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Home My WebLink About207-117CAUTION: 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:PB Wells Integrity To:Wallace, Chris D (OGC) Cc:Regg, James B (OGC); Bo York; Oliver Sternicki Subject:Disposal Well GNI-04 (PTD #207117) EPA MIT-IA Passed Date:Saturday, July 19, 2025 10:08:46 AM Attachments:MIT PBU GNI-04 07-18-25.xlsx Mr. Wallace, Disposal well GNI-04 (PTD #207117) passed EPA witnessed MIT-IA on 07/18/25. EPA inspector travel plans were disrupted due to heavy fog yesterday and resources were available to perform the MIT-IA in the evening. AOGCC inspector Kam StJohn waived witness. Please see attached 10-426 and call with any questions or concerns. Ryan Holt Hilcorp Alaska LLC Field Well Integrity / Compliance Ryan.Holt@Hilcorp.com P: (907) 659-5102 M: (907) 232-1005 From: PB Wells Integrity Sent: Friday, July 18, 2025 11:04 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: jim.regg <jim.regg@alaska.gov>; Bo York <byork@hilcorp.com>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Subject: Disposal Well GNI-04 (PTD #207117) Inconclusive EPA MIT-IA Mr. Wallace, Disposal well GNI-04 (PTD #207117) annual EPA / AOGCC witnessed MIT-IA was performed on 07/17/25 and deemed inconclusive due to failure to show stabilization. GNI-04 was shut in and EPA / AOGCC witnessed testing is scheduled for afternoon 07/19/25. Please see attached 10-426 and call with any questions or concerns. Ryan Holt Hilcorp Alaska LLC Field Well Integrity / Compliance Ryan.Holt@Hilcorp.com P: (907) 659-5102 3%8*1, 37' M: (907) 232-1005 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Submit to: OOPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2071170 Type Inj N Tubing 704 704 698 694 Type Test P Packer TVD 4461 BBL Pump 1.7 IA 79 1808 1738 1728 Interval O Test psi1500BBL Return1.3OA0000 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 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: Notes:1-year EPA MIT-IA. Witnessed by Evan Osbourne and James Phillips. Waived by Kam StJohn GNI-04 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Hilcorp North Slope LLC Prudhoe Bay / PBU / GNI Pad Ryan Holt 07/18/25 Form 10-426 (Revised 01/2017)2025-0718_MIT_PBU_GNI-04 9 9 9 9 999 99 9 À 9 -5HJJ MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Tuesday, August 26, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Bob Noble P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp North Slope, LLC GNI-04 PRUDHOE BAY UN UGN GNI-04 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 08/26/2025 GNI-04 50-029-23367-00-00 207-117-0 W SPT 4461 2071170 1500 1322 1327 1322 1318 0 0 0 0 OTHER I Bob Noble 7/17/2025 1 year EPA witnessed MIT-IA. Secont attempt. Left well shut in for eval. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:PRUDHOE BAY UN UGN GNI-04 Inspection Date: Tubing OA Packer Depth 281 1798 1775 1790IA 45 Min 60 Min Rel Insp Num: Insp Num:mitRCN250718165155 BBL Pumped:1.3 BBL Returned:1.6 Tuesday, August 26, 2025 Page 1 of 1            Inconclusive retest MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Tuesday, August 26, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Bob Noble P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp North Slope, LLC GNI-04 PRUDHOE BAY UN UGN GNI-04 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 08/26/2025 GNI-04 50-029-23367-00-00 207-117-0 W SPT 4461 2071170 1500 1395 1355 1379 1340 0 0 0 0 OTHER I Bob Noble 7/17/2025 1 year MIT-IA, EPA witnessed. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:PRUDHOE BAY UN UGN GNI-04 Inspection Date: Tubing OA Packer Depth 226 1799 1787 1742IA 45 Min 60 Min Rel Insp Num: Insp Num:mitRCN250718164040 BBL Pumped:3.8 BBL Returned:1.8 Tuesday, August 26, 2025 Page 1 of 1           Inconclusive; increased pressure loss during 2nd 15-min tests interval -- J. Regg 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: 7/23/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250723 Well API #PTD #Log Date Log Company AOGCC ESet # END 1-25A 50029217220100 197075 6/19/2025 HALLIBURTON T40691 KU 41-08 50133207170000 224005 6/30/2025 AK E-LINE T40692 MPU F-05 50029227620000 197074 7/1/2025 READ T40693 MPU J-02 50029220710000 190096 5/21/2025 YELLOWJACKET T40694 MPU R-106 50029238160000 225033 6/8/2025 HALLIBURTON T40695 MPU R-107 50029238190000 225049 7/11/2025 YELLOWJACKET T40696 ODSK-41 50703205850000 208147 6/13/2025 HALLIBURTON T40697 ODSN-02 50703206710000 213046 6/13/2025 HALLIBURTON T40698 ODSN-16 50703206200000 210053 6/14/2025 HALLIBURTON T40699 ODSN-17 50703206220000 210093 6/14/2025 HALLIBURTON T40700 ODSN-24 50703206620000 212178 6/15/2025 HALLIBURTON T40701 ODSN-28 50703206760000 213148 6/17/2025 HALLIBURTON T40702 ODSN-36 50703205610000 207182 6/12/2025 HALLIBURTON T40703 PBU 07-23C 50029216350300 225043 7/4/2025 HALLIBURTON T40704 PBU 14-18C 50029205510300 225040 6/25/2025 HALLIBURTON T40705 PBU 15-33C 50029224480300 216075 7/3/2025 HALLIBURTON T40706 PBU C-30A 50029217770100 208169 7/1/2025 HALLIBURTON T40707 PBU E-09C 50029204660300 209095 6/30/2025 HALLIBURTON T40708 PBU F-38B 50029220930300 225029 6/12/2025 HALLIBURTON T40709 PBU GNI-02A 50029228510100 206119 7/4/2025 HALLIBURTON T40710 PBU GNI-02A 50029228510100 206119 7/3/2025 HALLIBURTON T40710 PBU GNI-04 50029233670000 207117 6/27/2025 HALLIBURTON T40711 PBU GNI-04 50029233670000 207117 6/27/2025 HALLIBURTON T40711 PBU J-07C 50029202410300 225026 5/30/2025 HALLIBURTON T40712 PBU L-105 50029230750000 202058 6/24/2025 YELLOWJACKET T40713 PBU L-108 50029230900000 202109 6/23/2025 YELLOWJACKET T40714 PBU NK-25 50029227600000 197068 6/5/2025 YELLOWJACKET T40715 PBU P2-06 50029223880000 193103 6/19/2025 HALLIBURTON T40716 PBU S-104 50029229880000 200196 6/21/2025 YELLOWJACKET T40717 T40711PBU GNI-04 50029233670000 207117 6/27/2025 HALLIBURTON T40711PBU GNI-04 50029233670000 207117 6/27/2025 HALLIBURTON Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.07.28 09:54:00 -08'00' 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: PCU-05 50283202030000 225037 7/3/2025 YELLOWJACKET T40718 TBU D-08RD 50733201070100 174003 6/4/2025 READ T40719 Please include current contact information if different from above. Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.07.28 09:53:40 -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:Brooks, Phoebe L (OGC) To:PB Wells Integrity Cc:Regg, James B (OGC) Subject:RE: Hilcorp (PBU) July 2024 MIT Forms Date:Friday, August 30, 2024 9:34:54 AM Attachments:MIT PBU S-11B 07-06-24 Revised.xlsx MIT PBU GNI-2A GNI-3 GNI-4 07-26-24 Revised.xlsx MIT PBU H-13A 07-26-24 Revised.xlsx Hi Ryan, Attached are revised reports as follows: MIT PBU S-11B 07-06-24 – changed the packer tvd to 8439’ MIT PBU GNI-2A GNI-3 GNI-4 07-26-24 – changed the type of injection to “I” for GNI-03 (Class I well) MIT PBU H-13A 07-26-24 – changed the BBL Pump to reflect 20 added initial IA pressure of 1330 per the inspector’s report Please update your copy 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: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent: Thursday, August 1, 2024 9:22 AM To: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Subject: Hilcorp (PBU) July 2024 MIT Forms All, 3%8*1, 37' evised Attached are the completed MIT forms for the tests completed in July 2024 by Hilcorp North Slope, LLC. Well: PTD: Notes: GNI-02A 2061190 1-year MIT-IA EPA GNI-03 1971890 1-year MIT-IA EPA GNI-04 2071170 1-year MIT-IA EPA H-13A 2090440 MIT-T & CMIT per Sundry 324-234 P2-42 1931430 4-year MIT-IA PSI-01 2021450 2-year MIT-IA per AA AIO 4G.010 S-09A 2140970 MIT-T per Sundry 324-258 S-11B 1990530 2-year MIT-IA per AA AIO 3B.008 S-122 2050810 MIT-T & MIT-IA per Sundry 324-268 V-109 2022020 MIT-T per Sundry 324-042 V-220 2080200 4-year MIT-IA V-223 2080220 4-year MIT-IA X-11A 1990780 4-year MIT-IA Y-07A 2071050 4-year MIT-IA Please respond with any questions or concerns. Ryan Holt Hilcorp Alaska LLC Field Well Integrity / Compliance Ryan.Holt@Hilcorp.com P: (907) 659-5102 M: (907) 232-1005 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. GNI-04 2071170 1-year MIT-IA EPA Submit to: OOPERATOR: FIELDD // UNITT // PAD: DATE: OPERATORR REP: AOGCCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2061190 Type Inj N Tubing 276 318 305 304 Type Test P Packer TVD 4537 BBL Pump 5.9 IA 131 1710 1651 1639 Interval O Test psi 1500 BBL Return 1.5 OA 32 42 41 41 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 1971890 Type Inj I Tubing 1367 1365 1368 1365 Type Test P Packer TVD 4589 BBL Pump 2.0 IA 15 1736 1907 2050 Interval O Test psi 1500 BBL Return 1.7 OA 0 0 0 16 Result I Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 1971890 Type Inj I Tubing 1359 1363 1357 1352 Type Test P Packer TVD 4589 BBL Pump 1.3 IA 8 1725 1789 1847 Interval O Test psi 1500 BBL Return 1.5 OA 0 188 245 307 Result I Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 1971890 Type Inj I Tubing 1347 1347 1351 1351 Type Test P Packer TVD 4589 BBL Pump 1.2 IA 4 1730 1748 1776 Interval O Test psi 1500 BBL Return 1.3 OA 75 326 364 396 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2071170 Type Inj N Tubing 286 286 285 285 Type Test P Packer TVD 4461 BBL Pump 5.3 IA 5 1697 1626 1618 Interval O Test psi 1500 BBL Return 1.2 OA 85 104 119 119 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 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:Annual EPA MIT-IA. Witnessed by Nick Bruno from the EPA. Increased diesel test fluid to 140° F - Passed per EPA GNI-04 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: GNI-03 Notes: Annual EPA MIT-IA. Witnessed by Nick Bruno from the EPA Annual EPA MIT-IA. Witnessed by Nick Bruno from the EPA. Produced water injection temp rising - inconclusive Annual EPA MIT-IA. Witnessed by Nick Bruno from the EPA. Increased diesel test fluid to 120° F - produced water injection temp still rising - inconclusive Notes: Hilcorp Alaska LLC Prudhoe Bay / PBU / GNI Pad Ryan Holt 07/26/24 Notes: Notes: Notes: Notes:Annual EPA MIT-IA. Witnessed by Nick Bruno from the EPA GNI-02A GNI-03 GNI-03 Form 10-426 (Revised 01/2017)2024-0726_MIT_PBU_GNI_3wells 9 9 9 9 9 9 99 9 9 -5(JJ GNI-04 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: 5/31/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240531 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 13 50133205250000 203138 1/25/2024 AK E-LINE JB/GR/RBP MPI 2-14 50029216390000 186149 5/8/2024 READ CaliperSurvey MPS-17 50029231150000 202173 5/14/2024 READ LeakPointSurvey PBU GNI-03 50029228200000 197189 5/21/2024 READ PressureTemperatureLog PBU GNI-04 50029233670000 207117 5/22/2024 READ CaliperSurvey PBU GNI-04 50029233670000 207117 5/20/2024 READ PressureTemperatureLog TBU K-12RD2 50733201560200 208088 5/17/2024 READ CaliperSurvey TBU K-17 50733202480000 173001 5/16/2024 READ CaliperSurvey Please include current contact information if different from above. T38865 T38866 T38867 T38868 T38869 T38869 T38870 T38871 PBU GNI-04 50029233670000 207117 5/22/2024 READ CaliperSurvey PBU GNI-04 50029233670000 207117 5/20/2024 READ PressureTemperatureLog Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.05.31 13:00:13 -08'00' 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: 11/21/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20231121 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# MPU B-28 50029235660000 216027 11/16/2023 READ Caliper Survey PBU GNI-04 50029233670000 207117 6/13/2023 HALLIBURTON Press-Temp Please include current contact information if different from above. T38143 T38144 11/21/2023 50029233670000 207117 6/13/2023 HALLIBURTON Press-TempPBU GNI-04 Kayla Junke Digitally signed by Kayla Junke Date: 2023.11.21 12:11:15 -09'00' 1 Regg, James B (OGC) From:PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent:Tuesday, August 1, 2023 1:10 PM To:Brooks, Phoebe L (OGC); Regg, James B (OGC); Wallace, Chris D (OGC) Cc:PB Wells Integrity Subject:Hilcorp (PBU) July 2023 MIT Forms Attachments:July 2023.zip All, AƩached are the completed AOGCC MIT forms for the tests completed in July 2023 by Hilcorp North Slope, LLC. Well: PTD: Notes: 11‐31A 1961830 2‐year MIT‐T & CMIT‐TxIA per CO 736 13‐01 1780600 MIT‐T for P&A Sundry #323‐074 E‐34A 2140960 2‐year MIT‐T & CMIT‐TxIA per CO 736 F‐10C 2130860 2‐year MIT‐T & CMIT‐TxIA per CO 736 GNI‐02A 2061190 Annual EPA MIT‐IA GNI‐03 1971890 Annual EPA MIT‐IA GNI‐04 2071170 Annual EPA MIT‐IA L‐103 2021390 4‐year MIT‐IA L‐117 2011670 4‐year MIT‐IA L‐254 2230300 New Drill MIT‐IA per Sundry #323‐381 M‐28 1860740 4‐year MIT‐IA P2‐29 1931470 4‐year MIT‐IA PSI‐09 2021240 2‐year MIT‐T per CO 736 & 2‐year MIT‐IA per AA AIO 4F.001 PWDW3‐2 2190810 4‐year MIT‐IA V‐100 2010590 4‐year MIT‐IA W‐40A 2221030 IniƟal MIT‐IA for Injector Conversion per Sundry #323‐100 Y‐27 1900280 4‐year MIT‐IA Please reply with quesƟons or concerns. Andy Ogg Hilcorp Alaska LLC Field Well Integrity andrew.ogg@hilcorp.com P: (907) 659‐5102 M: (307)399‐3816 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, 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. PBU GNI-04PTD 2071170 Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 2061190 Type Inj N Tubing 314 316 314 314 Type Test P Packer TVD 4537 BBL Pump 5.1 IA 38 1710 1645 1635 Interval O Test psi 1500 BBL Return 2.2 OA 36 45 44 44 Result P Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 1971890 Type Inj N Tubing 283 286 283 282 Type Test P Packer TVD 4589 BBL Pump 3.9 IA 77 1708 1664 1657 Interval O Test psi 1500 BBL Return 1.5 OA 333 327 318 321 Result P Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 2071170 Type Inj W Tubing 1493 1494 1492 1493 Type Test P Packer TVD 4461 BBL Pump 3.8 IA 137 1704 1659 1662 Interval O Test psi 1500 BBL Return 1.8 OA 9 25 24 22 Result P Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: Hilcorp Alaska LLC Prudhoe Bay / PBU / GNI Pad Ryan Holt 07/21/23 Notes: Notes: Notes: Notes: GNI-02A GNI-03 Notes: GNI-04 Notes: Annual EPA MIT-IA. Witnessed by Nick Bruno from the EPA Annual EPA MIT-IA. Witnessed by Nick Bruno from the EPA Annual EPA MIT-IA. Witnessed by Nick Bruno from the EPA 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)2023-0721_MIT_PBU_GNI-pad_3wells        J. Regg; 10/12/2023 ==I 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. 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. Submit to: OPERATOR: FIELD /UNIT /PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2061190 Type Inj N Tubing 244 300 300 300 Type Test P Packer TVD 4537 BBL Pump 1.4 IA 69 1696 1651 1643 Interval O Test psi 1500 BBL Return 1.3 OA 71 170 174 174 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 1971890 Type Inj N Tubing 408 411 408 408 Type Test P Packer TVD 4589 BBL Pump 0.8 IA 137 1734 1706 1702 Interval O Test psi 1500 BBL Return 0.8 OA 79 83 82 84 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2071170 Type Inj W Tubing 1496 1490 1480 1488 Type Test P Packer TVD 4461 BBL Pump 1.3 IA 47 1696 1654 1658 Interval O Test psi 1500 BBL Return 1.3 OA 53 302 291 291 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: Hilcorp Alaska LLC Prudhoe Bay / PBU / X Pad Oliver Sternicki 07/21/22 Notes: Notes: Notes: Notes: GNI-02A GNI-03 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mec hanical Integrity Tes t jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: GNI-04 Notes: Annual EPA MIT-IA. Witnessed by Ryan Gross from the EPA Annual EPA MIT-IA. Witnessed by Ryan Gross from the EPA Annual EPA MIT-IA. Witnessed by Ryan Gross from the EPA Notes: Form 10-426 (Revised 01/2017)2022-0721_MIT_PBU_GNI-pad_3wells GNI-04 VS -1, . PROACTIVE DIAgNoST1G SERVICES, INC. WELL LOG TRANSM17 TAL To: AOGCC Natural Resources Technician 333 W. 7th Ave Suite 100 Anchorage, Alaska 99501 (907) 793-1225 RE: Cased Hole/Open Hole/Mechanical Logs and /or Tubing Inspection (Caliper / MTT) The technical data listed below is being submitted herewith. Please acknowledge receipt by returning a signed copy of this transmittal letter to the attention of : 1) Press/Temp Su 2) Signed Print Name: BP Exploration (Alaska), Inc. Petrotechnical Data Center Attn: Merion Kendall LR2 — 1 900 Benson Blvd. Anchorage, AK 99508 GANCPDCc USAANC.hou.xwh.BP.com and ProActive Diagnostic Services, Inc. Attn: Diane Williams 130 West International Airport Road Suite C Anchorage, AK 99518 Fax: (907)245-8952 20 1 17 30 94 7 RECEIVED JUL 0 3 2019 AOGCC 16 -May -19 GNI-04 /`\ BL/CD 50-029-23367-00 L't Date : O / I PROACTIVE DIAGNOSTIC SERVICES, INC., 130 W. INTERNATIONAL AIRPORT RD SUITE C, ANCHORAGE, AK 99518 PHONE: (907)245-8951 FAX: (907)245-8952 E-MAIL: PDSANCHORAGEi MEMORANDUM TO: Jim ReggG 1 -7 -7 l!cn-o P.I. Supervisor FROM: Guy Cook Petroleum Inspector NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Wednesday, June 24, 2020 SUBJECT: Mechanical Integrity Tests BP Exploration (Alaska) Inc. GNI-04 PRUDHOE BAY UN UGN GNI-04 Src: Inspector Reviewed By: P.I. Supry Comm Well Name PRUDHOE BAY UN UGN GNI-04 API Well Number 50-029-23367-00-00 Inspector Name: Guy Cook Permit Number: 207-117-0 Inspection Date: 6/16/2020 IBSp Num: mi[GDC200616070I59 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min GNI-04 Type Iul -TVD 4461 Tubing 1566 1567- 1567- - 1566 ' F 2071170 Type Test SPT Test psi 1500 IA 10 2383 2318, 2310mped: 6 BBL Returned: 2.5 OA 160 529 517 514 OTHER Notes: Annual Class I disposal well EPA test. Testing performed with a Little Red Services pump truck and calibrated gauges. The N2 cap was bled off of the IA and a fluid shot was taken to show the fluid level was approximately 170' below surface. The well should take approximately 4.4 bbis to fill. Ryan Gross with the EPA witnessed this test remotely via ZOOM from Seattle. Wednesday, June 24, 2020 Page 1 of 1 x,07— t '7 b • p RECEIVES AUG 10 2017 0 ABP Exploration(Alaska)Inc. V'V 906 East Benson Boulevard P.O. Box 196612 Anchorage.Alaska 99519-6613 (907)561-5111 August 8, 2017 UIC Manager, Ground Water Protection Unit SCANNED AUG 1 12017 U.S. Environmental Protection Agency (OCE-127) 1200 Sixth Avenue, Suite 900 Seattle, WA 98101 Re: Demonstration of Mechanical Integrity, Prudhoe Bay Grind and Inject, UIC Class I Permit AK-11008-A Dear UIC Manager: This letter is to submit the results of recent fluid movement tests and the annulus pressure test results for the three UIC Class I GNI wells located at the Prudhoe Bay Grind and Inject project operated by BP Exploration (Alaska), Inc (BPXA). The tests are specified as part of the demonstration of mechanical integrity under Part II, C.3 b of EPA UIC Class I permit AK11008-A. The enclosed descriptive and interpretive report contains the results for the following logs and tests as required under Part II, C.3.c(1) of the permit: - Fluid Movement Test: GNI-02A, GNI-03, and GNI-04 (Page 16, Part II, C.3.b(2)) - Annulus Pressure Tests: GNI-02A, GNI-03, and GNI-04 (Page 16, Part II, C.3.b(1)) There was no indication of a loss of well integrity. 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. BPXA understands that the EPA will notify BPXA of the acceptability of the mechanical integrity demonstration within 13 days of receipt of the results of the mechanical integrity tests (Part II, C.3.c.(4)). Injection may continue during this 13 day review period. If the EPA does not respond within 13 days, we will conclude that the results are acceptable and will continue with injection. If you have questions, please contact Carrie Janowski, Intervention & Integrity Specialist, at (907) 564-5273. Sincerely, e'.A'..J ri Wendy B_osmans East Area Operating Manager • • Cc: Evan Osborne, EPA Region 10 (letter and report) Chris Wallace, AOGCC (letter and report) Marc Bentley, ADEC (letter and report) Attachments: Demonstration of Mechanical Integrity Report Schlumberger GNI-02A Temperature and Pressure Survey, July 17, 2017 Halliburton GNI-03 Memory Temperature and Pressure Survey, June 27, 2017 Halliburton GNI-04 Memory Temperature and Pressure Survey, July 26, 2017 Annulus Pressure Test Results • Demonstration of Mechanical Integrity Prudhoe Bay Grind and Inject Project EPA permit AK-1I008-A effective 09/01/07 requires a fluid movement tests in the Prudhoe Bay Unit Class I Grind & Inject wells each calendar year. Approved fluid movement tests(Part II C 3 b (2)) include tracer surveys, temperature logs, noise logs, oxygen activation/water flow logs, borax pulse neutron logs (PNL)or other logs. The permit also requires a standard annulus pressure test(SAPT). Below are the results of logs and tests run recently in the GNI wells. Fluid Movement Tests Wellbore temperatures are affected by the temperature of the injected fluids by conduction and/or convection. When the well is injecting fluids, the wellbore and the adjacent formation reaches a temperature near the injection fluid temperature due to conductive heat transfer. When injection ceases, the wellbore temperature begins to return toward its original temperature. The rate of temperature change of the shut-in well will depend on the original formation temperature, the injection fluid temperature and the rate and cumulative volume of injection. In the GNI wells, the injected fluids are typically colder than the formation temperatures below about 4000 ft TVD. In areas where the injected fluids enter the formation, both conduction and convective heat transfer are involved. The amount of rock cooling is much larger and the rate of temperature change after shut-in is much slower due to the direct contact of the formation with the cold fluid. Channeling adjacent to the wellbore is evident because cooler injected fluids leak off into formations throughout the length of the channel. Several types of logging tools are available to be used to record the temperatures of the wellbore fluids: tools run on electric line with a real-time surface readout and memory tools run on slick line. The results from these instruments are presented in the enclosed logs of borehole temperature and pressure versus measured depth. Typical Shut-In Temperature Survey Procedure EPA permit AK-11008-A requires fluid movement tests surveys to "... be conducted at injection pressure at least equal to the average continuous injection pressure observed in the previous 6 months." Injection is cycled into the GNI wells on a rotating basis, with one well injecting at a time. The average and maximum injection pressures are reported quarterly on Form 7520-8. The survey Procedure generally involves the following steps: • Inject a significicant volume of cold water or slurryat the required pressure followed by a period of stabilized injection. • Shut—in the well after the injection cycle. • After at least 5 days of shut-in time, rig up prepare logging tools • Confirm depth control by comparing to the tie-in log on record. • Run the shut-in temperature/pressure survey • Compare the logged temperatures to previously shut in logs run in the well. The GNI wells normally inject cold slurry or cold water at 50-70 degrees F. The original formation temperature of the target disposal formation was about 115 degrees F. The Shut-In Temperature log technique is commonly used for cement channel detection in • • injection wells on the North Slope of Alaska and has been used to satisfy the GNI fluid movement test requirement as a demonstration of mechanical integrity. GNI-02A Shut-In Temperature Survey Results—reference Schlumberger GNI-02A Pressure and Temperature Survey (GR/CCL/Press/Temp/FBS) from July 17, 2017. The log trace was run from the total depth of the well to the surface. The average daily injection pressure in well GNI-02A over the 6 months prior to its survey was 1261 psi. Wellhead injection pressures exceeded this average pressure during the injection cycle prior to the survey. GNI-02A was shut in for approximately 42 days before the temperature/pressure survey. The shut-in temperature trace indicates increasing temperature with depth to about 7450' feet measured depth (MD) or 6080 feet true vertical depth (TVD). Below that point, temperature starts declining until fill level was reached or just above the perforated interval. Based on this data, there is no evidence of injected fluid movement above about 6080' TVD. GNI-03 Shut-In Temperature Survey Results—reference Halliburton GNI-03 Memory Pressure and Temperature Survey(GR/CCL/Press/Temp) from June 27, 2017. The log trace was run from the fill level in the well to the surface. The average daily injection pressure in well GNI-03 over the 6 months prior to its survey was 1237 psi. Wellhead injection pressures exceeded this pressure during the injection cycle prior to the survey. GNI-03 was shut in for approximately 14 days before the temperature/pressure survey. The shut-in temperature trace indicates increasing temperature with depth to about 6720' feet measured depth (MD) or 6099' feet true vertical depth (TVD). Below that point, the temperature decreases until the fill level was reached or just above the perforated interval. Based on this data, there is no evidence of injected fluid movement above about 6099' TVD. GNI-04 Shut-In Temperature Survey Results—reference Halliburton GNI-04 Memory Temperature Survey(GR/CCL/Press/Temp) from July 26, 2017. The log trace was run from fill level in the well to the surface. The average daily injection pressure in well GNI-04 over the 6 months prior to its survey was 1185 psi. Wellhead injection pressures exceeded this pressure during the injection cycle prior to the survey. GNI-04 was shut in for approximately 15 days before the temperature/pressure survey. The shut-in temperature trace indicates increasing temperature with depth to about 6640' feet measured depth(MD) or 6032' feet true vertical depth (TVD). Below that point,the termperature decreased until the fill level was reached or just above the perforated interval. Based on this data, there is no evidence of injected fluid movement above about 6032' TVD. • S Annulus Pressure Test Results Annulus pressure tests were performed on UIC Class I Prudhoe Bay Grind and Inject disposal wells GNI-02A, GNI-03 and GNI-04 on July 31, 2017. The tests were performed in accordance with the stipulations of Class I permit AK-11008-A. In each well, the nitrogen cushion normally maintained in the tubing - casing annulus was bled off and displaced with diesel prior to the test. The annulus was then pressured to above 1500 psi with diesel and observed for 30 minutes. The tests were conducted while all of the wells were shut in. The test results were as follows: Tubing Pressure Annulus Pressure psi 1st Half 2nd Half Test GNI Well Start/ End Start 15 Min 30 Min Decline Decline Result GNI-02A 347/345 1802/1752/1743 50 9 Pass GNI-03 250/249 1797/1762/1753 35 9 Pass GNI-04 268/267 1795/1723/1701 72 22 Pass In wells GNI-02A, GNI-03 and GNI-04, the pressure decline was less than 10 percent during the test period, with not more than 1/3 of the total decline in the second half of the 30 minute period. This data shows a stabilizing tendency as specified in EPA Permit AK-11008-A, Part II, C.3.b (1). Annulus pressures were observed on a recording digital test gauge. During the test period, the tubing pressure was essentially constant. The GNI-02A, GNI-03 and GNI-04 annulus pressure tests indicate the casing, tubing and packer are in sound mechanical condition. This is consistent with the absence of any indication of tubing or packer leakage during normal injection oeprations when there is a large pressure differential (>500 psi) between the tubing and the annulus in each of he wells. The tests were witnessed by EPA representatives Evan Osborne and Jason Selitsch. Carrie Janowski, Intervention & Integrity Specialist August 3, 2017 • bp Certified Mail: 7016 0910 0001 1040 6356 BP Exploration(Alaska)Inc. 900 East Benson Boulevard P.O.Box 196612 Anchorage,Alaska 99519-6612 July 19, 2017 (907)561-5111 UIC Manager, Ground Water Protection Unit RECEIVED U.S. Environmental Protection Agency (OCE-127) .JUL 2 0 2017 1200 Sixth Avenue, Suite 900 Seattle, WA 98101 AOGCC Re: Demonstration of Mechanical Integrity, Prudhoe Bay Grind and Inject UIC Class I Permit AK-1I008-A GNI-04 & GNI-02A Caliper w • 1 I Dear UIC Manager: Cit%Ir This letter is to submit the results of recent tubing inspection logs ran in UIC Class I wells GNI-04, GNI-02A, and GNI-03, located at the Prudhoe Bay Grind and Inject project operated by BP Exploration (Alaska), Inc (BPXA). These tests are specified as part of the demonstration of mechanical integrity under Part II, C.3 b of EPA UIC Class I permit AK11008-A. The enclosed descriptive and interpretive report contains the results for the following logs as required under Part II, C.3.c(1) of the permit: Tubing Inspection Log: GNI-04 (Page 16, Part II, C.3.b(3)) - Tubing Inspection Log: GNI-02A (Page 16, Part II, C.3.b(3)) - Tubing Inspection Log: GNI-03 (Page 16, Part II, C.3.b(3)) There was no indication of a loss of well integrity. 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. BPXA understands that the EPA will notify BPXA of the acceptability of the mechanical integrity demonstration within 13 days of receipt of the results of the mechanical integrity tests (Part II, C.3.c.(4)). Injection may continue during this 13 day review period. If the EPA does not respond within 13 days, we will conclude that the results are acceptable and will continue with injection. SCANNED JUL 2 7 2017 • S If you have questions, please contact Carrie Janowski, Intervention"& Integrity Specialist at (907) 564-5273. Sincerely, i L:y Bosun East Area Operating Manager Cc: Evan Osborne, EPA Region 10 (letter and report) Chris Wallace, AOGCC (letter and report) Marc Bentley, ADEC (letter and report) Attachments Demonstration of Mechanical Integrity Report GNI-04 Memory multi-finger caliper log, June 11, 2017 GNI-02A Memory multi-finger caliper log, June13, 2017, and June 28, 2017 GNI-03 Memory multi-finger caliper log, June 26, 2017 • 411 Demonstration of Mechanical Integrity Prudhoe Bay Grind and Inject Project EPA permit AK-1I008-A effective 09/01/07 requires a tubing inspection log in the Prudhoe Bay Unit Class I Grind& Inject wells annually.Approved tubing inspection logs (Part II C 3 b (3)) include pipe analysis logs, caliper logs or other equivalent tests. Tubing Inspection Logs A 40 arm caliper logging tool, supplied by Halliburton, was run on slickline to inspect the interior surface of both the tubing and the casing, on the GNI wells. A memory caliper log was run in well GNI-04 on June 11, 2017 to evaluate the tubing and casing. The 7"tubing looks to be in good to fair condition with a range of damage between 20-36%recorded. The 9 5/8"casing below the tubing tail looks to be in good condition with a range of damage between 15-27%recorded. A memory caliper log was run in well GNI-02A on June 13, 2017 to evaluate the tubing and on June 28, 2017, to evaluate the casing. The 7"tubing looks to be fair condition with a range of damage between 20-34%recorded. The 9 5/8"casing looks to be in decent condidiont with a range of damage between 20- 46%recorded. A memory caliper log was run in well GNI-03 on June 26, 2017 to evaluate the tubing and casing. The 7"tubing looks to be in decent condition overall with a range of damage between 20 -40%recorded, with the hightest recorded damage of 53%recorded. The 9 5/8"casing below the tubing tail looks to have moderate ring damage throughout with a range of damage between 40-60%recorded. Below are the observed maximum metal losses observed in the tubing and casing from the caliper logs. Well Date Maximum Wall Penetration Max Cross-Sectional Wall Loss GNI-04 Tubing 06/11/17 36% 19% GNI-04 Casing 06/11/17 27% 6% GNI-02A Tubing 06/13/17 34% 26% GNI-02A Casing 06/28/17 46% 20% GNI-03 Tubing 06/26/17 53% 27% GNI-03 Casing 06/26/17 50% 22% Enclosed are copies of the Halliburon Memory Multi-Finger Caliper log results summary for each well. Overall Conclusions The GNI-04 caliper log indicates the tubing has maximum penetration of 36% but it is suitable for continued injection. The GNI-02A caliper log indicates the tubing has maximum penetration of 34% but it is suitable for continued injection. The GNI-03 caliper log indicates the tubing has maximum penetration of 53% but it is suitable for continued injection. Carrie Janowski, Intervention& Integrity Specialist July 12, 2017 ez-a -7 ^ k bp CERTIFIED MAIL# 7016 0910 0001 1040 7001 APR 1 3 2017 BP Exploration(Alaska)Inc. April 13, 2017 P.O.Box 196612 900 E.Benson Boulevard Anchorage,AK 99519-6612 USA 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 RF: Mechanical Integrity Test Notifications Pad 3 Injection Wells, UIC Permit AK-11004-B, Wastewater Disposal, Permit No. 2010DB0001-0021 Grind and Inject Injection Wells, UIC Permit AK-11008-A, Area Injection Order No. 4G, General Wastewater, Permit No. 2010DB001-0012 Dear Sirs: BP Exploration (Alaska) Inc. (BPXA) respectfully submits the following notification of well surveillance activities to satisfy demonstration of mechanical integrity requirements for the Class 1 UIC permits mentioned above: 1) SAPT (Standard Annulus Pressure Test) 2) Fluid movement tests 3) Tubing inspection logs. 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. 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. Mechanical Integrity Tes.tification • April 13, 2017 Page 2 A summary of the proposed annual testing is presented in the attached table. If you have any questions, please contact me at (907) 564-4613 or tom.harvey@bp.com ..._-)S‘')Vvv\V--4041-0)?c/ Thomas J Harvey, CHMM Regulatory and Permitting Advisor-Waste/UIC Attachment cc: Evan Osborne, EPA Region 10 Mechanical Integrity Teseytification • • April 13, 2017 Page 3 Certification Statement Mechanical Integrity Test Notification 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 possibility of fine and imprisonment. 4/11/r4Respo Company Official Date Wendy Bosmans East Area Operations Manager BP Exploration Alaska) Inc. Printed Name Title Company Mechanical Integrity Tesiltification . • April 13, 2017 Page 4 bcc (hard copy, with enclosure): Pad 3 File [1007.01.26] Grind & Inject File [1007.02.011 bcc (electronic, enclosure): Carrie Janowski AK, HSSEE Env Adv Central • • Proposed Schedule for 2017 Demonstration of Mechanical Integrity Activities Class I UIC Wells Class I Well Activity Next Deadline 2017 Proposed test Notes (s) /Requirement date Pad 3— Caliper 8/24/18 7/27/17 OWDW-NW&C OWDW-NW, C OWDW-SE (every 2 years) wells have lined and SE Wells tubing Borax-RST 8/31/18 OWDW-SE 7/31/17 Order which wells logging (every 2 years) OWDW-NW 8/1/17 are tested could OWDW-C 8/2/17 change SAPT 8/30/17 8/3/17 Plan to test (Standard (annually, 3 month OWDW-NW, -C, &- annulus grace period at Director SE wells on same pressure discretion) day testing) BP calls MITIA Grind & Inject Tag fill & 2017 GNI-02A 6/3/17 Order which wells —GNI-02A, temperature (each calendar year) GNI-03 6/16/17 are tested could 03, and -04 survey GNI-04 6/28/17 change. Tag fill, memory temperature/ pressure logs and Caliper will be run Caliper 2017 GNI-02A 6/3-6/4/17 on same Slickline (annually, no monthly GNI-03 6/16-6/17/17 rig up if possible. requirement) GNI-04 6/28-6/29/17 SAPT 8/29/17 7/28/17 Plan to test GNI- (Standard (required annually, one 02A, -03, -04 wells annulus month grace period) on same day pressure testing) BP calls MITIA bl -1 \1 RECO V D by SEP 262016 Certified Mail: 7016 0750 0000 4951 8830 September 23, 2016 " " GC BP Exploration(Alaska)Inc. UIC Manager, Ground Water Protection Unit P.O.Box 196612 900 E Benson BoulevardU.S. Environmental Protection Agency(OCE-127) Anchorage,AK 99519-6612 1200 Sixth Avenue, Suite 900 USA Seattle, WA 98101 Dear UIC Manager: This letter is to submit the results of a recent tubing inspection log and fluid movement test in UIC Class I well GNI-04, and the annulus pressure test results for the three UIC Class I GNI wells located at the Prudhoe Bay Grind and Inject project operated by BP Exploration (Alaska), Inc (BPXA). The tests are specified as part of the demonstration of mechanical integrity under Part II, C.3 b of EPA UIC Class I permit AK11008-A. The enclosed descriptive and interpretive report contains the results for the following logs and tests as required under Part II, C.3.c(1) of the permit: - Tubing Inspection Logs: GNI-04 (Page 16, Part II, C.3.b(3)) - Fluid Movement Test: GNI-04 (Page 16, Part II, C.3.b(2)) - Annulus Pressure Tests: GNI-02A, GNI-03, and GNI-04 (Page 16, Part II, C.3.b(1)) There was no indication of a loss of well integrity. 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. BPXA understands that the EPA will notify BPXA of the acceptability of the mechanical integrity demonstration within 13 days of receipt of the results of the mechanical integrity tests (Part II, C.3.c.(4)). Injection may continue during this 13 day review period. If the EPA does not respond within 13 days, we will conclude that the results are acceptable and will continue with injection. If you have questions, please contact Carrie Janowski, Intervention & Integrity Specialist at (907) 564-5273. Sincerely,a� ,,�( SCANNED 7 Chris Fortenberry East Area Engineering Team Lead Cc: Evan Osborne, EPA Region 10 (letter and report) Chris Wallace, AOGCC (letter and report) Marc Bentley, ADEC (letter and report) • S Demonstration of Mechanical Integrity Prudhoe Bay Grind and Inject Project EPA permit AK-1I008-A effective 09/01/07 requires a tubing inspection log in the Prudhoe Bay Unit Class I Grind& Inject wells annually.Approved tubing inspection logs(Part II C 3 b (3)) include pipe analysis logs, caliper logs or other equivalent tests. The permit also requires a fluid movement test in each well each calendar year. Approved fluid movement tests(Part II C 3 b(2))include tracer surveys,temperature logs, noise logs, oxygen activation/water flow logs, borax pulse neutron logs(PNL)or other logs.Below are the results of a log and test run recently in well GNI-04. Tubing Inspection Logs A 40 arm caliper logging tool, supplied by PDS (ProActive Diagnostic Services), is run on slickline to inspect the interior surface of both the tubing and the casing. A memory caliper log was run in well GNI-04 on August 10, 2016. The GNI-04 tubing is in good to fair condition with a maximum wall penetration up to 35%and a maximum cross sectional wall losss of 19% metal volume recorded. The casing below the tubing tail is in fair condition. Below are the observed maximum metal losses observed in the tubing and casing from the caliper logs. Well Date Maximum Wall Penetration Max Cross-Sectional Wall Loss GNI-04 Tubing 08/10/16 35% 19% GNI-04 Casing 08/10/16 34% 14% Enclosed are copies of the PDS Memory Multi-Finger Caliper, Log Results Summary for this well. • • Fluid Movement Tests Wellbore temperatures are affected by the temperature of the injected fluids by conduction and/or convection. When the well is injecting fluids,the wellbore and the adjacent formation reaches a temperature near the injection fluid temperature due to conductive heat transfer. When injection ceases,the wellbore temperature begins to return toward its original temperature. The rate of temperature change of the shut-in well will depend on the original formation temperature,the injection fluid temperature and the rate and cumulative volume of injection. In the GNI wells,the injected fluids are typically colder than the formation temperatures below about 4000 ft TVD. In areas where the injected fluids enter the formation, both conduction and convective heat transfer are involved. The amount of rock cooling is much larger and the rate of temperature change after shut-in is much slower due to the direct contact of the formation with the cold fluid. Channeling adjacent to the wellbore is evident because cooler injected fluids leak off into formations throughout the length of the channel. Several types of logging tools are available to be used to record the temperatures of the wellbore fluids: tools run on electric line with a real-time surface readout and memory tools run on slick line. The results from these instruments are presented in the enclosed logs of borehole temperature and pressure versus measured depth. Typical Shut-In Temperature Survey Procedure EPA permit AK-1I008-A requires fluid movement tests surveys to "... be conducted at injection pressure at least equal to the average continuous injection pressure observed in the previous 6 months." Injection is cycled into the GNI wells on a rotating basis,with one well injecting at a time. The average and maximum injection pressures are reported quarterly on Form 7520-8. The survey procedure generally involved the following steps: - Inject a significant volume of cold water or slurry at the required pressure. - Shut-in after the injection cycle. Freeze protect the well. - After at least 5 days of shut in time, rig up logging tools and pressure test lubricator. - Confirm depth control by comparing to the tie-in log on record. - Run the shut-in temperature/pressure survey. Rig down and move off. - Compare the logged temperatures to previous shut in logs run in the well. The GNI wells normally inject cold slurry or cold water at 50-70 degrees F. The original formation temperature of the target disposal formation was about 115 degrees F. The Shut-In Temperature log technique is commonly used for cement channel detection in injection wells on the North Slope of Alaska and has been used to satisfy the GNI fluid movement test requirement as a demonstration of mechanical integrity. Due to a seawater pipeline integrity issue in April 2016,the GNI facility wells went on an approximate 3 month injection period using produced water(warmer than target disposal formation)to continue normal disposal operations. This resulted in the inability to inject significant volumes prior to shutting in the wells and created longer than normal shut in times prior to logging. • • GNI-04 Shut-In Temperature Survey Results—reference PDS GNI-04 Memory Temperature Survey(GR/CCL/Press/Temp), 10-August-2016. Note: the depths referenced below refer to the printed log. The enclosed log trace was run from the fill level in the well to the surface. The log contains the following traces: casing collar locator, gamma ray,temperature and pressure. The average daily injection pressure in well GNI-04 over the 6 months prior to its survey was 814 psi. Wellhead injection pressures exceeded this pressure during the injection cycle prior to the survey. The last injection cycle between 05/15 and 06/03/16 was utilizing produced water which created injection temperatures ranging from 80-130° F. GNI-04 was shut in for approximately 61 days before the temperature/pressure survey. The shut-in temperature trace indicates increasing temperature with depth to about 6750 feet measured depth(MD)or 6129 feet true vertical depth(TVD). Temperatures then decline with depth to about 7075 feet MD or 6416' TVD.Below that point,the temperature increases again until the fill level was reached within or just above the perforated interval. Based on this data,there is no evidence of injected fluid movement above about 6129' TVD,and little or no movement above 6416' TVD.The effect of injecting warm produced water after a 61 day shut-in time is illustrated in the chart below. • • A plot of the temperature log data from 2016 along with other GNI-04 logs is shown below. Exhibit 7d: GNI-04 Shut In Temperature Logs 130 I Pettsfea i 1 ----1k 1722108 81 20 • -n-146r12,109WI -•-$1471U911111d 'may #46+21129WI 110 -- #4,301138 WI r--$4 7(06114 810 -4-44 43015 7 tta SI 100 —•-4d 9111118 614a- U. • f� .- 90 I,' \ 11, 80 60 4■ 50 r . , , , , . , 4000 4500 5000 5500 6000 6500 7000 True Vertical Depth feet Demonstration of Mechanical Integrity Prudhoe Bay Grind and Inject Project Annulus Pressure Test Results Annulus pressure tests were performed on UIC Class I Prudhoe Bay Grind and Inject disposal wells GNI-02A, GNI-03 and GNI-04 on September 29, 2016. The tests were performed in accordance with the stipulations of Class I permit AK-11008-A. In each well, the nitrogen cushion normally maintained in the tubing - casing annulus was bled off and displaced with diesel prior to the test. The annulus was then pressured to above 1500 psi with diesel and observed for 30 minutes. The tests were conducted while all of the wells were shut in. The test results were as follows: Tubing Pressure Annulus Pressure psi 1st Half 2nd Half Test i • GM Well Start/End Start 15 Min 30 Min Decline Decline Result GNI-02A 538/532 1802 1752 1743 50 9 Pass GNI-03 470/468 1780 1749 1742 31 7 Pass GNI-04 256/256 1800 1750 1740 50 10 Pass In wells GNI-02A, GNI-03 and GNI-04, the pressure decline was less than 10 percent during the test period, with not more than 1/3 of the total decline in the second half of the 30 minute period. This data shows a stabilizing tendency as specified in EPA Permit AK-11008-A, Part II, C.3.b(1). Annulus pressures were observed on a recording digital test gauge. During the test period, the tubing pressure was essentially constant. The tests were witnessed by EPA representatives Jason Selitsch and Tim Mayers. • • OVERALL CONCLUSIONS The GNI-04 caliper log indicates the tubing has maximum penetration of 35% but it is suitable for continued injection. The GNI-04 shut-in temperature log indicates no movement of injected fluids above about 6129' TVD. The GNI-02A, GNI-03 and GNI-04 annulus pressure tests indicate the casing, tubing and packer are in sound mechanical condition. This is consistent with the absence of any indication of tubing or packer leakage during normal injection oeprations when there is a large pressure differential (>500 psi) between the tubing and the annulus in each of the wells. Carrie Janowski, Intervention& Integrity Specialist September 9, 2016 RECEIVED bp SEP 262016 Certified Mail: 7016 0750 0000 4951 8809 AOGCC BP Exploration(Alaska)Inc. September 23, 2016 P.O.Box 196612 900 E.Benson Boulevard Anchorage,AK 99519-6612 UIC Manager, Ground Water Protection Unit USA U.S. Environmental Protection Agency 1200 Sixth Avenue, Suite 900 Seattle, WA 98101 Re: Revision Demonstration of Mechanical Integrity, Prudhoe Bay Grind and Inject, UIC Class I Permit AK-11008-A Dear UIC Manager: On August 23, 2016, BP Exploration (Alaska), Inc (BPXA) submitted tubing inspection log and fluid movement tests for UIC Class I well GNI-02A at the Prudhoe Bay Grind and Inject facility under permit AK11008-A. BPXA has discovered that the Shut-In Temperature Survey chart submitted with this report was missing five data points.The missing data points do not affect the overall conclusions of the data but the characteristics of the graph have changed slightly. Attached is a revised temperature survey chart as well as corrections to the associated results language in bold text. 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 have questions, please contact Carrie Janowski, Intervention & Integrity Specialist, at (907) 564-5273. Sincerely, SCANNED Chris Fortenberry East Area Engineering Team Lead Cc: Evan Osborne, EPA Region 10 (letter and report) Jim Regg, AOGCC (letter and report) Marc Bentley, ADEC (letter and report) Attachments: Demonstration of Mechanical Integrity Report Revision PDS GNI-02A Memory Temperature and Pressure Survey, July 19, 2016 Revised GNI-02A Shut-In Temperature Survey Results GNI-02A Shut-In Temperature Survey Results—reference PDS GNI-02A Memory Temperature Survey (GR/CCL/QTS/PRT) from July 19, 2016. Note: the depths referenced below refer to the printed log. The enclosed log trace was run from the fill level in the well to the surface. The log contains the following traces: casing collar locator, gamma ray,temperature and pressure. The average daily injection pressure in well GNI-02A over the 6 months prior to its survey was 1054 psi. Wellhead injection pressures exceeded this pressure during the injection cycle prior to the survey. The last injection cycle between 06/03/16 and 06/17/16 was utilizing produced water which created injection temperatures ranging from 80-130°F. GNI-02A was shut in for approximately 31 days before the temperature/pressure survey. The shut-in temperature trace indicates increasing temperature with depth to about 7650 feet measured depth (MD) or 6206 feet true vertical depth(TVD). Temperatures then dip slightly to about 7850 feet MD or 6338 feet TVD and continue to decrease until 8075 feet MD or 6488 feet TVD. Below that point,the temperature increases slightly until the fill level was reached within or just above the perforated interval. Based on this data,there is no evidence of injected fluid movement above about 6206 feet TVD, and little or no movement above 6338' TVD. The effect of injecting produced water after a 31 day shut- in time is illustrated in the chart below. A plot of the temperature log data from 2016 along with previous GNI-02A logs is shown below. Revised 2016 GNI-02A Shut In Temperature Logs 130 I JewahyPerfs 120 —8--2 62-28-9 6 ,.� c — —2Al2-24-06 a —*--2A 06-30-1012da SI ,...:...7 ..a�:. 110 * 2A 10-22118 da SI ,a'y +� 2A 07-07-12 1 3da S —+-2A07•8.137daSI — 100 2A 07-21-144 da SI --+-2A08-26.159daSi . U. LL — 2A07.141631daSlr.^ . a a= *** a ,,,,,,,,,...---..............\\*i * 70 -tiag l� f 60 ..`' -2NI • • _ 4000 4500 5000 5500 6000 6500 7000 True Vertical Depth tt Overall Conclusions The GNI-02A shut-in temperature log indicates no movement of injected fluids above about 6206' TVD. Carrie Janowski, Intervention& Integrity Specialist September 9, 2016 • 2-.0 -\\-1 2"lCj245 WELL LOG TRANSMITTAL PROACTIVE DIAGNOSTIC SERVICES, INC. DATA LOGGED 141201(0 K. BENDER To: AOGCC Makana Bender RECEIVED 333 W. 7th Ave SEP 0 8 ��i; Suite 100 Anchorage, Alaska 99501 (907) 793-1225 AOGCC RE : Cased Hole/Open Hole/Mechanical Logs and/or Tubing Inspection(Caliper/MTT) The technical data listed below is being submitted herewith. Please acknowledge receipt by returning a signed copy of this transmittal letter to the attention of: BP Exploration (Alaska), Inc. Petrotechnical Data Center Attn: Merlon Kendall LR2-1 900 Benson Blvd. Anchorage, AK 99508 SCANNED NOV p 0s gancpdc(c bp.com and ProActive Diagnostic Services, Inc. Attn: Ryan C. Rupe 130 West International Airport Road Suite C Anchorage, AK 99518 Fax: (907) 245-8952 1) Pressure/Temp Survey 11-Aug-16 GNI-04 BL /CD/Report 50-029-23367-00 2) Signed : Q •Ozol.4 0 Date : Print Name: PROACTIVE DIAGNOSTIC SERVICES, INC., 130 W.INTERNATIONAL AIRPORT RD SUITE C, ANCHORAGE, AK 99518 PHONE: (907)245-8951 Fax: (907)245-8952 E-MAIL: PDSANCHORAGEOMEMORYLOG.COM WEBSITE:WWW.MEMORYLOG.COM D:\Achives\MasterTemplateFi les\Templates\Distribution\TransmittalSheets\BP_Transmit.docx 1ASAS �,'�i ►Ag iv os.„ . -75:- PROACTIVE c likr; PROACTIVE UTACiNOSTIC SERVICES Static Survey Temperature Pressure Chart Data GNI _ 04 Aug 11th, 2016 I • • 0 C•1 (N( 1 - W - O - �V5T5 a c)If - W N - tO M co O 0 I < °aN 0 0 . _ > m I - 06 a - cm I <"'ft d C _ Co - ro w 0 COc13 o« a) _ O c — c U) _ f 111 M CO _ 7 U) N - co E - °° d ,113 - CD - Co j CO - 1 y 91 01 O L 19 cri Q ' N - N i I O \ COI o 0 Co 0 U) 0 U) 0 u) 0 U) 0 1a 0 CI rn O O n N- O m N ID (N O O CO t0 In M N 0000000000 0 CO N N N N N N N N (N N 0) CO jd'Bea VISd a 4.1 1 ` 1 Q1 ',y N- '4) N O C) N Lt) .TN (O M .- O 00 N- O CO O O M ,- (0 00 M N- ,t M O C) co A- O C) O) C) C) co 00 00 co CO 00 00 N 0 CD I IVy U) r- O r- N O O N N N NV-c- r V- V- . 7- r 7- 7- C O :1.1 y O- co O (fl 00 co co h I- I,- f,- N- N- N- N- N- N- I- N- N- N- N- cg N C r N N N N N N N N N N N N N N N N N N N N IC u) co c I .. . .. y " rn • rn rn CC Tn .c 'rn r -, n n n CO l.L M M C)) U) N CO 00 CO r- 00 (O N T- V- C) 0 0 0 0 0 0 0 Ca -� 0J N 1 4) CO N O M N N N N N N N r N N N N N N M a) ` ` t 7 7 7 Q E0 N (f) t!7 st �7 d �t rf d tt cr C u) N to u) U d N N N H a_ d d 1ca co ca n QCZ a1 a) U = H c c m E . w °) -a < < 0 ca m m al 000000000000000000000Q� � � u) I o i m o V N ,c o %- NMv1.0Wr-. 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Q) m 1 _ o co I -- in c0 '7 ...., Il , C '''. ili +6 ° , , _ 0 o 0 „ „ I I Ctl (/) (13 ca. ta r (D000000000000 ,• ,• , oc,oc,00cnc.Qc.,00c.oc,c);') 00000000000000000 .” CV% 00)OD N.CO LO W C`I CNI,-- CO<-0)NIOCO%--01 N LI)CO 1-0)l's,LO c0 e- NC -0 lb .,-—,... -c34, cor,CNICNINCNIN,-,-N-e-e- L hl CO Cl_ ••4 j*Bea VISd I R FIVE b p AUG 2 5 2016 AOGCC 0 Certified Mail: 7016 0750 0000 4951 8748 BP Exploration(Alaska)Inc August 23, 2016 PO Box 196612 900 E Benson Boulevard Anchorage,AK 99519-6612 UIC Manager, Ground Water Protection Unit USA U.S. Environmental Protection Agency 1200 Sixth Avenue, Suite 900 Seattle, WA 98101 Re: Demonstration of Mechanical Integrity, Prudhoe Bay Grind and Inject, UIC Class I Permit AK-11008-A Dear UIC Manager: This letter is to submit the results of recent tubing inspection logs and fluid movement tests for UIC Class I well GNI-02A and GNI-03, two of UIC Class I GNI wells located at the Prudhoe Bay Grind and Inject project operated by BP Exploration (Alaska), Inc (BPXA). The tests are specified as part of the demonstration of mechanical integrity under Part II, C.3 b of EPA UIC Class I permit AK1I008-A. The enclosed descriptive and interpretive report contains the results for the following logs and tests as required under Part II, C.3.c(1) of the permit: - Tubing Inspection Logs: GNI-02A and GNI-03 (Page 16, Part II, C.3.b(3)) - Fluid Movement Test: GNI-02A and GNI-03 (Page 16, Part II, C.3.b(2)) There was no indication of a loss of well integrity. 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. BPXA understands that the EPA will notify BPXA of the acceptability of the mechanical integrity demonstration within 13 days of receipt of the results of the mechanical integrity tests (Part II, C.3.c.(4)). Injection may continue during this 13 day review period. If the EPA does not respond within 13 days, we will conclude that the results are acceptable and will continue with injection. If you have questions, please contact Carrie Janowski, Intervention & Integrity Specialist, at (907) 564-5273. Sincerely, Chris Fortenberry East Area Engineering Team Lead Cc: Evan Osborne, EPA Region 10 (letter and report) Jim Regg, AOGCC (letter and report) Marc Bentley, ADEC (letter and report) • • Attachments: Demonstration of Mechanical Integrity Report PDS GNI-02A Memory Multi-Finger Caliper Log Results Summary, July 19, 2016 PDS GNI-02A Memory Temperature and Pressure Survey, July 19, 2016 PDS GNI-03 Memory Multi-Finger Caliper Log Results Summary, July 21, 2016 PDS GNI-03 Memory Temperature and Pressure Survey, July 21, 2016 • • Demonstration of Mechanical Integrity Prudhoe Bay Grind and Inject Project EPA permit AK-11008-A effective 09/01/07 requires a tubing inspection log in the Prudhoe Bay Unit Class I Grind& Inject wells annually. Approved tubing inspection logs (Part II C 3 b (3)) include pipe analysis logs, caliper logs or other equivalent tests. The permit also requires a fluid movement test in each well each calendar year. Approved fluid movement tests(Part II C 3 b (2)) include tracer surveys,temperature logs, noise logs, oxygen activation/water flow logs, borax pulse neutron logs(PNL)or other logs. Below are the results of logs and tests run recently in well GNI-02A. Tubing Inspection Logs A 40 arm caliper logging tool, supplied by PDS (ProActive Diagnostic Services), is run on slickline to inspect the interior surface of both the tubing and the casing. A memory caliper log was run in well GNI-02A on July 19, 2016. The GNI-02A tubing is in fair condition with maximum wall penetration up to 37%and cross sectional metal loss up to 29%. The casing below the tubing tail is in fair condition. A memory caliper log was run in well GNI-03 on July 21, 2016. The GNI-03 tubing is in good to fair condition with maximum wall penetration up to 24%with no significant cross sectional metal loss recorded. The casing below the tubing tail is in fair to poor condition. Below are the observed maximum metal losses observed in the tubing and casing from the caliper logs. Well Date Maximum Pit Penetration Max Cross-Sectional Wall Loss GNI-02A Tubing 07/19/16 37% 29% GNI-02A Casing 07/19/16 35% 17% GNI-03 Tubing 07/21/16 24% >9% GNI-03 Casing 07/21/16 56% 26% Enclosed are copies of the PDS Memory Multi-Finger Caliper and Log Results Summary for these wells. 1111 • Fluid Movement Tests Wellbore temperatures are affected by the temperature of the injected fluids by conduction and/or convection. When the well is injecting fluids,the wellbore and the adjacent formation reaches a temperature near the injection fluid temperature due to conductive heat transfer. When injection ceases,the wellbore temperature begins to return toward its original temperature. The rate of temperature change of the shut-in well will depend on the original formation temperature, the injection fluid temperature and the rate and cumulative volume of injection. In the GNI wells, the injected fluids are typically colder than the formation temperatures below about 4000 ft TVD. In areas where the injected fluids enter the formation,both conduction and convective heat transfer are involved. The amount of rock cooling is much larger and the rate of temperature change after shut-in is much slower due to the direct contact of the formation with the cold fluid. Channeling adjacent to the wellbore is evident because cooler injected fluids leak off into formations throughout the length of the channel. Several types of logging tools are available to be used to record the temperatures of the wellbore fluids: tools run on electric line with a real-time surface readout and memory tools run on slick line. The results from these instruments are presented in the enclosed logs of borehole temperature and pressure versus measured depth. Typical Shut-In Temperature Survey Procedure EPA permit AK-1 1008-A requires fluid movement tests surveys to"... be conducted at injection pressure at least equal to the average continuous injection pressure observed in the previous 6 months." Injection is cycled into the GNI wells on a rotating basis, with one well injecting at a time. The average and maximum injection pressures are reported quarterly on Form 7520-8. The survey procedure generally involves the following steps: - Inject a significant volume of cold water or slurry at the required pressure. - Shut-in after the injection cycle. Freeze protect the well. - After at least 5 days of shut in time,rig up logging tools and pressure test lubricator. - Confirm depth control by comparing to the tie-in log on record. - Run the shut-in temperature/pressure survey. Rig down and move off. - Compare the logged temperatures to previous shut in logs run in the well. - Confirm depth control by comparing to the tie-in log on record. The GNI wells normally inject cold slurry or cold water at 50-70 degrees F. The original formation temperature of the target disposal formation was about 115 degrees F. The Shut-In Temperature log technique is commonly used for cement channel detection in injection wells on the North Slope of Alaska and has been used to satisfy the GNI fluid movement test requirement as a demonstration of mechanical integrity. Due to a seawater pipeline integrity issue in April 2016,the GNI facility wells went on an approximate 3 month injection period using produced water(warmer than target disposal formation)to continue normal disposal operations. This resulted in the inability to inject significant volumes prior to shutting in the wells and created longer than normal shut in times prior to logging. • • GNI-02A Shut-In Temperature Survey Results—reference PDS GNI-02A Memory Temperature Survey(GR/CCL/QTS/PRT) from July 19, 2016. Note: the depths referenced below refer to the printed log. The enclosed log trace was run from the fill level in the well to the surface. The log contains the following traces: casing collar locator, gamma ray,temperature and pressure. The average daily injection pressure in well GN1-02A over the 6 months prior to its survey was 1054 psi. Wellhead injection pressures exceeded this pressure during the injection cycle prior to the survey. The last injection cycle between 06/03/16 and 06/17/16 was utilizing produced water which created injection temperatures ranging from 80-130° F. GNI-02A was shut in for approximately 31 days before the temperature/pressure survey. The shut-in temperature trace indicates increasing temperature with depth to about 7650 feet measured depth (MD)or 6206 feet true vertical depth(TVD). Temperatures then decreased slightly with depth to about 8000 feet MD or 6370' TVD. Below that point,the temperature declined until the fill level was reached within or just above the perforated interval. Based on this data,there is no evidence of injected fluid movement above about 6206' TVD,and little or no movement above 6370' TVD. The effect of injecting produced water after a 31 day shut-in time is illustrated in the chart below. A plot of the temperature log data from 2016 along with previous GNI-02A logs is shown below. Exhibit 7b: GNI-02A Shut In Temperature Logs 130 • Jewe4ty+Petts 120 --+t--202-2S-$8L DNIA �.