLHEAD:ABB-VGI11" Mulitbowl 5ksi .832 Operational 8D DATE 6/18/03 7/15/03 1/6/04 103/4", 45.5#/ft, L-80, BTC @3960' MD 75/8", 29.7#/ft L-80, BTC-M @-8121 (-6512' TVDrkb) REV. BY JAS FH JAS COMMENTS Initial Diagram Proposed Completion Operational SD 'B. ELEV = 55.30' -BF. ELEV = 39.40' ASE FLANGE ELEV = 15.9' -350' Air Gap Freeze Protection Cement 9.8 NaCI Brine Northstar WFI I : N532 API NO: 50-029-23179 BP Exploration (Alaska) .... TREE:ABB-VGI 5 1/8" 5ksi WELLHEAO:ABB-VGI11" Mulitbowl 5ksi . 20", 169# X-56 @ 200' MD - 103/4", 45.5#/ft, L-80, BTC @3960' MD 4.5", 12.6#/ft, L-80, IBT-MOO TUBING 10: 3.958" CAPACITY: 0.015 BBLlFT 4.5" 'XN' NIPPLE, @ 8072' 3.725" 10 (OTIS) 75/8", 29.7#/ft L-80, BTC-M @8121'MD TO @8312' MD 6686' TVD DATE 6/18/03 1/5/04 REV. BY JAS JAS COMMENTS Initial Diagram Proposed Completion NS32 , , , , , , r , , , 1 , , , , , -, .B. ELEV = 55.30' -BF. ELEV = 39.40' BASE FLANGE ELEV = 15.9' 'X' Nipple @ 2150' MD 3.813" 10 Heat Trace @ 2250' MD Cement Baker S3 PACKER 3.875"10 @5155' MD 4.5" WLEG, @8100' MD 6 3/4" open hole Northstar WFI I : NS32 API NO: 50-029-23179 BP Exploration (Alaska) bp . . . " .~L I~ ..' BP Exploration Alaska Inc. To: From: Allen Sherritt Northstar Sen Date: January 6th, 2004 Subject: Reference: NS32i Applic tion for Sundry Approval - Re-entry into NS32 from Operation Shutdown Permit #203-158; API #50-029-23179 Sundry approval is being requested for re-entering well NS32i. An Operational Shutdown was conducted on December 15th due to an incompatibility issue between the existing ABB-VGI tubing hanger and the penetrator required for the Tyco heat trace. Well NS-32 has 7-5/8" casing set and tested in the Schrader Bluff, at approximately 8121' md (6512' TVD). The well was left with 9.8 ppg kill weight brine and a 350' air gap to surface for freeze protection. Re-entry into NS 32 is currently scheduled for Nabors 33E on approximately January 25th, 2004. There is no required pre-rig work for this re-entry. All operations will be competed by Nabors 33E. Below is an outline of the Re-entry operations to finish drilling and completing the well. RiCl Operations - Re-Entrv: Current Status (12115/03): Well has been drilled to TD of 9-7/8" hole section to 8121' md (6512' tvd). Completed EPA Witnessed OH logs. The 7-5/8" 29.7# casing was run, cemented and tested to 4450 psi. A USIT bond log was run and witnessed by EPA. Bond log indicated excellent cement across injection zones and above the confining shale zone. Prepare to re-enter well 1) MIRU Nabors 33E. 2) Verify there is no pressure on the tree. ND tree. a. The well was left with a TWCIBPV and the 7-5/8" w/ 9.8 ppg NaCL brine. b. The fluid level was left at 350' MD for air gap FP. 3) NU BOPE, pull the tubing hanger and run the test plug. Open annulus valve and test to 250/4800 psi. Test annular to 3500 psi. 4) Pull the test plug. Install the wear bushing. 5) Fill the casing wI 9.8 ppg NaCI brine. Test the 7-5/8" casing to 4450 psi for 30 minutes. This test may vary depending on actual MW in the hole. 6) PU the 6 3,4"directional assembly with GR/MWD. RIH. Continuation of the OriQinal Well ProQram 7) Drill 20' of new formation below 7 %" shoe. Perform LOT, targeting 11.0 ppg EMW. (FIT/LOT procedure on file with AOGCC). 8) Drill 6 3,4" hole to TD at 6687' TVD, 8312' MD. Minimum mud weight of 9.3 ppg will be required while drilling this hole section. POOH. 9) PU casing scraper on the 6 3,4" cleanout assembly. 10) RIH and displace the well to clean 9.8 ppg NaCI brine. POOH. -:' " .. 11) Run the 4 W' 12.6# L-80e-M tubing string with heat trace. Ensure propAMS are run in the BOP for Well Control. Drill pipe elevators and a TIW crossover from 4 1/2" to DP will be on the rig floor at all times. 12) Please Reference Completion Section 13) Heat trace will be run from 2250' MD to surface. 14) An "X" nipple will be run at 2150' MD en lieu of a SSSV. 15) No fiber optics will be run on this well. 16) RIH to packer setting depth of 5155' MD, (placement is no greater then 50' above upper injection interval.) Record pick-up and slack off weights. Spaceout as per tally, do not tag TD. Run space out pups as required by tubing tally. Sign Checklist upon EPA acceptance. 17) Land the hanger and RILDS. Pressure-test the tubing hanger seals to 5000 psi. 18) Rig up the manifolding (chicksan/hose) for injection into the 7 %" x 4-¥2" annulus. 19) Displace corrosion inhibitor (Corexit-7726 at 25 gals/100 bbls) pill down the 7 %" x 4 Y2" annulus to treat from +1-2200' MD to packer setting depth. Displace annulus with heated inhibited diesel equivalent to annulus capacity to a depth of 2000' TVD (2195' MD). Maximum displacement rate 3 BPM as per Baker recommendation to prevent damaging the packer elements. RD manifolding. a. Volume will be approximately 58 bbls. b. The mud weight (9.8 ppg) and depth (2000' TVD/2195' MD) is sufficient to provide a balanced condition in the wellbore. Any deviation from these specifications must ensure a balanced/overbalanced condition is met given the absence of cemented/tested casing, as this is a barefoot completion open to an 8.65 ppg formation pressure. 20) Drop ball and rod to set packer. Ensure that the proper ball size is dropped to match up with the RHC sub located in the 4 ¥2" 12.6# 'XN' Nipple. 21) Increase the tubing pressure to 5000 psi with 9.8-ppg completion fluid and hold for 30 minutes. Monitor tubing pressure for leaks. Record on chart. 22) Bleed tubing to 2000 psi and maintain during MIT. Pressure test 7 %" x 4 ¥2" annulus to 4500 psi for required mechanical integrity test (MIT). Monitor tubing pressure for leaks. Maintain pressure for 30 minutes and record annulus test on chart. Sign Checklist upon EPA acceptance. 23) Bleed off annulus and tubing. Fax chart to ODE. 24) Rig up Slickline. Pull the ball and rod I RHC profile from 'XN' nipple below the production packer to allow for bullheading down the tubing. Rig down Slickline. 25) Bullhead tubing with warmed mineral oil (Escaid 110) equivalent to tubing capacity to 500' TVD (500' MD). The volume required is approximately 8 barrels (6 drums). 26) Back out and lay down landing joint. Set the TWC valve in the tubing hanger. Nipple down BOP's. Nipple up the tubing head adapter and tree. Install all flanges and needle valves. 27) Test the tubing head adapter and tree to 5000 psi. Confirm that there is no pressure on the annulus. Dry rod the "two way" check. 28) Ensure all valves are closed. RD and move off well. ,. Post-Riq Work: 1. Conduct flow test and step rate injection test per EPA requirements Estimated Re-entry Date: January 25th, 2004. Allen Sherritt Northstar SDE Office: 564-5204/ Cell: 240-8070 A STATEOFALASKA . ALASKA (!P AND GAS CONSERVATION CO. · SION APPLICATION FOR SUNDRY APPROVAL 20 MC 25.280 1. Type of Request: o Abandon o Alter Casing o Chan¡¡e Approved Pro¡¡ram 2. Operator Name: BP Exploration (Alaska) Inc. 3. Address: P.O. Box 196612, Anchorage, Alaska 7. KB Elevation (ft): o Suspend o Repair Well o Pull Tubin¡¡ ~ Operation Shutdown 0 Perforate o Plug Perforations 0 Stimulate o Perforate New Pool 0 Re-Enter Suspended Well 4. Current Well Class: o Development 0 Exploratory o Stratigraphic 181 Service o Variance o Time Extension o Annular Disposal 5. Permit To Drill Number 203-158 6. API Number: 50-029-23179-00-00 99519-6612 Planned RKB = 55.3' 8. Property Designation: Y0181 o Other 9. Well Name and Number: NS32i 10. Field I Pool(s): Northstar Unit Junk (measured): N/A 11. Total Depth MD (ft): Total Depth rvD (ft): I Effective Depth MD (ft): I Effective Depth rvD (ft): 8121' 6512' 8121' 6512' L~ngth Plugs (measured): N/A 12. Attachments: 181 Description Summary of Proposal 0 BOP Sketch o Detailed Operations Program 14. Estimated Date for Commencing Operations: December 10, 2003 16. Verbal Approval: Date: 12/10/2003 Commission Representative: Winton Aubert 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Printed Name Robert Clump Title Drilling Engineer Structural Conductor Surface Intermediate Production Liner 201' 3920' 20" 10-3/4" Perforation Depth MD (ft): I Perforation Depth rvD (ft): I NM NM Packers and SSSV Type: None 201' 3964' 201' 3255' 2590 2480 4260 5210 Tubing Size: N/A Tubing MD (ft): NIA Tubing Grade: NIA Packers and SSSV MD (ft): None 13. Well Class after proposed work: o Exploratory 0 Development 181 Service 15. Well Status after proposed work: o Oil 0 Gas o WAG DGINJ o Plugged DWINJ o Abandoned 181 WDSPL Contact Robert Clump, 564-4672 Phone 3éJ3-3~7 o Plug Integrity o Mechanical Integrity Test Conditions of approval: Notify Commission so that a representative may witness o Location Clearance RECEIVED DEC 1 02003 o BOP Test Other: Subsequent form required 10- BY ORDER OF COMMISSIONER THE COMMISSION Date , Vi ' I J tf3; Su mit IlDuPlicate DUPLICATE bp . . ... ,\Jf.'~. --~~ ~.....- ~.- ~.~. ~...,\ ~..... .'~'.'~\' ". BP Exploration Alaska Inc. To: Mr. Winton Aubert - AOGCC Date: December 10th, 2003 From: Robert A. Clump Northstar Operations Drilling Engineer Subject: Reference: NS32i Application for Sundry Approval - Operational Shutdown after 7-5/8" Production Casing has been Set and Tested. Permit #203-158; API #50-029-23179 Sundry approval is being requested for the operational shutdown of well NS32i. It will be necessary to move off of well NS-32 due to an incompatibility issue between the existing ABB-VGI tubing hanger and the penetrator required for the Tyco heat trace. Well NS-32 will have the 7-5/8" casing set and tested in the Schrader Bluff, at approximately 8105' md (6500' TVDss). The plan is to leave the well with 9.8 ppg brine and an air gap from 350' to surface for freeze protection. The current schedule indicates the operational shutdown for NS32i should take place around December 13th, 2003. As per our phone conversation, ABB-VGI has redesigned a new hanger system that will accept the existing penetrator. The expected delivery to Northstar is in early January of 2004. Our current plan is to move Nabors 33E to NS 25 and drill and complete the grass-roots injection well. Re-entry into NS 32 is currently scheduled for Nabors 33E on approximately January 21 st, 2004. There is no required pre-rig work for this re-entry. All operations will be competed by Nabors 33E. Below is an outline of the Operational Shutdown and Re-entry operations to finish drilling and completing the well. Riq Operations - Shut Down and Re-Entrv: Current Status (12110/03): Well has been drilled to TD of 9-7/8" hole section to 8121' md (6512' tvd). Completed EPA Witnessed OH logs early this morning. Currently conducting clean out trip prior to running 7-5/8" 29.7# casing. 1) RU and run 7-5/8", 29.7# L-80 BTC-M intermediate casing with centrailizers 2) Cement the casing string from TD to surface in 3 stages. a. A Tam Port collar will be at 4150' MD (upper portion of SV4) and an ES cementer will be at 6150' MD (lower portion of the SV1) to ensure sufficient cement coverage and isolation. 3) MU 6-3/4" drilling assembly for cleanout run. RIH and drill out ES cementer closing plug +/- 6150' MD. RIH and drill and clean out shoe track to within 10' of float shoe if hard cement is present, otherwise stop. 4) Circulate and clean up the hole with mud. 5) Displace the 7-5/8" casing over to clean 9.8 ppg NaCL brine. POOH for USIT log. 6) RU and RIH with Schlumberger Wireline for EPA Witnessed cement evaluation logs. POH. 7) Test the 7 %" casing to 4450 psi with 9.8 ppg NaCL for 30 min. This test pressure may change based on the actual mud weight in the hole. Prepare for Operational SD 8) RIH with a closed TIW . on 4" drillpipe to 350' MD to evacuate the cefor air gap FP. POOH. 9) Install 4 W' tubing hanger and test seal area to 5000 psi. 10) Set the TWC. ND BOP's. NU Dry Hole Tree. Test the tubing head adapter and tree to 5000 psi. 11) RD and Move from NS32 to NS25. Prepare to re-enter well 12) MIRU Nabors 33E. 13) Verify there is no pressure on the tree. ND tree. a. The well was left with a TWC/BPV and the 7-5/8" w/ 9.8 ppg NaCL brine. b. The fluid level was left at 350' MD for air gap FP. 14) NU BOPE, pull the tubing hanger and run the test plug. Open annulus valve and test to 250/4800 psi. Test annular to 3500 psi. 15) Pull the test plug. Install the wear bushing. 16) Fill the casing w/ 9.8 ppg NaCI brine. Test the 7-5/8" casing to 4450 psi for 30 minutes. This test may vary depending on actual MW in the hole. 17) PU the 6 3J¡"directional assembly with GR/MWD. RIH. Continuation of the Oriqinal Well Proqram 18) Drill 20' of new formation below 7 %" shoe. Perform LOT, targeting 11.0 ppg EMW. (FIT/LOT procedure on file with AOGCC). 19) Drill 6 3J¡" hole to TD at 6687' TVD, 8312' MD. Minimum mud weight of 9.3 ppg will be required while drilling this hole section. POOH. 20) PU casing scraper on the 6 3J¡" cleanout assembly. 21) RIH and displace the well to clean 9.8 ppg NaCI brine. POOH. 22) Run the 4 W' 12.6# L-80 IBT-M tubing string with heat trace. Ensure proper RAMS are run in the BOP for Well Control. Drill pipe elevators and a TIW crossover from 41/2" to DP will be on the rig floor at all times. 23) Please Reference Completion Section 24) Heat trace will be run from 2250' MD to surface. 25) An "X" nipple will be run at 2150' MD en lieu of a SSSV. 26) No fiber optics will be run on this well. 27) RIH to packer setting depth of 5155' MD, (placement is no greater then 50' above upper injection interval.) Record pick-up and slack off weights. Spaceout as per tally, do not tag TD. Run space out pups as required by tubing tally. Sign Checklist upon EPA acceptance. 28) Land the hanger and RILDS. Pressure-test the tubing hanger seals to 5000 psi. 29) Rig up the manifolding (chicksan/hose) for injection into the 7 %" x 4-Y2" annulus. 30) Displace corrosion inhibitor (Corexit-7726 at 25 gals/100 bbls) pill down the 7 %" x 4 Y2" annulus to treat from +/-2200' MD to packer setting depth. Displace annulus with heated inhibited diesel equivalent to annulus capacity to a depth of 2000' TVD (2195' MD). Maximum displacement rate 3 BPM as per Baker recommendation to prevent damaging the packer elements. RD manifolding. a. Volume will be approximately 58 bbls. b. The mud weight (9.8 ppg) and depth (2000' TVD/2195' MD) is sufficient to provide a balanced condition in the wellbore. Any deviation from these specifications must ensure a balancedloverbalanced condition is met given the absence of cemented/tested casing, as this is a barefoot completion open to an 8.65 ppg formation pressure. 31) Drop ball and rod to set packer. Ensure that the proper ball size is dropped to match up with the RHC sub located in the 4 Y2" 12.6# 'XN' Nipple. 32) Increase the tubing pressure to 5000 psi with 9.8-ppg completion fluid and hold for 30 minutes. Monitor tubing pressure for leaks. Record on chart. 33) Bleed tubing to 2000 psi and maintain during MIT. Pressure test 7 %" x 4 Y2" annulus to 4500 psi for required mechanical integrity test (MIT). Monitor tubing pressure for leaks. Maintain pressure for 30 minutes and record annulus test on chart. Sign Checklist upon EPA acceptance. 34) Bleed off annulus and tubing. Fax chart to ODE. 35) Rig up Slickline. Pull the ball and rod / RHC profile from 'XN' nipple below the production packer to allow for bullheading down the tubing. Rig down Slickline. 36) Bullhead tubing with warmed mineral oil (Escaid 110) equivalent to tubing capacity to 500' TVD (500' MD). The volume required is approximately 8 barrels (6 drums). 37) Back out and lay down .ng joint. Set the TWC valve in the tubing he. Nipple down BOP's. Nipple up the tubing head adapter and tree. Install all flanges and needle valves. 38) Test the tubing head adapter and tree to 5000 psi. Confirm that there is no pressure on the annulus. Dry rod the "two way" check. 39) Ensure all valves are closed. RD and move off well. Post-Riq Work: 1. Conduct flow test and step rate injection test per EPA requirements Estimated Operation Shutdown Date: December 13th, 2003. Robert A. Clump Northstar ODE Office: 564-4672/ Cell: 632-3090 TREE:ABB-VGI . NS32 Current WELLHEAD:ABB-VGI11" Status12/10/03 Mulitbowl 5ksi I' " .~ 20", 169# X-56 @ 200' MD - ~ DATE 6/18/03 7/15/03 12/10/03 103/4", 45.5#/ft, L-80, BTC @3964' MD , ~ ( t ( ~ ( -~ 9-718" Hole Section TO @ 8121'MD (-6512' TVDrkb) REV. BY JAS FH RAC COMMENTS Initial Diagram Proposed Completion Current Well Status aKB. ELEV = 55.30' WB-BF. ElEV = 39.40' BASE FLANGE ELEV = 15.9' IIIIIII Cement 9.0 ppg SW Poly- mer Mud 1. Northstar WFI I : NS32 API NO: 50-029-23179 BP Exploration (Alaska) · TREE:ABB-VGI 5 1/8" 5ksi WELLHEAD:ABB-VGI 11" Mulitbowl 5ksi .532 Operational 5D 20", 169# X-56 @ 200' MD - DATE 6/18/03 7/15/03 12/9/03 103/4", 45.5#/ft, L-80, BTC @3964' MD 75/8", 29.7#/ft L-80, BTC-M @-81 (-6500' TVDrkb) REV. BY JAS FH RAC COMMENTS Initial Diagram Proposed Completion Proposed Operational SD .KB. ELEV = 55.30' B-BF. ELEV = 39.40' ASE FLANGE ELEV = 15.9' -350' Air Gap Freeze Protection Cement 9.8 NaCI Brine Northstar WFI I : N532 API NO: 50-029-23179 BP Exploration (Alaska) · . United States Department of the Interior MINERALS MANAGEMENT SERVICE Alaska Outer Continental Shelf Region 949 East 36th A venue, Suite 300 Anchorage, Alaska 99508-4363 Mr. Allen Sherritt Drilling Engineer BP Exploration (Alaska) Inc. 900 East Benson Blvd. Anchorage, AK 99508 SEP 2 4 2003 Dear Mr. Sherritt : The Application for Pennit to Drill (APD) for NS-32, Northstar Development Project, is hereby approved, subject to the conditions stated in this letter. Also enclosed is a signed copy of the APD. API number 50-029-23179 was issued by the State of Alaska AOGCC for this well. This well, meets the criteria established for the diverter departure approved on October 13,2001, therefore no diverter will be required during the drilling of the surface hole portion of the well. Your request to set the Blowout Prevention Equipment (BOPE) test pressure at 4800 psi is hereby accepted. The Northstar reservoir has been classified, as required under 30 CFR 250.417 (c), as hydrogen sulfide absent, therefore no hydrogen sulfide contingency plan is required for this well. Well information for this well will be submitted as specified in our letter of March 26, 200 I and modified on November 15,2001. BP Exploration (Alaska), Inc (BPXA) shall provide this office with a request for approval to commence injection operations for this well. Because the well surface location lies within State of Alaska waters and the bottom hole location lies in the Federal Outer Continental Shelf, both the Environmental Protection Agency (EP A) and the Minerals Management Service (MMS) have a regulatory mandate to oversee the construction, operation and abandonment of this disposal injection well. It is the MMS' intention to be actively engaged in monitoring the operation of this well. Since NS-32 has already been issued permits by EP A Region X, to avoid duplicative regulatory requirements, the MMS will adopt the requirements contained in the current EP A permit AK 1 m02-A. BPXA is required to provide copies of all required reports and notifications of non-compliance to the MMS at the same time the information is provided to the EP A. You are also required to provide advance notice of planned physical alteration or additions to NS-32 or changes in the types of injected fluids. The MMS does require that BPXA request approval prior to accepting and disposing of wastes generated off-site. If you have questions pertaining to disposal injection operations, please contact Ms. Christy Bohl at (907) 271-6082. TAKE PRIDE-þ---J ~ INAMERICA'~ : 2 . . This office plans to conduct periodic inspections of the drilling and injection operations and anticipates the need to utilize BP Exploration (Alaska) Inc. (BPXA) transportation and lodging. As allowed in 30 CFR 250.133, BPXA may request reimbursement for the cost of transportation and lodging provided for Minerals Management Service personnel. Your request must be submitted within 90 days of the inspection. After office hours, weekends and holidays, all calls related to drilling activities or changes to the approved APD should be made to Mr. Kyle Monkelien at the following numbers: Home. Cell Phone 907-349-5083 907-250-0546 If you should have any questions regarding this approval during normal business hours, please call Mr. Monkelien at 907-271-6431. Sincerely, \~\uJL~ Jei&e~Walker Regional Supervisor, Field Operations Enc1osure(s) cc: Tom Maunder, Senior Petroleum Engineer, AOGCC Jonathan Williams, EP A, Region X I u.s. Department of the InterJl¡ Submit ORIGINAL plus THR~~, Minerals Management Serv_MMS) with one copy marked "Public 19*1on" OMB Control Number 1010.0044 OMB Approval expires 101311200 Application for Permit to Drill (APD) 1. PROPOSAL TO DRILL 2. MMS OPERATOR NO. 3. OPERATOR NAME and ADDRES~ II NEWWELL 0 SIDETRACK 0 BYPASS 0 DEEPEN 00113' (Submitting otflce) 4. WELL NAME (Current) 5. SIDETRACK NO. (Current) 6. BYPASS NO. (CUnent) BP Exploration Alaska, Inc. P.O. Box 196612 NS31 STOO BPOO Anchorage, AK 99519-6613 7. PROPOSED START DATE 10101103 8. PLAN CONTROL NO. (NfIw Well Only) I. API WELL NO. (Current SIdetrack I Bypass) (12 DIgits)) NJA WELL AT TOTAL DEPTH (PROPOSED) 10. LEASE NO. WELL AT SURFACE 15. LEASE NO. OCS-YOl81 ADL312799 11. AREA NAME 16. AREA NAME Beedaey Poiat BeecJaey Poiat 12. BLOCK NO. 17. BLOCK NO. 13. LATITUDE o HAD 27 (OOM & PacIfIc) II HAD 83 (Alaska) 516 14. lONGITUDE 18. LATITUDE CHAD 27 (OOM & PacItlc)C NAD27 (GOlf &PacItIc) B HAD 83 (Alaska) ø HAD 83 (Alaska) LIST OF SIGNIFICANT MARKERS ANTICIPATED 21. TOP (AID) 20. NAME 515 11. LONGITUDE . . C HAl') 27(GOAf& PacIfIc) . ø HAD 83(AIaka) 20. NAME 21. TOP (AID) Top of Ugnu 6240' Top of Schrader Bluff 8112' Rl=rFIVFD Anchorage, Alaska 22. UST ALL ATTACHMENTS (AtIM:h Complete Well AúfI'JOSIs end Attachments Requhd by 30 CFèí$Ø.4Ù~~h (G) or 30 CFR 250.1617 (C) and (0), As Appropriate) NS32 Well Plan, NS32 DirectIOnal Survey, NS32 AOGCC PennIt Application and a SuppI8.n6ntak~1tÞIÞt MMS Fonn (MMS-123S). FIELD OPERATION MINERALS MANAGEMfNT SERVICE 23. AUTHORIZING OFFICIAL (Type or Print Name) Allen Sherrltt 24. 11TLE Drilling Engineer ~ 26. DATE.t;J¿/ ~/fo ~ THIS SPACE FOR MMS USE ONL Y --APPROYËÕ~-----------------fŠŸ-f\---~----\---~-----~---------------fTñië------------------------------ . ~ WIth Attached Conditions I \..A) . I -ÃPlwß.~~-THïšWËi.iL---:.- . -- -- -------- ----- --------~~1~~i~-12u~:r-}()~~~L(.\A~þe.~ . 50- 0 cr ~ 2 ~ J 71 . D ~ ! / ~ {( --./ PAPERWORK REDUC1ION ACr Of 1115 (PRAJ STATEMENT: The PRA (44 U.S.c. 35011Ua11. ___..III Inform ~ 11I8I we coIec:IlIIII infDrmIIIIon III abI8in knowledged equipmenllIIId ____ "'-'-11I lie IIIId In drIIIn CII8I1IIiQna. MMS _ lie infDrmIIIIon 1II......1IIId ___«~ lie ~ 01.. equIpIIIent 8ndIar ~ 1II..reIy perfarm the II1IIOI4Id drIIIn _"':"""" ReIpoMM -1MIdIIIoIy (.43 u.s.C. 1334). PIupItIâry... _ -.cI under 30 a:R 250.1t6. /vi IIQIIIICY ~ not condud« 1IOII8Or. IIIId . per-. II not AICUftd III Iwepond to.. coIection 0I1I\fonII8tiOII ....... diIpI8ya . cunwnIy valid 0M8 eon.oI Numbar. PublIc NIOIUng bunIen fur 11III fomIlleIIimaIIId III -. 211. '- per NIIOMe,IndudinG lie time fur reviewing IntIINI:Iion8. IIIheIq IIIId maiIIIIIIMIO dIIIa, IIIId compIeIing IIIId reviewing lie form. 0Irect CIIIIIIIWIII NganIing lie bunIen ...... or any oIhIIr asped 0111III fomIlII llelnfarmallon CaIecIIon a-anœ ()IIicer. Mall Slop 4230. ......... Management s.Mce. 1849 C 8net. N.W., WaIhIngIon, DC 20240. MMS FORM MM8-123 (October 2002 . Supersedes an previous versions of~ MMS-123 which may not be used.) Page 1 of 1 OMS ConIroI Number 1010.0131 OMS ~ ExpirM 10t3112OO5 11. WATER DEPTH 112. ElEVATION AT 1C81 39' Planned RKB .. 55.3' 13. HaS DESIGNATION o ICNOW\I 0 ~ ä ABSENT 14. HaS ACTIVATION PlAN DEPTH FT (TVD) NIA Submit ORIGINAL plus 7W0 coplfls with ONE copy msrked ·Publlc Informstlon. Supplemental APD InfonriatlonShéet:/, 5. WELL NAME (ProposerJ) III. TYPE OF WELl NS32i 0 EXPlORATORY Ii DEVElOPMENT 7. SIDETRACK NO. (Proposed) 18. BYPASS NO. (Proposed} STOO BPOO 9. RIG NAME 110. RIG TYPE Rotary u.s. ~rtment of the Interior MineralS Management Service (MMS) -.. - T\ge - (01-' I'W'J _ -. ~ Toot_ CooInI Toot M CooInI - IIIN~'" MI Toot MI ~BOP -. 2:: _ - - - - - - M M -.... "'" - -. M FO Nabors Rig 33E 11. ENGINEERING DATA CooInI DopII ~ c....,.- OI/IVI lID TYD IIIN BOTTOM lEASE NO. (ProposerJ) OCS-Y0181 1. OPERATOR NAME BP Exploration Alaska, Inc. 2. API WELl NO. (Proposed} (12 D1(Itt} 13. 4. TOTAl DEPTH (Proposed} MD 8457' 6737' pp T""., LNt lID T 1oloii<'_ c . 'NO WiIIII _-. c..,. -. MMO ... T\ge"_ ,..., .... - ... ~ "" _ c...,..-. ... - - - .... tIf Driven WB --- we --- WB wee 11.0 11.0 . 3500 3500 4800 U 3500 4ðOO 4800 8.3 . . - - 3!500 5000 13-518" 5000 3!500 5000 13-518" 5000 5000 13-518" - 13 12 9.5 9.3 8.65 8.65 201' 201' 39111' 3255' 8112' 8505' 8312' CI887' Surface 8urf8ce Surface 8112' 1.78 1.4 - - 1..... 3.811 1.3 1.52 1092 2281 2345 Weld BTC -- NIA ... 25tO 11210 2480 eeeo 4710 NtA NtA I_ X.. 4UI L-80 21.71 L-80 NtA NtA ~ 20" - 1~' - 7-518" IInIDøI N/A 20" 13-112" 9-7/r &-3/4' 18. CONTACT NAME 17. CONTACT PHONE NO. 118. CONTACT E~IL ADDRE88 Allen Sherritt (907) 564-5204 SherriJA 0 BP.com it. WIll you "JI,âl" qua.,lftIt: of mud and mud material (including weight t".l6ifal6 and additives) .utnclent to ra'" the entIN.,..., mud weight % ppg or more? 20, REMARKS: . 13-112" cement volumes 550 ax PF 'l', 394 8X ClalS 'G' o 9-718' cement volumes 116 ax SlIlcante, 159 ax PF 'l' and 1124 ax Class 'G' =:"'=='':':=!,::,'':::::~.~~44~-:J.:===-ar2llO~.:"==::"''''':''-:::'::'='===':=::='~-=~.''''=''-=-~c::..~~-::::.r:==:=... ==::...~""=.- --....-....-,.ftoII7" ~............-................. -.-... -. DIIMt_-.......__.",,_.......,.............. - CoIIocIonCloolwø~, -.....4ZIO, - ___-. ,....c_ N.W.. MMS FORM MM8-1238 (OdaIier2d02. fÍ'r IllIÂè ... II'8¥kIUI Wt'ÌIona of1Otm MM8-123S WhIcII may not be UNd.) Page 1 of 1 . - , ,II YES 0 NO bp . . BP Exploration Alaska Inc. From: Kyle Monkelien - MMS Allen Sherritt Northstar Senior Drilling Engineer . Date: September 2, 2003 To: Subject: NS32 Application for Drilling Permit Mr. Monkelien, Well NS32 is currently scheduled for Nabors 33E on October 1, 2003. A Diverter waiver is requested on NS32. To date, BP has successfully drilled all development wells through the Northstar upper strata-graphic intervals, absent any complications associated with shallow gas. All surface holes have been drilled and cemented to a common depth of approximately 3,170' TVDss depth, (-150' TVD below the top of the SV6), with one well extending into the SV5 -3280' TVDss. Well mud logs and seismic data do not indicate the presence of a shallow gas hazard. NS32 may perform an "Operation Shutdown" after drilling the surface hole. This will enable the Operations group an opportunity to tie-in the Northstar injectors after performing workovers for wellbore integrity. A Sundry for the Operation Shutdown will not be submitted, as the operations are covered in the ADP procedure. Please find attached the NS32 Well Plan Summary, directional plan and proposed completion diagram. If you should have any questions or concerns, please contact me @ 564-5204 , ~incer~y r ~ ~Ien~ BP Northstar Senior Drilling Engineer 564-5204 work 240-8070 cell NS32 SUMMARY DRI. OPERATIONS Pre-Ria Work: 1. Set 20" conductor and weld an ABB Vetco landing ring for the ABB Vetco Multibowl Wellhead on the conductor. (Already performed.) 2. Install 7' x 7' cellar and polyshield same. (Already performed.) . Ria Operations: 1. MIRU Nabors 33E. 2. Nipple up and function test 21-1/4" diverter system, if required. NOTE: A diverter dispensation has been requested. Confirm di~nsation decision with the Drilling Engineer. A D7 Diverter Drill will be conducted prior to spud. 3. MU 13 ¥.l" drilling assembly with MWD/GR and directionally drill surface hole to the surface casing point 3255' TVD, 3961' MD. POOH. 4. RU Schlumberger Wireline for open hole logs. Logging suite to include gamma ray (GR), spontaneous potential (SP), resistivity, and caliper. Use caliper results to confirm the surface cement volumes. RD Schlumberger Wireline. 5. RU and run 10 *", 45.5# l-80 BTC surface casing with centralizers. 6. Cement the casing to surface in 1 stage (lead and tail slurries). A TAM port collar will be run at 1000' MD for a 2-stage contingency. In the event the cement does not circulate to surface, please contact the Anchorage Drilling Team. 7. ND diverter 1 riser system and NU casing 1 multi-bowl wellhead. NU BOPE and test to 250/4800 psi. 8. MU 97/S" drilling assembly for cleanout run. RIH to float collar. Test the 10 *" casing to 500 psi with 9.5-ppg mud for 15 min. 9. Swap fluids to clean seawater. POOH. 10. RU Schlumberger Wireline for cement evaluation logs. Logging suite to include USIT from the 10 %" shoe to 500' MD. RD Schlumberger Wireline. 