�2Al2-24060L 2A 06.3410 120 St 110 .r 2A 10.22.118 0a St +--2A 07-07-12 13da St --s--2A07.06.137daSt 100 so,.-2A07.21-tl90aSI 0111111. 2A 08.26-159 0s S1 LL --«-2A07.19-16310aSt "N% �s +s 90 JI� 3 eo �` 70 *'"" "tjt� 60 ". Ili • 50 . 4000 4500 5000 5500 6000 6500 7000 True Vertical Depth ft • • GNI-03 Shut-In Temperature Survey Results—reference PDS GNI-03 Memory Pressure and Temperature Survey(GR/CCL/Press/Temp)from July 21, 2016. Note: the depths referenced below refer to the printed log. The enclosed log trace was run from the fill level in the well to the surface. The log contains the following traces: casing collar locator, gamma ray, temperature and pressure. The average daily injection pressure in well GNI-03 over the 6 months prior to its survey was 1063 psi. Wellhead injection pressures exceeded this pressure during the injection cycle prior to the survey. The last injection cycle between 06/17/16 and 07/04/16 was utilizing produced water which created injection temperatures ranging from 80-130° F. GNI-03 was shut in for approximately 17 days before the temperature/pressure survey. The shut-in temperature trace indicates increasing temperature with depth to about 6850 feet measured depth(MD) or 6207 feet true vertical depth(TVD). Temperatures decrease slightly with depth to about 6950 feet MD or 6291' TVD and continue to decrease until 7225 feet MD or 6521feet TVD. Below that point, the temperature increases again until the fill level was reached within or just above the perforated interval. Based on this data, there is no evidence of injected fluid movement above about 6207' TVD,and little or no movement above 6291' TVD. The effect of injecting produced water after a 17 day shut- in time is illustrated in the chart below. A plot of the temperature log data from 2016 along with previous GNI-03 logs is shown below. Exhibit 7c: GNI-03 Shut In Temperature Logs 130 • per wimeay —6448 Banana 071111t09day Si 120 —+-06129/1*12 da ►--06113112 12 da S1 w 06/2211312 da$ 110 • 07,19416 7 day S1 71211201617 day St .* la 100 , 90 .. 80 t • s•4'•r r # . 70 L.44,44* 7,4 60 • • • • 50 . . . 4000 4500 5000 5500 6000 6500 7000 True Vertical Depth feet • Overall Conclusions The GNI-02A caliper log indicates the tubing has maximum penetration of 37% but it is suitable for continued injection. The GNI-02A shut-in temperature log indicates no movement of injected fluids above about 6206' TVD. The GNI-03 caliper log indicates the tubing has maximum penetration of 24% but it is suitable for continued injection. The GNI-03 shut-in temperature log indicates no movement of injected fluids above about 6207' TVD. Carrie Janowski, Intervention&Integrity Specialist August 8, 2016 • 01 -111 n lrEIVED2 4111 APR 29 2016 CERTIFIED MAIL# 7015 1730 0000 6058 3491 AOGGC BP Exploration(Alaska)Inc. P.O.Box 196612 April 26, 201 6 900 E.Benson Boulevard Anchorage,AK 99519-6612 USA 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 SCANNED Anchorage, AK 99501-3192 Mr. Marc Bentley Department of Environmental Conservation 555 Cordova St. Anchorage, AK 99501 RE: Mechanical Integrity Test Notifications Pad 3 Injection Wells, UIC Permit AK-11004-B, Wastewater Disposal, Permit No. 2010DB0001-0021 Grind and Inject Infection Wells, UIC Permit AK-11008-A, Area Injection Order No. 4E, General Wastewater, Permit No. 2010DB001-0012 Dear Sirs: BP Exploration (Alaska) Inc. (BPXA) respectfully submits the followingnotifications: 1) the p Y 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-B and 2) 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. 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) Mechanical Integrity•Notification April 26, 2016 Page 2 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 e-mail. If you have any questions, please contact me at (907) 564-4267 or Tom.Barrett@bp.com Sincerely, Tom Barrett Environmental Team Lead Attachment cc: Thor Cutler, EPA Region 10 Mechanical IntegrityID Notification April 26, 2016 Page 3 Certification Statement Mechanical Integrity Test Notification certifyI under u der 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 possibility of fine and imprisonment. Vim/ _A./ y/ze,//G Respon- • - Compar,.""fficial Date Gary Crawford Logistics/Infrastructure Manager BP Exploration Alaska) Inc. Printed Name Title Company III ♦ r • • Proposed Schedule for 2016 Mechanical Integrity Testing Class I Wells MIT Proposed MIT T test Flexibility in Fluid Deadline date test date? Movement Logs Planned after MIT? Pad 3— By Mid-September 2016 Yes Borax-RST logs OWDW-NW, C September for each well and SE Wells 21, 2016 for scheduled with NW, C and MIT's SE wells Caliper log in OWDW-SE in (Logging summer/fall may be 2016 extended up to 3 months with Director approval) Grind and Inject By Mid-September 2016 Yes Shut-In —GNI-02A, September Temperature GNI-03 and 20, 2016 for Logs and/or GNI-04 GNI-02A, Water Flow Logs GNI-03 and planned for GNI-04. summer/fall 2016 (May be extended 1 Caliper logs in month or at summer/fall Director 2016 discretion) ii Zoe -t (1 S bp RECEIVED OCT 13 2015 AOGCCBP Exploration(Alaska)Inc. P.O.Box 196612 900 E.Benson Boulevard Anchorage,AK 99519-6612 CERTIDFIED MAIL: 7015 0640 0001 0916 8178 USA October 8, 2015 UIC Manager, Ground Water Protection Unit SCANNED U.S. Environmental Protection Agency (OCE-127) 1200 Sixth Avenue, Suite 900 Seattle, WA 98101 Re: Demonstration of Mechanical Integrity, Prudhoe Bay Grind and Inject, UIC Class I Permit AK-11008-A Dear UIC Manager: This letter is to submit the results of a recent tubing inspection log and fluid movement test in UIC Class I well GNI-02A, and the annulus pressure test for the three UIC Class I GNI wells located at the Prudhoe Bay Grind and Inject project operated by BP Exploration (Alaska), Inc(BPXA). The tests are specified as part of the demonstration of mechanical integrity under Part It, C.3 b of EPA UIC Class I permit AK1I008-A. The enclosed descriptive and interpretive report contains the results for the following logs and tests as required under Part II, C.3.c(1) of the permit: - Tubing Inspection Logs: GNI-02A(Page 16, Part II, C.3.b(3)) - Fluid Movement Test: GNI-02A(Page 16, Part II, C.3.b(2)) - Annulus Pressure Tests: GNI-02A, GNI-03, and GNI-04 (Page 16, Part II, C.3.b(1)) There was no indication of a loss of well integrity. 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. BPXA understands that the EPA will notify BPXA of the acceptability of the mechanical integrity demonstration within 13 days of receipt of the results of the mechanical integrity tests (Part II, C.3.c.(4)). Injection may continue during this 13 day review period. If the EPA does not respond within 13 days, we will conclude that the results are acceptable and will continue with injection. If you have questions, please contact Michael Bill, Sr. Staff Engineer at(907) 564-4692. Sincerely, Gary Crawford Logistics and Infrastructure Manager • • Attachments Cc: Thor Cutler, EPA Region 10 (letter and report) Jim Regg, AOGCC (letter and report) Marc Bentley, ADEC (letter and report) Bcc: (letter and report) M. Bill MB 7-1 D. Mulkey MB 4-4 A. Cooke MB 4-4 R. Daniel MB 7-1 C. Janowski MB 7-1 K. Parks/W. Pettus PRB 24 A. Reyes/A. Assmann PRB 42 Compliance Matrix Administrator Attachments Demonstration of Mechanical Integrity Report PDS GNI-02A Memory Multi-Finger Caliper Log Results Summary, August 27, 2015 PDS GNI-02A Memory Temperature Survey, August 26, 2015 Annulus Pressure Test Report • • Demonstration of Mechanical Integrity Prudhoe Bay Grind and Inject Project EPA permit AK-1I008-A effective 09/01/07 requires a tubing inspection log in the Prudhoe Bay Unit Class I Grind& Inject wells annually. Approved tubing inspection logs (Part II C 3 b(3))include pipe analysis logs,caliper logs or other equivalent tests. The permit also requires a fluid movement test in each well each calendar year. Approved fluid movement tests(Part II C 3 b(2))include tracer surveys,temperature logs,noise logs,oxygen activation/water flow logs, borax pulse neutron logs(PNL)or other logs. Below are the results of logs and tests run recently in well GNI-02A. Tubing Inspection Logs A 40 arm caliper logging tool, supplied by PDS (ProActive Diagnostic Services),is run on slickline to inspect the interior surface of both the tubing and the casing. A memory caliper log was run in well GNI-02A on August 27,2015. The GNI-02A tubing is in fair condition with maximum wall penetration up to 37%and cross sectional metal loss up to 23%. The casing below the tubing tail is in fair condition. Below are the observed maximum metal losses observed in the tubing and casing from the caliper logs. Well Date Maximum Pit Penetration Max Cross-Sectional Wall Loss GNI-02A Tubing 08/27/15 37% 23% GNI-02A Casing 08/27/15 38% 16% Enclosed are copies of the PDS Memory Multi-Finger Caliper,Log Results Summary for this well. • 111 Fluid Movement Tests The GNI wells normally inject cold slurry or cold water at 50-70 degrees F. The original formation temperature of the target disposal formation was about 115 degrees F. The Shut-In Temperature log technique is commonly used for cement channel detection in injection wells on the North Slope of Alaska and has been used to satisfy the GNI fluid movement test requirement as a demonstration of mechanical integrity. A shut-in temperature log was run in Grind& Inject well GNI-02A on August 26,2015 after the well was shut-in for 9 days prior to running the log. Wellbore temperatures are affected by the temperature of the injected fluids by conduction and/or convection. When the well is injecting fluids,the wellbore and the adjacent formation reaches a temperature near the injection fluid temperature due to conductive heat transfer. When injection ceases,the wellbore temperature begins to return toward its original temperature. The rate of temperature change of the shut-in well will depend on the original formation temperature,the injection fluid temperature and the rate and cumulative volume of injection. In the GNI wells,the injected fluids are colder than the formation temperatures below about 4000 ft TVD. In areas where the injected fluids enter the formation,both conduction and convective heat transfer are involved. The amount of rock cooling is much larger and the rate of temperature change after shut- in is much slower due to the direct contact of the formation with the cold fluid. Channeling adjacent to the wellbore is evident because cooler injected fluids leak off into formations throughout the length of the channel. Several types of logging tools are available to be used to record the temperatures of the wellbore fluids: tools run on electric line with a real-time surface readout and memory tools run on slick line. The results from these instruments are presented in the enclosed logs of borehole temperature and pressure versus measured depth. Shut-In Temperature Survey Procedure - EPA permit AK-1I008-A requires fluid movement tests surveys to"... be conducted at injection pressure at least equal to the average continuous injection pressure observed in the previous 6 months." Injection is cycled into the GNI wells on a rotating basis,with one well injecting at a time. The average and maximum injection pressures are reported quarterly on Form 7520-8. - Average daily injection pressure in well GNI-02A over the 6 months prior to its survey was 1385 psi. Wellhead injection pressures exceeded these pressures during the injection cycle completed prior to the survey. - The survey procedure generally involved the following steps: Inject a significant volume of cold water or slurry at the required pressure. Shut-in after the injection cycle. Freeze protect the well. After at least 5 days of shut in time,rig up logging tools and pressure test lubricator. Confirm depth control by comparing to the tie-in log on record. Run the shut-in temperature/pressure survey. Rig down and move off. - Compare the logged temperatures to previous shut in logs run in the well. GNI-02A Shut-In Temperature Survey Results—reference Schlumberger GNI-02A Memory Temperature Survey (UMT-GR-CCL-Press-Temp), 26-Aug-2015. Note: the depths referenced below refer to the printed log. The enclosed log trace was run from the fill level in the well to the surface. The log contains the following traces: casing collar • locator, gamma ray,temperature and pressure. The last injection cycle efore logging took place between 07/28 and 08/17/15. The shut-in temperature trace indicates uniformly increasing temperature with depth to about 7500 feet measured depth(MD)or 6112 feet true vertical depth(TVD). Temperatures increased then decreased slightly with depth to about 7875 feet MD or 6354' TVD. Below that point,the temperature declined until the fill level was reached within or just above the perforated interval. Based on this data, there is no evidence of injected fluid movement above about 6112' TVD, and little or no movement above 6354' TVD. A plot of the temperature log data from 2015 along with other GNI-02A logs is shown below. GNI-02A Shut In Tomp.rsture Loss „it'i 130 J77.9ylPay 120 a 202-28-969 _ Ili —2112-24-06 a1 ._. _. _�. _._. .__.II.R�!-_--'. .--2A D5ME.24-06 a S1 —9.-2A D7 1706 8 07 57 1f0 2A 06-30-10 1207 SI .».. 2A,0-22-11 86381 -+—2A 07-0T-12 13d.81 IqC —+-2A1'061]:07S, 100 f-2A07.21.149W31 -IL - r -+-tA 08.2673 9 07 94 J.., i s ,_ 1 ;4 4 BO x 70 ' - BOL _ w 4000 4500 5000 5500 6000 6500 7000 True Vertical Depth ft Demonstration of Mechanical Integrity Prudhoe Bay Grind and Inject Project Annulus Pressure Test Results Annulus pressure tests were performed on UIC Class I Prudhoe Bay Grind and Inject disposal wells GNI-02A, GNI-03 and GNI-04 on September 20, 2015. The tests were performed in accordance with the stipulations of Class I permit AK-11008-A. In each well, the nitrogen cushion normally maintained in the tubing - casing annulus was bled off and displaced with diesel prior to the test. The annulus was then pressured to above 1500 psi with diesel and observed for 30 minutes. The tests were conducted while GNI-04 was injecting and the other wells were shut in. The test results were as follows: Tubing Pressure Annulus Pressure psi 1st Half 2nd Half Test GNI Well Start / End Start 15 Min 30 Min Decline Decline Result GNI-02A 583 /584 1801 1759 1752 42 7 Pass GNI-03 265 /265 1801 1771 1763 30 8 Pass GNI-04 1203 / 1202 1798 1766 1764 32 2 Pass In wells GNI-02A, GNI-03 and GNI-04, the pressure decline was less than 10 percent during the test period, with not more than 1/3 of the total decline in the second half of the 30 minute period. This data shows a stabilizing tendency as specified in EPA Permit AK-11008-A, Part II, C.3.b (1). Annulus pressures were observed on a recordingdigital test gauge. Duringthe test 9 9 9 period, the tubing pressure was essentially constant. The tests were witnessed by EPA representatives Thor Cutler and Jason Selitsch. s • Overall Conclusions The GNI-02A caliper log indicates the tubing has maximum penetration of 37% but it is suitable for continued injection. The GNI-02A shut-in temperature log indicates no movement of injected fluids above about 6112' TVD. The GNI-02A, GNI-03 and GNI-04 annulus pressure tests indicate the casing,tubing and packer are in sound mechanical condition. This is consistent with the absence of any indication of tubing or packer leakage during normal injection oeprations when there is a large pressure differential (>500 psi) between the tubing and the annulus in each of he wells. Michael L. Bill, P.E. Carrie Janowski, Well Integrity Engineer October 7,2015 • • United States Environmental Protection Agency Region 10 1200 Sixth Avenue,Suite 900 Seattle,WA 98101 Thor Cutler-(206)553-1673 a-mail:cutlerthor@epa.gov MECHANICAL INTEGRITY TEST(MIT)FORM Facility Well I Permit No. PTD No. BP Alaska-Prudhoe Bay Unit,G&I Wells GNI-02A AK-11008-A 2061190 Injector MIT Type Test Type Test Date Class 1 T X IA Std.Annular Pressure Test(SAPT) 20-Sep-I5 Req'd Test Fluid Type(s)used to Packer Depth: Test Iotervat/Comments Presssure(psi) test MD/TVD 1,500 Diesel 5153 MD/4537 ND One Year Cycle Record all Wellhead Pressures before and during Test.Note whether well is or,injection or SI during test. If on injection,note injection rate,injection pressure and injection fluid temperature Note volume of diesel pumped in annulus during test. T START TIME: RECORDED PRESSURES(PSI) RESULT E 12:05 PM PRE MIT INITIAL 15 MIN 30 MIN 45 MIN 60 MIN S TUBING 583 594 584 584 T INNER ANNULUS 7 1,801 1,759 1,752 FAIL OUTER ANNULUS 85 95 95 95 1 LOSS 42 7 COMMENTS: SI,3 97 bbl diesel pumped T START TIME: RECORDED PRESSURES(PSI) RESULT E PRE MIT INITIAL 15 MIN 30 MIN 45 MIN 60 MIN S TUBING PASS/ T INNER ANNULUS FAIL OUTER ANNULUS 2 LOSS COMMENTS T START TIME: RECORDED PRESSURES(PSI) RESULT E PRE MIT INITIAL 15 MIN 30 MIN 45 MIN 60 MIN 3 TUBING PASS/ T INNER ANNULUS FAIL OUTER ANNULUS 3 LOSS COMMENTS OTHER COMMENTS. NOTE:Pressure must show stabilizing tendency: Criteria 1)Total loss must be less than 10%at the end of a 30 minute test 2)Pressure loss in last 15 minutes must be less than 33%of total loss Extend test duration to 60 minutes,if necessary,to eliminate thermal effects(on-site decision per Inspector) --E-mail this MIT Test Data Form to EPA Region 10-Thor Cutler EPA Rep: AOGCC Rep: Operator Rep: Thor Cutler/Jason Selitsch Johnnie Hill Kevin Parks/Ryan Holt • • � United States Environmental Protection Agency It (i.,,,,, rror I Region 10 G 1200 Sixth Avenue,Suite 900 Seattle,WA 98101 Thor Cutler-(206)553-1673 e-mail:cutler.thor@epa.gov MECHANICAL INTEGRITY TEST(MIT)FORM Facility I Well I Permit No. PTD No. BP Alaska-Prudhoe Bay Unit,G&I Wells GNI-03 AK-1[008-A 1971890 Injector MIT Type Test Type Test Date Class 1 T X IA Std.Annular Pressure Test(SAPT) 20-Sep-15 Req'd Test Fluid Type(s)used to Packer Depth: Test Interval/Comments Presssure(psi) test MD/TVD 1,500 Diesel 4874 MD/4589 TVD One Year Cycle Record all Wellhead Pressures before and during Test Note whether well is on injection or SI during test If on injection,note injection rate,injection pressure and injection fluid temperature Note volume of diesel pumped in annulus during test T START TIME: RECORDED PRESSURES(PSI) RESULT E 9:28 AM PRE MIT INITIAL 15 MIN 30 MIN 45 MIN 60 MIN S TUBING 265 266 265 265 MO T INNER ANNULUS 7 1,801 1,771 1.763 FAIL OUTER ANNULUS 28 29 29 30 1 LOSS 30 8 COMMENTS: St,2 97 bbl diesel pumped T START TIME: RECORDED PRESSURES(PSI) RESULT E PRE MIT INITIAL 15 MIN 30 MIN 45 MIN 60 MIN S TUBING PASS/ T INNER ANNULUS FAIL OUTER ANNULUS 2 LOSS - COMMENTS: T START TIME: RECORDED PRESSURES(PSI) RESULT E PRE MIT INITIAL 15 MIN 30 MIN 45 MIN 60 MIN S TUBING PASS/ T INNER ANNULUS FAIL, OUTER ANNULUS 3 LOSS COMMENTS. 'OTHER COMMENTS: NOTE:Pressure must show stabilizing tendency: Criteria 1)Total loss must be less than 10%at the end of a 30 minute test 2)Pressure loss in last 15 minutes must be less than 33%of total loss Extend test duration to 60 minutes,if necessary,to eliminate thermal effects(on-site decision per Inspector). --E-mail this MIT Test Data Form to EPA Region 10-Thor Cutler EPA Rep: AOGCC Rep: Operator Rep: Thor Cutler/Jason Selitsch Johnnie Hill Kevin Parks/Ryan Holt • • United States Environmental Protection Agency ' Wlltwi. "' Region 10 A 1200 Sixth Avenue,Suite 900 Seattle,WA 98101 Thor Cutler-(206)553-I673 e-mail:cutler.thor@epa.gov MECHANICAL INTEGRITY TEST(MIT)FORM Facility I Well I Permit No. PTD No. BP Alaska-Prudhoe Bay Unit,G&I Wells GNI-04 AK-11008-A 2071170 Injector MIT Type Test Type Test Date Class 1 _ T X IA Std.Annular Pressure Test(SAPT) 20-Sep-15 Req'd Test Fluid Type(s)used to Packer Depth: Presssure(psi) test MD/TVD Test Interval/Comments 1,500 Diesel 4873 MD/4461 TVD One Year Cycle Record all Wellhead Pressures before and during Test Note whether well is on injection or SI during test If on injection,note rateinjection ,in' lection pressure and injection fluid temperature Note volume of diesel pumped in annulus during test. T START TIME: RECORDED PRESSURES(PSI) RESULT E 9:28 AM PRE MIT INITIAL 15 MIN 30 MIN 45 MIN 60 MIN S TUBING 1203 1202 1204 1202 111111111 T INNER ANNULUS 98 1,798 1,766 1,764 FAIL OUTER ANNULUS 39 48 48 48 1 LOSS 32 2 COMMENTS: On injection 13 04 BPM 64°F Seawater(i!--,10:12 AM 6 5 bbls diesel pumped for MIT On injection 13 16 BPM 64°F Seawater Cis 11:25 AM T START TIME: RECORDED PRESSURES(PSI) RESULT E PRE MIT INITIAL 15 MIN 30 MIN 45 MIN 60 MIN S TUBING PASS/ T INNER ANNULUS FAIL OUTER ANNULUS 2 LOSS COMMENTS: T START TIME: RECORDED PRESSURES(PSI) RESULT E PRE MIT INITIAL 15 MIN 30 MIN 45 MIN 60 MIN S TUBING PASS/ T INNER ANNULUS FAIL OUTER ANNULUS 3 LOSS COMMENTS: OTHER COMMENTS: NOTE:Pressure must show stabilizing tendency: Criteria 1)Total loss must be less than 10%at the end of a 30 minute test 2)Pressure loss in last 15 minutes must be less than 33%of total loss Extend test duration to 60 minutes,if necessary,to eliminate thermal effects(on-site decision per Inspector). I--E-mail this MFF Test Data Form to EPA Region 10-Thor Cutler EPA Rep: AOGCC Rep: Operator Rep: Thor Cutler/Jason Selitsch Johnnie Hill Kevin Parks/Ryan Holt • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg 1°16-111;-- V c21 DATE: Tuesday,October 06,2015 P.I.Supervisor l\ � SUBJECT: Mechanical Integrity Tests BP EXPLORATION(ALASKA)INC GNI-04 FROM: Johnnie Hill PRUDHOE BAY UN UGN GNI-04 Petroleum Inspector Src: Inspector Reviewed By: P.I.Suprv3 NON-CONFIDENTIAL Comm Well Name PRUDHOE BAY UN UGN GNI-04 API Well Number 50-029-23367-00-00 Inspector Name: Johnnie Hill Permit Number: 207-117-0 Inspection Date: 9/20/2015 Insp Num: mitJWH150920193816 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well GNI-04 Type Inj J W. TVD 1- 4461 - Tubing 1203 - 1202 - 1204, 1202 PTD� 2071170 Type Test SPT Test psi 1500 IA 98 1798 - 1766 . 1764 - Interval OTHER P/F P OA 38 48 - 48 48 . Notes: this was an EPA witnessed test by Thor Cutler.....6.5bbls of diesel used SCANNED Tuesday,October 06,2015 Page 1 of 1 • R • VED bp SEP 01 2015 AOGCC 0 BP Exploration(Alaska)Inc. P.O.Box 196612 CERTIFIED MAIL: 7015 0640 0006 6000 0214 900 E.Benson Boulevard Anchorage,AK 99519-6612 USA August 31, 2015 UIC Manager, Ground Water Protection Unit U.S. Environmental Protection Agency (OCE-127) MAY 0 1 211v 1200 Sixth Avenue, Suite 900 %MA Seattle, WA 98101 Re: Demonstration of Mechanical Integrity, Prudhoe Bay Grind and Inject, UIC Class I Permit AK-11008-A Dear UIC Manager: This letter is to submit the results of a recent tubing inspection logs and fluid movement tests in UIC Class I wells GNI-03 and GNI-04 located at the Prudhoe Bay Grind and Inject project operated by BP Exploration (Alaska), Inc (BPXA). The tests are specified as part of the demonstration of mechanical integrity under Part II, C.3 b of EPA UIC Class I permit AK11008-A. The enclosed descriptive and interpretive report contains the results for the following logs and tests as required under Part II, C.3.c(1) of the permit: - Tubing Inspection Logs: GNI-03 and GNI-04 (Page 16, Part II, C.3.b(3)) - Fluid Movement Test: GNI-03 and GNI-04 (Page 16, Part II, C.3.b(2)) There was no indication of a loss of well integrity. 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. BPXA understands that the EPA will notify BPXA of the acceptability of the mechanical integrity demonstration within 13 days of receipt of the results of the mechanical integrity tests (Part II, C.3.c.(4)). Injection may continue during this 13 day review period. If the EPA does not respond within 13 days, we will conclude that the results are acceptable and will continue with injection. • • • If you have questions, please contact Michael Bill, Sr. Staff Engineer at (907) 564-4692. Sincerely, Gary Crawford Logistics and Infrastructure Manager Cc: Thor Cutler, EPA Region 10 (letter and report) ) Jim Regg, AOGCC (letter and report) Marc Bentley, ADEC (letter and report) Attachments: Demonstration of Mechanical Integrity Report PDS GNI-03 Memory Multi-Finger Caliper Log Results Summary, August 11, 2015 Schlumberger GNI-03 Memory Temperature and Pressure Survey, 19-Jul-2015 PDS GNI-04 Memory Multi-Finger Caliper Log Results Summary, August 04, 2015 PDS GNI-04 Memory Temperature Survey, August 03, 2015 • • • Demonstration of Mechanical Integrity Prudhoe Bay Grind and Inject Project EPA permit AK-11008-A effective 09/01/07 requires a tubing inspection log in the Prudhoe Bay Unit Class I Grind & Inject wells annually. Approved tubing inspection logs (Part II C 3 b (3)) include pipe analysis logs, caliper logs or other equivalent tests. The permit also requires a fluid movement test in each well each calendar year. Approved fluid movement tests (Part II C 3 b (2)) include tracer surveys, temperature logs, noise logs, oxygen activation/water flow logs, borax pulse neutron logs (PNL) or other logs. Below are the results of logs and tests run recently in wells GNI-03 and GNI-04. Tubing Inspection Logs A 40 arm caliper logging tool, supplied by PDS (ProActive Diagnostic Services), is run on slickline to inspect the interior surface of both the tubing and the casing. A memory caliper log was run in well GNI-03 on August 11, 2015. The GNI-03 tubing is in good to fair condition with maximum wall penetration up to 22% and cross sectional metal loss up to 11%. The casing below the tubing tail is in fair to poor condition. A memory caliper log was run in well GNI-04 on August 04, 2014. The GNI-04 tubing is in good to fair condition with maximum wall penetration up to 32% and cross sectional metal loss up to 15%. The casing below the tubing tail is in fair condition. Below are the observed maximum metal losses observed in the tubing and casing from the caliper logs. Well Date Maximum Pit Penetration Max Cross-Sectional Wall Loss GNI-03 Tubing 08/11/15 22% 11% GNI-03 Casing 08/11/15 52% 28% GNI-04 Tubing 08/04/15 32% 15% GNI-04 Casing 08/04/15 31% 12% Enclosed are copies of the PDS Memory Multi-Finger Caliper, Log Results Summary for these wells. • • Fluid Movement Tests The GNI wells normally inject cold slurry or cold water at 50-70 degrees F. The original formation temperature of the target disposal formation was about 115 degrees F. The Shut-In Temperature log technique is commonly used for cement channel detection in injection wells on the North Slope of Alaska and has been used to satisfy the GNI fluid movement test requirement as a demonstration of mechanical integrity. A shut-in temperature log was run in Grind & Inject well GNI-03 on July 19, 2015 after the well was shut-in for 7 days prior to running the log. A shut-in temperature log was run in Grind & Inject well GNI-04 on August 03, 2015 after the well was shut-in for 7 days prior to running the log. Wellbore temperatures are affected by the temperature of the injected fluids by conduction and/or convection. When the well is injecting fluids, the wellbore and the adjacent formation reaches a temperature near the injection fluid temperature due to conductive heat transfer. When injection ceases, the wellbore temperature begins to return toward its original temperature. The rate of temperature change of the shut-in well will depend on the original formation temperature, the injection fluid temperature and the rate and cumulative volume of injection. In the GNI wells, the injected fluids are colder than the formation temperatures below about 4000 ft TVD. In areas where the injected fluids enter the formation, both conduction and convective heat transfer are involved. The amount of rock cooling is much larger and the rate of temperature change after shut-in is much slower due to the direct contact of the formation with the cold fluid. Channeling adjacent to the wellbore is evident because cooler injected fluids leak off into formations throughout the length of the channel. Several types of logging tools are available to be used to record the temperatures of the wellbore fluids: tools run on electric line with a real-time surface readout and memory tools run on slick line. The results from these instruments are presented in the enclosed logs of borehole temperature and pressure versus measured depth. Shut-In Temperature Survey Procedure - EPA permit AK-11008-A requires fluid movement tests surveys to "... be conducted at injection pressure at least equal to the average continuous injection pressure observed in the previous 6 months." Injection is cycled into the GNI wells on a rotating basis, with one well injecting at a time. The average and maximum injection pressures are reported quarterly on Form 7520-8. - Average daily injection pressure in well GNI-03 over the 6 months prior to its survey was 1319 psi. Wellhead injection pressures exceeded this pressure during the injection cycle completed prior to the survey. - Average daily injection pressure in well GNI-04 over the 6 months prior to its survey was 1230 psi. Wellhead injection pressures exceeded this pressure during the injection cycle completed prior to the survey - The survey procedure generally involved the following steps: Inject a significant volume of cold water or slurry at the required pressure. Shut-in after the injection cycle. Freeze protect the well. After at least 5 days of shut in time, rig up logging tools and pressure test lubricator. Confirm depth control by comparing to the tie-in log on record. Run the shut-in temperature/pressure survey. Rig down and move off. - Compare the logged temperatures to previous shut in logs run in the well. • • GNI-04 Shut-In Temperature Survey Results — reference PDS Memory GNI-04 Temperature Survey (UMT-GR-CCL-Press-Temp), 03-August-2015. Note: the depths referenced below refer to the printed log. The enclosed log trace was run from the fill level in the well to the surface. The log contains the following traces: casing collar locator, gamma ray, temperature and pressure. The last injection cycle before logging took place between 07/13 and 07/28/15. The shut-in temperature trace indicates uniformly increasing temperature with depth to about 6700 feet measured depth (MD) or 6085 feet true vertical depth (TVD). Temperatures decline slightly with depth to about 6900 feet MD or 6262' TVD. Below that point, the temperature declined until the fill level was reached within or just above the perforated interval. Based on this data, there is no evidence of injected fluid movement above about 6085' TVD, and little or no movement above 6262' TVD. A plot of the temperature log data from 2015 along with other GNI-04 logs is shown below. GNI-04 Shut In Temperature Logs 133 • ...Pall*sW*a 39144 • f I 313 N�r 414 a r ♦ ' • • 3 SO n s • f > I 60 .._...._._.__. al `., • 4000 4500 5000 5500 SOOQ 6500 7000 True Vertical Depth feet • • GNI-03 Shut-In Temperature Survey Results — reference Schlumberger GNI-03 Memory Pressure and Temperature Survey (PSP GR/CCL/Press/Temp), 19-July-2015. Note: the depths referenced below refer to the printed log. The enclosed log trace was run from the fill level in the well to the surface. The log contains the following traces: casing collar locator, gamma ray, temperature and pressure. The last injection cycle before logging took place between 06/29 and 07/13/15. The shut-in temperature trace indicates uniformly increasing temperature with depth to about 6750 feet measured depth (MD) or 6124 feet true vertical depth (TVD). Temperatures decrease slightly with depth to about 6950 feet MD or 6291' TVD. Below that point, the temperature declined until the fill level was reached within or just above the perforated interval. Based on this data, there is no evidence of injected fluid movement above about 6124' TVD, and little or no movement above 6291' TVD. A plot of the temperature log data from 2015 along with other GNI-03 logs is shown below. GN143 Shot In Tim l cgs a iYffi, easelae -a--tsar ,3/Aat • aSOM aaw a Ca*Shit 27,1,10 etia 10 - . a rzdoSt �. • Obi 3'k2 tido St ^-00-allOan 1.2.10 St IMAM tt Y 91 --._. ...._._.. IL _�-i7s'lrtS 7f�91 s ric •• n • "„ •" Or }•_ 4. wire'r+ argr .R+ 550 • 4000 4500 55000 5500 8000 8500 T. Vertical Depth Nat • Overall Conclusions The GNI-03 caliper log indicates the tubing has maximum penetration of 22% but it is suitable for continued injection. The GNI-03 shut-in temperature log indicates no movement of injected fluids above about 6124' TVD. The GNI-04 caliper log indicates the tubing has maximum penetration of 32% but it is suitable for continued injection. The GNI-04 shut-in temperature log indicates no movement of injected fluids above about 6085' TVD. Michael L. Bill, P.E. August 14, 2015 Z‘)‘2..E3 WELL LOG TRANSMITTAL DATA LOGGED PROACTIVE DIAgNOSTIC SERVICES, INC. g/Z1/2015 K.BENDER To: AOGCC Makana Bender ,y 14-. . 333 W. 7th Ave Suite 100 t,UG 201, Anchorage, Alaska 99501 (907) 793-1225 0 RE : Cased Hole/Open Hole/Mechanical Logs and/or Tubing Inspection(Caliper/MTT) The technical data listed below is being submitted herewith. Please acknowledge receipt by returning a signed copy of this transmittal letter to the attention of: BP Exploration (Alaska), Inc. Petrotechnical Data Center Attn: Analisa Steger LR2— 1 900 Benson Blvd. Anchorage, AK 99508 gancpdc@bo.com and ProActive Diagnostic Services, Inc. SCANNED Attn: Robert A. Richey 130 West International Airport Road Suite C Anchorage,AK 99518 Fax: (907) 245-8952 1) Temperature Survey 03-Aug-15 GNI-04 BL/CD 50-029-22876-00 2) Signed : 6e.oteeet. Date : Print Name: PROACTIVE DIAGNOSTIC SERVICES, INC., 130 W.INTERNATIONAL AIRPORT RD SUITE C, ANCHORAGE, AK 99518 PHONE: (907)245-8951 FAX: (907)245-8952 E-MAIL: PDSANCHORAGE(i MEMORYLOG.COM WEBSITE:WWW.MEMORYLOG.COM D:\Achtves\MasterTemplateFiles\Templates\Distribution\TransmittalSheets\BP_Transmit.docx Zoe- 1-1 bp CERTIFIED MAIL#7011 2970 0001 9243 3630 BP Exploration(Alaska)Inc. April 28, 2015 P.O.Box 196612 900 E.Benson Boulevard Anchorage,AK 99519-6612 USA Mr. Edward J. Kowalski Director, Office of Compliance and Enforcement U.S. Environmental Protection Agency 1200 Sixth Avenue RECEIVED Seattle, WA 98101 MAY 0 1 2015 Mr. Chris Wallace Alaska Oil and Gas Conservation Commission AOGCC 333 West 7th Avenue Anchorage, AK 99501-3192 Mr. Marc Bentley SCANNED Department of Environmental Conservation 555 Cordova St. Anchorage, AK 99501 RE: Mechanical Integrity Test Notifications Pad 3 Injection Wells, UIC Permit AK-11004-B, Wastewater Disposal, Permit No. 2010DB0001-0021 Grind and Inject Injection Wells, UIC Permit AK-11008-A, Area Injection Order No. 4E, General Wastewater, Permit No. 2010DB001-0012 Dear Sirs: BP Exploration (Alaska) Inc. (BPXA) respectfully submits the following notifications: 1) 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-B and 2) 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. 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) • Mechanical Integritost Notification . April 28, 2015 Page 2 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 e-mail. If you have any questions, please contact me at (907) 564-4838 or Darren Mulkey at 564- 5229. Sincerely, Alison Cooke UIC Compliance Advisor Attachment cc: Thor Cutler, EPA Region 10 • Mechanical Integrity st Notification April 28, 2015 • Page 3 Certification Statement Mechanical Integrity Test Notification 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 possibility of fine and imprisonment. "";2/ Responsib a Compa Taal Date 1-/Ae(if— Gary Crawford Logistics/Infrastructure Manager BP Exploration Alaska) Inc. Printed Name Title Company • s • . Proposed Schedule for 2015 Mechanical Integrity Testing Class I Well (s) MIT Proposed MIT test Flexibility in Fluid Deadline date test date? Movement Logs Planned after MIT? Pad 3 — By Mid-September 2015 Yes Borax-RST logs OWDW-NW, C September for each well and SE Wells 18, 2015 for scheduled with NW, C and MIT's SE wells. Caliper log in OWDW-SE in (Logging summer/fall may be 2015 extended up to 3 months with Director approval) Grind and Inject By Mid-September 2015 Yes Shut-In —GNI-02A, September Temperature GNI-03 and 20, 2015 for Logs and/or GNI-04 GNI-02A, Water Flow Logs GNI-03 and planned for GNI-04. summer/fall 2015 (May be extended 1 Caliper logs in month or at summer/fall Director 2015 discretion) 2Y1 - «i • REIVED bp FEB 0 2 2015 AOGCC Certified Mail # 7011 2970 0001 9242 9121 BP Exploration(Alaska)Inc. P.O.Box 196612 900 E.Benson Boulevard Anchorage,AK 99519-6612 USA January 30, 2015 UIC Manager, Ground Water Protection Unit MAY .0 1 2.016 U.S. Environmental Protection Agency (OCE-127) 1200 Sixth Avenue, Suite 900 Seattle WA 98101 RE: Fourth Quarter 2014 —G&I Injection Well Monitoring Report UIC Class I Permit AK-11008-A Dear UIC Manager: This report is being submitted to fulfill the fourth quarter 2014 (October- December) reporting obligations for the above referenced permit. Enclosed are three forms [EPA 7520-8 (2-84)] containing the information required by the permit. Also attached is a listing of the types and volumes of materials injected during the reporting period, a CD of the raw data, and graphs showing injection pressure, annular pressure, and injection volume for the wells. A description of the wastes managed at G&I has been previously submitted to the EPA in the Waste Analysis Plan (WAP). The enclosed graphs and the raw data being submitted electronically on CD are a requirement under the G&I UIC Permit (AK-11008-A). There are no permitted limits for the pH and temperature of the injected fluids. They are included in the reports as a physical description of the injected fluids (see Part II, Section E (1) (b) of the permit). The pH values define the non-hazardous range allowed for non-exempt fluids injected and the temperature values define the range historically encountered. There were no permit exceedences of the 1500 psig annulus pressure limitation on the Class I wells during this reporting period. There was a high injection pressure incidence on 12/12/14. However, this was related to meter issues and was not indicative of the actual well injection pressure. If you need any clarification or additional information concerning these reports, please contact me at (907) 564-4838 or Alison.Cooke@bp.com. Sicerely, "jib' OAA,---. r Alison Cooke UIC Compliance Advisor Attachments cc: Thor Cutler, EPA Marc Bentley, ADEC . • UIC Manager January 30,2015 Page 2 Certification Statement Fourth Quarter 2014—G&I Injection Well Monitoring Report 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 possibility of fine and imprisonment. / C 07/ Responsible Corn ny Official Date p Gary Crawford Logistics/Infrastructure Manager BP Exploration (Alaska) Inc. Printed Name Title Company • • .. UNITED STATES ENVIRONMENTAL PROTECTION AGENCY WASHINGTON, D.C. 20460 EPA INJECTION WELL MONITORING REPORT YEAR 2014 MONTH MONTH MONTH Injection Pressure(PSI) October November December 1. Minimum 7 24 89 2. Average 886 908 608 3. Maximum 2,113 1,944 1,657 Injection Rate(Gal/Min) 1. Minimum 0 0 0 2. Average 161 280 82 3. Maximum 828 1452 1065 Annular Pressure(PSI) 1. Minimum 24 129 121 2. Average 167 150 151 3. Maximum 557 208 323 Injection Volume(Gal) 1. Monthly Total 7,170,954 12,102,888 3,673,446 2. Yearly Cumulative 91,808,514 103,911,402 107,584,848 Temperature(F) 1. Minimum 33 24 17 2. Average 73 53 39 3. Maximum 120 73 66 pH 1. Minimum 2 2 2 2. Average 7 7 7 3. Maximum 12.5 12.5 12.5 Other 1. Monthly Average Injection Volume(Gallons/Day) 231,321 403,430 118,498 2. Maximum Daily Injection Volume (Gallons/Day) 729,414 1,042,818 831,810 Name and Address of Permittee Permit Number BP EXPLORATION (ALASKA , INC. ) Well#2A 900 E. BENSON BLVD. ADEC 2010DB0001-0012 P.O. BOX 196612 EPA Well Permit No. ANCHORAGE , AK . 99519-6612 AK- 1I008A Name and Official Title Signa e Date Signed Gary Crawford Logistics and Infrastructure Manager Prudhoe Bay Operations / 0/Ph EPA Form 7520-8 (2-84) *The values provided define the non-hazardous range and are not measured values.See Waste Analysis Plan. Values in parentheses( ) are actual values for permit compliance • • .. UNITED STATES ENVIRONMENTAL PROTECTION AGENCY WASHINGTON, D.C. 20460 EPA INJECTION WELL MONITORING REPORT YEAR 2014 MONTH MONTH MONTH Injection Pressure(PSI) October November December 1. Minimum 16 0 0 2. Average 681 347 708 3. Maximum 1,545 2,272 1,588 Injection Rate(Gal/Min) 1. Minimum 0 0 0 2. Average 118 51 239 3. Maximum 1706 1096 1296 Annular Pressure(PSI) 1. Minimum 23 16 128 2. Average 230 118 159 3. Maximum 903 231 247 Injection Volume(Gal) 1. Monthly Total 5,268,144 2,184,546 10,681,776 2. Yearly Cumulative 83,300,070 85,484,616 96,166,392 Temperature(F) 1. Minimum 53 28 18 2. Average 83 52 47 3. Maximum 130 78 70 pH 1. Minimum 2 2 2 2. Average 7 7 7 3. Maximum 12.5 12.5 12.5 Other 1. Monthly Average Injection Volume(Gallons/Day) 169,940 72,818 344,573 2. Maximum Daily Injection Volume(Gallons/Day) 449,862 875,952 1,145,718 Name and Address of Permittee Permit Number BP EXPLORATION (ALASKA, INC.) Well#3 900 E. BENSON BLVD. ADEC 2010DB0001-0012 P.O. BOX 196612 EPA Well Permit No. ANCHORAGE ,AK . 99519-6612 AK- 11008A Name and Official Title Sig ture Date Signed Gary Crawford Logistics and Infrastructure Manager / 74, /f— Prudhoe Bay Operations EPA Form 7520-8 (2-84) *The values provided define the non-hazardous range and are not measured values.See Waste Analysis Plan. Values in parentheses( ) are actual values for permit compliance • UNITED STATES ENVIRONMENTAL PROTECTION AGENCY WASHINGTON, D.C. 20460 EPA INJECTION WELL MONITORING REPORT YEAR 2014 MONTH MONTH MONTH Injection Pressure(PSI) October November December 1. Minimum 1 0 0 2. Average 370 645 718 3. Maximum 1,629 2,261 4,203 Injection Rate(Gal/Min) 1. Minimum 0 0 0 2. Average 13 193 302 3. Maximum 892 1365 1112 Annular Pressure(PSI) 1. Minimum 49 95 152 2. Average 188 174 174 3. Maximum 304 239 206 Injection Volume(Gal) 1. Monthly Total 573,720 8,337,882 13,496,154 2. Yearly Cumulative 92,546,370 100,884,252 114,380,406 Temperature(F) 1. Minimum 41 25 18 2. Average 63 61 48 3. Maximum 130 125 73 pH 1. Minimum 2 2 2 2. Average 7 7 7 3. Maximum 12.5 12.5 12.5 Other 1. Monthly Average Injection Volume(Gallons/Day) 18,507 277,929 435,360 2. Maximum Daily Injection Volume (Gallons/Day) 361,074 645,666 951,090 Name and Address of Permittee Permit Number BP EXPLORATION (ALASKA , INC.) Well#4 900 E. BENSON BLVD. ADEC 2010DB0001-0012 P.O. BOX 196612 EPA Well Permit No. ANCHORAGE ,AK . 99519-6612 AK- 11008A Name and Official Title Signa re Date Signed Gary Crawford Logistics and Infrastructure Manager (/1//f-- Prudhoe Bay Operations / EPA Form 7520-8 (2-84) *The values provided define the non-hazardous range and are not measured values.See Waste Analysis Plan. Values in parentheses( ) are actual values for permit compliance • Grind & Inject - Plant bp Composition Summary North Slope Technical Services 10/01/2014 to 12/31/2014 Equipment Services Group By Exemption,By Component Component Cubic Yards Barrels Non-Exempt, Non-Hazardous Waste Stream Cement/Contaminate 664.90 pigging returns 6.00 Drilling Mud 1,356.38 rinate 100.00 Fresh Water 12,447.27 LCM 20.00 LVT-200 200.00 Seawater/Brine/KCI 20,916.75 POLYMER 43.25 Acid 49.45 rinsate 781.00 Line Pigging Solids 246.00 Spill Cleanup Waste 11.00 4.00 sump fluids 408.00 Cement Rinsate 270.00 sump solids 4.00 wash bay sump fluids 1,109.00 boiler blowdown water 30.00 Boiler Blowdown 534.00 Total Non-Exempt,Non-Hazardous Volume: 15.00 39 186.00 Exempt Fresh Water 15.80 30,820.93 hydrotest fluid 580.00 Gravel/Sand 5.00 Drilling Mud 217.80 67,451.89 Diesel/Water Gel 353.75 Cuttings 153.20 893.70 Crude Oil 10.40 Cement/Contaminate 12.00 3,401.25 Cement Rinsate 251.00 Generated using Access 2000-VIOPSVnhastruc(ue Waste MgnlFField Opaetbns1Waste SupportlWest, Printed on Friday, January 02, 2015 Page 1 of 2 • Grind & Inject - Plant bp Composition Summary North Slope Technical Services 10/01/2014 to 12/31/2014 Equipment Services Group By Exemption,By Component Component Cubic Yards Barrels Boiler Blowdown 337.00 Diesel 3.60 rinsate 12.00 2,945.00 water 1,072.00 washbay fluids 3,283.00 wash bay sump fluids 2,259.00 sump fluids 1,555.00 spill cleanup material 12.00 10.00 Soap 0.05 Snowmelt 19.00 Methanol 35.50 Scale/Corrosion Inhibitor 1.24 KCI/Wax Beads 1.60 rinate 67.00 Reserve/Flare/Relief Pit Water 107.00 Produced Water 495.00 Well Cellar Fluid 13.00 MINERAL OIL 14.20 lubricant 2.30 LCM 15.68 Seawater/Brine/KCI 4.20 55,865.91 Total Exempt Volume: 427.00 171,870.00 Total Volume: 442.00 211 056.00 Generated using Access 2000-V'IOPSVneastructure Waste MgnOWFidd OperationslWaste SupporttWest, Printed on Friday, January 02, 2015 Page 2 of 2 . • • W L() LC) L() +r � � � CI LU LU LU '- - N- CO O Z N co co G1 U) O d) >- >- } } 0 d cC co OSN- a o 06N o.. .° N t U) o c Q. 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CU = 4 !/c� C C °c_ U) < < RS > = , j .c 4 O4t 5Oce << iOc,'sic, 1 - AZO& Z n,° C7 0 0 0 0 0 0 0 0 Oe CO Nr N 0 CO CO 'V' N �L !Sd 1k» 'r REIVED bp FEB 0 2 2015 AOGCC BP Exploration(Alaska)Inc. P.O.Box 196612 900 E.Benson Boulevard Anchorage,AK 99519-6612 Certified Mail # 7011 2970 0001 9242 9114 USA January 30, 2015 SCONS UIC Manager, Ground Water Protection Unit U.S. Environmental Protection Agency (OCE-127) 1200 Sixth Avenue, Suite 900 Seattle, WA 98101 RE: Fourth Quarter 2014— Pad 3 Injection Well Monitoring Report UIC Class I Permit AK— 11004-B Dear UIC Manager: This report is being submitted to fulfill the Fourth quarter 2014 (October - December) reporting obligations for the above referenced permit. Enclosed are two forms [EPA 7520-8 (2-84)] containing the information required by Part II, Section E of the permit. Also attached is a listing of the types and volumes of materials injected during the reporting period, a CD of the raw data, and graphs showing injection pressure, annular pressure, and injection volume for the wells. A description of the wastes managed at Pad 3 has been previously submitted to the EPA in the Waste Analysis Plan (WAP). The enclosed graphs, and the raw data being submitted electronically on CD, are a requirement under the Pad 3 UIC Permit (AK-11004-B). There are no permitted limits for the pH and temperature of the injected fluids. They are included in the reports as a physical description of the injected fluids (see Part II, Section E (1) (b) of the permit). The pH values define the non-hazardous range allowed for non-exempt fluids injected and the temperature values define the range historically encountered. There were no permit exceedences of the 1400 psig injection pressure limitation or 150 psig annulus pressure limitation on the Class I wells during this reporting period. If you need any clarification or additional information concerning these reports, please contact me at (907) 564-4838 or Alison.Cooke@bp.com. Sincerely, C4\ Kilter br Alison Cooke UIC Compliance Advisor Attachments cc: Thor Cutler, EPA Chris Wallace, AOGCC Marc Bentley, ADEC i UIC Manager January 30,2015 Page 2 Certification Statement Fourthuarter 2014— Q Pad 3 e In1" i ct on Well Monitoring Report ort 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 possibility of fine and imprisonment. SO ',pon ible Com..ny Official Date Gary Crawford Logistics/Infrastructure Manager BP Exploration (Alaska) Inc. Printed Name Title Company 0 • UNITED STATES ENVIRONMENTAL PROTECTION AGENCY WASHINGTON,D.C.20460 EPA INJECTION WELL MONITORING REPORT YEAR 2014 MONTH MONTH MONTH Injection Pressure(PSI) October November December 1. Minimum 24 311 305 2. Average 310 353 525 3. Maximum 707 402 858 Injection Rate(Gal/Min) 1. Minimum 0 0 0 2. Average 0 0 65 3. Maximum 0 0 141 Annular Pressure(PSI) 1. Minimum 45 47 52 2. Average 47 49 59 3. Maximum 48 52 73 Injection Volume(Gal) 1. Monthly Total 0 0 1,488,308 2. Yearly Cumulative 8.328,628 8,328,628 9,816,936 Temperature(F) 1. Minimum 35 35 35 2. Average 50 50 50 3. Maximum 130 130 130 pH 1. Minimum 2 2 2 2. Average 7 7 7 3. Maximum 12.5 12.5 12.5 Other 1. Monthly Average Injection Volume(Gallons/Day) 0 0 48,010 2. Maximum Daily Injection Volume(Gallons/Day) 0 0 112,132 Name and Address of Permittee Permit Number BP EXPLORATION(ALASKA,INC.) NW Well 900 E. BENSON BLVD. ADEC 2010DB0001-0021 P.O.BOX 196612 EPA Well Permit No. ANCHORAGE,AK.99519-6612 AK-11004B Name and Official Title Sign re Date Signed Gary Crawford Logistics and Infrastructure / / Manager J Prudhoe Bay Operations , / EPA Form 7520-8 (2-84) 'The values provided define the non-hazardous range and are not measured values.See Waste Analysis Plan. Values in parentheses( ) are actual values for permit compliance • . I UNITED STATES ENVIRONMENTAL PROTECTION AGENCY WASHINGTON, D.C.20460 EPA INJECTION WELL MONITORING REPORT YEAR 2014 MONTH MONTH MONTH Injection Pressure(PSI) October November December 1. Minimum 22 364 331 2. Average 612 635 546 3. Maximum 1,031 910 918 Injection Rate(GalIMin) 1. Minimum 0 68 0 2. Average 110 111 35 3. Maximum 140 140 139 Annular Pressure(PSI) 1. Minimum 40 42 36 2. Average 56 56 42 3. Maximum 106 92 96 Injection Volume(Gal) 1. Monthly Total 2,985,020 2,368,481 678,749 2. Yearly Cumulative 16,006,238 18,374,719 19,053,468 Temperature(F) 1. Minimum 35 35 35 2. Average 50 50 50 3. Maximum 130 130 130 pH 1. Minimum 2 2 2 2. Average 7 7 7 3. Maximum 12.5 12.5 12.5 1. Monthly Average Injection Volume(Gallons/Day) 96,289 78,947 21,895 2. Maximum Daily Injection Volume(Gallons/Day) 174,762 159,974 101,396 Name and Address of Permittee Permit Number BP EXPLORATION(ALASKA , INC . ) SE Well 900 E .BENSON BLVD. ADEC 2010DB0001-0021 P.O. BOX 196612 EPA Well Permit No. ANCHORAGE,AK. 99519-6612 AK-110048 Name and Official Title Signature Date Signed Gary Crawford Logistics and Infrastructure Manager CA iA� Prudhoe Bay Operations / EPA Form 7520-8 (2-84) Gq-...--/ 'The values provided define the non-hazardous range and are not measured values.See Waste Analysis plan. The values in parenthesis( ) are actual values for compliance purposes. • Pad 3 - Injection b ' Composition Summary North Slope Technical Services 10/01/2014 to 12/31/2014 Equipment Services Group By Component Component Barrels Acid 94.65 bench test fluids 60.00 blue mango 4.25 Boiler Blowdown 517.00 Borax 5.80 cement additive/water 45.00 Cement rinsate 204.75 Cement/Contaminate 5,907.56 Chemclear 0.76 class 1 rinsate 943.00 class 1 sump fluids 1,538.00 class 1 wash Bay Fluids 500.00 class 2 rinsate 530.00 class 2 rinsate 2,157.00 class 2 wash bay fluids 127.00 Crude Oil 3,451.45 Cuttings 117.41 Diesel 1,490.85 Diesel/Water Gel 1,008.96 Domestic Water 4.00 Drilling Mud 12,891.91 Drum rinsate 32.00 Emulsion breaker 1.14 Frac Sand 2 02 Fresh Water 60,834.25 geo vis 0.54 Glycol 253.20 Gravel/Sand 5.32 Line pigging solids 292.50 meg 3.00 Methanol 2,501.52 Generated using Access 2000-V IOPSVntrastruct,ee Waste MgmhField Open&ionx.Waste Sup ortiWash Printed on Friday, January 02, 2015 Page 1 of 2 i • Pad 3 - Injection bp Composition Summary North Slope Technical Services 10/01/2014 to 12/31/2014 Equipment Services Group By Component Component Barrels parts washer fluid 56.00 Polymer 0.25 Produced Water 12,728.86 production facility fluids 54.00 Rinsate 3,076.00 rinse fluids 350.00 Scale/Corrosion Inhibitor 58.00 SCHBOO B GONE 87.00 Seawater/Brine/KCI 47,317.68 sewage 0.01 slurry water 290.00 snow melt 1,072.10 Snowmelt 314.50 Soap 1.81 Soda ash 277.30 Source Water 55.50 spill clean up waste 56.00 storm water 1,119.40 stormwater 580.00 Sump fluids 4,722.00 turbine wash 3.00 Turbine wash water 20.00 Wash Bay Fluids 4,379.00 water 12.75 well bore fluids 5.00 well cellar fluids 139.00 WR6 Soap 3.00 Total Volume: 172,303.00 Generated us Ing Access 2000-V10PSVnhashud ine Waste MgmliField Ope atianslWaste SugwMWasts Printed on Friday, January 02, 2015 Page 2 of 2 • • CDLULULU .— � N— to ` — o LU LU LU 1 * * i 0 Z CO U) co U) CD a) a) m >- >- >- >- a) a) E Cu co o 6 otf cc)., c•-. 0 ++ i >, U a) t ) Cu CuQ c c z .� C'1 a) >+ t 0 co C LL Q a) O CO Co 2 o >, 0 Cs M •C �+ _ C co Ti 5 Ct. aa)) c aQ 4— .� 2 : cn U a) 0 73C CU w 0 ° a) CO C v a) a) a) C a) > .5 �U cz O +� CO C Q N Cu in < to Q U • a) • Lo E co : 2 c �, co in U co co� � N m CD a) cn L 3 - 3 3 cu m CO as a) E E 0o (i) co o 0 2tto 0 z . i • a) U a) C a) D W o U) > 0 ca O Z J I Oc,, 4 p�/p /� i C,/ s - '6/p c/per CD .6 C/p zS c'/ ca ca �� / a O O pc,/ t H �! 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O~, ~ ~ - ~' ~ Well History File Identifier Organizing (done) RESCAN ~olor Items: p(Greyscale Items: ^ Poor Quality Originals: ~sded iiiuiiiiiuiiuii ^ Rescan Needed III II'I(~ (I (I 11I II OVERSIZED (Scannable) ^ Maps: ^ Other Items Scannable by a Large Scanner OVERSIZED (Non-Scannable) ^ Logs of various kinds: ^ Other.: ^ Other: NOTES: BY DIG TAL DATA Diskettes, No. I Other, No/Type: ~j~ ~©' Date:' I t 5~ /s/ Project Proofing III II'III IIIII II III BY: Maria Date: /s/ Scanning Preparation ~._ x 30 = ~ + ~ =TOTAL PAGES ~ d~ r f (Count does not include cover sheet) „~ n BY: Maria Date: 1 ~l I ~.~/A~Q /s/ I/Vj Production Scanning Stage 1 Page Count from Scanned File: ~_ (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: ~ YES NO BY: /laria Date: I '~ OQ /sl (M Stage 1 If NO in stage 1, page(s) discrepancies were founvvd: YES NO ~ Y BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. II I II II II ~ II II I I III Rescanned III IIIIIIIIIII IIIII BY: Maria Date: /s/ Comments about this file: Quality Checked III II~III III III III 10/6/2005 Well History File Cover Page.doc Pau 4ntz.-o4 Prb Z07j170 Regg, James B (DOA) From: AK, D&C Well Integrity Coordinator[AKDCWelllntegrityCoordinator @bp.com] Sent: Tuesday, October 01, 2013 9:45 PM To: Regg, James B (DOA); Wallace, Chris D (DOA); Brooks, Phoebe L (DOA); DOA AOGCC Prudhoe Bay Cc: AK, D&C Well Integrity Coordinator / loj 7//3 Subject: September 2013 AOGCC MIT Forms Attachments: September 2013 MIT Forms.zip All, Please find the attached MIT forms for September 2013. WELL PTD# NOTES MPE-12 2050670 MPE-26 2002060 MPE-29 2010370 MPG-05 1910230 MPG-19 2041920 MPS 15 2012450 SCANNED r E L l 4 L 14 NK-18 1931770 NK-65A 2050630 09-22 1831730 14-21A 2051070 GNI-02A 2061190 EPA AND AOGCC FORM GNI-03 1971890 EPA AND AOGCC FORM GNI-04 2071170 EPA AND AOGCC FORM ✓ 'jot W ressed 6,../ OWDW-NW 1002400 EPA AND AOGCC FORM 1 OWDW-SE 1002390 EPA AND AOGCC FORM N-23 1970120 NG I-01 1750480 P-03A 1972280 U-05A 2090700 X-29 1931390 Please contact us with any questions. Thank you, Jack Disbrow BP Alaska-Well Integrity Coordinator nut, Global Wells Organizatin Office: 907.659.5102 WIC Email:AKDCWellIntegrityCoordinator(a)bp.com 1 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: jim.reaq(rDalaska.00v; AOGCC.Inspectors(aialaska.gov; phoebe.brooks(Dalaska.gov chris.wallace @alaska.gov OPERATOR: BP Exploration(Alaska),Inc. fceett 1 0'1'13 FIELD/UNIT/PAD: Prudhoe Bay/PBU/GNI DATE: 09/22/13 OPERATOR REP: Jack Disbrow AOGCC REP: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well GNI-02A Type Inj. N TVD 4,537' Tubing 325 324 320 320 Interval 0 P.T.D. 2061190 Type test P Test psi 1500 Casing 154 1,797 1,766 1,761 P/F P Notes:Annual regulatory compliance witnessed by EPA OA 66 73 74 74 Pumped 4.6 bbls of diesel bled back 1.3 bbls of fluid Well GNI-04 Type Inj. N ' TVD '4,461' Tubing 293 293 290 290 Interval 0 P.T.D. 2071170 , Type test P - Test psi - 1500 Casing 227 -1,800 '1,758 '1,751 P/F P IV Notes:Annual regulatory compliance witnessed by EPA OA 52 387 _382 380 Pumped 4.5 bbls of diesel and bled back 2.4 bbls of fluid Well P.T.D. Notes: 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 0=Other(describe in notes) W=Water D=Differential Temperature Test Form 10-426(Revised 11/2012) MIT PBU GNI-02A GNI-04 09-22-13.xls ,' United States Environmental Protection Agency t ) Region 10 -r• 1200 Sixth Avenue,Suite 900 Seattle,WA 98101 Thor Cutler-(206)553-1673 e-mail:cutler.thor @epa.gov MECHANICAL INTEGRITY TEST(MIT)FORM Facility I Well I Permit No. PTD No. BP Alaska-Prudhoe Bay Unit,G&I Wells GNI-04 AK-1I008-A 2071170 Injector MIT Type Test Type Test Date Class I T X IA Std.Annular Pressure Test(SAPT) 9/22/2013 Req'd Test Fluid Type(s)used to Packer Depth(ft, Presssure(psi) test TVD) Test Interval/Comments 1,500 Diesel 4,461 One Year Cycle Record all Wellhead Pressures before and during Test.Note whether well is on injection or SI during test. If on injection,note injection rate,injection pressure and injection fluid temperature Note volume of diesel pumped in annulus during test. T START TIME: RECORDED PRESSURES(PSI) RESULT E 12:32 PM PRE MIT INITIAL 15 MIN 30 MIN 45 MIN 60 MIN P/F S TUBING 293 293 290 290 Pass T INNER ANNULUS 227 1800 1758 1751 OUTER ANNULUS _ 206 387 382 380 1 COMMENTS: Pumped 4.5 bbls of diesel and bled back 2.4 bbis of fluid T START TIME: RECORDED PRESSURES(PSI) RESULT E PRE MIT INITIAL 15 MIN 30 MIN 45 MIN 60 MIN S TUBING PASS/ T INNER ANNULUS _ FAIL OUTER ANNULUS 2 COMMENTS: T START TIME: RECORDED PR ESSURES(PSI) RESULT E PRE MIT INITIAL 15 MIN 30 MIN 45 MIN 60 MIN S TUBING PASS/ T INNER ANNULUS FAIL OUTER ANNULUS 3 COMMENTS: MISC COMMENTS: 'NOTE:Pressure must show stabilizing tendency: 1)Total pressure loss must be less than 10%at end of 30 minute test 2)Pressure loss in last 15 minutes must be less than 33%of total loss Start MIT over it 1)Total loss exceeds 10% 2)Loss during last 15 minute period=or>50%of loss during first 15 minute period Extend the test 30 minutes to demonstrate stabilization(thermal effects). --E-mail this MIT Test Data Form to EPA Region 10-Thor Cutler EPA Rep: AOGCC Rep: Operator Rep: Thor Cutler Waived by John Crisp Kevin Parks /f ;��j l Qom"^' t 7.- bp i N O V twit CEWED BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519 -6612 (907) 561 -5111 November 07, 2012 PT 0 (2,.O - ( 11 Commissioner Cathy Foerster, Chair Alaska Oil & Gas Conservation Commission 333 West 7 Avenue, Suite 100 SCANNED JAN 2 3 2013 Anchorage, Alaska 99501 Reference: Grind & Inject Project Annual Performance Report Dear Commissioner Foerster: Enclosed is the Annual Performance Report for waste slurry injection for the Grind and Inject project located near Drill Site 4 in the Prudhoe Bay Unit. This report is submitted to satisfy the requirements of Area Injection Order #4E, Rule 10, as modified by Administrative Approval No. AIO 4C.001 and an Erratum Notice dated July 17, 2009. This requirement is very similar to an EPA report requirement regarding Prudhoe Bay Unit UIC Class 1 injection wells contained in EPA permit AK- 11008 -A. The report covers the period from October 1, 2 through September 30, 20 and w a s structured to satisfy both the AOGCC and the EPA requirements. Should you have questions conceming the contents of this report, contact me at 564 -4692. Sincerely, Michael L. Bill Senior Staff Engineer F(k, t 1 Rod ° 1 1 4 FlACt_ • Prudhoe Bay Unit, Grind & Inject Project, Surfcote Pad Injection EPA UIC Class 1 Permit AK- 11008 -A Area Injection Order #4E, Rule 10 Annual Performance Report October 1, 2011 through September 30, 2012 This Annual Performance Report documents waste slurry injection on the Surfcote Pad near Drill Site 4 in the Prudhoe Bay Unit for the period October 1, 2011 through September 30, 2012. This report is submitted to satisfy the requirements of both EPA UIC Class 1 permit AK- 11008 -A, Part 11 3 c 7 and AOGCC Area Injection Order (AIO) #4E, Rule 10, as modified by Administrative Approval AIO 4C.001 and Erratum Notice dated July 17, 2009. Additional information requested in a letter from the AOGCC (Regg to Bill 12/22/03) is also included. The report contains a brief description of the current project status, a summary of the disposal well performance data acquired during this period and operational plans for the next year. Project Status The Grind & Inject (G &I) Project at the Surfcote pad was undertaken in 1998 by the owners of the Prudhoe Bay Unit, Initial and Lisburne Participating Areas, and the Kuparuk River Unit to dispose of drilling muds and cuttings stored in reserve pits. Other non - hazardous wastes processed through the G &I Plant included those referenced in AIO #4E, Rule 2 as Class 11 wastes, consisting of RCRA- exempt drill cuttings and oily solids from pipeline pigging, vessel cleanouts and well workovers, and RCRA- exempt liquid wastes such as used drilling mud from on -going North Slope drilling operations. EPAissued _Class J _U1C_permit_ AK41008 -A for Grrind &_Inject Project effective September 1, 2007. Authorizations to inject Class 1 substances were received on January 18, 2008 for wells GNI -02A and GNI -03 and on May 6, 2008 for GNI -04. Well GNI -01 remains a Class 11 only disposal well. All non - hazardous wastes injected for disposal in the GNI wells during the report period are within the description of wastes referenced in EPA UIC Class 1 Permit AK- 11008 -A, Part 11 C 3 7, the UIC Class 1 permit application submitted in November 2006, or in Area Injection Order 4B, Finding 7 as incorporated in AIO #4E. Several lined pits comprising the "material transfer station" (MTS) at DS 4 were operated to temporarily hold ongoing drilling and oily solids when necessary. On an infrequent basis, flow back liquids from new wells drilled with oil -based mud (OBM) or other wastes were injected directly into G &1 wells using temporary equipment staged on the Surfcote pad. As of September 30, 2012, project injection has included 51.8 MM barrels of water, 88.0 MM barrels of slurry containing 5.4 MM tons (6.0 MM cubic yards) of excavated reserve pit material and other waste solids, and 7.0 MM barrels of fluid from ongoing drilling operations. Exhibit 1 summarizes this data. 1 • . . Operations Operations during the year were affected by seawater supply interruptions due to high winds, power outages and maintenance work at the Seawater Treatment Plant and the Seawater Injection plant. G &I maintenance activities included an extensive inspection program of the piping and processing equipment within the plant and the pipelines to the wells. Major operations and maintenance activities included replacement or repairs of process valves and piping, ball mill liner and motor, super sucker tent heater, well manifold and valves, and make -up air units. Solids processing in the G &I plant was shut down during the 2011 summer until early February 2012, and from late May 2012 through the present. Disposal of ongoing liquid drilling wastes and water from pit dewatering operations continued during much of the summer shut down period. Solid wastes accumulated during the summer were stored at the MTS and processed when the full plant was in operation. The pace of excavation from the production reserve pits was reduced in 2010 with the concurrence of the Alaska Department of Environmental Conservation and batch processing of solids rather than continuous processing has been used as needed since. Well Operations and Monitoring The four GNI disposal wells are located on the Surfcote pad and continue to be available for disposal. Well GNI -01 has been shut -in due to tubing damage since May 2007, but it could be available for Class 11 direct injection pending current mechanical integrity testing or for observation purposes if needed. It was replaced for Class I waste and slurry injection by well GNI -04 which began in May 2008. Well GNI -02A was sidetracked to a new bottom hole location in November /December 2006 and is an active Class I waste and slurry injector. Existing Class I well GNI -03 is also active after a workover in December 2009 to replace damaged tubing. Each well is perforated in the Ugnu formation between 6400 and 6600 ft TVD. GNI plant discharge rate, temperature and slurry density, along with well injection pressure and temperature and annulus pressures are continuously monitored in the G &I Plant control room. Injection takes place into one well at a time on a rotating schedule. After each injection cycle, the newly shut in well is flushed with water and freeze protected with new product methanol mixed with water. Exhibit 4 lists the injection cycles and the well work and surveillance activities during the report period. The injection history and performance for each well is shown in Exhibits 1, 2, 3, 5, 6 and 10. Peak slurry injection rates are normally between 25,000 and 35,000 barrels per day with between 1,500 and 3,000 cubic yards per day of solids processed. Injected slurry density averaged about 9.5 ppg when solids were being processed (Exhibit 6). Surface injection pressure is heavily influenced by the slurry injection rate, slurry density and to some extent slurry temperature due to viscosity dependence on temperature and the impact of injection temperature on formation stress. Daily average surface injection and calculated bottom -hole injection pressures (BHIP) are shown in Exhibit 6 for each well. BHIP is calculated to account for the effects of the hydrostatic head and fluid friction of the slurry column. The calculated bottom hole injection pressures in each well have shown relatively stable injection pressures over the last year. All three active wells have maintained good formation injectivity with no sign of formation plugging. 2 • • By design, the outer annulus (OA) of each GNI well is in weak pressure communication with the formation adjacent to its surface casing shoe set at about 4000 ft TVD (GNI -03 and GNI -04) and about 2800' TVD in the GNI -02A sidetrack. The surface pressure in each outer annulus is monitored as potential indicator of any significant fluid movement above the approved injection interval. The OA pressure is also quite sensitive to thermal expansion or contraction of the annulus fluids resulting from the injection cycle and injection fluid temperature variations. The inner and outer annuli of each well are closely monitored during a well swap and periods of higher temperature injection and the annulus pressures are bled as necessary. Due to the communication with the formation, OA pressure changes related to thermal effects begin to dissipate within a short time. There have been no significant sustained pressure increases adjacent to the surface casing shoe and no abnormal or unexplained annulus pressures observed during the report period. Each GNI well is equipped with control line tubing open ended within the inner annulus (IA) to about 1000 ft. This line allows several hundred feet of nitrogen cushion to be maintained in the inner annulus (IA) to dampen the pressure changes due to thermal expansion or contraction of the annulus fluid. There has been no indication of tubing or packer leakage observed in any of the GNI wells, although the IA pressure may need to be bled during periods of high temperature injection and re- charged during periods of cooler injection. Exhibit 10 contains daily average tubing, IA and OA pressures for each of the wells. Dates when the annulus pressure was bled or re- pressured are also indicated. EPA witnessed mechanical integrity tests of the inner annulus are required annually under the Class I permit. The AOGCC requires an MIT -IA every two years in slurry injection wells under AIO 4E, Rule 6. Successful MIT -IA tests were performed in GNI wells 02A,_ am] 04onSeptember 23, 2012. EPA representatives witnessed each of these MIT -IA tests. Memory caliper logs were run in GNI wells 02A, 03 and 04 to inspect the 7" tubing strings in 2012. GNI -01 has remained shut -in since May 2007 due to the level of tubing damage. The following table lists the observed maximum metal loss in the tubing and the casing below the packer from the caliper Togs run during the report period. Well Date Max Pit Penetration Max Cross - Sectional Wall Loss Tubing Casing Tubing Casing GNI -02A 07/01/12 34% 26% 23% 15% GNI -03 06/14/12 13% 57% 4% 24% GNI -04 06/20/12 26% 26% 15% 14% After isolation of the tubing with bridge plugs and two way check valves, the trees on each of the wells were replaced and inspected for erosion and corrosion damage. Very little damage was observed on the trees which have been in service since 2010. 3 • • ` Well Surveillance and Testing The cycling of wells on injection generally allows well surveillance and maintenance activities to be scheduled with little disruption to G &I plant operations. To minimize freeze protection concerns, repeat well tests and logs are usually scheduled in the summer. The shut in temperature /pressure survey results for 2012 and prior years are shown in Exhibit 7. Repeat shut -in temperature /pressure logs were run in the wells in June and July. Based on the fill tags and the temperature profiles, all injection continues to exit each wellbore through the perforated intervals. The temperature p e I 9 very logs have ve similar character to the previous logs in each well. Consistent with the 2011 results, the temperature Togs have shown Tess than 500 feet TVD of vertical fluid movement. Since the GNI well bores are deviated and the effective depth of investigation of temperature logs is limited, the full extent of injection through vertical fractures may not be detected by the temperature logs. Observed static reservoir pressures obtained with the GNI -02A, 03 and 04 shut -in temperature /pressure logs were close to the 2011 measurements: -9 psi in GNI -02A, -11 psi in GNI -03, and +5 psi in GNI -04. Repeat step rate tests (SRTs) were performed in wells GNI -02A, 03 and 04 in July and August. Due to facility shut downs, two 2011 step rate tests were actually run after the 9/30/11 data cutoff for last year's report. The analyses for those tests were included in the 2011 report. The repeat SRT procedure included both a step up portion and a step down portion. Each SRT was analyzed using two methods to provide additional insight, a conventional analysis and a superposition method. The step rate test in well GNI -04 exhibited an unusual character with no specific fracture opening /propagation pressure indicated. This has been interpreted as injection into a pre- existing fracture or fracture network possibly held open by injected solids. Exhibit 8 discusses the 2012 step rate test data and analysis results. As in the past, SRT's confirm fractures are the primary disposal mechanism. Repeat surface pressure falloff (SPFO) tests were run in wells GNI -02A, 03 and 04 in June. Surface pressure falloff tests were run in the summer to avoid rate fluctuations due to freeze protection immediately prior to shut in. Also, since a well cannot be shut in while injecting slurry, each repeat SPFO test is run after a period of water injection containing only a small amount of mud liquids. No drilling mud was injected in the 24 hours prior to shutting in the well and the injection rate was stabilized. Normally, the SPFO tests are run after a period of seawater slurry injection. The SPFO tests should be viewed as representing a snapshot in time that may not completely reflect the downhole flow conditions present due to the differences with fluid rheology under actual slurry injection. As with past tests, calibrated surface memory gauges were used to record the pressure falloff data. 4 i • Exhibit 9 discusses the 2012 SPFO test analysis results. Several reservoir flow models were used in an attempt to obtain a type curve match of the data. The SPFO data from each of the wells was best matched using a radial composite double - porosity (RCDP) reservoir model. The tests from each of wells showed evidence of a damaged zone some distance from the wellbore. Storage Mechanism and Disposal Domain As reported in the past, a number of industry studies have been conducted to understand the downhole storage mechanism in slurry injection operations. These include two major industry studies: the Drilling Engineering Associates (DEA) 81 Joint Industry Project (JIP) laboratory study and the Mounds Drill Cuttings Injection JIP field pilot study. Individual operators have also reported monitoring and well testing programs to delineate the storage mechanism and geometry. Many of these studies and monitoring programs agree that multiple fractures are created during periodic injection operations. Step rate tests and pressure falloff tests of the GNI wells have also showed signatures of multiple opening or multiple closure events, indicating multiple fractures from GNI operations. The result is likely a complex disposal domain consisting of a series of fractures developed over time with different orientations. Branching fractures may also be a part of the storage mechanism. This disposal domain allows for the storage of large amounts of solids. Grind and Inject fracture modeling was updated in 2006 using a modified conventional hard rock fracture simulator adjusted for soft rock behavior and assuming the disposal domain described above. The layer description was extended upward and downward to include 22 layers. The updated model runs predicted fractures to be contained below 5900 ft TVD at that time, about 600 ft above the perforations in the original GNI completions. At some point the increasing stress due to solids storage in the fractures of the disposal domain will create conditions resulting in possible additional upward fracture extension. The model results indicate fracture growth to near 5000 ft TVD at some time beyond the year 2020, still well below the top of the approved interval at about 4500 ft TVD. While the primary G &I surveillance techniques (temperature logs, step rate tests and pressure falloff tests), the results from a prototype bore hole gravity meter reported in 2010 and the model results provide differing inferences as to the size of the fracture system (partially due to the specific conditions of each test), all indicate limited upward movement of the injected material and confinement well within the approved interval specified in EPA UIC Class 1 permit AK- 11008 -A, Part II 3 c 4 and AIO #4E, Rule 2. Well Plans Well GNI -01 has significant tubing damage and has injected over 1.6 MM cubic yards of waste drilling solids. Well GNI -01 could be available for occasional direct injection of Class II materials pending current mechanical integrity testing, and to observe various facets of the slurry injection process if needed. Routine waste injection is expected to continue to be cycled between the three active Class I disposal wells. 5 , , III 411 . Operational Plans The operational plan for the next twelve months will involve similar activities to those in recent years. Discussions are ongoing with Alaska Department of Environmental Conservation concerning the scope of the remaining production reserve pit closeout activities required by the State of Alaska's Inactive Reserve Pit Closure Regulations. While a significant feed for the G &I plant will be excavated drilling mud and cuttings from exploration reserve pits and well sites, the pace of excavation from the production reserve pits will likely remain reduced. As was the case in 2012, solid waste material will be processed in batches rather than continuously, except when the mill is shut down for maintenance, during well switches and for brief periods due to weather or utility outages. Class II liquids and solids from on -going drilling operations will be processed at the G &I plant on a periodic basis determined by the drilling and well workover activities. Oily solids will be accepted at the material transfer station and processed at the G &I plant during winter months when the material can be handled in a frozen state and mixed with reserve pit wastes. Non - hazardous Class I materials will be processed and injected in the three active GNI slurry injection wells, GNI -02A, GNI -03 and GNI -04. Direct injection of crude oil contaminated with oil based drilling mud from the initial production from new wells and of other non - hazardous wastes will be utilized when necessary. Snow melt accumulating in reserve pits will be injected by the GNI plant in the summer as needed. Each of the three active GNI wells will be used for injection on a rotating schedule as described above. 6 A n • Prudhoe Bay Unit, Grind & Inject Project, Surfcote Pad Injection EPA UIC Class I Permit AK- 11008 -A Area Injection Order #4E, Rule 10 Annual Performance Report October 1, 2011 through September 30, 2012 List of Exhibits 1. GNI Surfcote Injection Summary 2. GNI Injection Bar Graph 3. a,b GNI Solids Injection Bar Graphs 4. GNI Surfcote Well Surveillance Activities 5. b,c,d GNI Wells Injection Bar Graphs 6. b,c,d GNI Wells Daily Average Data Plots 7. b,c,d GNI Wells Temperature Logs 8. GNI Wells Step Rate Tests 9. GNI Wells Pressure Falloff Tests 10. a,b,c,d GNI Wells TIO Pressure plots 7 • • bp BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator, PRB -20 Post Office Box 196612 Anchorage, Alaska 99519 -6612 May 20, 2012 Mr. Jim Regg Alaska Oil and Gas Conservation Commission 333 West 7 Avenue st„AtitiEDAUG 0 7 2012 Anchorage, Alaska 99501 I Subject: Corrosion Inhibitor Treatments of GPB GNI Dear Mr. Regg, Enclosed please find multiple copies of a spreadsheet with a list of wells from GPB GNI 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, API and PTD numbers, 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, Gerald Murphy, at 659 -5102. Sincerely, Mehreen Vazir 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) GNI Date: 03 32012 Corrosion Initial top of Vol. of cement Final top of Cement top off Corrosion inhibitor/ Well Name PTD # API # cement pumped cement date inhibitor sealant date GNI -01 1972380 50029228450000 0.7 NA 0.7 NA 5.1 3/6/2012 GNI -02A 2061190 50029228510100 5.0 NA 5.0 NA 30.6 3/6/2012 GNI-03 1971890 50029228200000 5.8 NA 5.8 NA 35.7 3/6/2012 • - GNI -04 2071170 50029233670000 2.3 NA 2.3 NA 13.6 3/6/2012 DATE: 27- Jul -12 Stephanie Pacillo TRANS #: 6020 cr Data Delivery Services Technician / Makana K Bender Schiumherger Oilfield Services -4, : . Natural Resources Technician II WIRELINE � .. daska Oil & Gas Conservation Co „ - ,-s 2525 Gambell St, Ste. 400 'ir 2:: _ 7: . - ; :/e. 5 t_- ; e 12 . :- - -"- - a e . : :- Anchorage, AK 99503 W: Office: (907) 273 -1770 6 f (2/ ' I :, WELL - SERVICE :OH RESERV: CNL MECH - LOG DESCRIPTION DATE - B/W COLOR CD's - NAME ORDER# DIST DIST DIST DIST. LOGGED PRINTS; PRINTS GNI -03 C600 -00012 X MEMORY TEMP PRESS SURVE' 13- Jun -12 1 1 CD GNI -04 COT4 -00019 X MEMORY TEMP PRESS SURVE' 19- Jun -12 1 1 CD MPL -12 BAUJ -00133 X MEMORY LEAK DETECTION LO 8- Jun -12 1 1 CD • Z -06A C2JC -00021 X SCMT 7" 31- May -12 1 1 CD 14 -33A C5XI -00006 X MEMORY DEPTH DETERMINATI 12- Jun -12 1 1 CD Z -06A C2JC -00021 X SCMT 4.5 31- May -12 1 1 CD 02 -35B C5XI -00008 X MEMORY PPROF W/ GHOST 18- Jun -12 1 1 CD L -04 C5XI -00005 X MEMORY IPROF 10- Jun -12 1 1 CD • V -207 C600 -00013 X MEMORY PPROF 15- Jun -12 1 1 CD J -26 BZ81 -00019 X RST WFL LOG 9- Jun -12 1 1 CD MPB -15 C2JC -00028 X PPROF W DEFT 25- Jun -12 1 1 CD MPG -14 C5XI -00007 X MEMORY LEAK DETECTION LO 15- Jun -12 1 1 CD GNI -02A COT4 -00035 X MEMORY TEMP PRESS SURVE' 7- Jul -12 1 1 CD 09 -18 C3NA -00021 X INJECTION PROFILE 14- Jun -12 1 1 CD • a x X Please return a signed copy to: Please return a signed copy to: BP PDC LR2 -1 E 1 , -., " DCS 2525 Gambell St, Suite 400 900 E Benson Blvd ,' _ , Anchorage AK 99503 Iv N Anchorage AK 99508 '" 9 • • BP Exploration (Alaska) inc P 0. Box 196612 900 E. Benson Boulevard Anchorage, AK 99519 -6612 USA Certified Mail # 7011 0110 0000 4759 2705 r t Jl E; , FEB e ry ; October 03, 2011 W UIC Manager, Ground Water Protection Unit U.S. Environmental Protection Agency (OCE -127) } 1200 Sixth Avenue, Suite 900 , i ; a a ',l saes .I�'�r�? � "r 3r 714,3 iT Seattle WA 98101 RE: Demonstration of Mechanical Integrity, Prudhoe Bay Grind and Inject, UIC Class 1 Permit AK- 11008 -A ff3tic - ozAs Prb zee a %) pat Gut -- C f7-6 1q7062 Dear Mr. Kowalski: ''! t COs. - 04 ! -o Ali 3,9 This letter is to submit the results of recent annulus pressure tests for three UIC Class! GNI wells and a tubing inspection log for one well. The wells are located at the Prudhoe Bay Grind and Inject project and operated by BP Exploration (Alaska), Inc (BPXA). The tests and log are specified as part of the demonstration of mechanical integrity under Part 11, C.3 of EPA UIC Class I permit AK11008 -A. The tests and log were conducted in compliance with the permit requirements and were witnessed by EPA representative Thor Cutler. The annulus pressure tests, also known as Mechanical Integrity Tests (MITs) were performed on wells GNI -02A, GNI -03 and GNI -04 on September 22, 2011. The three wells passed the MITs. Detailed information regarding the results of the MITs is contained in the attached descriptive and interpretive analysis of the tests. Enclosed also is a descriptive and interpretive report containing the results of a tubing Inspection Log run in well GNI -02A on September 23, 2011 as required under Part II, C.3.b(3) of the permit. There was no indication of a loss of well integrity. 1 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. UIC Manager • October 03, 2011 Page 2 BPXA understands that the EPA will notify BPXA of the acceptability of the mechanical integrity demonstration within 13 days of receipt of the results of the mechanical integrity tests (Part II, C.3.c.(4)). Injection may continue during this 13 day review period. If the EPA does not respond within 13 days, we will conclude that the results are acceptable and will continue with injection. If you have questions, please contact Michael Bill, Sr. Staff Engineer at (907) 564 -4692. Sincerely, K Fontaine Logistics /Infrastructure Manager Attachments: Mechanical Integrity Test Results Mechanical Integrity Test Forms Cc: Thor Cutler, EPA Region 10 (letter and report) Talib Syed, EPA Consultant (letter and report) Jim Regg, AOGCC (letter and report) Shawn Stokes, ADEC (letter and report) • ! UIC Manager October 03, 2011 Demonstration of Mechanical Integrity Prudhoe Bay Grind and Inject Project Annulus Pressure Test Results Annulus pressure tests were performed on UIC Class I Prudhoe Bay Grind and Inject disposal wells GNI -02A, GNI -03 and GNI -04 on September 22, 2011. The tests were performed in accordance with the stipulations of Class I Permit AK- 1I008 -A. In each well, the nitrogen cushion normally maintained in the tubing - casing annulus was bled off and displaced with diesel. The annulus was then pressured to above 1500 psi with diesel and observed for 30 minutes. The tests were conducted while GNI -03 was injecting and the other wells were shut in. The results of the tests were as follows: Tubing Pressure Annulus Pressure psi 1st Half 2nd Half Test GNI Well Start / End Start 15 Min 30 Min Decline Decline Result GNI -02A 265 / 261 1800 ' 1750 1742 50 8 ' Passed ; GNI -03 885 / 880 1801 1797 1794 4 3 ' Passed GNI -04 250 / 248 1799 1751 1743 48 8 Passed In wells GNI -02A and GNI -04, the pressure decline was less than 10 percent during the test period, with less than 1/3 of the total decline in the second half of the 30 minute period. This data shows a stabilizing tendency as specified in EPA Permit AK- 1I008 -A, Part II, C 3 b (1). In well GNI -03, the pressure decline was also less than 10 percent during the 30 minute test period, in fact less than 0.4 %. The test was extended another 30 minutes to ensure stability and the pressure declined only an additional 6 psi (0.33 %) during that period. Annulus pressures were observed on a recording digital test gauge. During the test period, the tubing pressure was essentially constant in each well. The tests were witnessed by EPA representative Thor Cutler. III • UIC Manager October 03, 2011 Demonstration of Mechanical Integrity Prudhoe Bay Grind and Inject Project Tubing Inspection Log Results EPA permit AK- 1I008 -A effective 09/01/07 requires a tubing inspection log in the Prudhoe Bay Unit Class I Grind & Inject wells each calendar year. Approved tubing inspection logs (Part II C 3 b (3)) include pipe analysis logs, caliper logs or other equivalent tests. Below are the results of the caliper log run recently in well GNI -02A. Tubing Inspection Log A 40 arm caliper logging tool, supplied by PDS (ProActive Diagnostic Services), was run on slickline to inspect the interior surface of both the tubing and the casing. A memory caliper log was run in well GNI -02A on September 23, 2011. The tubing inspection indicated the GNI -02A tubing is in good to fair condition with no significant erosion/corrosion. The tubing was new when the well was completed in December 2006. The casing below the tubing tail is also in good to fair condition. Below are the observed maximum metal losses observed in the tubing and casing from the caliper log. Well Date Maximum Pit PenetrationMax Cross - Sectional Wall Loss GNI -02A Tubing 09/23/11 33% 24% GNI -02A Casing 09/23/11 26% 15% The log was witnessed by EPA representative Thor Cutler. Enclosed are copies of the PDS Memory Multi - Finger Caliper, Log Results Summary for this well. Over All Conclusions I conclude from the successful MIT's that the casing, tubing and packer in wells GNI -02A, GNI - 03 and GNI -04 are in sound mechanical condition. This is consistent with the absence of any indication of tubing or packer leakage during normal injection operations when there is a large pressure differential ( >500 psi) between the tubing and the annulus in each of the wells. The GNI -02A caliper log indicates the tubing has maximum penetration of 33% but it is suitable for continued injection. Michael L. Bill, P.E September 26, 2011 United States Environmental Protection Agency Region lO 1200 Sixth Avenue, Suite 900 Seattle, WA 98101 Thor Cutler - (206) 553 -1673 e-mail: cutler.thor @epa.gov MECHANICAL INTEGRITY TEST (MIT) FORM Facility Well I Permit No. PTD No. BP Alaska - Prudhoe Bay Unit, G &I Wells GNI - 02A AK 1I008 - A 197 7- Vic Injector MIT Type Test Type Test Date Class I T X IA Std. Annular Pressure Test (SAPT) 9/22/2011 Req'd Test Fluid Type(s) used to Packer Depth (ft, Test Interval / Comments Presssure (psi) test TVD) 1,500 Diesel 4,537 One Year Cycle Record all Wellhead Pressures before and during Test. Note whether well is on injection or SI during test. If on injection, note injection rate, injection pressure and injection fluid temperature Note volume of diesel pumped in annulus during test. T START TIME: RECORDED PRESSURES (PSI) RESULT E 10:14 AM PRE MIT INITIAL 15 MIN 30 MIN 45 MIN 60 MIN P/F S TUBING 260 265 ' 261 261 - T INNER ANNULUS 14 1800 - 1750 1742 PASS ✓ OUTER ANNULUS 34 38 38 38 ' 1 COMMENTS: took 1.5 bbls diesel to pressure up T START TIME: RECORDED PRESSURES (PSI) RESULT E PRE MIT INITIAL 15 MIN 30 MIN 45 MIN 60 MIN S TUBING T INNER ANNULUS OUTER ANNULUS 2 COMMENTS: T START TIME: RECORDED PRESSURES (PSI) RESULT E PRE MIT INITIAL 15 MIN 30 MIN 45 MIN 60 MIN S TUBING T INNER ANNULUS OUTER ANNULUS 3 COMMENTS: MISC COMMENTS: NOTE: Pressure must show stabilizing tendency: 1) Total pressure loss must be Tess than 10 % at end of 30 minute test 2) Pressure loss in last 15 minutes must be less than 33% of total loss Start MIT over if 1) Total loss exceeds 10 % 2) Loss during last 15 minute period = or > 50% of loss during first 15 minute period Extend test duration to 60 minutes, if necessary, to eliminate thermal effects (on -site decision per Inspector). I 0 -- E - mail this MIT Test Data Form to EPA Region 10 - Thor Cutler EPA Rep: AOGCC Rep: Operator Rep: Thor Cutler Waived by John Crisp Jon Arend • • United States Environmental Protection Agency ' `j Region 10 J'' 2/7A t 1200 Sixth Avenue, Suite 900 ' Seattle, WA 98101 Thor Cutler - (206) 553 -1673 e -mail: cutler.thor @epa.gov MECHANICAL INTEGRITY TEST (MIT) FORM Facility Well I Permit No. PTD No. BP Alaska - PBU GNI -03 AK- 11008 -A 1971890 Injector MIT Type Test Type Test Date Class I T X IA Std. Annular Pressure Test (SAPT) 9/22/2011 Req'd Test Fluid Type(s) used to Packer Depth (ft, Presssure (psi) test TVD) Test Interval / Comments 1,500 Diesel 4,589 One Year Cycle Record all Wellhead Pressures before and during Test. Note whether well is on injection or SI during test. If on injection, note injection rate, injection pressure and injection fluid temperature Note volume of diesel pumped in annulus during test. T START TIME: RECORDED PRESSURES (PSI) RESULT E 12:48 PM PRE MIT INITIAL 15 MIN 30 MIN 45 MIN 60 MIN P/F S TUBING 887 885 ' 883 880 878 877 T INNER ANNULUS 87 1801 , 1797 1794 1790 1788 ' PASS OUTER ANNULUS 225 402 • 406 406 402 398- 1 COMMENTS: 1 bbls diesel to pressure up T START TIME: RECORDED PRESSURES (PSI) RESULT E PRE MIT INITIAL 15 MIN 30 MIN 45 MIN 60 MIN S TUBING T INNER ANNULUS OUTER ANNULUS 2 COMMENTS: T START TIME: RECORDED PRESSURES (PSI) RESULT E PRE MIT INITIAL 15 MIN 30 MIN 45 MIN 60 MIN S TUBING T INNER ANNULUS OUTER ANNULUS 3 COMMENTS: MISC COMMENTS: Dedicated G&I solids injection wet. Drilled in late 2007 with slung injection start on 5/22/08. NOTE: Pressure must show stabilizing tendency: 1) Total pressure loss must be less than 10 % at end of 30 minute test 2) Pressure loss in last 15 minutes must be less than 33% of total loss Start MIT over if 1) Total loss exceeds 10 % 2) Loss during last 15 minute period = or > 50% of loss during first 15 minute period Extend test duration to 60 minutes, if necessary, to eliminate thermal effects (on -site decision per Inspector). -- E -mail this MIT Test Data Form to EPA Region 10 - Thor Cutler EPA Rep: AOGCC Rep: Operator Rep: Thor Cutler Waived by John Crisp Jon Arend . United States Environmental Protection Agency } Region 10 1200 Sixth Avenue, Suite 900 Z I A t Seattle, WA 98101 Thor Cutler - (206) 553 -1673 e -mail: cutler.thor @epa.gov MECHANICAL INTEGRITY TEST (MIT) FORM Facility Well I Permit No. PTD No. BP Alaska - PBU GNI -04 AK- 1I008 -A 2071170 Injector MIT Type Test Type Test Date Class I T X IA Std. Annular Pressure Test (SAPT) 9/22/2011 Req'd Test Fluid Type(s) used to Packer Depth (ft, Presssure (psi) test TVD) Test Interval / Comments 1,500 Diesel 4,461' One Year Cycle Record all Wellhead Pressures before and during Test. Note whether well is on injection or SI during test. If on injection, note injection rate, injection pressure and injection fluid temperature Note volume of diesel pumped in annulus during test. T START TIME: RECORDED PRESSURES (PSI) RESULT E 14:54 PRE MIT INITIAL 15 MIN 30 MIN 45 MIN 60 MIN P/F S TUBING 248 250 - 248 248 T INNER ANNULUS 16 1799 , 1751 1743 — PASS OUTER ANNULUS 91 119 - 118 118 - 1 COMMENTS: Took 1.38 bbls to pressure up T START TIME: RECORDED PRESSURES (PSI) RESULT E PRE MIT INITIAL 15 MIN 30 MIN 45 MIN 60 MIN S TUBING PASS/ T INNER ANNULUS FAIL OUTER ANNULUS _ 2 COMMENTS: T START TIME: RECORDED PRESSURES (PSI) RESULT E PRE MIT INITIAL 15 MIN 30 MIN 45 MIN 60 MIN S TUBING PASS/ T INNER ANNULUS FAIL OUTER ANNULUS 3 COMMENTS: MISC COMMENTS: Dedicated G &I solids injection well. Drilled in late 2007 with slurry injection start on 5/22/08. NOTE: Pressure must show stabilizing tendency: 1) Total pressure loss must be less than 10 % at end of 30 minute test 2) Pressure loss in last 15 minutes must be less than 33% of total loss Start MIT over if: 1) Total loss exceeds 10 % 2) Loss during last 15 minute period = or > 50% of loss during first 15 minute period Extend test duration to 60 minutes, if necessary, to eliminate thermal effects (on -site decision per Inspector). 1 1 — E -mail this MIT Test Data Form to EPA Region 10 - Thor Cutler EPA Rep: AOGCC Rep: Operator Rep: Thor Cutler Waived by John Crisp Jon Arend • 10 piik Memory Multi- Finger Caliper op Log Results Summary Company: BP Exploration (Alaska), Inc. WeII: GNI -02A Log Date: September 23, 2011 Field: Prudhoe Bay Log No.: 13006 State: Alaska Run No.: 7 API No.: 50- 029 - 22851 -01 Pipet Desc.: 7 in. 29 Ib. L -80 BTC -M Top Log Intvl.: Surface Pipet Use: Tubing Bot. Log Intvl.: 5,189 Ft. (MD) ?ipe2 Desc.: ?.325 in. 47 €b. L.-80 373-N! Top Log i tvi.: 3,189 Ft. (MD) ?ipe2 Use: Production Casing Bot. Log intvi.: 3,160 Ft. (MD) Inspection Type : Corrosion & Erosion Monitoring Inspection COMMENTS : This caliper data is tied into the WLEG at 5,189 feet (Driller's Depth). This log was run to monitor changes in the condition of the 7 inch tubing and 9.625 inch production casing with respect to corrosive, erosive and mechanical damage as a result of sustained solids injection. The caliper recordings indicate the 7 inch tubing appears to be in good to fair condition. Wall penetrations between 20% and 33% wall thickness are recorded in 131 of the 133 joints logged and cross - sectional wall loss ranging from 15% to 24% metal volume are recorded in 38 of the 133 joints logged. Recorded damage appears as apparent erosion throughout the tubing. No significant I.D. restrictions are recorded. The caliper recordings indicate the 9.625 inch production casing logged appears to be in good to fair condition with respect to corrosive, erosive and mechanical damage. Wall penetrations between 20% and 26% wall thickness are recorded in 72 of the 74 joints logged and cross - sectional wall loss of more than 15% metal volume is recorded in 8 of the 74 joints logged. Recorded damage appears as apparent erosion throughout the production casing logged. No significant I.D. restrictions are recorded throughout the production casing logged. This is the seventh time a PDS caliper has been run in this well and the fifth time this tubing and production casing have been logged. A comparison of the current and previous log (June 30, 2010) of the 7 inch tubing indicates an increase in erosive damage during the time between logs. A graph illustrating the difference in maximum recorded wall penetrations on a joint-by-joint basis between Togs is included in this report. A comparison of the current and previous log (June 30, 2010) of the 9.625 inch production casing logged indicates no increase in 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. 7 INCH TUBING - MAXIMUM RECORDED WALL PENETRATIONS : Apparent Erosion ( 33 %) Jt. 13 © 543 Ft. (MD) Apparent Erosion ( 33 %) Jt. 3 @ 116 Ft. (MD) Apparent Erosion ( 31%) Jt. 52 @ 2,107 Ft. (MD) Apparent Erosion ( 31%) Jt. 28 @ 1,138 Ft. (MD) Apparent Erosion ( 31%) Jt. 23 @ 936 Ft. (MD) ProActive Diagnostic Services, Inc. / P.O. Box 1369, Stafford, TX 77497 ?hone: (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 • 0 7 INCH TUBING - MAXIMUM RECORDED CROSS - SECTIONAL METAL LOSS : Apparent Erosion ( 24 %) Jt. 5 @ 217 Ft. (MD) Apparent Erosion ( 23 %) Jt. 3 @ 136 Ft. (MD) Apparent Erosion ( 23 %) Jt. 4 @ 149 Ft. (MD) Apparent Erosion ( 23 %) Jt. 7 @ 297 Ft. (MD) Apparent Erosion ( 22 %) Jt. 8 @ 340 Ft. (MD) 7 INCH TUBING - MAXIMUM RECORDED ID RESTRICTIONS : No significant I.D. restrictions are recorded. 9325 INCH CASING - MAXIMUM RECORDED WALL PENETRATIONS : Apparent Erosion ( 26 %) Jt. 61 @ 7,608 Ft. (MD) Apparent Erosion ( 25 %) Jt. 60 @ 7,569 Ft. (MD) Apparent Erosion ( 25 %) Jt. 73 © 8,131 Ft. (MD) Apparent Erosion ( 25 %) Jt. 54 @ 7,348 Ft. (MD) Apparent Erosion ( 25 %) Jt. 29 @ 6,359 Ft. (MD) 9.525 INCH CASING - MAXIMUM RECORDED CROSS - SECTIONAL METAL LOSS : Apparent Erosion ( 15 %) Jt. 52 @ 7,278 Ft. (MD) Apparent Erosion ( 15 %) Jt. 53 @ 7,298 Ft. (MD) Apparent Erosion ( 15 %) Jt. 65 @ 7,783 Ft. (MD) Apparent Erosion ( 15 %) Jt. 56 @ 7,426 Ft. (MD) Apparent Erosion ( 15 %) Jt. 33 @ 6,509 Ft. (MD) 9.625 INCH CASING - MAXIMUM RECORDED ID RESTRICTIONS : No significant I.D. restrictions are recorded throughout the production casing logged. Field Engineer: Wm. McCrossan Analyst: C. Waldrop Witness: B. Rochin 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) 559 -2307 Fax: (907) 659 -2314 0 0 A ir--- - Si 1 PDS Report Cross Sections Well: GNI -02A Survey Date: September 23, 2011 Field: Prudhoe Bay Tool Type: UW MFC XR 40 No. 218451 Company: BP Exploration (Alaska), Inc. Tool Size: 2.75 Country: USA No. of Fingers: 40 Tubing: 9.625 ins 47 ppf _ L -80 BTC -M Analyst: C. Waldrop Cross Section for Joint 53 at depth 7297.630 ft Tool speed = 52 Nominal ID = 8.681 = Nominal OD = 9.625 / �� - Remaining wall area = 85 %, III 1 � �N `�� Tool deviation = 44° �/ �� / , /i f A \ ' 1/ \ \ :1- S JJ • ' '' - \ ; Finger = 25 Penetration = 0.089 ins Apparent Erosion 15% Cross - Sectional Wall Loss HIGH SIDE = UP • • IPIII PDS Report Cross Sections Well: GNI-02A Survey Date: September 23, 2011 Field: Prudhoe Bay Tool Type: UW MFC XR 40 No. 218451 Company: BP Exploration (Alaska), Inc. Tool Size: 2.75 Country: USA No. of Fingers: 40 Tubing: 9.625 ins 47 ppf L-80 BTC-M Analyst: C. Waldrop Cross Section for Joint 52 at depth 7277.780 ft Tool speed = 53 Nominal ID = 8.681 -- --„ - _____ - Nominal OD = 9.625 ---- - \ .-- 1 ---/--------,„. `..,, Remaining wall area = 85% / ,--- \ 1 1 / '•\-, , \ Tool deviation = 44° 7 \ , ,,/ / / N \ !• / / .:, / , \ -. , / \ 1 , ! / 7 - ' . \ . / \ • , -- -- ■ . \ ------ 1 ' I --- --- ,__- -- . , \ \ . r ---- ■ 1 ' \ ----- - - --- I ,, ,,..., .. , .-- / .,.._. Finger = 37 Penetration = 0.105 ins Apparent Erosion 15% Cross-Sectional Wall Loss HIGH SIDE = UP le 1 jiikr3- c PDS Report Cross Sections Well: GNI -02A Survey Date: September 23, 2011 Field: Prudhoe Bay Tool Type: UW MFC XR 40 No. 218451 Company: BP Exploration (Alaska), Inc. Tool Size: 2.75 Country: USA No. of Fingers: 40 Tubing: 9.625 ins 47 ppf L -80 BTC -M Analyst: C. Waldrop Cross Section for Joint 60 at depth 7568.950 ft Tool speed = 52 — -__ _ Nominal ID = 8.681 ` _------- '� Nominal OD = 9.625 1 . I ` � Remaining wall area = 87% / ! N Tool deviation = 49° ` r / / /,/ \ \ \\ • ! 1 \ \ f" { r • 0 \ ' � �, Finger = 36 Penetration = 0.120 ins Apparent Erosion 0.12 ins = 25% Wall Penetration HIGH SIDE = UP i 0 111W IL- PDS Report Cross Sections Well: GNI -02A Survey Date: September 23, 2011 Field: Prudhoe Bay Tool Type: UW MFC XR 40 No. 218451 Company: BP Exploration (Alaska), Inc. Tool Size: 2.75 Country: USA No. of Fingers: 40 Tubing: _ 9.625 ins 47ppf L -80 BTC -M Analyst: C. Waldrop Cross Section for Joint 61 at depth 7607.650 ft Tool speed = 49 __ Nominal ID = 8.681 =_,. _-___,, Nominal OD = 9.625 Remaining wall area = 88% � , A Tool deviation = 49° 1 7 / / \ \. 1 w v / / I 'x�, ' 1 \ \ ,--__ , \ s\ \ - -: / ' \ A ` / � / - Finger = 24 Penetration = 0.125 ins Apparent Erosion 0.13 ins = 26% Wall Penetration HIGH SIDE = UP i • PDS REPORT JOINT TABULATION SHEET Pipe: 9.625 in 47.0 ppf L-80 BTC -M Well: GNI -02A Body Wall: 0.472 in Field: Prudhoe Bay Upset Wall: 0.472 in Company: BP Exploration (Alaska), Inc. Nominal I.D.: 8.681 in Country: USA Survey Date: September 23, 2011 Joint Jt. Depth Pen. Pen. Pen-. Metal Min. I Damage Profile 1 No. (Ft.) Upset Body % Loss I.D. Comments (% wall) (Ins.) (Ins.) % (Ins.) 0 50 100 1 5189 0.09 0.10 21 12 8.71 j Apparent Erosion. • r 2 5233 0.09 0.11 22 14 8.71 Apparent Erosion. • 3 5274 0.09 0.11 22 1 13 8.72 Apparent Erosion. • 4 5315 0.09 0.10 ! 20 I 12 8.71 Apparent Erosion. ■ 5 5354 0.08 0.11 22 13 8.70 Apparent Erosion. ■ 6 5395 0.07 0.10 20 13 8.73 Apparent Erosion. 7 5436 0.07 0.09 I 19 12 8.70 Shallow Apparent Erosion. 8 5476 0.07 0.09 19 13 8.71 _ ! Shallow Apparent Erosion. 9 5516 0.09 0.11 23 14 8.71 Apparent Erosion. 10 5558 0.08 I 0.10 I 20 13 8.71 Apparent Erosion. _ ___ _ ■ 11 5599 0.08 0.11 22 1 14 8.74 I Apparent Erosion. • 12 5638 0.07 0.10 21 I 13 8.73 Apparent Erosion. __ ■ 13 5676 0.09 0.11 , 23 13 8.73 Apparent Erosion. ■ 14 5718 0.07 1 0.10 J 21 12 8.71 Apparent Erosion. • 15 5760 0.08 0.10 21 L 14 8.73 , Apparent Erosion. • 16 5800 0.08 0.11 22 14 8.73 J Apparent Erosion. _ • 17 5841 0.11 0.12 ! 24 X13 8.69 Apparent Erosion. • 18 5883 0.08 0.11 23 I 12 8.71 Apparent Erosion. ■ 19 5924 0.07 1 0.11 23 j 13 8.70 Apparent Erosion. ■ 20 5964 0.09 0.11 22 1 14 8.73 1 Apparent Erosion. • 21 6004 0.08 0.11 22 13 8.71 1 Apparent Erosion. ■ 22 6045 0.09 0.11 i 22 14 8.72 Apparent Erosion. • 23 6085 0.11 1 0.12 L 25 14 8.71 Apparent Erosion. • 24 6127 0.09 0.11 23 14 8.72 Apparent Erosion. ■ 25 6166 0.08 0.10 ; 21 1 13 8.73 1 Apparent Erosion. • 26 6206 0.08 ! 0.10 21 13 8.74 Apparent Erosion. • 27 6246 0.07 j 0.10 1 20 1 14 8.73 Apparent Erosion. • 28 6287 0.09 0.10 ' 21 13 _ -_ 8.71 L Apparent Erosion. -__ • 29 6328 _- 0.08 .I_ 0.12 25 13 8.70 Apparent Erosion. ■ 1 30 6369 0.10 0.12 24 14 _8.71 Apparent Erosion. ■ 31 6409 0.09 0.11 22 14 8.74 Erosion. • I 32. -_6450 0.07 0.10 20 14 8.70 Apparent Erosion. • 33 6488 0.11 1 0.11 ; 22 15 8.75 Apparent Erosion. • 34 _ 652 9 0.08 0.11 22 I 14 -_ 8.72 Apparent Erosion. 1_ 35 65771 1 36 65 0.09 0.10 0.08 0.10 20 13 _ Apparent Erosion. • _ ' 21 14 8.75 Apparent Erosion. ------ - -_ -.- _ - -- - ■ 37 6648 0.09 j 0.11 22 14 8.72 Apparent Erosion__ 38 6686 0.09 1 0.10 1 20 - 13 8.73 _ Apparent Erosion. • 1 i I 39 6728 0.09 1 0.12 24 I 14 8.72 Apparent Erosion. ■ j 1 40 6767 0.08 j 0.11 22 14 8.71 1 Apparent Erosion. 41 6808 0.10 1 0.11 1 23 i 15 8.74 Apparent Erosion. • 42 6848 0.09 1 0.11 1, 22 14 8.72 Apparent Erosion. • 43 6891 0.09 0.10 1 21 13 8.73 1 Apparent Erosion. • 44 6932 0.07 0.11 23 1 13 8.71 Apparent Erosion. 45 6968 0.09 0.12 ! 24 14 8.73 Apparent Erosion. 46 7006 0.09 1 0.12 ; 24 13 8.69 Apparent Erosion. 47 7044 0.09 0.11 23 14 8.72 Apparent Erosion. 48 7083 0.10 0.11 23 i 14 8.73 Apparent Erosion. 1 i 49 7122 0.09 f 0.11 1 22 _ 14 8.72 _ _ Apparent Erosion. 50 7165 0.08 0.10 21 i14 8.70 � Apparent Erosion. _ ■ 1 1 Penetration Body ' Metal Loss Body Page 1 • • PDS REPORT JOINT TABULATION SHEET Pipe: 9.625 in 47.0 ppf L-80 BTC -M Well: GNI -02A Body Wall: 0.472 in Field: Prudhoe Bay Upset Wall: 0.472 in Company: BP Exploration (Alaska), Inc. Nominal I.D.: 8.681 in Country: USA Survey Date: September 23, 2011 1 Joint Jt. Depth Pen. j Pen. 1- Pen. Metal Min. ; Damage Profile ; No. (Ft.) Upset ! Body 96 ! Loss I.D. Comments (% wall) (Ins.) (Ins.) I % (Ins.) i 0 50 100 51 720 4 52 7204 0. 1 0.11 j 22 15 8.73 Apparent Erosion. j 0.12 I 24 15 8.73 Apparent Erosion. 53 7284 0.10 0.11 I 23 15 8.72 Apparent Erosion. 54 7324 0.09 1 0.12 25 ! 14 8.71 Apparent Erosion. 55 7360 0.11 ( 0.12 24 j 14 8.71 , Apparent Erosion. 56 __. 7400 0.09 0.11 _ 1 22 1 15 8.74 ! Apparent Erosion. _ I -- 57 7441 0.08 0.11 1 23 i 138.71 I Apparent Erosion. _ I) .1 58 7480 0.07 t 0.10 f, 20 13 8.72 - Apparent Erosion_ _ __ I j 59 _ _. 7522 0.09 , 0.12 24 _ _ 13 8.72 I Apparent Erosion. 60 7564 0.09 0.12 j 25 14 8.72 Apparent Erosion. 61 7605 0.08 0.13 1 26 14 8.70 1 Apparent Erosion. _ 62 7644 0.09 0.11 22 14 _ 8.72 Apparent Erosion. j [ _ 63 7686 0.08 _ 0.11 _ 22 ' 14 8.73 1 Apparent Erosion. 64 772 7 0.07 0.11 22 14 _ 8.70 Apparent Erosion. -- _ - -- I i j 65 _ 7768 0.09 0.11 4._ 23 15 8.72 Apparent Erosion. - - - ! j 66 - 7809 1 0.10 ' 0.11 22 14 8.71 Apparent Erosion. _ 67 __ - 7849 0.09 0.11 22 14 8.73 Apparent Erosion. 1 68 7889 0.09 0.11 23 12 8.70 Apparent Erosion. - i 69 7931 0.09 0.10 21 15 8.75 Apparent Erosion. 1 70 7969 0.09 ' 0.11 22 13 8.72 Apparent Erosion. 71 8010 0.09 1 0.12 j 24 14 8.72 1 Apparent Erosion. I 72 8051 0.07 1 0.10 1 21 13 8.73 j Aoparent Erosion. I . 73 8090 0.10 i 0.12 i 25 13 8.56 j Apparent Erosion. Lt. Deposits. j j 1 i._ 74 1 8132 0.08 i 0.11 . 23 1 11 8.51 I Apparent Erosion. Lt. Deposits. _ I I I I Penetration Body Metal Loss Body Page 2 0 • PIS Report Overview Body Region Analysis Well: GNI-02A Survey Date: September 23, 2011 Field: Prudhoe Bay Tool Type: UW MFC XR 40 No. 218451 Company: BP Exploration (Alaska), Inc. Tool Size: 2.75 ' Country: USA No. of Fingers: 40 1 Tubing: 9.625 ins 47 ppf L-80 BTC-M Analyst: C. Waldrop Tubing: Nom.OD Weight Grade & Thread Nom.ID Nom.Upset Upper len. Lower len. 1 1 9.625 ins 47 ppf L-80 BTC-M 8.681 ins 9.625 ins 6.0 ins 6.0 ins Penetration(% wall) Damage Profile (% wall) 80 1 1=0 Penetration body Metal loss body , i 0 50 F 100 ; 1 ' ; 60 rill ' I I ; i 40 ; , 1 I I , 1 20 - H ' . L I — 0 — , — 0 to 20 to 40 to over 21 — I 20% 40% 85% 85% , ,--- Number of joints analKsed (total = 74) 2 72 0 0 _I 31 . 1 - . . Damage Configuration ( body ) 41. 80 7 -- ... 60 4_ h 40 . 20 51 i .., 61 — 0 _. J , Isolated General Line Other Hole / , Pitting Corrosion Corrosion Damage Pos. Hole 71 .... ...- _Number of join_ts_damagedAtotal_= 74)- H 1 0 0 0 74 0 2 Bottom of Survey = 74 :., Maximum Recorded P rev i ous Penetration ckas. Comparison Well: GNI -02A Survey Date: September 23, 2011 Field: Prudhoe Bay Prev. Date: June 30, 2010 Company: BP Exploration (Alaska), Inc. Tool: UW MFC XR 40 No. 218451 Country: USA Tubing: 9.625" 47 lb L -80 BTC -M Overlay Difference Max. Rec. Pen. (mils) Diff. in Max. Pen. (mils) 0 100 200 300 400 -100 -50 0 50 100 mss* 11 11 21 21 31 " i I 31 .1 KIN. E E o � � I 41 H $ 41 i 51 51 a 61 61 71 � � 1 I. ( I 71 -81 41 0 41 81 0 September 23, 2011 ■June 30, 2010 Approx. Corrosion Rate (mpy) 0 • alb — PDS Report Cross Sections S Well: GNI -02A Survey Date: September 23, 2011 Field: Prudhoe Bay Tool Type: UW MFC XR 40 No. 218451 Company: BP Exploration (Alaska), Inc. Tool Size: 2.75 Country: USA No. of Fingers: 40 Tubing: 7 ins 29 ppf L -80 BTC -M Analyst: C. Waldrop _ Cross Section for Joint 3 at depth 135.990 ft Tool speed = 51 Nominal ID = 6.184 Nominal OD = 7 — Remaining wall area = 77% / Tool deviation = 0° <' \\''' - i 5 1 f t j / r t , L\ /' 1 // '� , / � \ '.7 Finger = 27 Penetration = 0.118 ins Apparent Erosion 23% Cross - Sectional Wall Loss HIGH SIDE = UP • • gili — PDS Report Cross Sections Well: GNI -02A Survey Date: September 23, 2011 Field: Prudhoe Bay Tool Type: UW MFC XR 40 No. 218451 Company: BP Exploration (Alaska), Inc. Tool Size: 2.75 Country: USA No. of Fingers: 40 Tubing: 7 ins 29 ppf L -80 BTC -M Analyst: C. Waldrop I Cross Section for Joint 5 at depth 216.680 ft Tool speed = 48 --�T---_- Nominal ID = 6.184 �- Nominal OD = 7 Remaining wall area = 76% ' i I 1 \\ Tool deviation = 0° ( // i I i ■ i i t i ; __ , j r � 1 \ �, N , / 1 Finger = 36 Penetration = 0.113 ins Apparent Erosion 24% Cross - Sectional Wall Loss HIGH SIDE = UP 0 PDS Report Cross Sections (........VS . Well: GNI -02A Survey Date: September 23, 2011 Field: Prudhoe Bay Tool Type: UW MFC XR 40 No. 218451 Company: BP Exploration (Alaska), Inc. Tool Size: 2.75 Country: USA No. of Fingers: 40 Tubing: 7 ins 29 ppf _L-80 BTC -M Analyst: C. Waldrop Cross Section for Joint 3 at depth 116.130 ft Tool speed = 56 _ --- ____ _ Nominal ID = 6.184 Nominal OD = 7 �� Remaining wall area = 77 % -, �\ Tool deviation = 0° -- -- / - N, Y 4 i 5 1 r , 1 // Finger = 26 Penetration = 0.133 ins Apparent Erosion 0.13 ins = 33% Wall penetration HIGH SIDE = UP • • PDS Report Cross Sections Well: GNI -02A Survey Date: September 23, 2011 Field: Prudhoe Bay Tool Type: UW MFC XR 40 No. 218451 Company: BP Exploration (Alaska), Inc. Tool Size: 2.75 Country: USA No. of Fingers: 40 Tubing: 7 ins 29 ppf L -80 BTC -M Analyst: C. Waldrop Cross Section for Joint 13 at depth 542.540 ft Tool speed = 56 -- Nominal ID = 6.184 Nominal OD = 7 Remaining wall area = 78 % _ tom N Tool deviation 0 a i / ' \ / �" ; \ 1 \ \ - - - ---- 1 f s , 7 /'/ Finger = 26 Penetration = 0.133 ins Apparent Erosion 0.13 ins = 33% Wall penetration HIGH SIDE = UP • • PDS REPORT JOINT TABULATION SHEET Pipe: 7. in 29.0 ppf L -80 BTC -M Well: GNI -02A Body Wall: 0.408 in Field: Prudhoe Bay Upset Wall: 0.408 in Company: BP Exploration (Alaska), Inc. Nominal I.D.: 6.184 in Country: USA Survey Date: September 23, 2011 Joint It Depth Pen. Pen. T Pen. Metal Min. 7- Damage Profile No. (Ft.) Upset Body % I Loss I.D. Comments I (% wall) (Ins.) (Ins.) % (Ins.) 10 50 100 50 2002 0.10 0.12 29 19 6.26 Apparent Erosion. 1 _ 51 2043 0.09 0.10 24 19 6.27 Apparent Erosion. 52 2083 0.11 0.13 ' 31 19 6.24 j Apparent Erosion. 53 212 4 0.10 1 0.11 I 26 16 6.23 Apparent Erosion. 54 2164 0.09 1 0.11 26 I 16 6.25 Apparent Erosion. 55 • 0.10' 0.11 28 L19 6.27 Apparent Erosion. 56 2244 0.11 0.11 28 ! 19 6.23 Apparent Erosion. _57 2284 0.10 _ ; 0.11 26 I 16 6.25 Apparent Erosion. 58 232 4 0.11 0.11 _ 28 I 18 6.25 Apparent Erosion. 59 2365 0.11 1 0.11 _ 26 1 18 6.23 Apparent Erosion. 60 2405 0.10 0.10 25 15 Apparent Erosion. 61 2445 0.10 _ 0.10 24 15 6.21 I Apparent Erosion. 62 _ 2485 0.10 - 0.12 - 29 18 6.22 Apparent Erosion. 63 2526 0.09 0 09 23 _ 15 6.21 Apparent Erosion. ((( 64 2567 0.10 0.11 28 18 6.23 Apparent Erosion. _ L 65 2608 0_09 .. f 0.10 24 - 15 6.24 j Apparent Erosion. 66 2648 0.10 +0.10 25 15 _ 6.25 Apparent Erosion. 67 2688 0.10 0.11 28 17 6.22 Apparent Erosion. 68 2729 0.09 0.10 25 15 6.23 Apparent Erosion. 69 2770 0.10 0.11 26 1 18 6.23 ! Apparent Erosion. I i 70 2810 0.09 j 0.09 23 I 15 6.24 Apparent Erosion. 71 2851 0.11 0.12 29 18 6.24 j Apparent Erosion. 72 2892 0.09 F 0.10 25 I 17 6.25 Apparent Erosion. 73 2933 0.09 1 0.11 28 I 17 6.25 Apparent Erosion. 74 2973 0.10 0.10 25 14 6.23 Apparent Erosion. 75 3014 0.09 0.10 25 j 16 6.24 Apparent Erosion. 76 3055 0.09 0.09 23 1 14 6.24 Apparent Erosion. I 1 _ 77 3096 0.10 ; 0.11 26 17 6.24 Apparent Erosion. 78 3137 0.10 0.10 25 14 6.22 Apparent Erosion. _ 79 3178 0.10 0.10 t 25 1 17 6.23 f Apparent Erosion. 80 3219 0.09 0.09 I 22__. 13 6.20 Apparent Erosion. 81 3259 0.09 0.10 1 25 17 6.25 T Apparent Erosion. 82 . 3300 0.09 ! 0.09 ! 22 13 6.21 Apparent Erosion. 83 3341 0.10 0.10 24 1 17 6.24 Apparent Erosion. _ 84 3381 0.08 0.08 ' 20x_14 6.23 _ Apparent Erosion_ ; 85 3420 0.09 _I 0.09 i 23 _� 156.23 Apparent Erosion. 86 _ 3460 0.09 0.09 ' 22 , 14 6.19 , Apparent Erosion. 87 3501 0.08 ; 0.09 22 13 6.23 Apparent Erosion. 88 3542 0.09 1 0.09 22 13 6.20 I Apparent Erosion. 89 3583 0.08 1 0.10 24 16 6.22 ! Apparent Erosion. 90 3624 0.08 0.10 24 16 6.23 Apparent Erosion. 91 3664 0.08 0.09 23 16 6.24 I Apparent Erosion. �J! 92 3705 0.09 0.09 ! 23 i 16 6.21 i Apparent Erosion. 93 3746 , 0.10 0.10 23 15 6.23 ! Apparent Erosion. 94 3786 0.08 0.09 ! 23 I 15 6.24 Apparent Erosion. I , 95 826 0.09 0.09 + 23 15 6.21 I Apparent Erosion. 96 1867 0.09 0.09 23 16 6.23 Apparent Erosion. 97 3908 0.09 i 0.10 25 14 6.23 Apparent Erosion. I j 98 .__ 3948 0.08 0.08 i 20 13 6.21 _ Appa rent Erosion. - ; 99 3989 a08 _: 0 l0 x 24 15 6.24 _ Aarent Erosion. Penetration Body Metal L Body Page 2 . ! PDS REPORT JOINT TABULATION SHEET Pipe: 7. in 29.0 ppf L -80 BTC -M Well: GNI -02A Body Wall: 0.408 in Field: Prudhoe Bay Upset Wall: 0.408 in Company: BP Exploration (Alaska), Inc. Nominal I.D.: 6.184 in Country: USA Survey Date: September 23, 2011 Joint Jt. Depth Pen. Pen. Pen. Metal Min. ! Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments 1 (% wall) (Ins.) (Ins.) % (Ins.) 10 50 100 100 4030 0.08 0.09 22 15 6.24 Apparent Erosion. , 101 4070 0.08 0.08 , 20 13 6.21 Apparent Erosion. 102 4111 0.09 0.09 22 12 6.21 Apparent Erosion. 103 4151 0.07 0.08 ' 20 12 6.21 I Apparent Erosion. I 104 4192 0.08 1 0.10 I 24 15 6.21 Apparent Erosion. 105 4233 0_07 _ ,0.08 ! 20 13 6.21 i Apparent Erosion. + 1 106 4273 0.08 0.08 20 12 6.19 _ ! Apparent Erosion. _ - . r 107 4314 0.09 f 0.09 22 {13 6.21 ! Apparent Erosion_ 108 _ 4355 0.09 0.10 23 ! 15 6.23 1 Apparent Erosion, __ 109 4396 0.07 0.08 L 20 __j_ 12 6.19 I Apparent Erosion. _ 110 4436 0.08 1 24 J 15 6.22 J Apparent Erosion. J. 111 4477 0.08 - 0.08 20 ' -12 6.20 . Apparent Ero __ , _ 112 4517 0.08. Y 0.08 20 _ 12 6.21 Apparent Erosion. - 113 4558 0.08 i 0.08 20 !12 6.19 Apparent Erosion. ______ i 114 4598 0.08 I 1 0.09 22 i 14 6.23 Apparent Erosion. • _ 115 _ 4639 0.07 T0 .10 Apparent Erosion. j - ! I 116 4639 0.07 _ _ 25 15 6.22 - i 0.09 j 22 12 - 6.20 Apparent Erosion. 117 4720 0.08 0.08 20 i 12 6.21 Apparent Erosion. 118 4761 0.07 0.08 20 12 6.20 I Apparent Erosion. 119 4800 0.08 1 0.08 20 ' 12 6.21 Apparent Erosion. 1111 i 120 4841 0.09 0.09 23 15 6.21 1 Apparent Erosion. 121 4881 0.08 i 0.08 20 I 12 6.19 Apparent Erosion. 122 4922 0.08 1 0.08 ; 20 12 6.21 Apparent Erosion. ' 123 4960 0.08 { 0.09 23 14 6.23 Apparent Erosion. ! .III 124 5001 0.08 0.09 23 14 6.22 I Apparent Erosion. 125 5042 0.09 0.09 ! 22 13 6.22 Apparent Erosion. l , 126 5082 0.07 0.08 19 12 6.21 Shallow Apparent Erosion. + 1 126.1 . 5123 0.08 0.09 _ 22 13 6.23 ; Pup Apparent Erosion. I 126.2 _ 5133 0_0 0 0 5.98 7" HES R Nipple ____ I 1 I I 126.3 5134 00 08 0.08 __ 20 _13 6.20 Pup Apparent Erosion. _+ I 126.4 _ 5144 0 . 1 0 0 . 0 9 2 2 1 4 _ 6.23 Pup Apparent Erosion. I I I 126 5154 0 0 0! 0_ 6.09 1 9.625" x 7" Baker S -3 Packer 1 126.6 5159 0.07 0.07 18 11 6.21 Shallow Apparent Erosion. __ 1 ' 126.7 5168 0.08 0.09 22 13 _ 6.22 I Pup Apparent Erosion. _ _ . __ I ' I 126.8 5178 0 i 0 0 0 5.98 7" HES R Nipple 126.9 5179 0.09 j , 0.09 22 ' 14 6.24 i Pup Apparent E rosion. 127.1 -- 5189 0 _� 0 0 I 0 6.291 7 "WLEG I - I I Penetration Body Metal Loss Body Page 3 • • PDS REPORT JOINT TABULATION SHEET Pipe: 7. in 29.0 ppf L -80 BTC -M Well: GNI -02A Body Wall: 0.408 in Field: Prudhoe Bay Upset Wall: 0.408 in Company: BP Exploration (Alaska), Inc. Nominal I.D.: 6.184 in Country: USA Survey Date: September 23, 2011 Joint Jt. Depth Pen. Pen. Pen. Metal Min. ! Damage Profile I No. (Ft.) Upset Body . To 1 Loss I.D. Comments 1 (% wall) (Ins.) (Ins.) I i % (Ins.) I0 50 100 i i 0.1 15 0.13 1 0.12 ! 30 21 6.29 Pup Apparent Erosion. T ; T I 1 19 0.11 0.12 i 30 22 6.28 Apparent Erosion. I 1 2 62 0.11 0.12 30 22 6.29 i Apparent Erosion. I 3 104 0.12 0.13 33 23 6.29 ! Apparent Erosion. I ! 4 144 0.12 0.13 I 31 23 6.30 j Apparent Erosion. 5 183 0.12 0.13 _ 31 24 6.31 Apparent Erosion. 6 224 0.10 0.12 29 a 22 6.30 Apparent Erosion. I 7 266 0.11 0.13' 31 23 _! Apparent Erosion. i ! 8 0.12 0.13 31 1 23 6.29 1 Apparent Erosion. f i I 9 _ 347 0.11 0.12 30 � 22 Apparent Erosion. iii i 1 10 386 0.13 0.12 30 22 6.28 Apparent Erosion. ,III j 1 1 428 0.11 1 0.12 30 - j 22 6.28 Apparent Erosion. ; I I I ! 12 468 0.10 ! 0.12 29 21 _ 6.28 Apparent Erosion. _ - -- - - - - - -- 13 0.12 0.13 33! i 22 6.28 I 1 Apparent Erosion. ; i 14 548 0_11 0.13 31 ! 22 6.28 Apparent Erosion. _ 1 15 588 0.11 0.12 1 30 ! 6.28 4 Apparent Erosion. _ - ' • 16 _ 629 0 .120.13 31 22 6.29 Apparent Erosion. 17 669 0.11 0.12 29 22 6.29 T Apparent Erosion. 18 710 0.11 0.12 29 21 6.28 Apparent Erosion. i 19 748 0.11 0.12 30 21 6.29 Apparent Erosion. 20 789 0.11 0.11 28 22 6.31 Apparent Erosion. i i , ' 21 828 0.10 ! 0.12 29 1 21 6.28 1 Apparent Erosion. i I 1 22 867 0.11 0.12 30 i 22 6.27 Apparent Erosion. i 1 ! 23 908 0.11 , 0.13 31 22 6.28 Apparent Erosion. 24 947 0.11 0.11 j 26 21 6.29 Apparent Erosion. ' 25 988 0.11 0.12 30 22 6.30 i Apparent Erosion. i , 26 1029 0.11 , 0.12 j 30 21 6.29 Apparent Erosion. __27 __ 1068 0.11 _; 0.12 30 _ _21 6.28 Apparent Erosion. ____ _ _ ', 28 1109 0.12 0.13 31 i22 6.30 Apparent Erosion. - - ' 29 1151 0.11 _.' 0 29 21 6.28 Apparent Erosion.____ _._.________ _ ___ ___ _ i 30 1191 0.11 0.11 28 6.27 I Apparent Erosion. 31 1232 0.11 0.12 29 22 6.28 1 Apparent Erosion. 1273 0.11 0.12 29 20 6.27 I Apparent Erosion. I 1 33 1314 0.11 0.12 29 20 6.27 1 Apparent Erosion. 341354 0.11 0.12 29 21 6.29 Apparent Erosion. 1 j 35 _ 1394 0.10 , 0.11 28 20 6.28 Apparent Erosion. ' 36 1435 0.10 0.12 29 21 _ 6.27 Apparent Erosion.___ _- -_ -__. _ __ 1 37 1475 0.11 ' 0.12 29 20 6.27 1 Apparent Erosion. 38 1516 0.11 0.11 28 19 6.27 Erosion. I 39 1557 0.10 0.11 28 20 6.27 1 Apparent Erosion. 40 1598 0.11 0.12 i 29 21 6.28 ! Apparent Erosion. 41 1639 0.11 0.12 ! 30 20 6.27 Apparent Erosion. 42 1679 0.10 0.11 I 26 19 6.29 Apparent Erosion. , 43 1721 0.12 0.11 28 21 6.28 ! Apparent Erosion. 1 I 44 1761 0.10 0.12 29 19 6.25 I Apparent Erosion. . j . 45 1800 0.10 0.11 26 19 6.27 I Apparent Erosion. , 1 I 1 1 46 1841 0.09 0.11 26 20 6.29 Apparent Erosion. , I ' I ' 47 1882 0.10 ! 0.12 1 29 19 6.26 Apparent Erosion. i ! i 48 _ 1923 0.11 1 i_28 19 - _ 6.26 % Erosion. - _ _ ! 1 49 _ 1964 0.10 0.12 I 29 18 _ _ 6.25 _ A_pparent Erosion_ L_i _1_ _ j i Penetration Body Metal Loss Body Page 1 GNI PDS Report Overview '� 411 . Body Region Analysis Well: Prudhoe Bay Tool Type: UW MFC XR 40 No. 218451 -02A Survey Date: September 23, 2011 Field: Company: BP Exploration (Alaska), Inc. Tool Size: 2.75 Country: USA No. of Fingers: 40 Tubing_ 7 ins 29 ppf L -80 BTC -M Analyst_ C. Waldrop Tubing: Nom.OD Weight Grade & Thread Nom.ID Nom.Upset Upper len. Lower len. 7 ins 29 ppf L -80 BTC -M 6.184 ins 7 ins 6.0 ins 6.0 ins Penetration(% wall) Damage Profile (% wall) 150 ® Penetration body i Metal loss body 0 �� 50 100 0 100 - _ E. 50 -. 0 0 to 20 to 40 to over 20% 40% 85% 85% Number of joints analysed (total = 133) 50 - 2 131 0 0 Damage Configuration ( body) _ - -_ - = 150 - _ 100 _ 101 50 — I 0 — Isolated General Line Other Hole / — Pitting Corrosion Corrosion Damage Pos. Hole • Num_b_er of n ama total - 13 J —.low t� ed gL j ! 