11. Test the 10 %" casing to 3500 psi with 9.5-ppg mud for 30 min. This test pressure may change based on actual mud weight in the hole. 12. RIH with open ended drillpipe to 100' below the base of the permafrost and circulate 6.8 ppg diesel to freeze protect the well to surface. POOH 13. Install 4 ¥.l" tubing hanger and test to 5000 psi. 14. Set the TWC. ND BOP's. NU Tree. Test the tubing head adapter and tree to 5000 psi. 15. Pull TWC and install BPV (dry rod is acceptable). Test BPV from below to 3500 psi for 10 minutes. 16. RD and move off NS32 for NS27 workover. Prepare to re-enter well 17. Prepare to re-enter well. 18. MIRU Nabors 33E. 19. Verify there is no pressure on the tree. ND tree. a. The well was left with a TWC, tested to 3500 psi from below. 20. NU BOPE, pull the tubing hanger and run the test plug. Open annulus valve and test to 250/4800 psi. Test annular to 3500 psi. 21. Pull the test plug. Install the wear bushing. 22. RIH with open-ended drillpipe to 2000' MD, circulating/displacing out diesel to the trip tank. Change over to seawater. a. Have G&I and rig crew line up Trip Tank#1 sump to G&I disposal pump suction. b. Coordinate with G&I and circulate one surface-to-surface volume of seawater, monitoring the volume in Trip Tank #1. c. When the Mud Engineer is satisfied with the water quality, the hole can be lined up elsewhere on the rig. d. POOH . See Barold Mud Program: Well Clean-outlDisplacement Procedure. 23. Test 10 %" liner to . psi for 30 minutes. .. 24. MU 9 7/8" direction~sembly with MWD/GR/PWD. RIH and "20' of new formation below 10 %" shoe. Perform LOT, targeting 11.5 ppg EMW. (FIT /LOT procedure on file with AOGCC). 25. Drill 9 7/8" intermediate hole to casing point at 6505' TVD, 8112' MD. Minimum mud weight of 9.3 ppg will be required. POOH. 26. RU Schlumberger Wireline for open hole logs. Logging suite to include gamma ray (GR), spontaneous potential (SP), resistivity, density, neutron, and sonic. RD Schlumberger Wireline. 27. RU and run 7 %", 29.7# L-80 BTC-M intermediate casing with centralizers. 28. Cement the casing string from TD to surface in 3 stages. A Tam port collar will be at 4150' MD (upper portion of SV4) and an ES cementer will be at 6150' MD (lower portion of the SV1) to ensure sufficient cement coverage and isolation. 29. MU 6 %" drilling assembly for cleanout run. Drill stage tool closing plug(s). RIH to float collar. Test the 7 %" casing to 500 psi with 9.3-ppg mud for 15 min. POOH. . . 30. RU Schlumberger Wireline for cement evaluation logs. Logging suite to include USIT from the 7 %" shoe to 2960' MD (calculated top of lead) inside the surface casing shoe. RD Schlumberger Wireline. 31. PU 6 %" directional assembly with GR/MWD. RIH. Test the 7 %" casing to 4600 psi with 9.3-ppg mud for 30 min. This test pressure may change based on actual mud weight in the hole. 32. Drill 20' of new formation below 7 %" shoe. Perform LOT, targeting 11.0 ppg EMW. (FIT/LOT procedure on file with AOGCC). 33. Drill 6 ~" hole to TD at 6687' TVD, 8312' MD. Minimum mud weight of 9.3 ppg will be required while drilling this hole section. POOH. 34. PU casing scraper on the 6 ~" cleanout assembly. 35. RIH and displace the well to clean 9.8 ppg NaCI brine. POOH. 36. Run the 4 *"12.6# L-80 IBT-M tubing string with heat trace. Ensure proper RAMS are run in the BOP for Well Control. Drill pipe elevators and a TIW crossover from 4112" to DP will be on the rig floor at all times. · Please Reference Completion Section · Heat trace will be run from 2250' MD to surface. · An "X" nipple will be run at 2150' MD en lieu of a SSSV. · No fiber optics will be run on this well. 37. RIH to packer setting depth of 5155' MD. Record pick-up and slack off weights. Spaceout as per tally, do not tag TD. Run space out pups as required by tubing tally. 38. Land the hanger and RILDS. Pressure-test the tubing hanger seals to 5000 psi. 39. Rig up the manifolding (chicksanlhose) to allow U tube to equalize from the 7 5/8" X 4-*" annulus to the 4 ¥.2" tubing. 40. Displace corrosion inhibitor (Corexit-7726 at 25 gals/1oo bbls) pill down the 7 5/8" X 4 ¥oz" annulus to treat from +1-5000' MD to packer setting depth. Displace annulus with heated inhibited diesel equivalent to annulus capacity plus tubing capacity to a depth of 4000' TVD (5008' MD). Maximum displacement rate 3 BPM as per Baker recommendation to prevent damaging the packer elements. 41. Allow diesel to U-tube and equalize. RD U-tube manifolding. 42. Drop ball and rod to set packer. Ensure that the proper ball size is dropped to match up with the RHC sub located in the 4 W' 12.6# 'XN' Nipple. 43. Increase the tubing pressure to 5000 psi with 9.8-ppg completion fluid and hold for 30 minutes. Monitor tubing pressure for leaks. Record on chart. 44. Bleed tubing to 2000 psi and maintain during MIT. Pressure test 7 %" x 4 ¥.2" annulus to 4500 psi for required mechanical integrity test (MIT). Monitor tubing pressure for leaks. Maintain pressure for 30 minutes and record annulus test on chart. 45. Bleed off annulus and tubing. Fax chart to ODE. 46. Back out and lay down landing joint. Set the TWC valve in the tubing hanger. Nipple down BOP's. Nipple up the tubing head adapter and tree. Install all flanges and needle valves. 47. Test the tubing head adapter and tree to 5000 psi. Confirm that there is no Dressure on the annulus. Drv rod the "two way" check. 48. Ensure all valves are closed. RD and move off well. Post-RiQ Work: . . 1. MIRU slickline. Pull the ball and rod I RHC profile from 'XN' nippl:tríow the production packer. 2. Conduct flow test and step rate injection test per EPA requirements. Estimated Spud Date: October 1, 2003 Allen Sherritt Senior Drilling Engineer 564-5204 · NS32 WELL PLAN SUMM" I Type of Well (producer or injector): Northstar Slot: Surface Location: Target (top of SAG): 300' Radius Bottom Hole Location: I Class I Disposal Well NS32 1358' FSL, 649' FEL, Sec. 11, T13N, R13E, UM X = 659821 Y = 6031131 5112' FSL, 3526' FEL, Sec. 12, T13N, R13E, UM X = 662140 Y = 6034936 6505' TVDrkb 5183' FSL, 3481' FEL, Sec. 12, T13N, R13E, UM X = 662184 Y = 6035008 6687' TVDrkb I AFE Number: 1831333 I Rig: 1 Nabors 33E I I Estimated Start Date: 110/1/03 I Operating days to complete: 122.6 I I MD: 18312 I TVDrkb: 16687 1 1 RKBlSurface Elevation: (a.m.s.I.) 155.3' / 15.9' 1 1 Well Design (conventional, slimhole, etc.): 1 Slim Hole Long String 1 I Objective: 1 Ugnu / Schrader Bluff non-hazardous disposal well 1 Well Name: API Number: Well Type (proposed): BHP: EMW: BHT: NS32 Class I Disposal Well 2925 psi @ 6500' TVDss 8.65 ppg 130 of @ 6500' TVDss Land Use Permit: Distance to Nearest Property: Distance to Nearest Well within Pool: MECHANICAL CONDmON: Cellar box: RKB to Cellar box: Rig Elevation: Conductor: LO-N96-00s 4,800 ft. 1,617 ft. from NS22 Elevation above MSL = 15.9' 39.4' (Estimated) RKB + MSL = 55.3' 201' MDrkb of 20·,169#, X-56 (pre-driven) Surface Hole Mud Properties: Seawater Spud Mud 13 W' Hole Section From Surface to -3961' MD / 3255' TVD (-150' TVD below top SV6). Interval Density Viscosity yp (ppg) (seconds) 8.8 - 9.5 100 - 200 *9.0 - 9.5 100 -150 *9.5 max 75 - 100 MUD PROGRAM: . Initial from -1555' SV6 @ Interval TD 50 - 70 30-45 20-35 . Tauo Gel 10 sec 25-40 15 - 25 10 - 25 API FL pH 15 - 20 8.5 - 9.5 6-10 8.5 - 9.5 6-10 8.5 - 9.5 >8 >6 >6 * Should gas hydrates be encountered, mud densities up to 10.2 ppg may prove necessary. Intermediate Hole Mud Properties: Seawater Polymer From Surface Casing Shoe to 8112' MD / 6505' TVD. Interval Density (ppg) PV YP All 8.6 - 9.3 12 - 17 15 - 25 Injection Interval Mud Properties: Seawater Polymer From Intennediate Casing Shoe to 8312' MD /6687' rvD Interval I Density (ppg) I PV I YP All 9.0-9.3 12-17 15-25 DIRECTlONAL:(P6) KOP: Maximum Hole Angle: Close Approach Wells: Survey Program: . . 97/8" Hole Section Tauo API I HTTP FL 3 - 6 <10 initial <8 at TD pH 8.5-9.5 6 ~" Hole Section Tauo APIFL 3-6 <6 pH 8.5 - 9.5 ±300' MD Cantenary curve 1.5°/100' to 2.5°/100' build :t:44.67° Surface- 10' well spacing to well NS31 and no wells to the North Gyro will be used for initial surveys and kickoff Gyros as required from surface to +/-1000'. IFR+MS corrected MWD surveys from +/-1000' to TD. SURFACE AND ANTI-COLLISION ISSUES: All wells pass the major risk rule; however, NS31 will be risked based at 1/200 to allow more flexibility while drilling the surface hole. Surface Shut-in Wells: See Northstar Anti-Collision and Well Shut-In checklist. LOGGING PROGRAM: . . 131h" Section: Drilling: GRlDirectional - Gyro as needed to -1000' MD. IFR-MS corrected surveys Mud Logging - Gas analysis/detection, show kit with indexed sample bottles, lithology samples (100' intervals) Open Hole: Gamma ray (GR), spontaneous potential (SP), resistivity, and caliper Cased Hole: USIT from the 10 3A" shoe to 500' MD 9 7/8" Section: Drilling: GRlDirectlonal, PWD. IFR-MS corrected surveys Mud Logging - Gas analysis/detection, show. kit with indexed sample bottles, lithology samples (100' intervals) Open Hole: Gamma ray (GR~ spontaneous potential (SP), resistivity, density, neutron, sonic Cased Hole: USIT from the 7 1." shoe to 2960' MD 6 3A" Section: Drilling: GRlDirectional. IFR-MS corrected surveys Mud Logging - Gas analysis/detection, show kit with indexed sample bottles, lithology samples (100' intervals) Open Hole: None Cased Hole: None Intearitv Testlna: Test Point Depth Shoe Test Type LOT LOT NA NA NA EMW Estimated Casing/Llner Test 3500 psi w/9.5 ppg 4600 psi w/9.3 ppg NA 5000 psi w/9.8 ppg 4500 psi w/9.8 ppg 13 W' Surface 9 '/8" Intermediate 6 3A" Injection interval 4 ~" Injection Tubing 4 ~" x 7 I>/a" Annulus 20' min from 10 3A" shoe 20' min from 71>/a" shoe NA NA NA 11.5 ppg EMW Target 11.0 ppg EMW Target NA NA NA CASINGlTUBING PROGRAM: Hole Size Casing! WtlFt Grade Conn. Casing Casing Top Hole Btm Tbg O.D. Length MDnvDrkb MDlTVDrkb 20" 20" 169# X-56 WELD 201' Surface 201 '1201' 13~" 103A" 45.5# L-80 BTC 3961' Surface 3961 '/3255' 9 '/a" 71>/a" 29.7# L-80 BTC-Mod 8112' Surface 8112'/6505' 63A" Barefoot NA NA NA NA 8112'/6505' 8312'/6687' Tubing 4~" 12.6# L-80 IBT -Mod 8112' Surface 8112'/6505' FORMATION MARKERS. . (ppg Formation TVDrkb MDrkb EMW) Comments Top Permafrost 1,204 1226 8.65 Base Permafrost 1,574 1643 8.65 SV6 - top confining zone 3,105 3750 8.65 Surface casing point 3,255 3961 SV5 - base confining zone 3,364 4114 8.65 SV4 3,725 4621 8.65 SV3 3,958 4949 8.65 SV2 - top upper injection zone 4,140 5205 . 8.65 SV1 - top major shale barrier 4,527 5749 8.65 TMBK - top lower injection zone - Top Ugnu 4,876 6240 8.65 WS1 - top Schrader Bluff - Base Ugnu 6,505 8112 8.65 Geologic target - 300' radius Production casing point 6,505 8112 Total Depth 6687 8312 8.65 REQUIRED MATERIALS: L-80 Surface: 3961' 1 1 17 1 1 1 10 ~", 45.5# L-80 BTC 10~" HES Super Seal" Float Shoe (4.25" valve) 10~" HES Super Seal" Float Collar (4.25" valve) 1 0 ~" x 13 14" SV Rigid Centralizers 10~" Port collar 45.5# L-80 BTC 20" x 10 *" ABB-VGI Fluted hanger BTC down, 12 *" ACME landing thread ABB-VGI Casing HeadfTbg head; 11" 5000 psi top flange, 1 0 ~" quick connect 120 7 %",29.7# L-80 BTC-M 7 %", HES Super Seal" Float Shoe 7 %", HES Super Seal" Float Collar 7 5/8", ES cementer, 1st stage and 2nd stage plug set, 29.7#, L-80, BTC-M 7 %", HES Baffle adapter and bypass baffle HES Cement Plug Set 7 %", Tam Port Collar, 29.7#, L-80 BTC-M 10~" x 7 518" ABB-VGI Casing Hanger BTC-Mod down, 8 14" stub ACME 7 %" x 9 %" SV Rigid Centralizers L-80 Intermediate: 8112' 1 1 1 1 1-set 1 1 Completion: 8112' 1 1 1 1 1 1 1 4 ~" 12.6# L-80 IBT-M 10 ~ x 4 ~" ABB-VGI tubing hanger 4 Y.l" ABB-VGI adapter flange with heat trace 4 ~" ABB-VGI 4 ~" 5K Swab Valve wI tree cap 4 Y.l" 'X' nipple T x 4 ~" Baker packer S-3, IBT-Mod 4 Y.l" 'XN' nipple 4 Y.l" WLEG PERMAFROST: The 1 0 ~" surface casing will be run approximately 1600' TVD below the permafrost to -3961' MD / 3255' TVD. The casing will be cemented to surface with a Premium 'G' with 2% calcium chloride tail slurry and a Permafrost "L' lead slurry. The tail slurry allows sufficient compressive strength to prevent the shoe from breaking down as well as an accelerator to decrease thickening time. The lead slurry is light slurry that contains a freezing point depressant which enables the cement to set up rather than freeze. . . CEMENT CALCULATIONS: Casing Size Basis 10.75-in 45.5-lblft L-80 BTC surface casing 125% excess over gauge hole in permafrost interval. 50% excess over gauge hole below permafrost. To'.> of tail cement 750-ft MD above casing shoe. Wash 20-bbl Water Spacer Total Cement Vol: 488-bbl Spacer Lead Tail . Casing Size 17.625-in 29.7-lbIft L-80 BTC-M intermediate casing, 1- Stage Basis Top of tail cement 6,150-ft MD, 60% excess over gauge - ES CEMENTER Depth Total Cement Wash 10-bbl Water Vol: 124-bbl Spacer Tail Casing Size 7.625-in 29.7-lbIft L-80 BTC-M intermediate casing 200 Stage Basis Top of tail cement 5,OOO-ft MD, Top of Lead 4,150 ft. MO - TAM Port Collar depth Total Cement Wash 20-bbl Water Vol: 99-bbl Spacer Lead Tail Casing Size 17.625-in 29.7-lbIft L-80 BTC-M intermediate casing 3rd Stage Basis Top of tail cement 2,960-ft MD, top of lead Surface 0% Excess Total Cement Wash 1O-bbl Water Spacer Vol: 166-bbl Spacer Lead Tail NS32 Permit to Drill . . WELL CONTROL: ~ A Diverter waiver has been requested on well NS32. To date, BP has successfully drilled all development wells through the Northstar upper strata-graphic intervals, absent any complications associated with shallow gas. All surface holes have been drilled and cemented to a common depth of approximately 3,170' TVDss depth, (-150' TVD below the top of the SV6), with one well extending into the SV5 -3280' TVDss. Well mud logs and seismic data do not indicate the presence of a shallow gas hazard. ~ Equipment to be Installed and capable of handling maximum potential surface pressures. (Schematics are on file with the AOGCC and MMS.) · 5000 psi working pressure pipe rams (2) · Blind/shear rams · Annular preventer ~ Based upon the calculations below, BOP equipment will be tested to 4800 psi. Surface Section: · Maximum anticipated BHP: 1397 psi @ 3050' TVDss - SV6 · Maximum surface pressure: 1092 psi @ surface (Based on BHP and a full column of gas from TD @ 0.1 psilft) Intermediate Section: · Maximum anticipated BHP: 2926 psi @ 6450' TVDss - Base Ugnu · Maximum surface pressure: 2281 psi @ surface (Based on BHP and a full column of gas from TD @ 0.1 psilft) Injection Interval (barefoot) Section: · Maximum anticipated BHP: 3008 psi @ 6631' TVDss - Total Depth · Maximum surface pressure: 2345 psi @ surface (Based on BHP and a full column of gas from TD @ 0.1 psilft) · Planned BOP test pressure: 4800 psi (annular to 3500 psi) · Planned completion fluid: 9.8 ppg Seawater /6.8 ppg Diesel DRILLING HAZARDS/CONTINGENCIES: HYDROGEN SULFIDE - H2S: ./ Northstar is not designated as an H~ drill site, however Standard Operating Procedures for H~ precautions should be followed at all times. ./ rm H2S was detected at Northstar while drilling or testing the Seal Island A-01, A-02, or A- 03 exploration/appraisal wells. ./ No H2S was detected while drilling the NS10 waste disposal well, or any subsequent Northstar wells. Reference information below on file with AOGCC: ~ Northstar/Nabors 33E H2S contingency plan. ~ Well test hydrocarbon analyses for Seal Island A-D1, A-02, and A-D3. DISPOSAL: Annular Injection: There will be no annular injection in this well. Cuttings Handling: Cuttings generated from drilling operations will be processed in the Grind and Inject Facility on Nabors 33E and will be disposed of in the NS10 Class I Waste Disposal Well. Fluid Handling: All Class I and Class II fluids will be processed by the Grind and Inject Facility on Nabors 33E and will be disposed of in the Northstar NS10 Class I Waste Disposal Well. 9 NS32 Permit to Drill . . SURFACE HOLE SECTION: · Mudloggers will be rigged up throughout the entire section. · No significant drilling problems have been identified in the surface hole interval based on offset data. Good hole cleaning and management of required mud properties are key to a successful interval. · Minor tight hole conditions have been noted in the shale intervals immediately below the pennafrost during short trips. · Differential sticking could be problematic in this hole section adjacent to the permeable SV Sands. Avoid leaving drill string stationary for extended periods; tighten fluid loss properties of mud. '. · Lost circulation has only been noted while drilling during hole opening runs and was most likely induced by poor hole cleaning. Losses have occurred while running and cementing surface casing. The NS27 experienced losses on the surface cement job at a rate of 12 BPM. The displacement rate was lowered to 10 BPM and full retums were re-established. Be sure to condition and thin mud appropriately prior to pulling out of the hole to run casing, and once on bottom with casing, bring circulation up slowly and reduce mud viscosities before pumping cement. Minor losses were seen on NS29 while running the 13 318" surface casing. Reduced running speed eliminated losses and the casing was cemented at 10 BPM displacement rate. · Gas hydrates may be present near the base of the permafrost. Wells drilled in the 2000-2003 drilling season have not experienced hydrates. Mudloggers will be used continuously on NS32 to help identify and trend any increase in background gas readings. If gas hydrates are encountered, mud weight may be increased to 10.2 ppg and treated with 2 ppb Driltreat (Lecithin). Additional measures include reducing flow rates to -450 to 500 gpm and keeping the mud temperature cool. INTERMEDIATE I INJECTION INTERVAL SECTION: · Mudloggers will be rigged up throughout these sections. · Minor gas shows have been reported in the four (4) Seal Island wells and have been identified as coal associated methane. No indications of shallow gas were seen while drilling during the 2000-2003 drilling season. Mudloggers will be used continuously on this well to help identify and trend any increase in background gas readings. Surface casing will be set prior to any intervals with previously noted gas shows to facilitate nippling up the BOP's. A minimum of 9.0 ppg is recommended. · The shallow intervals beneath Northstar are, by interpretation, not faulted. To be prepared for any potential lost circulation, a copy of the 'Non-Payzone Lost Circulation Decision Tree' can be found in the last section of the Master Well Plan, which can be found on the rig. · Pressure While Drilling (PWD) will be used to monitor the annular pressure. The pressure data will be used to minimize the equivalent circulating density (ECD), minimize lost circulation due to packing off due to loading up the wellbore with solids and provide for an additional well control tool to make sure the well does not become under-balanced. · Differential sticking can be a problem if lost circulation is occurring or if the drill string is left stationary for an extended period or time across the permeable SV Sands. · The kick tolerance for the 97/8" open hole section would be 62.7 bbls assuming an influx from the Schrader Bluff interval at 6505' TVD. This is the worst-case scenario based on a 9.15 ppg (0.5 ppg over the known pore pressure) pore pressure gradient, a fracture gradient (LOT) of 11.5 ppg at the 10 3A" shoe, and 9.3 ppg mud in the hole. · The kick tolerance for the 6 3A" open hole section would be infinite bbls assuming an influx from the Schrader Bluff interval at 6687' TVD. This is the worst-case scenario based on a 9.15 ppg (0.5 ppg over the known pore pressure) pore pressure gradient, a fracture gradient (LOT) of 11.0 ppg at the 7 5/8" shoe, and 9.3 ppg mud in the hole. 10 NS32 Permit to Drill . . NS32 Ria-site Summary of DrillinQ Hazards **POST THIS NOTICE IN THE DOGHOUSE** ...¡ Mudloggers will be used continuously on NS32 to help identify and trend any increase in background gas readings ~ Gas hydrates may be present near the base of the permafrost. If gas hydrates are encountered, mud weight may be increased to 10.2 ppg and treated with 2 ppb Driltreat (Lecithin). Additional measures include reducing flow rates to -450 to 500 gpm and keeping the mud temperature cool. ~ Minor gas shows have been reported in the four (4) Seal Island wells and have been identified as coal associated methane. No indication of shallow gas was seen in any previously drilled Northstar wells. . Surface casing will be set prior to any intervals with previously noted gas shows to facilitate nippling up the BOP's. ...¡ Differential sticking could be problematic in both the surface and intermediate hole sections adjacent to the permeable SV Sands. Avoid leaving drill string stationary for extended periods; tighten fluid loss properties of mud. ...¡ Packing off due to improper hole cleaning can lead to stuck pipe. The PWD data, pick- up/slack-off weights and other drilling parameters must be monitored at all times. If in doubt, stop and condition the hole prior to drilling ahead or tripping. ...¡ Though no faulting has been identified, be prepared for any potential lost circulation. A copy of the 'Non-payzone Lost Circulation Decision Tree' can be found in the last section of the Master Well Plan, which can be found on the Rig. ...¡ Northstar is not a designated H2S pad. CONSULT THE NORTHSTAR PAD DATA SHEET AND THE WELL PLAN FOR ADDmONAL INFORMATION 11 . July 29, 2003 . Proposed Completion Diaaram Northstar Well NS32 I WD-02 Cement/Stage Collar 1000' MD KOP: 400' Max. Angle 45° Departare at BHL: Approx 4540' Base Permafrost 1643' MD (1519' SS) 3750' MD (3050' SS) · SV 6 4114' MD w: SV 5 . (3309' 5S) œ c~ -- 1~ t:a <C 5205' MD · (4085' SS) · SV 2 SV1I.... .'.~0Z~~~:~;$~~ 6240' MD .> ",\~j)l,¡¡~E,BW:~;¡~,\~~. (4821' SS) TMBK c- .5!~ ÜCI CD_ ]'.5 . (6880' SS) PRINCE CREEK AND UGNU FORMATIONS SCHRADER BLUFF :.~.::~~ MD (BKB) (measured depth below rig) 20" Conductor 200' MD (145' SS) 10-3/4",45.5#, L-80 Casing 'X' Nipple 2150' MD (1912' 55) 2250' MD Heat Tracing 3961' 'MD (3200' SS) Cement/Stage -4150'MD Collar 4-112",12.6#, L-80 Tubing Packer 5155' MD Cement/Stage Collar -6150'MD ~9-7/8" Hole 7-5/8",29.7#, L-80, Casing (Run T.D. to Surface) 8112' MD (6450' SS) 7-5/8" Shoe i;~;~{.~;y·· ' 6-3/4" Open Hole 8312' MD (6631' SS) .'~ ..., TREE:ABB-VGI5 1/8" 5'- WELLHEAD:ABB-vGI11" Multbowl5ksl 20', 169# X-56 @200'MD- 10 3/4", 45.5#Ift, L-80, BTC @¡3961' MD 4.5", 12 .6#/ft, L-$O, IBT -MOD TUBING ID: 3.958" CAPACITY: 0.015 BBLlFT 4.5" 'XN' NIPPLE, @ 8072' 3.725" ID (OTIS) 75/8", 29.7#/ft L-80, BTC-M @8112'MD TD @8312' MD 6686' TVD NS32 DATE 6118/03 7/15/03 REV. BY JAS FH COMMENTS initial Diagram Proposed Completion . RKB. ELEV - 55.30' KB-BF. ELEV - 39.40' BASE FLANGE ELEV -15.9' 'X'Nlpple@¡ 2150'MD 3.813·'D Heal Trace @¡ 2250' MD . . Cement Baker S3 PACKER 3.875"ID @ 5155' MD 4.5" WLEG, @8100'MD 6 3/4"open hole North star WFI I : NS32 API NO: 50-029- BP Exploration (Alaska) Permit to Drill MMS Section 250.414 (f) (5) (iv) (9) Estimated Values (ppg) 9 10 11 12 13 14 . 8 o . 15 16 """:-Pore Pressure (ppg) 1000 --- Mud Weight (ppg) -.- Frac Gradient (ppg) 2000 ~ 1)3000 .æ · x . - .c Õ. CD Q 4000 0) c 33 CD (/) 0)5000 c .- f/) ca 0 6000 · ~: x . · x . 7000 8000 Casing Depth Pore Pressure t-rac Gradient I rip Margin Surge Margin (TVD) (ppg) Mud Weight (ppg) (ppg) (ppg) (ppg) 3255 8.65 9.5 13 9.15 12.5 6505 8.65 9.3 12 9.15 11.5 6687 8.65 9.3 12 9.15 11.5 . . Oilfield Services. Alaska Schlumberger Drilling & Measurements SchlumblPU8r 3940 Arctic Blvd. Site 300 Anchorage. AI< 99503 Tel (907) 273-1766 Fax (907) 561-8357 MOnday. August 25. 2003 Barbara Holt Northstar NS32 (P6) Nabors 33E BP Exploration Alaska Close Approach Analysis We have examined the potential intersections of subject well with all other potentially conflicting wells, according to the SPA Directional Survey handbook (BPA-D-004) dated 09199. Method of analysis: 1. A list of wells to be analyzed is created in Compass by peñorming a global scan with an initial search radius of two thousand feet with an increment of one hundred feet for every one thousand feet of measured depth in the subject well. W 2. Wells are analyzed using the Compass Anti~lision module (BP Company setup) with major risk safety E factors applied. For problem wells that are plugged and abandoned or that can be shut in, risk-based safety factor :3 may be used, with client notification. g 3. All depths are relative to the planned well profile. t3 ¢ ... Survey Program: Instrument Type GYD-GC-SS MWD-IFR-MS Start Depth 40.20' md 1,200' md End Depth 1,200' md 8.311.93' md Ü :!. <. ~, ~ ro Close ADDroach Analvsis results: Under method (2): All wells pass. Note, it is recommended to use the risk base rule set (1 :200) to increase the drilling space around NS31 in the surface hole. All data documenting these procedures is available for inspection at the Anadrill Directional Planning Center. Close APoroach Drillina Aids to be orovided: A drilling map, with offset wells on the plan view, and traveling cylinder will be provided. Checked by. Scott Delapp 08125/03 bp 0 NS32 (P6) Proposal Schlumbepgep R8port Dtà: Augusl26. 2003 ~ .....,.... -..... ...... """""'" """'" CIIIIIt BP Exploration Alaska Verticil tecIIon AIInIuIh: 32.sæ- FIIId: Ncr1hsIa- 81 3 Vd:lltecIIonOrlgln: NO.OOOft. EO.OOOII "':E E,"/....Approved 'M) IWftncI DIIum: KB 'M) Refnnce EIMIIon: 55.3 II IIIIaIIve 10 MSL s.. Bed I Oround I.IVII EIMIIon: 15.670 II relaIIve ID MSL . UWIIAPII: 50029 MIgneIIc DecIInIIIon: 25.6W Surw1 NIIIII/OII.: NS32 (P6) / Ny 16, 2003 ToIII FIeld SIrIIIItI: 57584.406 n T Tort/AHO/DOI/ERDnIIIo: 64.3-43"/4540.40 11/5.560/0.679 MIpeIIc DIp: 80.983" Grfd CoordInå SyIIem: NAD27 Alaska Stale Planes, Zone 04, us Feet DecIInIIIon 011.: September 20, 2003 LOCIIIon UIII.øng: N 70.49159610, W 1~.69333956 Magnetic DecIInaIIon Model: BOOM 2003 LOCIIIon GrId HIE YIX: N 6031131.220 nus. E 659821.460 flUS North Aef-= True North Grfd Con¥tI IIICI Angle: +1.23167222" ToIII Corr Mag North.. TM North: ~.6W Grfd Sell, FIttar: 0.99992902 I.OCII CoonIInateI Refftnctc To: WeB Head CommtnIt MeImnd IncIInIIIon AzImuIII TV[) Sub-StI TV[) VertIc* HS EW Dt.8 Tool F_ Northing EøtIn UItIIudt longitude DepCII Stc:tIon (ft) (deg) (ctea) (ft) (ft) (ft) (ft) (ft) ( degtOO ft) (cleøl (flUS) (IIUS) KBE 0.00 0.00 32.59 0.00 -55.30 0.00 0.00 0.00 0.00 32. 9M 6031131.22 659821.46 N 10.49159610 W 148.69333956 KOP Bid 1.51100 300.00 0.00 32.59 300.00 244.10 0.00 0.00 0.00 0.00 32.59M 6031131.22 659821.46 N 10.49159610 W 148.69333956 Bid 2.511 00 400.00 1.50 32.59 399.99 344.69 1.31 1.10 0.71 1.50 32.59M 6031132.34 659822.14 N 10.49159911 W 148.69333380 500.00 4.00 32.59 499.87 444.57 6.11 5.14 3.29 2.50 32.59M 6031136.43 659824.64 N 10.49161015 W 148.69331268 600.00 6.50 32.59 599.44 544.14 15.26 12.85 8.22 2.50 0.000 6031144.25 659829.40 N 10.49163121 W 148.69321240 700.00 9.00 32.59 698.52 643.22 28.74 24.21 15.48 2.50 0.000 6031155.76 659836.41 N 10.49166225 W 148.69321303 800.00 11.50 32.59 796.91 741.61 46.53 39.21 25.06 2.50 0.000 6031170.95 659845.67 N 10.49110321 W 148.6931. 