0 0 0 133 0 I Bottom of Survey = 127.1 j • • Maximum Recorded Penetration ca, Comparison To Previous Well: GNI-02A Survey Dat « September 23, 211 F,¢ Prudhoe e Prey. Date: June 30, 2010 c _w BP Exploration (,4� a), Inc. a+ UW gem 40 No. 218451 Country: USA Tubing: 7 29 bL-80FGM Overlay Difference } ' ! Max. Rec. Pen. (mi ¥ Diff.. Maw . (mi m 0 100 200 300 400 400 -50 0 50 100 . o., } } } \ ! i ' !o . 1 10 l : . | ! 20 . . . ] : , 2 ) . � 30 . i 30 ! . ! .. . � 40 • , ! } ! q ! ( . | 50 ; 2 } 60 ® } 1 . } ( Z 70 � I \ " . 7 I ] } . i I m 80 } 1 ; ! i ` } « ; ! m, | 1 | i !m { !e I ! , 110 \ . } _ . 20 � ) - . 20 | 20 j / !z6 4 ! | 126 4 \ , , , | ! { . -81 41 0 a 81 September el g • J elm 2010 : • x. Corrosion Rate (mpy) • • Correlation of Recorded Damage to Borehole Profile Pipe 1 7. in (14.9' - 5189.4') Well: GNI -02A Pipe 2 9.625 in (5189.4'- 8131.6') Field: Prudhoe Bay Company: BP Exploration (Alaska), Inc. Country: USA Survey Date: September 23, 2011 r i Approx. Tool Deviation ■ Approx. Borehole Profile 1 19 25 988 50 2002 75 3014 100 4030 v ' � Z 125 5042 a v i O 1 5189 25 6166 50 111 7165 74 8132 0 50 100 Damage Profile (% wall) / Tool Deviation (degrees) Bottom of Survey = 74 TREE = FMC a SAFETY Na: KNOWN AS 4 -62 IN PBAS . 3/8" SS WELLHEAD = FMC - CONTROL LINE STRAPPED TO TOP 1000' OF 7" TBG. ACTUATOR = BAKER C KB. ELEV = 55.2' ' BF. ELEV = 20.9' KOP = 2832' Max Angle = 51 @ 7604' Datum MD = 8322' Datum TV D = 6000' SS ' I 1000' IH 3 -8" SS CONTROL LINE STRAPPED TO 7" TBG I Minimum ID = 5.963" @ 5132" 7" HES "R" NIPPLE MILLOUT WINDOW (GNI -02A) 2832' - 2864' 2897' -19-5/8" HES CEMENTER I • 5132' H 7" HES "R" NIP, ID = 5.963" I 13 -3/8" WHIPSTOCKI —J 2832' I 5153' -19-5/8" X 7" BKR S -3 PKR, ID = 6.00" I 5177' H 7" HES "R" NIP, ID = 5.963" 7" WLEG, • /� 5189' I- • 13 -3/8" EZSV H 2866' I ID = 6.184" / r 13 -3/8" CSG, 72 #, L -80, ID = 12.347" -) 3794' I--- XO TO 54.5 #, K -55, ID = 12.35" MIIIIIMMI 1 13 -3/8" CSG, 54.5 #, K -55, ID = 12.35" I--I 4137' I , PERFORATION SUMMARY REF LOG: SLB USIT /CBL ON 12/08/06 7" TBG, 29 #, L -80, BTC-M, 5189' ANGLE AT TOP PERF: 48 @ 8146' .0371 bpf, ID = 6.184" Note: Refer to Production DB for historical pert data SIZE SPF INTERVAL Opn /Sqz DATE 4-1/2" 5 8146 - 8166 0 12/25/06 9 -5/8" CSG, 47 #, L -80, BTC-M, ID = 8.681" I-J 8414' I DATE REV BY COMMENTS DATE REV BY COMMENTS PRUDHOE BAY UNIT 03/13/98 ORIGINAL COMPLETION 12/25/06 RRD /PAG INITIAL PERFORATIONS WELL: GNI -02A 12/10/06 D14 SIDETRACK "A" 07/28/10 ?/ PJC WELLHEAD CORRECTION PERMIT No: Y 2061190 10/30/06 JMF /PAG CIBP/ TBG PUNCH / CHEM CUT 12/12/10 JNL /PJC SECTION LOCATION UPDATE API No: 50- 029 - 22851 -01 11/05/06 SKB /TLH WAIV ERSFTY NOTE DELETED SEC 26, T11N, R15E, 982' FNL & 681' FEL 11/06/06 DSM/TLH TREEJWH CORRECTIONS 12/14/06 JGR/PJC DRLG DRAFT CORRECTIONS BP Exploration (Alaska) • • GNI Area Type Log GNI -02 Marker TVD GR ss I : -Perm: 10 "°' 110 _ 1 r ° d 500 S = Shallowest Permitted Class II _ _ � _ 4000 -�_ _ __ Fluid Injection Interval -4100 - _ - _- 4200__ 3 SV2 = _ _ - 4300 Nows _ — � - -4400 ° -4500 - - �_ Shallowest Permitted Class II - 4600 - -- Slurry Injection Interval -4700 SV1 —' - -4800 1 -- s == - -4900 — ----- -- = 5000 GNI area shallowest possible fracture =F �— growth based on fracture modeling U 4 - - _ -5100 UG 4A 4 _ _ -5200 -5300 -- °_ - -5400 ______ _ --- _ _ - 55 00 --- `..... 5600 - GNI area wellbore fracture height UG3 _ ____ growth based on pressure falloff ,, 3 - 5700 _ tests -5800 - _ — �_ Shallowest GNI -02A MDT pressure - - -5900 -x interval where formation pressures �`= -- -- - - were elevated above hydrostatic tom_ E - __ GNI area near wellbore fracture height - L -6100 _ _ _ E growth based on shut in temperature UG1 - -6200 logging T - -6300 M 1 '-- = MB2� - -6400 1 T -6500 Target Slurry MC S - i Injection Interval NA , ° -6600 N. IB = 6700 -- Projected TD of GNI -04 well WS1 /0 Sds - 6800 — 1 -fi900 CM3 Marker: Base of Permitted Class II L - Slurry Injection Interval Below GNI Well TDs (Projected at -6975° TVDSS in GNI -04 area) • • WELL LOG TRANSMITTAL • PRoAcrivE DiAgNOSric SERVICES, Inc. To: AOGCC Christine Mahnken 333 W. 7th Ave Suite 100 Anchorage, Alaska 99501 (907) 793 -1225 RE : Cased Hole /Open Hole /Mechanical Logs and/or Tubing Inspection(Caliper / MTT) The technical data listed below is being submitted herewith. Please acknowledge receipt by returning a signed copy of this transmittal letter to the attention of : BP Exploration (Alaska), Inc. Petrotechnical Data Center Attn: Nita Summerhays LR2 - 1 900 Benson Blvd. Anchorage, AK 99508' fi ��e and ProActive Diagnostic Services, Inc. Attn: Robert A. Richey 130 West International Airport Road Suite C Anchorage, AK 99518 Fax: (907) 245 -8952 7/( Z X33 67 1) Temperature Survey 09- Jul -11 GNI-04 1 / 1 CD 50- 029 - X3287 -00 2) Temperature Surve 29- Jun -11 GNI -03 1 BL/ 1 CD 50-029- 22820 -00 Signed : ,�_ .�� Date : 3 C 1 Print Name: 14as W �,. kI.a,L PROACTIVE DIAGNOSTIC SERVICES, INC., 130 W. INTERNATIONAL AIRPORT RD SUITE C, ANCHORAGE, AK 99518 PHONE: (907)245 - 8951 FAX: (907)245 - 8952 E-MAIL : PDSANCHORAGE(MEMORYLOG.COM WEBSITE : WWW.MEMORYLOG.COM D: ArchivesOistributionlTransmittalSheetskBP Transtnit.docx h7 -- (f 7 bp C 0 ertified Mail # 7011 0110 0000 4759 1821 BP Exploration (Alaska) Inc. 900 East Benson Boulevard ,'}} P.O. Box 196612 11 c Anchorage, Alaska 99519 -6612 (907) 561 -5111 July 28, 2011 UIC Manager, Ground Water Protection Unit U.S. Environmental Protection Agency (OCE -127) l: ;. < 1200 Sixth Avenue, Suite 900 Seattle WA 98101 ", Y;lakr;q � . RE: Demonstration of Mechanical Integrity, Prudhoe Bay Grind and Inject, 5 UIC Class! Permit AK- 11008 -A Dear UIC Manager: Vvcv This letter is to submit the results of a recent tubing inspection logs and fluid movement tests in UIC Class 1 wells GNI -03 and GNI -04 located at the Prudhoe Bay Grind and Inject project operated by BP Exploration (Alaska), Inc (BPXA). The tests are specified as part of the demonstration of mechanical integrity under Part II, C.3 b of EPA UIC Class I permit AK1 1008 -A. The enclosed descriptive and interpretive report contains the results for the following Togs and tests as required under Part 11, C.3.c(1) of the permit: - Tubing Inspection Log: GNI -03, GNI -04 (Page 16, Part II, C.3.b(3)) — C,N,.– i ?S - Fluid Movement Test: GNI -03, GNI -04 (page 16, Part 11, C.3.b(2)) There was no indication of a loss of well integrity. 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. BPXA understands that the EPA will notify BPXA of the acceptability of the mechanical integrity demonstration within 13 days of receipt of the results of the mechanical integrity tests (Part 11, C.3.c.(4)). Injection may continue during this 13 day review period. If the EPA does not respond within 13 days, we will conclude that the results are acceptable and will continue with injection. If you have questions, please contact Michael Bill, Sr. Staff Engineer at (907) 564 -4692. Sincerely, Katharine Fontaine Logistics /Infrastructure Manager Attachments • • UIC Manager July 28, 2011 Page 2 cc: Thor Cutler, EPA Region 10 (letter and report) Talib Syed, EPA Consultant (letter and report) Jim Regg, AOGCC (letter and report) Shawn Stokes, ADEC (letter and report) • • UIC Manager July 28, 2011 Page 3 Bcc (electronic): (Letter and report) M. Bill MB 7 -5 A. Cooke MB 11 -6 R. Daniel MB 7 -5 J. Murphy /M. Vazir PRB 24 T. Winkel /A. Reyes PRB 42 Compliance Matrix Administrator Bcc: ANC File 1007.02.03 • • UIC Manager July 28, 2011 Page 4 Demonstration of Mechanical Integrity Prudhoe Bay Grind and Inject Project EPA permit AK- 1I008 -A effective 09/01/07 requires a tubing inspection log in the Prudhoe Bay Unit Class I Grind & Inject wells each calendar year. Approved tubing inspection logs (Part II C 3 b (3)) include pipe analysis logs, caliper logs or other equivalent tests. Below are the results of logs run recently in well GNI -03. Tubing Inspection Logs A 40 arm caliper logging tool, supplied by PDS (ProActive Diagnostic Services), was run on slickline to inspect the interior surface of both the tubing and the casing. A memory caliper log was run in well GNI -03 on June 29, 2011. The tubing inspection indicated the GNI -03 tubing is in good condition with no significant erosion/corrosion. The tubing was replaced during a workover in December 2009. The casing below the tubing tail is in fair to poor condition. A memory caliper log was run in well GNI -04 on July 11, 2011. The tubing inspection indicated the GNI -04 tubing is in good to fair condition with maximum wall penetration up to 33% and cross sectional metal loss up to 15 %. The tubing was new when the well was completed in January 2008. The casing below the tubing tail is in fair condition. Below are the observed maximum metal losses observed in the tubing and casing from the caliper log. Well Date Maximum Pit PenetrationMax Cross - Sectional Wall Loss GNI -03 Tubing 06/29/11 19% 4% GNI -03 Casing 06/29/11 52% 24% GNI -04 Tubing 07/11/11 33% 15% GNI -04 Casing 07/11/11 30% 15% f the PDS Memory Multi-Finger Caliper, Log Results Summary Enclosed are copies o ry g p g ary for these p wells. • UIC Manager July 28, 2011 Page 5 Fluid Movement Tests The GNI wells normally inject cold slurry or cold water at 50 -70 degrees F. The original formation temperature of the target disposal formation was about 115 deg F. The Shut -In Temperature log technique is commonly used for cement channel detection in injection wells on the North Slope of Alaska and has been used to satisfy the GNI fluid movement test requirement as a demonstration of mechanical integrity. A shut -in temperature log was run in Grind & Inject well GNI -03 on June 29, 2011. GNI -03 was shut -in for 12 days prior to running the log. A shut -in temperature log was run in Grind & Inject well GNI -04 on July 9, 2011. GNI -04 was shut -in for 11 days prior to running the log. Wellbore temperatures are affected by the temperature of the injected fluids by conduction or convection. When the well is injecting fluids, the wellbore and the adjacent formation reaches a temperature near the injection fluid temperature due to conductive heat transfer. When injection ceases, the wellbore temperature begins to return toward its original temperature. The rate of temperature change of the shut -in well will depend on the original formation temperature, the injection fluid temperature and the rate and cumulative volume of injection. In the G &I wells, the injected fluids are colder than the formation temperatures below about 4000 ft TVD. In areas where the injected fluids enter the formation, both conduction and convective heat transfer are involved. The amount of rock cooling is much larger and the rate of temperature change after shut -in will be much slower due to the direct contact of the formation with the cold fluid. Channeling adjacent to the wellbore is evident because cooler injected fluids leak off into formations throughout the length of the channel. Several types of logging tools are available to be used to record the temperatures of the wellbore fluids: tools run on electric line with a real -time surface readout and memory tools run on slick line. The results from these instruments are presented in the enclosed logs of borehole temperature and pressure versus measured depth. Shut -In Temperature Survey Procedure - EPA permit AK- 1I008 -A requires tracer surveys to "... be conducted at injection pressure at least equal to the average continuous injection pressure observed in the previous 6 months." Injection is cycled into the GNI wells on a rotating basis, with one well injecting at a time. The average and maximum injection pressures are reported quarterly on Form 7520 -8. - Average daily injection pressure in well GNI -03 over the 6 months prior to its survey was 1169 psi. Average daily injection pressure in well GNI -04 over the 6 months prior to its survey was 1370 psi.Average wellhead injection pressures exceeded this pressure during the injection cycle completed prior to this survey. - The survey procedure involved the following steps: Inject a significant volume of cold water or slurry at the required pressure. Shut -in and freeze protect the well after an injection cycle. After at least 5 days, rig up logging tools and pressure test lubricator. Confirm depth control by comparing to the tie -in log on record. Run the shut -in temperature /pressure survey. Rig down and move off. - Compare the logged temperatures to previous shut in logs run in the well. UIC Manager • July 28, 2011 Page 6 GNI -03 Shut -In Temperature Survey Results — reference PDS GNI -03 Temperature Log (UMT- CCL- Press - Temp), 29- June -11. Note: the depths referenced below refer to the printed log. The enclosed log trace was run from the fill level in the well to the surface. The log contains the following traces: casing collar locator, temperature and pressure. The last injection cycle before logging took place between 06/03 and 06/17/11. The shut -in temperature trace indicates uniformly increasing temperature with depth to about 6750 feet measured depth (MD) or 6124 feet true vertical depth (TVD). Temperatures continue to increase with depth to about 6950 feet MD or 6291' TVD. Below that point, the temperature declined until the fill level was reached within or just above the perforated interval. Based on this data, there is no evidence of injected fluid movement above about 6100' TVD, and little or no movement above 6300' TVD. A plot of the temperature log data from 2011 along with other GNI -03 logs is shown below. GNI -03 Shut In Temperature Logs '30 • ?tafn4JewCCly - 6/6,96 'Faeelne ^20 • 06422105 5 day Si • 06179/06 5 day SI 119 -•,- J050 7 12dey Si • {e42(00#1 0day SI, Lefb Shin ,65 • 06/15109 T day SI 07 ±:1110 9 day Si 99 S., 1# 41A" nt • 0612911112.dd � : � ••••• 1 ! ••�ft... M s # * ••• f ti • • ik 50 4000 4500 5000 5500 5008 6500 7 000 True Vertical Depth feet GNI -04 Shut -In Temperature Survey Results — reference PDS GNI -03 Temperature Survey (UMT -CCL- Press - Temp), 09- July -11. Note: the depths referenced below refer to the printed log. The enclosed log trace was run from the fill level in the well to the surface. The log contains the following traces: casing collar locator, gamma ray, temperature and pressure. The last injection cycle before logging took place between 06/17 and 06/28/11. • • UIC Manager July 28, 2011 Page 7 The shut -in temperature trace indicates uniformly increasing temperature with depth to about 6650 feet measured depth (MD) or 6041 feet true vertical depth (TVD). Temperatures continue to increase with depth to about 6850 feet MD or 6218' TVD. Below that point, the temperature declined until the fill level was reached within or just above the perforated interval. Based on this data, there is no evidence of injected fluid movement above about 6040' TVD, and little or no movement above 6200' TVD. A plot of the temperature log data from 2011 along with other GNI -04 logs is shown below. GNI -04 Shut II Temperature Logs 130 - ■ Pefs/Jeweery 1/22.0• 33L 120 — + — #4 4/2100 BL r4 1127/09 11daS1 • 114 8/12;10 9deS1 �» i sp4 /109111 11de31 110 u . t 100 .r"'' w 4,4 ,4-* 1! 2 ! 21 � =t 80 r' fi b, ht *4 sue 0 ` •• 1 4000 4500 5CU) 5500 5 8500 7000 True Vertical Depth feet Overall Conclusions The GNI -03 caliper log indicates the tubing has no significant erosion/corrosion damage and is suitable for continued injection. The GNI -03 shut -in temperature log indicates no movement of injected fluids above 6100' TVD. The GNI -04 caliper log indicates the tubing has maximum penetration of 33% but it is suitable for continued injection. The GNI -04 shut -in temperature log indicates no movement of injected fluids above 6040' TVD. Michael L. Bill, P.E. July 14, 2011 bp BP Exploration (Alaska) Inc. i 900 East Benson Boulevard P.O. Box 196612 — AaGhorage, Alaska 99519 -6612 (907) 561 -5111 November 15, 2010 (� er Commissioner Dan Seamount, Chairman Nov Alaska Oil & Gas Conservation Commission > > ; 333 West 7 Avenue, Suite 100 S 2Q1� Anchorage, Alaska 99501 ion q�j A116018 Reference: Grind & Inject Project Annual Performance Report Dear Mr. Seamount. Enclosed is the Annual Performance Report for waste slurry injection for the Grind and Inject project located near Drill Site 4 in the Prudhoe Bay Unit. This report is submitted to satisfy the requirements of Area Injection Order #4E, Rule 10, as modified by Administrative Approval No. AIO 4C.001 and an Erratum Notice dated July 17, 2009. This requirement is very similar to an EPA report requirement regarding Prudhoe Bay Unit UIC Class I injection wells contained in EPA permit AK- 11008 -A. The report covers the period from October 1, 2009 through September 30, 2010 and was structured to satisfy both the AOGCC and the EPA requirements. Should you have questions concerning the contents of this report, contact me at 564 -4692. c�V) ()a D�) Sincerely, Q3 Michael L. Bill Senior Staff Engineer Cc: A. Cooke MB 11 -6 M. McAnulty 2236, 3000 C Street C. Burgh MB 11 -6 H. Engel MB 7 -5 K. Fontaine MB 11 Harrington /Cantrell PRB 42 B. Collver PRB 42 Fagerland /Gogart PRB 42 Winkel /Reyes PRB 42 Well Integrity Coordinator PRB 7 S. Kenshalo, ConocoPhillips P. Bennett, ExxonMobil Prudhoe Bay Unit, Grind & Inject Project, Surfcote Pad Injection EPA UIC Class I Permit AK-1 1008-A Area Injection Order #4E, Rule 10 Annual Performance Report October 1, 2009 through September 30, 2010 This Annual Performance Report documents waste slurry injection on the Surfcote Pad near Drill Site 4 in the Prudhoe Bay Unit for the period October 1, 2009 through September 30, 2010. This report is submitted to satisfy the requirements of both EPA UIC Class I permit AK- 11008 -A, Part 11 3 c 7 and AOGCC Area Injection Order (AIO) #4E, Rule 10, as modified by Administrative Approval AIO 4C.001 and Erratum Notice dated July 17, 2009. Additional information requested in a letter from the AOGCC (Regg to Bill 12/22/03) is also included. The report contains a brief description of the current project status, a summary of the disposal well performance data acquired during this period and operational plans for the next year. Project Status The Grind & Inject (G &I) Project at the Surfcote pad was undertaken in 1998 by the owners of the Prudhoe Bay Unit, Initial and Lisburne Participating Areas, and the Kuparuk River Unit to dispose of drilling muds and cuttings stored in reserve pits. Other non - hazardous wastes processed through the G &I Plant included those referenced in AIO #4E, Rule 2 as Class II wastes, consisting of RCRA- exempt drill cuttings and oily solids from pipeline pigging, vessel cleanouts and well workovers, and RCRA- exempt liquid wastes such as used drilling mud from on -going North Slope drilling operations. EPA issued Class I UIC permit AK- 11008 -A for the Grind & Inject Project effective September 1, 2007. Authorizations to inject Class I substances were received on January 18, 2008 for wells GNI -02A and GNI -03 and on May 6, 2008 for GNI -04. Well GNI -01 remains a Class II only disposal well. All non - hazardous wastes injected for disposal in the GNI wells during the report period are within the description of wastes referenced in EPA UIC Class I Permit AK- 11008 -A, Part II C 3 7, the UIC Class I permit application, or in Area Injection Order 4B, Finding 7 as incorporated in AIO #4E. Several lined pits comprising the "material transfer station" (MTS) at DS 4 were operated to temporarily hold ongoing drilling and oily solids when necessary. On an infrequent basis, flow back liquids from new wells drilled with oil -based mud (OBM) or other wastes were injected directly into G &I wells using temporary equipment staged on the Surfcote pad. As of September 30, 2010, project injection has included 41.8 MM barrels of water, 81.4 MM barrels of slurry containing 5.1 MM tons (5.6 MM cubic yards) of excavated reserve pit material and other waste solids, and 5.9 MM barrels of fluid from ongoing drilling operations. Exhibit 1 summarizes this data. ,,,3tAr, S \ 5 6, A L S• o M `�ch ` S-15 Operations Operations during the year were affected by seawater supply interruptions due to high winds, power outages, supply pipeline problems, and maintenance work at the Seawater Treatment Plant and the Seawater Injection plant. G &I maintenance activities included an extensive inspection program of the piping and processing equipment within the plant and the pipelines to the wells. Solids processing in the G &I plant was shut down in 2009 during the summer until late December and in 2010 from mid May through the present. Major repairs included replacement of process piping and valves, as well as repairs to the slurry tank, ball mill, metering, and pump electrical systems. Disposal of ongoing liquid drilling wastes and water from pit dewatering operations continued during much of the summer shut down period. Solid wastes accumulated during the summer were stored at the MTS and processed when the full plant was in operation. The pace of excavation from the production reserve pits was reduced in 2010 with the concurrence of the Alaska Department of Environmental Conservation and batch processing of solids rather than continuous processing was used during part of the winter. Well Operations and Monitoring The four GNI disposal wells are located on the Surfcote pad and continue to be available for disposal. Well GNI -01 has been shut -in due to tubing damage since May 2007, but it is available for Class 11 direct injection and observation purposes. It was replaced for Class I waste and slurry injection by well GNI -04 which began in May 2008. Well GNI -02A was sidetracked to a new bottom hole location in November /December 2006 and is an active Class I waste and slurry injector. Existing Class I well GNI -03 is also active after a workover in December 2009 to replace damaged tubing. Each well is perforated in the Ugnu formation between 6400 and 6600 ft TVD. GNI plant discharge rate, temperature and slurry density, along with injection well pressure and temperature and annulus pressures are continuously monitored in the G &I Plant control room. Slurry is injected into one well at a time on a rotating schedule. After each injection cycle, shut in wells are flushed with water and freeze protected with new product methanol mixed with water. Exhibit 4 lists the injection cycles and the well work and surveillance activities during the report period. The injection history and performance for each well is shown in Exhibits 1, 2, 3, 5, 6 and 10. Peak slurry injection rates are normally between 25,000 and 35,000 barrels per day with between 2,000 and 3,000 cubic yards per day of solids processed. Injected slurry density averaged about 9.5 ppg when solids were being processed (Exhibit 6). Surface injection pressure is heavily influenced by the slurry injection rate, slurry density and to some extent slurry temperature due to viscosity dependence on temperature and the impact of injection temperature on formation stress. Daily average surface injection and calculated bottom -hole injection pressures (BHIP) are shown in Exhibit 6 for each well. BHIP is calculated to account for the effects of the hydrostatic head and fluid friction of the slurry column. The calculated bottom hole injection pressures in each well have shown relatively stable injection pressures over the last year. All three wells have maintained good formation injectivity with no sign of formation plugging. 2 By design, the outer annulus (OA) of each GNI well is in weak pressure communication with the formation adjacent to its surface casing shoe set at about 4000 ft TVD (GNI -03 and GNI -04) and about 2800' TVD in the GNI -02A sidetrack. The surface pressure in each outer annulus is monitored as potential indicator of any significant fluid movement above the approved injection interval. The OA pressure is also quite sensitive to thermal expansion or contraction of the annulus fluids resulting from the injection cycle and injection fluid temperature variations. The OA of each well is closely monitored during a well swap and periods of higher temperature injection and the annulus pressure is bled as necessary. Due to the communication with the formation, OA pressure changes related to thermal effects begin to dissipate within a short time. There have been no significant sustained pressure increases adjacent to the surface casing shoe and no abnormal or unexplained annulus pressures observed during the report period. Each GNI well is equipped with control line tubing open ended within the inner annulus (IA) to about 1000 ft. This line allows several hundred feet of nitrogen cushion to be maintained in the IA to dampen the pressure changes due to thermal expansion or contraction of the annulus fluid. There has been no indication of tubing or packer leakage observed in any of the GNI wells, although the IA pressure may need to be bled during periods of high temperature injection and re- charged during cooler injection periods. Exhibit 10 contains daily average tubing, IA and OA pressures for each of the wells. Dates when the annulus pressure was bled or re- pressured are also indicated. EPA witnessed mechanical integrity tests of the inner annulus are required annually under the Class I permit. The AOGCC requires an MIT -IA every two years in slurry injection wells under AIO 4E, Rule 6. Successful MIT -IA tests were performed in GNI wells 02A, 03 and 04 on September 26, 2010. EPA representatives witnessed each of these MIT -IA tests. Memory caliper logs were run in GNI wells 02A, 03 and 04 to inspect the 7" tubing strings in 2010. GNI -01 has remained shut -in since May 2007 due to the level of tubing 9 Y 9 damage. The following table lists the observed maximum metal loss in the tubing and 9 9 9 the casing below the packer from the caliper logs run during the report period. Well Date Max Pit Penetration Max Cross - Sectional Wall Loss Tubing Casing Tubin Casing GNI -02A 06/30/10 29% 26% 20% 16% GNI -03 05/26/10 <10% 42% <3% 24% GNI -04 06/12/10 22% 30% <13% 18% After isolation of the tubing with bridge plugs and /or back pressure valves, the trees on each of the wells were replaced and inspected for erosion /corrosion damage. Well Surveillance and Testing The cycling of injection to the wells generally allows well surveillance and maintenance activities to be scheduled with little disruption to G &I plant operations. To minimize freeze protection concerns, repeat well tests and logs are usually scheduled in the summer. 3 • • The shut in temperature /pressure survey results for 2010 and prior years are shown in Exhibit 7. Repeat shut -in temperature /pressure logs were run in the wells in June and July. Based on the fill tags and the temperature profiles, all injection continues to exit each wellbore through the perforated intervals. The temperature logs have very similar ( O character to the previous logs in each well. Consistent with the 2009 results, the VA00�M temperature logs have shown less tha 500 feet TVD of vertical fluid mo vement. Since the GNI well bores are deviated and the effective depth of investigation of temperature logs is limited, the full extent of injection through vertical fractures may not be detected by the temperature logs. Observed static reservoir pressures obtained from the GNI -02A, 03 and 04 shut -in temperature /pressure logs were slightly higher than the previous measurements: 38 psi in GNI -02A, 11 psi in GNI -03, and 83 psi in GNI -04. Repeat step rate tests SRTs were performed in wells GNI -02A 03 and 04 in Jul P p ( ) P Y and August. The repeat SRT procedure included both a step up portion and a step down portion. Each SRT was analyzed using two methods to provide additional insight, a conventional analysis and a superposition method. The step rate tests in wells GNI -02A and 03 exhibited an unusual character. This has been interpreted as injection into a pre - existing fracture or fracture network possibly held open by infected solids. Later in the test, the flow appeared to be dominated by a period of pressure dependent leak off from a non - propagating fracture. In the case of GNI -04 with less slurry injection prior to the test, there is a less complicated fracture network due to the lower cumulative solids injection. Exhibit 8 discusses the 2010 step rate test data and analysis results. As in the past, SRT's confirm fractures are the primary disposal mechanism. Repeat surface pressure falloff (SPFO) tests were run in wells GNI -02A, 03 and 04 in July and August. Surface pressure falloff tests were run in the summer to avoid rate fluctuations due to freeze protection immediately prior to shut in. Also, since a well cannot be shut in while injecting slurry, each repeat SPFO test is run after a period of water injection containing only a small amount of mud liquids. No drilling mud was injected in the 24 hours prior to shutting in the well and the injection rate was stabilized. Given these factors, the SPFO tests should be viewed as representing a snapshot in time that may not completely reflect the downhole flow conditions present due to the differences with fluid rheology under actual slurry injection. As with past tests, calibrated surface memory gauges were used to record the pressure falloff data. Exhibit 9 discusses the 2010 SPFO test analysis results. Several reservoir flow models were used in an attempt to obtain a type curve match of the data. The SPFO data from well GNI -02A was best matched using a radial composite homogeneous (RCH) reservoir model and GNI -03 was best matched using an infinite conductivity vertical fracture (IVCF) model. The data from GNI -04 was difficult to match with a single model. To gain insight into this well, the early period data was matched with the IVCF model and the late time data was matched using the RCH model. The tests from each well showed evidence of a "boundary" or damaged zone some distance from the wellbore. In general, the reservoir parameters derived from the tests were similar to those from 2009. A prototype bore hole gravity meter logging tool was run in well GNI -03 in July. The tool was developed by Scintrex Ltd and was run by Schlumberger. The tool was designed to 4 • • measure the gravitational field surrounding the wellbore at various depths and can potentially detect very small changes in formation density as a result of changes in fluid saturation or the accumulation of injected solids. Well GNI -03 was chosen for the test of this tool due to its high cumulative solids injection. A comparison of the results of the log with the original open hole density log showed good agreement except just above the perforated interval. These preliminary results appear to confirm the solids placement in or near the primary disposal injection interval with little upward movement of injected solids. Storage Mechanism and Disposal Domain As reported in the past, a number of studies have been conducted to understand the downhole storage mechanism in slurry injection operations. These include two major industry studies: the Drilling Engineering Associates (DEA) 81 Joint Industry Project (JIP) laboratory study and the Mounds Drill Cuttings Injection JIP field pilot study. Individual operators have also reported monitoring and well testing programs to delineate the storage mechanism and geometry. Most of these studies and monitoring programs agree that multiple fractures are created during periodic injection operations. Step rate tests and pressure falloff tests of the GNI wells have also showed signatures of multiple opening or multiple closure events, indicating multiple fractures from GNI operations. The result is likely a complex disposal domain consisting of a series of fractures developed over time with different orientations. Branching fractures may also be a part of the storage mechanism. This disposal domain allows for the storage of large amounts of solids. Fracture modeling was updated in 2006 using a modified conventional hard rock fracture simulator adjusted for soft rock behavior and assuming the disposal domain described above. The layer description was extended upward and downward to include 22 layers. The updated model runs predicted fractures to be contained below 5900 ft TVD at that time, about 600 ft above the perforations in the original GNI completions. At some point the increasing stress due to solids storage in the fractures of the disposal domain will create conditions resulting in possible additional upward fracture extension. The model results indicate fracture growth to near 5000 ft TVD at some time beyond the year 2020, still well below the top of the approved interval at about 4500 ft TVD. While the primary G &I surveillance techniques (temperature logs, step rate tests and pressure falloff tests) and the model results provide differing inferences as to the size of the fracture system (partially due to the specific conditions of each test), all indicate limited upward movement of the injected material and confinement well within the approved interval specified in A1O #4E, Rule 2. Well Plans Well GNI -01 has significant tubing damage and has injected over 1.6 MM cubic yards of waste drilling solids. Well GNI -01 will be available for occasional direct injection of Class 11 materials and to observe various facets of the slurry injection process. Operational Plans The operational plan for the next twelve months will involve similar activities to those in recent years. Discussions are ongoing with Alaska Department of Environmental 5 Conservation concerning the scope of the remaining production reserve pit closeout activities required by the State of Alaska's Inactive Reserve Pit Closure Regulations. While a significant feed for the G &I plant will be excavated drilling mud and cuttings from old exploration reserve pits and well sites, the pace of excavation from the production reserve pits will likely remain reduced. As was the case for a portion of last winter, solid waste material will be processed in batches rather than continuously, except when the mill is shut down for maintenance, during well switches and for brief periods due to weather or utility outages. Class II liquids and solids from on -going drilling operations will be processed at the G &I plant on a periodic basis determined by the drilling and well workover schedules. Oily solids will be accepted at the material transfer station and processed at the G &I plant during winter months when the material can be handled in a frozen state and mixed with reserve pit wastes. Non - hazardous Class I materials will be processed and injected in the three active GNI slurry injection wells, GNI -02A, GNI -03 and GNI -04. Direct injection of crude oil contaminated with oil based drilling mud from the initial production from new wells and of other wastes will be utilized when necessary. Snow melt accumulating in reserve pits will be injected by the GNI plant in the summer as needed. Each of the three active GNI wells will be used for injection on a rotating schedule as described above. Anticipated major repairs in 2010 include replacement of the mill liner and various piping segments. 6 Prudhoe Bay Unit, Grind & Inject Project, Surfcote Pad Injection EPA UIC Class I Permit AK-1 1008-A Area Injection Order #4E, Rule 10 Annual Performance Report October 1, 2009 through September 30, 2010 List of Exhibits 1. GNI Surfcote Injection Summary 2. GNI Injection Bar Graph 3. a,b GNI Solids Injection Bar Graphs 4. GNI Surfcote Well Surveillance Activities 5. a,b,c,d GNI Wells Injection Bar Graphs 6. a,b,c,d GNI Wells Daily Average Data Plots 7. b,c,d GNI Wells Temperature Logs 8. GNI Wells Step Rate Tests 9. GNI Wells Pressure Falloff Tests 10. a,b,c,d GNI Wells TIO Pressure plots 7 Exhibit 1 G &I Injection Summary Cumulative Thru September 30, 2010 Total GNIA GNI -2 GNI -02A GNI -3 GNI-4 Shut -In P &A Active Active Active _ �_\ Q Water Injection (MM Barrels) * 41.8 10.2 8.3 6.6 12.7 4.0 Slurry Injection (MM Barrels) ** 81.4 22.6 18.4 8.2 28.2 4.0 Total Injection (MM Barrels) " ** 123.2 32.8 26.8 14.7 40.9 8.0 Solids Injected (MM Tons) 5.1 1.5 1.2 0.4 1.8 0.2 Solids Injected (MM Cubic Yards) 5.6 1.6 1.3 0.5 2.0 0.2 Drilling Fluid Injected (MM Barrels) 5.9 1.3 1.0 1.0 2.1 0.5 Direct Injection (M Barrels) * * ** 169 38 28 4 99 0 * includes bypass sea water and produced water injected during plant outages and upsets ** includes all fluids pumped from the G &I plant " ** includes slurry, water and direct injection ` ** Includes oil based mud, contaminated crude, other waste and flush water pumped at the well site bp 0 BP Exploration (Alaska) Inc. 900 East Benson Boulevard NOV �; 9 NIB P.O. Box 196612 l�lf Y Anchorage, Alaska 99519 -6612 (907) 561 -5111 November 13, 2009 Commissioner Dan Seamount, Chairman 1v u v .f Z Alaska Oil & Gas Conservation Commission 333 West 7' Avenue, Suite 100 1 5 3, '� ` ' s s sa :? Anchorage, Alaska Anchamgo 99501 Reference: Grind & Inject Project Annual Performance Report Dear Mr. Seamount: g Enclosed is the Annual Performance Report for waste slurry injection for the Grind and Inject project located near Drill Site 4 in the Prudhoe Bay Unit. This report is submitted to satisfy the requirements of Area Injection Order #4E, Rule 10, as modified by Administrative Approval No. AIO 4C.001 and an Erratum Notice dated July 17, 2009. This requirement is very similar to an EPA report requirement regarding Prudhoe Bay Unit UIC Class I injection wells contained in EPA permit AK- 11008 -A. The report covers the period from October 1, 2008 through September 30, 2009 and was structured to satisfy both the AOGCC and the EPA requirements. Should you have questions concerning the contents of this report, contact me at 564 -4692. Sincerely, Michael L. Bill Senior Staff Engineer Cc: A. Cooke MB 11 -6 R. Bullock MB 11 -6 M. McAnulty MB 11 -6 C. Burgh MB 11 -6 A. Chow MB 3 H. Engel MB 7 -5 Harrington /Cantrell PRB 42 Ohnemus /Fagerland PRB 42 Collver /Dawley PRB 42 Well Integrity Coordinator PRB 7 GPB Environmental Team Leader PRB 7 S. Kenshalo, ConocoPhillips P. Bennett, ExxonMobil Prudhoe Bay Unit, Grind & Inject Project, Surfcote Pad Injection EPA UIC Class I Permit AK-1 1008-A Area Injection Order #4E, Rule 10 Annual Performance Report October 1, 2008 through September 30, 2009 This Annual Performance Report documents waste slurry injection on the Surfcote Pad near Drill Site 4 in the Prudhoe Bay Unit for the period October 1, 2008 through September 30, 2009. This report is submitted to satisfy the requirements of both EPA UIC Class I permit AK- 11008 -A, Part 11 3 c 7 and AOGCC Area Injection Order (AIO) #4E, Rule 10, as modified by Administrative Approval AIO 4C.001 and Erratum Notice dated July 17, 2009. Additional information requested in a letter from the AOGCC (Regg to Bill 12/22/03) is also included. The report contains a brief description of the current project status, a summary of the disposal well performance data acquired during this period and operational plans for the next year. Project Status In 1998, the Grind & Inject (G &I) Project at the Surfcote pad was undertaken by the owners of the Prudhoe Bay Unit, Initial and Lisburne Participating Areas, and the Kuparuk River Unit to dispose of drilling muds and cuttings stored in reserve pits. Other non - hazardous wastes processed through the G &I Plant included those referenced in AIO #4E, Rule 2 as Class II wastes, consisting of RCRA- exempt drill cuttings and oily solids from pipeline pigging, vessel cleanouts and well workovers, and RCRA- exempt liquid wastes such as used drilling mud from on -going North Slope drilling operations. EPA issued Class I UIC permit AK-1 1008-A for the Grind & Inject Project effective September 1, 2007. Authorizations to inject Class I substances were received on January 18, 2008 for wells GNI -02A and GNI -03 and on May 6, 2008 for GNI -04. Well GNI -01 remains a Class 11 only disposal well. All non - hazardous wastes injected for disposal in the GNI wells during the report period are within the description of wastes referenced in EPA UIC Class I Permit AK- 11008 -A, Part 11 C 3 7, the UIC Class I permit application, or in Area Injection Order 46, Finding 7 as incorporated in AIO #4E. Several lined pits comprising the "material transfer station" (MTS) at DS 4 were operated to temporarily hold ongoing drilling and oily solids when necessary. On an infrequent basis, flow back liquids from new wells drilled with oil -based mud (OBM) or other wastes were injected directly into G &I wells using temporary equipment staged on the Surfcote pad. As of September 30, 2009, project injection has included 36.2 MM barrels of water, 77.8 MM barrels of slurry containing 4.9 MM tons (5.5 MM cubic yards) of excavated reserve pit material and other waste solids, and 5.3 MM barrels of fluid from ongoing drilling operations. Exhibit 1 summarizes this data. 1 Operations Operations during the year were affected by seawater supply interruptions due to high winds, power outages, supply pipeline problems, and maintenance work at the Seawater Treatment Plant and the Seawater Injection plant. G &I maintenance activities included an extensive inspection program of the piping and processing equipment within the plant and the pipelines to the wells. Solids processing in the G &I plant was shut down from late May through October for inspections and maintenance. Major repairs included replacement of process piping, as well as repairs to the seawater heater. Repairs were also made to the ball mill, feed hopper, conveyor, slurry tank and injection pumps. Disposal of ongoing liquid drilling wastes and water from pit dewatering operations continued during much of the summer shut down period. Solid wastes accumulated during the summer were stored at the MTS. Well Operations and Monitoring 9 The four GNI disposal wells are located on the Surfcote pad and continue to be available for disposal. Well GNI -01 has been shut -in due to tubing damage since May 2007, but it is available for Class 11 direct injection and observation purposes. It was replaced for Class I waste and slurry injection by well GNI -04 which began in May 2008. Well GNI -02A was sidetracked to a new bottom hole location in November /December 2006 and is an active Class I waste and slurry injector. Existing Class I well GNI -03 is also active. Each well is perforated in the Ugnu formation between 6400 and 6600 ft TVD. GNI plant discharge rate, temperature and slurry density, along with injection well pressure and temperature and annulus pressures are continuously monitored in the G &I Plant control room. Slurry is injected into one well at a time on a rotating schedule. After each injection cycle, shut in wells are flushed with water and freeze protected with new product methanol mixed with water. Exhibit 4 lists the injection cycles and the well work and surveillance activities during the report period. The injection history and performance for each well is shown in Exhibits 1, 2, 3, 5, 6 and 10. Peak slurry injection rates are normally between 25,000 and 35,000 barrels per day with between 2,000 and 3,000 cubic yards per day of solids processed. Injected slurry density averaged about 9.5 ppg when solids were being processed (Exhibit 6). Surface injection pressure is heavily influenced by the slurry injection rate, slurry density and to some extent slurry temperature due to viscosity dependence on temperature and the impact of injection temperature on formation stress. Daily average surface injection and calculated bottom -hole injection pressures (BHIP) are shown in Exhibit 6 for each well. BHIP is calculated to account for the effects of the hydrostatic head and fluid friction of the slurry column. The calculated bottom hole injection pressures in each well have shown relatively stable injection pressures over the last year. All three wells have maintained good formation injectivity with no sign of formation plugging. By design, the outer annulus (OA) of each GNI well is in weak pressure communication with the formation adjacent to its surface casing shoe set at about 4000 ft TVD (GNI -03 and GNI -04) and about 2800' TVD in the GNI -02A sidetrack. The surface pressure in each outer annulus is monitored as potential indicator of any significant fluid movement above the approved injection interval. The OA pressure is also quite sensitive to 2 • thermal expansion or contraction of the annulus fluids resulting from the injection cycle and injection fluid temperature variations. The OA of each well is closely monitored during a well swap and periods of higher temperature injection and the annulus pressure is bled as necessary. Due to the communication with the formation, OA pressure changes related to thermal effects begin to dissipate within a short time. There have been no significant sustained pressure increases adjacent to the surface casing shoe and no abnormal or unexplained annulus pressures observed during the report period. Each GNI well is equipped with control line tubing open ended within the inner annulus (IA) to at least 1000 ft. This line allows several hundred feet of nitrogen cushion to be maintained in the IA to dampen the pressure changes due to thermal expansion or contraction of the annulus fluid. There has been no indication of tubing or packer leakage observed in any of the GNI wells, although the IA pressure may need to be bled during periods of high temperature injection and re- charged during cooler injection periods. Exhibit 10 contains daily average tubing, IA and OA pressures for each of the wells. Dates when the annulus pressure was bled or re- pressured are also shown. EPA witnessed mechanical integrity tests of the inner annulus are required annually under the Class I permit. The AOGCC requires an MIT -IA every two years in slurry injection wells under AIO 4E, Rule 6. Successful MIT -IA tests were performed in GNI wells 02A, 03 and 04 on October 7, 2008 and in wells 02A and 04 on September 28, 2009. EPA representatives witnessed each of these MIT -IA tests. Memory caliper logs were run in GNI wells 02A, 03 and 04 to inspect the 7" tubing strings in 2009. As noted in previous reports, a significant amount of erosion /corrosion related metal loss has been seen in well GNI -03. Due to the unknown rate of metal loss, the operator specified maximum IA pressure has been reduced to 1000 psi. A rig workover to replace the tubing string in GNI -03 is planned for 4th quarter 2009. GNI -01 has remained shut -in since May 2007 due to the level of tubing damage. The following table lists the observed maximum metal loss in the tubing and the casing below the packer from the caliper logs run during the report period. Well Date Max Pit Penetration Max Cross - Sectional Wall Loss Tubing Casinq Tubin Casing GNI -02A 07/01/09 26% 24% 19% <14% GNI -03 11/13/08 60% 34% 49% 20% GNI -03 04/13/09 60% 33% 52% 20% GNI -04 01/27/09 19% 31% 12% 18% After isolation of the tubing with bridge plugs and /or back pressure valves, the trees on wells GNI -02A and 04 were replaced and inspected for erosion /corrosion damage. Well Surveillance and Testing The cycling of injection to the wells generally allows well surveillance and maintenance activities to be scheduled with little disruption to G &I plant operations. To minimize freeze protection concerns, repeat well tests and logs are usually scheduled in the summer. 3 • • The shut in temperature /pressure survey results for 2009 and prior years are shown in Exhibit 7. Repeat shut -in temperature /pressure logs were run in well GNI -04 in January, GNI -03 in June and GNI -02A in July. Based on the fill tags and the temperature profiles, all injection continues to exit each wellbore through the perforated intervals. The temperature logs have very similar character to the previous logs in each well. Consistent with the 2008 results, the temperature logs have shown less than 400 feet TVD of vertical fluid movement. Since the GNI well bores are deviated and the effective depth of investigation of temperature logs is limited, the full extent of injection through vertical fractures may not be detected by the temperature logs. Observed static reservoir pressures obtained from the GNI -02A and 03 shut -in temperature /pressure logs were slightly lower (20 psi) in GNI -02A and slightly higher (5 psi) in GNI -03 than observed in 2008. Repeat step rate tests (SRTs) were performed in wells GNI -02A, 03 and 04 in May through August. The repeat SRT procedure included both a step up portion and a step down portion. Each SRT was analyzed using three methods to provide additional insight: conventional analysis, multi -rate pressure transient analysis and a superposition method. The step rate tests in all three slurry injection wells exhibited an unusual character. This has been interpreted as injection into a pre- existing fracture or fracture network possibly held open by injected solids. Later in the test, the flow appeared to be dominated by a period of pressure dependent leak off from a non - propagating fracture. In the case of GNI -04 with less slurry injection prior to the test, there may be some connection to the mature fracture network established in offset shut -in well GNI -01. Exhibit 8 discusses the 2009 step rate test data and analysis results. As in the past, SRT's confirm fractures are the primary disposal mechanism. Repeat surface pressure falloff SPFO tests were run in wells GNI -02A 03 and 04 in P P , June through August. Surface pressure falloff tests were run in the summer to avoid rate fluctuations due to freeze protection immediately prior to shut in. Also, since a well cannot be shut in while injecting slurry, each repeat SPFO test is run after a period of water injection containing only a small amount of mud liquids. No drilling mud was injected in the 24 hours prior to shutting in the well. Given these factors, the SPFO tests should be viewed as representing a snapshot in time that may not completely reflect the downhole flow conditions present due to the differences with fluid rheology under actual slurry injection. As with past tests, calibrated surface memory gauges were used to record the pressure falloff data. Exhibit 9 discusses the 2009 SPFO test analysis results. Various reservoir flow models were used in an attempt to obtain a type curve match of the data. The SPFO data from wells GNI -02A and GNI -03 were best matched using fractured reservoir models while the data from GNI -04 was best matched using a homogeneous reservoir model, although there was indication of a small fracture. The tests from each well showed evidence of a "no flow boundary" or damaged zone some distance from the wellbore. In general, the reservoir parameters derived from the tests were similar to those from 2008, but there was no evidence of multiple fractures evident in the 2009 tests. 4 • • Storage Mechanism and Disposal Domain As reported in the past, a number of studies have been conducted to understand the downhole storage mechanism in slurry injection operations. These include two major industry studies: the Drilling Engineering Associates (DEA) 81 Joint Industry Project (JIP) laboratory study and the Mounds Drill Cuttings Injection JIP field pilot study. Individual operators have also reported monitoring and well testing programs to delineate the storage mechanism and geometry. Most of these studies and monitoring programs agree that multiple fractures are created during periodic injection operations. Step rate tests and pressure falloff tests of the GNI wells have also showed signatures of multiple opening or multiple closure events, indicating multiple fractures from GNI operations. The result is likely a complex disposal domain consisting of a series of fractures developed over time with different orientations. Branching fractures may also be a part of the storage mechanism. This disposal f or f large amounts domain allows or the storage e o a e a ou is of solids. 9 9 Fracture modeling was updated in 2006 using a modified conventional hard rock fracture simulator assuming the disposal domain described above. The layer description was extended upward and downward to now include 22 layers. The updated model runs predicted fractures to be contained below 5900 ft TVD at that time, about 600 ft above the perforations in the original GNI completions. At some point the increasing stress due to solids storage in the fractures of the disposal domain will create conditions resulting in additional upward fracture extension. The model results indicate fracture growth to near 5000 ft TVD sat some time beyond the year 2020, still well below the top of the approved interval at about 4500 ft TVD. While the primary G &I surveillance techniques (temperature logs, step rate tests and pressure falloff tests) and the model results provide differing inferences as to the size of the fracture system (partially due to the specific conditions of each test), all indicate limited upward movement of the injected material and confinement well within the approved interval specified in AIO #4E, Rule 2. Well Plans Well GNI -01 has significant tubing damage and has injected over 1.6 MM cubic yards of waste drilling solids. Well GNI -01 will be available for occasional direct injection of Class II materials and to observe various facets of the slurry injection process. Well GNI -03 has significant tubing damage and has injected about 2.0 MM cubic yards of waste drilling solids. A rig workover to replace the tubing string in GNI -03 is planned for 4th quarter 2009. Operational Plans The operational plan for the next twelve months will involve similar activities to those in recent years. Discussions are ongoing with Alaska Department of Environmental Conservation concerning the scope of the remaining production reserve pit closeout activities required by the State of Alaska's Inactive Reserve Pit Closure Regulations. While a significant feed for the G &I plant will be excavated drilling mud and cuttings from reserve pits and from old exploration well sites, the pace of excavation from the 5 production reserve pits may be reduced. This winter solid waste material may be processed in batches rather than continuously, except when the mill is shut down for maintenance, during well switches and for brief periods due to weather or utility outages. Class II liquids and solids from on -going drilling operations will be processed at the G &I plant on a periodic basis determined by the drilling and well workover schedules. Oily solids will be accepted at the material transfer station and processed at the G &I plant during winter months when the material can be handled in a frozen state and mixed with reserve pit wastes. Non - hazardous Class I materials will be processed and injected in the three active GNI slurry injection wells, GNI -02A, GNI -03 and GNI -04. Direct injection of crude oil contaminated with oil based drilling mud from the initial production from new wells and of other wastes will be utilized when necessary. Snow melt accumulating in reserve pits will be injected by the GNI plant in the summer as needed. Each of the three active GNI wells will be used for injection on a rotating schedule as described above. Anticipated major repairs in 2009 include replacement of the mill liner and various piping segments. 6 Prudhoe Bay Unit, Grind & Inject Project, Surfcote Pad Injection EPA UIC Class I Permit AK-1 1008-A Area Injection Order #4E, Rule 10 Annual Performance Report October 1, 2008 through September 30, 2009 List of Exhibits 1. GNI Surfcote Injection Summary 2. GNI Injection Bar Graph 3. a,b GNI Solids Injection Bar Graphs 4. GNI Surfcote Well Surveillance Activities 5. a,b,c,d GNI Wells Injection Bar Graphs 6. a,b,c,d GNI Wells Daily Average Data Plots 7. b,c,d GNI Wells Temperature Logs 8. GNI Wells Step Rate Tests 9. GNI Wells Pressure Falloff Tests 10. a,b,c,d GNI Wells TIO Pressure plots i Exhibit 1 G &I Injection Summary Cumulative Thru September 30, 2009 Total GNI -1 GNI -2 GNI -02A GNI -3 GNI-4 Slot -- -c,= la+'�-� / ® .� i Water Injection (MM Barrels) * 36.4 10.2 8.3 4.3 11.7 1.9 Slurry Injection (MM Barrels) ** 77.8 22.6 18.4 6.8 27.2 2.8 Total Injection (MM Barrels) * ** 114.2 32.8 26.8 11.1 38.8 4.7 Solids Injected (MM Tons) 4.9 1.5 1.2 0.4 1.8 0.1 Solids Injected (MM Cubic Yards) 5.5 1.6 1.3 0.4 2.0 0.2 Drilling Fluid Injected (MM Barrels) 5.3 1.3 1.0 0.7 1.9 0.3 * * ** Direct Infection (M Barrels) 169 38 28 4 99 0 * includes bypass sea water and produced water injected during plant outages and upsets ** includes all fluids pumped from the G &I plant * ** includes slurry, water and direct injection * * ** Includes oil based mud, contaminated crude, other waste and flush water pumped at the well site by ~ Ce~~afie~C ~l6aiC # 7®®8 323® ®®00 249& 4419 July 21, 2010 UIC Manager, Ground Water Protection Unit • ~ c~...~ _) ~ . 'rte ,,-ter-,, ~ ~ " ~ v NUre ~ 1~ ~Q1~ r B? Exploration (Alaska) Inc. ~~~r;++~~(~ p~~ ~ ~~; ~~~g. ~'~' ~ ,~ o. Box 19ss12 ~9~-J~~$S~ E. Benson Boulevard +eif~~~j ~yT°~i Anchorage, AK 99519-6612 Direct 907 561 5111 U.S. Environmental Protection Agency (OCE-127 1200 Sixth Avenue, Suite 900 Seattle, WA 98101 Re: Demonstration of Mechanical Integrity, Prudhoe Bay Grind and Inject, UIC Class I Permit AK-11008-A Dear Mr. Kowalski: ~a ~ Z.' Q~ c}O~ - \ ~ This letter is to submit the results of a recent tubing inspection logs and fluid movement tests in UIC Class I wells GNI-02A and GNI-04 located at the Prudhoe Bay Grind and Inject project operated by BP Exploration (Alaska), Inc (BPXA). The tests are specified as part of the demonstration of mechanical integrity under Part II, C.3 b of EPA UIC Class I permit AK11008-A. The enclosed descriptive and interpretive report contains the results for the following logs and tests as required under Part II, C.3.c(1) of the permit: - Tubing Inspection Log: GNI-02A and GNI-04 (Page 16, Part II, C.3.b(3)) - Fluid Movement Test: GNI-02A and GNI-04 (page 16, Part II, C.3.b(2)) There was no indication of a loss of well integrity. 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 indi~liduals 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. BPXA understands that the EPA will notify BPXA of the acceptability of the mechanical integrity demonstration within 13 days of receipt of the results of the mechanical integrity tests (Part II, C.3.c.(4)). Injection may continue during this 13 day review period. If the EPA does not respond within 13 days, we will conclude that the results are acceptable and will continue with injection. If you have questions, please contact Michael Bill, Sr. Staff Engineer at (907) 564-4692. Sincerely, ~~ /~-u.~ atharine Fontaine Logistics and Infrastructure Manager ~~~ ta1~~ Attachments Cc: Thor Cutler, EPA Re~ 10 (letter and report) Talib Syed, EPA Consultant (letter and report) Jim Regg, AOGCC (letter and report) Shawn Stokes, ADEC (letter and report) • • Demonstration of Mechanical Integrity Prudhoe Bay Grind and Inject Project EPA permit AK-1I008-A effective 09/01/07 requires a tubing inspection log in the Prudhoe Bay Unit Class I Grind & Inject wells each calendar yeaz. Approved tubing inspection logs (Part II C 3 b (3)) include pipe analysis logs, caliper logs or other equivalent tests. Below are the results of logs run recently in wells GNI-02A and GNI- 04. Tubing Inspection Logs A 40 arm caliper logging tool, supplied by PDS (ProActive Diagnostic Services), was run on slickline to inspect the interior surface of both the tubing and the casing. A memory caliper log was run in well GNI-02A on June 30, 2010. The tubing inspection indicated the GNI-02A tubing is in good to fair condition with no significant erosion/corrosion. The tubing was installed when the well was completed in December 2006. The casing below the tubing tail is in good to fair condition. A memory caliper log was run in well GNI-04 on June 12, 2010. The tubing inspection indicated the GNI-04 tubing is in good to fair condition with no significant erosion/corrosion. The tubing was installed when the well was completed in January 2008. The casing below the tubing tail is in fair condition. Below aze the observed maximum metal losses observed in the tubing and casing from the caliper logs. Well Date Maximum Pit Penetration Max Cross-Sectional Wall Loss GNI-02A Tubing 06/30/10 29% 20% GNI-02A Casing 06/30/10 26% 16% GNI-04 Tubing 06/12/10 22% <13% GNI-04 Casing 06/12/10 30% 18% Enclosed are copies of the PDS Memory Multi-Finger Caliper, Log Results Summary for both wells. Fluid Movement Tests The GNI wells normally inject cold slurry or cold water at 50-70 degrees F. The original formation temperature of the target disposal formation was about 115 deg F. The Shut-In Temperature log technique is commonly used for cement channel detection in injection wells on the North Slope of Alaska and has been used to satisfy the GNI fluid movement test requirement as a demonstration of mechanical integrity. A shut-in temperature log was run in Grind & Inject well GNI-02A on June 30 and in GNI-04 on June 12, 2010. GNI-02A was shut-in for 12 days prior to running the log and GNI-04 was shut-in for 9 days. Wellbore temperatures are affected by the temperature of the injected fluids by conduction or convection. When the well is injecting fluids, the wellbore and the adjacent formation reaches a temperature near the injection fluid temperature due to conductive heat transfer. When injection ceases, the wellbore temperature begins to return toward its original temperature. The rate of temperature change of the shut-in well will depend on the original formation temperature, the injection fluid temperature and the rate and cumulative volume of injection. In the G&I wells, the injected fluids are colder than the formation temperatures below about 4000 ft TVD. In areas where the injected fluids enter the formation, both conduction and convective heat transfer are involved. The amount of rock cooling is much larger and the rate of temperature change after shut- in will be much slower due to the direct contact of the formation with the cold fluid. Channeling adjacent to the wellbore is evident because cooler injected fluids leak off into formations throughout the length of the channel. Several types of logging tools are available to be used to record the temperatures of the wellbore fluids: tools run on electric line with areal-time surface readout and memory tools run on slick line. The results from these instruments are presented in the enclosed logs of borehole temperature and pressure versus measured depth. Shut-In Temperature Survey Procedure - EPA permit AK-1I008-A requires tracer surveys to "... be conducted at injection pressure at least equal to the average continuous injection pressure observed in the previous 6 months." Injection is cycled into the GNI wells on a rotating basis, with one well injecting at a time. The average and maximum injection pressures are reported quarterly on Form 7520-8. - Average daily injection pressure in well GNI-02A over the 6 months prior to its survey was 1153 psi. Average wellhead injection pressures exceeded this pressure during the injection cycle completed prior to this survey. - Average daily injection pressure in well GNI-04 over the 6 months prior to its survey was 1404 psi. Average wellhead injection pressures exceeded this pressure during the injection cycle completed prior to this survey. - The survey procedure involved the following steps: Inject a significant volume of cold water or slurry at the required pressure. Shut-in and freeze protect the well after an injection cycle. After at least 5 days, rig up logging tools and pressure test lubricator. Confirm depth control by comparing to the tie-in log on record. Run the shut-in temperature/pressure survey. Rig down and move off. Compare the logged temperatures to previous shut in logs run in the well. GNl-02A Shut-In Temperatu~"!Survey Results -reference PDS ~Nl-~ Temperature survey (Press-GR-JCL-Temp), 30-Zune-10, Note: the depths referenced below refer to the printed log. The enclosed log trace was run from the fil! lave! in the well to the surfacee The log contains the following traces: gamma ray. casing collar locator, temperature and pressure. The last injection cycle before logging took place between 06/03 and 06/18/10. The shut-in temperature trace indicates uniformly increasing temperature with depth to about 7500 feet measured depth (1~D) or 6112 feet true vertical depth (TVD). Temperatures continue to increase with depth to about 7975 feet I~/1D or 6421' TVD. Below that point, the temperature declined until the fill level was reached within or just above the perforated interval. Based on this data, there is no evidence of injected fluid movement above about 6100' TVD, and little or no movement above 6420' TVD. A plot of the temperature log data from 2010 along with other GNI-02A logs is shown below. Gill-®2A Shu4 In Terttperature logs 130 120 110 m 100 Q `w a 90 80 70 ~~I ^ Jewelry/Parts ~ I 2 02-28-98 BL I -'~2A12-24-06 BL -+- 2A 07-14-07 11 da SI ~~ . on nc nn no ~cw., m. True Vertical Depth ft 9 n Q,_ "~ i GNI-04 Shut-In Temperature SurveYResults -reference PDS GNI-04 Static Survey (Gamma Ray/CCL/Pressure/Temperature), 12-.tune-10. Note: the depths referenced below refer to the printed log. The enclosed log trace was run from the fill level in the well to the surface. The log contains the following traces: gamma ray. casing collar locator, temperature and pressure. The last injection cycle before logging took place between OS/ 17 and 06103/ 10. The shut-in temperature trace indicates uniformly increasing temperature with depth to about 6650 feet measured depth (1VID) or 6041 feet true vertical depth (TVD). Temperatures continue to increase with depth to about 6900 feet I~ID or 6262' TVD. Below that point, the temperature declined until the fill level was reached within or just above the perforated interval. Based on this data, there is no evidence of injected fluid movement above about 6040' TVD, and little or no movement above 6260' TVD. 4000 4500 5000 5500 6000 6500 7000 u A plot of the temperature log data from 2010 along with other GNI-04 logs is shown below. L'sREI-C4 Shr3t 11 Temperatt:re Logs 130 -- -- - ------- i - - - - i O Perts/Jewelry ~ I ~~#41/22/08 BL I ~ 120 ~ - -F #4 M23/08 8L - - ' -- - - - -- --- - _ - ___ _ -'--#4 1/27/0911daSl -y -#46/72/70 9daSl ,i ~ ' 910 {------- - ----------i i ~ i ' ~ 100 I - '- --- -- '---- - -- - - ~~-•^,r-- ,- d t ~ I i .~°. m i ;r,-" ~ 90 }-- -- - I •• ~ • ~ r-- i~-r- - ! -- _ --- ~m .~~ ~ ~ ..*'~ • ~• 80 {-- - --- -- -- - ~ ~-~ - ----- ~- -- .•`~ 11 I i~a- - •~~ 70 ~ ~ ~ ~ ~ - - --- -- ----...--- --- ~ ---- - ~ ~ ss"~~~ c ~ ~ I ,s~os 60 # 4000 4500 5000 5500 6000 6500 7000 True Vertical Depth feet Overall Conclusions The GNI-04 caliper log indicates the tubing has no significant erosion/corrosion damage and is suitable for continued injection. The GNI-04 shut-in temperature log indicates no movement on injected fluids above 6040' TVD. The GNI-02A caliper log indicates the tubing has no significant erosion/corrosion damage and is suitable for continued injection. The GNI-02A shut-in temperature log indicates no movement on injected fluids above 6100' TVD. Michael L. Bill July 06, 2010 ~~~~~ ~: PROACTIVE DIAGNOSTIC SERVICES INC. WELL LOG TRANSM/TTAL To: AOGCC Christine Mahnken 333 W. 7th Ave Suite 100 Anchorage, Alaska 99501 (907) 793-1225 C~ RE : Cased Hofe/Open Hole/Mechanical Logs and/or Tubing Inspection[Caliper/ MTT) The technical data listed below is being submitted herewith. Please acknowledge receipt by returning a signed copy of this transmittal letter to the following BP Exploration (Alaska), Inc. Petrotechnical Data Center Attn: Joe Lastufka LR2-1 900 Benson Blvd. Anchorage, Alaska 99508 and ProActive Diagnostic Services, Inc. Attn: Robert A. Richey 130 West International Airport Road Suite C Anchorage, AK 99518 Fax: (907) 245$952 Y~~~ A~f ~ ~' ~ 1) Temperature Survey 12z)un-10 GNI-04 BL EDE ~ 50-029-23367-00 d~ ~ Signed : `I~~, ~, ~ , ~;,~ Date Print Name: :~. ~ ~, '!I'~'~l~,u PROACTIVE DIAGNOSTIC SERVICES, INC., 130 W. INTERNATIONAL AIRPORT RD SUITE C, ANCHORAGE, AK 99518 PHONE: (907)245-8951 FAX: (907)245-88952 E-MAIL : ~dsanchoraaen~emonttog com WEBSITE : ±.nr+,vw.rnemore~lop com C:~Documents and Settings\Diane WilliamslDesktop\Transmit_BP.docx Maunder, Thomas E (DOAj From: Nadem, Mehrdad [NademM@BP.com] Sent: Thursday, September 13, 2007 2:42 PM To: Maunder, Thomas E (DOA) Cc: Hobbs, Greg S (ANC); Bernaski, Greg E; Bill, Michael L (Natchiq) Subject: GNI-04 PTD Request for Additional Information Attachments: GNI_Calc_Dist To_Offset Wells.xls Tom, Page 1 of 2 We have researched your request for additional information dated September 10 regarding other wellbores near the Area of Review for proposed well GNI-04. Below are your three specific questions and responses. Attached is a revision to the spreadsheet tabulation of wellbores near or within the 1/4 mile Area of Review. The spreadsheet confirms there are no additional wellbores within the 1/4 mile AOR. Question 1: DS O4-22 {185-233) -According to the information in the file, DP became stuck and it was necessary to plug back the well in November, 1985. There is no survey information in the file. Based on the operations summary and the survey information, the "last" hole section was from 3710' - 4727' and 03760' - 4050' tvd). It would appear that this hate section is above the permitted injection interval. Would you confirm this? Answer 1: Referencing the lost hole section as 4-22PB1, the plugback hole reached a TD of 4727' MD {- 3990' TVDSS), which is projected to lie at a depth of 135 TVD feet below the top SV3 marker, or 460 TVD feet above the SV1 marker. Thus, the 04-22PB1 borehole reached TD in the SV3 confining layer 460 TVD feet above the top of the approved injection interval. Thus this borehole is above the injection zone and outside of the Area of Review. Question 2: DS O4-22A (197-094) -According to the opera#ions information, a section was milled and the well kicked off at 7697' and 05795' tvd). This depth is well above the possible primary cement top. A portion of the new 8-1/2" hole was plugged back, but the depth was well below the authorized injection interval. When the 7" liner was set, the cement was only raised 1000' above the Sag River. It appears that the authorized injection interval was not cx~vered with cement. Would you confirm the proximity of 04-22A with regard to the %4 mile radius of GNl-04? Answer 2: The attached GNI-04 offset well standoff spreadsheet was updated to include the projected SV1, Mc, GNI-04_TD, and CM3 markers from the 04-22A well. The closest approach between the 04-22A sidetrack and the proposed GNI-04 well is 1581 feet at the depth equivalent to the GNI-04 TD location. Question 3: DS 04-25 {186-049) -According to the operations information, a significant portion of 12-1/4A hale was lost when a fish go# stuck during a trip. Hole TD was 12420' and with the fish from 7180' - 7630' md. Cement was set to 6915' and and then another plug was set between 4100' - 450fl' md. New hole was kicked off at 4149' md. When the 9-518" casing was cemented, it does not appear that the authorized injection interval was covered with cement. Would you confirm the location of the abandoned hole section? Answer 3: Referencing the lost hole section as 4-25PB1, the attached GNI-04 offset well standoff spreadsheet was updated to include the projected SV1, Mc, GNI-04_TD, and CM3 markers from the 04-25PB1 well. The well course was established using single shot data documented in daily drilling reports and reported to the AOGCC. The closest approach between the 04-25PB1 borehole and the proposed GNI-04 well is 1999 feet at the depth equivalent to the GNI-04 TD location. Please contact me at 564-5941 if your have any additional questions. I will be out September 17 through September 21, but will be checking my Email. 2/5/2008 Well GNI-04 Lateral Standoff Distance to Offset Wells GNI-04 Lateral Standoff at SV1 Marker: Top of Permitted Infection Interval Lateral Distance to Equivalent Well Marker X Y NDSS Marker in GNI-04 well (Feet) (Feet) (Feet) (Feet) GNI-04_wp03 SV1 715337 5956956 -4490 - 04-17 SV1 713350 5953291 -4449 4169 04-20 SV1 712713 5953956 -4388 3985 04-21 SV1 711946 5955563 -4500 3666 04-22 SV1 712861 5955334 -4502 2960 04-22A SV1 04-23 SV1 712694 5953542 X447 4317 04-24 SV1 713077 5953756 -0447 3918 04-25 SV1 713756 5952918 -4499 4336 04-25P61 SV1 713788 5952823 -4499 4414 04.26 SV1 713880 5952723 -0500 4476 04.27 SV1 715171 5953087 -4500 3873 04.33 SV1 715614 5955034 -4504 1942 04.35 SV1 714270 5955026 -4502 2206 GNI-01 SV1 716026 5957182 -4487 725 GNI-02 SV1 717454 5957451 -4509 2174 GNI-02A SV1 716730 5957817 -4511 1638 GNI-03 SV1 718725 59565.10 -4519 3417 L3-24 SV1 709794 5960740 -4500 6712 L4-11 SV1 719726 5960003 -4502 5343 L4-15 SV1 720423 5959047 -4502 5499 Comment (1) SV1 depth estimated; no shallow logs run in this well SV1 depth estimated; no shallow logs run in this well SV1 depth estimated; no shallow logs run in this well SV1 depth estimated; no shallow logs run in this well Above Sidetrack hole KOP SV1 depth estimated; no shallow logs run in this well SV1 depth estimated; na shallow logs run in this well SV1 depth estimated; na shallow logs run in this well SV1 depth estimated; na shallow logs run in this well SV1 depth estimated; no shallow logs run in this well SV1 depth estimated; no shallow logs run in this well SVi depth estimated; no shallow logs run in this well SVi depth estimated; no shallow logs run in this well SV1 depth estimated; no shallow logs run in this well SV1 depth estimated; no shallow logs run in this well SV1 depth estimated; no shallow logs run in this well Comment (2) GNI-04 Lateral Standoff at UG Mc Marker: Top of Target Perforated Infection Zone Lateral Distance to Equivalent Well Marker X Y TVDSS Marker in GNI-04 well (Feet) (Feet) (Feet) (Feet) GNI-04 wp03 UG_ MC 714400 5957400 -6430 04-17 UG MC 113543 5954574 -6378 04-20 UG MC 711952 5956432 -6329 04-21 UG MC 710894 5958314 -6382 04-22 UG MC 712641 5957963 -6409 . 04.22A UG MC 712720 5957516 -6402 04-23 UG MC 711987 5954597 -6355 04-24 UG MC 713378 5955844 -6380 04-25 UG MC 714966 5955493 -6405 04-25PB1 UG MC 715202 5955470 -6405 04.26 UG MC 715178 5954267 -6402 04-27 UG MC 717203 5954828 -6441 04-33 UG MC 717379 5956835 -6471 04-35 UG MC 714992 5955881 -6410 GNI-01 UG MC 714452 5958717 -6437 GNI-02 UG MC 717578 5959007 -6495 GNI-02A UG MC 715797 5959791 -6472 GNI-03 UG MC 720098 5956657 -6518 L3-24 UG MC 711895 5960096 -6410 L4-11 UG MC 718189 5960797 -6527 L4-15 UG_ MC 719580 5958620 -0518 • GNI-04 Lateral Standoff at De pth Equivalent to GNl-04 TD Well Marker X Y TVDSS (Feet) (Feet) (Feet) GNI-04_wp03 TD 714274 5957460 -6690 Depth Equivalent to 04-17 GNI-oa TD 713564 5954736 -0625 Depth Equivalent to 04-20 GNI-oa TD 711780 5956839 -6579 Depth Equivalent to 04.21 GNI.04 TD 710762 5958666 -6634 2953 2632 3623 1847 1684 3699 1861 1990 2090 3228 3804 3032 1631 1318 3561 2769 5747 3680 5089 5322 Lateral Distance to Equivalent Marker in GNI-04 well (Feet) 2815 2570 3713 Comment (1) Mc depth estimated; no shallow logs run in this well Mc depth estimated; no shallow logs run in this well Mc depth estimated; no shallow logs run in this well Mc depth estimated; no shallow logs run in this well Mc depth estimated; no shallow logs run in this well Mc depth estimated; no shallow logs run in this well Mc depth estimated; na shallow bgs run in this well Mc depth estimated; na shallow bgs run in this well Mc depth estimated; no shallow logs run in this well Mc depth estimated; no shallow logs run in this well Mc depth estimated; no shallow logs run in this well Mc depth estimated; no shallow logs run in this well Mc depth estimated; no shallow logs run in this well Mc depth estimated; no shallow logs run in this well Mc depth estimated; no shallow logs run in this well Mc depth estimated; no shallow logs run in this well Comment (1) GNI-04 TD equivalent estimaked; no shallow logs run in this well GNt•04 TD equivalent estimated; no shallow logs run in this well GNi•04 TD equivalent estimated; no shallow logs run in this well Comment (2) Comment (2) Depth Equivalent to 04-22 GNI-04 TD 712610 5958308 -6661 1867 Depth Equivalent to 04-22A GNI-04 TD 712705 5957655 $638 1581 Depth Equivalent to 04-23 GNI-04 TD 711900 5954733 -6605 3615 Depth Equivalent to 04.24 GNI.04 TD 713441 5956131 -6632 1568 Depth Equivalent to 04-25 GNI-04 TD 715182 5955830 -6655 1866 . 04-25PB1 Depth Equivalent to GNI-04 TD 715336 5955766 -6655 1999 Depth Equivalent to 04-26 GNI-04 TD 715345 5954443 -6655 3201 Depth Equivalent to 04-27 GNI-D4 TD 717450 5955025 -6698 4002 Depth Equivalent to 04-33 GNI-04 TD 717585 5957082 -6729 3332 Depth Equivalent to 04-35 GNI-04 TD 715075 5956037 -6670 1633 Depth Equivalent to GNI-01 GNI-04 TD 714303 5958875 -6680 1415 Depth Equivalent to GNI-02 GNI-04 TD 717585 5959188 -6738 3735 GNI-02A Depth Equivalent to GNI-03 GNI-04 TD 720263 5956667 -6772 6041 Depth Equivalent to • L3-24 GNI-04 TD Depth Equivalent to 712166 5960009 -6662 3307 L4.11 GNI-04 TD 717990 5960862 -6780 5038 Depth Equivalent to L4-15 GNI-04 TD 719475 5958570 -6771 5318 GNI-04 Lateral Standoff at CM3 Marker: Base of Permitted Infection Zone Lateral Distance to Equivalent Well Marker X Y NDSS Marker in GNI-04 well (Feet) (Feet) (Feet) (Feet) GNI-04 TD equivalent estimated; no shallow logs run in this well GNI-04 TD equivalent estimated; no shallow logs run in this well GNI.04 TD equivalent estimated; no shallow logs run in this well GNI-04 TD equivalent estimated; na shallow logs run in this well GNI-04 TD equivalent estimated; no shallow logs run in this well GNI-04 TD equivalent estimated; no shallow logs run in this welt GNI-04 TD equivalent estimated; no shallow logs run in this well GNI-04 TD equivalent estimated; no shallow logs run in this well GNI-04 TD equivalent estimated; no shallow togs run in this well GNI-04 TD equivalent estimated; no shallow logs run in this well GNI-04 TD equivalent estimated; no shallow logs run in this well GNI-04 TD equivalent estimated; no shallow logs run in this well Depth not reached GNI-04 TD equivalent estimated; no shallow logs run in this well GNI-04 TD equivalent estimated; no shallow logs run in this well GNI-04 TD equivalent estimated; no shallow logs run in this well GNI-04 TD equivalent estimated; no shallow logs run in this well Comment (1) Comment (2) * -Lateral distance based on Proiected Death of GNI-04 CM3 marker; CM3 Depth Will Not Be GNI-04-wp03 CM3 714140 5957524 -6975 - Reached in GNl-o4 * -Lateral distance based on Proiected Depth of GNI-04 CM3 marker; CM3 Depth Will Not Be 04-17 CM3 713589 5954942 -6935 2641 CM3 depth estimated; no shallow logs run in this well Reached in GNI-04 * -Lateral distance based on Proiected Death ofGNI-04 CM3 marker CM3 De th Will Not Be p • 04-20 CM3 711561 5957347 -6929 2585 CM3 depth estimated; no shallow logs run in this well Reached in GNI.04 * -Lateral distance based on Proiected Depth of GNI-04 CM3 marker; CM3 Depth Will Not Be 04.21 CM3 710584 5959089 -6971 3885 CM3 depth estimaied; no shallow logs run in this well Reached in GNI-04 * -Lateral distance based on Proiected Depth of GNI-04 CM3 marker; CM3 Depth Will Not Be 04-22 CM3 712576 5958773 -6991 2002 CM3 depth estimated; no shallow logs run in this well Reached in GNI-04 * -Lateral distance based on Proiected Depth of GNI-04 CM3 marker; CM3 Depth Will Not Be 04-22A CM3 712685 5957845 -6977 1490 CM3 depth estimated; no shallow logs run in this well Reached in GNI-04 * -Lateral distance based on ° Proiected Death of GNI-04 CM3 marker; CM3 Depth Will Not Be 04-23 CM3 711769 5954932 -6990 3513 CM3 depth estimated; no shallow logs run in this well Reached in GNI-o4 * -Lateral distance based on • Proiected Death of GNI-04 CM3 marker; GM3 Depth tMll Nat Be 04-24 CM3 713513 5956495 -6927 1205 CM3 depth estimated; no shallow logs run in this well Reached in GNI-04 * -Lateral distance based on Proiected Depth of GNI-04 CM3 marker; CM3 Depth Will Not Be 04-25 CM3 715454 5956263 -6990 1822 CM3 depth estimated; no shallow logs run in this well Reached in GNI-04 * -Lateral distance based on Proiected Death of GNI-04 CM3 marker; CM3 Depth Will Not Be 04-25PB1 CM3 715565 5956301 -6990 1878 CM3 depth estimated; no shallow logs run in this well Reached in GNI-04 04-26 CM3 715531 5954642 -6959 3200 04-27 CM3 717717 5955242 -7000 4243 • 04-33 CM3 717826 5957380 -7039 3689 04-35 CM3 715179 5956226 -6990 1663 GNI-01 GNI-02 GNI-02A GNI-03 L3-24 CM3 712515 5959898 -7000 2876 L4-11 CM3 717740 5960975 -7089 4987 • L4.15 CM3 719387 5958526 -1089 5342 * -Lateral distance based on Projected Death of GNI-04 CM3 marker; CM3 Depth Will Not Be CM3 depth estimated; no shallow logs run in this well Reached in GNI-04 * -Lateral distance based on Projected Depth of GNI-04 CM3 marker; CM3 Depth Will Not Be CM3 depth estimated; no shallow logs run in this well Reached in GNI-04 * -Lateral distance based on Projected Depth of GNI-D4 CM3 marker; CM3 Depth Will Noi Be CM3 depth estimated; no shallow logs run in this well Reached in GNI-04 * -Lateral distance based on Projected Depth of GNI-04 CM3 marker; CM3 Depth Will Not Be CM3 depth estimated; no shallow logs run in this well Reached in GNI-04 Depth not reached Depth not reached Depth not reached Depth not reached * -Lateral distance based on Projected Depth of GNI-04 CM3 marker; CM3 Depth Will Not Be CM3 depth estimated; no shallow logs run in this well Reached in GNI-D4 * -Lateral distance based on Projected Depth of GNI.04 CM3 marker; CM3 Depth Will Not Be CM3 depth estimated; no shallow logs run in this well Reached in GNI-04 * -Lateral distance based on Projected Depth of GNI-04 CM3 marker; CM3 Depth Will Not Be CM3 depth estimated; no shallow logs run in this well Reached in GNI-04 Page 1 of 1 Maunder, Thomas E (DOA) From: Nadem, Mehrdad [NademM@BP.com] Sent: Tuesday, September 11, 2007 3:23 PM To: Maunder, Thomas E (DOA) Cc: Bill, Michael L ~Natchiq); Hobbs, Greg S (ANC) Subject: RE: GNI-04 PTD Request for Additional Information--again Tom, ~p~-~r'~ You are correct. The yield for DeepCrete is 3.85 cu. ft./sk. Schlumberger has resubmitted the CemCade with the correct yield. Also, attached please find info on DeepCrete. We will provide information on offset wells after we load the data on the computer. Regards, Mehrdad _ . ~l~ ~~~~ ~oos~ From: Maunder, Thomas E (DOA) ~~~~~'' y- ~` " 1 ~ l~c"~, ~ ~ C~ Sent: Friday, September 07, 2007 3:28 PM To: 'Hobbs, Greg S (ANC)' Subject: RE: GNI-04 PTD Request for Additional Information Greg and Mehrdad, I am reviewing the drilling program. Please confirm that the yield of the DeepCrete Lite is 1.85. There are so many different cements out there now, I loose track. A yield of 1.85 seems to be a little low with a weight of 10.7 pP9~ . Thanks, Tom Maunder, PE AOGCC `' Y ~ 2D' 2isi2oos • • Page 1 of 3 Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Monday, September 10, 2007 4:30 PM To: Hobbs, Greg S (ANC); Nadem, Mehrdad Cc: Jim Regg Subject: RE: GNI-04 PTD Request for Additional Information--again Mehrdad and Greg, I am further reviewing the application for GNI-04. Please see my questions of last Friday (below). I have some further questions with regard to the review of existing wells around the proposed well trajectory. DS 04-22 (185-233) -According to the information in the file, DP became stuck and it was necessary to plug back the well in November, 1985. There is no survey information in the file. Based on the operations summary and the survey information, the "lost" hole section was from 3710' - 4727' and (3760' - 4050' tvd). It would appear that this hole section is above the permitted injection interval. Would you confirm this? It does not appear that the authorized injection interval was covered when the 9-5/8' casing was ultimately cemented. DS 04-22 was plugged back for sidetrack in early 1994 and DS O4-22A was drilled. DS 04-22A (197-094) -According to the operations information, a section was milled and the well kicked off at 7697' and (-5795' tvd). This depth is well above the possible primary cement top. A portion of the new 8-1 /2" hale was plugged back, but the depth was well below the authorized injection interval. When the 7" liner was set, the cement was only raised 1000' above the Sag River. It appears that the authorized injection interval was not covered with cement. Would you confirm the proximity of 04-22A with regard to the %4 mile radius of GNI-04? DS 04-25 (186-049) -According to the operations information, a significant portion of 12-1/4" hole was lost when a fish got stuck during a trip. Hole TD was 12420' and with the fish from 7180' - 7630' md. Cement was set to 6915' and and then another plug was set between 4100` - 4500° md. New hole was kicked off at 4149' md. When the 9-5/8" casing was cemented, it does not appear that the authorized injection interval was covered with cement. Would you confirm the location of the abandoned hole section? DS 04-35 (191-039} - Of the DS 4 wells, this well is calculated to be the nearest to the'/d radius. The report for this well is interesting in that it indicates that a lead slurry of MTC° (mud to cement) was used. Based on the MTC and cement volumes listed in the operations report, potential top of MTC is -5200' tvd SS. Of the DS 4 wells examined, this is the highest possible "cement" top. I look forward to your reply. Call or message with any questions.. Tom Maunder, PE AOGCC From: Maunder, Thomas E (DOA) Sent: Friday, September 07, 2007 3:28 PM To: 'Hobbs, Greg S (ANC)' Subject: RE: GNI-04 PTD Request for Additional Information Greg and Mehrdad, I am reviewing the drilling program. Please confirm that the yield of the DeepCrete Lite is 1.85. There are so many different cements out there now, I loose track. A yield of 1.85 seems to be a little low with a weight of 10.7 PPg• Thanks, Tom Maunder, PE AOGCC From: Hobbs, Greg S (ANC) [mailto:Greg.Hobbs@bp.com] 2/5/2008 • Page 2 of 3 Sent: Thursday, September 06, 2007 12:03 PM To: Maunder, Thomas E (DOA) Subject: RE: GNI-04 PTD Request for Additional Information Thanks Tom! From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Thursday, September 06, 2007 10:51 AM To: Bill, Michael L (Natchiq) Cc: Nadem, Mehrdad; Bernaski, Greg E; Hobbs, Greg S (ANC); Engel, Harry R Subject: RE: GNI-04 PTD Request for Additional Information Mike, et al, I have just briefly looked at the documents. This looks very complete. I will be back to you/Mehrdad with any further questions. Tom From: Bill, Michael L (Natchiq) [mailto:Michael.Bill@bp.com] Sent: Thursday, September 06, 2007 10:17 AM To: Maunder, Thomas E (DOA) Cc: Nadem, Mehrdad; Bernaski, Greg E; Hobbs, Greg S (ANC); Engel, Harry R Subject: GNI-04 PTD Request for Additional Information Tom, Mehrdad Nadem is out of the office this week but checking his email. He asked me to work with geologist Greg Bernaski and forward the information you requested. Area Injection Order 4E, Rule 2 lists the authorized injection zone for slurry disposal as " ... strata defined as those which correlate with and are common to strata found in the ARCO Sag River State No. 1 well between the measured depths of 4,270-6750 feet." The top and base of this interval are close to the SV1 and CM3 markers. Enclosed are three documents to answer your questions. - map showing the proposed GNI-04 well course, offset wells and 1/4 mile circles at the SV1 and CM3 markers and 1/4 mile circles -type log (GNI-02) showing the markers for reference - spreadsheet containing calculated distances from the proposed GNI-04 well course to the equivalent markers in offset wells. The spreadsheet contains calculations at the SV1 marker, the UG Mc marker (target perforation interval), the equivalent depth at the proposed GNI-04 TD, and at the CM3 marker. Note, well GNI-04 will not penetrate the CM3 marker. The spreadsheet shows the distance between the proposed TD of well GNI-04 and the equivalent depth in the nearest wells to be: GNI-01 1415 ft, 4-24 1568 ft, and 4-35 1633 ft. As shown on the type log, the planned perforation interval is 20 feet at the UG Mc 04 marker. The nearest wells at the UG Mc marker are: GNI-01 1318 ft, 4-35 1631 ft, and 4-24 1861 ft. Let me or Mehrdad know if you have any questions or need additional information. Mike Bill ADW Wells Group 907-564-4692 office 907-564-5510 fax 2/5/2008 • • Page 3 of 3 Frem: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Friday, August 31, 2007 2:54 PM To: Nadem, Mehrdad Cc: Hobbs, Greg S (ANC); Arthur C Saltmarsh Subject: GNI-04 Mehrdad, We are beginning the initial review of the application for GNI-04. You have included the well proximity information; however I am requesting that a larger scale plot be provided. $-1/2" x 11" should be fine with the focus being the '14 mile radius at the top and bottom of the authorized injection interval. Please show the production wells you have identified. If possible, tvd depth markers along the well paths would be appreciated. Thanks in advance. Call or message with any questions. Tom Maunder, PE A®GCC 2/5/2008 Page 1 of 1 IlAaunder, Thomas E (DOA) From: Nadem, Mehrdad [NademM@BP.com] Sent: Sunday, September 02, 2007.6:21 PM To: Saltmarsh, Arthur C (DOA); Maunder, Thomas E (DOA) Subject: GNI-04 Attachments: GNI-04 Permit To DriiI.ZIP Art, My apologies of inadvertently leaving you off the first message. Regards, Mehrdad From: Nadem, Mehrdad Sent: Sunday, September 02, 2007 6:17 PM To: 'Maunder, Thomas E (DOA)' Subject: GNI-04 Tom, aoh-~ ~ ~ Thanks for your message. I will provide you with a large scale plot, and requested information regarding tvd depth markers along the paths. Also, I have attached an amended (revised) permit application to this Email. I request this submittal to supersede the previous submittal. I will call on Tuesday to discuss. Regards, Mehrdad Nadem From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Friday, August 31, 2007 2:54 PM To: Nadem, Mehrdad Ce: Hobbs, Greg S (ANC); Arthur C Saltmarsh Subject: GNI-04 Mehrdad, We are beginning the initial review of the application for GNI-04. You have included the well proximity information; however I am requesting that a larger scale plot be provided. 8-1/2" x 11"should be fine with the focus being the %4 mile radius at the top and bottom of the authorized injection interval. Please show the production wells you have identified. If possible, tvd depth markers along the well paths would be appreciated. Thanks in advance. Call or message with any questions. Tom. Maunder, PE AOGCC 2/5/2008 • GNI-04 ~/Vel I Top and base I n~ection Inter~ral ~/~ Mile Standoff Circles m~ m m m m m m~ m m~ m m m m ~ ~ m m N m m ~ c~ ~- .--. .-, ..~ ~--. .~ ~-, r, ~ ~ ~ ~ r` ~ ~ 5962eea ~ I I _ Jg6ieee - ~~~eeee- ~95geee 59~8eee 5957aee ~9~6e~ee- 04 59sseee s~54eee- m I -02 GNI-04 114 Mile radius ', GNI-04 1/4 Mile radius - - ' circle from the ~rQjected ;' --- --'! circle from SV1 Marker! CM3 Markerlbase top injection interval injection interval " ~~-!-- ":: * -Note that GNI-04 will reach TD 300 TVD feet above the CM3/base injection interval depth i =. ~r . ~.:. ~, , *. ~. . ~. ~.:: __ _ ~ ,~~ MICROFILMED 6/30/2010 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE C:\temp\Temporary Internet Files\OLK9\Microftlm_Marker.doc • • Proposed Schedule for 2010 Mechanical Integrity Testing Class I 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 -~ ~- t7 2011. Badami B1-01 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 ~4~ > `~ ~l summer barge season. Northstar NS10 By August 12, Late July 2010 The Water Flow Logs 2010 will be conducted during the summer a~0" \~s`~ bar a season. Northstar NS32 By August 12, Late July 2010 The Water Flow Logs 2010 will be conducted during the summer ~~ \~ ~° ~ bar e season. Liberty CRI Well N/A September 2010 All logs required to complete the well will ~p ~- ~ ~< ~~ y E ~- 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 `®~ ~~ ~ ~ and NW wells 2010 with MIT's. and by Caliper logs in a3~ November 7, summer/fall 2010. -.~-~ ~ 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 forGNI- /Early October, Logs and/or Water 03 ,and GNI-04 02A, GNI-03 and 2010 Flow Logs planned for ~C7~- ~~~ GNI-04. summer 2010. Caliper logs in 1 rl '" ~ ~ 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 7t'' Avenue Anchorage, AK 99501-3192 Mr. Shawn Stokes Department of Environmental Conservation 555 Cordova St. Anchorage, AK 99501 ~tE, ~ ~~ :~- , BP Exploration (Alaska) Inc. P. 0. Box 196612 900 E. Benson Boulevard Anchorage, AK 99519-6612 Direct 907 561 5111 Phone: (907) 564-4838 Email: Alison.Cooke~bp.com Web: www.bp.com FEe ~ 4 2oi~ ~as~~I~,G~s Gortu., ~~ RE: Mechanical Integrity Test Notifications Badami Class 1 Iniection We_II 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. 2005DB001-0001 Pad 3 Iniection Wells. UIC Permit AK-1!004-A Wastewater Disposal Permit No. 2005DB0001-0021 Grind and Iniect Injection Wells. UIC Permit AK-11008-A Area Injection 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 Integrit st Notification -= February 23, 2010 Page 2 Dear Sirs: BP Exploration (Alaska) Inc. (BPXA) respectfully submits the following notifications: 1) the annual Mechanical Integrity Test (MIT) and fluid movement 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; 41 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 meat (907) 564-4838. Sincerely, os.~.,'~ C~_ Alison Cooke Environmental Advisor Attachment cc: Thor Cutler, EPA Region 10 Talib Syed, EPA Consultant ~'~ ~~ • ~ a~~~~ ~. .~~:v ~ ~r. ~~~~~~:, Certified Mai) # 7008 3230 0000 2489 0749 October 29, 2008 ~4~t~~~~~ N ~ ~ ~ 6 200~ UIC Manager, Ground Water Protection Unit U.S. Environmental Protection Agency (OCE-127) 1200 Sixth Avenue, Suite 900 Seattle, WA 98101 BP Exploration (Aiaskal Inc. P. O. Box 196612 900 Easi Benson Boulevard Anchorage, AK 99519-6612 _ ~~ ~ ~; OCT ~ Z009 `~~ ~ ~ ~~ ~r~ ~~. .~~ ~o~~a o ~ °ssoor~ Re: Demonstration of Mechanical Integrity, Prudhoe Bay Grind and Inject, ~n~~ora~ UIC Class I Permit AK-11008-A Dear UIC Manager• ~~~-~~~ ~~~-~a ~ --~~~`1~~,~"~ ~N~-O~ This letter is to submit the results of annulus pressure tests for two IC Class I wells located at the Prudhoe Bay Grind and Inject project and operated by BP Exploration (Alaska), Inc (BPXA). The tests are specified as part of the demonstration of inechanical integrity under Part II, C.3 of EPA UIC Class I permit AK11008-A. The tests were conducted in compliance with the permit requirements and were witnessed by EPA representatives Thor Cutler and/or Talib Syed. The annulus pressure tests, also known as Mechanical Integrity Tests (MITs) were performed on well GNI-02A on September 25, 2009 and on well GNI-04 on September 28, 2009. Both wells passed the MITs. The fluid movement and caliper logging requirements of the permit were satisfied earlier in the year and the results were submitted in correspondence dated February 26, May 15 and, July 28, 2009. Detailed information regarding the results of the MITs is contained in the attached descriptive and interpretive analysis of the tests. 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 submii#ing faise information, including the possibility of fine and imprisonment. BPXA understands that the EPA will notify BPXA of the acceptability of the mechanical integrity demonstration within 13 days of receipt of the results of the mechanical integrity tests (Part II, C.3.c.(4)). Injection may continue during this 13 day review period. If the EPA does not respond within 13 days, we will conclude that the results are acceptable and will continue with injection. UIC Manager • • October 29, 2009 Page 2 If you have questions, please contact Michael Bill, Sr. Staff Engineer at (907) 564-4692. Sincerely, ~ ~~ /~ °Z ~-09 Bill E. March, Infrastructure Project Manager Attachments: Mechanical Integrity Test Results Mechanical Integrity Test Form Cc: Thor Cutler, EPA Region 10 Talib Syed, EPA Consultant Jim Regg, AOGCC Shawn Stokes, ADEC Mike Bill, BPXA ~ • Mechanical Integrity Test Results Grind and Inject Injection Wells Prudhoe Bay Unit Annulus pressure tests were performed on UIC Class I Prudhoe Bay Grind and Inject disposal well GNI-02A on September 25 and on well GNI-04 on September 28, 2009. The tests were performed in accordance with the stipulations of Class I Permit AK-1I008-A. In each well, the nitrogen cushion in the tubing - casing annulus was bled off and displaced with diesel. The annulus was then pressured to above 1500 psi with diesel and observed for 30 minutes. The tests were conducted while the subject well was shut in. The results of the tests were as follows: Tubin~Pressure Annulus Pressure psi 1 st Half 2nd Half Test Pad 3 Well Start / End Start 15 Min 30 Min Decline Decline Result GNI-02A 290 / 290 1520 1490 1480 30 10 Passed GNI-04 420 / 420 1520 1475 1456 45 19 Passed In each well, the pressure decline was less than 10 percent during the test period, with less than 1/3 of the total decline in the second half of the 30 minute period. This shows a stabilizing tendency as specified in EPA Permit AK-1I008-A, Part II, C 3 b(1). Annulus pressures were observed on a test gauge. During the test period, the tubing pressure was essentially constant in each well. The tests were witnessed by EPA representatives Thor Cutler and/or Talib Syed. AOGCC inspector was Bob Noble also witnessed the tests. I conclude from the successful MIT's that the casing, tubing and packer in wells GNI-02A and GNI-04 are in sound mechanical condition. This is consistent with the absence of any indication of tubing or packer leakage during normal injection operations when there is a large pressure differential (>500 psi) between the tubing and the annulus in each of the wells. Michael L. Bill October 29, 2009 ~ ~ -~"' `~" ~~~ United States Environmental Protection Agency ~~.~~ Region 10 ~:,'~/1 1200 Sixth Avenue, Suite 90(1 ~`"-J" Seattle, WA 98101 Thor Cutler -(206) 553-1673 e-mail: cuder.thor@epa.gov MECHANICAL INTEGRITY TEST (MIT) FORM Facility Well Permit No. PTD No. BP Alaska - PBU GNI-04 AK-1I0Q8-A 2071170 Tnjector MTT Type Test Type Test Date Class I T X IA Std. Annular Pressure Test (SAPT) 9/28/2009 Req'd Test Presssure (psi) Fluid Type(s) used to test Packer Depth (ft, TVD) Test Interval / Comments 1,500 Diesel 4,461' One Year Cycle Record all Wellhead Pressures before and during Test. Note whether well is on injection or SI during test. If on injection, note injection rate, injection pressure and injection fluid temperawre Note volume of diesel pumped in annulus during test. T START TIME: RECORDED PRFSSURFS (PSI) RESULT E 00:00 am/pm PRE MIT IN[TIAL 15 MIN 30 MIN 45 MIN 60 MIN P/F S TUBING 420 420 420 420 T INNER ANNULUS 0 1520 1475 1456 PASS OUTER ANNULUS 0 0 0 0 1 COMMENTS: T START TIME: RECORDED PRESSURES (PSI) RESULT E PRE MIT INITIAL 15 MIN 30 MIN 45 MIN b0 MIN S TUBING PASS/ T INNER ANNULUS FAIL OUTER ANNULUS 2 COMMENTS: T START TIME: RECORDED PRESSURES (PSI) RESULT E PRE MIT INITIAL 15 MIN 30 MIN 45 MIN 60 MIN $ TUBING PASS/ T INNER ANNULUS FAIL OUTER ANNUWS 3 COMMENTS: MISC COMMENTS: Last test MITIA -10/7/08 (witness T,Syed/T.Cutler), SI Temp Surveys and tbg/csg calipers - 1/27/09 Dedicated G&I solids injection well. Drilled in late 2007 with slurry injection start on 5l22/08. Last tested fw MITIA on 10l7/08 to 2000 psi. Total loss - 60 psi over 30 minutes (within 10 % allowable) NOTE: Pressure must show stabilizing tendency: 1) Total pressure loss must be less than 10 % at end of 30 minute test 2) Pressure loss in last 15 minutes must be less than 33% of total loss Start MI'f' over if: 1) Total loss exceeds 10 % 2) L.oss during last I S minute period = or > 50% of loss during first 15 minute period Extend test duration to 60 minutes, if necessary, to eliminate thermal effects (on-site decision per Inspector). r_~ 0 0 ~-- E-mail this MIT Test Data Form to EPA Region 10 • Thor Cutler EPA Rep: AOGCC Rep: Operator Rep: 7alib Syed, P.E./ Thor Cutler Bob Noble Anna Dube l_ J MEMORANDUM To: Jim Regg ~ I l I Z7 I P.I. Supervisor FROM: Bob Noble Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission DATE: Friday, October 23, 2009 SUBJECT: Mechanical Integrity Tests BP EXPLORATION(ALASKA)II1C GNI-04 PRUDHOE BAY UN UGN GNI-04 Src: Inspector NON-CONFIDENTIAL Reviewed By: P.I. Suprv J~~ Comm Well Name: PRUDHOE BAY UN UGN GNI-04 API Well Number: 50-029-23367-00-00 Inspector Name: Bob Noble Insp Num: mitRCN091023093104 Permit Number: 207-117-0 ~ Inspection Date: 9/28/2009 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. T GNI-04 ~ -~--,T-_ - Well ~ Type Inj. N I TVD ---~ ---- +~---i 4461 ~ IA ~ -0 -_~T _ __ _ _ - ~ 1520 - _ 1475 1456 ~ ~ _ _ --~-- - --r-- P.T.D zo~n~o iTypeTest "''' I Test psi I ~ -1 ~ 1 L ]s2o OA I o ------ L~----~- 0 - 0 0 ~ ~- - - ----- ---- --- -- _- - --- p ~ Interval oTI-IER P/F -- Tubin ~ 420 -- -- g~---1 420 - 420 420 - ~ ~ -~ - --- NOteS• One year test cycle, EPA witnessed t,~~S$ ~r~~~ ,~~11~ ~ ~ lf~~~t Friday, October 23, 2009 Page 1 of 1 • • STATE OF ALASKA ALASKA OIL AND GAS CONSERUATION COMMISSION Mechanical integrity Test Email to:jim.regg~alaska.gov; tom.maunder~alaska_gov;~.fleclcen.stein~a~ska.gav;doa.aogcc.prudhce.bay~alaska.gov OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: BP Explaratian (Alaska}, Inc. Prudhae Bay / PBE1 / GN! 09128/t39 Anna Dube Bbb Noble F'acfcer Pretrest in~1 15 Min_ 30 Min. Well GNI-04 T In'. D T\f~} ~,461" T` 4~Q 42(l 420 420 Intervai O P.T.D. 2071170 T test P Test ' 15UQ C` ~ 1,S2Q 1,475 1,456 P/F P Notes: MIT-IA to 15(m psi to sattfy EPA dass t perrrtat t3A (} U O 0 Well T in". Ti~ T' Interval P.T.D. T test Te.d ~ P/F Notes: OA Well T In'. TVd "f ~ Interval P.T.0. T test Te~t ' Gasi P/F Notes: OA Well T ir~~_ 71/C! T- Interval P.T.D. T test 'fest ' P/F Notes: Da Well T In"_ TuD T" Intervai P.T.D. T t+~t Tes# ' P/F Notes: OA TYPE INJ Codes D = Drilling Waste G = Gas I = Indusfial Wastevwater N = Not Injecting W = Water TYPE TEST Cm~les M = Annuf~ ~i~e~g P = Standard 63te~au~ tesE R = lrrterr~6 . TGxer Sucvey A = T a~re Sur~ey D - ' - 3' e ~'e:,t F~,;K.I~~"`~~~~4..~ ~'~! ;` ~ ~~ ~~i~;~ ~'~Cb INTERVAL Codes 1= Ini6al Test 4 = Four Year Gycle V = R~uired by Variance T = Test during Workover O = Other (describe in notes) MIT Report Form BFL 11l27l07 MIT PBU GNI-04 09-28-09.x1s • i ` United States Environmental Protection Agency , t~~ 'i Begion l0 1200 Sixth Avenue, Suite 90Q Seattle, WA 98101 Thor Cutler -(2d6) 553-1673 e-mail: cutler.thor@epa.gov MECHANICAL INTEGRITY TEST (MIT) FORM Facilily Wei1 Permit No. PTD No. BP Alaska - PBU G1vI-04 AK-1I008-A 207117d Injector MI'r'~'y~ Test Type Test Date Class I T X IA, Std Annular Pressure Test (SAPT~ 9/28/2009 Req'd Test Presssare (psi) Flaid Type(s) ased to test Packer DeptY (ft, TVD~ Test Interval ! Comments 1,500 Diesel 4,461' One Yeatr Cycle Record a(l Wellhead Pressures before and during Test. Note whether well is on injection or SI during test. If on injection, note injection rate, injection pressure and injection fluid temperature Note volurne of diesel pumped in annulus during tast. '~ START TIME: RECORDED PRESSURES (PSn RESULT E 011:00 am/pm rRE MTr INTrIAL 15 MIN 3o Nmv 4s bIIN 6o bmv P(F S TI7BING 420 420 420 420 T INNER ANNtJLUS 0 1520 1475 1456 PASS OUTER ANNiJLUS 0 0 0 0 7 COMIvvIEN'I'S: T START TIME: RECORDED PRESSIJRES (PSn RESULT E PRE MIT INITIAI. 15 MIN 311 MIN 45 MIN 60 MIN S TUBING PASS/ T INNERANNIJLUS FAIL OUTER ANN[JLUS 2 COMIVIEiN'I'S: T START TIME: RECORDED PRESSURES (PSn RESULT E PRE Mi' INTfIAL 15 MIN 30 hIIN 4511~III+T 60 MIIV S TIJBING PASS/ T INNER ANNLJLUS FAII, OUTER ANNULUS 3 COMMENTS: t~_.F C~ C~ ~- E-mail this MIT Test Data Form to EPA Region 10 - Thor Cutler EPA Rep: AOGCC Rtp: Operator Rep: Talib S~red, P.E./ Thor Cutler Bob Noble Anna Dube i) Total pressure toss must be less than 10 % at end of 30 minute test 2) Pressure loss in last 15 minutes must be less than 33% of total loss Start MIT over if. i) Tota1 loss exceeds IO % 2) Loss during last 1 S minute period = or > 50% of loss dwing first I S minute period Extend test duration to 60 minutes, if necessary, to eliminate thermat effects (on-site decision per Inspector). -S • ~~L TR~4f~1~li~fl°To4L ProActive Diagnostic Services, Inc. To: AOGCC Christine Mahnken 333 W. 7th Ave Suite 100 Anchorage, Alaska 99501 (907j 793-1225 RE : Cased Hole/C'pen Hole/Mechanical Logs and/or Tubing Inspection[Caliper/ MT7~ The technical data listed below is being submitted herewith. F~ease acknowledge receipt by returning a signed copy of this transmittal letter to the following BP Exploration (Alaska), Inc. Petrotechnical Data Center ,.;° rirE~~~E ~°~ ~ ~~ ~~~'~ Attn: Joe Lastufka LR2 - 1 900 Benson Blvd. Anchorage, Alaska 99508 U.TC, ~~~._ ~ ~~ J ~~~~ and ~9~ -oS3 (~s~S' ProActive Diagnostic Services, Inc. Attn: Robert A. Richey 130 West International Airport Road Suite C Anchorage, AK 99518 Fax: (907) 245-8952 1 J Coii Ftag 22,Jan-09 S,43L1 EDE 50-029-2275460 ~~ 2j Temperature Survey 2~~1 GNI.O~! 1 Color Log., E-~ , 50~~~ ~ -00 /I ~~ j% ~~ y A "_; Signed : ~ Date : ~? ~'_ `~ Print Name: PROACTIVE DIAGNOSTIC SERVICES, INC., 130 W. INTERNATIONAL AIRPORT RD SUITE C, ANCHORAGE, AK 99518 PHONE: (907245.8951 FAX: (907)245-88952 E-RMIL.: ~dsanc3a~rae~~Ca~~aae~-sar~,~,~.~~s~ WEBSrrE: v+nnr+.u.r~~~or~~Bc?~.~a~ C:\Documents and Settings\OwnerlDesktop\Tiansmit_BP.docx DATA SUBMITTAL COMPLIANCE REPORT 12/1 /2008 Permit to Drill 2071170 Well Name/No. PRUDHOE BAY UN UGN GNI-04 Operator BP EXPLORATION (ALASKA) INC API No. 50-029-23367-00-00 MD 7463 TVD 6757 REQUIRED INFORMATION Completion Date 1/31/2008 Mud Log No Samples No DATA I NFORMATION Types Electric or Other Logs Run: DIR / GR, GR /CCL /CBL /USIT, GR RES /DEN / NEU /DI POLE S Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Type Med/Frmt Number Name Scale Media No r~Ft t D Asc Directional Survey i Di p rect onal Survey C Exc Directional Survey pt Directional Survey og Cement Evaluation 5 Col 1 ~_g Sonic 5 Col i ~~I ~g Temperature 5 Blu 1 ,log Sonic 5 Col 1 i~D C Lis 15927/Sonic (yL~og Induction/Resistivity 25 Blu ~og Induction/Resistivity 25 Blu ~ED C Lis }-~28 ~nduction/Resistivity ir4z~ ~ecJ emperature 5 Blu 1 Log T 15986 ~`fem erature 5 Bl 1 p u ', Log Reservoir Saturation 5 Blu Directional Completion Status WDSP2 Current Status WDSP2 (data taken from Logs Portion of Master Well Data Maint Interval OH / Start Stop CH Received Comments 0 7463 Open 11/19/2007 0 7463 Open 11/19/2007 0 540 Open 11 /19/2007 0 540 Open 11/19/2007 0 4110 Case 11/19/2007 USIT-D, CBL, GPIT, CCL, GR 5-Nov-2007 4000 7350 Case 11/27/2007 USIT, CBL-VDL, GPIT, CR, CCL 11-Nov-2007 10 7356 Case 1/28/2008 Temp Survey, Pres, GR, CCL 22-Jan-2008 4235 7474 Case 1/22/2008 DSST. Comp Log 8-Nov- 2007 2941 7287 Case 2/4/2008 LIS Veri, USIT, CCL w/PDF and TIF graphics 108 7404 Open 2/13/2008 MD Vision Service 29-Oct- 2007 108 7404 Open 2/13/2008 TVD Vision Service 29-Oct- 2007 54 7464 Open 2/13/2008 LIS Veri, GR, ROP, FET, RPM, DRHO, NPHI w/PDF and TIF graphics 10 7356 Case 3/4/2008 Temp Survey, Pres, GR, CCL 22-Jan-2008 COPY 10 7356 Case 3/4/2008 Temp Survey, Pres, GR, CCL 22-Jan-2008 5125 7140 Case 5/9/2008 RST, WaterFlow, RST, Spin, Pres, Temp, GR, CCL 24-Apr-2008 DATA SUBMITTAL COMPLIANCE REPORT 12/1 /2008 Permit to Drill 2071170 Well Name/No. PRUDHOE BAY UN UGN GNI-04 Operator BP EXPLORATION (ALASKA) INC API No. 50-029-23367-00-00 MD 7463 'ED C Pds TVD 6757 Completion Date 1/31/2008 16244~servoir Saturation og Pressure g C Pds 16334 Pressure '' og Sonic /ED C Lis 16406 Sonic Well Cores/Samples Information: Name ADDITIONAL INFORMq~tQN ~ Well Cored? Y I(~ V] Chips Received? Y~1V'~ Analysis Y~ Received? Comments: Compliance Reviewed By: __ Completion Status WDSP2 Current Status WDSP2 UIC Y 5125 7140 Case 5/9/2008 RST, WaterFlow RST, Spin, Pres, Temp, GR, CCL 24-Apr-2008 5 Col 0 7140 Case 5/23/2008 Step Rate Injectivity, Spin, Pres, Temp, GR, CCL 23- Apr-2008 0 7140 Case 5/23/2008 Step Rate Injectivity, Spin, Pres, Temp, GR, CCL 23- Apr-2008 Blu 3690 7466 Case 6/6/2008 Digital Shear Sonic Tool 7- Nov-2007 3690 7466 Case 6/6/2008 LIS Veri, DAS Sample Interval Set Start Stop Sent Received Number Comments Daily History Received? ~N Formation Tops ~ N Date: lvlll roans Ior r,rti Lompiian~vor<nstar, tsaaami, raa ~, ~lvi . rage i oI 1 Regg, James B (DOA) ~ ~j? j~~ 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. NS32 (PTD #2031580): MIT-IA witnessed by Thor Cutler. 61-01 (PTD #1971570): MIT-IA witnessed by Thor Cutler and Talib Syed. GNI-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. GN(-04 (PTQ #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 10/17/2008 s ~ 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: BP Exploration (Alaska), Inc. `~ FIELD /UNIT /PAD: Prudhoe Bay /PBU /GNI c ((Jl Z ((~C ~ DATE: 10/07/08 ' 1~~~ OPERATOR REP: Andrea Hughes AOGCC REP: Packer Depth Pretest Initial 15 Min. 30 Min. Well GNI-02A T e In'. N TVD 4537 Tubing 350 350 350 350 Interval O P.T.D. 2061190 T pe test P Test psi 1500 Casing 10 1530 1490 1480 P/F P Notes: MIT-IA to satisfy pending Class 1 permit. OA 0 0 0 0 Witnessed by Thor Cutler and Talib S ed. Well GNI-03 Type Inj. D TVD 4022 Tubing 1250 1250 1250 1250 Interval O P.T.D. 1971890 Type test P Test si 1500 Casing 650 1550 1530 1530 P/F P Notes: MIT-IA to satisfy pending Class 1 permit. OA 400 420 420 420 Witnessed b Thor Cutler and Talib Syed. Well GNI-04 Type Inj. N TVD 4,461' Tubing 450 450 450 450 Interval O P.T.D. 2071170 Type test P Test psi 2000 Casing 130 2000 1950 1940 P/F P Notes: MIT-IA to satisfy pending Class 1 permit. OA 350 620 620 620 Witnessed b Thor Cutler and Talib S ed. Well T pe Inj. TVD Tubing Interval P.T.D. T pe test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test si 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 PBU GNI-02A, 03, 04 10-07-08.x15 05/30/08 Alaska Data & Consulting Services 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth WPII _Inh fF NO.4727 Company: State of Alaska Alaska Oil & Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Suite 100 Anchorage, AK 99501 ~ .... n..~....:..~:.... Z-03 11975773 SFRT 1- (~ 05/20/08 1~ 1 P2-32 12066522 MEM TEM SURVEY - 05/19/08 1 1 18-13B 12021159 MEM PROD PROFILE '~- ~ ~ 05/18/08 1 1 Z-03 11975773 USIT 1 L(~ 05/19/08 1 1 W-29 11999017 INJECTION PROFILE d( 05l26I06 1 1 15-39A 11999018 PRODUCTION PROFILE 6(p - c, 05/28/08 1 1 07-30A 11963095 SCMT ~ 05/27/08 1 1 14-096 11982432 PROD PROFILE W/FSI - ~, v 05/27/08 1 1 A-34A 12057614 USIT -/O ' /(pL/(~ 05/26/08 1 1 GNI-04 11824353 OH LDWG EDIT (DSI) V-t _ 1 ~, 11/07/07 1 1 o~ cnce nnv~~nun nn.+r nr ..r~.,-r .~ ------------_'-..---.. -..............-...... ...-.......n.v vn~vvr~ ~nvn ~v. BP Exploration (Alaska) tnc. Petrotechnical Data Center LR2-1 900 E. Benson Blvd. - Anchorage, Alaska 99508 Date Delivered: ~ ~-~'' ~'~it Alaska Data & Consulting Services 2525 Gambell Street, Suite 40 Anchorage, AK 99503-2 38 ATTN: Beth Received by: 05/13/08 ~ir~111111~ri1 fr~ Alaska Data & Consulting Services 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth wAu ~..ti ,+ NO. 4702 Company: State of Alaska Alaska Oil & Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Suite 1t10 Anchorage, AK 99501 MPS-11 12017492 - CEMENT & CORROSION LOG 7h~-( ~~ / 04/22/08 vvwi 1 vv 1 1-21lK-25 12061694 • PRODUCTION LOG `~~ .r~~ ~ ,~~L 04/18/08 1 1 GNI-04 12057606 ~ STEP RATE INJECTIVfi t I t~ i U'LG / 33Cf 04/23/08 1 1 L-220 11975763 USIT 04/22/08 1 i MPS-31 11962598 USIT C 05/03/08 1 1 X-17 12034894 USIT - / • /(p 3 ~- 05/03/08 1 1 04-47 11978458 MEM LDL d`jy-(5 3 05/01/08 1 1 Y-07A 11966254 TEMP & PRESS LOG aU'~-- ~ 05/02/08 1 1 L5-36 11975768 PRODUCTION PROFILE W/FSI / 04/28/08 1 1 Z-112 40016350 OH MWD/LWD EDIT "~-- 02/15/08 2 1 Z-112 PB 40016350 OH MWD/LWD EDIT p'~- ~~ 02/11/08 2 1 Y-07A 11962781 CH EDIT PDC GR fSCMTI ',~^~'~ /[~~ ~(a~p~-( 02/03/08 1 L2-16 11975760 RST ~ (~j=" --_~c~-'} i~ ~s~.~ 03/31/08 1 1 L2-33 11998999 RST ~ - 04/01/08 1 1 Li-14 11999000 RST ~ ~ 04/02/08 1 1 D-26B 40016518 OH MWD/LWD EDIT - b 02/21/08 1 1 o~ cecc nrrrnin~nn cnn~ oc no~nr o.. c.~..., ~.,.. ,. BP Exploration (Alaska) Inc. - ^ ^ -- - V...-~.'M v,•~ vvr ~ ~~v~ ~ ~ v. Petrotechnical Data Center LR2-1 900 E. Benson Blvd. - Anchorage, Alaska 99508 Date Delivered Alaska Data & Consulting Services 2525 Gambell Street, Suite 40 ;" Anchorage, AK 99503-2838 ;' ATTN: Beth ~ i \~~ Received by: ~t0 05/08/08 ~chlumber~r Alaska Data & Consulting Services 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth Wall _Inh et NO. 4690 Company: State of Alaska Alaska Oil & Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Suite 100 Anchorage, AK 99501 ~ n.- P1-18A 12014006 PRODUCTION PROFILE _ p 04/05(08 1 yV,vr 1 GNI-04 12057606 RSTIWFL ~ ~-_ I ( 04!24/08 1 1 MPL-15 12021153 MEM INJECTION PROFILE ~tJ ~~'--la~-O~® 1~t ~ `~ 04/19/08 1 1 03-09 11999005 . . e ~- PRODUCTION PROFILE W/FSI ~' 04/29/08 1 1 6-22A 11970825 USIT - ~ ~ 04/27/08 1 1 W-45 11978456 MEM TEMP & PRESS SURVEY V~_ ( G(oac.(( 04/28/08 1 1 X-06 12071852 INJECTION PROFILE ~ L 04/30/08 1 1 L5-32 11975767 PRODUCTION PROFILE W/FSI ' `~f ~- 04/27/08 1 1 ai Gesc er•rrninwi cnr_c ov roior ov ~~~...~ ~.~.. . BP Exploration (Alaska) Inc. Petrotechnical Data Center LR2-1 ~ ~ ~ ~ _ 900 E. Benson Blvd. - Anchorage, Alaska 99508 Date Delivered: ~ ti) ~;'(1(~}y Alaska Data & Consulting S rvices 2525 Gambell Street, Sui 4 Anchorage, AK 99503- 8 ATTN: Beth Received by: MAY-08-2008 THU 11 51 AM • FAM~ ~ ,~ - ~ ~ P, 01 7 ~A~ UNITED STAIRS ENVtRaNMENTAt. PRpTEC71aN AGENGY ~ i2b0 Sixth Ave~Ne, Suite 9bb ~ Seattle, w2~shiogtan 981 ay y914o a~ ~~.~~ 8 MAY `1(18 Reply Ta: OCE-127 C1l;RTIFIIlJD MAIL R.I£TIJIitN RECRIPT gE~UF,STED Neil Dunn HP Exploration (Alaska) Inc. 900 East Benson Blvd, Post Office Box 196612 Anchorage, Alaska 99S 19-6612 Re: Underground Injection Control Program Class I Grind and Inject Permit AK-~1I00$-A Approval to Commence Class I Injection Activities at Well GNI-04 Greater Prudhoe Bay, North Slope, Alaska. Dear Mr. Dunn: The U.S. Environmental Protection Agency (EPA) Region 10 has received and reviewed the Class I Weil Completion Report Grinii'and Inject Project Permit IYurnber AK-1I008-A submitted by BP Exploration (Alaska) Inc• Based on the review of the completion report received May S, 2008, BI'A authorizes BP Exploration (Alaska} Inc., to commence Class I injection activities at the Crrind and Inject Project and specifirsally GNI-04 well to process and inject Class I materials. Your conrinued Efforts to coordinate the scheduling of tests ors appreciated. if you have any questions or need further information, please call Thor Cutler at (206) 5~3-1673. cc: aim Regg, AOGrCC, Anchorage Susan McNeil, ADEC, Anchorage Sincerely, 1V(ichael A. Hassell, Director gffice of Compliance and Enforcement ~FikuWO~IAMGYCIMP~ Saltmarsh, Arthur C (DOA) From: Hubble, Terrie L [Terrie.Hubble@bp.com] Sent: Monday, April 07, 2008 3:42 PM To: Saltmarsh, Arthur C (DOA) Cc: Bill, Michael L (Natchiq) Subject: PBU GNI-04 / PTD #207-117 H i Art, Please reference the following well: Well Name: PBU GNI-04 Permit #: 207-117 API #: 50-029-23367-00-00 Top Perf MD: 7175' Battom Perf MD: 7195' This well began (Test) Injection on: March 18, 2008 Method of Operations is: Sea Water and Produced Water Injection No other test data is available. Page 1 of 1 4/15/2008 GNI-04 (PTD #2071170) MIT Fo~ ~ Page 1 of 1 Regg, James B (DOA) From: NSU, ADW Well Integrity Engineer [NSUADWWeIIlntegrityEngineer@BP.comj ~ 31~I~ Sent: Wednesday, March 26, 2008 12:31 PM ~~ To: Regg, James B (DOA); Maunder, Thomas E (DOA); Fleckenstein, Robert J (DOA) Cc: Bill, Michael L (Natchiq); NSU, ADW Well Integrity Engineer; NSU, ADW WI Tech; Holt, Ryan P (ASRC) ~ Subject: GNI-04 (PTD #2071170) MIT Form Attachments: MIT PBU GNI-04 03-22-08.x1s Jim, Tom and Bob, Please see the attached MIT form for GNI-04. The MITIA was the initial test for the well and was witnessed by EPA representative Thor Cutler. «MIT PBU GNI-04 03-22-08.x1s» Please call with any questions or concerns. Thank you, Andrea Hughes Well Integrity Coordinator Office: (907) 659-5102 Pager: (907) 659-5100 x1154 3/26/2008 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: EPA REP: BP Exploration (Alaska), Inc. ~ ~J Z.6 ~~ Prudhoe Bay /PBU /GNI Pad ~~~ 03/22/08 Anna Dube Thor Cutler Packer Depth Pretest Initial 15 Min. 30 Min. Well GNI-04 Type Inj. W TVD 4,461' Tubing 1360 1380 1380 1380 Interval I P.T.D. 2071170 Type test P Test psi 2000 Casing 880 000 1960 1950 P/F P Notes: MIT-IA for EPA / AOGCC compliance post initial OA 840 1000 960 940 injection. 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 9/1/05 MIT PBU GNI-04 03-22-OS.xls oz/2a/os ~iC~l~~ltllb~~'t~r'' NO. 4612 Alaska Data & Consulting Services Company: State of Alaska 2525 Gambell Street, Suite 400 Alaska Oil & Gas Cons Comm Anchorage, AK 99503-2838 Attn: Christine Mdhnken ATTN: Beth 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: P.Bay,Aurora,GNI,Pt.Mac,Milne Pt,Endicott Well Jnh i! ~ .,,. nea~r~tir~.,., n~re Qi r..i,.- rn 15-25A 12014000 LDL / ..~Co !- 02/20108 1 1 A-12A 11963077 MCNL :r 3 01/19/08 1 1 GNI-04 12031448 TEMP SURVEY (REVISED) ~(j~- ~ (0 01/22108 1 1 P2-32 11968730 USIT - ~ 02/13/08 1 1 17-02 11996384 USIT /~Q - ~' 02/17108 1 1 Y-07A 11962781 SCMT "}- j Q ~ 02103/08 1 1 P2-58 12031456 USIT 1~jQ - ~/ 02/25/08 1 1 MPH-12 12005205 MEM INJ PROFILE ~ _ j~-p It '3 02/15/08 1 1 4-14/R-34 11975755 USIT (J~e ~'- 02/25/08 1 1 S-126 11968731 JEWELRYIPERFISBHP ~ ~ 02/15/08 1 1 PLCHJC ANnrYVVYLCVbC RCI~CIr'1 6T Jlbrylryl7 HNU Kt1UKrylryl7 Vryt I.UYT tAGFi IU: BP Exploration (Alaska) Inc. Petrotechnical Data Center LR2-1 .-- - 900 E. Benson Blvd. Anchorage, Alaska 99508 Date Delivered: v, y A ~;~ c I~ ! , ~ {"~,~ Alaska Data & Consulting Services 2525 Gambell Street, Suite 400 Anchorage, AK 99503-283 ATTN: Beth Received by: Iy J STATE OF ALASKA ,s ~~ ~~~~~~ ALAS~OIL AND GAS CONSERVATION COMMISSION 1 ~~ WELL COMPLETION OR RECOMPLETION REPORT AND LOG - ~ 200$ (~'f~!'