900.00 14.00 32.59 894.44 839.14 68.60 57.80 36.95 2.50 0.000 6031189.80 659857.16 N 70.49175400 W 148.6930 1000.00 16.50 32.59 990.91 935.61 94.90 19.98 51.11 2.50 0.000 6031212.25 659810.84 N 70.49181454 W 148.69292113 1100.00 19.00 32.59 1086.14 1030.84 125.39 105.64 61.53 2.50 0.000 6031238.28 659886.10 N 10.49188411 W 148.69218151 1200.00 21.50 32.59 1179.95 1124.65 159.99 134.81 86.11 2.50 0.000 6031261.84 659904.71 N 10.49196431 W 148.69263513 Top Perm 1226.23 22.18 32.59 1204.30 1149.00 169.75 143.02 91.43 2.50 O.DOG 6031276.16 659909.78 N 70.49198681 W 148.69259220 1300.00 24.00 32.59 1272.11 1216.87 198.66 167.39 107.00 2.50 0.000 6031300.85 659924.83 N 10.49205331 W 148.69246488 1400.00 26.50 32.59 1362.61 1307.31 241.32 203.32 129.91 2.50 0.000 6031331.28 659941.02 N 10.49215155 W 148.69221108 1500.00 29.00 32.59 1451.10 1395.80 281.81 242.55 155.05 2.50 O.OOG 6031311.03 659911.25 N 10.49225811 W 148.69201209 1800.00 31.50 32.59 1531.41 1482.17 338.25 284.99 182.18 2.50 0.000 6031420.04 659991.46 N 10.49231466 W 148.69185029 B8sePerm 1643.45 32.59 32.59 1574.30 1519.00 361.30 304.41 194.60 2.50 O.DOG 6031439.72 660009.45 N 70.49242771 W 148.69174880 1700.00 34.00 32.59 1621.57 1586.21 392.34 330.57 211.32 2.50 0.000 6031466.23 660025.61 N 10.49249916 W 148.69161211 1800.00 36.50 32.59 1703.23 1647.93 450.05 379.19 242.40 2.50 0.000 6031515.51 660055.63 N 70.49263200 W 148.69135801 1900.00 39.00 32.59 1182.29 1726.99 511.27 430.11 215.37 2.50 0.000 6031567.78 660087.49 N 70.49277290 W 148.69108846 Versloo DO 3.1 RT ( d031 rt.546 ) 3.1 RT -SP3.03 NS32\NS32\Plan NS32\NS32 (P6) Generated 8/26/2003 1 :16 PM Page 1 of 2 CoInmIfttt MeeIInd IncIInItIon AzImIð 'M) Subo8M'M) VtI1IcII NS EW DU Tool F.. NortIIIng EøIIng Depdt SectIon L.ItItude LongIIude (ft) (deø) (dea) (ft) (ft) (ft) (ft) (ft) ( degltOO ft ) (dea) (ftUS) (ftUS) 2000.00 41.50 32.59 1858.61 1803.31 575.87 485.21 310.17 2.50 O.OOG 6031622.95 660121.10 N 70.49292161 W 148.69080397 2100.00 44.00 32.59 1932.04 1876.74 643.75 542.40 346.73 2.50 O.OOG 6031680.90 660156.42 N 70.49307783 W 148.69050510 End Bid 2126.86 44.67 32.59 1951.25 1895.95 662.52 558.21 356.64 2.50 O.OOG 6031696.93 660166.19 N 70.49312104 W 148.69042243 SV5 (Top Confining 3749.66 44.67 32.59 3105.30 3050.00 1803.42 1519.49 971.32 0.00 O.OOG 6032671.12 660759.83 N 70.49574696 W 148.68539797 Zone) 1tJ.:JW C8g Pt 3960.59 44.67 32.59 3255.30 3200.00 1951.71 1644.43 1051.19 0.00 O.OOG 6032797.75 660836.99 N 70.49608826 W 148.68474481 SVS (S8se ConfIning 4113.86 44.67 32.59 3364.30 3309.00 2059.47 1735.22 1109.23 0.00 O.OOG 6032889.76 660893.06 N 70.49633627 W 148.6841 Zone, SV4 4621.49 44.67 32.59 3725.30 3670.00 2416.35 2035.92 1301.45 0.00 O.OOG 6033194.50 661078.76 N 70.49715764 W 148.682 SV3 4949.13 44.67 32.59 3958.30 3903.00 2646.69 2230.00 1425.52 0.00 O.OOG 6033391.18 661198.61 N 70.49768778 W 148.681 8 (Top Upper Injection 5205.05 44.67 32.59 4140.30 4085.00 2826.62 2381.60 1522.42 0.00 O.OOG 6033544.82 661292.23 N 70.49810187 W 148.68089073 zone) SV1 {Top Major Shale 5749.24 44.67 32.59 4527.30 4472.00 3209.21 2703.95 1728.49 0.00 O.OOG 6033871.50 661491.30 N 70.49898237 W 148.67920514 Barr1e" Drp 2.51100 6225.06 44.67 32.59 4865.68 4810.38 3543.73 2985.81 1908.66 0.00 160.000 6034157.14 661665.36 N 70.49975224 W 148.67773121 TM8K {Top Lower Injectfon Zone . Top 6239.95 44.30 32.59 4876.30 4821.00 3554.16 2994.60 1914.28 2.50 180.00G 6034166.05 661670.79 N 70.49977625 W 148.67768524 UGNU' 8300.00 42.80 32.59 4919.82 4864.52 3595.53 3029.45 1936.56 2.50 180.000 6034201.38 661692.32 N 70.49987145 W 148.67750295 6400.00 40.30 32.59 4994.65 4939.35 3661.85 3085.33 1972.28 2.50 180.000 6034258.00 661726.83 N 70.50002408 W 148.67721072 6500.00 37.80 32.59 5072.31 5017.01 3724.84 3138.41 2006.21 2.50 180.000 6034311.79 661759.60 N 70.50016905 W 148.67693315 6600.00 35.30 32.59 5152.64 5097.34 3784.39 3188.58 2038.28 2.50 180.000 6034362.64 661790.59 N 70.50030608 W 148.67667076 6700.00 32.80 32.59 5235.49 5180.19 3840.37 3235.75 2066.43 2.50 180.000 6034410.44 661819.72 N 70.50043492 W 148.67642406 6800.00 30.30 32.59 5320.70 5265.40 3892.69 3279.83 2096.61 2.50 180.000 6034455.11 661846.94 N 70.50055532 W 148.67619351 6900.00 27.80 32.59 5408.12 5352.82 3941.24 3320.73 2122.76 2.50 180.000 6034496.57 661872.20 N 70.50066705 W 148.67597958 7000.00 25.30 32.59 5497.57 5442.27 3985.93 3358.39 2146.83 2.50 180.000 6034534.73 661895.46 N 70.50076990 W 148.67578261 End Drp 7011.93 25.00 32.59 5508.36 5453.06 3991.00 3362.66 2149.56 2.50 0.000 6034539.06 661898.10 N 70.50078156 W 148.675. 7-5f8-C8g Pt 8111.91 25.00 32.59 6505.29 6449.99 4455.88 3754.34 2399.9ð 0.00 O.OOG 6034936.00 662139.99 N 70.50185136 W 148.6737 1 Target 8111.93 25.00 32.59 6505.30 6450.00 4455.88 3754.34 2399.96 0.00 0.000 6034936.00 662140.00 N 70.50185137 W 148.67371149 WS1 (Top Schr&der 8111.94 25.00 32.59 6505.31 6450.01 4455.89 3754.34 2399.96 0.00 O.OOG 6034936.01 662140.00 N 70.50185138 W 148.67371147 8fuff. Base UGNU) TD 8311.93 25.00 32.59 6686.56 6631.26 4540.40 3825.56 2445.49 0.00 0.000 6035008.17 662183.98 N 70.50204588 W 148.67333896 Leo.1 Descrtøtlon: Northlna m rftUS1 Eaatlna 00 rftUS1 Surface: 1358 F8L 649 FEL 811 T13N R13E UM 6031131.22 659821.46 Target: 5112 FSL 3526 FEL 812 T13N R13E UM 6034936.00 662140.00 BHL: 5183 F8l3481 FEL 812 T13N R13E UM 6035008.17 662183.98 Version ~ 3.1 RT ( do31rL546 ) 3.1 RT -SP3.03 NS32\NS32\Plan NS32\NS32 (P6) Generated 8/26/2003 1 :03 PM Page 2 of 2 .... NS32 (P6) -- ......: ....,.. 3000 I '!': g ... II CD ! 4000 ~ bp 0'··, . .... . . ScIIlumberger _0 ."...,..... Northstar PF Northstar .., ..... 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BPX AI( Anticollision Report . C..a~: BP~ Field: Northstar Refereace SIte: Northatar PF Ref'ereaœ WeD: NS32 Ref'ereace WeUpatb: Plan NS32 NO GLOBAL SCAN: Uliag uer defiaed lelectioa " laa criteria laterpolatioa Metbod: MD latenal: 50.00 ft Deptb Raqe: 39.40 to 8311.93 ft Maximum Radius: 3000.00 ft Survey Program for Defiaitive Wellpatb Date: 311812002 Validated: No Plauaed From To Survey ft ft 39.40 1200.00 Planned: Plan ##6 V2 1200.00 8311.93 Planned: Plan ##6 V2 Cuiq Poiats ···:r·· 3960.59 8111.93 8311.93 Stuamary TVÐ '.." 3255.30 6505.30 6686.57 ...~.~ 10.750 7.625 6.750 Northstar PF Northstar PF Northstar PF Northstar PF Northstar PF Northstar PF Northstar PF Northstar PF Northstar PF Northstar PF Northstar PF Northstar PF Northstar PF Northstar PF Northstar PF NorthstarPF Northstar PF Northstar PF NorthstarPF Northstar PF Northstar PF Northstar PF Northstar PF Northstar PF Seal Island SealIsIand SealIsIand Seal Island Seallsfand ói1i(Itw~ . Welr·.'~<···· ',' .'.",,';' NS06 NS07 NS08 NS09 NS10. NS12 NS13 NS14 NS15 NS16 NS17 NS18 NS19 NS20 NS20 NS21 NS22 NS23 NS24 NS25 NS26 NS27 NS29 NS31 SEAL-A-01 SEAL-A-02 SEAL-A-02 SEAL-A-03 SEAL-A-04 BOle Size . in 13.500 9.875 6.750 . N..~ 10 314- 7-518- open )0;'> ·';;:·W~.. ,.,,'., ". NS06 V34 NS07 V33 NS08 V18 NS09 V14 NS10 V17 NS12 V28 NS13 V12 NS14 V11 NS15 V19 NS16 V39 NS17 V12 NS18 V12 NS19 V17 NS20 V4 NS2OPB1 V10 NS21 V46 NS22 V13 NS23 V33 NS24 V15 Plan NS25 V7 Plan: Pia NS26 V22 NS27 V29 NS29 V22 NS31 V14 SEAL-A-01 V4 SEAL-A-02 VO SEAL-M)2A V4 SEAL-A-03 V4 SEAL-A-04 V4 Date: 812612003 Time: 13:34:50 Page: Co-erdiaate(NE) Réfereace: Vertical (fVD)Ref'ereace: Well: NS32. True North NS32 plan 55.3 Ref'ereac:e: Error Model: Scaa Met1aod: Error Surface: Db: Sybase Principal Plan & PLANNED PROGRAM ISCWSA Ellipse Trav Cyfinder North EUipse + Casing Venioa: 3 Toolcode Tool Name GYD-GG-SS MWD+IFR:AK Gyrodata gyro single shots MWD + IFR [Alaska] ····'.~T~·i.\ #: . ·')·ft·:>.; 346.64 350.00 260.75 6.48 254.27 Pass: Major Risk 149.17 150.00 251.19 3.01 248.18 Pass: Major Risk 299.29 300.00 239.76 5.39 234.36 Pass: Major Risk 394.36 400.00 235.08 6.92 228.16 Pass: Major Risk 441.60 450.00 215.00 7.29 207.70 Pass: Major Risk 346.91 350.00 194.92 6.85 188.07 Pass: Major Risk 395.13 400.00 193.86 7.04 186.82 Pass: Major Risk 396.09 400.00 177.65 7.26 170.39 Pass: Major Risk 347.55 350.00 171.19 6.40 164.79 Pass: Major Risk 395.12 400.00 159.45 7.47 151.98 Pass: Major Risk 395.71 400.00 152.80 6.48 146.32 Pass: Major Risk 396.48 400.00 138.92 8.06 130.86 Pass: Major Risk 396.28 400.00 128.97 7.23 121.74 Pass: Major Risk 397.45 400.00 120.78 6.58 114.19 Pass: Major Risk 397.45 400.00 120.78 6.58 114.19 Pass: Major Risk 444.58 450.00 108.32 8.25 100.07 Pass: Major Risk 48.79 50.00 99.87 1.26 98.61 Pass: Major Risk 396.86 400.00 88.84 7.26 81.58 Pass: Major Risk 397.63 400.00 78.94 7.32 71.62 Pass: Major Risk 398.04 400.00 70.85 7.68 63.17 Pass: Major Risk 349.26 350.00 61.65 6.55 55.10 Pass: Major Risk 348.96 350.00 48.35 6.77 41.58 Pass: Major Risk 447.84 450.00 30.87 7.98 22.89 Pass: Major Risk 399.10 400.00 10.21 7.29 2.92 Pass: Major Risk 1270.45 1250.00 79.64 24.21 55.43 Pass: Major Risk 1217.05 1200.00 93.39 25.87 67.52 Pass: Major Risk 1217.59 1200.00 91.31 22.47 68.84 Pass: Major Risk 1218.53 1200.00 81.71 20.59 61.13 Pass: Major Risk 1335.67 1300.00 76.95 24.80 52.15 Pass: Major Risk . . BPX AK Anticollision Report CompaD)': BP Amoco FWd: Northstar Rd'ereace Site: NoI'thstar PF Ref'ereDee Well: NS32 Refereace WeDpatla: Plan NS32 NO GLOBAL SCAN: Vliac Iller clefiaed ldectioD &. scaD criteria IDterpolatioD Metlaod: MD laterval: 50.00 ft Depth Raace: 39.40 to 8311.93 ft Maximum Radius: 3000.00 ft Date: 812612003 Time: 14:14:53 Pace: 1 Co-ordfDate(NE) Refereac:e: Vertieal (TVD) Refereac:e:· Well: NS32. True North NS32 plan 55.3 Db: . Sybase Principal Plan & PLANNED PROGRAM ISCWSA Ellipse T ray Cylinder North Ellipse + Casing Refereaee: Error Model: SeaD Metlaod: Error Surface: Sarvey Prognm for Defiaitive Wellpatla Date: 311812002 Validated: No PlaDaed From To Survey ft ft 39.40 1200.00 Planned: Plan #6 V2 1200.00 8311.93 Planned: Plan #6 V2 Venioa: 3 Tooleode Tool Name GYD-GC-SS MWD+IFR:AK Gyrodata gyro single shots MWD + IFR [Alaska] Cui.. PoiDIs ":~':' 3960.59 8111.93 8311.93 &a-ry ~~f{',·, TVD ..ft 3255.30 6505.30 6686.57 DIameter In. 10.750 7.625 6.750 Bole Sbe . 'In 13.500 9.875 6.750 Name 10314· 7-5m" open . ..':itê(ere.,«<~;, MD ..... MD : > :ft':' ; )1;J;'i~i;{:~"J8\ 346.64 350.00 260.75 149.17 150.00 251.19 299.29 300.00 239.76 394.36 400.00 235.08 441.60 450.00 215.00 346.91 350.00 194.92 395.13 400.00 193.86 396.09 400.00 177.65 347.55 350.00 171.19 395.12 400.00 159.45 395.71 400.00 152.80 396.48 400.00 138.92 396.28 400.00 128.97 397.45 400.00 120.78 397.45 400.00 120.78 444.58 450.00 108.32 48.79 50.00 99.87 396.86 400.00 88.84 397.63 400.00 78.94 398.04 400.00 70.85 349.26 350.00 61.65 348.96 350.00 48.35 447.84 450.00 30.87 349.20 350.00 9.57 1270.45 1250.00 79.64 1217.05 1200.00 93.39 1217.59 1200.00 91.31 1218.53 1200.00 81.71 1335.67 1300.00 76.95 ....:i!.¡ '.. ,'c·', ,.".,"..;:'.- Nocthstar PF Nocthstar PF NorthstarPF Northstar PF Northstar PF Northstar PF Northstar PF Northstar PF Northstar PF Northstar PF Northstar PF Northstar PF Northstar PF Nocthstar PF Northstar PF Northstar PF Northstar PF Northstar PF Northstar PF Northstar PF Northstar PF Northstar PF Northstar PF Northstar PF Sea/Island SealIsIand SealIsIand Seal Island Sea/Island NS06 NS07 NSOS NS09 NS10 NS12 NS13 NS14 NS15 NS16 NS17 NS18 NS19 NS20 NS20 NS21 NS22 NS23 NS24 NS25 NS26 NS27 NS29 NS31 SEAL-A..()1 SEAL-A-02 SEAL-A-02 SEAL-A"()3 SEAL-A-04 NS06 V34 NS07 V33 NSOS V18 NS09V14 NS10 V17 NS12 V28 NS13 V12 NS14 V11 NS15 V19 NS16 V39 NS17 V12 NS18 V12 NS19 V17 NS20 V4 NS2OPB1 V10 NS21 V46 NS22 V13 NS23 V33 NS24 V15 Plan NS25 V7 Plan: PIa NS26 V22 NS27 V29 NS29 V22 NS31 V14 SEAL-A-01 V4 SEAL-A-02 VO SEAL-A-02A V4 SEAL-A-03 Vol SEAL-A-04 V4 6.48 3.01 5.39 6.92 7.29 6.85 7.04 7.26 6.40 7.47 6.48 8.06 7.23 6.58 6.58 8.25 1.26 7.26 7.32 7.68 6.55 6.77 7.98 2.81 24.21 25.87 22.47 20.59 24.80 254.27 248.18 234.36 228.16 207.70 188.07 186.82 170.39 164.79 151.98 146.32 130.86 121.74 114.19 114.19 100.07 98.61 81.58 71.62 63.17 55.10 41.58 22.89 6.76 55.43 67.52 68.84 61.13 52.15 Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Minor 11200 Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk U\IIIItÐ/CIt INFOINATION ~~........, ...c.e.: NS32. T_ Nath V.- .........., MSS1.... 55.30 ...... .........., SIoI· (O.OØN,O.OOE) w.-n.I DoItIh......: NSSl pion 55.30 c:.Icahûxt MOIhod: M__ o.r..n Northstar Northstar PF NS32 Plan NS32 Field: Site: WeD: WeDpath: FIELD DETAILS "....... ~~TIS 000d0Iiei1/2 us....... ~ Sy-. 191'1 . NADZ7(CIIIb 1866) AIoob, Zano4 Mopotic Modo!: IItpo2OO3 .,.. ~ MoMSeo~ LocoI North: T__ . . ._-~------------ A2im_ro T.... No.,¡, M.... North: 1$.11' æYIIId . 57S6OnT 0-. An . 1O:I6' ()on: 911011OO3 Meclet Itøm1OO3 NS25 (Pbn NSlS) I 2000 I) 1 i , I ' I ..~.. .-.+... ¡ ..--..;: ! SI!AW.~(BEA1M-041 '____-:._-+----.: ""120 ". - .T I 110 ^ M ..: .41 , . I . .... '. "1 . ... ._~ . --- ----- -- --- -~ --r- -- ----~ ------ I . " I MS12<NS22l i 'II," . .. .. , ! , i i , , , .. þ. -- ! , i I i 90 ' ... ¡ ~.. I .·~o : . NSI1(NSIZ) i --._..0--"---,-,- --.t-...-- i I i A.Qz(8EAL-A-02) ! ð.1IJII~f.) I , toO 90 i , i , i .! .___.1_____ : I I i .J . 1'.80 i ! I 9000 ì 6000 , ..- II) o 1~~(NSI9) 10 _. .-. -- . .fIO N' .. I 3000 ,0 \ I' I 1-- -j I o ---- I ·3000 " ~ ". l' i I , 1.~flØBl):I~..: -. ..... : ":-"'\,,~oo' I ~''\. 9000---- i ':"'\.~ -J I · r _ I. MSII{NsIS, . · --- I --~- -----.- . I - . NSI1(NS1?> 'k!.to.. !~ .. ¡ . I · - I I I - i .. 3000- ..¡-- I I I _. I I· ... ¡ · I 0- ! I - I ! · , I - I - I , .3000- . .!.. · , I · ¡ - I - 1___- ~----------.-r I ¡ , i I I \ i ·11000 I -9000 -9OOG ·15000 I I t . . JO "') '. ---~ " ~ "'-. , ,."" \.; '\ \ \ \ ., \ \ \ i / ". / I // . / ./ Nortbsœr Nortbsœr PF NS32 Plan NS32 ~.....--~ ~'" " "- , \. \... \ I I I , / // // .----/ " NS26 (NS26) _ . N '''~.. ''iIi~9fS~S5jI T....llina CyIincIor Azimuth (fFO+AZI) (dea)" c.m..to CenIn ~ (6OftJift) Field: Site: Well: WeUpath: NS21 27Q NS29 (NS29) _76 '-120 -- -0 -- 120 _76 I I I I .-. I j i ¡ I ~ '1 , I I I r ¡ _.' -i-- I i -- -1-----------------· i ¡ I i I : I I , ____L ! . . I 100 I ! r-· , ! i ¡ i ! i 1600 .. I , ¡ I i i --r------ , i I 1400 '- .. . I .. : .,. I 1100 -- . -. .\ I , '00 1000 M_~ Depth (100tV..) "10- v~ _,__ 0- ......... __."__ . - - - ~ eo --- I - - I - - ", . . - '," ~ ,.-. ..- 10-----. ~-:- - .. .. ~ .. ," - . . 1 . . - - I . J ~ --.....- ..-.... -..-..-... .- ¡ ! - I - ! ." -.. ~.. . - ...... .... )() .~---- , " - I. - - I - »- .-. '.. ... . .. .....1.. - I I - j - - lit I!qoMI..d'"'-~ .--'- ~ - - - ¡ - I 0 I 0 I 100 400 I I I i ! t ¡ ! t I ! i r i , I I , I I -I I I I I j I -1 I 600 . lûJF ~l~~ . I I / l I FRANK H. MURKOWSKI, GOVERNOR ~..,A.~KA. ORAND GAS CONSERVATION COMMISSION Allen Sherritt Drilling Engineer BP Exploration (Alaska), Inc. PO Box 196612 Anchorage AK 99519 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501·3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Northstar Unit NS32i BP Exploration (Alaska), Inc. Permit No: 203-158 Surface Location: 1359' NSL, 649' WEL, Sec. 11, TI3N, R13E, UM Bottomhole Location: 5184' NSL, 3481' WEL, Sec. 12, T13N, R13E, UM Dear Mr. Sherritt: 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 approvals 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 Commission 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 Commission 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 a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's North Slope petroleum field inspector at 659-3607 (pager). Sincerely, f<~ ~~ Randy Ruedrich Commissioner BY ORDER OF THE COMMISSION DATED this .11 day of September, 2003 cc: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. Exploration, Production and Refineries Section VJG~ ClîI/l.-CÐ·~ B Drill 0 Redrill 1a. Type of work 0 Re-Entry 2. Operator Name: BP Exploration (Alaska) Inc. 3. Address: P.O. Box 196612, Anchorage, Alaska 99519-6612 4a. Location of Well (Governmental Section): Surface: 1359' NSL, 649' WEL, SEC. 11, T13N, R13E, UM Top of Productive Horizon: 5113' NSL, 3526' WEL, SEC. 12, T13N, R13E, UM Total Depth: 5184' NSL, 3481' WEL, SEC. 12, T13N, R13E, UM 4b. Location of Well (State Base Plane Coordinates): Surface: x-659821 Y-6031131 Zone-ASP4 16. Deviated Wells: Kickoff Depth 18.. . yasingf'rogråm Size Casing 20" 10-3/4" 7-518" Barefoot _ STATE OF ALASKA . ALASKA O-'ND GAS CONSERVATION COM.. SION PERMIT TO DRILL 20 AAC 25.005 1b. Current Well Class 0 Exploratory o Stratigraphic Test B Service 5. Bond: IS! Blanket 0 Single Well Bond No. 2S100302630-277 6, Proposed Depth: MD 8457 TVD 6737 7. Property Designation: Y0181 o Development Oil 0 Multiple Zone o Development Gas 0 Single Zone 11. Well Name and Number: NS32i / 12, Field 1 Pool(s): Northstar Unit 8. Land Use Permit: LO-N96-006 9, Acres in Property: 5242 13. Approximate Spud Date: 10-01-03 -- 14. Distance to Nearest Property: 4800' 13-112" 9-7/8" 6-3/4" Weiç¡ht 169# 45.5# 29.7# NIA Length 201' 3961' 8112' 200' 10, KB Elevation 15. Distance to Nearest Well Within Pool (Height above GL): R::~n~3' feet 1617' away from NS22 ./ 17. Anticipated pressure (see 20 AAC 25.035) Max. Downhole Pressure: 3008 psig. Max. Surface Pressure: 2345/psig Settingiþepth . QU!ilntìtyofÇØrnept Top .....·...·....·i/i Bottom (cJ. or sacks) MD TVD MD TVD (including stage data) Surface Surface 201' 201' Driven Surface Surface 3961' 3255' 550 sx PF 'L', 394 sx Class 'G' / Surface Surface 8112' 6505' 116sxSilicalite, 159PF'L',1124sx Class'G' 8112' 6505' 8312' 6687' Barefoot Completion / Hole 20" 300 ft Maximum Hole Angle Sp¢èifications Grade Couplinç¡ X-56 WELD L-80 BTC L-80 BTC-Mod NIA NIA 45° 19. PRESENT WELL CONDITION SUMMARY (To be completed for Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effective Depth MD (ft): Junk (measured): Structural Conductor Surface Intermediate Production Liner 20. Attachments !HI Filing Fee 0 BOP Sketch o Property Plat 0 Diverter Sketch perfOration Depth TVD (ft): IS! Drilling Program 0 Time vs Depth Plot o Seabed Report 0 Drilling Fluid Program o Shallow Hazard Analysis IS! 20 AAC 25.050 Requirements Date: Contact Barbara Holt, 564-5791 Perforation Depth MD (ft): 21, Verbal Approval: Commission Representative: 22. I hereby certify that the foregoing is true and correct to the best of my knowledge. Printed Name Title Drilling Engineer Phone See cover letter for requirements DYes ~No ~Yes D No Permit To Drill API Number: Permit A~r~) ¡; ~~:~~~~:~~~p~·t£t? samp~e~ ~~q~r~ -. ~2 3/ /~es ~ No ~~~e~Og ~qU'd d_1 Hydrogen Sulfide Measures D Yes ~ No Directional Survey Required Other:U<;J- ßO P E +0 tf Boo r50 l. P4 U' Me 'L5. ,,~s (k)(L)1 tll~~'" r-¡wiM..",.~t- h w~,,~J. /'111: T, ~ t ~ u.d;)-: l () '\ 'p.. ~ 'tJ I..U.¡.J d . ~ ~ .J BY ORDER OF Approved By: ~ -"'-.. . '" R1ïG~~~LTHE COMMISSION Form 10-401 Revised 3/200: J ' , , Date tZ:~,~re bp e e BP Exploration Alaska Inc. To: Winton Aubert - AOGCC Date: September 2, 2003 From: Allen Sherritt Northstar Senior Drilling Engineer Subject: NS32 Application for Drilling Permit Mr. Aubert, Well NS32 is currently scheduled for Nabors 33E on October 1, 2003. A Diverter waiver is requested on NS32.~0 date, BP has successfully drilled all development wells through the Northstar upper strata-graphic intervals, absent any complications associated with shallow gas. All surface holes have been drilled and cemented to a common depth of approximately 3,170' TVDss depth, (-150' TVD below the top of the SV6), with one well extending into the SV5 -3280' TVDss. Well mud logs and seismic data do not indicate the presence of a shallow gas hazard. NS32 may perform an "Operation Shutdown" after drilling the surface hole. This will enable the Operations group an opportunity to tie-in the Northstar injectors after performing workovers for wellbore integrity. A Sundry for the Operation Shutdown will not be submitted, as the operations are covered in the ADP procedure. Please find attached the NS32 Well Plan Summary, directional plan and proposed completion diagram. If you should have any questions or concerns, please contact me @ 564-5204 NS32 SUMMARY DRILLING _RATIONS e Pre-Riq Work: 1. Set 20" conductor and weld an ABB Vetco landing ring for the ABB Vetco Multibowl Wellhead on the conductor. (Already performed.) 2. Install 7' x 7' cellar and polyshield same. (Already performed.) Riq Operations: 1. MIRU Nabors 33E. 2. Nipple up and function test 21-1/4" diverter system, if required. / NOTE: A diverter dispensation has been requested. Confirm dispensation decision with the Drilling Engineer. A 07 Diverter Drill will be conducted prior to spud. 3. MU 13 W' drilling assembly with MWD/GR and directionally drill surface hole to the surface casing /' point 3255' TVD, 3961' MD. POOH. 4. RU Schlumberger Wireline for open hole logs. Logging suite to include gamma ray (GR), spontaneous potential (SP), resistivity, and caliper. Use caliper results to confirm the surface cement volumes. RD Schlumberger Wireline. 5. RU and run 103,4",45.5# L-80 BTC surface casing with centralizers. /' 6. Cement the casing to surface in 1 stage (lead and tail slurries). A TAM port collar will be run at 1000' MD for a 2-stage contingency. In the event the cement does not circulate to surface, please contact the Anchorage Drilling Team. 7. NO diverter / riser system and NU casing / multi-bowl wellhead. NU BOPE and test to 250/4800 psi. /' 8. MU 97/8" drilling assembly for cleanout run. RIH to float collar. Test the 103,4" casing to 500 psi with / 9.5-ppg mud for 15 min. 9. Swap fluids to clean seawater. POOH. 10. RU Schlumberger Wireline for cement evaluation logs. Logging suite to include USIT from the 103,4" /' shoe to 500' MD. RD Schlumberger Wireline. 11. Test the 10 3,4" casing to 3500 psi with 9.5-ppg mud for 30 min. This test pressure may change based on actual mud weight in the hole. 12. RIH with open ended drillpipe to 100' below the base of the permafrost and circulate 6.8 ppg diesel to / freeze protect the well to surface. POOH 13. Install 4 W' tubing hanger and test to 5000 psi. 14. Set the TWC. NO BOP's. NU Tree. Test the tubing head adapter and tree to 5000 psi. 15. Pull TWC and install BPV (dry rod is acceptable). Test BPV from below to 3500 psi for 10 minutes. 16. RD and move off NS32 for NS27 workover. / Prepare to re-enter well 17. Prepare to re-enter well. 18. MIRU Nabors 33E. 19. Verify there is no pressure on the tree. NO tree. a. The well was left with a TWC, tested to 3500 psi from below. // 20. NU BOPE, pull the tubing hanger and run the test plug. Open annulus valve and test to 250/4800 psi. Test annular to 3500 psi. 21. Pull the test plug. Install the wear bushing. 22. RIH with open-ended drillpipe to 2000' MD, circulating/displacing out diesel to the trip tank. Change over to seawater. a. Have G&I and rig crew line up Trip Tank#1 sump to G&I disposal pump suction. b. Coordinate with G&I and circulate one surface-to-surface volume of seawater, monitoring the volume in Trip Tank #1. c. When the Mud Engineer is satisfied with the water quality, the hole can be lined up elsewhere on the rig. d. POOH . See Baroid Mud Program: Well Clean-out/Displacement Procedure. J'5~: _ 23. Test 10 3,4"JjPerto 3500 p~ 30 minutes. 24. MU 97/8" directional assembly with MWD/GR/PWD. RIH and drill 20' of new formation below 103,4" shoe. Perform LOT, targeting 11.5 ppg EMW. (FIT/LOT procedure on file with AOGCC). 25. Drill 97/8" intermediate hole to casing point at 6505' TVD, 8112' MD. Minimum mud weight of 9.3 ppg / will be required. POOH. 26. RU Schlumberger Wireline for open hole logs. Logging suite to include gamma ray (GR), spontaneous potential (SP), resistivity, density, neutron, and sonic. RD Schlumberger Wireline. 27. RU and run 7 %",29.7# L-80 BTC-M intermediate casing with centralizers. /' 28. Cement the casing string from TD to surface in 3 stages. A Tam port collar will be at 4150' MD (upper"/ portion of SV4) and an ES cementer will be at 6150' M~wer portion of the SV1) to ensure sufficient cement coverage and isolation. 29. MU 63,4" drilling assembly for cleanout run. Drill stage tool closing plug(s). RIH to float collar. Test the 7 %" casing to 500 psi with 9.3-ppg mud for 15 min. POOH. 30. RU Schlumberger Wireline for cement evaluation logs. Logging suite to include USIT from the 7 %" / shoe to 2960' MD (calculated top of lead) inside the surface casing shoe. RD Schlumberger Wireline. 31. PU 6 3,4" directional assembly with GR/MWD. RIH. Test the 7 %" casing to 4600 psi with 9.3-ppg ~ mud for 30 min. This test pressure may change based on actual mud weight in the hole. 32. Drill 20' of new formation below 7 %" shoe. Perform LOT, targeting 11.0 ppg EMW. (FIT/LOT procedure on file with AOGCC). 33. Drill 6 3,4" hole to TD at 6687' TVD, 8312' MD. Minimum mud weight of 9.3 ppg will be required while ,,/ drilling this hole section. POOH. 34. PU casing scraper on the 6 3,4" cleanout assembly. 35. RIH and displace the well to clean 9.8 ppg NaCI brine. POOH. 36. Run the 4 W' 12.6# L-80 IBT-M tubing string with heat trace. Ensure proper RAMS are run in the BOP ,/./ for Well Control. Drill pipe elevators and a TIW crossover from 4 1/2" to DP will be on the rig floor at all times. · Please Reference Completion Section · Heat trace will be run from 2250' MD to surface. · An "X" nipple will be run at 2150' MD en lieu of a SSSV. · No fiber optics will be run on this well. 37. RIH to packer setting depth of 5155' MD. Record pick-up and slack off weights. Spaceout as per tally, do not tag TD. Run space out pups as required by tubing tally. // 38. Land the hanger and RILDS. Pressure-test the tubing hanger seals to 5000 psi. 39. Rig up the manifolding (chicksan/hose) to allow U tube to equalize from the 7 %" x 4-%" annulus to the 4 W' tubing. 40. Displace corrosion inhibitor (Corexit-7726 at 25 gals/100 bbls) pill down the 7 %" x 4 W' annulus to treat from +/-5000' MD to packer setting depth. Displace annulus with heated inhibited diesel ,,/ equivalent to annulus capacity plus tubing capacity to a depth of 4000' TVD (5008' MD). Maximum displacement rate 3 BPM as per Baker recommendation to prevent damaging the packer elements. 41. Allow diesel to U-tube and equalize. RD U-tube manifolding. 42. Drop ball and rod to set packer. Ensure that the proper ball size is dropped to match up with the RHC sub located in the 4 W' 12.6# 'XN' Nipple. 43. Increase the tubing pressure to 5000 psi with 9.8-ppg completion fluid and hold for 30 minutes. /' Monitor tubing pressure for leaks. Record on chart. 44. Bleed tubing to 2000 psi and maintain during MIT. Pressure test 7 %" x 4 W' annulus to 4500 psi for required mechanical integrity test (MIT). Monitor tubing pressure for leaks. Maintain pressure for 30 minutes and record annulus test on chart. 45. Bleed off annulus and tubing. Fax chart to ODE. 46. Back out and lay down landing joint. Set the TWC valve in the tubing hanger. Nipple down BOP's. / Nipple up the tubing head adapter and tree. Install all flanges and needle valves. 47. Test the tubing head adapter and tree to 5000 psi. Confirm that there is no pressure on the annulus. Dry rod the "two way" check. 48. Ensure all valves are closed. RD and move off well. e ~~~~ e e 1. MIRU slickline. Pull the ball and rod / RHC profile from 'XN' nipple below the production packer. ",,- 2. Conduct flow test and step rate injection test per EPA requirements. Estimated Spud Date: October 1 , 2003 Allen Sherritt Senior Drilling Engineer 564-5204 &S32 WELL PLAN SUMMARY e I Type of Well (producer or injector): Northstar Slot: Surface location: Target (top of SAG): 300' Radius Bottom Hole location: I AFE Number: 1831333 I Class I Disposal Well NS32 135~FS~64~FE~Sec.11,T13N,R13E,UM X = 659821 Y = 6031131 5112'FSL,3526'FEL,Sec.12,T13N,R13E,UM X = 662140 Y = 6034936 6505' TVDrkb 5183'FSL,3481'FEL,Sec. 12,T13N, R13E,UM X = 662184 Y = 6035008 6687' TVDrkb I Rig: 1 Nabors 33E / / / r I Estimated Start Date: 110/1/03 I MD: 18312 I Operating days to complete: 122.6 I TVDrkb: 16687 1 I RKB/Surface Elevation: (a.m.sJ.) 155.3' 1 15.9' I Well Design (conventional, slimhole, etc.): 1 Slim Hole Long String I Objective: 1 Ugnu 1 Schrader Bluff non-hazardous disposal well Well Name: API Number: Well Type (proposed): BHP: EMW: BHT: NS32 Class I Disposal Well 292~i @ 6500' TVDss ~6~9 130 of @ 6500' TVDss ,/ land Use Permit: Distance to Nearest Property: Distance to Nearest Well within Pool: MECHANICAL CONDITION: Cellar box: RKB to Cellar box: Rig Elevation: Conductor: LO-N96-006 4,800 ft. 1,617 ft. from NS22 / Elevation above MSL = 15.9' 39.4' (Estimated) RKB + MSL = 55.3' 201' MDrkb of 20",169#, X-56 (pre-driven) MUD PROGRAM: e e Surface Hole Mud Properties: Seawater Spud Mud 13 W' Hole Section From Surface to -3961' MD /3255' TVD (-150' TVD below top SV6). Interval Density Viscosity YP Tauo Gel API FL pH (ppg) (seconds) 10 sec Initial 8.8-9.5 100 - 200 50 - 70 >8 25 - 40 15 - 20 8.5 - 9.5 from -1555' ~95 100 -150 30 - 45 >6 15 - 25 6-10 8.5 - 9.5 SV6 @ Interval TD 9.~~X 75 - 100 20 - 35 >6 10 - 25 6-10 8.5 - 9.5 * Should gas hydrates be encountered, mud densities up to 10.2 ppg may prove necessary. Intermediate Hole Mud Properties: Seawater Polymer From Surface Casing Shoe to 8112' MD / 6505' TVD. Interval Density (ppg) PV YP All 8.6-9.3 12-17 15-25 Injection Interval Mud Properties: Seawater Polymer From Intermediate Casing Shoe to 8312' MD / 6687' TVD Interval I Density (ppg) I PV I YP All 9.0 - 9.3 12 - 17 15 - 25 DIRECTIONAL:(P6) KOP: Maximum Hole Angle: Close Approach Wells: Survey Program: 9 7/8" Hole Section Tauo API/ HTTP FL 3 - 6 <10 initial <8 at TD pH 8.5- 9.5 6 3,4" Hole Section Tauo APIFL 3-6 <6 pH I 8.5 - 9.5 ~ ±300' MD Cantenary curve 1.5°/100' to 2.5°/100' build ±44.67° Surface- 10' well spacing to well NS31 and no wells to the North Gyro will be used for initial surveys and kickoff Gyros as required from surface to +/-1000'. IFR+MS corrected MWD surveys from +/-1000' to TD. SURFACE AND ANTI-COLLISION ISSUES: All wells pass the major risk rule; however, NS31 will be risked based at 1/200 to allow more flexibility while drilling the surface hole. Surface Shut-in Wells: See Northstar Anti-Collision and Well Shut-In checklist. e e LOGGING PROGRAM: 13 V2" Section: Drilling: GRlDirectional - Gyro as needed to -1000' MD. IFR-MS corrected surveys Mud Logging - Gas analysis/detection, show kit with indexed sample bottles, lithology samples (100' intervals) Open Hole: Gamma ray (GR), spontaneous potential (SP), resistivity, and caliper Cased Hole: USIT from the 10 %" shoe to 500' MD 97/8" Section: Drilling: GRlDirectional, PWD. IFR-MS corrected surveys Mud Logging - Gas analysis/detection, show kit with indexed sample bottles, lithology samples (100' intervals) Open Hole: Gamma ray (GR~ spontaneous potential (SP), resistivity, density, neutron, sonic Cased Hole: USIT from the 7 Is" shoe to 2960' MD 6 %" Section: Drilling: GRlDirectional. IFR-MS corrected surveys Mud Logging - Gas analysis/detection, show kit with indexed sample bottles, lithology samples (100' intervals) Open Hole: None Cased Hole: None InteQritv Testinq: Test Point Depth Shoe Test EMW Estimated Type Casing/Liner Test 13 W' Surface 20' min from 10 3fi¡" shoe LOT 11.5 ppg EMW Target 3500 psi wI 9.5 ppg ,/ 9 (/s" Intermediate 20' min from 7 "'/s" shoe LOT 11.0 ppg EMW Target 4600 psi w/ 9.3 ppg 6 3fi¡" Injection interval NA NA NA NA 4 W' Injection Tubing NA NA NA 5000 psi w/ 9.8 ppg 4 W' x 7 "'Is" Annulus NA NA NA 4500 psi w/ 9.8 ppg CASINGlTUBING PROGRAM: Hole Size Casingl WtlFt Gra~ Conn/ Casing Casing Top Hole 8tm Tbg O.D. Length MDITVDrkb MDITVDrkb 20" 20" 169# X-56 WELD 201' Surface 201 '/201' 13 Y2" 103fi¡" 45.5# L-80 BTC 3961' Su rface 3961 '/3255' 9 (/s" 7 "'/s" 29.7# L-80 BTC-Mod 8112' Su rface 8112'/6505' 63fi¡" Barefoot NA NA NA NA 8112'/6505' 8312'/6687' Tubing 4 Y2" 12.6# L-80 IBT-Mod 8112' Surface 8112'/6505' FORMATION MARKERS: e e (ppg Formation TVDrkb MDrkb EMW) Comments Top Permafrost 1,204 1226 8.65 Base Permafrost 1,574 1643 8.65 SV6 - top confining zone 3,105 3750 8.65 cr.)' Surface casing point 3,255 3961 SV5 - base confining zone 3,364 4114 8.65 SV4 3,725 4621 8.65 SV3 3,958 4949 8.65 9·) SV2 - top upper injection zone 4,140 5205 8.65 SV1 - top major shale barrier 4,527 5749 8.65 TMBK - top lower injection zone - Top Ugnu 4,876 6240 8.65 WS1 - top Schrader Bluff - Base Ugnu 6,505 8112 8.65 Geologic target - 300' radius Production casing point 6,505 8112 Total Depth 6687 8312 8.65 REQUIRED MATERIALS: 1 10 %", 45.5# L-80 BTC 10 %" HES Super Seal II Float Shoe (4.25" valve) 10 %" HES Super Seal II Float Collar (4.25" valve) 10 %" x 13 %" SV Rigid Centralizers 10 %" Port collar 45.5# L-80 BTC 20" x 10 %" ABB-VGI Fluted hanger BTC down, 12 %" ACME landing thread ABB-VGI Casing HeadfTbg head; 11" 5000 psi top flange, 10 3fi¡" quick connect L-80 Surface: 3961' 1 1 17 1 1 120 7 %",29.7# L-80 BTC-M 7 %", HES Super Seal II Float Shoe 7 %", HES Super Seal II Float Collar 7 %", ES cementer, 1st stage and 2nd stage plug set, 29.7#, L-80, BTC-M 7 %", HES Baffle adapter and bypass baffle HES Cement Plug Set 7 %", Tam Port Collar, 29.7#, L-80 BTC-M 10 3fi¡" x 7 5/8" ABB-VGI Casing Hanger BTC-Mod down, 8 W' stub ACME 7 %" x 9 %" SV Rigid Centralizers L-80 Intermediate: 8112' 1 1 1 1 1 - set 1 1 Completion: 8112' 1 1 1 1 1 1 1 4 W' 12.6# L-80 IBT-M 10 % x 4 W' ABB-VGI tubing hanger 4 W' ABB-VGI adapter flange with heat trace 4 W' ABB-VGI 4 W' 5K Swab Valve wI tree cap 4 W' "X' nipple 7" x 4 W' Baker packer S-3, IBT-Mod 4 W' "XN' nipple 4 W' WLEG - e PERMAFROST: The 10 3J¡" surface casing will be run approximately 1600' TVD below the permafrost to -3961' MD / 3255' TVD. The casing will be cemented to surface with a Premium 'G' with 2% calcium chloride tail slurry and a Permafrost 'L' lead slurry. The tail slurry allows sufficient compressive strength to prevent the shoe from breaking down as well as an accelerator to decrease thickening time. The lead slurry is light slurry that contains a freezing point depressant which enables the cement to set up rather than freeze. CEMENT CALCULATIONS: Casing Size Basis 10.75-in 45.5-lb/ft L-80 BTC surface casing 125% excess over gauge hole in permafrost interval. 50% excess over gauge hole below permafrost. To:> of tail cement 750-ft MD above casing shoe. Wash 20-bbl Water Spacer Total Cement Vol: 488-bbl Spacer 75-bbI10.5-lb/gal Alpha spacer Lead 407-bbl, 550-sx 10.7-lb/gal Permafrost L - 4.15 fe/sx (Cement to surface) Tail 81-bbl, 394-sx 15.8-lb/gal Premium G 2% CaCI- 1.15 ft;j/sx of tail at 1-ft Temp BHST:= 90°F from SOR, BHCT 70°F Casing Size 7.625-in 29.7-lb/ft L-80 BTC-M intermediate casing, 1st Stage Basis Top of tail cement 6, 150-ft MD, 60% excess over gauge - ES CEMENTER Depth Total Cement Wash 10-bbl Water Vol: 124-bbl Spacer Tail - 1.15 ft;j/sx Temp BHST:= 140°F from SOR, BHCT 105°F Casing Size 7.625-in 29.7-lb/ft L-80 BTC-M intermediate casing 2na Stage Basis Top of tail cement 5,000-ft MD, Top of Lead 4,150 ft. MD - TAM Port Collar depth Total Cement Wash 20-bbl Water Vol: 99-bbl Spacer 45-bbI10.5-lb/gal Alpha Spacer Lead 42-bbl, 116-sx 13.1-lb/gal Silicalite - 2.05 ft;j/sx (Top of Lead 4,150 ft. MD) Tail 57-bbl, 279-sx 1 Premium G - 1.15 ft;j/sx tail at := 90°F from SOR, BHCT 70°F Casing Size 7.625-in 29.7-lb/ft L-80 BTC-M intermediate casing 3rd Stage Basis Top of tail cement 2,960-ft MD, top of lead Surface 0% Excess Total Cement Wash 10-bbl Water Spacer Vol: 166-bbl Spacer 45-bb11 0.5-lb/gal Alpha spacer Lead 117-bbl, 159-sx 10.7-lb/gal Permafrost L - 4.15 ft;j/sx (Cement to surface) Tail 49-bbl, 240sx 1 Premium G 2% CaCI- 1.15 ft;j/sx of tail at Temp BHST:= 60°F from SOR, BHCT 60°F NS32 Permit to Drill e e WELL CONTROL: ~ A Diverter waiver has been requested on well NS32. To date, BP has successfully drilled all development wells through the Northstar upper strata-graphic intervals, absent any complications associated with shallow gas. All surface holes have been drilled and cemented to a common depth of approximately 3,170' TVDss depth, (-150' TVD below the top of the SV6), with one well extending into the SV5 -3280' TVDss. Well mud logs and seismic data do not indicate the presence of a shallow gas hazard. ~ Equipment to be Installed and capable of handling maximum potential surface pressures. (Schematics are on file with the AOGCC and MMS.) ~ 5000 psi working pressure pipe rams (2) ~ Blind/shear rams ~ Annular preventer ~ Based upon the calculations below, BOP equipment will be tested to 4800 psi. Surface Section: · Maximum anticipated BHP: 1397 psi @ 3050' TVDss - SV6 · Maximum surface pressure: 1092 psi @ surface (Based on BHP and a full column of gas from TD @ 0.1 psi/ft) Intermediate Section: · Maximum anticipated BHP: 2926 psi @ 6450' TVDss - Base Ugnu · Maximum surface pressure: 2281 psi @ surface (Based on BHP and a full column of gas from TD @ 0.1 psi/ft) Injection Interval (barefoot) Section: · Maximum anticipated BHP: · Maximum surface pressure: (Based on BHP and a full column · Planned BOP test pressure: · Planned completion fluid: i @ 6631' TVDss - Total Depth 2345 si @ surface from TD @ 0.1 psi/ft) 4800 psi (annular to 3500 psi) 9.8 ppg Seawater / 6.8 ppg Diesel DRILLING HAZARDS/CONTINGENCIES: HYDROGEN SULFIDE - H2S: ,/ Northstar is not designated as an H2S drill site, however Standard Operating Procedures for H2S precautions should be followed at all times. ,/ No H2S was detected at Northstar while drilling or testing the Seal Island A-01, A-02, or A- 03 exploration/appraisal wells. ,/ No H2S was detected while drilling the NS10 waste disposal well, or any subsequent Northstar wells. / Reference information below on file with AOGCC: ~ Northstar/Nabors 33E H2S contingency plan. ~ Well test hydrocarbon analyses for Seal Island A-01, A-02, and A-03. DISPOSAL: Annular Injection: There will be no annular injection in this well. Cuttings Handling: Cuttings generated from drilling operations will be processed in the Grind and Inject Facility on Nabors 33E and will be disposed of in the NS10 Class I Waste Disposal Well. Fluid Handling: All Class I and Class II fluids will be processed by the Grind and Inject Facility on Nabors 33E and will be disposed of in the Northstar NS10 Class I Waste Disposal Well. 9 NS32 Permit to Drill e e SURFACE HOLE SECTION: · Mudloggers will be rigged up throughout the entire section. · No significant drilling problems have been identified in the surface hole interval based on offset data. Good hole cleaning and management of required mud properties are key to a successful interval. · Minor tight hole conditions have been noted in the shale intervals immediately below the permafrost during short trips. · Differential sticking could be problematic in this hole section adjacent to the permeable SV Sands. Avoid leaving drill string stationary for extended periods; tighten fluid loss properties of mud. · Lost circulation has only been noted while drilling during hole opening runs and was most likely induced by poor hole cleaning. Losses have occurred while running and cementing surface casing. The NS27 experienced losses on the surface cement job at a rate of 12 BPM. The displacement rate was lowered to 10 BPM and full returns were re-established. Be sure to condition and thin mud appropriately prior to pulling out of the hole to run casing, and once on bottom with casing, bring circulation up slowly and reduce mud viscosities before pumping cement. Minor losses were seen on NS29 while running the 13 3/8" surface casing. Reduced running speed eliminated losses and the casing was cemented at 10 BPM displacement rate. · Gas hydrates may be present near the base of the permafrost. Wells drilled in the 2000-2003 drilling season have not experienced hydrates. Mudloggers will be used continuously on NS32 to help identify and trend any increase in background gas readings. If gas hydrates are encountered, mud weight may be increased to 10.2 ppg and treated with 2 ppb Driltreat (Lecithin). Additional measures include reducing flow rates to -450 to 500 gpm and keeping the mud temperature cool. INTERMEDIATE / INJECTION INTERVAL SECTION: · Mudloggers will be rigged up throughout these sections. · Minor gas shows have been reported in the four (4) Seal Island wells and have been identified as coal associated methane. No indications of shallow gas were seen while drilling during the 2000-2003 drilling season. Mudloggers will be used continuously on this well to help identify and trend any increase in background gas readings. Surface casing will be set prior to any intervals with previously noted gas shows to facilitate nippling up the BOP's. A minimum of 9.0 ppg is recommended. · The shallow intervals beneath Northstar are, by interpretation, not faulted. To be prepared for any potential lost circulation, a copy of the 'Non-Payzone Lost Circulation Decision Tree' can be found in the last section of the Master Well Plan, which can be found on the rig. · Pressure While Drilling (PWD) will be used to monitor the annular pressure. The pressure data will be used to minimize the equivalent circulating density (ECD), minimize lost circulation due to packing off due to loading up the wellbore with solids and provide for an additional well control tool to make sure the well does not become under-balanced. · Differential sticking can be a problem if lost circulation is occurring or if the drill string is left stationary for an extended period or time across the permeable SV Sands. · The kick tolerance for the 9 7/S" open hole section would be 62.7 bbls assuming an influx from the Schrader Bluff interval at 6505' TVD. This is the worst-case scenario based on a 9.15 ppg (0.5 ppg over the known pore pressure) pore pressure gradient, a fracture gradient (LOT) of 11.5 ppg at the 10 3J¡" shoe, and 9.3 ppg mud in the hole. · The kick tolerance for the 6 3J¡" open hole section would be infinite bbls assuming an influx from the Schrader Bluff interval at 6687' TVD. This is the worst-case scenario based on a 9.15 ppg (0.5 ppg over the known pore pressure) pore pressure gradient, a fracture gradient (LOT) of 11.0 ppg at the 7 %" shoe, and 9.3 ppg mud in the hole. 10 NS32 Permit to Drill e e NS32 RiQ-site SUmmary of DrillinQ Hazards **POST THIS NOTICE IN THE DOGHOUSE** --J Mudloggers will be used continuously on NS32 to help identify and trend any increase in background gas readings ~ Gas hydrates may be present near the base of the permafrost. If gas hydrates are encountered, mud weight may be increased to 10.2 ppg and treated with 2 ppb Driltreat (Lecithin). Additional measures include reducing flow rates to -450 to 500 gpm and keeping the mud temperature cool. ~ Minor gas shows have been reported in the four (4) Seal Island wells and have been identified as coal associated methane. No indication of shallow gas was seen in any previously drilled Northstar wells. . Surface casing will be set prior to any intervals with previously noted gas shows to facilitate nippling up the BOP's. --J Differential sticking could be problematic in both the surface and intermediate hole sections adjacent to the permeable SV Sands. Avoid leaving drill string stationary for extended periods; tighten fluid loss properties of mud. --J Packing off due to improper hole cleaning can lead to stuck pipe. The PWD data, pick- up/slack-off weights and other drilling parameters must be monitored at all times. If in doubt, stop and condition the hole prior to drilling ahead or tripping. --J Though no faulting has been identified, be prepared for any potential lost circulation. A copy of the 'Non-Payzone Lost Circulation Decision Tree' can be found in the last section of the Master Well Plan, which can be found on the Rig. --J Northstar is not a designated H2S pad. CONSULT THE NORTHSTAR PAD DATA SHEET AND THE WELL PLAN FOR ADDITIONAL INFORMATION 11 - July 29, 2003 e Proposed Completion Diagram / Northstar Well NS32 I WD-02 Cement/Stage Collar 1000' MD KOP: 400' Max. Angle 45° Departure at BHL: Approx 4540' Base Permafrost 1643' MD (1519' SS) 3750' MD (3050' SS) · SV 6 4114' MD · SV 5 . (3309' SS) 5205' MD (4085' SS) 6240' MD (4821' SS) (6880' SS) œ c ~ .- - 1ií ~ CI) ... t:ìi) <C . · SV2 SV1 TMBK c- CI ~ .- ~ tj CI) CI)_ .~ c c_ . PRINCE CREEK AND UGNU FORMATIONS SCHRADER BLUFF MD (BKB) (measured depth below rig) . r 8112' MD (6450' SS) 20" Conductor 200' MD (145' SS) 10-3/4",45.5#, L-80 Casing Heat Tracing 2150' MD (1912' SS) 2250' MD 3961' 'MD (3200' SS) Cement/Stage -4150'MD Collar 4-1/2",12.6#, L-80 Tubing Packer 5155' MD Cement/Stage Collar -6150'MD 7-5/8",29.7#, L-80, Casing (Run T.D. to Surface) 7-5/8" Shoe 6-3/4" Open Hole 8312' MD (6631' SS) TREE:ABB-VGI5 118" 5ksi WELLHEAO:ABB-VGI11" Mulitbowl5ksi .e NS32 / , , , , , , , ~ ~ , . , , , 20", 169# X-56 @ 200' M D - 103/4", 45.5#/ft, L-80. BTC @3961' MO 4.5", 12.6#/ft, L-80.IBT-MOO TUBING 10: 3.958" CAPACITY: 0.015 BBLlFT 4.5" 'XN'NIPPLE,@ 8072' 3.725" 10 (OTIS) 75/8", 29.7#/ft L-80, BTC-M @8112'MO TO @8312' MO 6686' TVO DATE 6/18/03 7115/03 REV. BY JAS FH COMMENTS Initial Diagram Proposed Completion e RKB. ELEV = 55.30' KB-BF. ELEV = 39.40' BASE FLANGE ELEV = 15.9' ~.~ ...., i; ~ ~ Cement ~ Baker 53 PACKER 3.875"10 @5155' MO 4.5" WLEG, @8100'MO 6 3/4" open hole Northst::lr WFI I : NS32 API NO: 50-029- BP Exploration (Alaska) e e 8 o Permit to Drill / MMS Section 250.414 (f) (5) (iv) (9) Estimated Values (ppg) 9 10 11 12 13 14 15 16 ~ Pore Pressure (ppg) 1000 - Mud Weight (ppg) .......- Frac Gradient (ppg) 2000 - C ~ 1) 3000 .æ · )( . - .c - Q, CÞ C 4000 C) c E CÞ tJ) C) 5000 c t/ ca 0 6000 · ~: · 7000 8000 Casing Depth PoreÞressure t-rac Gradient ) rip Margin Surge Margin (TVD) (ppg) Mud Weight (ppg) (ppg) (ppg) (ppg) 3255 8.65 9.5 13 9.15 12.5 6505 8.65 9.3 12 9.15 11.5 6687 8.65 9.3 12 9.15 11.5 e e Oilfield Services, Alaska Schlumberger Drilling & Measurements SchluRlblP" 3940 Arctic Blvd, Site 300 Anchorage, AK 99503 Tel (907) 273-1766 Fax (907) 561-8357 Monday,August25,2003 Barbara Holt Northstar NS32 (P6) Nabors 33E BP Exploration Alaska Close Approach Analysis We have examined the potential intersections of subject well with all other potentially conflicting wells, according to the BPA Directional Survey handbook (BPA-D-004) dated 09/99. Method of analvsis: 1. A list of wells to be analyzed is created in Compass by performing a global scan with an initial search radius of two thousand feet with an increment of one hundred feet for every one thousand feet of measured depth in the subject well. 2. Wells are analyzed using the Compass Anti-collision module (BP Company setup) with major risk safety factors applied. For problem wells that are plugged and abandoned or that can be shut in, risk-based safety factor may be used, with client notification. 3. All depths are relative to the planned well profile. Survey Program: Instrument Type GYD-GC-SS MWD-IFR-MS Start Depth 40.20' md 1,200' md End Depth 1,200' md 8,311.93' md ;,,.i ~, ~"" ",;;'" ¥'ot· rY, Close Approach Analvsis results: Under method (2): All wells pass. Note, it is recommended to use the risk base rule set (1 :200) to increase the drilling space around NS31 in the surface hole. All data documenting these procedures is available for inspection at the Anadrill Directional Planning Center. Close Approach Drillinq Aids to be provided: A drilling map, with offset wells on the plan view, and traveling cylinder will be provided. Checked by: Scott Delapp 08/25/03 bp 0 NS32 (P6) Proposal Schlumberuer , ,,' Report o.te: August 26, 2003 ~ ,...,,11I.$ __ ....... ,,"_m , I.<Ø"" Client: BP Exploration Alaska Vert1c81 SectIon AzImuth: 32.590" Field: Northstar 8/ Al3 VertIcal SectIon Origin: N 0.000 fI, E 0.000 fI Structure/Slot Northstar PF / NS32 .d 1VD Reference Detum: KB W.I: NS32 A pro¥ TVD Reference E1ev8llon: 55.3 fI relative to MSL ~.: ~~NS32 p s.. Bed / Ground L....eI EI....lllon: 15.670 fI relative to MSL UWI/APtt: 50029 Megnellc Decllnetlon: 25.646" Survey NII1III/ DIte: NS32 (PS) / July 16, 2003 Total Field Strength: 57584.406 n T Tort / AHD I 001/ ERD ratio: 64.343" /4540.40 fI I 5.560 / 0.679 Magnetic Dip: 80.983" e Grid Coordinate System: NAD27 Alaska Slate ~~es. Zone 04, US Feet Declination DIte: September 20, 2003 LOC8tIon LatILong: N 70.49159610, W 148.69333956 Magnetic Declination Model: BGGM 2003 Location Grid HIE Y/X: N 6031131.220 flUS, E 659821.460 flUS North Ref.ence: True North GrId Convergence Angle: +1.23167222" Total ColT Mag North -> True North: +25.646" Grid Scale Factor: 0.99992902 Local Coordln... Ref.enced To: Well Head Comments Mees...ecI Inclination AzImuth 1VD Sub-Sea TVD Vertical NS EW DLS Too! Fica Northing Eastlng latitude Longitude Depth SectIon (ft) (deg) (deg) (ft) (ft ) (ft) (ft) (ft) ( deg/100 ft) (deg) (ftUS) (ftUS) KBE 0.00 0.00 32.59 0.00 -55.30 0.00 0.00 0.00 0.00 32.59M 6031131.22 659821.46 N 70.49159610 W 148.69333956 KOP Bid 1.5/100 300.00 0.00 32.59 300.00 244.70 0.00 0.00 0.00 0.00 32.59M 6031131.22 659821.46 N 70.49159610 W 148.69333956 Bid 2.5/100 400.00 1.50 32.59 399.99 344.69 1.31 1.10 0.71 1.50 32.59M 6031132.34 659822.14 N 70.49159911 W 148.69333380 500.00 4.00 32.59 499.87 444.57 6.11 5.14 3.29 2.50 32.59M 6031136.43 659824.64 N 70.49161015 W 148.69331268 600.00 6.50 32.59 599.44 544.14 15.26 12.85 8.22 /2.50 O.OOG 6031144.25 659829.40 N 70.49163121 W 148.69327240 700.00 9.00 32.59 698.52 643.22 28.74 24.21 15.48 2.50 O.ooG 6031155.76 659836.41 N 70.49166225 W 148.69321303 800.00 11.50 32.59 796.91 741.61 46.53 39.21 25.06 2.50 0.000 6031170.95 659845.67 N 70.49170321 W 148.69313469 900.00 14.00 32.59 894.44 839.14 68.60 57.80 36.95 2.50 0.000 6031189.80 659857.16 N 70.49175400 W 148.69303753 1000.00 16.50 32.59 990.91 935.61 94.90 79.96 51.11 2.50 0.000 6031212.25 659870.84 N 70.49181454 W 148.69292173 1100.00 19.00 32.59 1086.14 1030.84 125.39 105.64 67.53 2.50 O.OOG 6031238.28 659886.70 N 70.49188471 W 148.69278_ 1200.00 21.50 32.59 1179.95 1124.65 159.99 134.81 86.17 2.50 O.OOG 6031267.84 659904.71 N 70.49196437 W 148.69263513 Top Perm 1226.23 22.16 32.59 1204.30 1149.00 169.75 143.02 91.43 2.50 0.000 6031276.16 659909.78 N 70.49198681 W 148.69259220 1300.00 24.00 32.59 1272.17 1216.87 198.66 167.39 107.00 2.50 O.OOG 6031300.85 659924.83 N 70.49205337 W 148.69246488 1400.00 26.50 32.59 1362.61 1307.31 241.32 203.32 129.97 2.50 O.OOG 6031337.28 659947.02 N 70.49215155 W 148.69227708 1500.00 29.00 32.59 1451.10 1395.80 287.87 242.55 155.05 2.50 O.OOG 6031377.03 659971.25 N 70.49225871 W 148.69207209 1600.00 31.50 32.59 1537.47 1482.17 338.25 284.99 182.18 2.50 O.ooG 6031420.04 659997.46 N 70.49237466 W 148.69185029 Base Perm 1643.45 32.59 32.59 1574.30 1519.00 361.30 304.41 194.60 2.50 0.000 6031439.72 660009.45 N 70.49242771 W 148.69174880 1700.00 34.00 32.59 1621.57 1566.27 392.34 330.57 211.32 2.50 0.000 6031466.23 660025.61 N 70.49249916 W 148.69161211 1800.00 36.50 32.59 1703.23 1647.93 450.05 379.19 242.40 2.50 O.ooG 6031515.51 660055.63 N 70.49263200 W 148.69135801 1900.00 39.00 32.59 1782.29 1726.99 511.27 430.77 275.37 2.50 O.OOG 6031567.78 660087.49 N 70.49277290 W 148.69108846 Version DO 3.1 RT ( d031 rt_546 ) 3.1 RT -SP3.03 NS32\NS32\Plan NS32\NS32 (P6) Generated 8/26/2003 1 :16 PM Page 1 of 2 Comments Menll'ed Inclination AzImuth TVD Sub-SeI TVD VertiCil NS EW DlS Tool F_ Northing EntIng latitude Longitude Depth SectIon (ft) (!leg) (deg) (ft) ( ft) (ft) (ft ) (ft) ( degI100 ft ) (deg) (OOS) (ftUS) 2000.00 41.50 32.59 1858.61 1803.31 575.87 485.21 310.17 2.50 O.OOG 6031622.95 660121.10 N 70.49292161 W 148.69080397 2100.00 44.00 32.59 1932.04 1876.74 643.75 542.40 346.73 2.50 O.OOG 6031680.90 660156.42 N 70.49307783 W 148.69050510 End Bid 2126.86 44.67 32.59 1951.25 1895.95 662.52 558.21 356.84 2.50 D.OOG 6031696.93 660166.19 N 70.49312104 W 148.69042243 SV6 (Top Confining 3749.66 44.67 32.59 3105.30 3050.00 1803.42 1519.49 971.32 0.00 O.DOG 6032671.12 660759.83 N 70.49574696 W 148.68539797 Zone) 10-314" Csg Pt 3960.59 44.67 32.59 3255.30 3200.00 1951.71 1644.43 1051.19 0.00 O.OOG 6032797.75 660836.99 N 70.49608826 W 148.68474481 SV5 (Base Confining 4113.86 44.67 32.59 3364.30 3309.00 2059.47 1735.22 1109.23 0.00 O.DOG 6032889.76 660893.06 N 70.49633627 W 148.68427017 Zone) SV4 4621.49 44.67 32.59 3725.30 3670.00 2416.35 2035.92 1301.45 0.00 O.DOG 6033194.50 661078.76 N 70.49715764 W 148.68269811 SV3 4949.13 44.67 32.59 3958.30 3903.00 2646.69 2230.00 1425.52 0.00 O.DOG 6033391.18 661198.61 N 70.49768778 W 148.68168338 (Top Upper InjectIon 5205.05 44.67 32.59 4140.30 4085.00 2826.62 2381.60 1522.42 0.00 O.DOG 6033544.82 661292.23 N 70.49810187 W 148.68089_ Zone) SV1 (Top Major Shale 5749.24 44.67 32.59 4527.30 4472.00 3209.21 2703.95 1728.49 0.00 O.OOG 6033871.50 661491.30 N 70.49898237 W 148.67920514 Barrier) Drp 2.5/100 6225.06 44.67 32.59 4865.68 4810.38 3543.73 2985.81 1908.66 0.00 180.00G 6034157.14 661665.36 N 70.49975224 W 148.67773121 TMBK (Top Lower InjectIon Zone - Top 6239.95 44.30 32.59 4876.30 4821.00 3554.16 2994.60 1914.28 2.50 180.00G 6034166.05 661670.79 N 70.49977625 W 148.67768524 UGNU) 6300.00 42.80 32.59 4919.82 4864.52 3595.53 3029.45 1936.56 2.50 180.00G 6034201.38 661692.32 N 70.49987145 W 148.67750295 6400.00 40.30 32.59 4994.65 4939.35 3661.85 3085.33 1972.28 2.50 180.00G 6034258.00 661726.83 N 70.50002408 W 148.67721072 6500.00 37.80 32.59 5072.31 5017.01 3724.84 3138.41 2006.21 2.50 180.00G 6034311.79 661759.60 N 70.50016905 W 148.67693315 6600.00 35.30 32.59 5152.64 5097.34 3784.39 3188.58 2038.28 2.50 180.00G 6034362.64 661790.59 N 70.50030608 W 148.67667076 6700.00 32.80 32.59 5235.49 5180.19 3840.37 3235.75 2068.43 2.50 180.00G 6034410.44 661819.72 N 70.50043492 W 148.67642406 6800.00 30.30 32.59 5320.70 5265.40 3892.69 3279.83 2096.61 2.50 180.00G 6034455.11 661846.94 N 70.50055532 W 148.67619351 6900.00 27.80 32.59 5408.12 5352.82 3941.24 3320.73 2122.76 2.50 180.00G 6034496.57 661872.20 N 70.50066705 W 148.67597956 7000.00 25.30 32.59 5497.57 5442.27 3985.93 3358.39 2146.83 2.50 180.00G 6034534.73 661895.46 N 70.50076990 W 148.67578261 End Drp 7011.93 25.00 32.59 5508.36 5453.06 3991.00 3362.66 2149.56 2.50 O.OOG 6034539.06 661898.10 N 70.50078156 W 148.67576028 7-518" Csg Pt 8111.91 25.00 32.59 6505.29 6449.99 4455.88 3754.34 2399.96 0.00 O.OOG 6034936.00 662139.99 N 70.50185136 W 148.67371151 Target 8111.93 25.00 32.59 6505.30 6450.00 4455.88 3754.34 2399.96 0.00 D.OOG 6034936.00 662140.00 N 70.50185137 W 148.67371. WS1 (Top Schrader 8111.94 25.00 32.59 6505.31 6450.01 4455.89 3754.34 2399.96 0.00 O.OOG 6034936.01 662140.00 N 70.50185138 W 148.673711 Bluff - Base UGNU) TD 8311.93 25.00 32.59 6686.56 6631.26 4540.40 3825.56 2445.49 0.00 O.OOG 6035008.17 662183.98 N 70.50204588 W 148.67333896 Leaal Description: Northlna (Y) rftUSl Eastlna DC) rftUSl Surface: 1358 FSL 649 FEL S11 T13N R13E UM 6031131.22 659821.46 Target: 5112 FSL 3526 FEL S12 T13N R13E UM 6034936.00 662140.00 BHL: 5183 FSL 3481 FEL 512 T13N R13E UM 6035008.17 662183.98 Version DO. 3.1RT (d031rt_546) 3.1RT-SP3.03 NS32\NS32\Plan N532\NS32 (P6) Generated 8/26/2003 1 :03 PM Page 2 of 2 WEU. NS32 (P6) -- ..... BOON 2003 3000 =- § .... ~ II CD ~ 4000 rn ~ bp e e IcIIlulDbarger F1B-D STRœTUOE Northstar PF Northstar Dip BO.tø:r ......Dee: +25.846'" &riIoe lOClllÎ(l'l IWJ21 N..u SbIIII AMeI. Zone 04. us FMI I ...- "'" _N.2003 ... "102120.141 -. to3113122 ftUS QridCmv: .'23161222" - NS32 NO Ref: KB (M.JO ft.oow MSl) ps. 51584.406n1 lm W1484138.022 E8dng: 151821."'1IJS 8c11eF8aI:O.IMI802OO155 ",., NS32(PS) SNyOlM: ~10.2003 1000 2000 3000 4000 5000 o o /:=~t--rr¡-l- ...........H··t···..·....·..··············..·····~··....········..······..············t···············..··....·············í·u·..·····..·······················t······..·········.,.................~................... -"-"-"-'r'- -"-··-"-ióp·p;;m"T-"-"-··-"-"-"-"-"-l-"-"""-··-"-··-"-··-'T'''''-''-''-''-''-''-''-''-r-''-''-''-''-''-''''''-''-'r'-''-''-''-' -".u.".uf:::·::: 0-."." .u.u.u.u."'''¡'..u.u....u.u.u.u.....i.u............_...u.._.'0';"'."."."."."."."."."."."."."."."."."_.~.._.._.._..-. 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Scale = 1(in):1000(ft) Origin = 0 Nt-S. 0 E/-W 5000 O· ..........~. p " . ..~ . . . NS32 (P6) -- - BOON..., WEll ^ ^ ^ z = ~ ~ II CD ãi () en en v v v e e Scblumb... RELO STRuctURE Northstar PF Northstar Dp ...."'" -:ZO·20031 51584.408n1 TVOA8I': 1CB(55.30ftIltøteMSl) Sny DMt: .uy 10, 2003 NAD27 Aa..uSllM~, Zone", US Feel 8031131'221tUS QidCaw: ..'.23161222" Mt821,.tfttJS SaMFKt: 0.9IIe02OO156 - .... NS32 AlII NS32 (PS) ~locMon lM: N7G292U46 Nolting Lorr W148 41 36.022 EatIng lO.os:r +256480 Dole FS o 500 2000 2500 1000 1500 TO 3500 3000 ¿(N i i : r'"'" ........................ " "'--....:....................................¿....................................:....................................¿................ '!' ¡ ¡ ¡ End~ · . . . · . . . · . . . · . . . · . . . · . . . · . . . · . . . · . . . · . . . · . . · . . · . . · . . · . . · . . · . . · . . · . . · . . · . . · . . · . . · . . · . . · . . · . . · . . · . . · . . 2500 2000 __mmr-·m'·'-'r' 1500 1000 500 o ¡ KOPBtclUl1o; ¡ ¡ ¡ . ·....········....·..·····....·r············..·····················1················..···u·..··········r····..········..········....········f··················..·······..