& C~ss II Disposal Well Alaelca x .,.,H r.. 1 a. Well Status: ^ Oil ^ Gas ^ Plugged ^ Abandoned ^ Suspended zoAAC zs.los zoAAC zs.1,o ^ GINJ ^ WINJ ®WDSPL ^ WAG ^ Other No. of Completions One 1 b. Well CI ~~;;~~~~--~~~ ` ^ Dev~I~IPn'ie'~if}`~~`] Exploratory ®Service ^ Stratigraphic 2. Operator Name: BP Exploration (Alaska) Inc. 5. Date Comp., Susp., or Aba • ~ 1/31/2008 ~ 12. Permit to Drill Number 207-117 ~ 307-362 3. Address: P.O. Box 196612, Anchorage, Alaska 99519-6612 6. Date Spudded ~ 10/29/2007- 13. API Number 50-029-23367-00-00 ~ 4a. Location of Well (Governmental Section): Surface: 4 ' ' 7. Date T.D. Reached 11/7/2007 14. Well Name and Number: PBU GNI-04 ~ 191 FSL, 1011 FEL, SEC. 26, T11 N, R15E, UM Top of Productive Horizon: 195' FSL, 3540' FEL, SEC. 23, T11N, R15E, UM 8. KB (ft above MSL): 47.6' Ground (ft MSL): 19.1' 15. Field /Pool(s): Prudhoe Bay Field /~~udhoe-Ba Total Depth: 270' FSL, 3675' FEL, SEC. 23, T11 N, R15E, UM 9. Plug Back Depth (MD+TVD) 7360 6667 ..Pe~ei- ~~~ ~ ~~~ 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 716973 y- 5956183 Zone- ASP4 10. Total Depth (MD+ND) 7463 , 6757 16. Property Designation: ADL 028323 TPI: x- 714407 y_ 5957394 Zone- ASP4 Total Depth: x- 714270 y- 5957465 Zone- ASP4 11. SSSV Depth (MD+TVD) None 17. Land Use Permit: 18. Directional Survey ®Yes ^ No Submit electronic and rimed information er 20 AAC 25.050 19. Water depth, if offshore N/A ft MSL 20. Thickness of Permafrost (TVD): 1900' (Approx.) ~1. Logs Obtained (List all logs here and submit electronic and printed information per 20 AAC 25.071): DIR / GR, GR /CCL /CBL /USIT, GR RES /DEN / NEU /Dipole Sonic, GR /CCL /CBL /USIT 22. CASING, LINER AND CEMENTING RECORD CASING SETTING DEPTH MD SETTING D EPTH TVD HOLE AMOUNT Wf. PER FT. GRADE TOP BOTTOM ` TOP BOTTOM SIZE CEMENTING RECORD PULLED 20" 91.5# H-40 Surface 108' Surface 108' 42" 260 sx Arctic Set A rox. 13-3/8" 68# L-80 30' 4230' 30' 3884' 16" 1111 sx DeepCrete Lite, 571 sx'G', 830 sx DeepCrete 9-5/8" 47# L-80 27' 7452' 27' 6747' 12-1 /4" 1248 sx Class 'G' 23. Open to production or inject ion? ®Yes ^ No 24. TuawG RECORD If Yes, list each i (MD+ND of Top & Bottom; Pe nterval open rforation Size and Number): SIZE DEPTH SET MD PACKER .SET MD 4-1/2" Gun Diameter, 5 spf 7", 29#, L-80 4999' 4873' MD TVD MD TVD 7175' - 7195' 6504' - 6522' 25. Aclo, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL MD AMOUNT $c KIND OF MATERIAL USED Freeze Protect w/ 126 Bbls of Diesel 26. PRODUCTION TEST Date First Production: Not on Injection Yet Method of Operation (Flowing, Gas Lift, etc.): N/A Date Of Test: HOUfS Tested: PRODUCTION FOR TEST PERIOD OIL-BBL: GAS-MCF: WATER-BBL: CHOKE SIZE: GAS-OIL RATIO: Flow Tubing PreSS. CaSing PfeSS: CALCULATED 24-HOUR RATE OIL-BBL: GAS-MCF: WATER-BBL: OIL GRAVITY-API (CORK): 27. CORE DATA Conventional Core(s) Acquired? ^Yes ®No Sidewal l Cores Ac uired? ^Yes ®No If Yes to either question, list formations and intervals cored (MD+ND of top and bottom of each), and summarize lithology and presence of oil, gas or water (submit separate sheets with this form, if needed). Submit detailed descriptions, core chips, photographs and laboratory analytical results per 20 AAC 250.071. '=6e None ~ O f I t r Form 10-407 Revised 02/2007 L~ °~~ ~ ~~>~T~D Orr-t~E Rs~'S~e~, v~ G 28. GEOLOGIC MARKERS (LIST ALL FORMATIONS RKERS ENCOUNTERED): 29. FORMATION TESTS NAME MD TVD Well Tested? ^ Yes ®No Permafrost Top If yes, list intervals and formations tested, briefly summarizing test results. Attach separate sheets to this form, if needed, and submit Permafrost Base 1965' 1904' detailed test information per 20 AAC 25.071. SV6 2790' 2631' None EOCU / SV5 3562' 3293' SV4 3743' 3453' SV3 4263' 3913' SV2 4475' 4103' SV1 4938' 4519' Ugnu 4 5472' 4997 Ugnu 4A 5500' 5022' Ugnu 3 5869' 5348' Ugnu 1 6574' 5973' Ma 6926' 6285' Mb1 6953' 6309' Mc 7140' 6473' WS2 7197' 6524' Na 7273' 6590' Nb 7295' 6610' Ne 7353' 6660' OA 7460' 6754' Formation at Total Depth (Name): OA 7460' 6754' 30. list of Attachments: Summary of Daily Drilling Reports, Well Schematic Diagram, Surveys 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. ~Z~2? Si d gne Terrie Hubbl Title Drilling Technologist Date 1 PBU GNI-04 207-117 307-362 Prepared By Name/Number. Terrie Hubble, 564-4628 Well Number Permit No. / A rOVal NO. Drilling Engineer: Mike Bill, 564-4692 INSTRUCTIONS GeNew-~: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. 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 and Ground Level elevation in feet above mean sea level. 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: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. 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). IreM 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-In, or Other (explain). IreM 27: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. IreM 29: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 02/2007 Submit Original Only BP EXPLORATION Page 1 of 1 Leak-Off Test Summary Legal Name: GNI-04 Common Name: GNI-04 Test Date Test Type Test Depth (TMD) Test Depth (TVD) AMW Surface Pressure Leak Off Pressure' (BHP) EMW Printed: 11/29/2007 8:49:41 AM ~ ~ BP EXPLORATION Page 1 of 12 Operations Summary Report Legal Well Name: GNI-04 Common Well Name: GNI-04 Spud Date: 10/29/2007 Event Name: DRILL+COMPLETE Start: 10/24/2007 End: 11/13/2007 Contractor Name: NABORS ALASKA DRILLING I Rig Release: 11 /13/2007 Rig Name: NABORS 7ES Rig Number: Date From - To Hours Task Code. NPT Phase: Description of Operations 10/26/2007 18:00 - 00:00 6.00 MOB P PRE RD. Prepare for rig move. Move pits, camp and truck shop to 10/27/2007 100:00 - 10:00 I 10.00 I MOB I P 10:00 - 22:30 I 12.50 MOB P 22:30 - 00:00 1.50 RIGU P 10/28/2007 00:00 - 02:30 2.50) RIGU P 02:30 - 06:00 3.50 RIGU P 06:00 - 08:00 I 2.001 RIGU I P 08:00 - 14:30 6.50 RIGU P 14:30 - 16:00 1.50 RIGU P 16:00 - 20:45 4.75 RIGU P 20:45 - 22:15 1.50 RIGU P 22:15 - 00:00 .1.75 RIGU P 10/29/2007 00:00 - 01:00 1.00 RIGU P 01:00 - 02:00 1.00 RIGU P 02:00 - 05:00 3.00 DRILL P 05:00 - 05:30 05:30 - 06:30 06:30 - 18:30 18:30 - 20:30 20:30 - 00:00 110/30/2007 J 00:00 - 05:30 i 5.501 DRILL I P 0.50 DRILL P 1.00 DRILL P 12.00 DRILL P GNI-04. PRE Moving pits, Iliamna Camp, truck shop f/G-19 to GNI-04. Move sub off G-19. RD, LD derrick. PRE Move sub from G-19 to GNI-04. PRE Hang riser in cellar. Hang diverter on bridge cranes in cellar. Move sub over GNI-04. Prep diverter. PRE NU diverter. Prepare cellar. PRE Raise derrick. Prep floor f/drilling. Bridle down. RU top drive. Spot pits to sub. Tie in pits to sub. Mobilize roads and pads machinery to cut back berm to make room for diverter line. PRE Bring on spud mud. Roads and pads removed gravel berms and levelled pad. ND diverter. Redirect diverter line to mud pits side of rig to avoid interference w/well house. Accept rig at 07:00. PRE Pre spud meeting w/night tour crew. NU diverter and lines. Install riser. PRE Load pipeshed w/5" drill pipe. Strap pipe. PRE PU 114 jts drill pipe and stand back in derrick. PRE PU 23 jts of 5" HWDP and stand back in derrick. Clean out cuttings tank (prior to spud) of residues from G-19B w/supersucker and manifest as class II waste per Brian Colver. PRE PU drilling BHA #1 w/16" Reed TC11 C bit and 1.83 deg motor assy. Function test diverter and knife valve. Witnessed by Lowell Anderson BP WSL and Lenward Toussant NAD TP. AOGCC representative Bob Noble waived AOGCC presence at test. Hold prespud meeting w/day tour crew. PRE Continue PU partial BHA #1. PRE Clean cement out of cutting tank. SURF Fill stack and conductor w/water. Cleanout to 108'. Swap over to spud mud. Drill out cement and overboard cement contaminated mud. Drill down w/2 stands 5" HWDP to 263'. 465 gpm, 610 psi, 2.1K tq. SURF CBU x 3 540 gpm, 650 psi. SURF POH w/2 stands HWDP and PU rest of BHA # 1. SURF Drill directionally/slide f/263' to 1190'. 35K WOB, 600 gpm, 1530 psi on, 1370 psi off, 6K tq on, 2K tq off, 80K PU, 75K SO, 75K ROT, 50 rpm. 2.00 DRILL N FLUD SURF Viscosity too high to pump. SD and clean pump screens, lines and condition mud in pits. 3.50 DRILL P SURF Drill directionally/slide f/1190' to 1315'. WOB 35K, 607 gpm, 1538 psi on, 1309 psi off, 7K tq on, 3K tq off, 90 K PU, 75K SO, 80K ROT, 50 rpm. 06:00 - 07:30 10.501 DRILL P 07:30 - 08:30 I 1.001 DRILL I P ADT=10.22 hrs, ART=6.27 hrs, AST=3.95 hrs. Progress f/24 hrs = 1207'. SURF Drill directionally/slide f/1315' to 1662'. WOB 35K, 506 gpm, 1250 psi on, 1150 psi off, 7K tq on, 4K tq off, 100 K PU, 95K SO. Can't build angle as required. SURF CBU. 597 gpm, 1440 psi prior to POH for BHA check. SURF Pull out of hole from 1,662' to 904' Tight spot @ 1,000', wipe twice. POH to BHA at 903'. SURF Rack back drill collars and lay down stabilizers. Inspect bit. Printed: 11/29/2007 8:49:51 AM ~ ~ BP EXPLORATION Page 2 of 12 Operations Summary Report Legal Well Name: GNI-04 Common Well Name: GNI-04 Spud Date: 10/29/2007 Event Name: DRILL+COMPLETE Start: 10/24/2007 End: 11/13/2007 Contractor Name: NABORS ALASKA DRILLING I Rig Release: 11/13/2007 Rig Name: NABORS 7ES Rig Number: Date. From - To Hours Task Code NPT Phase. Description of Operations 10/30/2007 07:30 - 08:30 1.00 DRILL P SURF Graded 7/7. Damage to all teeth. 08:30 - 09:30 1.00 DRILL P SURF PU BHA #2 w/Hughes 16" MX-1 tri-cone bit w/serial #6060257 and 1.83 deg motor assembly w/new motor sleeve. PU stabilizers and collars. 09:30 - 10:30 1.00 DRILL P SURF RIH f/903' to 1362'. 10:30 - 23:30 13.00 DRILL P SURF Drill directionally/slide f/1362' to 2608'. 20K WOB, 600 gpm, 1801 psi on, 1620 psi off, 8K tq on, 5K tq off, 125K PU, 85K SO, 100K ROT, 60 rpm. Backreaming 1 jt after each stand drilled down. 23:30 - 00:00 0.50 DRILL P I SURF 10/31/2007 00:00 - 06:00 6.00 DRILL P 06:00 - 07:00 I 1.001 DRILL I N I STUC I SURF 07:00 - 08:00 I 1.001 DRILL I P 08:00 - 15:45 I 7.751 DRILL I P 15:45 - 17:00 I 1.251 DRILL I P 17:00 - 19:00 I 2.001 DRILL I P 19:00 - 00:00 1 5.001 DRILL I P 11/1/2007 00:00 - 01:30 1.50 DRILL I P 01:30 - 03:00 1.50 DRILL P 03:00 - 03:30 I 0.501 DRILL I P 03:30 - 04:15 0.75 DRILL P 04:15 - 06:30 2.25 DRILL P SURF SURF SURF SURF SURF SURF SURF SURF SURF SURF 06:30 - 10:30 ~ 4.00 ~ DRILL ~ P ~ I SURF 10:30 - 12:00 1.50 DRILL P SURF 12:00 - 13:00 1.00 DRILL P SURF 13:00 - 14:00 1.00 DRILL P SURF 14:00 - 14:30 0.50 DRILL P SURF ADT=12.2 f/24 hrs. AST = 8.04 hrs. ART = 4.16 hrs. Service top drive and replace Link-tilt solenoid. Service rig. Drill directionally/slide f/2608' to 3353'. 20K WOB, 600 gpm, 2250 psi on, 1995 psi off, 10K tq on, 6K tq off, 135K PU, 90K SO, 113K ROT, 60 rpm. Backreaming 1 jt after each stand drilled down. Stuck pipe off bottom a 3343' attempting to run back to bottom after backreaming. No ability to move or rotate. Circulate 450 gpm, 2100 psi. Jarred up and freed pipe. Circulate and condition mud. 750 gpm, 2600 psi. Reciprocate pipe 70'. Drill directionally/slide f/3353' to 4240' and TD surface hole section per geo. 35K WOB, 668 gpm, 2682 psi on, 2628 psi off, 9K tq on, 8K tq off, 165K PU, 105K SO, 120K ROT, 80 rpm. ADT = 9.05 hrs. AST = 2.6 hrs. ART = 6.45 hrs. Progress f/day to TD of surface hole section = 1632'. Circulate/reciprocate/rotate 4240' to 4155', 727 gpm, 2654 psi, 80 rpm, 9K tq. pumping total 1141 bbls. POH f/4240' to 2880' work through tight spots from 4137' to 3840'. Continue POH to 2880'. Back ream (/2893' to 1465'. 613 gpm, 1328 psi, 50 rpm, 4K tq. Tight 2760', 2325', 1933'. RIH f/1465' to 2690'. Tag up on obstruction. Attempt to work past obstruction at 2690' w/out topdrive, no progress. Then ream, 200 gpm, 40 rpm and backream w/600 gpm, 80 rpm. get through obstruction. Work f/2690' to 3180' reaming and backreaming as indicated. Ream, 200 gpm, 40 rpm and backream w/600 gpm, 80 rpm. to work through obstructions. RIH f/3180' to 4240' w/no obstructions. Wash last stand to bottom. CBU x 1.5. 720 gpm, 2336, 100 rpm, 9.4K tq, reciprocate pipe. POH f/4240' to tight hole at 3850'. Back ream f/3850' to 2040'. 650 gpm, 1840 psi, 50 rpm, 10K tq. POH f/2040' to tight hole at 700'. Work tight hole f/700' to 355'. Continue to POH to 214'. POH w/BHA and check bit. Some worn teeth, in gauge. Adjust motor bend f/1.83 deg to 1.15 deg, orient MWD. RIH to 275' and. shallow test MWD, 741 gpm, 1148 psi. Printed: 11/29/2007 8:49:51 AM Common Well Name: GNI-04 Spud Date: 10/29/2007 Event Name: DRILL+COMPLETE Start: 10/24/2007 End: 11/13/2007 Contractor Name: NABORS ALASKA DRILLING I Rig Release: 11/13/2007 Rig Name: NABORS 7ES Rig Number: Date From - To Hours Task Code NPT Phase Description of Operations 11/1/2007 14:30 - 16:00 1.50 DRILL P SURF Slip/cut 125' of drilling line. 16:00 - 17:45 1.75 DRILL P SURF RIH f/275' to 3430' and tag up. SO 50K. No progress. 17:45 - 23:00 5.25 DRILL P SURF Work pipe down and ream down (/3400' to 3900'. 215 gpm, 730 BP EXPLORATION Page 3 of 12 Operations Summary Report Legal Well Name: GNI-04 23:105 - 00:00 I 0.75) DRILL P I I SURF 11/2/2007 00:00 - 01:00 1.001 DRILL I P I SURF 01:00 - 04:30 3.50 DRILL P SURF 04:30 - 05:30 1.00 DRILL P SURF 05:30 - 07:00 1.50 DRILL P SURF 07:00 - 08:00 1.00 DRILL P SURF 08:00 - 09:00 1.00 DRILL P SURF 09:00 - 12:00 3.00 DRILL P SURF 12:00 - 15:00 I 3,001 DRILL I P I I SURF 15:00 - 18:00 I 3.001 DRILL I P I I SURF 18:00 - 20:00 I 2.001 DRILL I P I I SURF 210:00 - 23:00 2.001 CASE p I SURF SURF 23:00 - 00:00 I 1.001 CASE I P I I SURF 111/3/2007 100:00 - 09:00 I 9.001 CASE I P I I SURF 09:00 - 10:30 I 1.501 CASE I P I I SURF 10:30 - 11:00 ( 0.501 CASE I P I SURF 11:00 -13:30 2.50 CASE P psi. 40 rpm, 14K tq. ream tight spots through entire section w/torque limiter stalling top drive at 15K tq. RIH f/3900' to 4240'. CBU x 2. Circulate/reciprocate/rotate 4240' to 4155', 677 gpm 2540 psi, 10K tq, 120 rpm, 165K PU, 100K SO, 75K ROT. Gravel, wood, sand across shakers. Continue w/CBU x 2. Attempt to pull off bottom and pull over 45K above string wt. Attempt to pump out of hole w/out backreaming and pull over string wt 45K. Begin backreaming out of hole f/4240' to 1915'. 600 gpm, 1715 psi, 50 rpm, 7K tq. POH f/1915' to BHA at 215'. LD drilling BHA #3. Clear and clean floor. PU cleanouUwiper BHA #4. RIH and tag up on obstruction at 3234'. Wash through obstruction f/3324' to 3320'. 140 gpm, 600 psi. Continue RIH to 3523'. Wash through tight hole at 3523' down to 3617'. 140 gpm, 600 psi. RIH to TD w/ no problems washing down last stand. 3' of fill on bottom. Circulate/condition mud. Stage pumps up to 700 gpm, 2495 psi and CBU x 2. Pea gravel on shakers as on previous circulations cleaning up towards end. Monitor well. 1 bph losses. Pull off bottom w/90K overpull to 250K. MW = 9.5 ppg. Pull to 4066' and work tight spot. PU 165K. 3981' 165K-195K PU. 3887' 155K Pu. Seeing lots of clay on tool jts at surface. 3124' 135K. 2842' 125K. 2747' 120K. 2200' 110K. Continue pulling to 855' no problems. TOH followed 3.5 friction factor on torque and drag plot. Monitor well 1 bph static loss. PJSM w/all hands. Rack back HWDP, drill collars. LD wiper trip BHA #4. Clean and clear floor. RU to run 13-3/8", 68#, L-80, BTC casing. Make dummy run w/FMC hanger. C/O bails. RU Franks tool. RU casing running equipment. MU and BakerLok shoe track. Pump through floats w/Franks tool, check for backflow w/3rd joint. OK. MU average 9000 fUlbs. to 123'. Continue to RIH w/13-3/8", 68#, L-80, BTC casing f/123'. RIH to obstruction at 3281'. Wash down/work pipe w/gentle finesse 3bpm, 285 psi f/3281' to 3512'. Continue to RiH w/no problem to 4198'. MU hanger/landing jt. Tag up on obstruction at 4219'. Wash down f/4219' to 4230'. 3 bpm, 300 psi. Land casing on landing ring. Stage up rates: 3 bpm 430 psi, 4 bpm 515 psi, 5 bpm 588 psi while reciprocating casing. RD/LD Franks Fillup Tool. MU cementing head and lines. Circulate and condition mud and stage rates up to 8 bpm, 570 psi. Continue to reciprocate casing, but difficult getting hanger Printed: 11/29/2007 8:49:51 AM BP EXPLORATION. Page 4 of 12 Operations Summary Report Legal Well Name: GNI-04 Common Well Name: GNI-04 Spud Date: 10/29/2007 Event Name: DRILL+COMPLETE Start: 10/24/2007 End: 11/13/2007 Contractor Name: NABORS ALASKA DRILLING I Rig Release: 11/13/2007 Rig Name: NABORS 7ES Rig Number: Date From - To Hours Task Code NPT Phase Description of Operations 11/3/2007 11:00 - 13:30 2.50 CASE P SURF landed and packoff. Pulled max. 450K w/no breakover on weight indicator. Land hanger and cease reciprocating. PJSM w/Schlumberger, all hands, mud man, NAD toolpusher and BP WSL. Circulated a total of 1437 bbls. during hole conditioning. 13:30 - 20:00 6.50 CEMT P SURF Pump 5 bbls. H2O and pressure test lines to 3500 psi. Mix and pump 100 bbls of 10.00 ppg mud push. At 12:53 shut down and drop bottom plug, see plug indicator trip. At 12:53 begin mixing and pumping 758 bbls. of 10.75 ppg DeepCrete lead slurry 1 ppb cemnet and additives. At 15:47. 7.0 bpm, 365 psi, lead slurry 20 bbls around shoe and lost returns. At 15:50 returns back. Returns fluctuating. At 16:05 begin mixing and at 16:14 pumping 15.8 ppg class G tail slurry w/1 ppb Cemnet and additives. Lost returns after switching to tail cement. At 16:45 stop pumping tail slurry. Shut down and drop top plug. Plug indicator tripped. At 16:55 switch to rig pumps and begin displacement w/9.5 ppg mud. 4.0 bpm, 1656 psi. Returns fluctuating from 4 bbls/min to 0. At 19:30 bump plugs on stroke count schedule. FCP = 2350 psi. Increase 500 psi over circulating pressure to 2850 psi and hold f/1 min. No indication of cement or mud push to surface. Bleed back and check floats. OK. Job witnessed by EPA observer Talib Syed. CIP @ 19:30 hrs 20:00 - 21:00 1.00 CEMT P SURF RD cement head and casing running equipment, change out bails. 21:00 - 22:30 1.50 CEMT P SURF Remove top portion of split landing jt. and install TAM landing plate on top end of landing jt. MU TAM Port Collar Combo operating tool. RIH to TAM Port Collar at 1018' and locate collar. PU 45K, SO 45K. Test tool to 500 psi. OK. Rotate 1/4 turn to left and open TAM Port Collar. 22:30 - 00:00 1.50 CASE P SURF Circulate and stage pumps up to 8 bpm, 150 psi. No pack off occuring. Retums good. Circulate at 4 bpm. Consult w/town team and mobilize increased quantity of cement from Schlumberger Deadhorse plant for top job. 11/4/2007 00:00 - 02:30 2.50 CEMT P SURF Continue to circulate through TAM Port Collar and wait for cement to arrive for top job. Schlumberger changeout on pump truck personnel maxed out on hours. 02:30 - 04:30 2.00 CEMT P SURF NOTE: This section is 1 hr short due to daylight savings time change at 02:00. PJSM w/Schlumberger, all hands, mudman, TP, WSL. Pump 5 bbls H2O w/Schlumberger to floor and pressure test to 3500 psi. OK. Mix and pump (every sack on location) 586 bbls of 10.7 ppg Crete cement + additives average rate of 4.6 bbls/min 250 psi. Returns excellent until 450 bbls pumped and mudpush f/earlier job (ph 12.5) brought large amounts of wall cake and plugged stack and flowline. Switch returns from flowline to 4" valves below 13-3/8" casing hanger. Remove returns f/cellar w/supersucker. Returns began to thin out, red dye seen in small amounts. Switched from cellar to flow line w/570 bbls of cement pumped. 18 bbls. good cement to surface. Weight = 10.8 ppg. Witnessed by EPA representative Talib Syed. 568 total bbls cement pumped. Pump 5 bbls H2O displacement w/Schlumberger. Shut down. Switch to rig pumps and displace 13 bbls of mud 3.5 bbls/min, Printed: 11/29/2007 8:49:51 AM ~ ~ BP EXPLORATION Page 5 of 12 Operatiolns Slumllnary Report Legal Well Name: GNI-04 Common Well Name: GNI-04 Spud Date: 10/29/2007 Event Name: DRILL+COMPLETE Start: 10/24/2007 End: 11/13/2007 Contractor Name: NABORS ALASKA DRILLING I Rig Release: 11/13/2007 Rig Name: NABORS 7ES Rig Number: Date From - To Hours Task Code NPT Phase Description of Operations 11/4/2007 02:30 - 04:30 2.00 CEMT P SURF 276 psi. Shut down. Rotate TAM port collar 1/4 turn to right to close. Pressure test across ports to 500 psi. OK, ports closed. PU to place Combo tool cups in blank pipe and blow out ball seat. Circulate hole clean w/9.5 ppg mud fITAM port collar to surface. 230 gpm, 309 psi. EPA representative Thor Cutler and AOGCC representative Jeff Jones notified that 10.8 ppg cement returned to surface. 04:30 - 05:00 I 0.501 CASE ( P 05:00 - 06:00 1.00 CEMT P 06:00 - 07:00 1.00 CEMT P 07:00 - 08:00 I 1.001 CASE I P 08:00 - 09:30 1.50 BOPSU P 09:30 - 10:30 I 1.001 WHSUR I P 10:30 - 14:30 4.00 BOPSU~P 14:30 - 19:00 4.50 BOPSU P 19:00 - 19:30 0.50 BOPSUF~P 19:30 - 20:30 1.00 EVAL I P 20:30 - 21:30 1.00 EVAL I N 21:30 - 22:30 1.00 EVAL P 23:30 - 00:00 I 0.501 CASE I C 111 /5/2007 100:00 - 03:00 I 3.00 i CASE I C 03:00 - 03:30 I 0.501 CASE I C SURF Inspect and clean cement out of surface stack. SURF LD side entry sub and TIW valve. POH f. 1019'. SURF LD TAM Combo tool. Packed w/cement. Flush w/H2O. Clean and clear rig floor. SURF LD split landing jt. SURF ND diverter lines clean annular preventer and knife valve. Pull surface riser. ND surface stack. SURF NU and test FMC big bore well head. Test to 1000 psi f/10 mins. SURF NU BOPS. RU test equipment. SURF Test BOP with 5" test joint, low 250 psi, high 3,500 psi State of Alaska's right to witness was waived by Jeff Jones, Test witnessed by BP WSLs Mike Dinger and Lowell Anderson and NAD Toolpushers Chris Weaver and Biff Perry. Test #1 5" Test Joint Top Rams, Choke valves 1, 2, 3, & 16, HCR Kill, Dart Valve, Lower IBOP Test #2 5" Test Joint Bottom Rams, Choke Valves 4, 5, 6, Manual Kill, and Manual IBOP Test #3 Choke Valves 7, 8, 9, and TIW Test #4 Super Choke, Manual Choke B Test #5 Choke Valves 10, 11, & 15 Test #6 Choke Valve 14 Test #8 Manual Choke Test #9 Annular Test #10 Blind Rams, Choke Valves 12 & 13 Test #11 5" Test Joint Top Pipe Rams Test #12 5" Test Joint Top Pipe Rams Koomey Test Bleed down from 3,000 psi to 1,500 psi Pressure up 200 psi - 17 sec Pressure up to 3,000 psi - 1 min 58 sec Average 5 bottles nitrogen 1,800 psi SURF RD test equipment. BD lines. Install wear bushing, SURF PJSM w/Schlumberger and crew. RU sheaves and USIT wireline equipment. EPA representative Talib Syed on location for USIT run. SURF Schlumberger E-Line. Surface test failure. Check and repair. SURF RIH w/USIT/CBL logging equipment and tag up on obstruction at 1000' just above area cemented wITAM port collar at 1018'. POH and rig down logging tools. PU cleanout BHA # 5 w/used 12-1/4" Hughes MXC-1 ser # 5069874, bit sub, drill collars, jars, HWDP and RIH to 817'. PU 5" drill pipe 1 x 1 and RIH to4060'. No obstructions noted RIH. Service rig, service topdrive. SURF SURF SURF SURF SFAL Printed: 11/29/2007 8:49:51 AM `BP EXPLORATION Page 6 of 12 '' Operations Summary Report. Legal Well Name: GNI-04 Common Well Name: GNI-04 Spud Date: 10/29/2007 Event Name: DRILL+COMPLETE Start: 10/24/2007 End: 11/13/2007 Contractor Name: NABORS ALASKA DRILLING I Rig Release: 11/13/2007 Rig Name: NABORS 7ES Rig Number: Date From - To Hours Task Code NPT Phase Description of Operations 11/5/2007 03:30 - 05:30 2.00 CASE C SURF Wash down f/4060' to cement at 4133'. Drill out cement to top of plug at 4146'. CBU. 400 gpm 460 psi. 80 rpm, 8K tq. Pump dry job. Remove blower hose. 05:30 - 07:00 1.50 CASE C SURF POH to cleanout BHA #5 at 129'. 07:00 - 07:30 0.50 CASE C SURF LD BHA # 5. 07:30 - 09:00 1.50 EVAL C SURF PJSM w/Schlumberger and crew. RU Eline unit and equipment. PU USIT-D/CBL/GPIT/CCL/GR tools. 09:00 - 10:00 1.00 EVAL C SURF RIH w/eline to 4110'. 10:00 - 12:00 2.00 EVAL C SURF Log f/4110' to surface. USIT/CBL logging witnessed by EPA representative Talid Syed. 12:00 - 13:30 1.50 EVAL C SURF RD eline and equipment. 13:30 - 15:30 2.00 DRILL C PROD1 PJSM w/Schlumberger and all hands on nuke safety. PU BHA #6 w/12.25" Hycalog DTX719M ser# 4340047 PDC bit and 1.50 deg. motor assy. Load source and continue to PU BHA to 249'. 15:30 - 18:00 2.50 DRILL C PROD1 RIH f/249' to 937' and wash down to 4090'. 304 gpm, 600 psi, pump 150 bbls. PU 160K, SO 110K. 18:00 - 19:30 1.50 DRILL C PROD1 PJSM w/Schlumberger. RU circulating lines to Schlumberger pump truck. Test 13-3/8" casing from float collar at 4146' to surface w/3500 psi for 30 minutes w/chart. Good test. RD lines and blow down. RD Schlumberger. 19:30 - 21:30 2.00 DRILL C PROD1 Continue to RIH. Wash down to 4105', 650 gpm, 130 psi, 50 rpm, 11K tq. Tagged some cement stringers washing down to plugs/float collar at 4146'. PU 160K, SO 110K, ROT 135K. Drill plugs and float collar then cement to 4227' w/shoe below at 4230'. 21:30 - 23:00 1.50 DRILL C PROD1 Displace mud f/spud mud to 9.3 ppg LSND mud. 630 gpm, 1240 psi. Rotate/reciprocate during displacement. 50 rpm, 10K tq. 600 bbls. pumped. 23:00 - 23:30 0.50 DRILL C PROD1 Drill rest of shoe track to 4230'. Drill to 4240' and then new hole to 4260' for FIT. 23:30 - 00:00 0.50 DRILL C PROD1 POH to 4186' and RU equipment for FIT. 11/6/2007 00:00 - 00:30 0.50 DRILL P PROD1 Perform FIT to 11.1 ppg EMW w/9.3 ppg mud, shoe TVD 3893', new hole to 4260', 364 psi. RD test equipment. 00:30 - 06:00 5.50 DRILL P PROD1 Drill directionally f/4260' to 5180'. WOB 15K to 20K, 750 gpm, 2150 psi, 2000 psi off, 125 rpm, 11.5K tq. on 10.OK tq. off, PU 183K, SO 125K, ROT 133K. 06:00 - 12:00 6.00 DRILL P PROD1 Continue drilling from 5,180' to 5,986', Correction slides as needed per DD 790 GPM @ 2,270 psi off, 2,505 psi on, MW in and out = 9.8 PP9 WOB = 15-30K, PUW = 210K, SOW = 130K, RWT = 158K Torque 13K off, 15K on @ 120 RPMs SPR's taken at 5,418': Pump #1: 2 bpm / 100 psi , 3 bpm / 140 psi Pump #2: 2 bpm / 80 psi , 3 bpm / 120 psi 12:00 - 00:00 12.00 DRILL P PROD1 Continue drilling from 5,986' to 7,080', Correction slides as .- needed per DD 780 GPM @ 2,425 psi off, 2,560 psi on, MW in and out = 9.8 PP9 WOB = 15-20K, PUW = 247K, SOW = 140K, RWT = 177K Torque 17K off, 20K on @ 120 RPMs SPR's taken at 6,932': Printed: 11/29/2007 8:49:51 AM ~ ~ BP EXPLORATION. Page 7 of 12 Operations: Summary Report Legal Well Name: GNI-04 Common Well Name: GNI-04 Spud Date: 10/29/2007 Event Name: DRILL+COMPLETE Start: 10/24/2007 End: 11/13/2007 Contractor Name: NABORS ALASKA DRI LLING I Rig Release: 11/13/2007 Rig Name: NABORS 7ES Rig Number: Date From -To Hotars Task Code NPT Phase Description of Operations 11/6/2007 12:00 - 00:00 12.00 DRILL P PROD1 Pump #1: 2 bpm / 120 psi , 3 bpm / 160 psi 11/7/2007 00:00 - 04:30 4.50 DRILL P PROD1 04:30 - 06:00 1.50 DRILL P PROD1 06:00 - 06:30 0.50 DRILL P PROD1 06:30 - 07:00 0.50 DRILL P PROD1 07:00 - 13:00 6.00 DRILL P PROD1 13:00 - 14:00 1.00 DRILL P PROD1 14:00 - 15:30 1.50 DRILL P PROD1 15:30 - 17:00 1.50 DRILL P PROD1 17:00 - 18:30 1.50 DRILL P PROD1 18:30 - 20:30 2.00 DRILL P PROD1 20:30 - 00:00 3.50 DRILL P PROD1 11/8/2007 00:00 - 02:00 2.00 EVAL P PROD1 02:00 - 10:00 8.00 EVAL P PROD1 10:00 - 12:00 2.00 EVAL N WAIT PROD1 12:00 - 13:00 1.00 EVAL P PROD1 13:00 - 13:30 0.50 WHSUR P PROD1 Pump #2: 2 bpm / 120 psi , 3 bpm / 160 psi Midnight Update: ADT=14.06, AST=2.82, ART=11.24, Bit Hours = 14.06 Continue drilling from 7,080' to 7,463' TD per Geologist. ~ 790 GPM @ 2,550 psi off, 2,675 psi on, MW in and out = 9.8 PP9 WOB = 15-20K, PUW = 250K, SOW = 140K, RWT = 185K Torque 17K off, 18-20K on @ 120 RPMs SPR's taken at 7,463': Pump #1: 2 bpm / 80 psi , 3 bpm / 100 psi Pump #2: 2 bpm / 50 psi , 3 bpm / 90 psi ADT = 2.85 ,AST = 0.07 ,ART = 2.78 ,Jar hours = 48.62 Circulate bottoms up twice to clean up the hole. 800 GPM / 2,560 psi pump pressure Reciprocating and rotating pipe at 140 RPM with 17K ft-Ibs of torque. Pumped a total of 1,909 bbls. Monitor well -mud weight = 9.8 ppg. POOH from 7,463' to 6,358'. Mad pass from 6,358' to 5,670' and from 5,260' to 5,000' at 300 ft/hour. 600 GPM, 1,470 psi, 80 RPM, 14K ft-Ibs of torque. POOH from 5,000' to 4,186'. Slip and cut 101' of drilling line. Service Top Drive, adjust brakes and service Crown. TIH from 4,186' to TD at 7,463' with no problems. Pump 9.8 ppg hi-vis sweep to aid in cleaning the hole. 750 GPM / 2,340 psi pump pressure. Reciprocating and rotating pipe at 130 RPM with 16K ft-Ibs of torque. Pumped a total of 1,670 bbls with 20% increase in cuttings (silt) in returns. Monitor well -static loss rate of 2 bbls/hour. POOH from 7,463' to 7,070'. Mad pass from 7,070' to 7,020' at 300 ft/hour. 650 GPM, 1,745 psi, 80 RPM, 16K ft-Ibs of torque. Monitor well -static loss rate of 2 bbls/hour. Pump dry job. POOH from 7,020' to 215'. Stand back HWDP and LD Drill Collars. PJSM with Schlumberger MWD reps. Handle the Source with Schlumberger MWD reps. LD remaining BHA components. Clear and clean Rig Floor. PJSM with Schlumberger E-line personnel and Rig Crew. RU E-line with Air Wiper. Run Dipole Sonic and Four-Arm Caliper Log with E-line in the open hole section per Geologist. Wait on orders due to suspected bad log data. Decision made that the data is sufficient and good. RD E-line. Pull Wear Ring and set Test Plug. Printed: 11/29/2007 8:49:51 AM ~ ~ 8P EXPLORATION. Page 8 of 12 Operations Summary Report Legal Well Name: GNI-04 Common Well Name: GNI-04 Spud Date: 10/29/2007 Event Name: DRILL+COMPLETE Start: 10/24/2007 End: 11/13/2007 Contractor Name: NABORS ALASKA DRILLING I Rig Release: 11/13/2007 Rig Name: NABORS 7ES Rig Number: Date. From - To Hours Task Code NPT Phase Description of Opel•ations 11/8/2007 13:30 - 15:00 1.50 BOPSU P PROD1 Change out upper Pipe Rams from 3-1/2" x 6" VBR's to 9-5/8". Test to 250 / 4,000 psi for 5 charted mins - OK. 15:00 - 15:30 0.50 CASE P RUNPRD PU and dummy run with Casing Hanger. RKB = 27.06'. 15:30 - 17:00 1.50 CASE P RUNPRD RU 9-5/8" Handling Equipment. Change Bails. RU Frank's Fill-up Tool. 17:00 - 00:00 7.00 CASE P RUNPRD PJSM with Halliburton and Nabors personnel. PU and MU Shoe Track. Baker-lok'd Shoe Track components (Joints #1-3). Joint #1 Centralizer pinned 10' from the Float Shoe. Joint #2 Centralizer pinned in the middle of the Joint. Check the floats - OK. RIH with 9-5/8", 47#, L-80, BTC-M Casing. Using Best-O-Life 2000 Pipe Dope on all connections. MU connections to the mark. Avg MU Torque = 8,400 ft-Ibs. PUW and SOW obtained every 15 Joints in the 13-3/8" and compared with the torque and drag plot. Install one free-floating Centralizer on each Joint up to the Halliburton ES Cementer (Jts #3 - 76). One bow spring Centralizer on Joints #77-78 above and below the ES Cementer pinned 10' from the Cementer with stop rings. MU and Baker-lok Halliburton ES Cementer with Halliburton rep. Midnight update: Ran Casing to depth of 3,252'. 11/9/2007 00:00 - 01:00 1.00 CASE P RUNPRD Continue RIH with 9-5/8", 47#, L-80, BTC-M Casing from 3,252' to 4,200'. Using Best-O-Life 2000 Pipe Dope on all connections. MU connections to the mark. Avg MU Torque = 8,400 ft-Ibs. PUW and SOW obtained every 15 Joints in the 13-3/8" and compared with the torque and drag plot. 01:00 - 02:30 1.50 CASE P RUNPRD Stop at the 13-3/8" Shoe and circulate 1-1/2 Casing volumes to condition the mud. Staged pump up to 5 bpm with 295 psi. Pumped a total of 463 bbls and checked the mud with MI Engineer - OK. 02:30 - 08:00 5.50 CASE P RUNPRD Continue RIH with 9-5/8", 47#, L-80, BTC-M Casing from 4,200' to 7,452'. Using Best-O-Life 2000 Pipe Dope on all connections. MU connections to the mark. Avg MU Torque = 8,400 ft-Ibs. PUW and SOW obtained every 10 Joints in the open hole section and compared with the torque and drag plot. MU Landing Joint and Hanger and land the Casing with a final set depth of 7,452'. Final PUW = 400K ,SOW = 235K. RD Frank's Fill-up Tool and RU Cement Head with circulating lines. 08:00 - 11:30 3.50 CEMT P RUNPRD Stage pumps up to cementing rate of 5 bpm in 1/2 bbl increments. ICP = 0.5 bpm / 200 psi Reciprocate the pipe while circulating. FCP = 5 bpm / 345 psi , pumped a total of 830 bbls. 11:30 - 17:00 5.50 CEMT P RUNPRD PJSM with WSL, Toolpusher, Crew, Schlumberger reps and Halliburton reps. Printed: 11/29/2007 8:49:51 AM ~ ~ BP EXPLORATION Page 9 of 12 Operations Summary Report Legal Well Name: GNI-04 Common Well Name: GNI-04 Spud Date: 10/29/2007 Event Name: DRILL+COMPLETE Start: 10/24/2007 End: 11/13/2007 Contractor Name: NABORS ALASKA DRILLING I Rig Release: 11/13/2007 Rig Name: NABORS 7ES Rig Number: Date ~ From - To I Hours I Task I Code L NPT I :Phase.' Description of Operations 11/9/2007 11:30 - 17:00 5.50 CEMT P RUNPRD Pump 5 bbls of water and pressure test lines to 3,500 psi - good. Pump 61 bbls of 12.6 ppg mud push at 5 bpm / 600 psi. Pump 260 bbls 15.8 ppg Class G cement at 5 bpm / 1,200 psi. Switch to Rig Pumps and displace at a rate of 5 bpm / 1,710 final pressure. Slow down pump rate to 3 bpm with 20 bbls prior to bumping the Plug. Pumped a total of 539 bbls to bump the Plug with a pressure of 1,950 psi (95% pump efficiency). CIP @ 14:53 hrs. Bleed the pressure and check the floats - OK. Attempt to open the ES Cementer by pressuring up to 2,700 psi -did not open. Bleed the pressure and pressure up to 3,000 psi -did not open. Repeat the process and open the ES Cementer at 4,100 psi. Pump through the ES Cementer at a rate of 3.5 bpm / 500 psi to displace the annulus. Pumped a total of 275 bbls of 9.8 ppg mud. Recovered 60 bbls of mud push, 42 bbls of cement and 87 bbls of contaminated mud to surface. 17:00 - 21:30 4.50 CEMT P RUNPRD Pump 20 bbls of 9.8 ppg mud at a rate of 3 bpm / 450 psi through the ES Cementer to flush the annulus every 30 mins while waiting on 100 psi compressive strength. RU Little Red Hot Oil to aid in freeze protecting the annulus. 21:30 - 00:00 2.50 CASE P RUNPRD Break circulation with 30 bbl hi-vis spacer at a rate of 3 bpm / 400 psi through the ES Cementer. Pump 147 bbls of 10.7 ppg brine at a rate of 3 bpm / 350 psi through the ES Cementer. Chase with 122 bbls of 70 degree diesel with Little Red Hot Oil at a rate of 2.25 bpm / 300 psi. 11/10/2007 00:00 - 02:00 2.00 CASE P RUNPRD Drop the ES Cementer closing Plug with Halliburton reps. RD Little Red Hot Oil. Chase the Plug with 9.8 ppg mud at a rate of 5 bpm / 1,000 psi. Got diesel returns unexpectedly to surface after 261 bbls away. Bumped the Plug after 316 bbls pumped. Pressure up to 1,700 psi per Halliburton rep to close the ES Cementer - OK. 02:00 - 03:30 1.50 CASE P RUNPRD RD Cementing Head and circulating lines. Pull and lay down Landing Joint. Drain BOP Stack. 03:30 - 05:00 1.50 WHSUR P RUNPRD Install 9-5/8" Packoff with FMC rep. RILDS. Test to 5,000 psi for 10 mins - OK. 05:00 - 05:30 0.50 WHSUR P RUNPRD RD Packoff Running Tool. Set Test Plug. 05:30 - 07:00 1.50 BOPSU P RUNPRD Change out upper Pipe Rams from 9-5/8" to 3-1/2" x 6" VBRs. 07:00 - 07:30 0.50 BOPSU P RUNPRD RU Test Equipment. Pressure test the VBR's to 250 / 4,000 psi per BP / AOGCC Regulations. The State's right to witness the test was waived by Chuck Scheve. 07:30 - 08:30 1.00 WHSUR P RUNPRD RD Test Equipment. Set Wear Ring and RILDS. 08:30 - 09:30 1.00 CASE P RUNPRD Inspect all Tugger Sheaves in the Derrick. 09:30 - 11:00 1.50 CASE P RUNPRD PJSM. PU and MU BHA #7 (8-1/2" Bit Cleanout Assembly) per Printed: 11/29/2007 8:49:51 AM ~ ~ BP EXPLORATION Page 10 of 12 Operatioins Summary. Report Legal Well Name: GNI-04 Common Well Name: GNI-04 Spud Date: 10/29/2007 Event Name: DRILL+COMPLETE Start: 10/24/2007 End: 11/13/2007 Contractor Name: NABORS ALASKA DRILLING I Rig Release: 11/13/2007 Rig Name: NABORS 7ES Rig Number: .Date From - To Hours Task ..Code NPT Phase. Description of Operations ,11/10/2007 09:30 - 11:00 1.50 CASE P RUNPRD DD. 11:00 - 13:00 2.00 CEMT P RUNPRD TIH with BHA #7 on 5" DP and tag the ES cementer on depth @ 4334'. 13:00 - 13:30 0.50 CEMT P RUNPRD Drill up the ES Cementer and plug w/ no problem. 255 GPM, 400 psi off, 435 psi on 50 RPM, 6.5K ft-Ibs torque off, 7K ft-Ibs torque on WOB = 10K, PUW = 135K, SOW = 95K, RW = 115K. 13:30 - 14:30 1.00 CASE P RUNPRD Circulate bottoms up to clean up the wellbore. 260 GPM, 440 psi , pumped a total of 225 bbls of 9.8 ppg mud. 14:30 - 16:00 1.50 CASE P RUNPRD TIH from 4,337' to 7,139'. Kelly up and wash down to top of plugs and baffle adaptor @ 7360'. 150 GPM, 375 psi, PUW = 235K, SOW = 130K. 16:00 - 17:30 1.50 CASE P RUNPRD Circulate bottoms up to clean up the wellbore. 475 GPM, 1,200 psi, pumped a total of 383 bbls of 9.8 ppg mud. Rotated and reciprocated pipe to aid in cleaning up the wellbore. 100 RPM, 14K ft-Ibs torque, RW = 165K. 17:30 - 18:30 1.00 CASE P RUNPRD RU Test Equipment. Test the 9-5/8" Casing to 4,000 psi for 30 charted mins -good. RD Test Equipment. 18:30 - 21:30 3.00 CASE P RUNPRD Pump 50 bbl hi-vis sweep followed by 150 bbl water spacer. Swap the welt over to clean 9.5 ppg brine. 530 GPM, 1,410 psi, pumped a total of 500 bbls of new 9.5 ppg brine. 21:30 - 00:00 2.50 CASE P RUNPRD POOH with cleanout assembly laying down DP in the Pipe Shed. Midnight update: POOH to a depth of 5,007'. 11/11/2007 00:00 - 01:30 1.50 CASE P RUNPRD PJSM. Cut and slip 63' of drilling line. Service Top Drive and Drawworks. 01:30 - 06:00 4.50 CASE P RUNPRD POOH from 5,007' with cleanout assembly laying down DP in the Pipe Shed. 06:00 - 07:00 1.00 CASE P RUNPRD Break out and lay down BHA components with DD. 07:00 - 07:30 0.50 CASE P RUNPRD Clear and clean Rig Floor. 07:30 - 09:00 1.50 EVAL P RUNPRD PJSM with crew and Schlumberger. RU E-line with air wiper. 09:00 - 12:00 3.00 EVAL P RUNPRD Run USIT/CBL log in Primary Depth Control mode with E-line from 7,360' to 4,000'. Field pick TOC @ 4,354'. 12:00 - 13:00 1.00 EVAL P RUNPRD RD E-line. 13:00 - 13:30 0.50 WHSUR P RUNCMP Pull Wear Ring and set Test Plug. 13:30 - 15:00 1.50 BOPSU P RUNCMP Change out upper Pipe Rams from 3-1/2" x 6" VBRs to 7" Pipe Rams. Test the 7" Pipe Rams to 250 / 4,000 psi per BP / AOGCC Regulations. 15:00 - 15:30 0.50 BOPSU P RUNCMP MU Landing Joint to Tubing Hanger. Make dummy run with Hanger - OK. 15:30 - 16:30 1.00 RUNCO RUNCMP PJSM with crew, Nabors Casing and Schlumberger Completions rep. RU to run 7" Completion. RU Spooling Unit. 16:30 - 00:00 7.50 RUNCO RUNCMP PJSM. PU and MU Tailpipe Assembly with Baker rep. Bakerlok all connections below the 9-5/8" x 7" Baker S-3 Packer. RIH with 7", 29#, L-80, BTC-M Tubing. I'flflt@d: l1/292U07 8:49:51 AM ! ~ BP EXPLORATION Page 11 of 12 Opera#ions Summary :Report Legal Well Name: GNI-04 Common Well Name: GNI-04 Spud Date: 10/29/2007 Event Name: DRILL+COMPLETE Start: 10/24/2007 End: 11/13/2007 Contractor Name: NABORS ALASKA DRILLING I Rig Release: 11/13/2007 Rig Name: NABORS 7ES Rig Number: Date. From - To Hours Task Code NPT Phase. Description of Operations 11/11/2007 16:30 - 00:00 7.50 RUNCO RUNCMP Making up all connections to the mark. Average MU Torque = 8,700 ft-Ibs. Using Best-O-Life 2000 Pipe Dope on all connections. Single, 3/8" stainless steel control line from 954' to surface (Jts #97-120) banded to the Tubing. Midnight update: 102 Joints in the hole. PUW = 135K ,SOW = 110K. 11/12/2007 00:00 - 02:00 2.00 RUNCO RUNCMP Continue RIH with 7", 29#, L-80, BTC-M Tubing Completion. Average MU Torque = 8,700 ft-Ibs (making up to the mark). Using Best-O-Life Pipe Dope on all connections. Single, 3/8" stainless steel control line from 954' to surface (Jts #97-120) banded to the Tubing. Ran a total of 120 Joints of 7", 29#, L-80, BTC-M Tubing. Total number of stainless steel bands used = 24 (with more on the Hanger to come}. PU Landing Joint and Tubing Hanger with FMC reps. 02:00 - 11:00 9.00 RUNCO WAIT RUNCMP Wrong Tubing Hanger for the Completion. No port for the control line. One other Hanger on the Slope but doesn't have a port either. Send the Hanger to Baker Machine to have a port machined into existing Hanger. Clear and clean the Rig. Prepare for rig move. 11:00 - 13:00 2.00 RUNCO RUNCMP Hanger arrives on location. MU Hanger and terminate Control Line. Final PUW = 160K ,SOW = 128K. Final count on stainless steel bands used = 29. Test Hanger Port for Control Line to 5,000 psi - OK. Land Tubing Hanger with FMC rep. RILDS. Lay down Landing Joint. 13:00 - 14:00 1.00 WHSUR P RUNCMP Set TWC with FMC rep. RU Test Equipment. Test TWC from above to 1,000 psi for 5 charted mins. RD Test Equipment. 14:00 - 17:00 3.00 BOPSU P RUNCMP PJSM. Change out 7" Pipe Rams to 3-1/2" x 6" VBR's. ND and set back BOPE. 17:00 - 21:30 4.50 WHSUR P RUNCMP NU Adapter Flange. Test Hanger void to 5,000 psi for 15 mins with FMC rep - OK. 21:30 - 00:00 2.50 WHSUR P RUNCMP NU Tree and test with diesel to 5,000 psi - OK. 11/13/2007 00:00 - 01:00 1.00 WHSUR P RUNCMP RU Lubricator and pressure test to 1,000 psi. Pull TWC with DSM Techs. 01:00 - 02:00 1.00 RUNCO RUNCMP RU circulating lines to the Tree. Pressure test line to 1,000 psi - OK. 02:00 - 03:00 1.00 RUNCO RUNCMP Pump 77 bbls of corrosion inhibited 9.5 ppg brine down the Tubing at 3 bpm / 160 psi. Pump 105 bbls of clean 9.5 ppg brine down the Tubing at 3 bpm / 170 psi. 03:00 - 03:45 0.75 RUNCO RUNCMP RU Little Red Hot Oil to freeze protect the well. Line them up on the Tubing. Pressure test their high pressure hose to 4,000 psi. 03:45 - 06:00 2.25 RUNCO RUNCMP Pump 126 bbls of diesel down the Tubing at 2 bpm / 200 psi with Little Red. Allow the diesel to U-tube into the IA for 1 hour. 06:00 - 10:30 4,50 RUNCO RUNCMP Drop ball and rod to set the Packer per Baker Completions rep. Pressure up on the Tubing with Little Red Hot Oil and test to 4,000 psi for 30 mins -good. Printed: 11/29/2007 8:49:51 AM • BP EXPLORATION Page 12 of 12 Operations Summary Report Legal Well Name: GNI-04 Common Well Name: GNI-04 Spud Date: 10/29/2007 Event Name: DRILL+COMPLETE Start: 10/24/2007 End: 11/13/2007 Contractor Name: NABORS ALASKA DRILLING I Rig Release: 11/13/2007 Rig Name: NABORS 7ES Rig Number: Date... I From - To I Hours I Task I Code I NPT I Phase ( Description of Operations 11/13/2007 06:00 - 10:30 4.50 RUNCO RUNCMP Pressure up on the IA with Little Red Hot Oil and test to 4,000 psi for 30 mins -good. RD Little Red Hot Oil and blow down all lines. 10:30 - 11:00 0.50 WHSUR P RUNCMP Set BPV with Baker Completions rep. 11:00 - 12:00 1.00 RIGD P POST Change out flanges on annulus valves. Secure the Cellar. The Rig was released at 12:00 hrs on 11/13/2007. Printed: 11/29/2007 8:49:51 AM C~I:V~~~~4 • ~ Page 1 of 1 Well History Well Date Summary GNI-04 1/19/2008 ***WELL S/I ON ARRIVAL*** RIGGING UP SLICKLINE UNIT IN PROGRESS ***CONTINUED ON 1/20/07 WSR*** GNI-04 1/20/2008 ***CONTINUED FROM 1/19/08 WSR*** PULLED B&R ~ 4,949' SLM PULLED 7" RHC PLUG BODY FROM 4951' SLM DRIFTED W/ 4.5" DMY GUN STOP ~ 7260' SLM AS PER PROGRAM ***WELL S/I ON DEPARTURE, NOTIFIED DSO*** GNI-04 1/22/2008 ***WELL SHUT-IN ON ARRIVAL***T/I/O 230/0/0. RAN STATIC TEMP SURVEY FROM SURFACE TO 7,360'. UNABLE TO COMPLETE PERFORATIONS DUE TO MAN BASKET LIMITATIONS AND INCREASING WIND. DEPTH CORRECTED TO SLB USIT LOG DATED 11-NOV-2007. ***WELL LEFT SHUT-IN*** GNI-04 1/27/2008 JOB NOT ATTEMPTED DUE TO TEMPERATURES EXCEEDING MAN-LIFT OPERATING LIMIT OF - 20 DEG. PE SCHEDULING SCAFFOLD CREW FOR USE OF SCAFFOLD INSTEAD OF MAN-LIFT. ***JOB POSTPONED'** GNI-04 1/30/2008 ****WELL SHUT-IN ON ARRIVAL**** INTIAL T/ I/ O = 0/ 0/ 0 PSI. BEGAN RIGGING UP FOR PERFORATING JOB. ****CONTINUED ON 31 JAN 2008.**** GNI-04 1/31/2008 ****CONTINUATION OF JOB FROM 30 JAN 2008**** WELL SHUT-IN ON ARRIVAL. INTIAL UI/O = 0/0/0 PSI. RAN IN HOLE WITH 4.5" 20' GUN 4505 PJ HMX, 5 SPF. PERFORATED INTERVAL 7175' to 7195'. API PENETRATION DATA = 54.1 ", API ENTRANCE HOLE DIAMETER = 0.42". POOH: WELL LEFT SHUT-iN. FINAL T/I/O: 0/0/0. ****JOB COMPLETE**** Print Date: 2/27/2008 Page 1 of 1 http://digitalwellfile.bpweb.bp.com/WI Info/Reports/ReportViewer.aspx 2/27/2008 by ~'"'~ _... _ . _ _ Schlumberger -~,w,- t~l N i-u4 a u ...r.... ,.~... Client: . .............. , ..... BP Alaska Field: Lisbttme Structure 1 Slot: Surfcote /GNI-04 Well: GNI-04 Borehole: GNI-04 uwllAPla: 50029233670( Survey Name 1 Date: GNI-04 /November 7, 2001 Tort I AHD 1 DDI I ERD ratio: 81.262° / 2996.49 k 15.430 / 0.44: Grad Coordinate System: NAD27 Alaska State Planes, Zone 04, US Fee Location LaULong: N 7016 58.678, W 14814 38.43. Location Grid NIE YIX: N 5956183.150 ftUS, E 716973.080 ftU: Grid Convergence Angle: +1.65309642° rcepvrt survey 1 DLS Computation Method: Minimum Curoalure / L Vertical Section Azimuth: 269.970° Vertical Section Origin: N 0.000 ft, E 0.000 fl TVD Reference Datum: Rotary Table TVD Reference Elevation: 47.60 ft relative t0 MSL Sea Bed 1 Ground Level Elevation: 19.10 ft relative to MSL Magnetic Declination: 24.188° Total Field Strength: 57626.167 nT Magnetic Dip: 80.958° Declination Date: NOVembef 01, 2001 Magnetic Declination Model: BGGM 2007 North Reference: True North Total Corr Mag North •> True North: +24.188° • Comments Measured Inclination Azimuth Sub-SeaTVD TVD Vertical Along Hole Closure NS EW DLS Northing Easting Latitude Longitude Depth Section Departure k de de k ft ft ft k ft ft d 1100 k kUS kUS n nn n nn encc~oo ~e 7~cn70 na 41 7n 1C C!! R7a \A/ SAC 1A 4a A4A Klt U.W V.W U.VV W/.W U.W U.VV V.w V.vV V.VV V.vv ~.vv vow .v....v r .v.~....vv ...v .v ..v.v. .. .. .~.. .~.....~..~ GYD CT DMS 100.00 0.22 237.16 52.40 100.00 0.16 0.19 0.19 -0.10 -0.16 0.22 5956183.04 716972.92 N 70 16 58.677 W 14814 38.439 200.00 0.28 244.01 152.40 200.00 0.54 0.63 0.63 -0.32 -0.54 0.07 5956182.82 716972.55 N 70 16 58.675 W 14814 38.450 300.00 1.75 299.38 252.38 299.98 2.09 2.33 2.12 0.33 -2.09 1.61 5956183.42 716970.98 N 70 16 58.681 W 14814 38.495 400.00 3.87 302.81 352.26 399.86 6.26 7.23 6.90 2.90 -6.26 2.13 5956185.87 716966.74 N 7016 58.706 W 14814 38.616 500.00 5.88 301.34 451.89 499.49 13.47 15.73 15.37 7.40 -13.47 2.01 5956190.16 716959.40 N 7016 58.750 W 148 14 38.826 MWD+IFR+MS 567.89 7.51 296.15 519.31 566.91 20.42 23.64 23.28 11.16 -20.42 2.56 5956193.72 716952.34 N 7016 58.787 W 14814 39.029 657.38 9.09 299.77 607.86 655.46 31.80 36.55 36.19 17.25 -31.81 1.86 5956199.47 716940.79 N 7016 58.847 W 148 14 39.360 746.39 11.26 300.08 695.47 743.07 45.42 52.27 51.91 25.10 -45.44 2.44 5956206.93 716926.94 N 70 16 58.925 W 14814 39.757 836.95 13.46 297.96 783.93 831.53 62.38 71.65 71.29 34.47 -62.40 2.48 5956215.81 716909.72 N 70 16 59.017 W 14814 40.251 931.74 15.05 298.36 875.79 923.39 82.95 94.99 94.63 45.49 -82.97 1.68 5956226.23 716888.83 N 7016 59.125 W 14814 4 1025.79 15.37 297.34 966.55 1014.15 104.76 119.67 119.30 57.02 -104.79 0.44 5956237.12 716866.69 N 7016 59.238 W 148 14 4 1121.55 16.67 296.60 1058.59 1106.19 128.31 146.09 145.71 68.99 -128.35 1.37 5956248.41 716842.80 N 70 16 59.356 W 14814 42. 2 1215.51 17.69 297.63 1148.36 1195.96 153.00 173.85 173.46 81.65 -153.04 1.13 5956260.35 716817.75 N 70 16 59.481 W 148 14 42.892 1310.77 15.96 298.65 1239.53 1287.13 177.31 201.42 201.03 94.64 -177.36 1.84 5956272.63 716793.07 N 70 16 59.608 W 14814 43.600 1405.72 15.95 298.83 1330.83 1378.43 200.19 227.52 227.13 107.19 -200.25 0.05 5956284.52 716769.83 N 7016 59.732 W 1481444.267 1497.62 17.10 299.68 1418.93 1466.53 222.99 253.66 253.27 119.97 -223.05 1.28 5956296.63 716746.67 N 7016 59.858 W 1481444.931 1594.42 17.44 301.58 1511.37 1558.97 247.70 282.39 281.98 134.61 -247.77 0.68 5956310.55 716721.54 N 7017 0.002 W 14814 45.651 1688.28 19.23 301.19 1600.46 1648.06 272.90 311.92 311.47 149.99 -272.98 1.91 5956325.19 716695.90 N 70 17 0.153 W 148 1446.385 1779.89 22.73 301.53 1685.98 1733.58 300.89 344.71 344.23 167.06 -300.98 3.82 5956341.45 716667.42 N 7017 0.321 W 14814 47.201 1876.76 22.68 302.09 1775.34 1822.94 332.65 382.10 381.58 186.77 -332.75 0.23 5956360.23 716635.10 N 7017 0.514 W 14814 48.127 1972.91 25.07 301.73 1863.26 1910.86 365.68 421.01 420.46 207.33 -365.79 2.49 5956379.83 716601.48 N 7017 0.717 W 14814 49.089 2067.38 27.45 301.21 1947.97 1995.57 401.32 462.81 462.23 229.14 -401.44 2.53 5956400.61 716565.22 N 70 17 0.931 W 14814 50.128 2163.10 28.91 299.24 2032.35 2079.95 440.37 508.01 507.43 251.88 -440.50 1.81 5956422.21 716525.52 N 70 17 1.155 W 14814 51.265 SurveyEditor Ver SP 2.1 Bld( doc40x_100) GNI-04\GNI-04\GNI-04\GNI-04 Generated 11/29/2007 8:51 AM Page 1 of 3 Comments Measured Inclination Azimuth Sub-Sea ND 7yp Vertical Along Hole Closure NS EW DLS Northing Easting Latitude Longitude Depth Section Departure ft de de ft ft ft ft ft ft ft de 100 ft ftUS ftUS LLO/.04 3V.L0 LY4.`J, L114.00 LIOL. 10 901.71 009.00 OJ~i.VH L/J.IV -YOL.VO L.V/ V.7JVYYG.LL 2351.87 28.68 294.18 2196.59 2244.19 524.07 601.05 600.25 292.38 -524.23 1.74 5956460.28 2444.78 26.20 295.37 2279.04 2326.64 562.94 643.86 642.94 310.31 -563.10 2.73 5956477.07 2539.43 26.94 294.85 2363.69 2411.29 601.27 686.20 685.19 328.27 -601.44 0.82 5956493.92 2635.82 28.56 294.73 2449.00 2496.60 642.00 731.07 729.98 347.09 -642.18 1.68 5956511.55 2730.01 29.07 294,66 2531.52 2579.12 683.24 776.47 775.29 366.05 -683.43 0.54 5956529.32 2827.64 29.72 293.58 2616.58 2664.18 726.96 824.39 823.09 385.63 -727.17 0.86 5956547.62 2921.45 30.53 293.96 2697.72 2745.32 770.04 871.47 870.06 404.61 -770.25 0.89 5956565.35 3015.65 30.80 295.21 2778.75 2826.35 813.72 919.51 918.03 424.60 -813.94 0.73 5956584.07 3109.92 31.32 294.54 2859.50 2907.10 857.83 968.15 966.62 445.05 -858.06 0.66 5956603.25 3203.72 32.74 293.57 2939.02 2986.62 903.25 1017.90 1016.28 465.32 -903.49 1.61 5956622.19 3300.53 32.22 292.03 3020.69 3068.29 951.16 1069.88 1068.11 485.47 -951.41 1.01 5956640.95 3395.86 31.50 290.98 3101.66 3149.26 997.96 1120.20 1118.21 503.92 -998.22 0.95 5956658.04 3489.13 30.23 292.86 3181.72 3229.32 1042.34 1168.05 1165.88 521.77 -1042.61 1.71 5956674.60 3584.38 27.70 295.72 3265.05 3312.65 1084.38 1214.16 1211.96 540.70 -1084.66 3.03 5956692.31 3678.97 27.99 297.82 3348.69 3396.29 1123.81 1258.34 1256.13 560.60 -1124.10 1.08 5956711.06 3774.85 28.41 299.19 3433.19 3480.79 1163.61 1303.65 1301.41 582.22 -1163.91 0.80 5956731.52 3869.41 28.03 296.27 3516.52 3564.12 1203.16 1348.35 1346.10 603.03 -1203.48 1.51 5956751.18 3963.73 28.24 291.69 3599.70 3647.30 1243.76 1392.81 1390.50 621,08 -1244.09 2.30 5956768.06 4058.68 27.89 292.26 3683.49 3731.09 1285.18 1437.48 1435.04 637.80 -1285.51 0.46 5956783.57 4153.25 26.74 295.29 3767.52 3815.12 1324.88 1480.87 1478.38 655.27 -1325.22 1.91 5956799.89 4172.89 26.57 295.64 3785.07 3832.67 1332.83 1489.68 1487.19 659.06 -1333.18 1.18 5956803.44 4288.88 26.70 295.08 3888.75 3936.35 1379.81 1541.68 1539.18 681.33 -1380.17 0.24 5956824.35 4383.75 26.54 296.53 3973.56 4021.16 1418.07 1584.18 1581.68 699.83 -1418.43 0.71 5956841.74 4477.37 26.34 295.33 4057.39 4104.99 1455.54 1625.87 1623.36 718.06 -1455.92 0.61 5956858.88 4571.74 26.04 295.14 4142.07 4189.67 1493.21 1667.52 1665.01 735.81 -1493.60 0.33 5956875.54 4667.44 25.91 295.56 4228.11 4275.71 1531.08 1709.43 1706.92 753.76 -1531.47 0.24 5956892.38 4762.45 25.80 294.81 4313.61 4361.21 1568,56 1750.87 1748.34 771.39 -1568.97 0.36 5956908.92 4856.35 25.87 294.47 4398.12 4445.72 1605.75 1791.79 1789.25 788.45 -1606.16 0.17 5956924.90 4951.47 25.55 294.38 4483.82 4531.42 1643.31 1833.05 1830.50 805.51 -1643.73 0.34 5956940.87 5045.25 26.02 295.50 4568.27 4615.87 1680.29 1873.84 1871.28 822.72 -1680.72 0.72 5956957.00 5139.59 26.34 298.55 4652.93 4700.53 1717.34 1915.46 1912.88 841.63 -1717.78 1.47 5956974.84 5234.88 26.80 299.93 4738.16 4785.76 1754.52 1958.08 1955.44 862.45 -1754.97 0.81 5956994.58 5330.99 26.73 301.12 4823.97 4871.57 1791.79 2001.36 1998.60 884.43 -1792.25 0.56 5957015.47 5423.81 27.45 300.94 4906.61 4954.21 1828.00 2043.63 2040.72 906.22 -1828.47 0.78 5957036.21 5521.14 27.88 301.83 4992.81 5040.41 1866.56 2088.82 2085.74 929.76 -1867.05 0.61 5957058.62 5616.33 27.44 301.37 5077.12 5124.72 1904.19 2133.01 2129.76 952.91 -1904.68 0.51 5957080.68 5710.56 28.08 301.50 5160.51 5208.11 1941.62 2176.89 2173.49 975.80 -1942.13 0.68 5957102.48 5806.31 28.15 301.90 5244.96 5292.56 1980.00 2222.02 2218.44 999.51 -1980.52 0.21 5957125.07 5901.21 27.93 302.37 5328.72 5376.32 2017.76 2266.63 2262.86 1023.24 -2018.30 0.33 5957147.70 5995.01 27.99 301.03 5411.57 5459.17 2055.17 2310.60 2306.69 1046.35 -2055.71 0.67 5957169.71 / IO90J.J/ 1\ / V 1 / I.JOJ VY 190 19 0L.9/O 716440.66 N 7017 1.553 W 148 14 53.704 716401.29 N 70171.729 W 148 14 54.837 716362.45 N 7017 1.906 W 14814 55.954 716321.18 N 7017 2.091 W 14814 57.141 716279.41 N 7017 2.278 W 14814 58.342 716235.13 N 70 17 2.470 W 14814 59.616 716191.51 N 70 17 2.657 W 14815 0.872 716147.27 N 70 17 2.853 W 14815 2.144 716102.58 N 70 17 3.054 W 14815 3.430 716056.59 N 70 17 3.254 W 14815 716008.11 N 70 17 3.452 W 14815 6.149 715960.78 N 70 17 3.633 W 14815 7.513 715915.90 N 70 17 3.809 W 14815 8.806 715873.33 N 70 17 3.995 W 148 15 10.031 715833.33 N 70 17 4.190 W 148 15 11.180 715792.91 N 7017 4.403 W 148 15 12.340 715752.77 N 7017 4.607 W 14815 13.492 715711.65 N 7017 4.785 W 14815 14.676 715669.77 N 7017 4.949 W 14815 15.882 715629.57 N 7017 5.121 W 14815 17.039 715621.51 N 7017 5.158 W 14815 17.271 715573.90 N 7017 5.377 W 14815 18.640 715535.12 N 7017 5.559 W 14815 19.755 715497.12 N 7017 5.738 W 14815 20.847 715458.95 N 70 17 5.913 W 14815 21.945 715420.57 N 70 17 6.089 W 148 15 23.048 715382.59 N 70 17 6.263 W 148 15 24. 1 715344.92 N 70 17 6.430 W 148 15 2 715306.87 N 70 17 6.598 W 148 15 2 . 715269.41 N 70 17 6.767 W 14815 27.396 715231.82 N 70 17 6.953 W 14815 28.476 715194.05 N 7017 7.158 W 14815 29.560 715156.15 N 70 17 7.374 W 14815 30.646 715119.32 N 7017 7.588 W 14815 31.701 715080.08 N 7017 7.820 W 14815 32.825 715041.79 N 70 17 8.047 W 148 15 33.922 715003.70 N 70 17 8.272 W 14815 35.013 714964.65 N 70 17 8.505 W 1481536.132 714926.20 N 70 17 8.739 W 14815 37.232 714888.14 N 70 17 8.966 W 1481538.323 SurveyEditor Ver SP 2.1 Bld( doc40x_100) GNI-04\GNI-04\GNI-04\GNI-04 Generated 11/29/2007 8:51 AM Page 2 of 3 Comments Measured Inclination Azimuth Sub-Sea ND ND Vertical Along Hole Closure NS EW DLS Northing Easting Latitude Longitude Depth Section Departure ft d de ft ft k k ft ft k de 100 ft ftUS ftUS 6089.77 27.79 298.85 5495.33 5542.93 2093.56 2354.93 2350.95 1068.47 -2094.12 1.10 5957190.72 6183.46 27.64 298.01 5578.27 5625.87 2131.86 2398.50 2394.51 1089.22 -2132.43 0.45 5957210.35 6278.39 27.00 295.00 5662.62 5710.22 2170.83 2442.06 2438.06 1108.67 -2171.41 1.60 5957228.66 6374.00 26.84 292.93 5747.87 5795.47 2210.37 2485.34 2481.28 1126.25 -2210.96 0.99 5957245.10 6469.60 27.32 294.29 5832.99 5880.59 2250.23 2528.86 2524.72 1143.68 -2250.83 0.82 5957261.37 6563.73 27.55 294.83 5916.53 5964.13 2289.67 2572.23 2568.06 1161.71 -2290.27 0.36 5957278.25 6659.36 27.54 294.63 6001.32 6048.92 2329.82 2616.45 2612.25 1180.21 -2330.44 0.10 5957295.58 6749.39 27.17 294.17 6081.28 6128.88 2367.49 2657.82 2653.58 1197.30 -2368.11 0.47 5957311.58 6847.48 27.88 298.12 6168.28 6215.88 2408.14 2703.14 2698.89 1217.28 -2408.78 2.00 5957330.38 6942.64 28.32 298.34 6252.22 6299.82 2447.82 2747.96 2743.69 1238.48 -2448.27 0.48 5957350.43 7038.40 28.52 299.25 6336.44 6384.04 2487.55 2793.54 2789.24 1260.43 -2488.21 0.50 5957371.22 7133.45 28.31 299.41 6420.04 6467.64 2526.97 2838.77 2834.43 1282.59 -2527.64 0.24 5957392.23 7227.96 28.64 299.03 6503.12 6550.72 2566.28 2883.82 2879.45 1304.59 -2566.96 0.40 5957413.08 7323.59 28.66 298.93 6587.04 6634.64 2606.38 2929.68 2925.28 1326.80 -2607.07 0.05 5957434.13 Last Survey 7376.24 28.63 298.94 6633.24 6680.84 2628.46 2954.91 2950.50 1339.01 -2629.16 0.06 5957445.70 TD (Projected) 7463.00 28.63 298.94 6709.39 6756.99 2664.83 2996.49 2992.05 1359.13 -2665.54 0.00 5957464.75 Survey Type: Definitive Survey NOTES: GYD-CT-DMS - (Gyrodata - cont. drilipipe mis -- Gyrodata pump-down multishot surveys with continuous tool (RGS-CT) in drill-pipe. ) MWD + IFR + MS - (In-field referenced MWD with mull-station analysis and correction applied in post-processing. Assumes a BHA sag correction is applied to enhance inclination accuracy. ) Leoal DescrioUon: Northing (Y) [ftUS] Easting (X) [ftUS] Surface : 4190 FSL 1011 FEL S26 T11N R75E UM 5956183.15 716973.08 BHL : 269 FSL 3675 FEL S23 T11N R75E UM 5957464.75 714269.57 714849.11 N 7017 9.183 W 14815 39.442 714810.22 N 7017 9.387 W 14815 40.558 714770.70 N 7017 9.578 W 14815 41.694 714730.66 N 7017 9.751 W 14815 42.846 714690.31 N 7017 9.922 W 1481544.008 714650.36 N 70 17 10.100 W 14815 45.157 714609.68 N 70 17 10.281 W 1481546.327 714571.53 N 70 17 10.449 W 14815 47.425 714530.31 N 70 17 10.646 W 14815 48.610 714490.22 N 70 17 10.854 W 14815 49.761 714449.67 N 70 17 11.070 W 148 15 5l~ 714409.62 N 70 17 11.288 W 148 15 52. 3 714369.68 N 70 17 11.504 W 148 15 53.219 714328.94 N 70 17 11.722 W 1481554.388 714306.51 N 70 17 11.842 W 14815 55.032 714269.57 N 70 17 12.040 W 1481556.092 r 1 L_J SurveyEditor Ver SP 2.1 Bld( doc40x_100) GNI-04\GNI-04\GNI-04\GNI-04 Generated 11/29/2007 8:51 AM Page 3 of 3 TREE = 7-1/16" 5M CMJ ~ ~ • BPV = 6" Tvne "J„ G N 1 0 4 WELLHEAD = 13-5/8" FMC ACTUATOR __ KB. ELEV = 47.60' BF. ELEV = 17.25' KOP = 400' Max Angle = __ 33 @ 3204' Datum MD = 6658' Datum TVD = 6000' T 13-3/8" CSG, 68#, L-80, BTC, ID=12.415" - 4,228` Minimum ID = 5.770" @ 4,947` HES RN NIPPLE 3/8" SS Control Line Strapped to 7" Tubing from 954` to surface 4,334' - 9-5/8" ES Cementer -- 4,844` - 7" HES R NIP ID = 5.963" 7" TBG, 29#, L-80, BTC-M, 0.0371 bpf - ID = 6.184" --- 4,873` - 9-5/8" x 7" BKR S-3 PKR 4,947` - 7" HES RN NIP, ID-5.770" 4,998` - 7" TBG TAIL WLEG PERFORATION SUMMARY REF LOG: ANGLE AT TOP PERF: Note: Refer to Production DB for historical perf data SIZE SPF INTERVAL Opn/Sqz DATE 4-1/2" 5 7175 - 7195 0 01131;08 PBTD - 7,360` - 9-5/8" Shoe - 7,450' 9-5/8" CSG, 47#, L-80, BTC-M, 0.0732 bpf, ID=8.681" 7,463` - TD DATE REV BY COMMENTS DATE REV BY COMMENTS 11/13/07 N7ES COMPLETION 02/02/08 TEL/SV INITIAL PERFS (01/31/08) PRUDNOE BAY UNff WELL: GNp04 PERMIT No: 2071170 API No: 50-029-23367-00 SEC26, T11 N, R15E, 1089.29 FNL 1010.89 FEL~ BP Exploration (Alaska) o2/oa/o8 • Schlumberger NO. 4572 Alaska Data & Consulting Services Company: State of Alaska 2525 Gambell Street, suite aoo Alaska Oil & Gas Cons Comm Anchorage, AK 99503-2838 Attn: Christine Mahnken aTTN: Beth 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: P.Bay, Milne Pt, Polaris,Lisburne Wall _Inh # Lnn Dasr_rintinn Date BL Color CD LGI-04 11970706 SBHP SURVEY - j ~ ' 01/01/08 1 MPH-12 11978435 MEM DDL 01/31/08 1 W-216 12031441 USIT (~}- 01/11108 1 W-214 11855826 CH EDIT PDC GR (USIT) j 11/19/07 1 GNI-04 11846828 CH EDIT PDC GR (USIT) 11/11/07 1 15-36B 11216209 MCNL to 08/05/06 1 1 H-24A /1767145 h1CNL '~ :~.- 1b ~~~~ 11/29/07 'I 1 C-04B 11216198 MCNL ~ ~ 3 06/02/06 1 1 L3-11 11962776 MCNL ~ ~ q 12/12/07 1 1 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE DOPY EACH TO: BP Exploration (Alaska) Inc. ` Petrotechnical Data Center LR2-1 ~ ~~ "~f ~ ~ .,T 900 E. Benson Blvd. '~ ~ °"'~ l~ Anchorage, Alaska 99508 y 6. Date Delivered: ~'~~) ~~ ~ ~~~~ Alaska Data & Consulting Services 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth Received by: ~ ~~ ovoa/o8 • d ~C~1~1111~~1'!1~1' Alaska Data & Consulting Services 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth NO. 4579 Company: State of Alaska Alaska Oil & Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: P.Bay Wetl Job # Lo Descri lion uate tst. ~o~or ~.u GNI-04 40016010 OH MWD EDIT () - ~ 11/07107 2 1 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY EACH TO: BP Exploration (Alaska) Inc. Petrotechnical Data Center Lf~ 1~ ~, ~ ~~ ' v1 900 E. Benson Blvd. ~,: ~~ ~ ~. _.