·······r............. o 2500 500 1000 1500 «< W Scale = 1 (in):500(ft) E >>> 2000 / 3500 3000 2500 2000 1500 1000 500 o e BPX AK Anticollision Report e Company: BP Amoco Fidd: Northstar Reference Site: Northstar PF Reference WeD: NS32 Reference WeDpatb: Plan NS32 NO GWBAL SCAN: Using user defined selection & sean criteria Interpolation Method: MD Interval: 50.00 ft Depth Range: 39.40 to 8311.93 ft Maximum Radius: 3000.00 ft Reference: Error Model: Scan Method: Error Surface: Principal Plan & PLANNED PROGRAM ISCWSA Ellipse Trav Cylinder North Ellipse + Casing Survey Program for Definitive Wellpath Date: 3/1812002 Validated: No Planned From To Survey ft ft 39.40 1200.00 Planned: Plan 1m V2 1200.00 8311.93 Planned: Plan 1m V2 Venion: 3 T ooleode Tool Name GYD-GC-SS MWD+IFR:AK Gyrodata gyro single shots MWD + IFR [Alaska] Casing Points 3960.59 8111.93 8311.93 3255.30 6505.30 6686.57 10.750 7.625 6.750 13.500 9.875 6.750 10 3/4" 7-5/8" open Summary NorthstarPF NS06 NS06 V34 346.64 350.00 260.75 6.48 254.27 Pass: Major Risk NorthstarPF NS07 NS07 V33 149.17 150.00 251.19 3.01 248.18 Pass: Major Risk Northstar PF NS08 NS08 V18 299.29 300.00 239.76 5.39 234.36 Pass: Major Risk NorthstarPF NS09 NS09 V14 394.36 400.00 235.08 6.92 228.16 Pass: Major Risk NorthstarPF NS10 NS10 V17 441.60 450.00 215.00 7.29 207.70 Pass: Major Risk NorthstarPF NS12 NS12 V28 346.91 350.00 194.92 6.85 188.07 Pass: Major Risk Northstar PF NS13 NS13 V12 395.13 400.00 193.86 7.04 186.82 Pass: Major Risk Northstar PF NS14 NS14 V11 396.09 400.00 177.65 7.26 170.39 Pass: Major Risk Northstar PF NS15 NS15 V19 347.55 350.00 171.19 6.40 164.79 Pass: Major Risk NorthstarPF NS16 NS16 V39 395.12 400.00 159.45 7.47 151.98 Pass: Major Risk Northstar PF NS17 NS17 V12 395.71 400.00 152.80 6.48 146.32 Pass: Major Risk Northstar PF NS18 NS18 V12 396.48 400.00 138.92 8.06 130.86 Pass: Major Risk NorthstarPF NS19 NS19 V17 396.28 400.00 128.97 7.23 121.74 Pass: Major Risk Northstar PF NS20 NS20 V4 397.45 400.00 120.78 6.58 114.19 Pass: Major Risk Northstar PF NS20 NS20PB1 V10 397.45 400.00 120.78 6.58 114.19 Pass: Major Risk Northstar PF NS21 NS21 V46 444.58 450.00 108.32 8.25 100.07 Pass: Major Risk NorthstarPF NS22 NS22 V13 48.79 50.00 99.87 1.26 98.61 Pass: Major Risk NorthstarPF NS23 NS23 V33 396.86 400.00 88.84 7.26 81.58 Pass: Major Risk Northstar PF NS24 NS24 V15 397.63 400.00 78.94 7.32 71.62 Pass: Major Risk Northstar PF NS25 Plan NS25 V7 Plan: Pia 398.04 400.00 70.85 7.68 63.17 Pass: Major Risk Northstar PF NS26 NS26 V22 349.26 350.00 61.65 6.55 55.10 Pass: Major Risk Northstar PF NS27 NS27 V29 348.96 350.00 48.35 6.77 41.58 Pass: Major Risk Northstar PF NS29 NS29 V22 447.84 450.00 30.87 7.98 22.89 Pass: Major Risk NorthstarPF NS31 NS31 V14 399.10 400.00 10.21 7.29 2.92 Pass: Major Risk Seal Island SEAL-A-Q1 SEAL-A-Q1 V4 1270.45 1250.00 79.64 24.21 55.43 Pass: Major Risk Seallsland SEAL-A-Q2 SEAL-A-Q2 VO 1217.05 1200.00 93.39 25.87 67.52 Pass: Major Risk Seal Island SEAL-A-Q2 SEAL-A-02A V4 1217.59 1200.00 91.31 22.47 68.84 Pass: Major Risk Seal Island SEAL-A-03 SEAL-A-Q3 V4 1218.53 1200.00 81.71 20.59 61.13 Pass: Major Risk Seal Island SEAL-A-D4 SEAL-A-Q4 V4 1335.67 1300.00 76.95 24.80 52.15 Pass: Major Risk e BPX AK Anticollision Report e C~~.ly: BP Arnooo ·"iøJ~j North~ar ReférelìceSltè: NOrthstar PF ···Itet~~!I¢e \yèl.l: .. NS32 Rt(ere.C(\ Wellpatb: PlanNS32 NO GWBAL SCAN: Using user defined selection & scan criteria Interpolation Metbod: MD Interval: 50.00 ft Deptb Range: 39.40 to 8311.93 ft M8J:imum Radius: 3000.00 ft Date: Reference: Error Model: Scan Metbod: Error Surface: Principal Plan & PLANNED PROGRAM ISCWSA Ellipse Trav Cylinder North Ellipse + Casing Survey Program for Definitive Wellpatb Date: 3/18/2002 Validated: No Planned From To Snrvey ft ft 39.40 1200.00 Planned: Plan #If¡ V2 1200.00 8311.93 Planned: Plan #If¡ V2 Version: 3 Toolcode Tool Name GYD-GC-SS MWD+IFR:AK Gyrodata gyro single shots MWD + IFR [Alaska] Casing Points 3960.59 8111.93 8311.93 3255.30 6505.30 6686.57 10.750 7.625 6.750 13.500 9.875 6.750 103/4" 7-5/8" open Summary NorthstarPF NS06 NS06 V34 346.64 350.00 260.75 6.48 254.27 Pass: Major Risk NorthstarPF NS07 NS07 V33 149.17 150.00 251.19 3.01 248.18 Pass: Major Risk Northstar PF NS08 NS08 V18 299.29 300.00 239.76 5.39 234.36 Pass: Major Risk Northstar PF NS09 NS09 V14 394.36 400.00 235.08 6.92 228.16 Pass: Major Risk NorthstarPF NS10 NS10 V17 441.60 450.00 215.00 7.29 207.70 Pass: Major Risk NorthstarPF NS12 NS12 V28 346.91 350.00 194.92 6.85 188.07 Pass: Major Risk Northstar PF NS13 NS13 V12 395.13 400.00 193.86 7.04 186.82 Pass: Major Risk Northstar PF NS14 NS14 V11 396.09 400.00 177.65 7.26 170.39 Pass: Major Risk Northstar PF NS15 NS15 V19 347.55 350.00 171.19 6.40 164.79 Pass: Major Risk Northstar PF NS16 NS16 V39 395.12 400.00 159.45 7.47 151.98 Pass: Major Risk NorthstarPF NS17 NS17 V12 395.71 400.00 152.80 6.48 146.32 Pass: Major Risk NorthstarPF NS18 NS18 V12 396.48 400.00 138.92 8.06 130.86 Pass: Major Risk Northstar PF NS19 NS19 V17 396.28 400.00 128.97 7.23 121.74 Pass: Major Risk Northstar PF NS20 NS20 V4 397.45 400.00 120.78 6.58 114.19 Pass: Major Risk NorthstarPF NS20 NS2OPB1 V10 397.45 400.00 120.78 6.58 114.19 Pass: Major Risk NorthstarPF NS21 NS21 V46 444.58 450.00 108.32 8.25 100.07 Pass: Major Risk NorthstarPF NS22 NS22 V13 48.79 50.00 99.87 1.26 98.61 Pass: Major Risk Northstar PF NS23 NS23 V33 396.86 400.00 88.84 7.26 81.58 Pass: Major Risk NorthstarPF NS24 NS24 V15 397.63 400.00 78.94 7.32 71.62 Pass: Major Risk Northstar PF NS25 Plan NS25 V7 Plan: Pia 398.04 400.00 70.85 7.68 63.17 Pass: Major Risk Northstar PF NS26 NS26 V22 349.26 350.00 61.65 6.55 55.10 Pass: Major Risk Northstar PF NS27 NS27 V29 348.96 350.00 48.35 6.77 41.58 Pass: Major Risk Northstar PF NS29 NS29 V22 447.84 450.00 30.87 7.98 22.89 Pass: Major Risk Northstar PF NS31 NS31 V14 349.20 350.00 9.57 2.81 6.76 Pass: Minor 1/200 Seal Island SEAL-A-01 SEAL-A-01 V4 1270.45 1250.00 79.64 24.21 55.43 Pass: Major Risk Seal Island SEAL-A-02 SEAL-A-02 VO 1217.05 1200.00 93.39 25.87 67.52 Pass: Major Risk Seal Island SEAL-A-02 SEAL-A-02A V4 1217.59 1200.00 91.31 22.47 68.84 Pass: Major Risk Seal Island SEAL-A-03 SEAL-A-03 V4 1218.53 1200.00 81.71 20.59 61.13 Pass: Major Risk Seal Island SEAL-A-04 SEAL-A-04 V4 1335.67 1300.00 76.95 24.80 52.15 Pass: Major Risk REFERENCE INFORMATION Co-ordir&e (NÆm Reference: Wen Cedre: NS32, TNe North Veo1icaI (TVD Reference: NS32 plan 55.30 Secticn (VS Reference: Slot - (O.OON,O.OOE) MeasuIed Dcø1h Reference: NS32 plan 55.30 Calc:uIøtion Method: Minimum Curvature Northstar Northstar PF NS32 Plan NS32 Field: Site: Well: Well path: ]927 FIELD DETAILS Northstar ~~ÅTES Oeodotic~: US SI8Ie Plane Coordìœte SysIem EI\ioIoid: NAD27 (Clmlte \ ß66) Zone: AIaoIca, Zone 4 Mopetiç Model: bgsm2003 SysIem Doium: Mean Sea Level Loco! North: TNe North Azimuths to Tnie NOrd. Magnetic North: 25.82· M 'cFielcl S~S6OnT D-.Anî\e:IIO:W e ÖaIe: 912012\)03 Model: bgm2\)03 e 110" .... NS]2 (NS12) (Plan NS25 NS25 I 12000 HI fOO 1 j I I ; I , , ·.1~---- ---~._-.......-.---:--- - T ^J JI : I ." . I "..." ." J I 6000 We.ot(-)IEast(+) (3000ftfm I -3000 I I i I î I i i i .600() I 1 i '''<-~o ", ~I).]....\?-:. -, " . ",,~OO --i-~ "". ". '.. ' "-,,'" I -9000 I T ì 1 I ¡ f ¡ I I ~._------~--------t------'--------._-_.....-_......- I i I -------~--+"-------------" I i ¡ -12000 9000------~ -3000- ~ -9000 -\5000 3000- :¡ I Ì t ! 'I tit e .0 Northstar Northstar PF NS32 Plan NS32 Trawlling Cylinder Azimulh (fFOtAZl) (deg] "" Centre to Centre Separation [60ft/in] Field: Site: Well: Wellpath: 27(; NS29 (NS29) -176 '--120 --~ -0 --~ 120 -176 I .. ¥~S --.-- - --f -.--- -.- ---- I -----~----e e I 800 I 1200 Meaaurod Depth [200ft/in) I 800 I 200 70-- 60 S<r-----~-- 40- 3Q-- 20- 10 o I i ~ s ~ p 055124 DATE 7/14/2003 I r CHECK NO. 055124 DATE INVOICE I CREDIT MEMO DESCRIPTION GROSS VENDOR DISCOUNT NET 7/14/2003 INV# PR071003N PERMIT TO DRILL FEE H e -'YDO~ THE ATrACHED CHECK IS IN PAYMENT FOR ITEMS DESCRIBED ABOVE. TOTAL ... "GN, (ALA9KA) I PAY: e II· 0 5 5 ~ 2 It II· -: 0 It ~ 2 0 ~ a c:¡ 5.: 0 ~ 2 'i' a Ii b II· . . TRANSMIT AL LETTER CHECK LIST CIRCLE APPROPRIATE LETTER/PARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME PTD# CHECK WHAT APPLffiS ADD-ONS (OPTIONS) MULTI LATERAL (If API number last two (2) digits are between 60-69) "CLUE" The permit is for a new wellbore segment of existing well ~ Permit No, API No. Production should continue to be reported as a function· of the original API number stated above. HOLE In accordance with 20 AAC 25.005(1), all records, data and logs acquired for the pilot hole must be clearly differentiated in both name (name on permit plus PH) and API number (50 70/80) from records, data and logs acquired for well (name on permit). PILOT (PH) SPACING EXCEPTION DRY DITCH SAMPLE Rev: 07/10/02 C\jody\templates The permit is approved subject to full compliance with 20 AAC 25.055. Approval to peñorate and produce is contingent upon issuance of a conservation order approving a spacing exception. (Companv Name) assumes the liability of any protest to tbe spacing . exception that may occur. All dry ditcb sample sets submitted to the Commission must be in no greater than 30' sample intervals from below the permafrost or from wbere samples are first caught and 10' sample intervals through target zones. Company BP EXPLORATION (ALASKA) INC Well Name: NORTHSTAR UNIT NS-32i Program SER Well bore seg D PTD#: 2031580 Field & Pool -HORTHSTAR. WDSP UNDEFINED - 590036 nitial ClasslType SER I WDSPL GeoArea Uni On/Off Shore ~ Annular Disposal D Administration 12 Pß(miUee attache.d . . . . . . - - - - Yes - - - - - - - - .Leasß .numberapprORri¡¡te. - - - - - - Yßs - - - - - - '3 .U.nique weltn.amß.and oumb.er . . . . . . . . . . . . . . . . . . . . . . . . · Yes - ~ - - - - - - - - - - - - - - - - - - - - -- - - - - - - -- 4 WellJQc¡¡tßd lnadefine.dppol . - - - - - - - - - - - - No. . Thi~ is ¡¡ .ctass Idjspos.a! wellioto the JJoclefine.d.Scbr¡¡der .Bluffdlspos¡¡tz.one 5 Well JQc¡¡ted proper .distance from driJling uoitbound<lry - - - - - · Yes 810~23dpe~ 001 define a dispQsa/injection zone. 6 WelUQcatßd proper .distance. from otber wells. . - - - - - Yßs - - - - - - - - - - - 7 S.ufficientacreag.e.ayail¡¡ble indrilliog unjt . . . . . . - - - - - Yßs - - - - - - 8 Jf.deviated, js. weJI bOJe plaUncluded . - - - - · Yßs - - - - - - - - - 9 O.perator onl}' C!fteçted pC!rty. . - - - - - - - - - - - - · Yßs - - - - - - - - - - - - - - - - 10 .O.pecator bC!s.apprppriate.bond [nJorce . . . . . . . . . . . . . . . . . . . · .Y.es - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 11 Pßrmit can be issued wjtbQut conserva.tion order. · Yßs - - - - - Appr Date 12 Pßrmit c.an be issued wjtbQut ad.ministrati\¡e.apprpvaJ . . - - - - - Yes - - - - - - - - - RPC 9/11/2003 13 Can permit be approved before 15-day wait Yes 14 Well JQcated withio areC! andstrat¡¡ .autborized by lojectipo Order # (PullO# in. cpmm.ents) (For. No No 81.0-23. d.oes no.t define acl<lss.ldisposa! zone. ~. 15 .AJI wells. within .1 l4.l1Jile.area.of reyiew idßotlfied (Fpr servjc.ewell only). . . . . . . . . . . . . . . .Yßs - - ~ - - - - - - - - - - - - - - - - ~ 16 Pre-produced injector; dur<ltiQnof pre-.productipnless. than 3 months. (For service wel! Qnly) . . No - - - - - - 17 .AÇMP.F.iodlng.of Consistency.h.as beeni~sued.for.tbis pr.oleçt . . . . .NA - - -- - - - - - Engineering 18 .C.ondu.ctor strin.g.prQvided . - - - - - - - - - - -- - - - - - - · Yes - - - - 19 SJJrJC!ceca~ing.prQtec.t~ all known USDWs . . . . . . - - - - - - .Yßs - - - -- - - - - - 20 .CMTvoladequate.to circulate.o.n.cond.uctor& SUJf.csg . . . - - - - - - - · Yes - - - - - -- - - - - - 21 CMT v.ol adequate.to tie-in Jong .string to surf csg. . . . . - - - - - - -- Yßs - - - - - 22 .CMTwiIJ COYEHaJl Kno.wnproductiye bQrizon.s. . . . · No. Open. cpmpletjo.n, - - - - - 23 .C.asing designs ad.equate fpr C,."r:, B .&. Rerl1Jafr.ost . . . . . . . . . . ... Yes - - - - - 24 Adequ<ltetan.kage.oJ re.serve pit. . . ~ - - - - ~ - - - - - ~ · Yßs NabofS.3.3E. . - - - - - 25 Jfare-drilt basa. tOA03 fOJ abandooment beßn ¡¡PPJQved . . . . NA - - - - ~ - - - - - 26 .Adequ<lte.wellborE!. separatjo.npro'posed. . . _ . . . . . . . . . . . . . . . . . . _ ... Yßs - - - - - - - - - - - ~ - - - - - - - - 27 Jf.djvecter req.uired, dQes jt .meet reguJations. ~ - - - - - - - - - - -- · .NA W<liyeuequested. . Appr Date 28 DriUiog fluid. pJQg.ram sc.hematic.&. equip Jistadequatß. . . . - - - ~ · Yes Max MW9~5 ppg.. . - - - -- WGA 9/11/2003 29 .BOPEs,.dp .they meet reguJaJion . - - - - - - Yes - - - - - - - - '. 30 .BOPE.prE!.ss ra1iog appropriate;.test to.(pu.t p$ig i.n.col)1ments) .Yßs Test tp .4800 Rsi. .MSFl2345 psi. 31 C.hPkel1Janjfold cQmpJie~ w/APt RI=I-53 (May 84). . . . . . . · Yes - - - - - 32 WQrk will occ.ur withpytoperationsbutdo.wn . . . . . . . . . - - - - - - · Yßs - - - - 33 J~ presence. Qf H2S gas Rrob.able . - - - - - - - - - - - - - - - - - · No. 34 Mecba.nlcaLcpodJllonpt WE!.lIs withi080B. yerified (for.s.ervice welJ only). . Yßs No wells jr¡AQR. Geology 35 Pß(mit c.an be tssu.ed wlo. hydrogen. s.ulfide measures. . - - - - - - - Yes 36 .D.ata.presented or¡ pote.ntial pverpres.surß .zones. . . . . - - - - - - .NA Appr Date 37 .Seismic.analysJs Qf sbaJlow gaszpoes. . . . . . . . . . . . . . . . . · NA RPC 9/11/2003 38 Sßabedcoodjtipo survey.(if off-sh.ore) . . . . . . . . . . . . . . . . . . . .NA 39 . CQnta.ct namelphon.eJor.weekly prpgress.reRorts [exploratpry .only] . . . . . . .NA Geologic Engineering Public Commissioner Date: Commissioner: Date Commissioner Date bTJ ((JìlJ ~ ~ ....r e e Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify fìnding infonnation, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of infonnation. I I I I I I I I I I I I I I I I I I I sper'r'v-sun C RI L-L.I N G SERV I c: E 5 ~O3>-- /,>(f BP EXPLORATION ALASKA END OF WELL REPORT NORTHSTAR NS 32 I I I I T ABLE OF CONTENTS I I 1. General Information I 2. Daily Summary I 3. Daily Operations 4. Morning Reports I 5. BHA's I 6. Bit Record 7. Mud Reports I 8. Survey Record I 9. Formation Tops 10. Formation Evaluation Logs I I I I sper-r"v-sun I:IRIL.L.INI::Þ 5EFI\JIt:E5 I I I I I I I I I I I I I I I I I I I I I I GENERAL WELL INFORMATION Company: Rig: Well: Field: Borough: State: Country: API Number: Sperry-Sun Job Number: Job Start Date: Job End Date: North Reference: Declination: Dip Angle: Total Field Strength: Date Of Magnetic Data: Wellhead Coordinates N: Wellhead Coordinates W: Vertical Section Azimuth: SDl Engineers: Company Representatives: Company Geologist: lease Name: SSDS Unit Number: State: Borough: BP Exploration Alaska Nabors Alaska Drilling No. 33-E Northstar NS32 Northstar North Slope Alaska United States 50-029-23179-00 AK-AM-22163/ AK-AM-2775313 Nov 26, 2003 Apr30, 2004 True 25.646 deg 80.983 deg 57584.406 nT Sep 20, 2003 North 70 deg 29 min 29.746 sec East 148 deg 41 min 36.022 sec 32.590 deg Doug Wilson Mark Lindloff Reg Wilson Tom Mansfield Lance Vaughn Barb Holt Joe Polya Mike Dinger Ken Lemley Northstar 107 Alaska North Slope sperr"'v-sun ¡;;¡ RI L.L.I N (¡i seR\J Ic:e = I I I I I I I I I I I I I I I I I I I North Star NS32 Well Summary 11/14/03 Moved rig from NS29 Workover Preparing to spud. 11/15/03 Spud NS32. Cleaned out conductor to 334'. Tripped for BRA #2. RIH and drilled to 729'. Maximum gas of 14 units. 11/16/03 Drilled 13 Yí" hole from 729' to 1855' with Gyro. Directional drill from 1855' to 3221 '. Maximum gas of 47 units. Top Permafrost at 1208' MD, 1194' TVD. Base Permafrost at 1615' MD, 1550' TVD. 11/17/03 Drilled to 3980' MD, 3265' TVD, TD 13 W' hole section. Prep for running 10 %" casing. 11/18 - 12/03/03 Drilling suspended on NS32 for work-over operations 12/04/03 Tested BOPE and prepared to drill out of 10 %" casing. 12/05/03 Tested IBOP. Tested casing to 3500 psi. P/U BRA #5. Slipped & Cut. RIH. Serviced Top Drive. Displaced 9.9 brine to seawater while washing down and drilling cement to shoe. Displaced well to 8.6 ppg Seawater polymer mud. Drilled shoe plus 3' to 3964'. Circulated 2X hole volume. Performed FIT at 3964' to 11.5 ppg EMW. Drilled ahead to 4000'. Circulated bottoms up in preparation for additional FIT. Max gas 11 units at 4000' 12/06/03 Performed FIT at 4000' to 11.5 ppg EMW. Drilled ahead 97/8" hole ahead to 6079' MD, 4758' TVD with a max gas of 176 units from 4937'. SV5 @ 4114' MD, 3363' TVD. SV4 @ 4582' MD, 3700' TVD. SV3 @ 4922' MD, 3942' TVD. SV2 5139' MD, 4099' TVD. SVl @ 5724' MD, 4509' TVD. 12/07/03 Drilled ahead from 6079' to 7139' MD with max gas of397 units from coal bed at 6507'. UGNU @ 6237' MD, 4875' TVD 12/08/03 Drilled ahead from 7139' to 8082' MD with max gas of 564 units from 7140'. Schrader Bluff @ 8069' MD, 6465' TVD. 12/09/03 TD 9 7/8" hole section at 8122' MD, 6515' TVD. Circulate and condition for logging and running 7 5/8" casing. 04/28/04 Move rig over NS32 slot to complete drilling of 6 % " hole for disposal well. Nipple up BOP and test same. Test 75/8" casing to 4500 psi for 30 minutes. Makeup 6 %" drilling assembly (Bit #6 XR+, TFA+ 0.5180.). Run in hole picking up 195 joints of 4" drill pipe. 04/29/04 Finish running in hole. Swap out 9.8 ppg Brine for 8.9 ppg Seawater. Maximum gas on bottoms up 228 units. Drill out cement and 20' of new hole to 8141' MD. Perform Formation Integrity Test to 13.6 ppg EMW. Drill 6 %" hole to Total depth of8321' MD, 6991' TVD. Average gas for drilling this interval to TD was 77 units, with a maximum of322 units noted at 8151' MD. Bit #6 statistics= 200 feet, 2.8 hours and 34 K revolutions. Pumped sweep to clean hole and circulate bottoms up. Trip out of hole with drilling assembly. Laydown same. Pickup and makeup scraping assembly and run in hole with same. Perform scraping job. Pull out of hole with scraping assembly. I I I I I I I I I I I I I I I I I I I 04/30/04 Pull out of hole with scraping assembly. Rig up to run 412" tubing Run 4 12" tubing and set packer. I I BP Exploration - Northstar NS32 Daily Operations (I.A.D.C) I Time Elapsed Operations Breakdown (hrs) Time I 11/14/03 I 00:00-00:30 0.50 PJSM / ATP for skidding rig to NS-32 w/ rig & Ops personnel. - Released rig from NS-29 RWO @ 00:00 on 11-14-03 00:30-04:30 4.00 Prepare for skidding rig while Prod. continues bleeding down NS-3l I to 0 pSI. 04:30-06:00 1.50 Skid rig towards NS-32 I - Moving back into area that was not leveled or brought up to grade with 04:30-06:00 1.50 additional gravel this summer due to the rig being stacked out in this I area during the summer. - Shimming over flow lines as rig is being moved. I 06:00-07:00 1.00 Shut down rig move while Production personnel C/O. Rig crew to breakfast. - Renew permits I 07:00-08:00 1.00 Skid rig over NS-32. - Accept rig @ 0800 hrs. 08:00-12:00 4.00 Shim rig & clean up around NS-29. I 12:00-20:00 8.00 R/U surface riser. (had to modify) - Install drain valves on conductor - Transfer fluid between L pits & pits. I - Test lines - Continue mixing spud mud. 20:00-21 :30 1.50 slip & cut drilling line. I 21 :30-22:00 0.50 Install iron roughneck track. 22:00-22:30 0.50 Calibrate Anadrill block height decoder. 22:30-00:00 1.50 PIU HWDP from pipeshed & M/U stands & rack back. I 11/15/03 I 00:00-01 :30 1.50 PIU HWDP,jars, & stand back in derrick. 01 :30-04:00 2.50 MIU BHA 04:00-05:30 1.50 R/U Schlumberger for gyro surveys. I 05:30-06:00 0.50 Pre spud meeting w/ Leigh's crew to discuss objectives of well & hazards of hole section. I - Reviewed D-7 drill (shallow gas w/o diverter) Complete items on pre spud list. 06:00-07:00 1.00 Fill riser w/ sea water - leaking @ drip pan. I - Test mud lines to 3800 psi 07:00-07:30 0.50 B/D all lines 07:30-08:00 0.50 Stand back BHA. I 08:00-12:00 4.00 Drain riser & pull to reseal at drip pan. I - Reinstall I 12:00-13:30 1.50 Pull riser & remove gasket. Reinstall using sealant wlo gasket. 13 :30-14:30 1.00 Pre spud meeting wi Wood's crew to discuss objectives of well & hazards of hole section. I - Reviewed D-7 drill (shallow gas wlo diverter) 14:30-16:00 1.50 Clean out conductor & drill to 218'. 16:00-16:30 0.50 Run gyro survey. I - Survey at base of conductor indicates AZ of 31.79 deg, which lines up excellent with our proposed AZ of 32.59 deg. I 16:30-17:30 1.00 Continue drilling 13 112" hole to 334'. 17:30-18:30 1.00 Condition mud & circulate for trip to change out BRA. 18 :30-19:00 0.50 POR & LID BRA #1. I 19:00-20:30 1.50 PIU BRA #2 & RIR. 20:30-21 :00 0.50 Continue drilling 13 112" hole to 368'. I - Pumping red mud sweeps prior to running gyros. 21 :00-22:00 1.00 Run gyro survey. 22:00-00:00 2.00 Drill & slide from 368' to 728'. I 11/16/03 00:00-12:00 12.00 Drill directional in 13 1/2" hole from 723' to 1855' MD. I - Pumping red mud sweeps prior to gyros & as needed to aid in hole cleaning. I 12:00-12:30 0.50 Circulate sweep to prep for gyro. 12:30-13:30 1.00 Run gyro & confirm MWD within JORPS. 13 :30-14:30 1.00 LID gyro & RJD Schlumberger. I 14:30-00:00 9.50 Drill directional in 13 112" hole from 1855' to 3221' MD. - Last survey Incl. 44.92 deg Az. 34.25 deg I 11/17/03 00:00-02:00 2.00 Replace pin in pipe grapper on Top Drive. I 02:00-09:00 7.00 Drill ahead in 13 1/2" hole to casing point @ 3,980 ft. 09:00-10:30 1.50 Sweep hole. Circ & cond mud for logs. 10:30-11 :00 0.50 Flow check well static. Blow down surface circ system I 11 :00-19:30 8.50 POR wi 13 1/2" bit. Work tight hole @ 2170 - 1948 ft. Pump thru 1735 - 1665 ft. Rack BRA in derrick. LD MWD. I 19:30-20:00 0.50 PJSM wi Schl e line crew 20:00-20:30 0.50 RU Schl e line, no pressure control equip. 20:30-23 :00 2.50 Schl RIH wi PEX logging suite. Unable to work past 1,770 ft. POR I wi logs. RD Schl. 23:00-00:00 1.00 MU & RIR wi 13 1/2" bit. I 11/18/03 I 00:00-00:30 0.50 Surface test MWD. Blow down lines. 00:30-04:30 4.00 RIH wi 13 1/2" bit. Wash thru following area. 1855 - 2042 ft I 3833 - 3980 ft I I I I I I I I I I I I I I I I I I I 04:30-06:00 1.50 06:00-06:30 0.50 06:30-09:30 3.00 09:30-14:00 4.50 14:00-14:30 0.50 14:30-16:30 2.00 16:30-00:00 7.50 Circ & cond mud. 8.5 BPM - 1800 psi Flow check showing well static. Blow down lines. POH wi 13 1/2" bit to BHA. Hole fill reflects well stable. LD BHA. P JSM for surface casing. RU floor for runing 103/4" surface casing. RIH wi 103/4" surface casing to 3920 ft. Avg 5800 MU TQ 11/19/03 00:00-00:30 0.50 MID hanger & wash down landingjt @ 3.5 BPM - 450 psi. - Ran a total of95 jts 10 3/4" 45.50# buttress casing. - Hole was slick - landed casing wi 135K Stage up pump & circulate 1 1/2 BID prior to cement job. - ICP @ 1.5 BPM 270 psi - FCP @ 6 BPM 288 psi. - Held PJSM for cement job while circulating. RID Frank's fillup tool & R/U Halliburton cement head & x-over. Continue circulate & condition mud - adding water to thin mud to 00:30-02:00 1.50 02:00-02:45 0.75 02:45-03:30 0.75 less 03:30-06:30 3.00 than 25 YP. - Add 8 sx bicarb prior to cementing - ICP @ 7 BPM 300 psi - FCP @ 10 BPM 400 psi. Pump 5 bbls sea water & test lines to 3000 psi - Pump 75 bbls. 10.5 ppg weighted spacer & drop plug. - Pump 455 bbls 10.7ppg lead cement (615 sx) - Pump 82 bbls 15.9 ppg tail cement (400 sx) - Drop plug & flush lines wi 25 bbls sea water. Displace cement & bump plug wi 350 bbls mud @ 95% pump efficiency. - Hold 2200 psi for 5 minutes & bleed off. Floats holding. - No losses throughout cement job. RID cement head - Clean floor - LID Landingjt. - Clear floor - Change bails Service TD - change pin in grabber. Clean pits & weight up brine to 9.8 ppg. Repair TD. Adjust linkage to bails per Canrig Rep. RIH to displace mud to 9.8 ppg brine PJSM - Well displacement Wash down & tag cement 11' above FC @ 3866'. Displace well wi 80 bbls sea water, followed by 50 bbls hi vis spacer, followed by 100 bbls sea water, followed by 400 bb1s 9.8 ppg brine. - Rotate (35 RPM) & reciprocate while displacing to brine @ 10 BPM 400 psi. All returns going to G & I via drag chain. POH 06:30-07:30 1.00 07 :30-10:00 2.50 10:00-12:00 2.00 12:00-15:30 3.50 15:30-17:30 2.00 17:30-20:00 2.50 20:00-20:30 0.50 20:30-21 :00 0.50 21 :00-22:30 1.50 22:30-00:00 1.50 11/20/03 I 00:00-00:30 0.50 paR & break offbit. I 00:30-00:00 23.50 Waiting on E-line Ops to complete setting IBP portion of the pre-rig work on NS-27 before USIT log can be run on NS-32. - Performing maintenance on rig as follows: I - Remove pulsation dampener bladder in #1 mud pump & CIO. 11/21/03 I 00:00-15 :00 15.00 Continue waiting for E-line to complete pre rig work on NS-27. - Maintenance on rig while waiting. I - Wire line Unit Finish IBP and Rig down from NS27. 15:00-16:00 1.00 PJSM in pre-tour meeting. Friday Rig Crew Change Out. - Deliver wireline tools & equipment to rig floor. I 16:00-18:30 2.50 Prepare wire line unit of run - cia spools on E-line unit. 18 :30-19:30 1.00 R/U with Schlumberger crews to run USIT logging tools. I 19:30-23:00 3.50 RIH to 3844' wi USIT tools. Troubleshoot to detect problem wi tool string. I - Arrange for helicopter to bring out another string of US IT tools. 23:00-00:00 1.00 POR & cia USIT from Run #1. I 11/22/03 00:00-00:30 0.50 Continue swapping out USIT logging tools. I 00:30-05:00 4.50 RIH wi USIT log. Unable to log. - Made 4 different runs to various depths with different combinations of I transducers & cartridges trying to get log. - Interface between job site & Schlumberger management attempting to I 00:30-05:00 4.50 troubleshoot problems wlo success. 05:00-06:00 1.00 RID E-line crew 06:00-08:00 2.00 RIH wi 5" RWDP & 5" DP & displace brine to leave 350' air gap. I - Slick line R/U on NS-27 to complete pre rig work. (Dumping sluggit on top of IBP) 08:00-10:00 2.00 N/D riser. I 10:00-11 :30 1.50 N/U multi bowl ass'y & test to 2500 psi. 11:30-12:30 1.00 Install 4 112" hanger wi penetrator & test seals to 5000 psi. - Install cover plate & caps on well. I 12:30-14:30 2.00 Clean cellar & prep for rig move. 14:30-18:00 3.50 Wait while slick line completes pre rig work on NS-27. 3 trips & dumped I 5' of sluggit on top of IBP - Slick line RID @ 1800 hrs 18 :00-00:00 6.00 P/U lubricator & set BPV on NS-27. I - Review ATP's with rig crew, OPS, APC, & AIC. - Remove scaffolding from NS-27. - Remove "s" riser between tree & flow line. I - Remove well house, bleed trailer, & other material required for rig move. - Function rig moving equip't. I - Lay plywood on mats. I - Inspect NS-27 w/ ACS Tech & complete pre drillsite checklist. I - Release rig from NS-32 @ 00:00 on 11-23-03 12/03/04 I 00:00-00:30 0.50 Continue to PU 4" HT-40 drill pipe Goint #93 - #111). 00:30-01 :00 0.50 POOH with 9 stands of 4" drillpipe and rack back in derrick. I 01 :00-02:00 1.00 Continue to PU 4" HT-40 drill pipe Goint #111 - #138). 02:00-03:30 1.50 POOH with 37 stands of 4" drillpipe and rack back in derrick. 03:30-06:00 2.50 Change 7" rams to 2-7/8" x 5" variable rams (top rams). I 06:00-06:30 0.50 Pull wear ring. 06:30-07:00 0.50 Fill hole with 9.3 ppg brine. I 1. 53 bbls total- 550' of9.3 ppg brine. 07:00-07:30 0.50 Rig up to test BOP's. 07:30-09:00 1.50 Attempt to test. Change out seal on the test plug. 09:00-09:30 0.50 Attempt to test BOP. Test plug leak. Change out test plug. I 09:30-12:00 2.50 Attempt to test BOP. Test plug not seating. 12:00-12:30 0.50 Install lower test plug. Fill stack. 12:30-14:30 2.00 Test BOP's to 250 psi low and 4800 psi high for 5 min. I 14:30-15:00 0.50 Change out test plug. 15 :00-19:30 4.50 Test BOP's to 250 psi low and 4800 psi high for 5 min. I 19:30-20:00 0.50 Pull test plug and install wear ring. 20:00-20:30 0.50 Blow down choke and kill lines and test pump. 20:30-23 :30 3.00 Change out upper mop. I 23:30-00:00 0.50 Rig up and test upper IBOP. 12/05/03 I 00:00-00:30 0.50 Continue testing BOP's. 00:30-01 :00 0.50 Rig down from BOP test and blow down lines. I 01:00-02:30 1.50 Test casing to 3500 psi for 30 minutes. 1. The pressure increased at approximately 400 psi / 5 strokes. 2. 47 strokes were pumped to 3600 psi; approximately 4.5 bbls. I 3. 6" liners in the pumps 02:30-03:00 0.50 Blow down mud lines. Change out from 4" tools to 5" tools. 03 :00-06:00 3.00 Make up BHA #5. Drilling assembly for 9.7/8" hole. I 06:00-06:30 0.50 Function test MWD and motor. Blow down all lines. 06:30-07:00 0.50 Rill with HWDP to 834' MD. 07:00-07:30 0.50 Island muster drill and D-l drill. I 07:30-08:30 1.00 Continue to RIH with 5" drillpipe to 1,118" MD. 08:30-10:00 1.50 Slip and cut drilling line. 10:00-11 :00 1.00 Service drawworks, crown, and top drive. I 11 : 00-13: 00 2.00 Continue to RIH with 5" drillpipe to 3,755' MD. 13 :00-14:30 1.50 Displace the 9.8 pp brine to seawater while washing down / drilling cement to shoe. I 14:30-15 :30 1.00 Set back a stand. Grease a valve on the mud manifold. Make connection. 15 :30-16:30 1.00 Wash down to 3,875' MD. No rotation, pumping at 140 SPM. Did I not see any cement on top of the plug. 16:30-17:30 1.00 Drill out float equipment. I 17:30-18:30 1.00 Clean out cement down to shoe at 3,959' MD. I Displace well to 8.6 ppg seawater polymer mud using a 25 bbl hi-vis I spacer. 18:30-19:00 0.50 Continue displacement. 19:00-19:30 0.50 Drill out shoe and clean out to 3,964' MD. I 19:30-21 :00 1.50 Circulate & condition mud. 8.6 ppg in / out. Mud at 60 degrees in / out. 1. Pump at 60 spm (6 BPM) with pump #1, 6" liners. I 2. Pump 7500 strokes at 192 psi 3. Rotate at 30 rpm, no recprocation. I 4. Torque at 8300 ftlbs. 21 :00-22:30 1.50 FIT test to 11.5 ppg EMW. Blow down lines. 1. Had difficulty with chart recorder, repeated test. I 2. Charted test at 11.5 ppg EMW (490 psi) for 30 minutes. 22:30-23 :00 0.50 Cleanout rathole and drill from 3,980' MD to 4,000' MD. 23:00-23:30 0.50 Circulate bottoms up until 8.6 ppg MW in and out (3600 strokes). 23 :30-00:00 0.50 FIT test to 11.5 ppg EMW. Blow down lines. I 1. Charted test at 11.5 ppg EMW (490 psi) for 30 minutes. 12/06/03 I 00:00-02:00 2.00 Drill 9-7/8" hole from 4,000' MD to 4,225' MD. I 02:00-02:30 0.50 Service Rig. Work on drawworks drum. 02:30-12:00 9.50 Drilllslide 9-7/8" hole from 4,225' MD to 5,450' MD 1. Rotate 6.2 hours. Slide 0.6 hour. Total on bottom 6.8 hours. I 2. Pumping high vis sweeps every 400'. Seeing increase at shakers. 12:00-00:00 12.00 Drill/slide 9-7/8" hole from 5,450' MD to 6,111' MD 1. Rotate 7.6 hours. Slide 1.8 hours. Total on bottom 9.4 hours. I 2. Pumping high vis sweeps every 400'. Seeing increase at shakers. 3. Pump walnut sweep during slow drilling. No change. 4. Drilling SV sand/shale sequence. I 12/07/03 I 00:00-12:00 12.00 Drilllslide 9-7/8" hole from 6,111' MD to 6,682' MD 1. Rotate 6.2 hours. Slide 3.8 hours. Total on bottom 10.0 hours. 2. Pumping high vis sweeps every 400'. Seeing increase at shakers. I 12:00-00:00 12.00 Drill/slide 9-7/8" hole from 6,682' MD to 7,130' MD 1. Rotate 6.1 hours. Slide 3.8 hours. Total on bottom 9.9 hours. 2. Pumping high vis sweeps every 400'. Seeing increase at shakers. I 12/08/03 I 00:00-01 :30 1.50 Drilllslide 9-7/8" hole from 7,130' MD to 7,185' MD. 01 :30-02:00 0.50 Service drawworks. 02:00-07:00 5.00 Drill/slide 9-7/8" hole from 7,185' MD to 7,349' MD. I 07:00-07:30 0.50 Check top drive RPM counter and brakes. 07:30-08:30 1.00 Service top drive. 08:30-09:00 0.50 Change out RPM counter. I 09:00-09:30 0.50 Island power outage. 09:30-10:00 0.50 Continue to work on top drive. 10:00-00:00 14.00 Drilllslide 9-7/8" hole from 7,349' MD to 8,110' MD. I 1. Rotate 10.8 hours. Slide 0.4 hours. Total on bottom 11.2 hours. I 2. Pumping high vis sweeps every 400'. I 12/09/03 00:00-01 :00 1.00 Drill/slide 9-7/8" hole from 8,110' MD to 8,121' MD. I 01:00-02:30 1.50 Condition mud and circulate. 1. Pump 25 bbl hi-vis sweep at TD. Saw increased cuttings at shakers at bottoms up. I 2. Circulated 1.5 hole volumes. 02:30-03:00 0.50 POOH first 5 stands wet from 8121' MD to 7730' MD. Good hole fill. I 03:00-03:30 0.50 Pump 20 bbls of 11.5 ppg dry job. Blow down top drive and mud line. Monitor well for 10 minutes. No flow. I 03:30-05:30 2.00 POOH from 7730' MD to 3959' MD. Good hole fill. 05:30-06:00 0.50 Monitor well at shoe (3959' MD) for 15 minutes. Perfonn D-1 drill. 06:00-06:30 0.50 ' Service top drive and drawworks. I 06:30-09:30 3.00 Rill from 3959' MD to 8121' MD. Ream the last stand to bottom. 09:30-13 :00 3.50 Circulate and condition mud. I 1. Pump 50 bbl hi-vis sweep, surface to surface. 2. Circulate 3.5 bottoms up. 13:00-17:00 4.00 POOH with driling assembly. No tight spots. 