~% Anchorage, Alaska 99508 - Date Delivered: j--r--~-~ -~- ~ ~~n~ =sldfik~l (~1~ xu ~'ie1~ ~ 4)il`~, i;t~ll)till.`>~i(lt}+. ltl,~i~ilUt"~~r-s Alaska Data & Consulting Services 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth r - Received by: 01 /25/08 I• S ~~~~~~~~~~~r~ Alaska Data & Consulting Services 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth well Jot) ~ Lo Descri tion Date BL Color CD W-25 11962584 SBHPSURVEY ~j7f-~ 01/22/08 1 GNI-04 12031448 TEMPERATURE SURVEY 01122/08 G-27A 11649965 MCNL ~}-_ * 05/20/07 1 1 L2-24 11970805 RST ~ 12/12107 1 1 PLEASE ACKNOWLEDGE RE CEIPT BY SIGN ING AND RETURNING ONE COPY EACH TO: NO.4569 Company: State of Alaska Alaska Oil 8 Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: P.Bay BP Exploration (Alaska) Inc. Petrotechnical Data Center LR2-1 900 E. Benson Blvd. Anchorage, Alaska 99508 Date Delivered: i Alaska Data & Consulting Services 2525 Gambell Street, Suite 40 Anchorage, AK 99503-2 8 ATTN: Beth Received by: .. 12/28/07 V Sehlumb~rger NO. 4542 Alaska Data & Consulting Services Company: State of Alaska 2525 Gambell Street, Suite 40o Alaska Oil & Gas Cons Comm Anchorage, AK 99503-2838 Attn: Christine Mahnken ATTN: Beth 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: P.Bay, Lisburne, Orion Well Joh # I_nn Dascrinfinn n~to cu c.,~..r cn Z-15 11968824 PROD PROFILE 12117/07 1 L1-02 11982424 PROD PROFILE 12/12/07 1 GNI-04 N/A DIGITAL SHEAR SONIC TOOL (~~- 11/08/07 1 N-27 11962771 SCMT ~- -) 11128/07 1 A-12 11975740 USIT () - ~ ~ 12/03/07 1 03-36A 40015115 OH MWDILWD EDIT ~ ~-~ (~ !3' 04/30/07 2 1 V-210 11963075 MEMORY INJECTION PROFILE 12118/07 1 r ~crlaG „~+nwvYYLCNVC RCliClr I DT JIVIYI niV HIVU RCI VKIVIIYb VIVt l.VY7 tAl:rt IU: BP Exploration (Alaska) Inc. Petrotechnical Data Center LR2-1 - _ ~. ,;;~ 900 E. Benson Blvd. Anchorage, Alaska 99508 ~ ~" Date Delivered: ~~~~ -~~ i .~~ ,., _~ Alaska Data & Consulting Services 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth Received by: • ~~ ~ ~7 - f ~ ~7 ~~~r~ UNITEpSTATESENyIRONMENI'A1.PROTECTIONAGENCY ~ ~' .. REGION 10 ~ ~ ~ 1200 Sixth Avenue ~ ~i2k~ClG~Z Seattle, WA 98101 ~PAO~ ~~r~~ ~~.~1/1l'1^~GTpAI l N111Y 1. Li £tK1s! ~ ~ ...' ,. Reply To R ~iz:song ~I~47ic Attn Of: Suite 900, OCE-127 CERTIFIED MAIL -RETURN RECEIPT REQUESTED Neil Dunn BP Exploration (Alaska) Inc. 900 East Benson Blvd. Post Office Box 196612 Anchorage, Alaska 99519-6612 dr., tvy i U ~c9 Re: Underground Injection Control Program Class I Grind and Inject Permit AK-1I008-A Approval to Commence Class I Injection Activities at Wells GNI-02A and GNI-03 Greater Prudhoe Bay, North Slope, Alaska. Dear Mr. Dunn: The U.S. Environmental Protection Agency (EPA) Region 10 has received and reviewed the Class I Well Completion Report for the Grind and Inject Project Permit Number AK-1I008-A submitted by BP Exploration (Alaska) Inc. Based on the review of the completion report received January 7, 2008, EPA authorizes BP Exploration (Alaska) Inc. to commence Class I injection activities at the Grind and Inject Project, and specifically, for the GNI-02A and GNI-03 wells to process and inject Class I materials. Your continued efforts to coordinate the scheduling of tests are appreciated. If you have any questions, or need further information; please call Thor Cutler at (206) 553-1673. Sincerely, Michael A. Bussell, Director Office of Compliance and Enforcement cc: Jim Regg, AOGCC, Anchorage Susan McNeil, ADEC, Anchorage .~ Q £~ ~I SARAH PALlN, GOVERNOR CUNSEB~TIOH n ~~v~ 333 W 7th AVENUE, SUITE 100 as-7 ii <.0~11~Tr~~~iii~~•iiiii----777 Ol` ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Mike Bill Staff Engineer BP Exploration Alaska Inc. PO Box 196612 Anchorage, AK 99519-6612 Re: Prudhoe Bay Field, Undefined Disposal Pool, PBU GNI-04 Sundry Number: 307-362 Dear Mr. Bill: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. DATED this .,~ day of December, 2007 Encl. ~c>'~' -its Sincerely, S ~ Z/t' Z` ~ ~'~ ~'L SATE OF ALASKA ~ ~~,~~~~~~ m~ ~ ~ ALASKA OIL AND GAS CONSERVATION COMMISSION- ~O`/ ~ ~ ?~?~1 APPLICATION FOR SUNDRY APPROV~~I~a ~,« ,~~ 20 AAC 25.280 1. T e of Re uest: `'"""'`'' Yp q ^ Abandon ^ Suspend ^ Operation Shutdown ®Perforate ^-Time Extension "~ ^ Alter Casing ^ Repair Well ^ Plug Perforations ^ Stimulate ^ Re-Enter Suspended Well ^ Change Approved Program ^ Pull Tubing ^ Perforate New Pool ^ Waiver ^ Other 2. Operator Name: 4. Current Well Class: 5. Permit To Drill Number BP Exploration (Alaska) Inc. ^ Development ^ Exploratory 207-117 3. Address: ®Service ^ Stratigraphic 6. API Number: P.O. Box 196612, Anchorage, Alaska 99519-6612 50-029-23367-00-00 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: 24,420' PBU GNI-04 Spacing Exception Required? ^ Yes ®No 9. Property Designation: 10. KB Elevation (ft): 11. Field /Pool(s): J~~~ '~.c_ ~~ ADL 028323 ` 47.6' Prudhoe Bay Field / PPddhea.~ye 12. PRESENT WELL CONDITION SUM MARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 7463 - 6757 7360 6667 4947 None Casin Len h Size MD TVD Burst Colla se Structural C nd ctor 108' 20" 1 1 14 0 470 Surface 4199' 13-3/8" 4230' 3884' 4930 2270 Intermediate Pr i n 742 ' - /8" 7452' 6747' 687 47 Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): None N/A 7", 29# L-80 4999' Packers and SSSV Type: 9-5/8" x 7" Baker'S-3' packer Packers and SSSV MD (ft): 4873' 13. Attachments: 14. Well Class after proposed work: ® Description Summary of Proposal ^ BOP Sketch ^ Exploratory ^ Development ®Service ^ Detailed Operations Program 15. Estimated Date for 16. Well Status after proposed work: Commencin O erations: December 19, 2007 ^ Oil ^ Gas ^ Plugged ^ Abandoned 17. Verbal Approval: Date: ^ WAG ^ GINJ ^ WINJ ®WDSPL Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Mike Bill, 564-4692 Printed Name Mike Bill Title Staff Engineer Prepared By Name/Number: Signature ,~'/~-~~ Phone 564-4692 Date ~/ ~w 7 Terrie Hubble, 564-4628 Commission Use Onl Sundry Number. ~~ - Conditions of approval: Notify Commission so that a representative may witness 9 9 tY ^ .~( 9 Y ^ ^ Plu Inte ri BOP Test Mechanical Inte rit Test Location Clearance f~ Other: ~~f-\~t©r~~0~~~'~7~~h'~C~v\~ c~f~ ~©~c~~ ~.^~~ 1 Subsequent Form Required: '"1~ APPROVED BY n d~ ~ ' ~ ~ A roved B ISSIONER THE COMMISSION Date A V~~, Form 10-403 Revised 06/2006 (~ `~ Submit In Duplicate ~~~~~i.:~~~oo, ORiGIN~, s s- GNI-04 Initial Perforations Purpose: Prepare new Class I/Class II disposal well for injection. Satisfy AOGCC Baseline Temperature Log requirement. Perforations: Proposed: 7175-7195' MD (ref: Schlumberger USIT/CBL-VDL 11 /11 /07) Tubing: 7" 29 #/ft L-80, WLEG @ 4998' MD Packer: 7" X 9 5/8" Baker S-3 @ 4873' MD (Drlg) (ID = 6.00") Min ID: RN Nipple @ 4947' MD (Drlg), 5.770" ID Casing: 9-5/8" 47#/ft L-80 @ 7450' MD (Drlg) PBTD: 7360' MD (Drlg 11/10/07) Last Tag: 7350' MD ELM (USIT/CBL-VDL 11/11/07) Max. Deviation: 32.74° @ 3204' MD; 28.5° at perfs Fluid in tubing: Diesel to 2000', brine to PBTD Fluid in IA: Diesel to 2000', inhibited brine to packer Tie in Log: None -see this procedure Primary depth control log: Schlumberger USIT/CBL-VDL11/11/07 (Ultrasonic Imaging Tool, USIT /CBL-VDL / GPIT / GR / CCL) Latest H2S value: None taken. Expected level = 0 ppm Current status: New Class I /Class II disposal well Pull Ball & Rod. Drift & Tag 1. Pull back pressure valve. 2. Rig up slickline, pressure test. 3. RIH and pull ball & rod and RHC-M plug from the RN nipple located at 4947`MD (Drlg). 4. Drift & tag to PBTD for perforating (4-1/2" (4.74") perforating gun). Proposed bottom perforation is 7195' MD (ref Schlumberger USIT-CBL-VDL 11 /11 /07). Tie-In Log: Baseline GR/CCL/Temperature 1. Rig up E-line. Pressure test 2. RIH with GR/CCL/Temperature/Pressure tool. 3. Tie into primary depth control log: Schlumberger USIT/CBL-VDL 11/11/07 4. Log baseline GR/CCL/Temperaturefrnm surface to PBTD. 5. POOH f Initial Perforations 1. Pressure test. 2. RIH with 4-1/2" HSD perforating gun, 4505 Power Jet HMX 3. Perforate 7175'-7195' MD (ref. Schlumberger USIT/CBL-VDL 11/11/07) 4. POOH TREE = 7-1/16" 5M CM/ BPV = 6" Tvoe "J" WELLHEAD = 13-5/8" FMC ACTUATOR = KB. ELEV = 47.60' BF. REV = 17.25' KOP = 400' Max Angle = 33 @ 3204' Datum MD = 6658' Datum TV D = 6000' DRLG DRAFT 13-3/8" CSG, 68#, L-80, BTC, ID=12.415" - 4,228` Minimum ID = 5.770" @ 4,947' HES RN NIPPLE 7"TBG, 29#, L-80, BTC-M, 0.0371 bpf - ID = 6.184" PERFORATION SUMMARY REF LOG: ANGLE AT TOP PERF: Note: Refer to Production DB for historical pert data SIZE SPF INTERVAL OpnlSgz DATE PBTD - 7,360` 9-5/8" Shoe - 7,45 • SS Control Line Strapped Tubing from 954' to surface S4' - 9-5/8" ES Cementer 4'-7"HESRNIPID=5.963" 3' - 9-5/8" x 7" BKR S-3 PKR 7' - 7" HES RN NIP, ID-5.770" i' - 7" TBG TAIL WLEG CSG, 47#, L-80, BTC-M, 0.0732 bpf, ID=8.681" .,.53'-TD DATE REV BY COMMENTS DATE REV BY COMMEMS PRUDHOE BAY UNfr 11/13/07 N7ES COMPLETION WELL: GNI-04 PERMfr No: 2071170 API No: 50-029-23367-00 SEC26, T11N, R15E; 1089.29 FNL 1010.89 FEL BP Exploration (Alaska) GNI-04 . ~ Page 1 of 2 Maunder, Th©mas E (DOA) From: Maunder, Thomas E (DOA} Sent: Tuesday, December 11, 2007 3:15 PM To: 'Bill, Michael L (Natchiq}' Subject: RE: Initial Perfs GNI-04 (207-117} Thanks Mike. This answers my questions. Tom From: B{I{, Michael L (Natchiq) [mailto:Michae{.Bi{I@bp.com] Sent: Tuesday, December 11, 2007 12:58 PM To: Maunder, Thomas E (DOA} Gc: Nadem, Mehrdad; Hobbs, Greg S (ANC); Engel, Harry R; Hubble, Terrie L Subject: RE: Initial Perfs GNI-04 (207-117) Tom, After perforating and after the flowline is installed, we will be doing several additional jobs to "commission°' well GNI-04 for slurry injection: - infectivity test using methanol-water to ensure the perforations are open -step rate test -required by the both AIO 4E, Rule 10 and the EPA Class Ipermit -will use G&I plant as water source - waterflow log - a demonstration of no channel is required by the EPA Class Ipermit -will use G&I plant as water source - MIT-IA after a the well is warmed up - AIO-4E, Rule 6 and EPA Class I permit - Surface Pressure Falloff -required by AIO-4E rule 10 -note the test may be cut short due to freeze protection concerns -I'll discuss with Jim Regg Once this work is completed we will forward the results to the EPA and request authorization to use the wel9 for Class 1 injection. Enclosed are the draft work request procedures that I will send to the slope for these jobs. Note- there could be some changes before the final version goes north. Let me know if you have any additional questions, Mike Bill ADW Wells Group 907-564-4692 office 907-564-5510 fax Prom: Maunder, Thomas E (DOA) [mailto:tom.maunder@a{aska.gov] Seat: Tuesday, December 11, 20(}7 11:06 AM To: BiH, Michael L (Natchiq) Cc: Nadem, Mehrdad; Hobbs, Greg S (ANC) Subject: Initial Petfs GNI-04 (207-ii7) Mike, I am finalizing the review of the sundry to perforate GNI-04. The proposal looks ftne. 7175 - 7195 shows some of the better coverage. 12/11/2007 • . Page 2 of 2 I presume that the step-rate test and various logging operations will follow. Could you provide some details? Thanks in advance. Calf or message with any questions. Tom Maunder, PE AOGCC 12/11/2007 • by ~~~ ~~~~"~ Memorandum To: J. Bixby/C. Olsen Date: November 30, 2007 GPB Well Ops Team Leaders PECT: PBGNIWELL From: Mike Bill Res Surv_lnjectivity, SRT, MIT-IA, PFO Disposal 8~ Regulatory Compliance Engineer Est. Cast: $50,000 Subject: GNI-04: Perf Break Down, Stea Rate Test; Waterflow Loy; MIT-lA; Surface Pressure Falloff 1. F Infectivity Test 2. E Step Rate Test - Press/TempfSpinner 3. E Waterflow Lag 4. F MIT-IA - AOGCC witness 5. O Surface Pressure Falloff - 3 days with Halliburton pressure gauge on tree J ustificationlPriorlty/Timing: New Disposal Well Compliance work: GNI-04 is a new Class l/Class ll disposal well. This work is required to utilize the well for slurry disposal service. The work will satisfy EPA Class I permit and AOGCC requirements for new shiny injection wells. An infectivity test using a pump truck is requested to ensure injection is established before breaking freeze protection on the well and surface lines. The MiT-IA should be performed while the well is injecting, at least 2 days after the start of water injection. The test should be witnessed by EPA and/or AOGCC. The required test pressure under the Class I permit is 1500 psi; this procedure specfies a 2000 psi MIT-lA to allow a 2000 psi MAASP. G&I currently cycles injection between wells GNl-02A and GNI-03; GNI-03 is currently injec~ing_ Work items should be performed in sequence after the v~li is perforated per a previous Exocedure. The infectivity test can be done prior to the installation of the flowline, well house and instrumentation. The SRl`, WFL and MIT-IA shouk# be schedu~ci after the flow line, etc work is comp~te<i. F'n~sured sea water and/or produced water will be supplied from DS 4 via the Gil plant. The SPFO will follow the initial water injection period. Freeze protection of the wail should be delayed until #~ end of the pressure falloff if possible. Scheduling far all work should be eonf'rrrted with the G&l plant operator at 659-8419, pager 659-5100, 2815. See attadied procedures. For questions or comments please call Mike Bill at 564-4692(w) or 333-5395(h). cc: Well File Mike Bill Harry Engel Steve Rossberg Well Surveillance Grind ~ inject r~ GNI-0211/26107 Infectivity Test Step Rate Test Waterflow Log MIT-IA Surface Pressure Fafl Off Test Cost Code: PBGNIWELL Purpose: Prepare new disposal well for injection. Satisfy EPR and AOGCC Baseline welt test requirements. Perforations: Tubing: Packer: Min ID: Casing: PBTD: Last Tag: Max. Deviation: Fluid in tubing: Fluid in IA: Tie in Log: Latest H2S value: Current status: Proposed: 7175-7195' MD (ref: Schlumberger USIT/CBL-VDL 11 /11 /07) 7" 29 #fft L-80, WLEG ~ 4998' MD 7" X 9 5/8" Baker S-3 @ 4873' MD (Drlg} (tD = 6.00°) RN Nipple ~ 4947' MD (Drlg), 5.770" ID 9-518" 47#/ft L-80 ~ 7450' MD (Drlg} 7360' MD (Drtg 11/10/07) 7350' MD ELM (USITlCBL-VDL 11/11/07) 32.74° ~ 3204' MD; 28.5° at perfs Diesel to 2000', brine to PBTD Diesel to 2000', inhibited brine to packer None - GR/CCtlTemperature/Pressure log to be run prior to this procedure Primary depth control tog: Schlurnberger USITlCBL-VDL11/11/07 (Ultrasonic Imaging Tool, USIT /CBL-VDL t GPtT / GR I CCL) None taken. t=xpected ~vel = 0 ppm New Class t /Class II disposal well Timing: Work to be scheduled after initial perforations. Work may be scheduled before or after the flow tine, well house and instrumentation installation, to begin alx~ut 12/15/07. Note: Injection will be active in GNI-02A or GNI-03, over 2700' away. Grind & Inject Pfant :John DumonttTony Christensen 659-8419 Halliburton contact: Gary Rainey/ Sheridan Cleland, 670-5891 G&t Engineer: Mike Bitt, 564-4692, tritlml a~bp.com Infectivity Test 1. Rig up pump truck. 2. Verify infectivity by pumping 200 barrels methanol-water at 4-5 bpm into tubing. Note injection pressures every 5 minutes during pumping. 3. Note: Monitor inner and outer annulus pressures. Blued annuli as necessary. Well Surveifiance Grind & Inject 2 • • GNI-04 Stea Rate Test with Sainner/Pressure/Temaerature loa 1. Displace well with 1000 barrels (2.5 well bore volumes) of seawater at 5 bpm using the G&! plant bypass. Verify well instrumentation is working correctly. Note: Monitor inner and outer annulus pressures. Bleed as necessary. Z. Rig up E-line 3-1/2" spinnerlpressure/temperature toot. RIH to 7100' MD 3. After the weft has been shut in for 6 hours, restart seawater injection using the G&I plant bypass. Inject water at 1 bpm constant rate (or minimum rate) for 45 minutes. - E-Line: record spinner, temperature and pressure during the test at 1 minute interval. Download data to CD for later analysis - G&I Plant: record time, injection rate, surface injection pressure and calculated bottom hole injection pressure on the GNi Step Rate Test Data Form at 5 minute intervals. 4. Repeat at 2 bpm, 3 bpm, 4 bpm, 5 bpm, 7 bpm, 9 bpm, 11 bpm, 13 bpm, 15 bpm, 17 bpm, 19 bpm, 21 bpm and max bypass rate. 5. Reduce rate to <3 bpm and POOH with E-line tools. Forward log and data to Mike Bill, MB 7-5 (billml~bp.com) GNI-04 Waterflow LoA 1. Rig up E-Line RST/GRICCL in waterflow mode for upward water flow. 2. Reduce injection rate to <3 bpm RIH to 7150' MD, keeping the too! above the top perforation at 7175' MD. Note: Monitor inner and outer annulus pressures. BMed as necessary. 3. Increase injection rate to maximum sustainable bypass injection rate (+f- 20 bpm}. 4. Make 10 waterflow log stops with the RST detectors at +/- 7150', 7100', 7025', 6~0', 6750', 6535', 6320', 6085', 5575', and 5125' MD. 5. Reduce injection rate to <3 bpm. POOH with E-line tool. 6. Contact DS 4 and swap injection to r aced water. Restart water injection at maximum constant rate (18-22 bpm). Note: Monitor inner and otrter annulus pressures. Bleed annuli as necessary. Forward log and data to Mike Bill, MB 7-5 (billml~bp.com) Well Surveillance Grind 8 [eject 3 GNt-04 MIT-IA during infection, EPA/AOGCC Witnessed -see attached Wireline Work Request 1. Notify EPA of upcoming test to allow a rnritness to be present. 2. MIT-lA should be performed while the well is injecting water at constant rate and temperature, and at least 2 days after the start of produced water injection to allow the well to be thermally stable. 3. Notify AOGCC 24 hours in advance of the MIT-IA. Install a 2 pen Barton pressure recorder with a circular chart (or equivalent] to document the IA and tubing pressures during the test. 4. If a nitrogen cap has been placed in the inner annulus, displace the nitrogen with diesel using the open ended control tine to fluid pack the annulus. 5. Pressure the inner annulus to over 2000 psi. Monitor pressure for 30 minutes. The Class I permit requires: the annulus must not decline more than 10% in 30 minutes and must show a stabilizing tendency. A stabil¢ing tendency means the pressure may not decline more than 1/3 of the total loss in the last half of the test period. If this stabilization criterion is not met, the test may be extended. 6. Document the MIT-lA and forward a copy of the chart and report to Mike Bill, MB 7-5. 7. After passing the MIT-IA, pEace a nitrrogen cushion in the inner annulus using the 3/8" control fine. The fluid level should be 100-200 feet. Well Surveillance Grind 8~ Inject 4 GNI-04 Surface Pressure Fall Off Test - to be aerformed after at least 4 days of PW Infection. 1. Service the injecting GNI well Wing Valve and "Sputter" Valve to insure both valves sea(. 2. Rig up Halliburton Spartek surface pressure gauge to the GNI well tree cap at Least one day before the well is shut in. The Halliburton gauge may tie installed in parallel with the wellhead gauge on the tree cap. Provide thermal isolation by placing an insulated endosure around the Halliburton gauge, if possible located away from the well house heater. if possible, reset the GNI well house heater thermostat to minimize the number of on-off cyder. 3. Open the Swab Valve and needle valves between the welt and the gauges. Program the Halliburton gauge for 5 second irrtervals for the entire test. 4. There should be no vac truck deliveries taken during the 24 hours prior to beginning the falloff test. Constant infection rate durinca this period is critical for data aualiri and anatxss. 5. Block open the GNI-04 Surface Safety Valve (SSV) for the SPFO test. Do not close Master Valve. Swab Valve or Surface Safety Valve during the test. 6. If possible, delay freeze protection unfit after SPFO. Otherwise, freeze protect the well tine and well with methanoVwater at the same rate (if possible) as the water flush.. 7. Contact SIP to inform them of a short term interruption in injection. 8. Shut in well by closing the Ong Valve as fast as possible. Immediately close the GNI - 04 weR "Sputter" Yalve located behind ~ GNi-02A well house to ir~ur9e iaoia4on of well GNf-04. 9. After GNt-04 is isolated, immediately open the next GNI well "Spotter Valve and Wing Valve to begin injection. 10. Inspect the well house at least every 6 hours to insure no leaks develop.. 11. Record the pressure falloff for 48 hours (2 days) after the well is shut in. 12. Rig down Halliburton gauge and notify the G8! plant. 13. Immediately freeze protect welt GNI-04. 14. Forward raw and any processed data to Mike Bill, MB 7-5 (billml rLDbp.com). Data Pruning Mode: The pressure gauge wiN be set to retard surface injection pressure every 4 seconds for the entire test. Halliburton's "pruning" program may be utilized to record d.5 psi changes or every 2 minutes. Well Surveillance Grind $~ Inject 11 /21 /07 Schlumberg~r N0.4509 Alaska Data & Consulting Services Company: State of Alaska 2525 Gambell Street, Suite 400 Alaska Oil 8 Gas Cons Comm Anchorage, AK 99503-2838 Attn: Christine Mahnken ATTN: Beth 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: P.Bay, Milne Pt., Endicott Wall _Inh ft I .... ne~~.:..H..., n_._ Z-10 11676974 GLS =--~=- -- ' ' 11/11/07 06-16 11686797 PPROF & RS ' ~ (" _ (": ~~~' 11/15/07 1 MPL-33 11661179 MEM INJECTION PROFILE (_) 3 a~ ~~ 'r ,~ ry - '"" 11113/07 1 MPF-25 11846827 USIT / '`} ~"- q y ~ a., 11/10/07 1 GNI-04 11846828 USIT ° ° ':"-,._ i ~'".!._ 11/11/07 1 OWDW-SW 11626128 RST a .x°~ "r"' ~~'-'"~ tr °a~`~~='~r- 10/10/07 1 1 3-35/L-36 11630502 RST ? ~~" ~°y- , ~ ~ ~, ~` - > d ~:~ 09109/07 1 1 15-26B 11661165 MCNL ,r{) /' =' ~ ~.t °,~ ~ 08124/07 1 1 05-36A 10928638 MCNL ~~~ -' ~~-- )';7_ r`•, '~= b'~5 """A. ' ' 06/11/05 1 1 07-16A 11216211 MCNL -, - '~ ~~' ~- I'~ ~' ' •f 08/27/06 1 1 2-28B/0-19 11638650 RST )~;~;~ - ~,~_~lr ~ i°~ 1~"a 07/05/07 1 1 07-02A 11649983 MCNL ~~ '; - t71~''is ~- -- ~. 3 r 08107/07 1 1 N-27 40015763 OH MWD/LWD EDIT 1 ? ..-:+?a ; -° ~ -°"z-+, 09111/07 2 1 . ~~r...~ r...........~...,,,~ ..~..~... ... .~..~......~ .,..., nc ~ a.nlv~.v ~n~~vv,r:a-Frr~.n I v: BP Exploration (Alaska) Inc. --- t~ _ ~. ~' .i. Petrotechnical Data Center LR2-1 ,; 900 E. Benson Blvd. Anchorage, Alaska 99508 ,. Date Delivered: aii~ ~ ~ 3 ;t~iit158i->~ 4.aF Alaska Data & Consulting Services 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2,83a~ ATTN: Beth ~'~ Received b ~ ~, ,~~ ~ ~, ~"~ yl~ 11/12/07 ~~i~tl~~Lf~I1~Pr NO. 4496 Alaska Data & Consulting Services Company: State of Alaska 2525 Gambetl Street, Suite 400 Alaska Oil & Gas Cons Comm Anchorage, AK 99503-2838 Attn: Christine Mahnken ATTN: Beth 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: P.Bay, Lisburne Wall _Inla i! 1 .... r1e~~ ..t:.,.. n~F., o~ n,. ~... ~n L3-08 11637143 LDL - C f 10/27/07 1 L3-08 11637143 LDL -. C 10/28/07 1 N-12 11626132 LDL ~ ~ -~/~ 11/03/07 1 14-18B 11637368 ISOLATION SCANNER ~-- 10/26/07 1 NGI-13A 11637144 CEMENT BOND & IMAGE LOG 10/28107 1 GNI-04 11676971 USIT ~-- ~'~- 11/05107 1 r LGfaJG fall nl~IV YYLGLla7C RCai Clrl 6T JIV IYInIV HIVU RG 1 UKn111VV VIVO liVY7 tAl. r1 I V: BP Exploration (Alaska) Inc. Petrotechnical Data Center LR2-1 y, - F; . 900 E. Benson Blvd. Anchorage, Alaska 99508 Date Delivered: Alaska Data & Consulting Services 2525 Gambetl Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth Received by: ~. ~~ ~ d gy data Gyrodata Incorporated 1682 W. Sam Houston Pkwy. N. Houston, Texas 77043 713/461-3146 Fax: 713/461-0920 November 15, 2007 State of Alaska - AQGCC Attn: Christine Mahnken 333 W. 7th Ave, Suite 100 Anchorage, Alaska 99501 Re: Surfcote Pad.., Well #~GNI-04 Prudhoe Bay, Alaska CJ Enclosed, please find two (2) copies, and one (1) disk of the compteted survey for the above referenced weft. We would tike to take this opportunity to thank you. for using Gyrodata, and we look forward to serving you in the future. Sincerely, .~' ~~~" ~~f~~~ , Rob Shoup %~ North American Regional Manager RS:tf Serving the Worldwide Energy Industry with Precision Survey Instrumentation gyr data Gyrodata Incorporated 1682 W. Sam Houston Pkwy. N. Houston, Texas 77043 713/461-3146 Fax: 713/461-0920 SURVEY REPORT BP Surfcote Pad #GNf-04 Prudhoe Bay, AK AK1007G_557 30 Oct 2007 Serving the Worldwide Energy Industry with Precision Survey Instrumentation ~~~~ ~t ~ A Gyrodata Directional Survey for BP EXPLORATION (ALASKA) INC. Lease: Surfcote Pad Well: GNI-04, Location: Nabors #7ES, Prudhoe Bay, Alaska Job Number: AK1007G 557 Run Date: 30 Oct 2007 Surveyor: Steve Thompson Calculation Method: MINIMUM CURVATURE Survey Latitude: 70.282966 deg. N Longitude: 148.244009 deg. W Azimuth Correction: Gyro: Bearings are Relative to True North • Vertical Section Calculated from Well Head Location Closure Calculated from Well Head Location Horizontal Coordinates Calculated from Well Head Location BP Exploration (Alaska) Inc. Lease: Surfcote Pad Well: GNI-04 Location: Nabors #7ES, Prudhoe Bay, Alaska Job Number: AK1007G 557 A Gyrodata Directional Survey MEASURED I N C L AZIMUTH BORE HOLE DOGLEG VERTICAL CLOSURE DEPTH BEARING SEVERITY DEPTH DIST. AZIMUTH feet deg. deg. deg. min. deg./ feet feet deg. 100 ft. 0.00 0.00 0.00 N 0 0 E 0.00 0.00 0.0 0.0 0 - 540 FT. RATE GYROSCOPIC MULTISHOT SURVEY ALL MEASURED DEPTHS AND COORDINATES REFERENCED TO NABORS #7ES R.K.B. 100.00 0.22 237.16 S 57 9 W 0.22 100.00 0.2 237.2 200.00 0.28 244.01 S 64 1 W 0.07 200.00 0.6 239.8 300.00 1.75 299.38 N 60 37 W 1.60 299.98 2.1 278.7 400.00 3.87 302.81 N 57 11 W 2.12 399.86 6.9 294.8 500.00 5.88 301.34 N 58 39 W 2.02 499.49 15.4 298.8 540.00 6.91 300.33 N 59 40 W 2.60 539.24 19.8 299.2 Final Station Closure: Distance: 19.81 ft Az: 299.21 deg. HORIZONTAL COORDINATES feet 0.00 N 0.00 E 0.10 S 0.16W 0.32 S 0.55 W 0.32 N 2.10 W 2.90 N 6.26 W 7.39 N 13.46 W 9.67 N 17.29 W 2 ~. SCHLUMBERGER Survey report Client ...................: BP Exploration (Alaska) Inc. Field ....................: Prudhoe Bay Well .....................: GNI-04 API number ...............: 50-02923367-00 Engineer .................: Na Woo Kim RIG ....................... Nabors 7ES STATE :...................: Alaska ----- Survey calculation methods------------- Method for positions.....: Minimum curvature Method for DLS...........: Mason & Taylor ----- Depth reference ----------------------- Permanent datum..........: MEAN SEA LEVEL Depth reference..........: Driller's Pipe Tally GL above permanent.......: 19.10 ft KB above permanent.......: N1A ft DF above permanent.......: 47.60 ft ----- Vertical section origin---------------- Latitude (+N/S-).........: 0.00 ft Departure (+E/W-)........: 0.55 ft ----- Platform reference point--------------- Latitude (+N/S-).........: -999.25 ft Departure (+E/W-)........: -999.25 ft Azimuth from Vsect Origin to target: 296.97 degrees 7-Nov-2007 11:27:15 Page 1 of 4 Spud date ................: 29-Oct-2007 Last survey date.........: 07-Nov-07 Total accepted surveys...: 80 MD of first survey.......: 0.00 ft MD of last survey........: 7463.00 ft ----- Geomagnetic data ---------------------- Magnetic model...........: BGGM version 2007 Magnetic date ............: 04-Nov-2007 Magnetic field strength..: 57677.87 GAMA Magnetic dec (+E/W-).....: 23.74 degrees Magnetic dip .............: 80.96 degrees ----- MWD survey Reference Reference G ............... Reference H ..............: Reference Dip ............: Tolerance of G............ Tolerance of H............ Tolerance of Dip.........: Criteria --------- 1002.68 meal 57678.00 LAMA 80.96 degrees (+/-) 2.50 meal (+/-)300.00 LAMA (+/-) 0.45 degrees ----- Corrections --------------------------- Magnetic dec (+E/W-).....: 23.74 degrees Grid convergence (+EJW-}.: 0.00 degrees Total az corr (+E/W-)....: 23.74 degrees (Total az corr = magnetic dec - grid cony) 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 • ~v~-rr7 SCHLUMBERGER Survey Report 7-Nov-2007 11:27:15 Page 2 of 4 Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ t ool Corr - (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) 1 0.00 0.00 296.96 0.00 0.00 0.49 0.00 0.00 0.00 0.00 0.00 TIP None 2 100.00 0.22 237.16 100.00 100.00 0.58 -0.10 -0.16 0.19 237.16 0.22 BP_ GYD CT DMS 3 200.00 0.28 244.01 100.00 200.00 0.83 -0.32 -0.54 0.63 239.82 0.07 BP_ GYD CT DMS 4 300.00 1.75 299.38 100.00 299.98 2.50 0.33 -2.09 2.12 278.88 1.61 BP_ GYD CT DMS 5 400.00 3.87 302.81 100.00 399.86 7.38 2.90 -6.26 6.90 294.89 2.13 BP GYD CT DMS 6 500.00 5.88 301.34 100.00 499.49 15.85 7.40 -13.47 15.37 298.77 2.01 BP_ GYD CT DMS 7 567.89 7.51 296.15 67.89 566.91 23.75 11.16 -20.42 23.28 298.66 2.56 BP_ MWD+IFR+MS 8 657.38 9.09 299.77 89.49 655.46 36.66 17.25 -31.81 36.19 298.47 1.86 BP_ MWD+IFR+MS 9 746.39 11.26 300.08 89.01 743.07 52.37 25.10 -45.44 51.91 298.92 2.44 BP_ MWD+IFR+MS 10 836.95 13.46 297.96 90.56 831.53 71.73 34.47 -62.40 71.29 298.92 2.48 BP MWD+IFR+MS 11 931.74 15.05 298.36 94.79 923.39 95.07 45.49 -82.97 94.63 298.73 1.68 BP_ MWD+IFR+MS 12 1025.79 15.37 297.34 94.05 1014.15 119.74 57.02 -104.79 119.30 298.55 0.44 BP_ MWD+IFR+MS 13 1121.55 16.67 296.60 95.76 1106.19 146.17 68.99 -128.35 145.71 298.26 1.37 BP_ MWD+IFR+MS 14 1215.51 17.69 297.63 93.96 1195.96 173.92 81.65 -153.04 173.46 298.08 1.13 BP_ MWD+IFR+MS 15 1310.77 15.96 298.65 95.26 1287.13 201.48 94.64 -177.36 201.03 298.08 1.84 BP MWD+IFR+MS 16 1405.72 15.95 298.83 94.95 1378.43 227.57 107.19 -200.25 227.13 298.16 0.05 BP_ MWD+IFR+MS 17 1497.62 17.10 299.68 91.90 1466.53 253.69 119.97 -223.05 253.27 298.27 1.28 BP_ MWD+IFR+MS 18 1594.42 17.44 301.58 96.80 1558.97 282.36 134.61 -247.77 281.98 298.52 0.68 BP_ MWD+IFR+MS 19 1688.28 19.23 301.19 93.86 1648.06 311.80 149.99 -272.98 311.47 298.79 1.91 BP_ MWD+IFR+MS 20 1779.89 22.73 301.53 91.61 1733.58 344.50 167.06 -300.98 344.23 299.03 3.82 BP MWD+IFR+MS 21 1876.76 22.68 302.09 96.87 1822.94 381.76 186.77 -332.75 381.58 299.30 0.23 BP_ MWD+IFR+MS 22 1972.91 25.07 301.73 96.15 1910.86 420.52 207.33 -365.79 420.46 299.55 2.49 BP_ MWD+IFR+MS 23 2067.38 27.45 301.21 94.47 1995.57 462.19 229.14 -401.44 462.23 299.72 2.53 BP_ MWD+IFR+MS 24 2163.10 28.91 299.24 95.72 2079.95 507.31 251.88 -440.50 507.43 299.76 1.81 BP_ MWD+IFR+MS 25 2257.64 30.28 294.95 94.54 2162.16 553.98 273.10 -482.06 554.04 299.53 2.67 BP MWD+IFR+MS 26 2351.87 28.68 294.18 94.23 2244.19 600.31 292.38 -524.23 600.25 299.15 1.74 BP_ MWD+IFR+MS 27 2444.78 26.20 295.37 92.91 2326.64 643.08 310.31 -563.10 642.94 298.86 2.73 BP_ MWD+IFR+MS 28 2539.43 26.94 294.85 94.65 2411.29 685.40 328.27 -601.44 685.19 298.63 0.82 BP_ MWD+IFR+MS 29 2635.82 28.56 294.73 96.39 2496.59 730.24 347.09 -642.18 729.98 298.39 1.68 BP_ MWD+IFR+MS 30 2730.01 29.07 294.66 94.19 2579.12 775.60 366.05 -683.43 775.29 298.17 0.54 BP_ MWD+IFR+MS L~ • SCHLUMBERGER Survey Report 7-Nov-2007 11:27:15 Page 3 of 4 Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total 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) ----- ------ 31 2827.64 29.72 293.58 97.63 2664.18 823.46 385.63 -727.17 823.09 297.94 0.86 BP_ MWD+IFR+MS 32 2921.45 30.53 293.96 93.81 2745.32 870.47 404.61 -770.25 870.06 297.71 0.89 BP_ MWD+IFR+MS 33 3015.65 30.80 295.21 94.20 2826.35 918.47 424.60 -813.94 918.03 297.55 0.73 BP_ MWD+IFR+MS 34 3109.92 31.32 294.54 94.27 2907.10 967.07 445.05 -858.06 966.62 297.41 0.66 BP_ MWD+IFR+MS 35 3203.72 32.74 293.57 93.80 2986.62 1016.76 465.32 -903.49 1016.28 297.25 1.61 BP MWD+IFR+MS 36 3300.53 32.22 292.03 96.81 3068.29 1068.60 485.47 -951.41 1068.11 297.03 1.01 BP_ MWD+IFR+MS 37 3395.86 31.50 290.98 95.33 3149.26 1118.69 503.92 -998.22 1118.21 296.79 0.95 BP_ MWD+IFR+MS 38 3489.13 30.23 292.86 93.27 3229.32 1166.35 521.77 -1042.61 1165.88 296.59 1.71 BP_ MWD+IFR+MS 39 3584.38 27.70 295.72 95.25 3312.65 1212.41 540.70 -1084.66 1211.96 296.50 3.03 BP_ MWD+IFR+MS 40 3678.97 27.99 297.82 94.59 3396.29 1256.58 560.60 -1124.10 1256.13 296.51 1.08 BP MWD+IFR+MS 41 3774.85 28.41 299.19 95.88 3480.79 1301.87 582.22 -1163.91 1301.41 296.58 0.80 BP_ MWD+IFR+MS 42 3869.41 28.03 296.27 94.56 3564.12 1346.57 603.03 -1203.48 1346.10 296.61 1.51 BP_ MWD+IFR+MS 43 3963.73 28.24 291.69 94.32 3647.30 1390.95 621.08 -1244.09 1390.50 296.53 2.30 BP_ MWD+IFR+MS 44 4058.68 27.89 292.26 94.95 3731.09 1435.45 637.80 -1285.51 1435.04 296.39 0.46 BP_ MWD+IFR+MS 45 4153.25 26.74 295.29 94.57 3815.11 1478.77 655.27 -1325.22 1478.38 296.31 1.91 BP_ MWD+IFR+MS 46 4172.89 26.57 295.64 19.64 3832.67 1487.57 659.06 -1333.18 1487.19 296.31 1.18 BP_ MWD+IFR+MS 47 4288.88 26.70 295.08 115.99 3936.35 1539.55 681.33 -1380.17 1539.18 296.27 0.24 BP_ MWD+IFR+MS 48 4383.75 26.54 296.53 94.87 4021.16 1582.05 699.83 -1418.43 1581.68 296.26 0.71 BP_ MWD+IFR+MS 49 4477.37 26.34 295.33 93.62 4104.99 1623.73 718.06 -1455.92 1623.36 296.25 0.61 BP_ MWD+IFR+MS 50 4571.74 26.04 295.14 94.37 4189.67 1665.36 735.81 -1493.60 1665.01 296.23 0.33 BP MWD+IFR+MS 51 4667.44 25.91 295.56 95.70 4275.71 1707.25 753.76 -1531.47 1706.92 296.21 0.24 BP_ MWD+IFR+MS • 52 4762.45 25.80 294.81 95.01 4361.21 1748.67 771.39 -1568.97 1748.34 296.18 0.36 BP_ MWD+IFR+MS 53 4856.35 25.87 294.47 93.90 4445.72 1789.55 788.45 -1606.16 1789.25 296.15 0.17 BP_ MWD+IFR+MS 54 4951.47 25.55 294.38 95.12 4531.42 1830.78 805.51 -1643.73 1830.49 296.11 0.34 BP_ MWD+IFR+MS 55 5045.25 26.02 295.50 93.78 4615.87 1871.54 822.72 -1680.72 1871.28 296.08 0.72 BP_ MWD+IFR+MS 56 5139.59 26.34 298.55 94.34 4700.53 1913.15 841.63 -1717.78 1912.88 296.10 1.47 BP_ MWD+IFR+MS 57 5234.88 26.80 299.93 95.29 4785.76 1955.74 862.45 -1754.97 1955.44 296.17 0.81 BP_ MWD+IFR+MS 58 5330.99 26.73 301.12 96.11 4871.57 1998.93 884.43 -1792.25 1998.60 296.27 0.56 BP_ MWD+IFR+MS 59 5423.81 27.45 300.94 92.82 4954.21 2041.10 906.22 -1828.47 2040.72 296.36 0.78 BP_ MWD+IFR+MS 60 5521.14 27.88 301.83 97.33 5040.41 2086.15 929.76 -1867.05 2085.74 296.47 0.61 BP_ MWD+IFR+MS SCHLUMBERGER Survey Report 7 -Nov-2007 11:27:15 Page 4 of 4 Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total 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 5616.33 27.44 301.37 95.19 5124.72 2130.20 952.91 - 1904.68 2129.76 296.58 0.51 BP _MWD+IFR+MS 62 5710.56 28.08 301.50 94.23 5208.11 2173.95 975.80 - 1942.13 2173.49 296.68 0.68 BP _MWD+IFR+MS 63 5806.31 28.15 301.90 95.75 5292.56 2218.92 999.51 - 1980.52 2218.44 296.78 0.21 BP _MWD+IFR+MS 64 5901.21 27.93 302.37 94.90 5376.32 2263.35 1023.24 - 2018.30 2262.86 296.88 0.33 BP _MWD+IFR+MS 65 5995.01 27.99 301.03 93.80 5459.17 2307.18 1046.35 - 2055.71 2306.69 296.98 0.67 BP MWD+IFR+MS 66 6089.77 27.79 298.85 94.76 5542.93 2351.44 1068.47 - 2094.12 2350.95 297.03 1.10 BP _MWD+IFR+MS • 67 6183.46 27.64 298.01 93.69 5625.87 2394.99 1089.22 - 2132.43 2394.51 297.06 0.45 BP _MWD+IFR+MS 68 6278.39 27.00 295.00 94.93 5710.21 2438.55 1108.67 - 2171.41 2438.06 297.05 1.60 BP _MWD+IFR+MS 69 6374.00 26.84 292.93 95.61 5795.47 2481.77 1126.25 - 2210.96 2481.28 296.99 0.99 BP _MWD+IFR+MS 70 6469.60 27.32 294.29 95.60 5880.59 2525.21 1143.68 - 2250.83 2524.72 296.94 0.82 BP MWD+IFR+MS 71 6563.73 27.55 294.83 94.13 5964.13 2568.54 1161.71 - 2290.27 2568.06 296.90 0.36 BP _MWD+IFR+MS 72 6659.36 27.54 294.63 95.63 6048.92 2612.73 1180.21 - 2330.44 2612.25 296.86 0.10 BP MWD+IFR+MS 73 6749.39 27.17 294.17 90.03 6128.88 2654.06 1197.30 - 2368.11 2653.58 296.82 0.47 BP _MWD+IFR+MS 74 6847.48 27.88 298.12 98.09 6215.88 2699.36 1217.28 - 2408.78 2698.89 296.81 2.00 BP MWD+IFR+MS 75 6942.64 28.32 298.34 95.16 6299.82 2744.17 1238.48 - 2448.27 2743.69 296.83 0.48 BP MWD+IFR+MS 76 7038.40 28.52 299.25 95.76 6384.04 2789.72 1260.43 - 2488.21 2789.24 296.87 0.50 BP _MWD+IFR+MS 77 7133.45 28.31 299.41 95.05 6467.64 2834.92 1282.59 - 2527.64 2834.43 296.90 0.24 BP MWD+IFR+MS 78 7227.96 28.64 299.03 94.51 6550.71 2879.94 1304.59 - 2566.96 2879.45 296.94 0.40 BP _MWD+IFR+MS 79 7323.59 28.66 298.93 95.63 6634.64 2925.76 1326.80 - 2607.07 2925.27 296.97 0.05 BP _MWD+IFR+MS 80 7376.24 28.63 298.94 52.65 6680.84 2950.99 1339.01 - 2629.16 2950.50 296.99 O.Ob BP MWD+IFR+MS 81 7463.00 28.63 298.94 86.76 6756.99 2992.53 1359.13 -2665.54 2992.05 297.02 0.00 Projected TD • [(c)2007 IDEAL ID12_OC_13] ~ ~ Drilling & Measurements MWD/LWD Log Product Delivery Customer BP Exploration (Alaska) Inc. Dispatched To: Christine Mahnken Well No GNI-04 Date Dispatched: 15-Nov-07 Installation/Rig Nabors-7ES Dispatched By: 5 LWD Log Delivery V2.1, 03-06-06 Data No Of Prints No of Floppies Surveys 2 1 Received By: Please sign and return to: 1 Drilling & Measurements LWD Division ~ ~' ? 2525 Gambell Street, Suite 400 I U y v (~- Anchorage, Alaska 99501 fclarke3C~slb.com Fax:907-561-8317 ~ t~7 ~ ll 7 GT1I-04 Surface Casing Page 1 0~ ~ i ~- Maunder, Thomas E (DOA) From: Nadem, Mehrdad [NademM a~BP.com] Sent: Monday, November 05, 2007 4:22 PM To: Maunder, Thomas E (DOA) Subject: RE: GNI-04 Surface Casing Tom, ~ add - ~ ~ We encountered 1 bph losses on November 2, and I do not recall loss control issues while the surface hole was being drilled. We did have tight spots that had to be worked, had to contend with running gravel, and did get a fair amount of wood at surface. There was a tight spot that proved to be persisting. We found out that the bit was shut 7/7, after tripping out to determine why the driller could not build a dogleg. I believe the hole wash out resulted necessitated atwo-stage cement job. The rig did a greatjob in keeping up the mud viscosity, and I think that was instrumental in success of this phase. Please let me know if you need additional information. I the 12-1/4" hole would not be as problematic. Regards, Mehrdad Nadem Operotions Drilling Engineer Phone: 907/564-5941 Cell: 907/440-0213 Email: nndemm@bp.com From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Monday, November 05, 2007 8:04 AM To: Nadem, Mehrdad Subject: RE: GNI-04 Surface Casing Mehrdad, This is not a problem. The AOGCC regulatory requirement is 50% of the BOP rating which in this case would be 2500 psi. That requirement is a minimum. With regard to the surface casing cementing, I'd appreciate some additional information. Were difficulties experienced with lost returns? Look forward to your reply. Tom Maunder, PE AOGCC From: Nadem, Mehrdad [mailto:NademM@BP.com] Sent: Monday, November 05, 2007 7;29 AM To: Maunder, Thomas E (DOA) Subject: GNI-04 Surface Casing Tom, We would like to pressure test the 13-3l8" surface casing to 3,500 psi instead of 4,000 psi. Please send me a note indicating if AOGCC is approving this request. Regards, i 1i6i2oa~ I Maunder, Thomas E (DOA) From: Nadem, Mehrdad [NademM@BP.com] Sent: Sunday, November 04, 2007 6:26 PM To: Maunder, Thomas E (DOA) Subject: Update: GNI-04 -Surface Casing Tom: This is to notify the AOGCC that 7ES was able to circulate cement to surface through the TAM port collar. Best Regards, Mehrdad Maunder, Thomas E (DOA) From: Nadem, Mehrdad [NademM~BP.comJ Sent: Saturday, November 03, 2007 9:58 PM To: Maunder, Thomas E (DOA) Cc• Engel, Hany R; Bill, Michael L (Natchiq); NSU, ADW Drlg Rig 7ES; Tirpack, Robert B Subject: GNI-04 Cementing operations Tom, This is notify AOGCC that cement could not be circulated to surface during the primary cementing operation of the 13-3/8" surface casing at GNI-04. This event was also reported to the AOGCC staff, Mr. Jones, on the Slope. 7ES plans to circulate cement through the TAM port collat at 1,000' MD. I will send a follow up report apprising you of the status of the secondary cementing operation. Regards, Mehrdad Nadem Page l of 1 Regg, James B (DOA) From: Jones, Jeffery B (DOA) Sent: Sunday, November 04, 2007 4:05 PM To: Regg, James B (DOA) Subject: GNI-04 cement Top Job Hello Jim, Mike Dinger, the BPXA rep on Nabors 7ES notified me at 1930 hrs. on 11-3-07 that he didn't get cement to surface on well GNI-04 and would circulate and perform a top job via the TAM port collar. Talib with EPA was on location and witnessed the operation. Mike notified me today that the top job was successful. Thanks, Jeff 11/5/2007 RE: GNI-04 Maunder, Thomas E (DQA) Page 1 of 1 From: Maunder, Thomas E (DOA) Sent: Tuesday, October 23, 2007 3:53 PM To: 'Nadem, Mehrdad' Subject: RE: GNf-04 Thanks for the information. Nothing further is needed. I will place a copy in the well file. Good luck with the operations. Tom Maunder, PE AOGCC From: Nadem, Mehrdad [mailto:NademM@BP.com] Sent: Tuesday, October 23, 2007 3:.07 PM To: Nadem, Mehrdad; Maunder, Thomas E (DOA) Subject: RE: GNI-04 Tom, Hope al! are well with you. 7ES is expected to move to GNI-04 this Friday. Attached is the revised schematic diagram for GNI-04. This schematic is modified to reflect moving down the ES Cementer to 4,320' MD from 4,220' MD. Please note the correction to the location of the 3/8" SS bands. Additionally, we would like to use seawater as the completion fluid. The permit to drill noted 9.5 ppg as the completion fluid. We plan to perforate this well post rig with Wireline. I am available to provide you with additional information. Mehrdad Nadem Operations Drilling Engineer Phone: 907/564-5941 Cell: 907/440-0213 Email: nademm@bp.com «06-surfcote~ad. jpg» ~o'~-~t~... 10/23/2007 TRH- h#iU Lirl EL LHEd. D _. r~ F ~: P, CT (W.7C~ P. - ............._ . . . kH.ELEi - BF. ELE'~~ - HLI P - NCO' I14.R~QW- -o[~ 1 `r` Cvb m Tai U - X30' _-_ hoiir~imum IU = 5.cr3~' l3' 4,910' x4,:?SiJ• HES R halF'PLE T' T BG, .~#, L-sp, p_i I:;r '1 b pf - I D = B. 1 ~4" P ERFQ P.°,Tl] r~ S UlAl.l°, ff~r PEFUiG: SLOLt~ff,C6Lilhal^1TS3~4'~ r,r#:LERTTLiP PERF: Mo~:P.eNrb Prr~~7ri:ri_~Y CIB rear YKbrCalFerttl~ SCrE SPF r~ITER5i.4L iIF~YJr~ CW,TE _+tiJ3 ~, p PB TD .7;305!; G N I-0~ _ ~', Cor~tr~~l Lirle car3ppa,y' to T' Tubin~~ 4,3'Lr - ES C~mentPr - 4h917 - ?~. HEO"P' NiF IU = F.9$.:i' -- 4,9317 - 9-6r'~' EF<::F : =3 F'P`R -4,9Fi r - ; ° HES F; N NIF, IC-~.9r~? } n0i r - ; " TB G T.~l L'dU LEG ,',-~56 - TC~ i,4~F' - 9-5,~~" CS~3 - 4?#, L-?0, BTC-fo1, ID=S.BS1 CBL of Surface Casing on GNI-04 Page 1 of 1 Maunder, Thomas E (DOA) From: Nadem, Mehrdad [NademM@BP.com] Sent: Friday, September 21, 2007 7:12 AM ~-~~ ~. " ~, To: Maunder, Thomas E (DOA); Hobbs, Greg S (ANC) Subject: RE: CBL of Surface Casing on GM-04 Tom, I am in Houston and for some odd reason I could not send Emails out on my BP computer from the hotels. No problems here at Chevron building. Yes, we do plan to run aCBL-USIT in the surface casing. Best Regards, Mehrdad From: Maunder, Thomas E (DOA) [mailtoaom.maunder@alaska.gov] Sent: Tuesday, September 18, 2007 3:53 PM To: Hobbs, Greg S (ANC); Nadem, Mehrdad Subject: RE: CBI_ of Surface Casing on GNI-04 Thanks Greg and Mehrdad. No need to send a corrected operations summary. An email note if the log will be run will suffice. Tom Maunder, PE AOGCC From: Hobbs, Greg S (ANC) [mailto:Greg.Hobbs@bp.com] Sent: Tuesday, September 18, 2007 3:48 PM To: Nadem, Mehrdad Cc: Maunder, Thomas E (DOA) Subject: CBL of Surface Casing on GNI-04 Mehrdad- Tom noted that your operations summary did not contain a CBL of the surface casing that you stated would be done in a conversaion with him. I told him that we would run the log, and you would follow up with a corrected operations summary upon your return- Thanks! Greg 9/21 /2007 • SARAH PALlN, GOVERNOR S~ OIIl ~D ~S 333 W. 7th AVENUE, SUITE 100 ~'~~ CO1~T5ER'QA~`I011T COM11II55IO1Q ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Greg Hobbs Senior Drilling Engineer BP Exploration Alaska Inc. PO Box 196612 Anchorage, AK 99519-6612 Re: Prudhoe Bay Field, Prudhoe Bay Oil Pool, PBU GNI-04 BP Exploration Alaska Inc. Permit No: 207-117 Surface Location: 4190' FSL, 1011' FEL, SEC. 26, T 11 N, R 15E, UM Bottomhole Location: 263' FSL, 3671' FEL, SEC. 23, Tl 1N, R15E, UM Dear Mr. Hobbs: Enclosed is the approved application for permit to drill the above referenced service well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the 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. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (90,7~"~59-3607 (pager). DATED this ~ day of September, 2007 cc: Department of Fish 8v Game, Habitat Section w/o enc?. Department of Environmental Conservation w/o encl. ~.,z..F O Tv ~..~ STATE OF ALASK~ 5 0 ~ D~ ALAS~IL AND GAS CONSERVATION COMMI~N ~ ~1 PERMIT 7CI®k~1~6~s Cons. Commission 20 AAC 25.005 Anchorage Revised: 09/04/07, See Attached 1 a. Type of work ® Drill ^ Redrill ^ Re-Entry 1 b. Current Well Class ^ Exploratory ^ Development Gas ®Service ^ Multiple Zone ^ Stratigraphic Test ^ Development Oil ^ Single Zone 1 c. Specify if well is proposed for: ^Coalbed Methane ^ Gas Hydrates ^ Shale Gas 2. Operator Name: BP Exploration (Alaska) Inc. 5. Bond: ®6lanket ^ Single Well Bond No. 6194193 - 11. Well Name and Number: PBU GNI-04 ` 3. Address: P.O. Box 196612, Anchorage, Alaska 99519-6612 6. Proposed Depth: MD 7455 _ TVD 6738- 12. Field /Pool(s): Prudhoe Bay Field / Prudhoe Bay 4a. Location of Well (Governmental Section): Surface: ~ 4190' FSL 1011' FEL SEC 26 T11 N R15E UM (As Staked) 7. Property Designation: ADL 028323 Pool - , , . , , , Top of Productive Horizon: 200' FSL, 3507 FEL, SEC. 23, T11 N, R15E, UM ~ 8• Land Use Permit: 13. Approximate Spud Date: October 10, 2007 Total Depth: 263' FSL, 3671' FEL, SEC. 23, T11 N, R15E, UM r 9. Acres in Property: 2560 14. Distance to Nearest Property: 24,420' 4b. Location of Well (State Base Plane Coordinates): Surface: x-716973 y- 5956183 Zone-ASP4 10. KB Elevation Plan (Height above GL): 62.8 feet 15. Distance to Nearest Well Within Pool: 879' 16. Deviated Wells: Kickoff Depth: 400 feet Maximum Hole An le: 28 de rees 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole: 3095 Surface: 2452 1'8. Casin P 'ram: S ec~catio ns - To - Settin D th -Bo ttom uantit of Cement c.f. or sacks Hole Casin Wei ht Grade Cou lin Len th MD TVD MD TVD includin sta a data 42" 20" 91.5# H-40 Weld 108' Surface Surface 108' 108' 260 sx Arctic Set A rox. 16" 13-3/8" 68# L-80 BTC-M 4204' Surface Surface 4204' 3870' 1965 sx Dee Crete Lite 558 sx'G' 12-1/4" 9-5/8" 47# L-80 BTC-M 74 urface Surf c 7455' 6737' 1241 sx Class' ' 19. PRESE NT 1NELL CONDITION SUMMARY(To be'completed for Redrill and Re-entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effective Depth MD (ft): Effective Depth TVD (ft): Junk (measured): .Casing Length ize Cement Volume MD TVD Conductor /Structural Surface Intermediate Producti n Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments ^ Filing Fee, $100 ^ BOP Sketch ®Drilling Program ^ Time vs Depth Plot ^ Shallow Hazard Analysis ^ Property Plat ^ Diverter Sketch ^ Seabed Report ®Drilling Fluid Program ®20 AAC 25.050 Requirements 21. Verbal Approval: Commission Representative: Date: 22. I hereby certify that the foreg ng is true and correct. Contact Mehrdad Nadem, 564-5941 Printed Name Greg H ~ Title Senior Drilling Engineer Prepared By Name/Number: Si nature Phone 564-4191 Date `' Terrie Hubble, 564-4628 Commission Use Onl Permit To Drill Number: aT0 f/~o API Number: 000 50-0~9 ~..~•~ ~ ~ 0 Permit Approval See cover letter for Date: ' ~ other re uirements Conditions of Approval: ~ ~'`' Si G~~.,~.~.~~i(3.~~,~- t orCS ~bC~tc-C:e'~~..r~~rDl~ ~~~qr,~S. ~j,~ t ~{ ~ C ~ If box is checked, well may not be used o plore for, est, produce Coalbed methane, gas hydr tes, or gas contained shales: WIZGG ~s ` ~ C ~ ~" fs,S I~~Csr~r.i:=~T' Samples Req'd: ^ Yes ~NO Mud Log Req'd: ^ Yes ~No ~„y J-IZS Measures: G~Yes ^ o rect nal Survey Req'd: Yes ^ No Other: ~ `4~cC Kc~r4~;~ ~.cGS~G~`tC °ra' ~C'~%~G'~LL ~.i~C~~:~tG o ~ v ~~ ~h~L~ ) APPROVED BY THE COMMISSION Date ~ ~ ,COMMISSIONER Form 10-401 Revised 12/2005 ~~ ~ l`~~ ~ Submit In Duplicate ORIGiN • To: Thomas Maunder, Petroleum Engineer Alaska Oil & Gas Conservation Commission From: Mehrdad Nadem, ODE Date: August 31, 2007 Re: Amendment to GNI-04 Permit to Drill • by This is an amendment to the GNI-04 Permit to Drill. The major changes in the revised permit are modification of the disposal section, the cementing program, and the operation summary. Segments of the GNI-04 permit needs to be approved by the EPA. This revised plan is being submitted so that identical versions are submitted to both agencies. This plan superseded the permit to drill application submitted on August 29, 2007. The GNI-04 is scheduled to be drilled by Nabors 7ES. The rig is currently scheduled to move onto the well/location on our about October 10, 2007. The plan for this Class I & II disposal well is to drill a 16" surface hole to the top of SV3 sands at approximately 4,204' MD. A 13-3/8" casing will be run and cemented to surface. A 12-1/4" injection hole will be drilled from the surface casing shoe through the targeted Ugnu formation to the West Sak formation at approximately 7,455' MD. A 9-5/8" casing string will then be run and cemented to approximately 20'-50' below the 13-3/8" surface shoe. The 13-3/8" x 9-5/8" annulus to surface will be left open to allow some monitoring of the injection well pressures/activity. 7" injection tubing will be run to complete the well. Please note the injection packer for this 7" tubing (9-5/8" x 7" packer) will be placed at the SV1 marker (top of the injection zone) at 4,960' which is 2,400' above the top of the injection perforations in this well. Therefore, as State regulations specify the injection packer to be within 200' of the top perforation, a wavier will be required for this packer placement. Please note the following Well Plan summary as detailed below: Well Name: GNI-04 Drill and Complete Plan Summary T e of Well service / roducer / in'ector : Injector Tar et X Y Z TVDss Townshi Ran a Section FSL FEL Surface As-Staked 716,973 5,956,183 N/A 11 N 15E 26 4190 1011 Tar et 1 714,440 5,957,400 6,430' 11 N 15E 23 200 3507 BHL 9-5/8" Casin Point 714,274 5,957,459 6,690' 11 N 15E 23 263 3671 AFE Number: NA API Number: To be determined Estimated Start Date: October 10, 2007 O eratin da s: 18.27 Ri Nabors 7ES TMD 7,455' TVD at TD (rkb): 6,737' RKB/GL 28.5'/34.3' RTE 62.8 Well Desi n: Grassroots, Class I /II Injector. 7", 29# BTC-M Completion Current Status: New drill General Well Information: Estimated BHP: 3,060 psi at 6,690' TVD Estimated BHT: 115 deg F at 6,941' TVD GNI-04 Permit to Drill Page 1 • Formation Markers, Hydrocarbon Zones, and Pore Pressures: Est. Formation To s Uncertain Commercial H drocarbon Bearin Est. Pore Press. Est. Pore Press. Formation TVDss feet Yes/No Psi (PP9 EMW NOTE: All formation tops are required from 1000' above proposed KOP to TD for sidetracks NOTE: All formation tops are required from surface to TD for all new wells Base Permafrost (behind surf. cs -1950 +-30 No 878 8.7 SV6 behind surf. cs -2605 +-30 No 1172 8.7 SV5 behind surf. cs -3240 +-30 No 1458 8.7 SV4 behind surf. cs -3355 +-30 No 1510 8.7 SV3 behind surf. cs -3855 +-30 No 1735 8.7 SV2 -4050 10 No 1830 8.7 SV1 -4510 20 No 2050 8.7 UG4 -5000 +-30 No 2250 8.7 UG4A -5020 +-30 No 2280 8.7 UG3 -5350 +-30 No .2440 8.8 UG1 -5980 +-30 No 2850 9.2 Ma -6290 +-30 No 3050 9.3 Mb1 -6325 +-30 No 3075 9.3 Mb2 -6380 +-30 No 3100 9.3 Mc -6475 +-30 No 3140 9.3 WS2 -6510 +-30 No 3155 9.3 Na -6580 +-30 No 3185 9.3 Nb -6600 +-30 No 3195 9.3 Ne -6630 +-30 No 3205 9.3 TD -6660 +-30 No 3075 8.9 OA/WS1 -Not Reached -6705 +-30 No 3080 8.8 Casina/Tubina Proaram: Hole Size Csg/ Tbg O.D. WUFt Grade Connection Length (ft) Top MD/TVD RTE ft Btm MDlTVD RTE ft 42" 20" non-insulated 91.5 H-40 0.438" ID WLD 108 GL 108/108 16" 13-3/8" 68 L-80 BTC-M 4,204 GL 4,204/3,870 12-1/4" 9-5/8" 47 L-80 BTC-M 7,455 GL 7,455/6,737 Tubin 7" 29 L-80 BTC-M 5,100 GL 5,100/4,567 GNI-04 Permit to Drill Page 2 • • Directional• Directional Plan: Schlumber er Feasibilit Stud P3 KOP: 400' MD, be in 1.25/100 build Close A roach Wells: All Wells ass Ma'or Risk Scan, reference anti-collision re ort Surve Pro ram: MWD 2300' ,MWD + IFR + MS 7455' Maximum Hole An le: 28.14 de rees Distance to Nearest Pro ert Line: 24,420' east to PBU bounda from to of the Mc Sand Distance to Nearest Well in Pool: 879' to GNI-01 at 3,850' TVDSS at SV3 Mud Praaram: 16" Surface Hole Mud Pro erties Spud -Freshwater Mud Interval Density PV YP PH Funnel Vis FL 0-2,079' BPRF 8.8-9.2 30-55 50 - 70 9.0 - 9.5 300-400 NC - 8 2,074'-4,204' SV3 9.2-9.5 30-55 45 - 60 9.0 - 9.5 250-300 < 8.0 12-1/4" Hole Mud Pro erties Type: LSND Interval Density PV YP PH API Filtrate MBT 4,204'-7,455' 9.3-9.8 12-18 18-24 9- 10 6.0-8.0 < 20 Survey and Laaaina Praaram~ 16" Hole Section: Surface Gyro until MWD surreys are clean. MWD /LWD: Dir/GR O en Hole: None Cased hole: GR/CCVCBVUSIT 12-1/4" Hole Section: MWD /LWD: GR/RES/Density/Neu on Dipole Sonic O en Hole: Dipole sonic may require wireline run Cased Hole: GR/CCVCBUUSIT Cement Calculations: Casin Size Surface Casing - 13-3/8" 72 Ib/ft L-80 BTC -Single Stage Basis Lead: Open hole volume + 250% excess in permafrost and 40% excess below permafrost. TOC at surface Tail: O en hole volume + 40% excess + 80' shoe track. TOC 1,000' MD above shoe 4,204' MD . Fluid Sequence and A Tam Port collar/ an ES Cementer may be located at 1,000' as a contingency for Volume: cement to surface Wash None .- Sacer 100 bbls of MudPush II wei kited to 10.60 Lead 646.5 bbls 10.7 Ib/ al Dee Crete Lite cement - 1965.4 sxs cuft/sk Tail 116.8 bbls 15.8 Ib/qal Class G - 558.49 sxs, 1.17 cu ft/sk Casin Size Injection Casing - 9-5/8" 47 Ib/ft L-80 BTC-M Basis Tail: Open hole volume + 40% excess. TOC at 4,230' MD, which is 26' below surface shoe. Fluid Sequence and An ES Cementer will be placed 4,224' for the purpose of circulating the OA clean. Volume: Wash None 3 acer 60 bbls MudPUSH at 12.50 Tail 257 bbl 15.8 pqq Class Gcement -1241 sxs 1.17 cu GNI-04 Permit to Drill Page 3 • • Surface and Anti-Collision Issues: • Surface Shut-in Wells: There are no wells requiring surface shut-in in order to move onto the well. GNI-01 is 50' away. • Close Approach Shut-in Welis: All wens have passed the major risk scan. No wells will require subsurface shut-in during drilling operations. Reference the Anti-collision report in the directional plan for a full list of offset well paths. Well Control Surface hole will be drilled with a diverter. The injection and production hole sections will be drilled with well control equipment consisting of 5000 psi working pressure pipe rams(2), blind/shear rams, and annular preventer. This equipment is capable of handling maximum potential surface pressures. Based upon calculations below, BOP equipment will be tested to 4,000 psi. Diverter, BOPE and drillina fJ~id system schematics are on file with the AOGCC. _.. Variance Request To avoid the risk of plugging the flow line with large rocks and wood encountered while drilling surface hole, it is requested to drill without a flow paddle for the first portion of the surface hole. After drilling past the larger rocks and wood sections, the flow paddle will be put back in the flow line. • To mitigate any risk involved with no flow paddle, the following steps will be taken while the flow paddle is removed from the flow line. Ensure PVT alarms are used and the pit levels are accurately monitored for any pit gain. Visually look down the riser during connections to ensure the well is not flowing. • BOPE: • Maximum anticipated BHP: • Maximum surface pressure: • Planned BOP test pressure: • 13-3/8" Casing Test: • Kick Tolerance: • Note: See Variance Request Hydril GK, 21-1/4", 2000 psi 1,733 psi - SV3 (8.7 ppg EMW C~ 3,850' TVD) 1,348 psi -Based on a full column of gas C~ 0.10 psi/ft Function Test 3,500 psi surface pressure test NA Intermediate Section Kick Tolerance and Intearity Testin • BOPE: Hydril, 13-5/8", 5000 psi • Maximum anticipated BHP: 3,095 psi - Mc Sand (9.3 ppg EMW ~ 6,430' TVD) • Maximum surface pressure: 2,452 psi -Based on a full column of gas C~3 0.10 psi/ft • Planned BOP test pressure: 4,000 psi high / 250 psi low 7-day test cycle (Pre-drilling phase) 14-day test cycle (Drilling operations) • 9-518" Casing Test: 4,000 psi surface pressure test • Integrity Test -12-1/4" hole: 20' - 50' from 13-3/8" shoe • Kick Tolerance: 56.0 bbl kick tolerance with 9.3 mud, and 67.9 bbls with 9.8 ppg mud. • Planned completion fluid: Estimated 9.5 ppg Brine / 6.8 ppg Diesel GNI-04 Permit to Drill Page 4 • • Area of Review ~'~~' ,~* ~`~~ ` ~ ~ ~~ ~ ~ ~ S~ ~~i~~r The Area of Review for well GNI-04 considered wellbores within ~/a mile of the proposed GNI-04 wellbore within the ~ ~ 1~ approved disposal interval in Area Injection Order 4E. Rule 2 specifies the authorized injection strata for disposal: Class II slurry injection from the Grind and Inject processes may be disposed into strata defined as those which correlate with and are common to the strata found in the ARCO Sag River State No. 1 well between the measured' depths of 4890-6750 feet." The top of this disposal interval is close to the SV1 geologic marker, approximately 5030' MD (4488' TVDSS) in nearby well GNI-01. The base of the interval is close to the CM3 marker. The only wellbore within the GNI-04 Area of Review is well GNI-01. At the SV1 level, the GNI-04 wellbore will be approximately 723 feet from the GNI-01 wellbore. Well GNI-01 is cemented to above the SV1 marker and a USIT log was run to verify isolation. At the anticipated perforated level, well GNI-01 is over ~/a mile from the proposed GNI-04 well bore and development wells 4-22A, 4-24, 4-25 and 4-35. There are no identified faults in the vicinity of wells GNI-01 or the proposed GNI-04 wellbore. Disposal • No annular disposal in this well. • No annular injection in this well. • Cuttings Handling: solids will be stored or injected at the GNI facility. Determination will be made to establish that solids are not hazardous. • Alternatively, solids may be stored at CC2A (or T-Pad) for future disposal. • Fluid Handling: waste drilling mud will be stored or injected at GNI or Pad 3. Determination will be made to establish that fluids are not hazardous. • All returned fluids not re-used or recycled must be considered either potentially hazardous or non-exempt. Freeze protect fluids have been identified as potentially hazardous, therefore diesel and/or methanol recovered from the well should be recycled or reused as freeze protection at the end of the well construction. Returned acid and cement contaminated fluids must be neutralized to pH between 2.0 and 12.5 and sent to class I disposal. GNI-04 Permit to Drill Page 5 • • GNI-04 Potential Drilling Hazards (Post on Rig) • .Pre-job HAZOP's and Safety meetings are recommended when there is a clear change in workscope. If at any time things don't feel or look right, STOP the job and discuss the situation before making the next move. • Flash Points o Dead Crude= <40degF o Methanol (neat)= 52degF o Diesel=100degF • Hydrogen Sulfide o The Surfcote Pad is not an H2S pad. However, Standard Operating Procedures for H2S precautions should still be followed at all times. o Offset H2S readings: None. o Both DS#4 and L4 Lisburne wells have high H2S readings. • Bottom Hole Pressure 0 3,095 psi - Mc Sand (9.3 ppg EMW C 6,430' TVD) o While there has been significant injection activity into this area as associated with the G&I processes, there is a high degree of confidence in the predicted BHP's in this area. • Maximum anticipated wellhead pressure: 0 2,452 psi with full column of gas • Potential for loss circulation o Moderate (While we do not anticipate any communication with the previous injection activities as associated with the G&I processes, an adequate supply of conventional LCM should be on location ready for use. • Faults -None • Close Approaches -None GNI-04 Permit to Drill Page 6 • • GNI-04 Drill and Complete Procedure Summary Pre-Riq Work: 1. Install a 20" conductor. 