17:00-18:00 1.00 Lay down BHA. I 18 :00-20:30 2.50 PJSM. Rig up to run quad-combo wireilne logs. 20:30-00:00 3.50 Run quad-combo wireline logs. I 12/10/03 00:00-03:00 3.00 Continue to run WL logs. I Once at the shoe, a sufficient density log could not be displayed. Another pass of the hole was made after some parameters were changed in the I tool. The second logging pass was successful. 03:00-03:30 0.50 P JSM -- Rig down e-line. 03:30-05:00 1.50 Load rig floor with casing and drill pipe tools to rig floor. VLE I access will be blocked due to Slickline work. 05 :00-06:00 1.00 Make up BHA #6. I 06:00-12:00 6.00 Rill from 1017' MD with dril pipe to 8121' MD. Good hole fill. Well bore in good shape. I 12:00-15:00 3.00 Condition mud and ciruc1ate. 1. Pump 50 bbl hi-vis sweep, surface to surface. 2. Circulate 3.5 bottoms up. I 15:00-18:00 3.00 Trip out of hole. No tight spots or overpulls. 18:00-20:30 2.50 Lay down BHA. 20:30-21 :30 1.00 Pull wear bushing. Set test plug. I 21 :30-22:00 0.50 PJSM for changing pipe rams. 22:00-23:30 1.50 Change upper pipe rams to 7-5/8" rams. 23 :30-00:00 0.50 Test ram body to 3500 psi. I 12/11/03 00: 00-00: 3 0 0.50 LD test jt. Clear rig floor. I 00:30-02:00 1.50 RU for 75/8" csg. Chg out bails. I 02:00-08:00 6.00 MU & RIH wi 75/8" csg as per program to 103/4" shoe @ 3980 ft. I 08:00-09:00 1.00 CBU @ shoe. 9 BPM - 510 psi. PUW 165k, SOW 140k 09:00-15:00 6.00 Con't RIH wi 7518 csg to setting depth. MU hanger, land csg wi FS @ I 8105 ft, FC @ 8060 ft, LC @ 8015 ft, ES CMTER @ 6152 ft, TAM @ 15:00-16:30 1.50 RD Franks tool, MU cmt head. Circ & condition at 10 bpm. I 16:30-17:00 0.50 PJSM on cementing operations. 17:00-19:30 2.50 First Stage Cement: 1. Test lines to 3500 psi. I 2. Drop 1 st stage bottom plug. 3. Load 1st stage top plug. I 4. Pump 45 bbls spacer. 5. Pump 124 bbls of 15.9 ppg cement. 6. Chase with 25 bbls of seawater. I 7. Pump 3430 stks to bump plug (96% eft). 8. Hold 1470 psi for 5 minutes and check floats holding. 9. Reciprocated pipe while cement turning comer. I 10. Lost 30 bbls of returns during cement job. 19:30-21 :30 2.00 Second Stage Cement 21:30-22:30 1.00 Second Stage Cement (Cont.) I 1. PJSM for second stage job. 2. Pump 45 bbls. spacer. 3. Pump 43 bbls of 13.1 ppg lead slurry. I 4. Pump 57 bbls of 15.9 ppg tail slurry. 5. Drop plug. 6. Pump 25 bbls of seawater. I 7. Pump 257 bbl of mud (2560 strokes) with rig pumps (96% eft). 8. Close ES cementer, Confirmed closed. Hold 2200 psi. 22:30-23:30 1.00 Lay down cement head. Back out upper part oflandingjoint. I 23:30-00:00 0.50 Rig up to run 4" drill pipe to open TAM port collar. 12/12/03 I 00:00-00:30 0.50 MID TAM port collar shifting tool. 00:30-02:30 2.00 RIH wi TAM port collar shifting tool on 4" DP to 4137' MD. 02:30-03:00 0.50 Open TAM port collar I - Up wt. 125K, Dn wt 105K - Pressure up to 1000 psi, then bleed off to 300 psi. 03 :00-04:00 1.00 CBU & PJSM for 3rd stage cement job. I 04:00-06:30 2.50 Cement & close TAM port collar. - Pump 45 bbls. 10.5 spacer, 136 bbls 10.5 lead slurry, 46 bbls. 15.9 tail I slurry. Displaced cement wi 45 bbls sea water via Halliburton pump. 06:30-07:00 0.50 RID cement hose & BID lines 07:00-09:00 2.00 POH & LID TAM shifting tool. I 09:00-10:00 1.00 LID landingjt & CIO elevators from 4" to 5" 10:00-11 :00 1.00 MID packoff ass'y. - RIH & test packoff. (1st attempt failed)) I 11:00-12:00 1.00 Install bowl protector & flush BOP stack. 12:00-14:30 2.50 Packoff failed to test. - Pull bowl protector I - Pull packoff. I 14:30-15:30 1.00 Install new packoff & test to 5000 psi I - Install bowl protector. 15:30-16:30 1.00 CIO saver sun on Top drive to handle 4" DP 16:30-18:00 1.50 P JSM to cut drilling line I - Cut drilling line 18 :00-19:30 1.50 P JSM - - PIU BHA # 7 I 19:30-23 :00 3.50 RIH - picking up singles from pipeshed. 23:00-23:30 0.50 Rotate slowly thru TAM collar @ 4135'. - Wash through TAM port collar @ 4135'. I - No cement detected in casing @ port collar. - Test casing to 1000 psi for 5 minutes. 23:30-00:00 0.50 Continue RIH. I 12/13/03 00:00-01 :30 1.50 RIH wi 4" DP I - PIU singles out of pipe shed. 01 :30-02:15 0.75 Tag cement @ 6060' - 92' above ES Cementer (4 bbls cement) I - Wash & rotate through cement. 40 RPM, 8 BPM @ 870 psi. 02:15-02:45 0.50 Drill plugs & ES Cementer - Tag ES Cementer @ 6160' I 02:45-03:15 0.50 Pump Hi-vis sweep & circulate - Cement, plug rubber, & ES cementer metal seen at shakers. 03:15-03:45 0.50 Test casing to 1000 psi & hold for 5 min. I 03:45-04:30 0.75 Continue RIH wi 4" DP from 6240' to 7855'. 04:30-07:00 2.50 Drill cement & LC from 7855' to 8040'. - LlC @ 8015' I 07:00-08:00 1.00 Pump Hi-vis sweep & circulate. - Test casing to 1000 psi 08:00-10: 15 2.25 Displace well to 9.8 ppg brine. I - Monitor well & BID lines 10:15-12:00 1.75 POH wi 4" DP LID singles. 12:00-13:00 1.00 Lubricate rig. I 13:00-18:30 5.50 POH wi 4" DP & BHA. LID singles. - Rack back 16 stands for RIH & displacing brine. (350' air gap) - Clear tools & clean floor. I 18:30-19:00 0.50 PJSM - RID Schlumberger 19:00-20:00 1.00 RID Schlumberger E-line for USIT log. 20:00-00:00 4.00 RIH wi USIT log. I 04/27/04 09:00-17:00 8.00 P JSM for Rig Move. Move rig from NS21. I - SI NS22, 23, 24, 25, 27, 29, and 31 along the way. Bring on wells after wells become exposed while moving rig I - NS31 in cellar ...remain SI for Heavy Lift. 17:00-19:00 2.00 Level and benn rig. Place flooring in cellar. **ACCEPT rig at 1900 hrs on 12/27/04. I 19:00-19:30 0.50 PJSM for ND dry hole tree and Tbg spool. 19:30-21 :30 2.00 ND dry hole tree & production sweep. ND tubing spool. 21:30-23 :00 1.50 NU spacer spool and new tubing spool (modified for accepting new I penetrator). I 23 :00-00:00 1.00 NU BOP's. I - Put NS31 back on injection at 23:30 hrs. Note: AOGCC Rep, John Spaulding waived witnessing test. I 04/28/04 00:00-03:30 3.50 Continue NU BOP. - Test ABB- VETCO Gray tubing spool to 5000 psig. I 03:30-06:00 2.50 Rig up to Test BOP's. 06:00-14:30 8.50 Pressure Test BOPE to 2501 4800 psig. - AOGCC Rep, John Spaulding waived witness on 4/27/2004. I 14:30-15 :00 0.50 Remove test and blow down Top Drive and lines. 15 :00-15 :30 0.50 Install wear ring. 15:30-17:00 1.50 Pressure test 7-5/8" casing to 4450 psig for 30 mins. I 17:00-18:00 1.00 MUBRA#8. - 6-3/4" Smith XR+ (3xI5's) and 4-3/4" Slimpulse MWD 18:00-18:30 0.50 Shallow Test MWD. I 18:30-20:00 1.50 Single in wI 4" RT-40 DP and BRA to 1696' md. 20:00-21 :00 1.00 Repair pipe skate. 21:00-00:00 3.00 Continue to single in wI BRA from 1696' to 4884' md. I 04/29/04 00:00-03:30 3.50 PU 4" DP from pipeshed and derrick. Wash down and tag TOC at I 8040' md. 03:30-05:30 2.00 Drill cement and the remainder of float equipment (FC and FS @ I 8105'), drill out rathole to 8121' md and drill ahead 20' of new 6-3/4" hole. - Pumped sweep to bit followed by 8.9 ppg NACL brine and I recovered 9.8 ppg NACL brine that was left for suspension while drilling ahead. -Circulate out sweep and cement filling L-Pit. I - Condition MWin= MWout= 9.0 ppg. 05:30-06:30 1.00 Perform LOT to 13.6 ppg EMW. - 9.0 ppg brine in hole with 1570 psi surface pressure. I 06:30-09:00 2.50 Drill ahead 6-3/4" hole from 8141' md to TD at 8321' md (6691' tvd rkb). Drilling parameters: I - 120 rpm wI 8-9 K torque - WOB 15 K-Ibs, ROP= 75 [ph. - 300 gpm wI 1000 psig I 09:00-10:30 1.50 Pump hi vis sweep surface to surface while reciprocating and rotating. - Spot viscosified brine pill in OR, leaving top of pill at 7900' md. I 10:30-11 :00 0.50 Monitor well. Pull 5 stands. 11:00-13:00 2.00 PJSM. Slip and cut drilling line. Service TD and Draw works. 13:00-16:00 3.00 TOR wI BRA#8. I 16:00-16:30 0.50 Monitor well and change out elevators. 16:30-17:30 1.00 PJSM. LID BRA #8. - 6-3/4" bit graded 1-1 WT I 17:30-18:00 0.50 PJSM. MU BRA#9 (6-3/4" Bit and 7-518" scraper). 18 :00-22:00 4.00 Rill wI BRA#9 on 4" DP to 7900' md. 22:00-00:00 2.00 P JSM for pumping casing wash pills and sweeps. I - Pump 40 bbls caustic. I I I I I I I I I I I I I I I I I I I - Followed by 25 bbls Dirt Magnet - Followed by 30 bbls of high vis spacer. - Followed by 90 bbls of 8.9 ppg spacer. - Chase spacer with 9.8 ppg brine. I Customer: BP Alaska Report No.: 1 Well: NorthStar NS 32 Date: 11/15/2003 spe....,....,v-sun Area: North Slope Depth 729 CRI LLI N G seRVIc:es Lease: NorthStar NS 32 Footage Last 24 hrs: 729 Rig: Nabors 33E Rig Activity: Drilling Mudlogger's Morning Report Job No.: AFE 831333 Report For: Vaughn/Dinger Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data R.O.P. 242 ftIhr 302 ftIhr ( 816 fUhr @ 529 ) Pump 1 73 spm DH flow na gpm - Gas' 7 units 5 unit~ ( 14 units @ 334 ) Pump 2 74 spm Total flow gpm - Temp Out 40 Deg F ( 45 deg F @ 268 ) Pump 3 spm A V @ DP fpm - Pump Pres 940 psi AV @ DC fpm .....-- - Mud Wt In 8.70 ppg Visc 116 secs API filt 16.4 ml HTHP 0.0 Mud Wt at Max Gas ~ppg Mud Wt Out 8.70 ppg PV 17 cP YI 61 I bs/1 00ft2 GelE 24 I 30 I 35 Ibs/100ft2 pH 8.9 Sd 0.1 % - - - - - - - Bit No.: 1 Type: MXC1 Bit Size: 13 1/2 Jets: 12 \ 18 \ 18 \ 18 \ \ TFA: 0.8560 - - - - - Wt On Bit: 1-5 RPM: 0 Hrs. On Bit: 2.5 Total Revs on Bit: 14 Footage for Bit Run 729 Trip Depth: ft Trip Gas: Mud Cut: ppg TripCI: 15000 ppm - Short Trip Depth ft Short Trip Gas: Mud Cut: ppg Short Trip CI: ppm - Tight Spots: to to to Feet of Fill on Bottom: ft '-'UII "'ll L.illlology: 0 % % % % %LCM Connection Gas and Mud Cut ft units ppg ft units ppg ft units ppg - - - - - - ft units ppg ft units ppg ft units ppg - - - - - - ft units ppg ft units ppg ft units ppg - - - - - - Drilling Breaks Depth Drill Rate Gas % Lithology before during after before during after Sst Sltst Sh to - - - - to - - - - to - - - - to - - - - 24 hour accumulation of Steel Filings from Possum Belly Magnets: oz. Description of fillings: 24 hr Rec. Drilling ahead to 729 MD No Formation Tops at this time. Logging Engineer: Doug WilsonlMark Lindloff * 10000 units = 100% Gas In Air I I I I I I I I I I I I I I I I I I I I Customer: BP Alaska Report No.: 2 Well: NorthStar NS 32 Date: 11/16/2003 Spef""'f""'V-SUn Area: North Slope Depth 3,287 !:JRI LLI N G seRVices Lease: NorthStar NS 32 Footage Last 24 hrs: 2,557 Rig: Nabors 33E Rig Activity: Drilling Mudlogger's Morning Report Job No.: AFE 831333 Report For: Vaughn/Dinger Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data R.O.P. 0 ftIhr 331 ftIhr ( 2700 ftlhr @ 1416 ) Pump 1 75 spm DH flow na gpm - Gas' 14 units 11 unit! ( 47 units @ 2404 ) Pump 2 90 spm Total flow 698 gpm Temp Out 55 Deg F ( 55 deg F @ 2884 ) Pump 3 spm A V @ DP 55 fpm Pump Pres 1600 psi AV @ DC 104 fpm ........--- - Mud Wt In 9.10 ppg Visc 87 secs API filt 10.0 ml HTHP 0.0 Mud Wt at Max Gas 8.7 ppg - Mud Wt Out 9.10 ppg PV 18 cP YI 45 Ibs/100ft2 Gels 20 I 32 I 40 Ibs/100ft2 pH 9.1 Sd 0.75 % - - - - - - - Bit No.: 1 Type: MXC1 Bit Size: 13 1/2 Jets: 12 \ 18 \ 18 \ 18 \ \ TFA: 0.8560 - - - - - Wt On Bit: 33 RPM: 36 Hrs. On Bit: 22.5 Total Revs on Bit: 83 Footage for Bit Run 3,287 Trip Depth: ft Trip Gas: Mud Cut: ppg TripCI: 17000 ppm - Short Trip Depth ft Short Trip Gas: Mud Cut: ppg Short Trip CI: ppm - Tight Spots: to to to Feet of Fill on Bottom: ft 0 % % % % %LCM Connection Gas and Mud Cut ft units ppg ft units ppg ft units ppg - - - - - - ft units ppg ft units ppg ft units ppg - - - - - - ft units ppg ft units ppg ft units ppg Drilling Breaks Depth Drill Rate Gas % Lithology before during after before during after Sst Sltst Sh to - - - - to - - - - to - - - - to - - - - 24 hour accumulation of Steel Filings from Possum Belly Magnets: oz. Description of fillings: 24 hr Ree. Drilling ahead from 729 MD to 3287' MD TOP PERMAFROST 1208' MD, 1194' TVD BASE PERMAFROST 1615' MD, 1550' TVD Logging Engineer: Doug WilsonlMark Lindloff . 10000 units = 100% Gas In Air I I I I I I I I I I I I I I I I I I Customer: BP Alaska Report No.: 3 Well: NorthStar NS 32 Date: 12/5/2003 sper"r"v-sun Area: North Slope Depth 4,000 [JRILLING SERVIc:es Lease: NorthStar NS 32 Footage Last 24 hrs: 20 Rig: Nabors 33E Rig Activity: Drilling Mudlogger's Morning Report Job No.: AFE 831333 Report For: Vaughn/Holt Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data R.O.P. 83 0 85 ftIhr ( 95 ftIhr @ 3999 ) Pump 1 90 spm DH flow na gpm Gas· 3 units 2 unit~ ( 11 units @ 4000 ) Pump 2 90 spm Total flow 761 gpm Temp Out 53 Deg F ( 55 deg F @ 4000 ) Pump 3 spm AV @ DP 252 fpm - Pump Pres 1650 psi AV @ DC 349 fpm ........--- - Mud Wt In 8.60 ppg Visc 46 secs API filt 15.2 ml HTHP Mud Wt at Max Gas 8.6 ppg - Mud Wt Out 8.60 ppg PV 9 cP YI 17 Ibs/100ft2 Gel~ 6 I 7 I 8 I bs/1 00ft2 pH 9.7 Sd 0 % - - - - - - - Bit No.: 2 Type: GFXIVC Bit Size: 97/8" Jets: 12 \ 18 \ 18 \ 18 \ \ TFA: 0.8560 - - - - - Wt On Bit: 18 RPM: 46 Hrs. On Bit: 0.3 Total Revs on Bit: 1.5K Footage for Bit Run 20 Trip Depth: ft Trip Gas: Mud Cut: ppg TripCI: ppm - Short Trip Depth ft Short Trip Gas: Mud Cut: ppg Short Trip CI: ppm - Tight Spots: to to to Feet of Fill on Bottom: ft ~u -"J' % % % % %LCM Connection Gas and Mud Cut ft units ppg ft units ppg ft units ppg - - - - - - ft units ppg ft units ppg ft units ppg - - - - - - ft units . ppg ft units ppg ft units ppg Drilling Breaks Depth Drill Rate Gas % Lithology before during after before during after Sst Sltst Sh to - - - - to - - - - to - - - - to - - - - 24 hour accumulation of Steel Filings from Possum Belly Magnets: oz. Description of fillings: 24 hr Rec. Test IBOP. Test casing to 3500 psi. P/U BHA #5. Slip & Cut. RIH. Service Top Drive. Displace 9.9 brine to seawater while washing down and drilling cement to shoe. Displace well to 8.6 ppg Seawater polymer mud. Drill shoe plus 3' to 3964'. Circ 2X hole volume. Perform FIT at 3964' to 11.5 ppg EMW. Drill ahead to 4000'. Circ bottoms up in preparation for additional FIT. Logging Engineer: Tom Mansfield I Reg Wilson . 10000 units = 100% Gas In Air I I I I I I I I I I I I I I I I I I I Customer: BP Alaska Report No.: 4 Well: NorthStar NS 32 Date: 12/6/2003 spel'""'l'""'v-sun Area: North Slope Depth 6,079 CAI LLI N G SERVICES Lease: NorthStar NS 32 Footage Last 24 hrs: 2,079 Rig: Nabors 33E Rig Activity: Drilling Mudlogger's Morning Report Job No.: AFE 831333 Report For: Vaughn/Holt Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data R.O.P. 148 128 ftIhr ( 615 ftIhr @ 4170 ) Pump 1 84 spm DH flow gpm - Gas· 25 units 28 unit! ( 176 units @ 4937 ) Pump 2 87 spm Total flow 723 gpm - Temp Out 80 Deg F ( 80 deg F @ 6079 ) Pump 3 spm AV @ DP 191 fpm Pump Pres 1970 psi A V @ DC 245 fpm ...........- - Mud Wt In 8.80 ppg Visc 46 secs API filt 5.5 ml HTHP Mud Wt at Max Gas 8.8 ppg - - Mud Wt Out 8.80 ppg PV 10 cP YI 26 Ibs/100ft2 Gel5 10 I 14 I I bs/1 00ft2 pH 9.0 Sd 0.05 % - - - - - - - Bit No.: 2 Type: GFXIVC Bit Size: 97/8" Jets: 12 \ 18 \ 18 \ 18 \ \ TFA: 0.8560 - - - - - - Wt On Bit: 27 RPM: 108 Hrs. On Bit: 16.4 Total Revs on Bit: 158K Footage for Bit Run 2,099 Trip Depth: ft Trip Gas: Mud Cut: ppg Trip CI: ppm - Short Trip Depth ft Short Trip Gas: Mud Cut: ppg Short Trip CI: ppm - Tight Spots: to to to Feet of Fill on Bottom: ft , :." ogy: % % % % %LCM - - - Connection Gas and Mud Cut ft units ppg ft units ppg ft units ppg - - - - - - ft units ppg ft units ppg ft units ppg - - - - - - ft units ppg ft units ppg ft units ppg - - - - - - Drilling Breaks Depth Drill Rate Gas % Lithology before during after before during after Sst Sltst Sh to - - - - to - - - - to - - - - to - - - - 24 hour accumulation of Steel Filings from Possum Belly Magnets: oz. Description of fillings: 24 hr Recê Perform FIT at 4000' to 11.5 ppg. Drill ahead. SV5 @ 4114' MD, 3363' TVD. SV4 @ 4582' MD, 3700' TVD. SV3 @ 4922' MD, 3942' TVD. SV2 5139' MD, 4099' TVD. SV1 @ 5724' MD, 4509' TVD Logging Engineer: Tom Mansfield I Reg Wilson * 10000 units = 100% Gas In Air I I I I I I I I I I I I I I I I I I I Customer: BP Alaska Report No.: 5 Well: NorthStar NS 32 Date: 12/7/2003 spe....,....,v-sun Area: North Slope Depth 7,139 [JRI LLI N G seRVIces Lease: NorthStar NS 32 Footage Last 24 hrs: 1,060 Rig: Nabors 33E Rig Activity: Drilling Mudlogger's Morning Report Job No.: AFE 831333 Report For: Vaughn/Holt Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data R.O.P. 50 90 ftIhr ( 585 ftIhr @ 6384 ) Pump 1 84 spm DH flow gpm - Gas' 80 units 45 unit! ( 397 units @ 6507 ) Pump 2 82 spm Total flow 702 gpm Temp Out 105 Deg F ( 105 deg F @ 7078 ) Pump 3 spm A V @ DP 186 fpm Pump Pres 2200 psi AV @ DC 239 fpm ..."....- - Mud Wt In 8.80 ppg Visc 43 secs API filt 6.0 ml HTHP Mud Wt at Max Gas ~ppg - Mud Wt Out 8.80 ppg PV 10 cP YI23 Ibs/100ft2 Gel~ 10 I 13 I 15 Ibs/100ft2 pH 9.0 Sd 0.05 % - - - - - - - Bit No.: 2 Type: GFXIVC Bit Size: 97/8" Jets: 12 \ 18 \ 18 \ 18 \ \ TFA: 0.8560 - - - - - Wt On Bit: 30 RPM: 110 Hrs. On Bit: 35.1 Total Revs on Bit: 308K Footage for Bit Run 3,159 Trip Depth: ft Trip Gas: Mud Cut: ppg Trip CI: ppm - Short Trip Depth ft Short Trip Gas: Mud Cut: ppg Short Trip CI: ppm - Tight Spots: to to to Feet of Fill on Bottom: ft vUII "'"' L.llllology: % % % % %LCM - - - - Connection Gas and Mud Cut ft units ppg ft units ppg ft units ppg - - - - - - ft units ppg ft units ppg ft units ppg - - - - - - ft units ppg ft units ppg ft units ppg Drilling Breaks Depth Drill Rate Gas % Lithology before during after before during after Sst Sltst Sh to - - - - to - - - - to - - - - to - - - - 24 hour accumulation of Steel Filings from Possum Belly Magnets: oz. Description of fillings: 24 hr Recé Drilled ahead. UGNU @ 6237' MD, 4875' TVD Logging Engineer: Tom Mansfield I Reg Wilson * 10000 units = 100% Gas In Air I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I Customer: BP Alaska Report No.: 6 Well: NorthStar NS 32 Date: 12/8/2003 spe....,....,v-sun Area: North Slope Depth 8,082 J:lRILLING seRVices Lease: NorthStar NS 32 Footage Last 24 hrs: 943 Rig: Nabors 33E Rig Activity: Drilling Mudlogger's Morning Report Job No.: AFE 831333 Report For: Vaughn/Holt Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data R.O.P. 42 58 ftIhr ( 600 fUhr @ 7455 ) Pump 1 84 spm DH flow gpm - Gas' 52 units 70 unit! ( 564 units @ 7140 ) Pump 2 82 spm Total flow 702 gpm - Temp Out 120 Deg F ( 105 deg F @ 8032 ) Pump 3 spm A V @ DP 186 fpm Pump Pres 2400 psi A V @ DC 239 fpm ....-- - Mud Wt In 8.95 ppg Visc 45 secs API filt 6.0 ml HTHP Mud Wt at Max Gas ~ppg - - - Mud Wt Out 8.95 ppg PV 11 cP YI 24 Ibs/100ft2 Gel5 9 I 13 I 15 Ibs/100ft2 pH 8.9 Sd 0.05 % - - - - - - - Bit No.: 2 Type: GFXIVC Bit Size: 97/8" Jets: 12 \ 18 \ 18 \ 18 \ \ TFA: 0.8560 - - - - - Wt On Bit: 28 RPM: 107 Hrs. On Bit: 51.3 Total Revs on Bit: 476K Footage for Bit Run 4,102 Trip Depth: ft Trip Gas: Mud Cut: ppg Trip CI: ppm - Short Trip Depth ft Short Trip Gas: Mud Cut: ppg Short Trip CI: ppm - Tight Spots: to to to Feet of Fill on Bottom: ft % % % % %LCM - - - - Connection Gas and Mud Cut ft units ppg ft units ppg ft units ppg - - - - - - ft units ppg ft units ppg ft units ppg - - - - - - ft units ppg ft units ppg ft units ppg Drilling Breaks Depth Drill Rate Gas % Lithology before during after before during after Sst Sltst Sh to - - - - to - - - - to - - - - to - - - - 24 hour accumulation of Steel Filings from Possum Belly Magnets: oz. Description of fillings: 24 hr Recê Drilled ahead. Update: TO 9 7/8" hole @ 8121' MO, 6514' TVO, 12:55 a.m. Schrader Bluff @ 8069' MD, 6465' TVD Logging Engineer: Tom Mansfield I Reg Wilson * 10000 units = 100% Gas In Air I I I Customer: BP Alaska Report No.: 6 Well: NorthStar NS 32 Date: 12/9/2003 spe..........v-sun Area: North Slope Depth 8,121 ~ A I L..L..I N G SEAVIt:ES Lease: NorthStar NS 32 Footage Last 24 hrs: 39 Rig: Nabors 33E Rig Activity: wireline Mudlogger's Morning Report Job No.: AFE 831333 Report For: Vaughn/Holt Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data R.O.P. 175 ftlhr ( 315 fUhr @ 8108 ) Pump 1 spm DH flow gpm - Gas' units 65 unit! ( 101 units @ 8102 ) Pump 2 spm Total flow gpm - Temp Out Deg F ( deg F @ ) Pump 3 spm A V @ DP - fpm Pump Pres psi A V @ DC - fpm .......--- Mud Wt In 9.00 ppg Visc 43 secs API filt 7.0 ml HTHP Mud Wt at Max Gas ~ppg - Mud Wt Out 9.00 ppg PV 10 cP YI23 Ibs/100ft2 GelE 8 I 12 I I bs/1 00ft2 pH 9.1 Sd 0.05 % - - - - - - - Bit No.: 2 Type: GFXIVC Bit Size: 97/8" Jets: 12 \ 18 \ 18 \ 18 \ \ TFA: 0.8560 - - - - - Wt On Bit: 28 RPM: 107 Hrs. On Bit: 50.7 Total Revs on Bit: 597K Footage for Bit Run 4,141 Trip Depth: ft Trip Gas: Mud Cut: ppg Trip CI: ppm - Short Trip Depth ft Short Trip Gas: Mud Cut: ppg Short Trip CI: ppm - Tight Spots: to to to Feet of Fill on Bottom: ft % % % % %LCM - - - - Connection Gas and Mud Cut ft units ppg ft units ppg ft units ppg - - - - - - ft units ppg ft units ppg ft units ppg - - - - - - ft units ppg ft units ppg ft units ppg Drilling Breaks Depth Drill Rate Gas % Lithology before during after before during after Sst Sltst Sh to - - - - to - - - - to - - - - to - - - - 24 hour accumulation of Steel Filings from Possum Belly Magnets: oz. Description of fillings: 24 hr Recê Drilled ahead to 8121' MD, 6514' TVD. Circulate and condition hole for wirelining and 7 5/8" casing. Schrader Bluff @ 8069' MD, 6465' TVD Logging Engineer: Tom Mansfield I Reg Wilson * 10000 units = 100% Gas In Air I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I Customer: BP Alaska Report No.: 7 Well: NorthStar NS 32 Date: 4/28/2003 sperrv-sun Area: North Slope Depth 8,121 [:JRI LLI N G SERVIC::ES Lease: NorthStar NS 32 Footage Last 24 hrs: 0 Rig: Nabors 33E Rig Activity: RIH Mudlogger's Morning Report Job No.: AFE 831333 Report For: Holt 1 Clump Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data R.O.P. fUhr ( fUhr @ ) Pump 1 spm DH flow gpm - Gas' units unit! ( units @ ) Pump 2 spm Total flow gpm - Temp Out Deg F ( deg F @ ) Pump 3 spm A V @ DP - fpm Pump Pres - psi AV @ DC - fpm Mud Wt In 9.80 ppg Visc 28 secs API filt 0.0 ml HTHP Mud Wt at Max Gas ppg - - Mud Wt Out 9.80 ppg PV 0 cP YI 0 Ibs/100ft2 Gel~ I I I bs/1 00ft2 pH Sd % - - - - - - - Bit No.: 6 Type: XR+ Bit Size: 63/4 Jets: 15 \ 15 \ 15 \ \ \ TFA: 0.5180 - - - -- Wt On Bit: RPM: Hrs. On Bit: 0.0 Total Revs on Bit: 0 Footage for Bit Run 0 Trip Depth: ft Trip Gas: Mud Cut: ppg Trip CI: ppm - Short Trip Depth ft Short Trip Gas: Mud Cut: ppg Short Trip CI: ppm - Tight Spots: to to to Feet of Fill on Bottom: ft Current Lithology: % % % % %LCM - - - - Connection Gas and Mud Cut ft units ppg ft units ppg ft units ppg - - - - - - ft units ppg ft units ppg ft units ppg - - - - - - ft units ppg ft units ppg ft units ppg Drilling Breaks Depth Drill Rate Gas % Lithology before during after before during after Sst Sltst Sh to - - - - to - - - - to - - - - to - - - - 24 hour accumulation of Steel Filings from Possum Belly Magnets: oz. Description of fillings: 24 hr Rec¡ Completed move from NS21 to NS32. Rig up. N/D tree and tbg spool. N/U spacer and new tbg spool. N/U BOP. Test tbg spool to 5000 psi. R/U, test BOPE. Test csg to 4500psi for 30 min. M/U 6.75" BHA and surface test. RIH picking up 195 jnts of 4" DP. Logging Engineer: Tom Mansfield I Doug Wilson * 10000 units = 100% Gas In Air I I I I I I I I I I I I I I I I I I I Customer: BP Alaska Report No.: 8 Well: NorthStar NS 32 Date: 4/29/2004 spe............v-sun Area: North Slope Depth 8,321 I:JRIL-L-ING seRVices Lease: NorthStar NS 32 Footage Last 24 hrs: 200 Rig: Nabors 33E Rig Activity: POOH Mudlogger's Morning Report Job No.: AFE 831333 Report For: Holt / Clump Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data R.O.P. 0 106 ftIhr ( 204 ftlhr @ 8211 ) Pump 1 51 spm DH flow gpm - Gas' 0 units 77 unit! ( 322 units @ 8151 ) Pump 2 51 spm Total flow 363 gpm Temp Out Deg F ( deg F @ ) Pump 3 spm A V @ DP 284 fpm Pump Pres 1159 psi AV @ DC 360 fpm .....-- - Mud Wt In ppg Visc 28 secs API filt 0.0 ml HTHP Mud Wt at Max Gas ppg - - Mud Wt Out 9.80 ppg PV 0 cP YI 0 I bs/1 00ft2 Gel~ I I Ibs/100ft2 pH Sd % - - - - - - - Bit No.: 6 Type: XR+ Bit Size: 63/4 Jets: 15 \ 15 \ 15 \ \ \ TFA: 0.5180 - - - - -- Wt On Bit: 12 RPM: 113 Hrs. On Bit: 2.8 Total Revs on Bit: 34 Footage for Bit Run 200 Trip Depth: ft Trip Gas: Mud Cut: ppg Trip CI: ppm - Short Trip Depth ft Short Trip Gas: Mud Cut: ppg Short Trip CI: ppm - Tight Spots: to to to Feet of Fill on Bottom: ft % % % % %LCM - - - - Connection Gas and Mud Cut ft units ppg ft units ppg ft units ppg - - - - - - ft units ppg ft units ppg ft units ppg - - - - - - ft units ppg ft units ppg ft units ppg - - - - - - Drilling Breaks Depth Drill Rate Gas % Lithology before during after before during after Sst Sltst Sh to - - - - to - - - - to - - - - to - - - - 24 hour accumulation of Steel Filings from Possum Belly Magnets: oz. Description of fillings: 24 hr Rec, Finish RIH, Drlled out cement and 20' new formation. Performed FIT to 13.6 ppg. Drilled ahead to TO of 8321'. Pumped sweep to clean hole, POOH, RIH with scraping BHA. Currently POOH. Gas peaked at 322 units Logging Engineer: Mark Lindloff I Doug Wilson * 10000 units = 100% Gas In Air I I I I I I I I I I I I I I I I I I I Ver.10-03 Scblullbøpgøp BHA# 1 Job # 40009833 Date In 15-Noy-03 Date Out 15-Noy-03 Hole Size 13 1/2 Customer BP ADW Time In 1 :30 Time Out 19:30 Hole Seet Surface Well NS32i Depth In 201 Depth Out 334 Bha Type Steerable Field Northstar TVD In 201 TVD Out 334 Hrs BRT 18.00 Rig Nabors 33E Drlg Hrs 0.6 Drlg Ft 133 Avg ROP 221.67 AFE# NSD-831333 Slide Hrs Slide Ft Slide ROP #DIV/O! DD's Rinke / Tunnell Rot Hrs 0.6 Rot Ft 133 RotROP 221.67 Co. Men Vaughn / Dinger Pump Hrs 1.8 Rotate % 100 Slide % PDM Run # 1 R/S 3/4 PDM Jet Blk Inel In Azln Bit>Srvy 39.00 PDM Ser# 962-3573 Stages 4.5 Bearing Mud InelOut 0.92 Az Out 35.54 T/F Carr PDM Size 9 5/8 Rev/Gal 0.221 Rubber RM 1 OOD Avg Dls Max Ds Plan Dls Mud Type Spud Mud Wt 8.7 Sand % RPM 25 GPM 420 SPP On 400 BHT F Mud Vis 100 Solids % DIg TQ 1.5 Kftlbs WOB 5 SPP Off 400 Bit#1 MXC1 Hughes 5037998 13 1/2 1x123x18 1.00 1.00 TFA=.856 6 5/8 Reg P 2 X-OVER Ana GLDD-208 8 13/16 2 718 6 5/8 Reg B 0.90 1.90 7 5/8 Reg P 3 9 5/8 Std PDM 1.83° Ana 962-3573 9 5/8 Tool 13 3/8 2.18 7 5/8 Reg B 26.78 28.68 6 5/8 H90 B 4 Orienting Sub Ana STORS-HA-105 7 15/16 2 112 6 5/8 H-90 P 1.47 30.15 6 5/8 H-90 B 5 NM STAB Ana NMSZSS-HA-020 8 2 7/8 13 1/2 2.30 6 5/8 H-90 P 5.02 35.17 6 5/8 H-90 B 6 MONEL LC Ana 800-007 8 2 7/8 6 5/8 H-90 P 9.52 44.69 6 5/8 H-90 B 7 MONEL LC Ana 10-HA-008 8 2 7/8 6 5/8 H-90 P 9.73 54.42 6 5/8 H-90 B 8 NM STAB Ana NMSZSS-HA-010 8 2 7/8 12 1/4 2.40 6 5/8 H-90 P 5.50 59.92 6 5/8 H-90 B 9 X-OVER Ana STXOS-HC-614 7 1/16 X 8 1/E 2 7/8 1.28 6 5/8 H-90 P 3.08 63.00 4 1/2 IF B Clean out conductor and survey BHL DryWt Buoyed Wt Inel Angle Buoy+lnel Wt 9,408 10,845 9,408 39' IADC# 115 Footage 133 Hrs 0.6 k Revs 4 k Grade Not graded Comment 0.0 Motor Jars Bít#1 0.0 1.8 0.6 0.6 1.8 Schlumberger Public I I Ver.10-03 Scblallberler BHA# 2 Job # 40009833 Date In 15-Nov-03 Date Out 17-Nov-03 Hole Size 13 1/2 I Customer BP ADW Time In 19:30 Time Out 20:00 Hole Sect Surface Well NS32i Depth In 334 Depth Out 3,980 Bha Type Steerable Field Northstar TVD In 334 TVD Out 3,266 Hrs BRT 48.50 Rig Nabors 33E Drlg Hrs 15.5 Drlg Ft 3,646 Avg ROP 235.23 I AFE# NS 0-831333 Slide Hrs 4.8 Slide Ft 1,041 Slide ROP 216.88 DD's Rinke / Tunnell RotHrs 10.7 Rot Ft 2,605 Rot ROP 243.46 Co. Men Vaughn / Dinger Pump Hrs 26.5 Rotate % 71 Slide % 29 PDM Run # 1 R/S 3/4 PDM Jet Blk Inclln 0.89 Azln 36.13 Bit>Srvy 68.40 I PDM Ser# 962-3573 Stages 4.5 Bearing Mud InclOut 43.28 Az Out 32.13 T/F Corr 3.8 PDM Size 9 5/8 Rev/Gal 0.221 Rubber RM 1 000 Avg Dls 2.7 Max Ds 5.0 Plan Dls 2.5 Mud Type Spud Mud Wt 9.2 Sand % .75 RPM 40 GPM 720 SPP On 1750 I BHT F 90 Mud Vis 90 Solids % 4 DIg TQ 10.0 WOB 30 SPP Off 1600 Bit#1 MXC1 Hughes 503799B 13 1/2 1x123x18 1.00 1.00 I 6 5/8 Reg P 2 X-OVER Ana GLDD-20B 8 13/16 2 7/8 6 5/8 Reg B 0.90 1.90 7 5/8 Reg P 3 9 5/8 Std PDM 1.830 Ana 962-3573 9 5/8 Tool 13 3/8 2.18 7 5/8 Reg B 26.78 28.68 I 6 5/8 H90 B 4 MONEL LC Ana BOO-007 8 2 7/8 6 5/8 H-90 P 9.52 38.20 6 5/8 H-90 B 5 MONEL LC Ana 10-HA-00B 8 2 7/8 6 5/8 H-90 P 9.73 47.93 I 6 5/8 H-90 B 6 NM STAB Ana NMSZSS-HA-010 8 2 7/8 12 1/4 2.40 6 5/8 H-90 P 5.50 53.43 6 5/8 H-90 B 7 MWD Ana 196 8 Tool 1.82 6 5/8 H90 P 29.38 82.81 I filter 6 58 H90 B 8 Orienting Sub Ana STORS-HA-105 7 15/16 2 1/2 6 5/8 H-90 P 1.47 84.28 6 5/8 H-90 B 9 NM STAB Ana NMSZSS-HA-013 8 2 7/8 12 1/4 2.30 6 5/8 H-90 P 5.22 89.50 I 6 5/8 H-90 B 10 NM DC Ana NM DC-HA-025 8 2 7/8 6 5/8 H-90 P 30.90 120.40 6 5/8 H-90 B 11 NM DC Ana NMDC-HA-020 8 2 7/8 6 5/8 H-90 P 30.92 151.32 I 6 5/8 H-90 B 12 NM STAB Ana NMSZSS-HA-020 8 2 7/8 13 1/2 2.30 6 5/8 H-90 P 5.02 156.34 6 5/8 H-90 B 13 NM DC Ana NMDC-HA-024 8 2 7/8 6 5/8 H-90 P 30.93 187.27 I 6 5/8 H-90 B 14 HYDJARS DAI LEY 1417-1044 7 3/4 3 1.20 6 5/8 H90 P 30.80 218.07 4 1/2 IF B 15 26 Jnts HWDP 5" NAD 26HWDP 5 3 4 1/2 IF P 781.86 999.93 I 4 1/2 IF B 16 DP 5" to Surface NAD DP 5 4 1/4 41/2 IF P 999.93 4 1/2 IF B I I I Drill build and tangent to surface TO DryWt 68,354 IADC# 115 Motor 1.8 28.3 run Buoyed Wt 58,775 Footage 3,646 Jars 0.0 15.5 Inel Angle Hrs 15.5 Bit #2 0.0 15.5 I point Buoy+lnel Wt 58,775 k Revs 174 k 26.5 Grade 1-1-WT-A-E-1-NO-TD , GR=66.28' Comment I Schlumberger Public I I Ver.10-03 S Ib I' BHA# 3 Job # 40009833 Date In 17 -Noy-03 Date Out 18-Noy-03 Hole Size 13 1/2 I Customer BP ADW Time In 23:00 Time Out 13:30 Hole Seet Surface Well NS32i Depth In 3,980 Depth Out 3,980 Bha Type Cleanout Field Northstar TVD In 3,266 TVD Out 3,266 Hrs BRT 14.50 Rig Nabors 33E Drlg Hrs Drlg Ft Avg ROP #DIV/O! I AFE# NSD-831333 Slide Hrs Slide Ft Slide ROP #DIV/O! DD's Rinke I Tunnell Rot Hrs Rot Ft Rot ROP #DIV/O! Co. Men Vaughn I Dinger Pump Hrs 2.2 Rotate % #DIV/O! Slide % #DIV/O! PDM Run # R/S 3/4 PDM Jet Blk Inelln 43.28 Az In 32.13 Bit>Srvy 68.40 I PDM Ser# 962-3573 Stages 4.5 Bearing Mud Inel Out Az Out T/F Carr PDM Size 9 5/8 Rev/Gal 0.221 Rubber RM 1 OOD Avg Dls Max Ds Plan Dls Mud Type Spud Mud Wt 9.2 Sand % RPM GPM SPP On BHT F Mud Vis Solids % DIg TQ WOB SPP Off I Bit#1 MXC1 Hughes 503799B 13 1/2 1x123x18 1.00 1.00 I 6 5/8 Reg P 2 X-OVER Ana GLDD-20B 8 13/16 2 718 6 5/8 Reg B 0.90 1.90 7 5/8 Reg P 3 9 5/8 Std PDM 1.83' Ana 962-3573 9 5/8 Tool 13 3/8 2.18 7 5/8 Reg B 26.78 28.68 I 6 5/8 H90 B 4 MONEL LC Ana BOO-007 8 2 7/8 6 5/8 H-90 P 9.52 38.20 6 5/8 H-90 B 5 MONEL LC Ana 10-HA-00B 8 2 7/8 6 5/8 H-90 P 9.73 47.93 I 6 5/8 H-90 B 6 NM STAB Ana NMSlSS-HA-010 8 2 7/8 12 1/4 2.40 6 5/8 H-90 P 5.50 53.43 6 5/8 H-90 B 7 MWD Ana 196 8 Tool 1.82 6 5/8 H90 P 29.38 82.81 I filter 6 58 H90 B 8 Orienting Sub Ana STORS-HA-105 7 15/16 2 112 6 5/8 H-90 P 1.47 84.28 6 5/8 H-90 B 9 NM STAB Ana NMSlSS-HA-013 8 2 7/8 12 1/4 2.30 6 5/8 H-90 P 5.22 89.50 I 6 5/8 H-90 B 10 NM DC Ana NMDC-HA-025 8 2 7/8 6 5/8 H-90 P 30.90 120.40 6 5/8 H-90 B 11 NM DC Ana NMDC-HA-020 8 2 7/8 6 5/8 H-90 P 30.92 151.32 I 6 5/8 H-90 B 12 NM STAB Ana NMSlSS-HA-020 8 2 7/8 13 1/2 2.30 6 5/8 H-90 P 5.02 156.34 6 5/8 H-90 B 13 NM DC Ana NMDC-HA-024 8 2 7/8 6 5/8 H-90 P 30.93 187.27 I 6 5/8 H-90 B 14 HYD JARS DAILEY 1417-1044 7 3/4 3 1.20 6 5/8 H90 P 30.80 218.07 4 1/2 IF B 15 26 Jnts HWDP 5" NAD 26HWDP 5 3 4112 IF P 781.86 999.93 I 4 1/2 IF B 16 DP 5" to Surface NAD DP 5 4 1/4 4 1/2 IF P 999.93 4 1/2 IF B I I I Cleanout after wireline logs DryWt 68,354 IADC# 115 Motor 28.3 30.5 Buoyed Wt 58,775 Footage Jars 0.0 0.0 Inel Angle Hrs Bit #2 0.0 0.0 I Buoy+lnel Wt 58,775 k Revs 2.2 Grade , GR=66.28' Comment I Schlumberger Public I I I I I I I I I I I I I I I I I I I Ver.10-03 Schlumberger Job # 40009833 Customer BP ADW Well NS32 Field Northstar Rig Nabors 33E AFE # NSD-831333 DD's Rinke 1 Tunnell Co. Men Vaughn 1 Dinger PDM Run # PDM Ser# PDM Size Mud Type Spud BHT F R/S Stages Rev/Gal 0.221 Mud Wt 9.2 Mud Vis Date In 19-Nov-03 Time In 17:00 Depth In 3,980 TVD In 3,266 Drlg Hrs Slide Hrs Rot Hrs Pump Hrs PDM Jet Bearing Rubber Sand % Solids % BHA# 4 Date Out 20-Nov-03 Time Out 0:30 Depth Out 3,980 TVD Out 3,266 Drlg Ft Slide Ft Rot Ft Rotate % #DIV/O! Inclln Az In Incl Out Az Out Avg Dls Max Ds RPM GPM DIg TQ WOB Hole Size 9 7/8 Hole Sect Intermeidate Bha Type Cleanout Hrs BRT 7.50 Avg ROP #DIV/O! Slide ROP #DIV/O! Rot ROP #DIV/O! Slide % #DIV/O! Bit>Srvy 68.40 T/F Corr Plan Dls SPP On SPP Off Bit#4 GFXIVC Smith MN9839 9 7/8 1x123x18 1.00 1.00 6 5/8 Reg P 2 BIT SUB Ana DFS-AS-802 8 4 7/8 1.20 6 5/8 Reg B 2.28 3.28 4 1/2 IF B 3 24 Jnts HWDP 5" NAD 24HWDP 5 3 4 1/2 IF P 722.63 725.91 4 1/2 IF B 4 DP 5" to Surface NAD DP 5 4 1/4 4 1/2 IF P 725.91 4 1/2 IF B DryWt 36,167 IADC# 115 Motor Buoyed Wt 31,099 Footage Jars Inel Angle Hrs Bit #4 Buoy+lnel Wt 31,099 k Revs Grade GR= Comment I I Ver.10-03 Schlll_hlPgl' BHA# 5 Job # 40009833 Date In 05-Dec-03 Date Out 09-Dec-03 Hole Size 9 7/8 I Customer BP ADW Time In 3:00 Time Out 18:00 Hole Sect Intermeidate Well NS32i Depth In 3,980 Depth Out 8,121 Bha Type Steerable Field Northstar TVD In 3,266 TVD Out 6,512 HrsBRT 111.00 Rig Nabors 33E Drlg Hrs 50.7 Drlg Ft 4,141 Avg ROP 81.68 I AFE # NS D-831333 Slide Hrs 10.4 Slide Ft 586 Slide ROP 56.35 DD's TunnelllRinke Rot Hrs 40.3 Rot Ft 3,555 Rot ROP 88.21 Co. Men Vaughn I Holt Pump Hrs 78.9 Rotate % 86 Slide % 14 PDM Run # 3 R/S 7/8 PDM Jet Blk Inelln 42.28 Az In 32.13 Bit>Srvy 84.60 I PDM Ser# A800-3198 Stages 4.0 Bearing Mud InelOut 25.95 Az Out 32.15 TIFCorr 188.6 PDM Size 8 1/4 RevlGa/0.160 Rubber RM100D Avg Dls 2.0 Max Ds 3.1 Plan Dls 2.5 Mud Type Spud Mud Wt 9.0 Sand % .05 RPM 100 GPM 730 SPP On 2300 I BHT F 118 Mud Vis 45 Solids % 3.2 DIg TQ 18.0 WOB 30 SPP Off 2150 Bit#5 GFXIVC Smith MN9839 9 7/8 1x123x18 1.00 1.00 I TFA=.856 6 5/8 Reg P 2 81/4XPPDM1.15° Ana A800-3198 8 1/4 Tool 9 3/4 1.85 6 5/8 Reg B 27.64 28.64 Float 9 3/4 6 5/8 H90 B 3 X-OVER Ana STORS-HA-1059 6 1/2x7 7/8 2 7/8 1.40 6 5/8 H-90 P 2.30 30.94 I 4 1/2 IF B 4 XO Float Sub Ana STFLS-FA-504 6 7/8 3 1/2 4 1/2 IF P 1.63 32.57 41/2XH B 5 NM LEAD Ana 675-10-004LC 6 3/4 2 13/16 4 112 XH P 9.80 42.37 I 4 1/2 XH B 6 NM STABILIZER Ana NMSZSS-FA-004 6 3/4 2 7/8 9 7/8 2.42 41/2XHP 5.70 48.07 913/16 4 112 XH B 7 CDR Ana 7109 6 3/4 Tool 10.87 4 1/2 XH P 23.00 71.07 I 5 1/2 FH B 8 MWD Ana 712 6 3/4 Tool 1.50 5 1/2 FH P 28.82 99.89 4 1/2 XH B 9 NM STABILIZER Ana NMSZSS-FA-011 6 3/4 2 13/16 9 718 2.43 4 1/2 XH P 5.60 105.49 I 913/16 41/2XH B 10 NM Flex DC Ana NMFC-FA-018 611/16x5 2 13116 2.44 4 1/2 XH P 30.89 136.38 41/2XH B 11 NM Flex DC Ana NMFC-FA-027 6 3/4x5 1/16 2 13/16 2.52 4 1/2 XH P 31.01 167.39 I 4 1/2 XH B 12 NM Flex DC Ana NMFC-FA-025 6 5/8x5 1/8 2 13/16 2.52 4 1/2 XH P 31.02 198.41 4 1/2 XH B 13 xo Ana STXOS-FE-086 6 1/2 2 7/8 4 1/2 XH P 2.18 200.59 I 4 1/2 IF B 14 HYD JARS DAILEY 1416-1562 6 1/2 2 3/4 1.71 4 1/2 IF P 32.61 233.20 4 1/2 IF B 15 26 Jnts HWDP 5" NAD 26HWDP 5 3 4 1/2 IF P 781.86 1015.06 I 4 1/2 IF B 16 String reamer Jeatherfo 247986 6 1/2 2 13/16 9 7/8 2.50 4 1/2 IF P 6.97 1022.03 913/16 4 1/2 IF B I 17 Dart Valve Sub BPX CM7996 6 3/4 3 1/8x41/2 4 1/2 IF P 2.37 1024.40 4 1/2 IF B 18 DP 5" to Surface NAD DP 5 4 1/4 4 1/2 IF P 1024.40 4 1/2 IF B I I Drill ahead holding angle and direction to top of TMBK, then drop at 2.5/100 to 25 degrees, reach csg point DryWt 56,377 IADC# 115 Motor 0.0 78.9 while rotating Buoyed Wt 48,649 Footage 4,141 Jars 0.0 50.7 40' slides generated 2.5"/100 DLS Inel Angle 42 Hrs 50.7 Bit #4 0.0 50.7 I TO Buoy+/ne/ Wt 36,153 k Revs 597 k 78.9 Grade 3-3-WT-A-E-2-ER-TD GR=65.32, PWD=56.07 Comment I Schlumberger Public I I I Client: BP Exploration Alaska Field: Northstar structure: Northstar PF I Depth In: 201.00 Inclination In: 1.13 Azimuth In: 36.15 Comments: I Statistics: 1 Max I I I Bha 1 Slide Sheet BHAs: 1 Well: NS32 Borehole: Plan NS32 UWI/API#: Depth Out: 334.00 Inclination Out: 1.27 Azimuth Out: 37.31 Tot Distance: 133.00 SLIDE: 0.00 % SLIDE 0.0 ROTATE: 133.00 % ROTAT 100.0 Total Time: 0.6 Time: 0.0 0.6 ~lbl~I~lbl~I~I~I~1 0.600 201.00 334.00 133.00 222.0 420 I Orienting I Drilling I I Bit Time Method Duration Md From (hr) (hr) (ft) 0.200 ROTATE 0.200 201.00 0.600 ROTATE 0.400 243.00 I I I I I I I I I I I I NS32 Sha's.xls Avg 400 Avg 400 Md To I Course I Calc ROP TF MOdel TF Angle Flow I SPP Off Bot I SPP On Bot I WOB I (ft) (ft) (ft/h) (G/M) (0) (gal/min) (psi) (psi) (10001bf) 243.00 42.00 210.0 G 0.0 420 400 400 5.0 334.00 91.00 227.5 G 0.0 420 400 400 5.0 Schlumberger Public Page 1 01 1 Directional Driller: Rinke Directional Driller: Tunnell Job#: Avg 5.0 I ~~ I Total ROP: 221.7 ROTATE ROP: 221.7 Avg 1.5 I 3~0~0 I ~~~ Avg 36.73 Avg 0.38 RPM I Torque I Svy Md I Incl Azmth I DlS I (elmin) (1000 ft.lbl) (ft) (0) (0) (0 (100ft) 25 1.5 25 1.5 250.00 1.13 36.15 0.48 300.00 1.27 37.31 0.28 5/6/2004-10:42 AM I I Bha 2 Slide Sheet I BHA:2 Client: BP Exploration Alaska Well: NS32 Directional Driller: Rinke Field: Northstar Borehole: Plan NS32 Directional Driller: Tunnell Structure: Norths!ar PF UWl/API#: Job#: I Depth In: 334.00 Depth Out: 3980.00 Tot Distance: 3646.00 Total Time: 15.5 Total ROP: 235.2 Inclination In: 2.42 Inclination Out: 43.33 SLIDE: 1041.00 % SLIDE 28.6 SLIDE Time: 4.8 SLIDE ROP: 217.8 Azimuth In: 28.22 Azimuth Out: 32.67 ROTATE: 2605.00 % ROTAT 71.4 ROTATE Time: 10.7 ROTATE ROP: 243.0 Comments: I Statistics: I Max None I Sum I Min I Max I Sum I Avg I Max I Avg I Avg I Avg Avg Avg I Avg I Avg 139~~541 Avg Avg Avg 15.500 334.00 3980.00 3646.00 278.1 -6.0 685 1283 1483 19.8 40 7.9 34.34 32.40 1.93 I I I Orienting I Drilling I I Bit Time Method Duration Md From MdTo Course calc ROP TF MOdeTFAngle Flow SPP Off Bot SPPonBot WOB RPM I Torque I SvyMd I Incl Azmth I DLS I ~~ ~~ ffl) (It) (It) (fUh) (G/M) (0) (Qal/min) (psi) (psi) (1000Ibl) (clmin) (1000 It.lbl) (It) (0) (") (°/100 It) 0.100 ROTATE 0.100 334.00 368.00 34.00 340.0 G 0.0 630 900 900 5.0 40 2.0 I 0.260 SLIDE 0.160 368.00 418.00 50.00 312.5 M 25.0 630 900 910 5.0 0 0.0 400.00 2.42 28.22 1.18 0.390 ROTATE 0.130 418.00 458.00 40.00 307.7 M 0.0 620 900 950 5.0 40 2.0 0.570 SLIDE 0.180 458.00 508.00 50.00 277.8 M 29.0 620 950 1000 10.0 0 0.0 500.00 4.97 27.92 2.55 0.720 ROTATE 0.150 508.00 549.00 41.00 273.3 M 0.0 620 920 950 10.0 40 3.0 I 0.880 SLIDE 0.160 549.00 599.00 50.00 312.5 G 15.0 620 920 1000 10.0 0 0.0 1.100 ROTATE 0.220 599.00 638.00 39.00 177.3 G 0.0 620 950 1000 10.0 40 3.0 600.00 7.44 32.10 2.51 1.270 SLIDE 0.170 638.00 688.00 50.00 294.1 G 0.0 630 1000 1100 20.0 0 0.0 1.410 ROTATE 0.140 688.00 728.00 40.00 285.7 G 0.0 630 1000 1050 15.0 40 4.0 700.00 9.71 31.40 2.27 1.560 SLIDE 0.150 728.00 768.00 40.00 266.7 G 0.0 630 980 1050 20.0 0 0.0 I 1.730 ROTATE 0.170 768.00 818.00 50.00 294.1 G 0.0 630 980 1050 15.0 40 5.0 800.00 11.51 31.23 1.80 1.850 SLIDE 0.120 818.00 868.00 50.00 416.7 G -10.0 630 1100 1200 15.0 0 0.0 1.990 ROTATE 0.140 868.00 908.00 40.00 285.7 G 0.0 630 1100 1150 10.0 40 5.0 900.00 13.75 32.18 2.25 2.100 SLIDE 0.110 908.00 958.00 50.00 454.5 G 0.0 630 1050 1100 15.0 0 0.0 2.230 ROTATE 0.130 958.00 999.00 41.00 315.4 G 0.0 630 1050 1100 10.0 40 5.0 1000.00 15.40 34.25 1.73 I 2.350 SLIDE 0.120 999.00 1049.00 50.00 416.7 G 0.0 630 1050 1100 5.0 0 0.0 2.480 ROTATE 0.130 1049.00 1094.00 45.00 346.2 G 0.0 630 1100 1150 5.0 40 5.0 2.750 SLIDE 0.270 1094.00 1154.00 60.00 222.2 G -20.0 630 1100 1200 20.0 0 0.0 1100.00 16.84 32.74 1.50 3.040 ROTATE 0.290 1154.00 1189.00 35.00 120.7 G 0.0 630 1100 1200 20.0 40 5.0 I 3.390 SLIDE 0.350 1189.00 1260.00 71.00 202.9 G 0.0 630 1100 1350 30.0 0 0.0 1200.00 20.54 29.51 3.84 3.570 ROTATE 0.180 1260.00 1285.00 25.00 138.9 G 0.0 630 1100 1250 20.0 40 5.0 3.950 SLIDE 0.380 1285.00 1335.00 50.00 131.6 G 15.0 630 1100 1250 25.0 0 0.0 1300.00 24.13 30.85 3.63 4.330 ROTATE 0.380 1335.00 1380.00 45.00 118.4 G 0.0 630 1100 1250 15.0 40 5.0 I 4.630 SLIDE 0.300 1380.00 1435.00 55.00 183.3 G 15.0 730 1400 1600 25.0 0 0.0 1400.00 26.13 35.51 2.81 4.840 ROTATE 0.210 1435.00 1475.00 40.00 190.5 G 0.0 730 1400 1600 30.0 40 6.0 5.360 SLIDE 0.520 1475.00 1550.00 75.00 144.2 G 10.0 680 1250 1400 30.0 0 0.0 1500.00 28.75 3587 2.63 5.550 ROTATE 0.190 1550.00 1570.00 20.00 105.3 G 0.0 680 1250 1400 30.0 40 6.0 5.780 SLIDE 0.230 1570.00 1610.00 40.00 173.9 G 0.0 680 1250 1400 30.0 0 0.0 1593.00 33.42 42.33 6.16 I 5.960 ROTATE 0.180 1610.00 166600 56.00 311.1 G 0.0 680 1250 1400 20.0 40 6.0 6.060 SLIDE 0.100 1666.00 1696.00 30.00 300.0 G -20.0 680 1250 1400 20.0 0 0.0 1687.00 35.44 37.97 3.39 6.220 ROTATE 0.160 1696.00 1760.00 64.00 400.0 G 0.0 680 1250 1400 20.0 40 6.0 6.510 SLIDE 0.290 1760.00 1795.00 35.00 120.7 G -30.0 680 1250 1400 20.0 0 0.0 1788.80 37.44 34.57 2.79 I 6.680 ROTATE 0.170 1795.00 1855.00 60.00 352.9 G 0.0 680 1250 1400 30.0 40 6.0 6.930 SLIDE 0.250 1855.00 1885.00 30.00 120.0 G -30.0 680 1250 1400 20.0 0 0.0 1877.92 38.89 33.70 1.74 7.090 ROTATE 0.160 1885.00 1949.00 64.00 400.0 G 0.0 680 1250 1400 20.0 40 8.0 7.180 SLIDE 0.090 1949.00 1984.00 35.00 388.9 G -30.0 680 1250 1400 20.0 0 0.0 1973.57 40.37 32.17 1.85 I 7.380 ROTATE 0.200 1984.00 2045.00 61.00 305.0 G 0.0 680 1250 1400 20.0 40 8.0 7.560 SLIDE 0.180 2045.00 2080.00 35.00 194.4 G -20.0 680 1250 1400 20.0 0 0.0 2068.95 43.06 32.11 2.82 7.690 ROTATE 0.130 2080.00 2141.00 61.00 469.2 G 0.0 680 1300 1450 20.0 40 8.0 7.830 SLIDE 0.140 2141.00 2176.00 35.00 250.0 G -30.0 680 1300 1450 20.0 0 0.0 2165.44 45.01 31.85 2.03 8.030 ROTATE 0.200 2176.00 2236.00 60.00 300.0 G 0.0 680 1300 1450 20.0 40 8.0 I 8.340 ROTATE 0.310 2236.00 2332.00 96.00 309.7 G 0.0 700 1400 1550 20.0 40 8.0 2260.93 45.07 35.99 3.07 8.440 SLIDE 0.100 2332.00 2362.00 30.00 300.0 G -90.0 700 1400 1550 20.0 0 0.0 2355.54 45.24 28.99 5.25 8.580 ROTATE 0.140 2362.00 2427.00 65.00 464.3 G 0.0 700 1400 1550 20.0 40 8.0 8.820 ROTATE 0.240 2427.00 2522.00 95.00 395.8 G 0.0 720 1500 1650 20.0 40 8.0 2451.28 44.70 29.18 0.58 I 9.121 ROTATE 0.301 2522.00 2617.00 95.00 315.6 G 0.0 720 1500 1650 20.0 40 8.0 2548.74 44.42 29.05 0.30 9.490 ROTATE 0.369 2617.00 2713.00 96.00 260.2 G 0.0 720 1500 1650 20.0 40 8.0 2644.00 44.05 29.44 0.48 9.800 ROTATE 0.310 2713.00 2809.00 96.00 309.7 G 0.0 720 1500 1650 20.0 40 8.0 2736.58 43.33 30.12 0.93 10.040 SLIDE 0.240 2809.00 2849.00 40.00 166.7 G 15.0 750 1550 1850 35.0 0 0.0 2831.27 45.75 31.07 2.65 10.200 ROTATE 0.160 2849.00 2904.00 55.00 343.8 G 0.0 730 1550 1800 20.0 40 10.0 I 10.600 ROTATE 0.400 2904.00 2999.00 95.00 237.5 G 0.0 720 1650 1850 20.0 40 100 2926.69 46.52 31.98 1.06 I Schlumberger Public NS32 Bha's.xls Page 1 012 5/6/2004-10:43 AM I I I I Orienting I Drilling Bit Time Method Duration Md From (hr) (hr) (II) 10.790 ROTATE 0.190 2999.00 11.200 ROTATE 0.410 3095.00 11.370 SLIDE 0.170 3191.00 11.730 ROTATE 0.360 3221.00 MdTo I Course Calc ROP TF MOde TFAngle Flow SPPOffBotSPPonBot WOB I RPM I Torque I SvyMd (II) (II) (fUh) (G/M) (0) (gal/min) (psi) (psi) (1000Ibf) (c/min) (1000Il.lbf) (II) 3095.00 96.00 505.3 G 0.0 720 1700 1900 20.0 40 10.0 3023.07 3191.00 96.00 234.1 G 0.0 720 1700 1900 20.0 40 10.0 3121.95 3221.00 30.00 176.5 G 180.0 730 1650 1900 40.0 0 0.0 3216.71 3286.00 65.00 180.6 G 0.0 730 1650 1850 20.0 40 10.0 Incl (0) 46.80 47.46 44.98 Azmth I DLS I (0) (°/100 II) 31.67 0.37 32.54 0.93 32.81 2.63 I I 12.200 ROTATE 0.470 3286.00 3381.00 95.00 202.1 G 0.0 720 1600 1700 20.0 3309.14 44.15 32.65 0.91 12.480 ROTATE 0.280 3381.00 3476.00 95.00 339.3 G 0.0 720 1600 1750 20.0 40 10.0 3403.18 44.47 32.64 0.34 12.760 ROTATE 0.280 3476.00 3572.00 96.00 342.9 G 0.0 720 1600 1750 15.0 40 10.0 3499.30 44.22 32.36 0.33 13.110 ROTATE 0.350 3572.00 3667.00 95.00 271.4 G 0.0 720 1600 1750 20.0 40 10.0 3594.81 43.82 32.92 0.58 13.480 ROTATE 0.370 3667.00 3761.00 94.00 254.1 G 0.0 720 1600 1750 20.0 40 10.0 3688.34 43.93 32.29 0.48 14.320 ROTATE 0.840 3761.00 3857.00 96.00 114.3 G 0.0 720 1600 1750 30.0 40 10.0 3784.70 44.01 33.16 0.63 3878.03 43.59 33.33 0.47 15.190 ROTATE 0.870 3857.00 3950.00 93.00 106.9 G 0.0 720 1600 1750 30.0 40 10.0 3908.54 43.33 32.67 1.71 15.500 ROTATE 0.310 395000 3980.00 30.00 96.8 G 0.0 720 1600 1750 30.0 40 10.0 I I I I I I I I I I I I I I NS32 Bha's.xls Schlumberger Public Page 2 of 2 5/6/2004-10:43 AM I I NS·32 Slide Sheet Slide Sheet I BHA: Bha #5 (9.875") Client: BP Exploration Alaska Well: NS32 Directional Driller: James Tunnell Field: Northstar Borehole: Plan NS32 Directional Driller: Marty Rinke Structure: Northstar PF UWUAPI#: Job #: 40009833 I Depth In: 3980.00 Depth Out: 8121.00 Tot Distance: 4099.00 Total Time: 50.7 Total ROP: 80.8 Inclination In: 42.26 Inclination Out: 25.95 SLIDE: 586.00 % SLIDE 14.3 SLIDE Time: 10.4 SLIDE ROP: 56.4 Azimuth In: 32.99 Azimuth Out: 32.15 ROTATE: 3513.00 % ROT AT 85.7 ROTATE Time: 40.3 ROTATE ROP: 87.1 I Comments: Statistics: I I None I Min I Max I Sum I Avg I Avg I Max I Avg I Avg Avg Avg I Avg I Avg 180~~0 I Avg Avg 3980.00 8121.00 4099.00 145.4 -177.5 732 1722 1943 32.4 97 13.4 37.68 32.37 I Orienting I I Md To I Course I Calc ROP I TF Angle I TF Mode I Flow I SPP Off Bot I SPP On Bot I WOB I I Method Md (~om RPM I Torque I Svy Md I Incl Azmth (ft) (ft) (ftIh) (0) (G/M) (gallmin) (psi) (psi) (1000Ibf) (c/min) (1000 ft.lbf) (ft) ¡O) (0) ROTATE 3980.00 4000.00 20.00 74.1 0.0 G 580 1000 1100 20.0 40 10.0 ROTATE 4000.00 4037.00 37.00 1233 0.0 G 750 1450 1600 25.0 55 11.0 ROTATE 4037.00 4131.00 94.00 164.9 0.0 G 750 1450 1650 25.0 60 10.0 4042.79 42.26 32.99 I SLIDE 4131.00 4161.00 30.00 300.0 0.0 G 750 1450 1550 35.0 0 0.0 4135.87 42.71 35.09 ROTATE 4161.00 4225.00 64.00 400.0 0.0 G 750 1500 1650 20.0 60 10.0 ROTATE 4225.00 4320.00 95.00 4130 0.0 G 750 1500 1650 20.0 100 11.0 4231.33 42.91 33.84 SLIDE 4320.00 4370.00 50.00 185.2 -10.0 G 750 1500 1650 45.0 0 0.0 4325.25 44.14 31.95 I ROTATE 4370.00 4414.00 44.00 200.0 0.0 G 750 1500 1650 25.0 100 11.0 ROTATE 4414.00 4510.00 96.00 152.4 0.0 G 750 1500 1700 30.0 100 12.0 4420.36 46.14 31.14 ROTATE 4510.00 4602.00 92.00 148.4 0.0 G 750 1500 1700 30.0 100 12.0 4514.00 45.79 30.75 I ROTATE 4602.00 4695.00 9300 310.0 0.0 G 750 1500 1700 30.0 100 12.0 4608.46 45.15 30.98 ROTATE 4695.00 4791.00 96.00 157.4 0.0 G 750 1500 1700 30.0 100 11.0 4701.83 44.64 30.76 ROTATE 4791.00 4885.00 94.00 223.8 0.0 G 750 1600 2000 30.0 100 10.0 4796.18 44.30 31.10 ROTATE 4885.00 4980.00 95.00 202.1 0.0 G 750 1600 2000 30.0 100 12.0 4890.94 43.99 31.90 ROTATE 4980.00 5074.00 94.00 391.7 0.0 G 720 1550 1700 30.0 100 12.0 4985.47 43.63 31.02 I ROTATE 5074.00 5167.00 93.00 178.8 0.0 G 720 1550 1700 30.0 100 12.0 5078.76 43.67 30.59 ROTATE 516700 5262.00 95.00 527.8 0.0 G 720 1650 1750 30.0 100 12.0 5173.84 4355 30.26 SLIDE 5262.00 5302.00 40.00 210.5 45.0 G 720 1650 1770 45.0 0 0.0 5267.96 44.75 30.73 I ROTATE 5302.00 5356.00 54.00 385.7 0.0 G 720 1650 1800 30.0 100 13.0 ROTATE 5356.00 5450.00 94.00 254.1 0.0 G 720 1650 1750 30.0 100 13.0 5362.31 45.89 31.93 ROTATE 5450.00 5543.00 93.00 258.3 0.0 G 720 1550 1750 30.0 100 130 5455.68 45.81 31.33 ROTATE 5543.00 5638.00 95.00 93.1 0.0 G 720 1650 1850 45.0 100 13.0 5551.25 45.81 30.14 I SLIDE 5638.00 5668.00 30.00 33.3 90.0 G 720 1650 1750 45.0 0 0.0 5643.95 46.20 31.99 ROTATE 5668.00 5732.00 64.00 145.5 0.0 G 720 1650 1750 30.0 100 130 ROTATE 5732.00 5826.00 94.00 218.6 0.0 G 720 1650 1750 30.0 100 13.0 5738.05 45.45 32.44 ROTATE 5826.00 5921.00 95.00 61.3 0.0 G 730 1750 2100 30.0 100 13.0 5832.29 45.55 32.00 I ROTATE 5921.00 6016.00 95.00 43.8 0.0 G 730 1750 2100 30.0 100 13.0 5928.53 45.58 32.44 SLIDE 6016.00 6026.00 10.00 31.3 170.0 G 730 1750 2050 65.0 0 0.0 6023.86 44.92 32.00 ROTATE 6026.00 6035.00 9.00 32.1 0.0 G 730 1750 2100 30.0 100 13.0 SLIDE 6035.00 6048.00 13.00 21.3 170.0 G 730 1750 1950 55.0 0 0.0 I ROTATE 6048.00 6111.00 63.00 48.1 0.0 G 730 1750 2050 30.0 100 13.0 SLIDE 6111.00 6131.00 20.00 50.0 170.0 G 730 1750 2050 55.0 0 0.0 6117.78 43.93 32.94 ROTATE 6131.00 620700 76.00 59.8 0.0 G 730 1750 2050 30.0 100 130 SLIDE 6207.00 6247.00 40.00 42.6 180.0 G 730 1750 2000 55.0 0 0.0 6213.02 42.40 34.10 I ROTATE 6247.00 6303.00 56.00 147.4 0.0 G 730 1750 2050 30.0 100 13.0 SLIDE 6303.00 6332.00 29.00 93.5 180.0 G 730 1750 2000 55.0 0 0.0 6307.88 40.24 34.39 ROTATE 6332.00 6396.00 64.00 128.0 0.0 G 730 1750 2050 30.0 100 13.0 SLIDE 6396.00 6403.00 7.00 29.2 -170.0 G 730 1750 1950 50.0 0 0.0 I ROTATE 6403.00 6419.00 16.00 38.1 0.0 G 730 1750 2050 30.0 100 15.0 6403.61 38.99 34.24 SLIDE 6419.00 6443.00 24.00 30.8 180.0 G 730 1750 2050 65.0 0 0.0 ROTATE 644300 6461.00 18.00 47.4 0.0 G 730 1750 2000 30.0 100 15.0 I SLIDE 6461.00 6474.00 13.00 38.2 180.0 G 730 1750 2050 50.0 0 0.0 ROTATE 6474.00 6492.00 18.00 45.0 0.0 G 730 1750 2000 30.0 100 130 I NS32 Bha's.xls Page 1 of 2 5/6/2004-10:43 AM I I I Orienting I I Method Md (~om Md To I Course I Cale ROP I TF Angle I TF Mode I Flow I SPP Off Bot I SPP On Bot I WOB I RPM I Torque I Svy Md I Inel I Azmth I I (ft) (ft) (ftIh) ¡O) (G/M) (gal/min) (psi) (psi) (1000Ibf) (e/min) (1000 ft.lbf) (ft) (0) (0) SLIDE 6492.00 6532.00 40.00 76.9 180.0 G 730 1750 2100 50.0 0 0.0 649920 3605 34.60 ROTATE 6532.00 6588.00 56.00 54.9 0.0 G 730 1750 2000 30.0 100 14.0 SLIDE 6588.00 6628.00 40.00 148.1 -150.0 G 730 1750 1950 40.0 0 0.0 6592.81 34.63 34.63 I ROTATE 6670.00 6682.00 12.00 20.7 0.0 G 730 1750 2000 30.0 100 15.0 SLIDE 6682.00 6722.00 40.00 137.9 -150.0 G 730 1750 2050 50.0 0 0.0 6688.03 32.73 32.97 ROTATE 6722.00 6777.00 55.00 94.8 0.0 G 730 1750 2150 30.0 100 14.0 SLIDE 6777.00 6810.00 33.00 117.9 180.0 G 730 1800 1900 50.0 0 0.0 6781.57 3190 32.96 I ROTATE 6810.00 6820.00 10.00 30.3 0.0 G 730 1800 2150 30.0 100 13.0 SLIDE 6820.00 6835.00 15.00 22.7 150.0 G 730 1800 1900 45.0 0 0.0 ROTATE 6835.00 6877.00 42.00 35.6 0.0 G 730 1800 2000 30.0 100 14.0 SLIDE 6877.00 6901.00 24.00 42.9 180.0 G 730 1800 2150 50.0 0 0.0 6878.86 29.78 33.57 I ROTATE 6901.00 6912.00 11.00 39.3 0.0 G 730 1800 2150 30.0 100 14.0 SLIDE 6912.00 6922.00 10.00 28.6 180.0 G 730 1800 2150 50.0 0 0.0 ROTATE 6922.00 6929.00 7.00 24.1 0.0 G 730 1800 2150 30.0 100 14.0 SLIDE 6929.00 6940 00 11.00 24.4 -170.0 G 730 1800 50.0 0 0.0 I ROTATE 6940.00 6967.00 27.00 39.7 0.0 G 730 1800 2100 30.0 100 14.0 SLIDE 6967.00 7017.00 50.00 41.0 -160.0 G 730 1800 2100 50.0 0 0.0 6975.05 26.79 34.22 ROTATE 7017.00 7063.00 46.00 52.9 0.0 G 730 1800 30.0 100 14.0 I ROTATE 7063.00 7130.00 67.00 54.5 0.0 G 730 1800 2100 30.0 100 15.0 7070.33 24.85 33.73 ROTATE 7130.00 7158.00 28.00 133.3 0.0 G 730 1800 2100 30.0 100 15.0 SLIDE 7158.00 7175.00 17.00 43.6 -90.0 G 730 1900 2150 50.0 0 0.0 7165.95 25.12 32.44 ROTATE 7175.00 7254.00 79.00 41.8 0.0 G 730 1900 2200 30.0 100 15.0 I ROTATE 7254.00 7349.00 95.00 41.3 0.0 G 730 1900 2200 30.0 100 15.0 7260 52 25.07 32.08 ROTATE 7349.00 7444.00 95.00 60.5 0.0 G 730 1900 2200 30.0 100 15.0 7355.63 25.37 32.78 ROTATE 7444.00 7539.00 95.00 62.5 0.0 G 730 2000 2150 30.0 100 16.0 7451.05 25.38 32.00 ROTATE 7539.00 7635.00 96.00 50.3 0.0 G 730 2000 2150 30.0 100 16.0 7546.03 25.71 32.27 I ROTATE 7635.00 7731.00 96.00 109.1 0.0 G 730 2000 2150 30.0 100 16.0 7642.73 25.54 31.88 ROTATE 7731.00 7826.00 95.00 58.3 0.0 G 730 2000 2150 30.0 100 16.0 7738.30 25.62 32.04 ROTATE 7826.00 7921.00 95.00 70.9 0.0 G 730 2000 2150 30.0 100 16.0 7833.00 25.70 32.28 ROTATE 7921.00 8017.00 96.00 65.3 0.0 G 730 2100 2300 30.0 100 17.0 7929.99 25.73 32.37 I ROTATE 8017.00 8121.00 104.00 74.8 0.0 G 730 2100 2300 30.0 100 18.0 8035.10 25.95 32.15 I I I I I I I I NS32 Bha's.xls Page 2 of 2 5/6/2004-10:43 AM ------------------- sperry-sun DRILLING SERVICES BHA# Bit Record 1 2 5 8 Bit No. 1 RR1 5 6 Bit Type MX-C1 MX-C1 GFXIVC XR+ 1llleJlU:..:r.Jl Customer: BP EXPLORATION ALASKA Well: NS32 Area: BEAUFORT SEA,ALASKA Lease: NORTHST AR Rig: NABORS DRLG RIG 33E Mud Company: BAROID Job No.: AK-AM 22163 / AK-AM 2775313 IJ."JIIIU UL-rIJ[ :~~:..J'JIIIJ W Casing Program 20 10.75 75/8" 4.5 mr l.~::"': n. inch at inch at inch at inch at inch at inch at 201 3960 8105 ft ft ft ft ft ft Serial Size TFA Depth Depth Feet Hours ROP RPM KREV Slide Number In Out ftlhr % GRADE 5037998 13.5 0.856 201 334 133 0.6 221.7 25 4 0 USE NEXT BHÄ 5037998 13.5 0.856 334 3980 3646 10.7 243.5 40 174 29 1-1-WT-Ä-E-1-NO-TD MN9839 9.875 0.856 3980 8121 4141 50.7 40.3 81.68 476 14 553-3-WT-Ä-E-2-ER-TD MP4441 6.75 0.518 8121 8321 200 2.8 77 118 22.7 0 - - - - - - - - - - - - - - - - - - - Customer: BP ALASKA Casing Program 20" inch at 201 ft sperry-sun Well: NORTHSTAR NS32 10 3/4 inch at 3960 ft Area: BEAUFORT SEA, ALASKA 75/8 inch at 8105 ft Lease: NORTHSTAR 4.5" inch at 8321 ft DRILLING SERVICES Rig: NABORS DRILLING RIG 33E inch at ft Mud Company: BAROID DRILLING FLUIDS inch at ft Waterbase Mud Record Job No.: AK-AM 0002775313 Depth MW Vis PV YP Gels Fltr HTHP Cake 501 Oil Water 5d CEC pH Pm I PtI Mf Chlorides Calcium Comments Date ft Ib/gal sec LB/100 105/10M ml/30 ml@deg F 32's % % % % mgefhg ppm ppm 11/14/UJ U j,ll 1UII 111 411 1;¿/1ti/111 111.U ;¿ J.4 U.U !:Iti.b U.UU ;¿.U II.;¿ U.UU U.UUI.ti 111UUU f;¿U '1VIovmg Klg 11/15/UJ J;¿4 11.7 11ti 1f ti1 ;¿4/JU/J5 1ti.4 J ;¿.5 U.U !:I7.5 U.1U 1.U II.!:I U.15 U.1U/1.;¿U 15UUU JUU "IJrllllng 11/1ti/UJ ;¿1I1I4 !:I. 1 117 111 45 ;¿U/J;¿/4U 1U.U ;¿ 5.5 U.U !:I4.5 U.f5 7.U !:I. 1 U.;¿U U.15/U.!:IU 17UUU 411U "IJrullng U/U5/UJ 4UUU lI.ti 5J !:I 1f tiff/II 15.;¿ 1 1.7 U.U !:III.J U.UU !:I.f U.UU U.;¿5/U.75 1!:1UUU 5;¿U "IJrllllng U/Ub/UJ tiUUII 11.11 4b 1U ;¿ti 1U/14 5.5 1 J.;¿ U.U !:Ib.1I U.U5 ;¿.II !:I.U U.UU U.;¿U/U.7U 1!:1UUU 5;¿U "IJrllllng U/U fIUJ fU11 11.11 4J 1U ;¿J 1U/1J/15 ti.U 1 J.J U.;¿ !:Iti.f U.U5 J.II !:I.U U.UU U.1U/U.5U 111UUU 5;¿U "IJ rill mg U/UII/UJ f!:lti4 !:I.U 45 11 ;¿4 !:I/1J/15 ti.U 1 4.4 U.;¿ !:I5.b U.U5 ti.U II.!:I U.UU U.U5/U.J5 111UUU 5;¿U "IJrllllng U4/;¿II/U4 111;¿1 !:I.II ;¿II U U U/U/U U.U U U.U U.U !:IU.U U U.U U.U U.UU U/U 15UUUU U "IVIove rig U4/;¿!:I/U4 IIJ;¿1 !:I.II ;¿II U U U/U/U U.U U 1.f U.U 1I!:I.ti U U.U U.U U.UU U/U 15UUUU U IU ------------------- Final_survey_Ns32i .TXT SCHLUMBERGER Survey report client...... ......... ....: BP Exploration (Alaska) Inc. Field....................: Northstar well. . . . . . . . . . . . . . . . . . . . .: NS32i API number. ..... ..... ....: 50-029-23179-00 Engineer... ........... ...: T. webster Ri g: . . . . . . . . . . . . . . . . . . . . .: Nabors 33E STATE: . . . . . . . . . . . . . . . . . . .: Alaska ----- survey calculation methods------------- Method for positions. ....: Minimum curvature Method for DLS....... ....: Mason & Taylor ----- Depth reference ----------------------- permanent datum..... .....: Mean Sea Level Depth reference...... ....: Drill Floor GL above permanent. ......: 15.90 ft KB above permanent.......: NA DF above permanent.......: 55.95 ft ----- vertical section origin---------------- Latitude (+N/S-).........: 0.00 ft Departure (+E/W-)...... ..: 0.00 ft ----- Platform reference point--------------- Latitude (+N/S-).........: -999.25 ft Departure (+E/W-).. ......: -999.25 ft Azimuth from rotary table to target: 32.59 degrees [(c)2004 IDEAL ID8_1C_02] Page 1 29-Apr-2004 09:25:11 spud date................: Last survey date...... ...: Total accepted surveys...: MD of first survey.... ...: MD of last survey..... ...: Page 1 of 5 15-Nov-2003 29-Apr-04 92 0.00 ft 8321. 00 ft Geomagnetic data ---------------------- Magnetic model....... ....: BGGM version 2003 Magnetic date............: 27-Apr-2004 Magnetic field strength..: 1152.06 HCNT Magnetic dec (+E/W-).....: 25.38 degrees Magnetic dip.............: 80.99 degrees ----- MWD survey Reference Reference G............ ..: Reference H............ ..: Reference Dip.......... ..: Tolerance of G........ ...: Tolerance of H. ....... ...: Tolerance of Dip.........: Criteria --------- 1002.69 mGal 1151. 79 HCNT 80.99 degrees (+/-) 2.50 mGal (+/-) 6.00 HCNT (+/-) 0.45 degrees ----- Corrections --------------------------- Magnetic dec (+E/W-)... ..: 25.38 degrees Grld convergence (+E/W-).: 0.00 degrees Total az corr (+E/W-). ...: 25.38 degrees (Total az corr = magnetic dec - grid conv) survey Correction Type...: I=Sag Corrected Inclination M=schlumberger Magnetic Correction S=Shell Magnetic Correction F=Failed Axis Correction R=Magnetic Resonance Tool Correction D=Dmag Magnetic Correction ------------------- Final_survey_Ns32i.TXT SCHLUMBERGER survey Report 29-Apr-2004 09:25:11 page 2 of 5 --- -------- ------ ------- ------ -------- -------- ---------------- --------------- -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ ------ seq Measured Incl Azimuth Course TVD Vertical Displ Displ Tota 1 At DLS srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool Corr (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) --- -------- ------ ------- ------ -------- -------- ---------------- --------------- -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ ------ 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 TIP None 2 50.00 0.44 38.47 50.00 50.00 0.19 0.15 0.12 0.19 38.47 0.88 GYR None 3 100.00 0.59 25.95 50.00 100.00 0.64 0.53 0.35 0.64 33.45 0.37 GYR None 4 150.00 0.92 35.54 50.00 149.99 1.29 1.09 0.70 1.29 32.61 0.70 GYR None 5 200.00 0.89 36.13 50.00 199.99 2.08 1. 73 1.16 2.08 33.83 0.06 GYR None 6 250.00 1.13 36.15 50.00 249.98 2.96 2.44 1. 68 2.96 34.52 0.48 GYR None 7 300.00 1. 27 37.31 50.00 299.97 4.01 3.28 2.31 4.01 35.10 0.28 GYR None 8 400.00 2.42 28.22 100.00 399.91 7.22 6.02 3.98 7.22 33.43 1.18 GYR None 9 500.00 4.97 27.92 100.00 499.70 13.64 11.71 7.00 13 .65 30.88 2.55 GYR None 10 600.00 7.44 32.10 100.00 599.11 24.43 21. 03 12.47 24.45 30.68 2.51 GYR None 11 700.00 9.71 31.40 100.00 697.98 39.34 33.71 20.31 39.35 31.07 2.27 GYR None 12 800.00 11.51 31. 23 100.00 796.27 57.75 49.44 29.88 57.77 31.14 1.80 GYR None 13 900.00 13.75 32.18 100.00 893.84 79.61 68.03 41. 38 79.63 31. 31 2.25 GYR None 14 1000.00 15.40 34.25 100.00 990.62 104.77 89.07 55.18 104.78 31. 78 1. 73 GYR None 15 1100.00 16.84 32.74 100.00 1086.69 132.53 112.23 70.49 132.53 32.13 1. 50 GYR None 16 1200.00 20.54 29.51 100.00 1181. 40 164.54 139.69 86.97 164.55 31. 91 3.84 GYR None Page 2 ------------------- Final_survey_Ns32i.TXT 17 1300.00 24.13 30.85 100.00 1273.88 202.50 172 .52 106.10 202.53 31. 59 3.63 GYR None 18 1400.00 26.13 35.51 100.00 1364.42 244.93 208.00 129.38 244.95 31. 88 2.81 GYR None 19 1500.00 28.75 35.87 100.00 1453.16 290.94 245.42 156.26 290.94 32.49 2.63 GYR None 20 1593.00 33.42 42.33 93.00 1532.81 338.55 282.51 186.64 338.59 33.45 6.16 GYR None 21 1687.00 35.44 37.97 94.00 1610.35 391. 21 323.14 220.85 391. 40 34.35 3.39 GYR None 22 1788.80 37.44 34.57 101.80 1692.25 451. 53 371. 89 256.57 451. 81 34.60 2.79 G-MAG None 23 1877.92 38.89 33.70 89.12 1762.32 506.58 417.48 287.47 506.88 34.55 1. 