2. Weld an FMC landing ring for the FMC Big Bore wellhead on the 20" conductor. Install two 4" side outlet valves on the conductor pipe for surface cementing operations. Riq Operations: 1. MIRU Nabors 7ES. 2. Nipple up and function test diverter system. PU 5" DP to drill surface hole and stand back in derrick. 3. MU 16" drilling assembly with MWD/GR and directionally drill surface hole to 4,204' MD. The actual surface hole TD will be +/-30' TVD below the top of the SV3 sands as noted in the statement of requirements (SOR). 4. Run and cement the 13-3/8", 68# surface casing back to surface. A port collar might be run in the casing to allow for sec nd ry cementing if cement is not circulated to surf,~,ce during primary cementing operations. 5. ND diverter s`~ys~e~m~ar~c~'0 c~ sing tu'~ ng h a'`~"~f~`~~`~a c~'te°S~to~~,b0~psi~ ~'`}~°~° ~AO~'c1 \+-~ 6. Displace the well to 9.3 ppg LSND mud. Drill 20' of new formation. Perform FIT to 11.1 ppg EMW. POOH. 7. RIH w/ 12-1/4" DIR/GR/Res (real time) -Neu/Den/dipole Sonic (recorded mode) drilling assembly and drill to planned TD at 7,455' MD. 8. Circulate and condition the hole prior to POOH to run open-hole log (dipole sonic) and running the 9-5/8", 47# casing. POOH. 9. Run open-hole log(s) (dipole sonic) as required. 10. Make conditioning trip if necessary prior to running the 9-5/8" 47# casing. 11. Run 9-518", 47#, L-80, BTC-M casing from surface to the TD (an ES cementer will be positioned in the 9-5/8" casing to be ~20' outside the 13-3/8" surface casing shoe. 12. Cement the 9-5/8" casing from TD to the base of the window in the 13-3/8" casing with 15.8 ppg class G cement bumping the plug on the cement job with mud. 13. With the plug on the cement job bumped, continue to pressure up the casing to open the ES cementer (3300 psi opening pressure required /will have a baffle adapter in the casing string above the float collar to allow the required opening pressure) and circulate the 9-5/8" x 13-3/8" annulus clear of excess cement with mud (this annulus will be left open to allow monitoring of injection activities). 14. After circulating the 9-5/8" x 13-3/8" annulus clear with the 9.8 ppg LSND mud, freeze protect the annulus with 127 bbls of diesel or "dead" crude. 15. Close the ES cementer by pumping down the closing plug. NOTE: The closing plug will chase the freeze protect to the ES cementer closing the cementer as the freeze protection is pumped into the annulus. 16. RIH and drill out the ES cementer and clean out the 9-5/8" casing to TD. 17. Test 9-5/8" casing to 4000 psi for 30 minutes and chart. 18. With the 9-5/8" cleaned out to TD and pressure tested, displace the un-perforated well to clean seawater POOH. 19. Run cement bond logs as required. This is a critical step for demonstrating compliance with the pertinent AOGCC and the EPA regulations. 20. R/U and run 7", 29#, L-80, BTC-M completion tubing with open-ended 3/8" SS control line to 1000'. (NOTE: Injection packer to be set -4,930' MD and will require waiver from AOGCC.) Per SOR injection packer should be set less than 100' above the SV1 formation. 21. Land the tubing & RILDS. 22. Set a TWC and test to 1,000 psi. 23. Nipple down the BOPE. Nipple up the tree (new/re-furbished) and test to 5,000 psi. Pull TWC w/lubricator. 24. While taking returns up the annulus, pump 126 bbls diesel/dead crude down the tubing to freeze protect the well to 2000' on both sides of the tubing followed by ~38 bbls of inhibited seawater treated with enough inhibitor to treat ~75 bbls of seawater which is the volume of the annulus from the base of the diesel at 2000' to the top of the injection packer at 4,930' MD). With the combined 164 bbls of diesel and inhibited seawater in the tubing, shut down and U-tube the well through the tree to get the inhibited brine and 2000' of diesel to the annular side of the completion. 25. Drop ball & rod and set packer and individually test the tubing and annulus to 4,000 psi for 30 minutes and record each test. 26. Install BPV 27. Secure the well /rig down and move off. GNI-04 Permit to Drill Page 7 • ~ Post-Rig Work 1. Slick-line recovery of ball & rod. 2. Run tie-in logs and perforate well. 3. Install well-house and instrumentation. 4. Return location to grade/re-berm well location as required. GNI-04 Permit to Drill Page 8 TREE = CNV WELLHEAD = FMC ACTUATOR = KB. ELEV = BF. ELEV = KOP = 400' Max Angle = 28 @ 1856' Datum MD = 7455' Datum TVD = 6690' SS • GNI-04 13-3/8" CSG, 68#, L-80, ID=12.347" - 4,204` Minimum ID = 5.963" @ 4,910` & 4,950" HES R NIPPLE 7" TBG, 29#, L-80, 0.0371 bpf - ID = 6.184" PERFORATION SUMMARY REF LOG: SLB USrr/CBL ON 12/08/06 ANGLE AT TOP PERF: Note: Refer to Production DB for historical perf data SIZE SPF INTERVAL Opn/Sqz DATE 9-5/8" 5 O PBTD - 7,305` n 3/8" SS Control Line Strapped to 7" Tubing 4,220' - ES Cementer 4,910` - 7" HES R NIP ID = 5.963" 4,930' - 9-5/8" BKR SABL-3 PKR 4,950` - 7" HES R NIP, ID-5.963 5,000` - 7" TBG TAIL WLEG 7,455` - TD 7,455' - 9-5/8" CSG - 47# Surfcote Map 5,961,000 DS L3 5,960,000 5,959,000 5,958,000 5,957,000 a Q 5,956,000 5,955,000 5,954,000 5,953,000 5,952,000 710,000 711,000 712,000 713,000 714,000 715,000 716,000 717,000 718,000 719,000 720,000 721,000 722,000 723,000 ASP X lar ger t~rf ' ~se uu ~u ror mauon 24 %~ L ~ ``~ L4-11 - - - - L4- 3 - .-- ;'-- GNI- 2A , ~'~ , ,' - p ' - - ~~ - `~ , ' ~ . ~ ~ ~ DS L4 - Radiu ~ n ~ ~ ~ ~~ -E3- GJ~ Oi '' ' ,. b , 3~ ,, ., •. , ,~ l~G~ ~ ~, ~ -22A '~-- ~ ~ ,•_ ~ SV1 0 - - , 4-31 ~. ~ ~ ~ ~ ,GNI-0 4 ~ ~~Target ~ 3• GNI-03 _ ' #3 Pin ut ' 4-24 4-35 Surfc to / 1 ~ ~ Pad ` ' Pad 4-34A 4 25 4-27 - -- 4- 7 O 4-23A 4-2 O 4-36 X ~49 4-16 'r O -- _ ,~ ~-'1 4-0 -- 4-28 ~ _T_~-,_~.~ . - - • - - SL-BHL Pad 04-08 04-16 --~- 04-17 --r- 04-20 ---~- 04-21 04-22A 04-23A 04-24 04-25 04-26 04-27 -- 04-28 9.. 04-33 ---~- 04-34A 04-35 - 04-36 -• 04-37 -il 04-39 04-49 -~---- L3-18 --~-- L3-24 --~" L4-03 L_J O 6500' TVD I ~ . , .+ I by Schlumberger GNI-04 (P3) Proposal Report Date: August 2, 2007 Survey 1 DLS Computation Method: Minimum Curvature / Lubinski Client: BP Vertical Section Azimuth: 296.970° Field: Prudhoe Bay Unit -Lisburne ~ Vertical Section Origin: N 0.000 ft, E 0.000 ft Structure 1 Slot: NON-PAD /GNI-04 ~' ~~ s ~ y TVD Reference Datum: Rotary Table Well: GNI-04 ~~b TVD Reference Elevation: 47.20 ft relative to MSL Borehole: Plan GNI-04 ~e~ Sea Bed I Ground Level Elevation: 18.70 ft relative to MSL UWIIAPI#: 50029 Magnetic Declination: 24.206° Survey Name 1 Date: GNI-04 (P3) /August 2, 2007 Total Field Strength: 57626.137 nT Tort I AHD I DDI 1 ERD ratio: 28.137° 12985.24 ft 14.968 / 0.443 Magnetic Dip: 80.957° Grid Coordinate System: NAD27 Alaska State Planes, Zone 04, US Feet Declination Date: October 15, 2007 Location LaULong: N 70.28296567, W 148.24401444 Magnetic Declination Model: BGGM 2005 Location Grid WE YIX: N 5956183.000 ftUS, E 716972.460 ftUS North Reference: True North Grid Convergence Angle: +1.65309166° Total Corr Mag North -> True North: +24206° Grid Scale Factor: 0.99995348 Local Coordinates Referenced To: Well Head Measured Vertical Gravity Directional Comments Inclination Azimuth Sub-Sea TVD TVD NS EW DLS Northing Easting Latkude Longitude Depth Section Tool Face Difficulty ft de de ft ft ft ft ft de de 100 ft Index ftUS ftUS Klt U.UU U.UU Yyti.`J/ -4/.ZU U.UU U.UU KOP Bld 1.25/100 300.00 0.00 296.97 252.80 300.00 0.00 400.00 1.25 296.97 352.79 399.99 1.09 500.00 2.50 296.97 452.74 499.94 4.36 600.00 3.75 296.97 552.59 599.79 9.81 Bld 2/100 700.00 5.00 296.97 652.29 699.49 17.44 800.00 7.00 296.97 751.74 798.94 27.89 900.00 9.00 296.97 850.76 897.96 41.81 1000.00 11.00 296.97 949.24 996.44 59.18 1100.00 13.00 296.97 1047.05 1094.25 79.97 1200.00 15.00 296.97 1144.07 1191.27 104.16 1300.00 17.00 296.97 1240.19 1287.39 131.72 1400.00 19.00 296.97 1335.29 1382.49 162.62 1500.00 21.00 296.97 1429.26 1476.46 196.82 1600.00 23.00 296.97 1521.97 1569.17 234.28 1700.00 25.00 296.97 1613.32 1660.52 274.95 1800.00 27.00 296.97 1703.20 1750.40 318.78 End Bld 1856.85 28.14 296.97 1753.59 1800.79 345.09 Base Perm 2079.58 28.14 296.97 1950.00 1997.20 450.13 SV6 2725.97 28.14 296.97 2520.00 2567.20 754.96 SV5 3474.42 28.14 296.97 3180.00 3227.20 1107.91 SV4 3667.20 28.14 296.97 3350.00 3397.20 1198.82 U. UU U.VU --- U.UU U.UU 5y5f71tlJ. UU 0. 00 0.00 HS 0.00 0.00 5956183. 00 0. 49 -0.97 HS 1.25 0.13 5956183. 47 1. 98 -3.89 HS 1.25 1.04 5956184. 87 4. 45 -8.75 HS 1.25 1.57 5956187. 20 7. 91 -15.55 HS 1.25 1.94 5956190. 46 12. 65 -24.86 HS 2.00 2.29 5956194. 93 18. 96 -37.26 HS 2.00 2.58 5956200. 88 26. 84 -52.74 HS 2.00 2.82 5956208. 30 36. 27 -71.27 HS 2.00 3.02 5956217. 19 47. 24 -92.83 HS 2.00 3.20 5956227. 54 59. 74 -117.39 HS 2.00 3.35 5956239. 32 73. 75 -144.93 HS 2.00 3.50 5956252. 54 89. 26 -175.41 HS 2.00 3.62 5956267. 16 106. 25 -208.80 HS 2.00 3.74 5956283. 18 124. 70 -245.04 HS 2.00 3.85 5956300. 57 144. 58 -284.11 HS 2.00 3.95 5956319. 32 156. 51 -307.56 -- 2.00 4.00 5956330. 57 204. 15 -401.17 --- 0.00 4.12 5956375. 49 342. 41 -672.84 --- 0.00 4.35 5956505. 84 502. 49 -987.41 -- 0.00 4.53 5956656. 77 543. 72 -1068.43 --- 0.00 4.56 5956695. 65 /16`J/Z.46 N /U.YtfYyUb6/ W 14tS.Z44U1444 716972.46 N 70.28296567 W 148.24401444 716971.47 N 70.28296702 W 148.24402231 716968.52 N 70.28297107 W 148.24404590 716963.59 N 70.28297783 W 148.24408521 716956.69 N 70.28298728 W 148.24414022 716947.25 N 70.28300023 W 148.24421560 716934.67 N 70.28301747 W 148.24431595 716918.97 N 70.28303898 W 148.24444117 716900.18 N 70.28306474 W 148.24459110 716878.31 N 70.28309472 W 148.2447 716853.40 N 70.28312887 W 148.2449 716825.47 N 70.28316715 W 148.24518714 716794.55 N 70.28320953 W 148.24543377 716760.70 N 70.28325594 W 148.24570391 716723.93 N 70.28330633 W 148.24599721 716684.31 N 70.28336064 W 148.24631332 716660.53 N 70.28339324 W 148.24650307 716565.59 N 70.28352337 W 148.24726054 716290.05 N 70.28390101 W 148.24945887 715971.02 N 70.28433825 W 148.25200441 715888.84 N 70.28445086 W 148.25266009 WeIlDesign Ver SP 2.1 Bld( doc40x_100) GNI-04\GNI-04\Plan GNI-04\GNI-04 (P3) Generated 8/2/2007 11:09 AM Page 1 of 2 Measured Vertical Gravity Directional Comments Inclination Azimuth Sub-Sea ND ND NS EW DLS Northing Easting Latitude Longitude Depth Section Tool Face Difficulty ft de de ft ft ft ft ft de de 100 ft Index ftUS ftUS 73-3/tt" GSg /'r 4LUU.7y Ztt.74 Zy6.9/ 3ttZU.UU 3tf6/.ZU 14bU. 7/ 6b/. /L -7ZyZ.44 -- U.UU 4.6b 9yblitfU3.73 /79607.(ib N /U.Yti4/(iLLU W 74tf.Zb44/Zy7 SV3 4234.21 28.14 296.97 3850.00 3897.20 1466. 21 664.99 -1306.74 --- 0.00 4.65 5956809.99 715647.15 N 70.28478207 W 148.25458863 SV2 4449.67 28.14 296.97 4040.00 4087.20 1567. 82 711.08 -1397.30 --- 0.00 4.68 5956853.44 715555.30 N 70.28490793 W 148.25532148 SVl 4959.98 28.14 296.97 4490.00 4537.20 1808. 47 820.22 -1611.77 --- 0.00 4.75 5956956.35 715337.78 N 70.28520599 W 148.25705724 UG4 5492.97 28.14 296.97 4960.00 5007.20 2059. 82 934.22 -1835.78 --- 0.00 4.80 5957063.83 715110.58 N 70.28551728 W 148.25887019 UG4A 5526.99 28.14 296.97 4990.00 5037.20 2075. 86 941.50 -1850.08 --- 0.00 4.81 5957070.69 715096.08 N 70.28553715 W 148.25898591 UG3 5889.87 28.14 296.97 5310.00 5357.20 2246. 99 1019.11 -2002.60 --- 0.00 4.84 5957143.87 714941.40 N 70.28574908 W 148.26022029 UG1 6592.96 28.14 296.97 5930.00 5977.20 2578. 56 1169.49 -2298.10 -- 0.00 4.90 5957285.66 714641.69 N 70.28615968 W 148.26261199 Ma 6944.51 28.14 296.97 6240.00 6287.20 2744. 34 1244.68 -2445.85 --- 0.00 4.93 5957356.55 714491.84 N 70.28636497 W 148.26380787 Mbl 6989.87 28.14 296.97 6280.00 6327.20 2765. 73 1254.38 -2464.91 --- 0.00 4.93 5957365.70 714472.51 N70.28639145 W148.26396 Mb2 7069.25 28.14 296.97 6350.00 6397.20 2803. 17 1271.36 -2498.28 ~- 0.00 4.94 5957381.71 714438.67 ~ N 70.28643781 W 148.2642 Mc 7159.96 28.14 296.97 6429.99 6477.19 2845. 94 1290.76 -2536.40 --- 0.00 4.95 5957400.00 714400.00 N 70.28649078 W 148.2645 GNI-04 Tgt 1 7159.97 28.14 296.97 6430.00 6477.20 2845 .95 1290.77 -2536.40 --- 0.00 4.95 5957400.00 714400.00 N 70.28649078 W 148.26454084 7205.33 28.14 296.97 6470.00 6517.20 2867 .34 1300.47 -2555.47 -- 0.00 4.95 5957409.15 714380.66 N 70.28651727 W 148.26469515 WS2 7205.34 28.14 296.97 6470.01 6517.21 2867. 35 1300.47 -2555.47 --- 0.00 4.95 5957409.15 714380.66 N 70.28651728 W 148.26469519 Na 7279.04 28.14 296.97 6535.00 6582.20 2902. 10 1316.23 -2586.45 --- 0.00 4.96 5957424.01 714349.24 N 70.28656031 W 148.26494591 Nb 7301.72 28.14 296.97 6555.00 6602.20 2912. 80 1321.08 -2595.98 ~- 0.00 4.96 5957428.59 714339.58 N 70.28657355 W 148.26502306 Ne 7347.08 28.14 296.97 6595.00 6642.20 2934. 19 1330.79 -2615.05 --- 0.00 4.96 5957437.73 714320.24 N 70.28660004 W 148.26517737 7454.81 28.14 296.97 6690.00 6737.20 2984. 99 1353.83 -2660.32 --- 0.00 4.97 5957459.46 714274.32 N 70.28666295 W 148.26554387 TD / 9-5/8" Csg Pt 7455.33 28.14 296.97 6690.46 6737.66 2985 .24 1353.94 -2660.54 --- 0.00 4.97 5957459.56 714274.10 N 70.28666325 W 148.26554562 WeIlDesign Ver SP 2.1 Bld( docAOx_100) GNI-04\GNI-04\Plan GNI-04\GNI-04 (P3) Generated 8/2/2007 11:09 AM Page 2 of 2 by ~ • Schlumberger WELL GNI-04 (P3) FIELD Prudhoe Bay Unit -Lisburne STRUC TURE Surfcote Magnetic Parametms Surtar:e L ~ritnn hAU2)AlasFa Stile %anes Zon«OJ USF«el Mlerella neous MoAel S6GM 2005 Dip a0951- pale O~.n.[er'S 2(10/ Lai h/~'65A 5]6 Nort0ing 595a~fi300 SUS !'ai~Cnnv - n5 )0966' Slol GM1I-0< ND Rey Roury Td~H ~</2C0 at1o~e MSL~ Mag pec -3<M6' FS 5/fi2fi '~ni Lan 6<52 Easung i1o912 a6 OUS 099995]<]9~ t.hl.p<~P3/ 'rvy Dade August J2. 200 0 800 1600 2400 3200 0 800 1600 2400 `o 0 c 3200 a~ m U 4000 ........................;... 4800 ....................... 5600 6400 \ _ -13-3/8" Csg Pt ..- -..-..-..-..-..~..D. v~.. .-..-..-..-. - -..-..-..-..~..-..-..-..i..-..-..- .....t .............................. ....................................................................................... .i.. ..-i.-..-..-..-..~..-..-..-. -i....-..-..-..-..-..-..- .i..-. .~~ .-.._..-..-..- .~. -..-..- GNI-0b Tgt 1 0 800 1600 2400 3200 Vertical Section (ft) Azim = 296.97°, Scale = 1(in):800(ft) Origin = 0 N/-S, 0 E/-V 0 800 1600 2400 3200 4000 4800 5600 6400 1500 TD / 9-5lB" Csg 1200 n n 900 Z 0 0 ch C I I ~ 60C f0 U In In V V v 30C by Schlumberger WELL FIELD STRUCTURE GNI-04 (P3) Prudhoe Bay Unit -Lisburne Surfcote Magne~c Paeameien Sunau ou~wn NnD2] Nasky Slale Plane. Zore G. US Feed Mlscal~aropus MWeI. BGGM 2005 Dip BO 95]' Data. Q:io6er t5. 200/ La1 L N]01656 fi]6 NunMng. S9S61B300IN5 Gn~COnv: ~1 653091fifi' Sb~ GNI-CW ND RaI. Rotary Tabin 14]2011 aS~ve MSLi May Unc. X24.206' FS S/626.1 nT Wt4B 1436.452 Easing. Tt 69 /246 aU5 Srale FaaU9999534]91 Plan: GNI-0d IP31 Grvy Dale. Augus102. 200] -2400 -2100 -1800 -1500 -1200 -900 -600 -300 0 1500 1200 900 600 300 0 -2400 -2100 -1800 -1500 -1200 «< W Scale = 1(in):300(ft) E »> -900 -600 -300 0 BP Alaska Anticollision Report 'Company: BP AmOCO Date: 8/2/2007 Time: 13:16:42 Pagec 1 Vii, Field: Prudhoe Bay (various). Reference Site: PB Surfcote Co-ordinate(NE) Reference: Well: Plan GNI-04, True North Reference Well: Plan: GNI-04 Vertical (TVD) Reference: GNI-04 Plan 47.2 Reference Wellpakh: Plan GNI-04 DV: Oracle ~ ' GLOBAL SCAN APPLIED: All wellpaths within 200'+ 100/1000 of reference -There are t~@If~>iaYells in thisRliidlpal Plan & PLANNED PROGRAM Interpolation Method: MD Interval: 5.00 ft Error Model: ISCWSA Ellipse ' ' Depth Range: 28.50 to 7455.33 ft Scan Method: Trav Cylinder North ' Maximum Radius: 942.68 ft Error Surface: Ellipse + Casing Survey Program for Definitive Wellpath Date: 5/11/2007 Validated: No Version: 1 ' Planned From To Survey Toolcode Tool Name ', ft ft j 28.50 500.00 Planned: Plan #3 V1 GYD-GC-SS Gyrodata gyro single shots ' '~ 500.00 7455.33 Planned: Plan #3 V1 MWD+IFR+MS MWD +IFR + Multi Station Casing Points MD' TVD Diameter Hole Size Name ft- ft in _ in 4200.19 3867.20 13.375 16.000 13 3/8" 7455.33 6737.66 9.625 12.250 9 5/8" Summary ._. - - <------------ Offset Wellpath ------------% - Reference Offset Ctr-Ctr No-Co ~llowahle Site Well Wellpath MD MD' Distance Area Deviation Warniing I ft ft ft ft ft ', PB DS 04 04-24 04-24 V1 Out of range PB Surfcote GNI-01 GNI-01 V2 398.01 400.00 51.03 6.85 44.18 Pass: Major Risk ~ • ~~ Field: Prudhoe Bay (various) Site: PB Surfcote ', Well: Plan GNI-04 We~lpath: Plan GNI-04 -313 300 200 l00 0 l00 zoo 300 -313 n inv Travelling Cylinder Bzimuth (TPO+AZI) [deg vs Centre to Centre Sepamrion [100ft/ink Site: PB Surfcote Drilling Target Conf.: 95% Description: Map Northing: 5957400.00 ft Map Easting :714400.00 ft Latitude: 70° 1 T 11.367N Shape: Circle Target: GNI-04 Tgt 1 Well: Plan GNI-04 Based on: Planned Program Vertical Depth: 6430.00 ft below Mean Sea Level Local +N/-S: 1290.76 ft Local +E/-W: -2536.40 ft Longitude: 148° 15'S2.347W Radius: 100 ft --_ _ __ 0 0 0 0 0 00 0 0 0 0 Q D ~ ~o ~n ~-- m ~ Q ~ '~ ~ ~f i (~ ~ ~ i c~ i c~ i 500 ~~oo i~oo 1200 iioo 0 0 c~ STATE OF ALASKA ALAS IL AND GAS CONSERVATION COMMI N PERMIT TO DRILL 20 AAC 25.005 ,C~ V ~~ ~,,J G 2 9 2007 a~~:a Cis ~ Cos Cons. Commission 1 a. Type of work ® Drill ^ Redrill ^ Re-Entry 1 b. Current Well Class ^ Exploratory ^ Development Gas ®Service ^ Multiple Zone ^ Stratigraphic Test ^ Development Oil ^ Single Zone 1 c. Speci if well is prop9 e ^ C Ibed Methane L1 GasHydrates ^ hale Gas 2. Operator Name: BP Exploration (Alaska) Inc. 5. Bond: ®Blanket ^ Single Wel Bond No. 6194193 11. Well Name and Number: PBU GNI-04 3. Address: P.O. Box 196612, Anchorage, Alaska 99519-6612 6. Proposed Depth: MD 7455 TVD 38 12. Field /Pool(s): Prudhoe Bay Field / Prudhoe Bay 4a. Location of Well (Governmental Section): Surface: 4190' FSL 1011' FEL SEC 26 R15E UM (As Staked) T11N 7. Property Designation: ADL 028323 Pool , , , . , , Top of Productive Horizon: 200' FSL, 3507' FEL, SEC. 23, T11 N, R15E, UM 8. Land Use Permit: ~ 13. Approximate Spud Date: October 10, 2007 Total Depth: 263' FSL, 3671' FEL, SEC. 23, T11 N, R15E, UM 9. Acres in Prope ~ 60 14. Distance to Nearest Property: 24,420' 4b. Location of Well (State Base Plane Coordinates): Surface: x-716973 y-5956183 Zone-ASP4 10. KB Eleva ' n n (Height a ve GL). " 5.2 feet 15. Distance to Nearest Well Within Pool: 890' 16. Deviated Wells: K;ckoff Depth: 400 feet Maximum Hole An le: 28 de rees 17. axi m Anti ' to Pressures in psig (see 20 AAC 25.035) o hol ~ 0 5 Surface: 2452 i8'. Cas;n Pr tam: S cifications To - n De h -Bo ttom. uanti of C meet c.f. or sa s Hole Casin Wei ht Grade Cou lin Len MD D MD TVD includin sta a data 42" 20" 91.5# H-40 Weld 8 urfa urface 1 108' 260 sx Arctic Set A rox. 16" 13-3/8" 68# L-80 BTC-M S Surface 0 3870' 1965 sx Dee Crete Lite 561 sx'G' 12-1/4" 9-5/8" 47# -80 BTC-M 5' S e Surface 55' 67 1241 sx lass 'G' 19. PRESE NT WELI. CON TIO S U RY (T mplet for ~ a Re-entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plu eas ): tiv Dept ~~, ft): Effective Depth TVD (ft): Junk (measured): Casing - Length Siz C me MD: TVD Conductor /Structural Surface Intermediate Producti n ~~ Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments ^ Filing Fee, 100 ^ BOP Sketch ^ Property at ^ Diverter Sketch ®Drilling Program ^ Time vs Depth Plot ^ Shallow Hazard Analysis ^ Seabed Report ®Drilling Fluid Program ®20 AAC 25.050 Requirements 21. Verbal Approval: Co mission Representative: Date: 22. I hereby certify that th go'r5g is true and correct. Printed Name Greg ~ ~ Si nature -~ Contact Mehrdad Nadem, 564-5941 Title Senior Drilling Engineer Prepared By Name/Number: Phone 564-4191 Date - r- ~ ' Terrie Hubble, 564-4628 Commission Use Onl Permit To Drill Number= ~ API Number: 50- ~r~D Permit Approval See cover letter for Date: other re uirements Conditions of Ap royal: If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained shales: ^ Samples Req'd: ^ Yes ^ No Mud Log Req'd: ^ Yes ^ No HZS Measures: ^ Yes ^ No Directional Survey Req'd: ^ Yes ^ No Other: APPROVED BY THE COMMISSION Date ,COMMISSIONER Form 10-401 Revised 12/2005 ~ ~ ~ ~ R ¢ Submit In Duplicate Page 1 of 2 Maunder, Thomas E (DOA) From: Sent: To: Cc: Subject Nadem, Mehrdad [NademM@BP.com] Thursday, September 13, 2007 2:42 PM Maunder, Thomas E (DOA) Hobbs, Greg S (ANC}; Bernaski, Greg E; Bill, Michael L (Natchiq) GNI-04 PTD Request for Additional Information ....................... ao1-~11 Attachments: GNI Calc Dist To Offset Wells.xls Tom, We have researched your request for additional information dated September 10 regarding other wellbores near the Area of Review for proposed well .GNI-04. Below are your three specific questions and responses. Attached is a revision to the spreadsheet tabulation of wellbores near or within the 1/4 mile Area of Review. The spreadsheet confirms there are no additional wellbores within the 1/4 mile AOR. Question 1: DS 04-22 (185-233) -According to the information in the file, DP became stuck and it was necessary to plug back the well in November, 1985. There is no survey information in the file. Based on the operations summary and the survey information, the "lost" hole section was from 3710' - 4727' and (3760' - 4050' tvd). It would appear that this hole section is above the permitted injection interval. Would you confirm this? Answer 1: Referencing the lost hole section as 4-22PB1, the plugback hole reached a TD of 4727' MD (- 3990' TVDSS), which is projected to lie at a depth of 135 TVD feet below the top SV3 marker, or 460 TVD feet above the SV1 marker. Thus, the 04-22P61 borehole reached TD in the SV3 confining layer 460 TVD feet above the top of the approved injection interval. Thus this borehole is above the injection zone and outside of the Area of Review. Question 2: DS 04-22A (197-094) -According to the operations information, a section was milled and the well kicked off at 7697' and (5795' tvd). This depth is well above the possible primary cement top. A portion of the new 8-1/2" hole was plugged back, but the depth was well below the authorized injection interval. When the 7" liner was set, the cement was only raised 1000' above the Sag River. It appears that the authorized injection interval was not covered with cement. Would you confirm the proximity of 04-22A with regard to the '/4 mile radius of GNI-04? Answer 2: The attached GNI-04 offset well standoff spreadsheet was updated to include the projected SV1, Mc, GNI-04_TD, and CM3 markers from the 04-22A well. The closest approach between the 04-22A sidetrack and the proposed GNI-04 well is 1581 feet at the depth equivalent to the GNI-04 TD location. Question 3: DS 04-25 (186-049) -According to the operations information, a significant portion of 12-1/4" hole was lost when a fish got stuck during a trip. Hole TD was 12420' and with the fish from 7180' - 7630' md. Cement was set to 6915' and and then another plug was set between 4100' - 4500' md. New hole was kicked off at 4149' md. When the 9-5/8" casing was cemented, it does not appear that the authorized injection interval was covered with cement. Would you confirm the location of the abandoned hole section? Answer 3: Referencing the lost hole section as 4-25PB1, the attached GNI-04 offset well standoff spreadsheet was updated to include the projected SV1, Mc, GNI-04_TD, and CM3 markers from the 04-25PB1 well. The well course was established using single shot data documented in daily drilling reports and reported to the AOGCC. The closest approach between the 04-25PB1 borehole and the proposed GNI-04 well is 1999 feet at the depth equivalent to the GNI-04 TD location. Please contact me at 564-5941 if your have any additional questions. I will be out September 17 through September 21, but will be checking my Email. 9/ 18/2007 Well GNI-04 Lateral Standoff Distance to Offset Wells GNI-04 Lateral Standoff at SV1 Marker: 1~ob of Permitted Iniectiorrtnfervai Lateral Distance to Equivalent Well Marker X Y NDSS Marker in GNI-04 well (Feet) (Feet) (Feet) (Feet) GNI-04_wp03 04-17 04-20 04-21 04-22 04-22A 04-23 04-24 04-25 04-25PB1 04-26 04-Z7 04-33 04-35 GNI-01 GNI-02 GNI-02A GNI-03 L3-24 • L4-11 L4-15 SV1 715337 5956956 -4490 - SV1 713350 5953291 -0449 4169 SV1 712713 5953956 -0388 3985 SV1 711946 5955563 -4500 3666 SV1 712861 5955334 -0502 2960 SV1 SV1 712694 5953542 -4447 4317 SV1 713077 5953756 -4447 3918 SV1 713756 5952918 -4499 4336 SV1 713788 5952823 -4499 4414 SV1 713880 5952723 -0500 4476 SV1 715171 5953087 -4500 3873 SV1 715614 5955034 -4504 1942 SV1 714270 5955026 -4502 2206 SV1 716026 5957182 -4487 725 SV1 717454 5957451 -4509 2174 SV1 716730 5957817 -4511 1638 SV1 718725 5956510 -4519 3417 SV1 709794 5960740 -4500 6712 SV1 719726 5960003 -4502 5343 SV1 720423 5959047 X502 5499 ~' ~"" Comment (1) SV1 depth estimated; no shallow logs run in this well SV1 depth estimated; no shallow logs run in this well SV1 depth estimated; no shallow logs run in this well SV1 depth estimated; no shallow logs run in this well Above Sidetrack hole KOP SV1 depth estimated; no shallow logs run in this well SV1 depth estimated; no shallow logs run in this well SV1 depth estimated; no shallow logs run in this well SV1 depth estimated; no shallow logs run in this well SV1 depth estimated; no shallow logs run in this well SV1 depth estimated; no shallow logs run in this well SV1 depth estimated; no shallow logs run in this well SV1 depth estimated; no shallow logs run in this well SV1 depth estimated; no shallow logs run in this well SV1 depth estimated; no shallow logs run in this well SV1 depth estimated; no shallow logs run in this well Comment (2) GNI-04 Lateral Standoff at UG Mc Marker: Top of Ta rget Pdrfo rated Inlectlon Zone Lateral Distance to Equivalent Well Marker X Y NDSS Marker in GNI.04 well Comment (1) (Feet) (Feet) (Feet) (Feet) GNI-04 wp03 UG MC 714400 5957400 -6430 04-17 UG MC 713543 5954574 -6378 2953 Mc depth estimated; no shallow logs run in this well 04-20 UG MC 711952 5956432 -6329 2632 Mc depth estimated; no shallow logs run in this well 04-21 UG MC 710894 5958314 -6382 3623 Mc depth estimated; no shallow logs run in this well 04.22 UG MC 712641 5957963 -6409 1847 ~-- Mc depth estimated; no shallow logs run in this well 04-22A UG_ MC 712720 5957516 -6402 1684 e~-- Mc depth estimated; no shallow logs run in this well 04-23 UG MC 711987 5954597 -6355 3699 Mc depth estimated; no shallow logs run in this well 04-24 UG MC 713378 5955844 -6380 1861 "~"' Mc depth estimated; no shallow logs run in this well 04-25 UG MC 714966 5955493 -6405 1990 ~ Mc depth estimated; no shallow logs run in this well 04-25PB1 UG MC 715202 5955470 -6405 2090 Mc depth estimated; no shallow logs run in this well 04-26 UG MC 715178 5954267 $402 3228 Mc depth estimated; no shallow logs run in this well 04-27 UG MC 717203 5954828 -6441 3804 Mc depth estimated; no shallow logs run in this well 04,33 UG MC 717379 5956835 -6471 3032 Mc depth estimated; no shallow logs run in this well 04-35 UG MC 714992 5955881 -6410 1631 ~ Mc depth estimated; no shallow logs run in this well • GNI.01 GNI.02 UG UG MC MC 714452 717578 5958717 5959007 -6437 -6495 1318 *~-- 3561 GNI-02A UG MC 715797 5959791 X472 2769 GNI.03 UG MC 720098 5956657 -6518 5747 L3-24 UG MC 711895 5960096 -6410 3680 Mc depth estimated; no shallow logs run in this well L4-11 UG MC 718189 5960797 -6527 5089 Mc depth estimated; no shallow bgs run in this well L4-15 UG MC 719580 5958620 -6518 5322 Mc depth estimated; no shallow logs run in this well Comment (2) • GNI-04 Lateral Stand 'Eauiv~lent to GNl-04 TD Lateral Distance to Equivalent Well Marker X Y TVDSS Marker in GNI-04 well Comment (1) (Feet) (Feet) (Feet) (Feet) GNI-04_wp03 TD 714274 5957460 -6690 - 04-17 GNI-04 TD 713564 5954736 -6625 2815 GNI-04 TD equivalent estimated; no shallow logs run in this well 04-20 GNI-04 TD 711780 5956839 -6579 2570 GNI-04 TD equivalent estimated; no shallow logs run in this well 04-21 GNI-04 TD 710762 5958666 -6634 3713 GNI-04 TD equivalent estimated; no shallow logs run in this well 04-22 GNI-04 TD 712610 5958308 -6661 1867 '~'"~' GNI.04 TD equivalent estimated; no shallow logs run in this well 04-22A GNI-04 TD 712705 5957655 -6638 1581 ~' GNI-04 TD equivalent estimated; no shallow logs run in this well 04-23 GNI-04 TD 711900 5954733 -6605 3615 GNI-04 TD equivalent estimated; no shallow logs run in this well 04-24 GNI-04 TD 713441 5956131 -6632 1568 ~-"' GNI-04 TD equivalent estimated; no shallow logs run in this well 04-25 GNI-04 TD 715182 5955830 -6655 1866 t~---- GNI-ll4 TD equivalent estimated; no shallow logs run in this well 04-25PB1 GNI-04 TD 715336 5955766 -6655 1999 ,C~-- GNI-D4 TD equivalent estimated; no shallow logs run in this well 04-26 GNI-04 TD 715345 5954443 -6655 3201 GNI-04 TD equivalent estimated; no shallow logs run in this well 04-27 GNI-oa TD 717450 5955025 -6698 4002 GNI-04 TD equivalent estimated; no shallow logs run in this well 04-33 GNI-04 TD 717585 5957082 -6729 3332 GNI-04 TD equivalent estimated; no shallow logs run in this well 04-35 GNI-04 TD 715075 5956037 -6670 1633 ~- GNI-04 TD equivalent estimated; no shallow logs run in this well GNI-01 GNI-04 TD 714303 5958875 -6680 1415 ~'-- GNI-D4 TD equivalent estimated; no shallow logs run in this well GNI-02 GNI-04 TD 717585 5959188 -6738 3735 GNI.04 TD equivalent estimated; no shallow logs run in this well GNI-02A Depth not reached GNI-03 GNI-04 TD 720263 5956667 -6772 6041 GNI-04 TD equivalent estimated; no shallow logs run in this well L3-24 GNI-04 TD 712166 5960009 -6662 3307 GNI.04 TD equivalent estimated; no shallow logs run in this well L4-11 GNI-04 TD 717990 5960862 -6780 5038 GNI-04 TD equivalent estimated; no shallow logs run in this well L4-15 GNI-D4 TD 719475 5958570 -6771 5318 GNI-04 TD equivalent estimated; no shallow logs run in this well Comment (2) • n U GNI-04 Lateral Standoff at CM3 Marker: Base ofPermitted Iniec>tlon Zone Lateral Distance to Equivalent Well Marker X Y NDSS Marker in GNI-04 well (Feet) (Feet) (Feet) (Feet) GNI-04-wp03 CM3 714140 5957524 -6975 - 04-17 CM3 713589 5954942 X935 2641 04-20 CM3 711561 5957347 -6929 2585 04-21 CM3 710584 5959089 X971 3885 04-22 CM3 712576 5958773 -6991 2002 04-22A CM3 712685 5957845 -6977 1490 04-23 CM3 711769 5954932 -6990 3513 04-24 CM3 713513 5956495 -6927 1205 04-25 CM3 715454 5956263 -6990 1822 04-25P61 CM3 715565 5956301 -6990 1878 04-26 CM3 715531 5954642 -6959 3200 04-27 CM3 717717 5955242 -7000 4243 04-33 CM3 717826 5957380 -7039 3689 04-35 CM3 715179 5956226 -6990 1663 GNI.01 GNI-02 GNI-OZA GNI-03 L3-24 CM3 712515 5959898 -7000 2876 L4.11 CM3 717740 5960975 -7089 4987 L4-15 CM3 719387 5958526 -7089 5342 '~.'° *~--- Comment (1) Comment (2) CM3 depth estimated; no shallow logs run in this well CM3 depth estimated; no shallow logs run in this well CM3 depth estimated; no shallow logs run in this well CM3 depth estimated; no shallow logs run in this well CM3 depth estimated; no shallow logs run in this well CM3 depth estimated; no shallow logs run in this well CM3 depth estimated; no shallow logs run in this well CM3 depth estimated; no shallow logs run in this well CM3 depth estimated; no shallow logs run in this well CM3 depth estimated; no shallow logs run in this well CM3 depth estimated; no shallow logs run in this well CM3 depth estimated; no shallow logs run in this well CM3 depth estimated; no shallow logs run in this well Depth not reached Depth not reached Depth not reached Depth not reached CM3 depth estimated; no shallow logs run in this well CM3 depth estimated; no shallow logs run in this well CM3 depth estimated; no shallow logs run in this well Proiected Depth of GNI-04 CM3 Proiected Death of GNI-04 CM3 Proiected Depth of GNI-04 CM3 Proiected Death of GNI-04 CM3 Proiected Depth of GNI-04 CM3 Proiected Depth of GNI-04 CM3 Proiected Depth of GNI-04 CM3 Proiected Death of GNI-04 CM3 Proiected Depth of GNI-04 CM3 Proiected Depth of GNI-04 CM3 Proiected Depth of GNI.04 CM3 Proiected Depth of GNI-04 CM3 Proiected Depth of GNI-04 CM3 Proiected Depth of GNI-04 CM3 Proiected Depth of GNI-l)4 CM3 Proiected Depth of GNI-04 CM3 Proiected Depth of GNI-04 CM3 • Page 1 of 1 • • Maunder, Thomas E (DOA) From: Nadem, Mehrdad [NademM@BP.com) -a ~ ~ ^ "~ Sent: Tuesday, September 11, 2007 3:23 PM To: Maunder, Thomas E (DOA) Cc: Bill, Michael L (Natchiq); Hobbs, Greg S (ANC) Subject: RE: GNI-04 PTD Request #or Additional Information-again Tom, You are correct. The yield for DeepCrete is 3.85 cu. ft./sk. Schlumberger has resubmitted the CemCade with the correct yield. Also, attached please find info on DeepCrete. We will provide information on offset wells after we load the data on the computer. Regards, Mehrdad From: Maunder, Thomas E (DOA) Sent: Friday, September 07, 2007 3:28 PM To: 'Hobbs, Greg S (ANC)' Subject: RE: GNI-04 PTD Request for Additional Information Greg and Mehrdad, I am reviewing the drilling program. Please confirm that the yield of the DeepCrete Lite is 1.85. There are so many different cements out there now, I loose track. A yield of 1.85 seems to be a little low with a weight of 10.7 pP9~ Thanks, Tom Maunder, PE AOGCC 9/18!2007 GNI-04 Well Top and Base Injection Interval '/4 Mile Standoff Circles m m m m m m m m m m m m N m cr ~ ~ ~ ~ m m m m m m ~n c.o m m m m m m N ~ SQF~~IDIDI sg6leee sg6eeee -02 sgs9eee s9s8eee s9s~eee s9s6eee 04~ s9sseee s9s4eee GNI-04 1/4 Mile radius GNI-04 1/4 Mile radius --- - circle from the ejected >-- -- circle from SV1 Marker/ CM3 Marker/base top injection interval injection interval * ~~ . -~ * -Note that GNI-04 will reach TD 300 TVD feet above the CM3/base injection interval depth • L` G N I Area TX~e Log G N I-02 Marker ND _ GR ss 10 '"" 110 -4000 -4100 -4200 -4300 -4400 -4500 -ssoo -a7oo -4aoo -4900 -5000 -5100 -5200 -5300 -5400 -5500 -ssoo -5700 -ssoo -5900 `~ -sooo UG1 M NA WS1/0 Sds_ i -slop -s2oo -s3oo -sooo _ssoo -6600 -s7oo -ssoo _6900 ~ Shallowest Permitted Class II Fluid Injection Interval ~ Shallowest Permitted Class II Slurry Injection Interval ~_ GNI area shallowest possible fracture growth based on fracture modeling GNI area wellbore fracture height growth based on pressure falloff tests ~_ Shallowest GNI-U2A MDT pressure interval where formation pressures were elevated above hydrostatic GNI area near wellbore firacture height F- growth based on shut in temperature logging ~ Target Slurry Injection Interval ~-- Projected TD of GNI-04 well ~ r6_o~, CM3 Marker: Base of Permitted Class II ~~ Slurry Injection Interval Below GNI Well TDs (Projected at -6975' TVDSS in GNI-04 area) ~L~ 1 _M~ ~n0 • • Well GNI-04 ' ' ' _' Lateral Stand off Distance to Offset Wells ,- _ _ __ _ ~f l - _ - -- ~- GNI-04 Lateral Standoff at SV7 Marker: Too - - ~_ of Permitted Infection Interval _ - _ _ -- _ _ Lateral Distance to Equivalent Well Marker X Y TVDSS Marker - _ in GNI-04 well - --- _ _ .Comment (1) Comment (2) _ __ - _ -(Feet) - (Feet) ', (Feet) (Feet). _ -- - - __ GNI-04_wp03 SV1 _ 715337 .5956956 -4490 - ___ -- _ _ _ SV1 depth estimated; no '04.17 SV1 713350 5953291 -4449, 4169. _ - shallow logs run in this well _ . - - - _- _ - r SV1 depth estimated, no '04-20 SV1 712713 5953956.. -4388 3985 shallow logs run in this well _ - __ _ __ _ __ - ISV1 dedepth estimated, no '04-21 SV1 711946'. - ,5955563' -4500 . 3666 'shallow logs run in this well q. _ -__ _- - - - - - _ SV1 depth estimated; no '04-22 SV1 712861 5955334 -4502 2960 - ',shallow logs run in this well ' SV1 depth estimated; no ~, '04-23 SV1 ' 712694' 5953542. -4447 4317 shallow logs run in this well ' --- _ _ ' SV1 depth estimated; no '04-24 SV1 713077 5953756 X447 3918 shallow,logs run in this welt - _ _ _ ---- SV1 depth estimated; no '04-25 SV1 7137561 5952918, -4499 4336 shallow logs run in this well -__ _ _ - _ r-- - _ ' _ _ _ ~.SV1 depth estmated; no '04-26 SV1 713880' 5952723'.. -4500'. 4476 _ - - _ ''shallow logs rvn in this well 'SV1 depth estimated; rw '04-27 SV1 715171 5953087 -45001 3873 '.shallow logs run in this well - '~, SV1 depth estimated; no '04-33 SV 1 715614 5955034'' -4504' 1942 shallow logs run in this well '. '..SV1 depth estimated; no '.. '04-35 SV1 714270 5955026 -4502'. 2206 ;shallow logs run in this well GNI-01 SV1 716026, 5957182, -4487', 725 - GNI-02 _ SV1 _ 717454 5957451' -4509' 2174 GNI-02A T SV1 716730'', 5957817- _ -4511 1638 GNI-03 SV1 718725 5956510. X519 3417 --- _. , __x_ 1 . SV1 depth estimated no ', L3-24 SV1 ', 709794' 5960740'. -4500. 6712 shallow logs run in this well ' '~~ - '~ SV1 depth estimated; no L4-11 SV1 719726 5960003'' -4502' 5343 ---- shallow logs run in this well ---- __- -- - _ r_ - - _ __ - _ ',SV1 depth estimated; no L4-15 ' SV1 720423' 5959047''.. -4502' 5499 shallow logs run in this well GNI-04 Lateral Standoff at UG Mc Marker: Toy of Target Perforated Infection Zone ! ', Lateral Distance to Equivalent Well Marker ' X ' Y TVDSS Marker in GNI-04 well Comment (1) ' - _ Comment (2) _ - - - _ - (Feet) , (Feet) - (Feet)- _- (Feet) ~ GNI-04 wp03 UG MC 714400' 5957400' -6430.. __ __ - _- - r---- -~ ~.. - - --- - -- ._-- Mc depth estimated: no ' - _-- '04-17 ' UG MC 7135431 5954574'. -63781 2953 shallow logs run in this well ~~ 'Mc depth estimated; no '04-20 UG_MC 711952 59564321E -6329 2632 'shallow logs run in this well ~ ' '. Mc depth estimated; no '04-21 UG_MC 710894' 5958314 -6382' _ _ 3623 - - shallaw logs run in this well - - - ' - ''- Mc depth estimated, no 11 ' 04-22 _ UG MC 712641 5957963 -6409 - _ - _ 1847 t '1 y _ 'shallow logs run in this well _ ~ ~ ~ - Cl- ,U. -- _ _ r ~~ _ ~I Mc depth estimated; no - '0423 UG MC 711987'. 5954597 -6355' 3699 shallow logs run in thiswell '04-24 _ _. ~ UG_MC ,713378', 5955844 _.. -6380' _._ - - 1861 ~ _ _- - Mc depth estimated, no ~ '',shallow logs run in this well ` ~ ~ \, ~~V ~_ ... _ _ ' Mc depth estimated: no ~ _ .,, r ~~ ~ V ~~+y 04-25 UG MC ! 714966, 5955493 -64051 1990 \zj j _ shallow logs run in this well \ ~~ ~ !. , Mc depth estimated; no '04.26 UG_MC ~ 715178+ 5954267 -6402 3228 shallow logs run in this well x ~, , ~. . _ . ~ Mc depth estimated; no '04-27 UG_MC 717203'' 5954828'1 -6441 3804 shallow Togs run in this well _ ' Mc depth estimated; no '04-33 UG MC - 717379' 5956835 i -6471 _ _ 3032 _ --- - 'sl hallow logs run in this well - _ _ ._ --- ~ ~ ~ ~ Mc depth estimated; no ~~~ , + 'j ~ ~ ~ ' 04-35 _.-- - UG_MC ---- - 714992 -- 5955881' 6410 - _ ', -r 1631 __ ~~ shallow logs run in this well - \ ~+ - _ GNI-01 --- __ UG_MC _ 714452', 59587171 _ -6437'' 1318. ~-_ 1 _ _ _ ___- _~~ \"' ~~~_____ GNI-02 UG_MC 717578', 5959007' -6495'. 3561 GNI-02A UG MC 5 959791 -6472' 2769 GNI-03 t _ _ UG MC + _ 720098'' 5956657 _ -_ -- -6518 5747 Y _ _ i ' ~,, '', '. '... '.. Mc depth estimated, no !, . L3-24 UG MC ' 711895 5960096' -6410' _ 3680 shallow logs run in this well -t - _ _- I... _. y ---- - ~ ~. --~- ' Mc depth estimated: no L411 UG MC ' 718189' 5960797 ' -6527'1 5089 shallow logs run in this well '~~ ~~. '~. Mc depth estimated; no L4-15 UG MC ' 719580' 5958620' -6518 5322 shallow logs run in this well a _---- -- tandoff at Depth Equivalent to GNI-04 TD _ GNI-04 Lateral S _--___-_ __ -_-- Lateral Distance to Equivalent Well Marker X Y TVDSS ' Marker in GNI-04 well _ '_ -- Comment (1) Comment (2) _ - - (Feet) - (Feet) (Feet) (Feet) _ _ GNI-04_wp03 _- TD 714274 5957460 ' _ -6690 - _ __ _ .GNI-04 TD equivalent Depth Equivalent to .estimated; no shallow logs run '04-17 GNI-04 TD 713564 5954736 -6625' 2815 ' in this well '. GNI-04 TD equivalent Depth Equivalent to ' estimated; no shallow logs run 04-20 GNI-04 TD 711780 5956839' -6579' 2570 _ 'yin this well _ _ _ '. GNI-04 TD equivalent ~ Depth Equivalent to ', ''~ '~ estimated; no shallow logs run '04-21 GNI-o4 TD 710762 5958666' -6634 3713 - - _ ', in this well _ - - ~ - '-- '~, GNI-04 TD equivalent Depth Equivalent fo '.. '~~ estimated; no shallow logs run '. '04-22 'GNI-04 TD 712610' 5958308' -6661 1867 _. ' in this well _. __-. __ - ,GNI-04 TD equivalent '. Depth Equivalent to ' ~. estimated; no shallow logs run '04-23 GNI-04 TD 711900' ~ 5954733 -6605 3615 in this well _ ~- --- - r_ -_ _ ' GNI-04 TD equivalent ', Depth Equivalent to 'estimated; no shallow logs run '04-24 GNI-04 TD 713441 5956131 -6632 1568 in this well _._ _ - - - ~, '.. GNI-04 TD equivalent ', Depth Equivalent to estimated; no shallow logs run '04-25 GNI-113 TD 715182 5955830.. -6655' __ 1866 -__ in this well - - _ _ GNI-04 TD equivalent Depth Equivalent to '~ ' '. estimated; no shallow logs run '04-26 GNI-I)4 TD 715345 5954443' -6655'. - -- 3201 _ in this well r ---- - -- --- _ --- ---- - * ~, r ',GNI-04 TD equiTD equivalent ', Depth Equivalent to ~, ' '~~ estimated; no shallow logs run '04-27 'GNI-04 TD ', 717450'' 5955025' -6698, 4002 'in this well '~ - - - -- ~ -- '. I GNI-Q4 TD equivalent '~. Depth Equivalent to '', '~ '. estmated; no shallow logs run ' '04.33 ,GNI-04 TD 7175851 5957082' -6729 3332 - ' in this well - ___ __ - ~ + ~~ _ GNI-04 TD equivalent '~. Depth Equivalent to ' estimated; no shallow logs run '04-35 'GNI-04 TD : 715075' 5956037 -6670 - _ 1633 in this well -__- - _ ---_-- ---- - _ - _ r- _ _ _ __ _ GNI-04 TD equivalent I Depth Equivalent to ' estimated; no shallow logs run ', GNI-01 GNI-oa TD 714303 7 5958 8 5 -6680', 1415 in this well _ __ _ . _ __ '~ ' GNI-04 TD equivalent '. Depth Equivalent to '~ '~. estimated; no shallow logs run '~, GNI-02 'GNI-tkt TD 717585 5959188' -6738' 3735 ' in this well _GNI-02A - ~ - - --~' - - Depthirot reached -- _ -- - __ _ ___ _ r - ~ ~. GNI-04 TD equivalent ~! Depth Equivalent to ' ' '~. estimated; no shallow logs run GNI-03 'GNI-04 TD 720263' 5956667' . -6772 6041 in this well - - - ', --- _ ''. GNI-04 TD equivalent ~',, Depth Equivalent to '. '. ' estimated; no shallow logs run L3-24 ~ GNI-174 TD 712166' 5960009 -6662 _ 3307 _- --_ in this well _-_ __. - --- _ _ ~. i GNI-04 TD equivalent valent to E ~pt estrmat nos ow ~ L411 ~ TD 717990 5960862 -6780 5038 in this well ~ - - -~~ '~ '.GNI-04 TD uivalent Depth Equivalent to ' ~'~ '. estimated; no shallow logs run '~. L4-15 GNI-o4 TD + 719475. 5958570' -6771 ' - ----- _ 5318 ' in this well ~ _ -- -- -- - - -- - - _ -- -F ~ iection Zone GNI-04 Lateral Standoff at CM3 Marker: Base of Permitted In Yell _ _ Marker X Y TVDSS Marker in GNI-04 welt y- _ _ Comment (1) - Comment (2) _ _ L_ (Feet) (Feet) - (Feet) - _ _ _ (Feet) _ • -Lateral distance based on GNI-04-wp03 ' '04-17 CM3 M3 714140 '. ', 713589'' 5957524, ', I. ~' 5954942 j -69751 I. -6935' - 641 __ _ _ '.. ~I CM3 depth estimated; no 'shallow logs run in this well -- lteacnecmvw-ua • -Lateral distance based on ' Projected Depth of GNI-04 CM3 marker, CM3 Depth Will Not ee I Reached in GNI-oa - -- ', ', ', - ',. - -- ~ ~ i ~ • -Lateral distance based on ' ~~ I. ' ~ ', Projected Depth of GNI-04 CM3 ', ~'~, '~, '. '~. CM3 depth estimated; no I. marker, CM3 Depth Will Not ee '04-20 ', - _ - CM3 711561 ' ~ 5957347, - - -6929 2585 'shallow logs run in this well I Reached in GNI-aa ~. • -Lateral distance based on ' '. ''~. Projected Deotlt of GNI-04 CM3 '. 'CM3 depth estimated; no ''~ marker, CM3 DepM Will Not Be '04-21 ---- - CM3 _ 710584', _ 59 9089 _ 3885 ,shallow logs run in this well R raCr a Fred in GNI-64 ',, • -Lateral distance based on '~ '', ' ~I Projected Depth of GNI-04 CM3 ~' ~I CM3 depth estimated; no marker, CM3 Depth Will Not Be ' 0422 -- --___ ~- M3 I 712576 59 3 T - -6991 --_r 2002 - 'shallow logs run in this well ---~-- ~I, Reached in GNI-04 '... ~. • - Later distance based on ' '.. ~'~.. ', Projected Depth of GNI-04 CM3 '~, ', ~'. CM3 depth estimated; no ~. marker, CM3 Depth Will Not Be '04-23 CM3 711769' 5954932 -6990 3513 shallow logs run in this well Reached in GNI-oa ' - - - ° -Lateral distance based on Projected Depth of GNI-04 CM3 .CM3 depth estimated; no .marker; CM3 Depth Will Not Be '04-24 CM3 713513 5956495 -6927 1205 shallow logs run in this well ~ Reached in GNI-04 '. ` -lateral distance based on ~ ' '~.. Projected Depth of GNl-04 CM3 ~ ~'. CM3 depth estimated; no I marker, CM3 Depth Will Not ee '04-25 CM3 715454 ~- 5956263 -6990 1822 shallow logs run in this well ~ _ 'Reached in GNI-04 ' ' -Lateral distance based on Projected Depth of GNI-lY1 CM3 CM3 depth estimated; no marker; CM3 Depth Will Not Be '04-26 CM3 __ 715531 ' _ _ 5954642 ___ _ -6959', 3200 shallow logs run in this well 'Reached in GNI-04 ` -Lateral distance based on '. ~, Projected Depth of GNI-04 CM3 CM3 depth estimated no ..marker; CM3 Will Not Be D ~ 04-27 CM3 717717 5955242 - 7000 4243 ogs run m this well shallow I - y Reached in GN ' f _ - _ _ r_ ~ -_ -_ _. --._ - _ - -- - _--... _ _. . Lateral distance based on ' ' '', Projected Depth of GNI-04 CM3 ' '~ '. CM3 depth estimated; no '~. marker, CM3 Depth Will Not Be '04-33 _ CM3 7178261 5957380A -70391 3689 shallow logs run in this well Reached in GNI-04 ~' ' -Lateral distance based on Projected Depth of GNI-04 CM3 ',. ~. CM3 depth estimated; no I. marker, CM3 Depth Will Not Be '04-35 CM3 715179' 5956226 -6990 1663 shallow logs mn in this well Reached in GNl-04 GNI-01 _ - Depth not reached GNI-02 ~. Depth rat reached '.. GNI-02A _ ~, -_ _ - _ not reached _ __-'~'- - - _ _ ___- GNI-03 i Depth not reached --- --- - - - _-- - ---- - _ - '. -- - _ - ~,' - Laterel distance based on ', ',.. I I Projected Deofh of GNI-04 CM3 ', ' ', I. CM3 depth estimated; no II marker, CM3 Depth Will Not Be L3-24 CM3 712515'', 5959898' -7000 2876 'shallow logs run in this well I Reached in GNI-o4 '. '.. ~..~ • - Laterel distance based on I ' ',. ~ I Projected Depth of GNI-lM CM3 ', ' ~ '. CM3 depth estimated; no 'marker, CM3 Depth Will Not Be L4-11 CM3 ' 717740 5960975', -70891 4987 _ _ _shallow logs run in this well Reached in GNI-04 '~ ' ' - Laterel distance based on ' ',. 1, Projected Depth of GNI-04 CM3 I '~, CM3 depth estimated; no ~'~, marker, CM3 Depth Will Not Be L4-15 CM3 719387' 5958526 -7089 5342 shallow logs run. in this well 'Reached in GNI-04 Page 1 of 3 • • Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) ~~^ _ ~~~ Sent: Monday, September 10, 2007 4:30 PM To: 'Hobbs, Greg S (ANC)'; Nadem, Mehrdad Cc: Jim Regg Subject: RE: GNI-04 PTD Request for Additional Information-again Mehrdad and Greg, I am further reviewing the application for GNI-04. Please see my questions of last Friday (below). I have some further questions with regard to the review of existing wells around the proposed well trajectory. DS 04-22 (185-233) -According to the information in the file, DP became stuck and it was necessary to plug back the well in November, 1985. There is no survey information in the file. Based on the operations summary and the survey information, the "lost" hole section was from 3710' - 4727' and (-3760' - 4050' tvd). It would appear that this hole section is above the permitted injection interval. Would you confirm this? It does not appear that the authorized injection interval was covered when the 9-5/8" casing was ultimately cemented. DS 04-22 was plugged back for sidetrack in early 1994 and DS 04-22A was drilled. DS 04-22A (197-094) -According to the operations information, a section was milled and the well kicked off at 7697' and 05795' tvd). This depth is well above the possible primary cement top. A portion of the new 8-1/2" hole was plugged back, but the depth was well below the authorized injection interval. When the 7" liner was set, the cement was only raised 1000' above the Sag River. It appears that the authorized injection interval was not covered with cement. Would you confirm the proximity of 04-22A with regard to the %< mile radius of GNI-04? DS 04-25 (186-049) -According to the operations information, a significant portion of 12-1/4" hole was lost when a fish got stuck during a trip. Hole TD was 12420' and with the fish from 7180' - 7630' md. Cement was set to 6915' and and then another plug was set between 4100' - 4500' md. New hole was kicked off at 4149' md. When the 9-5/8" casing was cemented, it does not appear that the authorized injection interval was covered with cement. Would you confirm the location of the abandoned hole section? DS 04-35 (191-039) - Of the DS 4 wells, this well is calculated to be the nearest to the %< radius. The report for this well is interesting in that it indicates that a lead slurry of "MTC" (mud to cement) was used. Based on the MTC and cement volumes listed in the operations report, potential top,of MTC is 5200' tvd SS. Of the DS 4 wells examined, this is the highest possible "cement" top. I look forward to your reply. Call or message with any questions. Tom Maunder, PE AOGCC From: Maunder, Thomas E (DOA) Sent: Friday, September q7, 2007 3:28 PM To: 'Hobbs, Greg S (ANC)' Subject: RE: GNI-04 PTD Request for Additional Information ~ ~----- Greg and Mehrdad, I am reviewing the drilling program. Please confirm that the yield of the DeepCrete Lite is 1.85. There are so many different cements out there now, I loose track. A yield of 1.85 seems to be a little low with a weight of 10.7 pp9~ Thanks, Tom Maunder, PE AOGCC From: Hobbs, Greg S (ANC) [mailto:Greg.Hobbs@bp.com] 9/11/2007 Page 2 of 3 • • Sent: Thursday, September 06, 2007 12:03 PM To: Maunder, Thomas E (DOA) Subject: RE: GNI-04 PTD Request for Additional Information Thanks Tom! From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Thursday, September 06, 2007 10:51 AM To: Bifl, Michael L (Natchiq) Cc: Nadem, Mehrdad; Bernaski, Greg E; Hobbs, Greg S (ANC); Engel, Harry R Subject: RE: GNI-04 PTD Request for Additional Information Mike, et al, I have just briefly looked at the documents. This looks very complete. I will be back to you/Mehrdad with any further questions. Tom From: Bill, Michael L (Natchiq) [mailto:Michael.Bill@bp.com] Sent: Thursday, September 06, 2007 10:17 AM To: Maunder, Thomas E (DOA) Cc: Nadem, Mehrdad; Bernaski, Greg E; Hobbs, Greg S (ANC); Engel, Harry R Subject: GNI-04 PTD Request for Additional Information Tom, Mehrdad Nadem is out of the office this week but checking his email. He asked me to work with geologist Greg Bernaski and forward the information you requested. Area Injection Order 4E, Rule 2 lists the authorized injection zone for slurry disposal as " ... strata defined as those which correlate with and are common to strata found in the ARCO Sag River State No. 1 well between the measured depths of 4,270-6750 feet." The top and base of this interval are close to the SV1 and CM3 markers. Enclosed are three documents to answer your questions. - map showing the proposed GNI-04 welt course, offset wells and 114 mile circles at the SV1 and CM3 markers and 1/4 mile circles - type log (GNI-02) showing the markers for reference -spreadsheet containing calculated distances from the proposed GNI-04 well course to the equivalent markers in offset wells. The spreadsheet contains calculations at the SV1 marker, the UG Mc marker (target perforation interval), the equivalent depth at the proposed GNI-04 TD, and at the CM3 marker. Note, well GNI-04 will not penetrate the CM3 marker. The spreadsheet shows the distance between the proposed TD of well GNI-04 and the equivalent depth in the nearest wells to be: GNI-01 1415 ft, 4-24 1568 ft, and 4-35 1633 ft. As shown on the type log, the planned perforation interval is 20 feet at the UG Mc 04 marker. The nearest wells at the UG Mc marker are: GN1-01 1318 ft, 4-35 1631 ft, and 4-24 1861 ft. Let me or Mehrdad know if you have any questions or need additional information. Mike Bill ADW Wells Group 907-564-4692 office 907-564-5510 fax 9!11/2007 • Page 3 of 3 From: Maunder, Thomas E {DOA) [mailto:tom.maunder@alaska.gov] Sent: friday, August 31, 2007 2:54 PM To: Nadem, Mehrdad Cc: Hobbs, Greg S (ANC); Arthur C Saltmarsh Subject: GNI-04 Mehrdad, We are beginning the initial review of the application for GNI-04. You have included the well proximity information; however I am requesting that a larger scale plot be provided. 8-112° x 11"should be fine with the focus being the'/. mile radius a# the top and bottom of the authorized injection interval. Please show the production wells you have identified. if possible, tvd depth markers along the well paths would be appreciated. Thanks in advance. Ca11 or message with any questions. Tom Maunder, PE AOGCC 9/11/2007 Alaska Department of Natural Resources Land Administration System Page 1 of 2 ~,:;,. ~f` _-°,~; t.ias~p-r ~'-d ~~~;~, . ;r~;-~ Plats Recorder`s Search State Cabins ~l~tuFa~ R+es~~r+ae5 Alaska ?Na Case 5urnrnary File Type ADL„ ._ , File Number: 28323 ', ~ Printable Case Fite_Summary See Township, Range, Section and Acreage? ~" Yes ~+ No New Search ~ AS Men~~ I Case Abstract I Case Detail I Lane! Abstract _. Pile: AUL 28323 ~~'!='~' Search for Status Plat Updates .<~~ of 09i0~i~0(17 Customer: 000107377 BP LX1'LORATION (ALAS1~'~) INC PO BOX 196612/900 E. BENSON BL ATTN: LAND MANAGER- ALASKA ANCHORAGE AK 99~ 196612 Case Type: '~~~. OIL & GAS LEASE COMP DNR Urait: 780. OIL AND GAS File Location: DOG DIV OIL ANDGAS Case Status: 35 ISSUED Status Date: 09/14/1965 Total Acres: 2560.000 Date Initiated: 05/28/1965 Office of Primary Responsibility: DOG DIV OIL AND GAS Last Transaction Date: 12/04/2006 Case Subtype. NORTH SLOPE Last Transaction: AA-NRB ASSIGNMENT APPROVED Meridian: U Townslrr~~: U I l N Rirrt,~~ : 01 ~ E: ,S~°ctroj~: l ~ .Sectirni -lcrE~.~~: 6'10 Search Plats llc~ridi~ur.~ E Tuii~n~hih: O1 IN Kc~ns~r~: 015E S'ec[iun: 14 Scctrun_9cf°E~~~: C~0 ME~r~rdiur~.~ U %uu~rr,rhip: 01 I N ka~t~e: U 15 L ~ S'ecliurt: ~ i .1"~~r~iun . l crc~s~: 64U IYI~~rrdrurr: U 7ini~n,~hip.~ OI iN R~ut~e.~ Ol>[~; .5~~~~~Irujt.~ ?-~ S'e~tinr~;lcrt~5~.~ 6-10 l,c~al Description US-28-1965 * * *SALE .NOTICE LEGAL DESCRIPTIO_N* CI =i-153 TI 1 N-RISE- UM 13, X 4, 23, 2~ 2560.00 U- 3- 7 end ca Case ~ut~tmry Last updated on 09105/2007. http://wtivw. dnr.state. ak. us/las/Case_S ummary. cfm?FileType=ADL&FileNumber =2 8323 & ... 9/5/2007 ~- ~`~"'~ UNI'x'ED37ATESENVIR R~ 1rNTALPAOTEC'~'tONAGENCY GION 1d 1200 Sixth Avenue . Seattle, WA 913101 ~ r ~vl,.. 2oor Reply To . AtW Of OCE -12'7 C TIFIEA M -RETURN RECEIPT RE UESTED Mr. Neil E. Dunn BP Exploration (Alaska), Inc. `'~~ ~~~ ~' x ~~~y P. O. Hox 196612 90O••l/ast Benson Boulevard Anchorage, Alaska 99529.5612 Re: Prudhoe Bay Unit Grind and Inject Project, Prudhoe Bay, North Slope, Alaska UIC Permit No.: AK-1I008-A Dear Mr. Dunn; We are issuing an Underground ejection Control permit for BP Exploration {Alaska) Inc., (BPXA) Greater Prudhoe Bay Grind and Inject Area Prudhoe Bay; North Slope, Alaska. The enclosed docum~t autktorizes the facility to inject non-hazardous industrial waste utilizing up to three (3) Class I injection wells at the Prudhoe Bay Unit below the SVI Sagavanirktok Formation aril above the CM2 Colville/Seabee Shale Formation. The operator is not authorized to initiate Class I injection activities until the Completion Report has been submitted to EPA and approved by the Director of the Office of Ca fiance an authorized representative. The authorization far Class V fluids ~ ~ Enf°rce'nent or remain in place until all requirements of the Class i permit have been metes. tTlte start date forlthe~morvitoxing and record keeping requirements for this permit will be the date that EPA provides written authorization to inject. Also enclosed is EPA's response to the comments received an the draft permit during the public comment period, This letter serves as service of notice under 40 CFR 124.19(a}. The permit wilt become effective on the date indicated in the permit unless a timely appeal meeting the requirements of 40 CFR 224.19 is received by the Envirorunental Appeals Board. Information about the administrative appeal process .may be obtained on-line at epa.gov/eab.or by contacting the Clerk of the Environnaer~tal Appeals Board at (202) 233-0122. Sincerely, Uir. Michael A. 8ussell, Director Oft=<ce of Compliance and Enforcement Enclosures: Permit Response to Comments • ec: Sharmon Stambaugh, ADEC Division of Water/VVaste Discharge Permits Trevor Fairbanks, ADEC Industria! Wastewater Program Britt Constantine John Noun, Commissioner, A4GCC t- ~ (~~ l of 20 ISSUANCE DATE AND SIGNATURE PAGE U.S, ENVIRONMENTAL PROTECTION AGENCY UNDERGROUND INJECTION CONTROL PERMIT: CLASS I Permit Number AK-1I408-A In compliance with provisions of the Safe Drinking Water Ac"t (SDWAj, as amended, (42 U.S.C. 300f-300j-9), and attendant regulations incorporated by the U.S. Environmental Protection Agency (EPA} under Title 40 of the Code of Federal Regulations, BP Exploration (Alaska) Inc. (BpX.A,)(p~ittee) is authorized to inject non-hazardous ~ (> industrial waste utilizing up to three (3) Class I injection wells through three current, ~' y sidetrack ornew/replacement Class I injection wells associated with the Prudhoe Ba Unit Grind and Inject (PBU-G&I) Project, North Slape, Alaska, into the Prince Creek/Ugnu and West Sak and Sagavanirktok Formations, in accordance with Title 40 CFR 144.33 and the conditions sat forth herein. injection of hazardous was#e as defined under the Resource Conservation and Recovery Act (RCRA}, as amend are not authorized under this permit, injection shall~t con~fnence under thids permit un~~iies the operator has received written authorization to inject from EPA Region 10's Director of the Office of Corrxpliance and Enforcement (Director). All references to Title 40 of the Code of Federal Regulations are to regulations that are in effect on the date that this permit is issued. Figures and appendices are referenced to EPXA's I'BU-G&I Project, Underground Injection Control Class I Permit Application dated November 20, 2006. This permit shall become effective September 1, 2007, in accordance with 40 CFR 124.1 S. This permit and the authorization to innject shall expire at midnight, august 31, 2017, unless terminated, Signed this ~'~`day of Sr1 2007. ~ . ~~ Michael A. Bussell, Director Office of Compliance and Enforcement U.S. Environmental Protection Agency Region I 0 (OCE-164) 1200 Sixth Avenue Seattle, WA 98 I 0 ] TRANSMITTAL LETTER CHECKLIST WELL NAME ~~~1 ~~j~~~ PTD# °?~~// ~~ Development / Service Exploratory Stratigraphic Test Non-Conventional Well Circle Appropriate Letter /Paragraphs to be Included in Transmittal Letter CHECK ADD-ONS TEXT FOR APPROVAL LETTER WHAT (OPTIONS) APPLIES MULTI LATERAL The permit is for a new wellbore segment of existing well (If last two digits in permit No. , API No. 50- - - API number are Production should continue to be reported as a function of the between 60-69) original API number stated above. PILOT HOLE In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( PH) and API number (50- - -_) from records, data and logs acquired for well SPACING The permit is approved subject to full compliance with 20 AAC EXCEPTION 25.055. Approval to perforate and produce /inject is contingent upon issuance of a conservation order approving a spacing exception. , assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: Non-Conventional production or production testing of coal bed methane is not allowed Well for dame of well) until after (Company Namel has designed and implemented a water well testing program to provide baseline data on water quality and quantity. SCompan~Name) must contact the Commission to obtain advance approval of such water well testing ro ram. Rev: 7/13/2007 • • ^^ ~ , m o o. , m ~ a, , Q ~ ; ~~ , , ~ , . i 3, w, S ' . c O ! ; ~, ~, 3. v. ~ , . N N. O ~ ~ ~ ~ ~ ~ ~ ~ ~ ~, ~ _, ~ ~ o. 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