74 G-MAG None 24 1973.57 40.37 32.17 95.65 1835.99 567.58 468.68 320.62 567.86 34.38 1.85 G-MAG None 25 2068.95 43.06 32.11 95.38 1907.18 631.04 522.42 354.38 631.28 34.15 2.82 G-MAG None 26 2165.44 45.01 31. 85 96.49 1976.54 698 . 11 579.31 389.90 698.30 33.94 2.03 G-MAG None 27 2260.93 45.07 35.99 95.49 2044.03 765.63 635.36 427.59 765.84 33.94 3.07 G-MAG None 28 2355.54 45.24 28.99 94.61 2110.79 832.62 691. 87 463.58 832.82 33.82 5.25 G-MAG None 29 2451. 28 44.70 29.18 95.74 2178.52 900.16 751. 00 496.47 900.27 33.47 0.58 G-MAG None 30 2548.74 44.42 29.05 97.46 2247.97 968.42 810.74 529.74 968.47 33.16 0.30 G-MAG None [(c)2004 IDEAL ID8_1C_02] SCHLUMBERGER Survey Report 29-Apr-2004 09:25:11 page 3 of 5 --- -------- --- -------- (deg) ------ ------- ------ -------- -------- ---------------- --------------- ------ ------- ------ -------- -------- ---------------- --------------- Incl Azimuth Course TVD Verti cal Displ Di sp 1 Total At DLS srvy angle angle length depth section +N/S- +E/W- di spl Azim (deg/ tool (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type ------ ------ seq Measured Tool # depth Corr (ft) --- -------- ------ ------- ------ -------- -------- ---------------- --------------- --- -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ ------ Page 3 -------------------- Final_survey_NS32i .TXT 31 2644.00 44.05 29.44 95.26 2316.22 1034.76 868.73 562.20 1034.77 32.91 0.48 G-MAG None 32 2736.58 43.33 30.12 92.58 2383.16 1098.63 924.23 593.96 1098.63 32.73 0.93 G-MAG None 33 2831. 27 45.75 31.07 94.69 2450.65 1165.00 981.39 627.77 1165.00 32.61 2.65 G-MAG None 34 2926.69 46.52 31. 98 95.42 2516.77 1233.78 1040.03 663.75 1233.78 32.55 1.06 G-MAG None 35 3023.07 46.80 31.67 96.38 2582.92 1303.87 1099.59 700.71 1303.87 32.51 0.37 G-MAG None 36 3121. 95 47.46 32.54 98.88 2650.19 1376.34 1160.97 739.23 1376.34 32.49 0.93 G-MAG None 37 3216.71 44.98 32.81 94.76 2715.75 1444.75 1218.56 776.16 1444.75 32.50 2.63 G-MAG None 38 3309.14 44.15 32.65 92.43 2781. 60 1509.61 1273.12 811. 23 1509.61 32.51 0.91 G-MAG None 39 3403.18 44.47 32.64 94.04 2848.89 1575.30 1328.43 846.66 1575.30 32.51 0.34 G-MAG None 40 3499.30 44.22 32.36 96.12 2917.63 1642.48 1385.10 882.76 1642.48 32.51 0.33 G-MAG None 41 3594.81 43.82 32.92 95.51 2986.32 1708.85 1440.98 918.56 1708.85 32.52 0.58 G-MAG None 42 3688.34 43.93 32.29 93.53 3053.74 1773.68 1495.59 953.49 1773.68 32.52 0.48 G-MAG None 43 3784.70 44.01 33.16 96.36 3123.09 1840.58 1551. 87 989.65 1840. 58 32.53 0.63 G-MAG None 44 3878.03 43.59 33.33 93.33 3190.45 1905.17 1605.90 1025.07 1905.17 32.55 0.47 G-MAG None 45 3908.54 43.33 32.67 30.51 3212.60 1926.16 1623.50 1036.50 1926.16 32.56 1. 71 G-MAG None 46 4042.79 42.26 32.99 134.25 3311.11 2017.36 1700.14 1085.94 2017.36 32.57 0.81 G-MAG None 47 4135.87 42.71 35.09 93.08 3379.75 2080.20 1752.22 1121.13 2080.20 32.61 1.60 G-MAG None 48 4231.33 42.91 33.84 95.46 3449.78 2145.03 1805.71 1157.84 2145.03 32.67 0.91 G-MAG None 49 4325.25 44.14 31.95 93.92 3517.88 2209.70 1860.02 1192.95 2209.71 32.67 1. 91 G-MAG None 50 4420.36 46.14 31.14 95.11 3584.97 2277 .10 1917.47 1228.21 2277 .11 32.64 2.19 G-MAG None 51 4514.00 45.79 30.75 93.64 3650.06 2344.40 1975.21 1262.83 2344.40 32.59 0.48 G-MAG None 52 4608.46 45.15 30.98 94.46 3716.30 2411.70 2033 . 01 1297.38 2411. 70 32.54 0.70 G-MAG None Page 4 ------------------- Final_survey_Ns32i.TXT 53 4701. 83 44.64 30.76 93.37 3782.44 2477 .58 2089.58 1331.19 2477 .58 32.50 0.57 G-MAG None 54 4796.18 44.30 31.10 94.35 3849.77 2543.64 2146.27 1365.16 2543.65 32.46 0.44 G-MAG None 55 4890.94 43.99 31.90 94.76 3917.77 2609.63 2202.54 1399.65 2609.64 32.43 0.67 G-MAG None 56 4985.47 43.63 31.02 94.53 3985.99 2675.05 2258.36 1433.80 2675.07 32.41 0.75 G-MAG None 57 5078.76 43.67 30.59 93.29 4053.49 2739.42 2313.67 1466.78 2739.44 32.37 0.32 G-MAG None 58 5173.84 43.55 30.26 95.08 4122.33 2804.95 2370.22 1499.99 2804.98 32.33 0.27 G-MAG None 59 5267.96 44.75 30.73 94.12 4189.87 2870.46 2426.71 1533.26 2870.50 32.29 1. 32 G-MAG None 60 5362.31 45.89 31. 93 94.35 4256.21 2937.53 2484.01 1568.14 2937.58 32.26 1. 51 G-MAG None [(c)2004 IDEAL ID8_1C_02] SCHLUMBERGER survey Report 29-Apr-2004 09:25:11 Page 4 of 5 --- -------- ------ ------- ------ -------- -------- ---------------- --------------- -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ ------ seq Measured Incl Azimuth Course TVD Vertical Di sp 1 Displ Tota 1 At DLS Srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool Corr (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) --- -------- ------ ------- ------ -------- -------- ---------------- --------------- -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ ------ 61 5455.68 45.81 31. 33 93.37 4321. 24 3004.52 2541. 05 1603.28 3004.57 32.25 0.47 G-MAG None 62 5551. 25 45.81 30.14 95.57 4387.86 3073.00 2599.95 1638.30 3073.07 32.22 0.89 G-MAG None 63 5643.95 46.20 31.99 92.70 4452.25 3139.66 2657.07 1672.71 3139.74 32.19 1. 50 G-MAG None 64 5738.05 45.45 32.44 94.10 4517.83 3207.15 2714.17 1708.69 3207.23 32.19 0.87 G-MAG None 65 5832.29 45.55 32.00 94.24 4583.88 3274.37 2771. 03 1744.53 3274.44 32.19 0.35 G-MAG None 66 5928.53 45.58 32.44 96.24 4651. 26 3343.08 2829.17 1781.16 3343.16 32.19 0.33 G-MAG None Page 5 ------------------- Final_surveY_NS32i.TXT 67 6023.86 44.92 32.00 95.33 4718.37 3410.78 2886.44 1817.26 3410.86 32.19 0.77 G-MAG None 68 6117.78 43.93 32.94 93.92 4785.45 3476.52 2941.91 1852.55 3476.60 32.20 1. 27 G-MAG None 69 6213.02 42.40 34.10 95.24 4854.91 3541. 66 2996.23 1888.52 3541. 74 32.22 1. 81 G-MAG None 70 6307.88 40.24 34.39 94.86 4926.15 3604.27 3048.00 1923.76 3604.33 32.26 2.29 G-MAG None 71 6403.61 38.99 34.24 95.73 4999.89 3665.28 3098.42 1958.17 3665.33 32.29 1.31 G-MAG None 72 6499.20 36.05 34.60 95.59 5075.70 3723.46 3146.44 1991.07 3723.50 32.33 3.08 G-MAG None 73 6592.81 34.63 34.63 93.61 5152.06 3777.57 3191. 00 2021.83 3777.60 32.36 1. 52 G-MAG None 74 6688.03 32.73 32.97 95.22 5231.30 3830.36 3234.86 2051. 22 3830.38 32.38 2.22 G-MAG None 75 6781. 57 31.90 32.96 93.54 5310.35 3880.36 3276.82 2078.42 3880.38 32.39 0.89 G-MAG None 76 6878.86 29.78 33.57 97.29 5393.88 3930.23 3318.52 2105.77 3930.25 32.40 2.20 G-MAG None 77 6975.05 26.79 34.22 96.19 5478.57 3975.79 3356.36 2131.18 3975.81 32.41 3.12 G-MAG None 78 7070. 33 24.85 33.73 95.28 5564 . 34 4017.27 3390.77 2154.37 4017.29 32.43 2.05 G-MAG None 79 7165.95 25.12 32.44 95.62 5651. 01 4057.66 3424.61 2176.42 4057.67 32.44 0.64 G-MAG None 80 7260.52 25.07 32.08 94.57 5736.65 4097.77 3458.52 2197.82 4097.78 32.44 0.17 G-MAG None 81 7355.63 25.37 32.78 95.11 5822 . 70 4138.29 3492.73 2219.56 4138. 31 32.44 0.44 G-MAG None 82 7451. 05 25.38 32.00 95.42 5908.91 4179.18 3527.26 2241. 46 4179.20 32.43 0.35 G-MAG None 83 7546.03 25.71 32.27 94.98 5994.61 4220.14 3561. 94 2263.25 4220.15 32.43 0.37 G-MAG None 84 7642.73 25.54 31.88 96.70 6081.80 4261. 96 3597.37 2285.46 4261.97 32.43 0.25 G-MAG None 85 7738.30 25.62 32.04 95.57 6168.00 4303.22 3632.38 2307.30 4303.24 32.42 0.11 G-MAG None 86 7833.00 25.70 32.28 94.70 6253.36 4344.22 3667.10 2329.13 4344.24 32.42 0.14 G-MAG None 87 7929.99 25.73 32.37 96.99 6340.74 4386.31 3702.66 2351. 63 4386.33 32.42 0.05 G-MAG None 88 8035.10 25.95 32.15 105.11 6435.34 4432.12 3741. 40 2376.08 4432.14 32.42 0.23 G-MAG None Page 6 ------------------- Final_survey_Ns32i.TXT 89 8159.36 28.11 31.73 124.26 6546.02 4488.58 3789.32 2405.95 4488.60 32.41 1.75 SP None 90 8254.81 31.89 29.61 95.45 6628.67 4536.26 3830.39 2430.24 4536.29 32.39 4.11 SP None [(c)2004 IDEAL ID8_1C_02] SCHLUMBERGER survey Report 29-Apr-2004 09:25:11 page 5 of 5 --- -------- ------ ------- ------ -------- -------- ---------------- --------------- -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ ------ seq Measured Incl Azimuth Course TVD Verti cal Displ Displ Tota 1 At DLS srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool Corr (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) --- -------- ------ ------- ------ -------- -------- ---------------- --------------- -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ ------ 91 8299.50 33.39 30.48 44.69 6666.31 4560.34 3851. 25 2442.31 4560.37 32.38 3.52 SP None projected to TD 92 8321.00 33.39 30.48 21. 50 6684.26 4572 .17 3861. 45 2448.31 4572.20 32.38 0.00 PRO] None [(c)2004 IDEAL ID8_1C_02] Page 7 ------------------- NS32 - Spud 11/15/03 Prognosed Tops I Actual Depths I Delta I Days since Formation TVDss I TVDrkb I MDrkb TVDss I TVDrkb I MDrkb TVD Spud Top Permafrost 1,149 1206 1226 1149 1206 1226 0 2 Base Permafrost 1,519 1576 1643 1519 1576 1643 0 2 SV6 - top confining zone 3,050 3107 3750 3047 3104 3754 3 3 Surface casing point 3,200 3257 3961 3200 3257 3980 0 3 SV5 - base confining zone 3309 3366 4114 3306 3363 4114 3 20 SV4 3,670 3727 4621 3643 3700 4582 27 20 SV3 3,903 3960 4949 3885 3942 4922 18 21 SV2 - top upper injection zone 4,085 4142 5205 4042 4099 5139 43 21 SV1 - top major shale barrier 4,472 4529 5749 4452 4509 5724 20 22 TMBK - top lower injection zone - Top Ugnu 4,821 4878 6240 4818 4875 6237 3 22 WS1 - top Schrader Bluff - Base Ugnu 6,450 6507 8112 6408 6465 8069 42 23 Production Casing Point 6,450 6507 8112 6455 6512 8121 -5 24 Total Depth 6,631 6688 8312 6629 6685 8321 2 #VALUEI F ornlation Tops Cpr) "'.:i.~ . i~ J': S· S .. .... :.\" ¡q ~ '. . .~~ IJe~1 ry . un BP EXPLORATION (ALASKA), INC. Northstar NS 32 Forrnation Evaluation Log 2"MD Formation Evaluation Log 2" TVU þ£crfl.ONI L. Cop,! AVf1IL/t~LE I I I I I I I I I I I I I I I I I I I )~)-lç8 Memory Multi-Finger Caliper Log Results Summary Company: Log Date: Log No. : Run No.: Pipe1 Desc.: Pipe1 Use: BP Exploration (Alaska), Inc. May 14, 2005 5754 2 4.5" 12.6 lb. L-80 IBT-M Tubing Well: Field: State: API No.: Top Log Intvl1.: Bot. Log Intvl1.: NS-32 I WD-02 Northstar Alaska 50-029-23179-00 Surface 8,105Ft. (MD) Inspection Type: Corrosion Monitoring Inspection COMMENTS: This log is tied into the WLEG @ 8,100' (ELMD). This log was run to assess the condition ot the tubing with respect to changes in corrosive and mechanical damage. This is the second time a PDS caliper has been run on this well. The caliper recordings indicate that the 4.5" tubing is in good condition with respect to corrosive damage. No significant wall penetrations, areas ot cross-sectional wall loss or 1.0. restrictions are recorded. A comparison between the current log and the previous log run on this well (May 12. 2004) indicates no increase in corrosive damage. The distribution of maximum recorded penetrations is illustrated in the Body Region Analysis Page of this report. MAXIMUM RECORDED WALL PENETRATIONS: No significant wall penetrations (> 11 %) are recorded. MAXIMUM RECORDED CROSS-SECTIONAL METAL LOSS: No significant areas of cross-sectional wall loss (> 4%) are recorded. MAXIMUM RECORDED ID RESTRICTIONS: No significant 1.0. restrictions (less than the 1.0. of the trac sleeve) are recorded. I Field Engineer: N. Kesseru Analyst: M. Lawrence Witness: M. Harris ProActive Diagnostic Services, Inc. / P.O. Box 1369, Stafford, TX 77497 Phone: (281) or (888) 565-9085 Fax: (281) 565-1369 E-mail: PDS@memorylog.com Prudhoe Bay Field Office Phone: (907) 659-2307 Fax: (907) 659-2314 I I I Well: Fiel& Company: Country: NS-32 Northstar BP Exploration (Alaska), Inc. USA I I Tubing: I Thread Weight 1 2.6 ppf Nom.oD 4.5 ins L-80 I Penetration and Metallo!>!> (% wall) I penetration body metal loss body 200 I 150 100 I 50 () o to 1 "ft, 1 to 10% 10 to 20 to LO')/¡, 40% 40 to over 85% 8S% I ¡'~umber of joints pene. 1 199 1 loss 47 154 0 (total ~ 2(1) o 0 o 0 o o I I Damage Configuration ( body) 10 I I o I isolated pittmg hole / poss ible bole general Hoe ring corrosIon corrosIOn corrosìon I Number of joints damaged (total ~ 0) o 0 0 0 o I I ew ody Region Analysis Survey Date: Tool Type: Tool Size: No. of Fingers: May 14, 2005 MFC 24 No. 99628 1.69 24 M. Lawrence Nom.lD 3.958 ins Upper len. 1.2 ins Lower len. 1.2 ins Nom. Upset ins Damage Profile (% wall) penetration body o metal loss body 50 100 49 146 I 194 Bottom of Survey ~ 194.4 Analysis Overview page 2 I I I I Maximum Penetration I Comparison To Previous Well: NS-32 Survey Date: May 14, 2005 I Field: North star Prevo Date: May 12, 2004 Company: BP Exploration (Alaska), fne. Tool: MFC 24 No. 9962B Country: USA Tubing: 4.5" ¡ 2.6 Ib L-80 I Overlay Difference I Max. Rec. Pen. (mils) Diff. in Max. Pen. (mils) 0 100 200 -100 -50 0 50 100 I I I I .. OJ -'" E :::¡ I z ... ;: c: :§. ]. I I I I ~._..~..,.. -100 -50 0 50 100 I Approx. Corrosion Rate (mpy) May 14, 2005 May 12, 2004 I I I I I I I Well: Field: Company: Country: I I I I I I I I I I I I I I I I NS-32 North,!ar BP Exploration (Alaska), Inc. USA Minimum Diameter Profile Survey Date: Too!: Tool Size: Tubing I.D.: May 14, 2005 MFC 24 No. 99628 1.69 inches 3.958 inches Minimum Measured Diameters (In.) 225 2.75 3.25 1.75 4 : 9 : 14 19 24 29 : 34 : 39 : 44 :. 49 : 51.3 56 - 61 66 : 71 81 86 ;¡¡ 91 ..Q E 96 :: '" z 101 <: :g !06 111 12-r 123 128 1.13 138 143 -148 1.51 1.58 168 1ì3 ,," 183 188 191 194 3.75 I 1;1 I Pipe: Body Wall: Upset Wall: Nominal 1.0.: I I I I I I I I I I I I I I II II I PDS JOINT "t.::> ¡¡¡ 12.6 0.2ìl in 0.2 ì1 in 3.958 in v\lclì: Field: Company: Country: Survey Date: L·80 LATION NS·32 Northstar BP Exploration (Alaska), Ine. USA May 14, 2005 i'/;in. to. Comments (Ins.) 3.89 3.91 PUP 3.91 PUP 3.90 3.91 3.91 Deposits. 3.89 3.91 3.89 3.90 3.90 3.90 3.90 3.90 ]·13:; ___ 3.88 3.90 3.90 JOÎnt j1. Pen. No. Body (Ins.) 40 1.1 ìO 1.2 ì8 7. 88 3 126 4 167 5 209 ì 290 8 332 9 3ì3 10 415 11 457 12 499 541 14 583 15 625 16 666 17 708 18 750 19 792 20 834 2î 8ì5 22 916 23 958 2-4 1000 25 1042 1084 27 1124 28 ¡ 165 29 1207 30 1247 31 12R9 32 1331 33 1372 34 14J.LL___ 3::. 1456 36 1497 37 1538 1580 39 1622 40 1664 41 1706 43 1789 44 1829 45 1869 46 1911 1952 48 1994 3.38 3.90 3.91 3.88 3.89 3.90 3.90 3.90 _3-,ª~ 3.89 3.91 3.90 3.90 3.90 ') hr .).OJ 3.87 3.83 3.88 3.84 _3·§ª 3.86 Profile ('Yo wall) 50 100 11 1 Body Loss Body II I REPORT JOINT TABULATION SH 4.5 in 12.6 0.271 in 0.271 in 3.958 in L-80 Well: Field: Company: Country: Survey Date: Pipe: Body Wall: Upset Wall: NominaII.D.: I I Pen. ! Body (Ins.) Min. 1.0. (Ins.) I Joint .It. No. I I I I I I I I I 86 87 88 3.81 3.84 3.85 3.80 3.83 3.85 UQ 3.84 3.80 3.86 I I I 2 I I NS-32 Northstar BP Exploration (Alaska), Inc USA May 14, 2005 Comments Profile «Yo wall) 50 100 i i I I Body Metal Loss Body Joint jt. Vt..,·n No. 97 98 99 JOO 102 4230 103 4272 104 4314 105 4355 106 4397 107 4438 108 4479 109 4519 110 4560 111 4601 1!2 4640 113 4681 114 4719 115 4761 116 4802 117 4844 118 4886 119 4928 120 4969 171 SOW 122 5051 122.1 ! 5092 122.2 5102 I I Pipe: Body Wail: Upset Wall: NorninaII.D.: I I I I I I I I I I I 129 130 131 I 1'11"'. .)/ I I I I I 4.5 in "t 2.6 0.271 in 0.271 in 3.958 in L 110 Min. !D. (Ins.) 3.85 3.83 3.84 3.84 3.86 3.82 3.82 3,80 3.85 3.85 3.83 3.81 3.81 3.81 3.81 3.83 3.82 3.77 3.Hl NT TABU VVe!!: Field: Company: Country: Survey Date: 3.83 3.83 Lt. Deposits. 3.81 (L_...L82 ...~_Lt. Deposits. 3.82 3.82 Lt. Deposits. 3.82 5238 5280 5322 5364 5403 5444 S4RS 1Ji2 3.83 3.79 3.80 3.80 3.76 3.80 3.82 3.78 PUP Packer PUP Deposits. Lt. Deposits. Page 3 N NS32 Northstar SP Exploration (Alaska), Inc. USA May 14, 2005 Comments o Frome wall) 50 100 ! I I I Penetration Body Metal Loss Body I JOINT TABU N 3.87 3.83 Deposits. 3.88 3.89 3.87 3.90 3.92 3.91 3.87 3.91 I Pipe: Body Wall: Upset Wall: Nominaf I.D.: 4.5 in 12.6 LBO 0.271 in 0.271 in 3.958 in I Joil1t J1. No. 143 144 145 146 147 148 149 151 152 154 D ¡ en. Min. LO. (Ins.) Body (Ins.) I I 5976 6018 6058 6099 6140 6182 I 6389 6430 6472 3 6555 6596 6637 6678 6719 6761 6802 6843 6884 6925 6966 7008 7049 7091 J.Öö I 158 159 160 I 161 162 163 164 165 166 167 168 169 170 171 172 173 174 I I I I I I 187 188 189 190 7751 7790 7831 7873 4 7956 I 192 I I I We!!: Field: Company: Country: Survey Date: Lt. Deposits. L1. Deposits. L1. Deposits. Deposits. L1. Deposits. Page 4 N$-32 Nortnstar BP Exploration (Alaska), ine. USA May 14, 2005 Comments o Profiie wall) 50 1 I. ! , I I I I I Penetration Body Metal Loss Body I I Pipe: Body Wali: Upset Wall: Nominal !.D.: I I jOint )1. Depth No. (Ft.) I 193 194 194.1 194.2 1943 194.4 I I I I I I I I I I I I I I IIIIII!IIIII 7998 8040 8078 8088 8090 8100 4.5 in! Lb 0.271 in 0.271 in 3.958 in L-80 3.88 ?,90 3.91 3.75 3.82 N/A JOINT We!l: Fie!d: Company: Country: Survey Date: LO. (Ins.) PUP XN NIPPLE PUP Lt. Deposits. WLEG Page 5 u N SH NS-32 Northstar BP Exploration (Alaska), Inc. USA May 14, 2005 Comments Profile j ('Yo wall) I o 50 100 I I ' Penetration Body Metal Loss Body I ' . I I I I I I I I I I I I I I I I I I TREE:ABB-VGI5 1/8" 5ksi WELLHEAD:ABB-VGI 11" Mulitbowl 5ksi I (Note: Hanger - 4" BPVITWC) ~ 20", 169# X-56 @ 200' MD - NS32 , , , , , '" , 103f4", 45.5#fft, L-80, BTC @3964' MD ... 4.5", 12.6#fft, L-80, IBT-MOD TUBING ID: 3.958" CAPACITY: 0.0152 BBLlFT ~ 4.5" 'XN' NIPPLE, @ 8088' 3.725" ID (HES) __- 75/8", 29.7#/ft .... . L-80, BTC-M @8107 'MD- TD @8321' MD 6684' TVD DATE 6/18/03 115104 5111/04 REV. BY JAS JAS RAC COMMENTS Initial Diagram Proposed Completion Completion 5/2/04 , , ~ RKB. ELEV = 55.95' KB-BF. ELEV = 40.05' BASE FLANGE ELEV = 15.9' l 7-5/8"x4-1/2" Annulus Freeze Protected to 2000' TVD wI 60 bbls of Inhibited Diesel Heat Trace Starting @ 2097' MD 'X' Nipple @ 2169' MD 3.813" ID ~ Cement Packer Fluid - 9.8 ppg inhibited brine below diesel Baker 7-5/8" x 4-1/2" "S-3" PACKER 3.875"10 @5102' MD ;..- 4.5" WLEG, @8100' MD ,~ 6 3/4" open hole Northstar WFJ J : NS32 API NO: 50-029-23179 BP Exploration (Alaska) I I I I I I I I I I I I I I I I I I I Company: Log Date: Log No. : Run No.: Pipe1 Desc.: Pipe1 Use: Inspection Type: COMMENTS: u::c~ ;{ tJ"!/ "/38' Memory Multi..Finger Caliper log Results Summary BP EXPLORATION (ALASKA) INC. May 12, 2004 5422 1 4.5" 12.6 lb. L-80 IBT-M Tubing Well: Field: State: API No.: Top Log Intvl1.: Bot. Log IntvI1.: NS-32 I WD-02 Northstar Alaska NIA Surface 8,111 Ft. (MD) Corrosive & Mechanical Damage Inspection This log is tied into the X Nip @ 2,169' (ELMD). This log was run to assess the condition of the tubing with respect to corrosive and mechanical damages. The caliper recordings indicate that the 4.5" tubing is in good condition with respect to corrosive damage. No significant wall penetrations or areas of cross-sectional wall loss are recorded. Lt. Deposits restrict the I.D. to 3.80" in joint 4 @ 240'. The distribution of maximum recorded penetrations is illustrated in the Body Region Analysis Page of this report. MAXIMUM RECORDED WALL PENETRATIONS: No significant wall penetrations (> 18%) are recorded. MAXIMUM RECORDED CROSS-SECTIONAL METAL LOSS: No significant areas of cross-sectional wall loss (> 4%) are recorded. MAXIMUM RECORDED ID RESTRICTIONS: Lt. Deposits Lt. Deposits Minimum I.D. = 3.80" Minimum I.D. = 3.80" 240 Ft. (MD) 1,372 Ft. (MD) 4 31 @ @ Jt. Jt. No other significant I.D. restrictions are recorded. 1 Field Engineer: R.A. Richey Analyst: M. Lawrence Witness: R. Liddelow ProActive Diagnostic Services, Inc. I P.O. Box 1369, Stafford, TX 77497 Phone: (281) 01 (888) 565-9085 Fax: (281) 565-1369 E-mail: PDS(cÙmemorylog.com Prudhoe Bay Field Office Phone: (907) 659-2307 Fax: (907) 659-2314 I I I Well: Fie)d: Company: Country: NS-32 / WD-02 Northstar BP EXPLORATION (ALASKA), INC. USA I Tubing: Weight 12.6 ppf Grade & Thread L-80 IBT-M Nom.OD 4.5 ins I I Penetration and Metal loss (% wan) penetration body metal loss body I 200 150 100 50 I 01 o to 1 'Yo over 85'1" 1 to 10% 10 to 20% 20 to 40% 40 to 85(j{) I Number of joints ana)ysed (tota) = 199) pene. 7 169 23 0 0 Joss 111 88 0 0 0 I Damage Configuration ( body) 20 I 10 I I o isolated genera! line ring hole / poss pitting corrosion corrosion corrosion ¡ble hole I Number of joints damaged (total = 15) 3 0 12 0 o I I I PDS Repo Overview Body Region Analysis Survey Date: Tool Type: Tool Size: No. of Fingers: Analyst: Nom.lD 3.958 ins May 12, 2004 MFC 40 No. 030807 2.75 40 M. Lawrence Upper len. 1.2 ins Lower len. 1.2 ins ~~om. Upset 4.5 ins Damage Profile (% wall) penetration body o metal loss body 50 100 50 o o 99 147 Bottom of Survey ~ 193.4 Overview page 2 I I I I Well: Field: Company: Country: I I I I I I I I I I I I I I I NS-32 I WD-02 Northstar BP EXPLORATION (ALASKA) USA PDS Caliper ¡V\inimum Diameter Profile Survey Date: Tool: Tool Size: Tubing 1.0.: May! 2, 2004 MFC 40 No. 030807 2.75 inches 3.958 inches Minimum Measured Diameters (In.) 2.85 2.95 3.05 3.15'-25 3.35 3.45 .3.55 3.65 3.75 3.85 3.95 1 1 I 2.75 6 11 16 : 21 26 : 11 : 36 41 46 : 50.1 53 SR :: 63 : 68 T' 78 : 83 ßß: ... OJ ..Q 93 E " 98 : Z 'E 103 :§, 108 In 118 : 121 125 : no U5 140 : 145 150 : 155 160 165 170 175 180 185 190 193 I PDS JOI TABU N EET I Pipe: Body Wall: Upset Wall: NominaII.D.. Well: Field: Company: Country: Survey Date: N5-32 / WD-02 Northstar BP EXPLORATION (ALASKA), INC USA May 12, 2004 Joint Jt. Depth Pen. Min. I Damage Profile No. (Ft.) Body !.D. Comments (%wall) (Ins.) (Ins.) 0 50 100 1 87 0.02 3.85 Lt Deposits. 2 125 0.01 3.87 3 !67 0.02 3.85 Lt Deposits. 4 209 0.04 3.80 Shallow pitting. Lt. Deposits. 5 248 0.04 3.88 Line shallow corrosion. Lt. Deposits. -~ 290 0.01 3.87 Lt. Deposits. 7 331 0.03 3.88 Lt. Deposits. -----ª-- ___ 37.J^ 0.02 3.88 9 0.02 3.84 Lt. Deposits. _li2- 0.02 3.88_ 11 0.01 3.88 12 0.01 3.86 13 0.01 3.89 14 0.01 3.88 15 0.01 3.37 Lt. Deposits. 0.02 3.83 Lt. Deposits. 0.01 3.89 18 791 0.02 3.89 19 833 O.OJ 3.88 ~O 875 0.03 3.88 Lt. Deposits. ---2L ---21 6 0.04 3.88 Line shallmv corrosion. Lt. Deposits. 22 958 0.01 3.88 ~3 1000 0.01 3.84 Lt. Deposit?~ 24 1042 0.02 3.89 Deposits. 25 1084 0.01 3.85 Deposits. 1124 0.02 , ~ n~ 5.0::1 3.88 28 1206 0.01 3.87 ~- 1248 0.04 3.87 Shallow pitting. Lt. Deposits. 30 1290 0.01 3.89 31 1331 0.03 3.80 Lt. Deposits. 32 1372 0.03 3.84 Lt. Deposits. 33 1414 0.01 3.85 Lt. Deposits. 34 1456 0.04 3.81 Shallow pitting. Lt. Deposits. 35 1497 0.01 3.89 36 1538 0.01 3.91 37 1580 0.03 3.86 Lt Deposits. 38 1622 0.02 3.91 39 1664 0.03 3.88 1706 0.02 , 3.88 41 1748 0.03 3.87 42 1789 0.02 3.87 43 1829 0.01 3.83 ._~- _1369_ 0.02 3.B9 45 1911 0.01 3.87 ---'lli 1953 0.02 3.87 47 1994 0.01 3.89 __L1JL 2035 0.01 3.90 --.12. 2077 0.01 3.88 50 2118 0.02 3.88 Penetration Body Metal Loss Body Page 1 4.5 in 12.6 ppf L-80 !BT-M 0.271 in 0.271 in 3.958 in I I I I I I I I I I I I I I I I I I Pipe: Bodv Wall: Upset Wall: Nominal I.D.: I Joint I Jt. Depth I No. I (Ft.) I 50.1 ... 50.3 51 52 I 54 55 56 _57 _. 58 59 60 61 62 63 ---2.1 ---22... 66 67 --.!ill.. 69 70 7ì ----'ZL 73 74 75 I I I I I 77 78 79 80 81 82 83 84 ~- 86 87 88 89 90 91 92 93 94 I I I I I 2159 2169 2171 2180 2221 22 6 2.. 2304 2345 2387 2429 2470 2512 2554 2595 2636 2677 . __27ì¡) 2760 2801 2843 _~{)5 2927 2968 3010 3050 3091 3132 3174 3213 3254 3294 3332 3373 3413 3453 3494 3536 3576 3616 3657 ' 3698 3740 3781 3821 3861 3903 3943 3984 4025 4067 PDS REPORT JOINT 4.5 in 1 L6 ppf L-80 IBT-M 0.271 in 0.271 in 3.958 in Pen. Body (Ins.) 0.02 o 0.00 0.02 0.02 0.02 0.01 0.02 0.03 0.02 0.01 0.01 0.01 0.01 0.02 0.01 0.01 0.03 0.02 0.03 0.02 0.01 0.02 0.01 0.02 0.01 0.01 0.01 0.02 0.02 0.01 0.01 0.02 0.Q1 0.03 0.02 0.02 0.02 0.00 Min. LO. (Ins.) 3.87 3.81 3.89 3.89 3.88 3.88 3.90 3.88 3.86 3.89 3.89 3.91 3.88 3.89 3.91 3.89 3.87 3.88 3.89 3.88 3.89 3.90 3.89 3.90 3.90 3.90 3_JH~ 3.88 3.90 3.87 3.87 3.88 3.88 3.89 3.89 3.91 3.88 3.86 3.90 3.89 ' 3.88 3.88 3.90 3.87 3.90 3.85 3.9_0 3.89 3.87 3.90 Well: Field: Company: Country: Survey Date: PUP X NIP PUP Page 2 UlATION NS-32 / WD-02 Northstar BP EXPLORATION (ALASKA), INC. USA May 1 2, 2004 Comments Damage Profile (%wall) o 50 100 Body Metal Loss Body I I PDS NT TABULATION SH I Pipe: Body Wall: Upset Wall: NominaII.D.: 4.5 in 12.6 0.271 in 0.271 in 3.958 in L-80 !BT-M Well: Field: Company: Country: Survey Date: ~.,JS-32 í WD-02 Northstar BP EXPLORATION (ALASKA), INC. USA May! 2, 2004 I I Joint Jt Depth Pen. ¡"tin. ' Damage Profile I No. (Ft) Body !.D. Comments (%wall) (Ins.) (Ins.) 0 50 100 98 4108 0.01 3.89 99 4149 0.02 3.91 100 4190 0.02 3.89 101 4232 0.02 3.88 102 4273 0.01 3.86 103 4315 0.01 3.91 104 4357 0.02 3.89 4399 0.01 3.88 106 4440 0.01 3.89 107 4480 O.OL 3.90 108 4521 0.01 3.89 .~ 4562 0.01 3.88 110 4603 0.01 3.91 111 4641 0.01 3.89 1!2 4682 0.01 3.86 ~1~-..1721 0.02 3.9! _JJ4 .-..1162 0.02 3.88 115 4804 0.01 3.91 .~ 4846 0.02 3.89 ~J7 4888 0.03 3.90 118 4930 0.01 3.89 119 4970 0.02 3.89 120 5012 0.02 3.88 121 5053 0.01 3.89 121.1 5094 0.01 3.91 PUP 121.2 5104 0 3.88 , PACKER 5108 0.00 3.92 PUP 122 5118 0.01 3.88 5158 0.01 3.90 124 5199 0.01 3.93 125 5240 0.01 3.89 126 5282 0.03 3.90 1')7 5324 0.01 3.91 L.' 128 5366 0.03 3.85 129 5405 0.00 3.86 130 5446 0.01 3.91 5487 0.02 3.89 132 5527 0.01 3.91 133 5569 0.01 3.89 134 5610 0.02 3.90 135 5651 0.01 3.91 ---.119.. 5692 0.02 3.89 Pitting. 137 5733 0.00 3.87 138 5773 0.01 3.90 139 5814 0.02 3.89 140 5854 0.01 3.90 ....l.±L..... ..... 5895 0.01 3.88 142 5936 0.01 3.91 ---.143 5977 0.01 3.91 --..l 44 6019 0.01 3.90 Body Loss Body Page 3 I I I I I I I I I I I I I I PDS REPORT JOINT ULATION SH I NS-32 / WD-02 Northstar BP EXPLORATION (ALASKA), INC USA May 12, 2004 4.5 in 12.6 ppf L-80 !BT-M 0.271 in 0.271 in 3.958 in Well: Field: Pipe: Body Waif: Upset Wall: Nominal 1.0.: I Country: Survey Date: I Jt. Depth I (Ft.) Joint No. Pen. Body (Ins.) ,'vtin. !.D. (Ins.) Comments o I 6060 6101 6142 6183 6225 62<26 6307 6348 6390 6432 6473 6515 6556 6598 6639 6680 6721 6763 6803 6844 __ 6886 6927 6967 7009 7050 7092 I 7134 7176 7217 7258 7299 7340 73<32 742) 746} 7504 7545 7587 7629 7670 7711 7753 7791 , 7833 7874 7915 7957 7999 8041 8080 147 148 149 150 151 0.01 0.02 0.02 0.01 0.01 0.02 0.02 0.01 0.03 O.j)-º-------l~ 0.01 0.02 0.01 0.02 0.03 0.02 0.01 0.01 0.04 0.01 O.ü! 0.04 0.04 0.04 0.03 0.05 0.01 0.01 0.03 0.02 0.04 _ 13 __--.l 0.01 Q,-º-L- 0.01 0.02 0.03 0.03 0.04 0.03 0.03 0.04 0.01 0.04 0,05 0.02 0.01 0.03 0.01 I I 153 155 56 157 ...J 58 _16Q II I' I I ^^----^~--~,~. 3.91 3.89 3.90 3.92 3.89 3.91 3.91 3.89 3.88 3.89 3.88 3.88 Line shallow corrosion. 3.89 3.86 3.89 3.92 3.89 3.90 3.91 3.91 3.90 3.91 3.89 3.89~Lif1g__Shal!Q\.'Y_corroSjon. _.. _.__ 3.88 Deposits. 3.89 __ 3.91 i Line shallow corrosion. 3.87 I 3.90 Ljne shallow corrosion. 3.88 Line shallovysorrosion. 3.89 I 162 163 ....J.Q.4 ..-125 166 167 Deposits. I ^~~--~-^^~-, Line shallow corrosion. Line shallow corrosion. Line shallow corrosion. I 174 ..-1EL 176 I _._------,~- -,-,----,-----_.~ ~----~~.._-~.~- 177 178 179 I ~..m___ ._JßL 1132 183 184 185 186 187 I I _l'n .192 193 193.1 I 3·119 3.93 PUP I Body Metal Loss Body Page 4 I I I I Pipe: Body Wall: Upset Wall: Nomìnai 1.0.: Joìnt No. I ~2_ I I I I I I I I I I I REPORT 4.5 in 12.5 ppf 1,-80 IBT·M 0.271 in 0.271 in 3.958 in )t. Depth I (Ft.) I I I 8090 I Pen. Body (Ins.) o 0.01 o NT TABULATION Well: Field: Company: Country: Survey Date: Min. I 1.0. (Ins.) 3.81 3.89 N/A X NIP PUP End ofTubing Page 5 NS-32 / WD-02 Northstar BP EXPLORATION (ALASKA), INC. USA May 12, 2004 Comments I Damage Profile ' «Yo wall) o 50 100 111111111 Body Metal loss Body .. .. .. .. .. .. .. .. .. Well: Field: Company: Country: Tubing: NS-32 / WD-02 Northstar BP EXPLORATION (ALASKA), INC. USA 4.5 ins 12.6 ppfJ-80 IBT-M __ Cross Section Joint 4 at depth 240.24 ft Tool speed = 64 Nominal ID = 3.958 Nominal OD = 4.500 Remaining wall area = 100 'Yo Tool deviation 2 0 .. .. .. .. .. .. ~,~-- DS R port ross Survey Date: Tool Type: Tool Size: No. of Fingers: Analyst: May 12, 2004 MFC 40 ¡'10. 030807 2.75 40 Finger 6 Projection = -0.132 ins Lt. Deposits ._~"~~ Minimum 1.0. 3.80 ins HIGH SIDE = UP ~--- Cross Sections page 1 .. ns .. IIIIIiIIIIIIIII .. .. lIB .. .. .. .. .. .. ---~-- --.-""-- Well: Field: Company: Country: Tubing: NS-32 / WD·02 Northstar BP EXPLORATION (ALASKA), INC. USA 4.5 ins 12.6 ppf L-80 IBT-M Cross Section 31 at depth 1.371 J Tool speed = 69 NominallD = 3.958 Nominal OD 4.500 Remaining wall area = 1 00 'Yo Tool deviation 2.3 0 .. .. .. .. .. .. .. -~,~~------~'" S Report Cross Sections Survey Date: Tool Type: Tool Size: No. of Fingers: May 12, 2004 MFC 40 No. 030807 2.75 40 M. Lawrence ft Finger 22 Projection = -0.122 ins Lt. Deposits Minimum I.D. 3.80 ins HIGH SIDE = UP Cross Sections page 2 .. .. - .. .. I I I I I I I I I I I I I I I I I I I Cement/Stage Collar May 3, 2004 Completion Diagram Northstar Well NS32 I WD-02 990' MD KOP: 400' Max. Angle 47.5° Departure at BHL: Approx 4572' Base Permafrost 1643' MD (1519' SS) 3754' MD (3047' SS) + SV 61 4114' MD + SV 5 (3306' SS) t a'I C ~ -- .. 1;; ~ = ... I::cií ~ 5139' MD + (4042' SS) · SV 2 SV1 I 6237' MD (4818' SS) TMBK c- Q ~ -- i:: tí = =- ...., c .E- . (6880' SS) CONFINING ZONE PRINCE CREEK AND UGNU FORMATIONS ------ SCHRADER BLUFF CONFINING SHALE MD (BKB) (measured depth below rig) 20" Conductor 201' MD (145' SS) 10-3/4",45.5#, L-80 Casing Heat Tracing 'X' Nipple 2097' MD 2169' MD (1923' SS) 3964' MD (3197' SS) Cement/Stage 4137' MD Collar 4-1/2",12.6#, L-80 Tubing IBT-M Baker Packer 5102' MD 7-5/8", 29.7#, L-80, Casing (Run T.D. to Suñace) . . r " 7-5/8" Shoe 6-3/4" Open Hole 6154' MD 8107' MD (6443' SS) 8321' MD (6628' SS)