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206-135
7. Property Designation (Lease Number): 1. Operations Performed: 2. Operator Name: 3. Address: 4. Well Class Before Work:5. Permit to Drill Number: 6. API Number: 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): Susp Well Insp Install Whipstock Mod Artificial Lift Perforate New Pool Perforate Plug Perforations Coiled Tubing Ops Other Stimulate Fracture Stimulate Alter Casing Pull Tubing Repair Well Other: Change Approved Program Operations shutdown 11. Present Well Condition Summary: Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 16. Well Status after work: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. OIL GAS WINJ WAG GINJ WDSPL GSTOR Suspended SPLUG Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: PBU AGI-10A Water Wash Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 206-135 50-029-22353-01-00 9937 Conductor Surface Intermediate Production Liner 8394 76 3690 9408 576 9933 20" 13-3/8" 9-5/8" 7" 8390 36 - 112 35 - 3725 30 - 9439 9359 - 9935 36 - 112 35 - 3381 30 - 7982 7916 - 8392 none 470 2260 4760 5410 none 1490 5020 6870 7240 9485 - 9933 7-5/8" x 7" L-80 27 - 9366 8020 - 8390 Structural 7" Baker S-3 , 9317 , 7883 7" DB-6 , 2174 , 2130 9317 7883 Bo York Operations Manager Dave Bjork David.Bjork@hilcorp.com (907) 564-4672 PRUDHOE BAY / PRUDHOE OIL Total Depth Effective Depth measured true vertical feet feet feet feet measured true vertical measured measured feet feet feet feet measured true vertical Plugs Junk Packer Measured depth True Vertical depth feet feet Perforation depth Tubing (size, grade, measured and true vertical depth) Packers and SSSV (type, measured and true vertical depth) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a.Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: Subsequent to operation: 15. Well Class after work: Exploratory Development Service StratigraphicDaily Report of Well Operations Copies of Logs and Surveys Run Electronic Fracture Stimulation Data Sundry Number or N/A if C.O. Exempt: ADL 0034628 , 0028301 27 - 7922 0 0 148573 223110 0 0 225 200 3304 3373 324-068 13b. Pools active after work:PRUDHOE OIL STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS Sr Pet Eng: Sr Pet Geo: Form 10-404 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Sr Res Eng: Due Within 30 days of Operations By Grace Christianson at 8:24 am, Jun 18, 2024 Digitally signed by David Bjork (3888) DN: cn=David Bjork (3888) Reason: I am approving this document. Date: 2024.06.17 15:25:11 -08'00' David Bjork (3888) DSR-6/18/24 RBDMS JSB 062024 WCB 9-9-2024 ACTIVITYDATE SUMMARY 5/18/2024 T/I/O= 2692/168/104 (TUBING WASH/PICKLE) Pumped 10 bbls of 60/40, 100 bbls of 180* Diesel, 600 bbls of Fresh Water with 0.2% F-103 Surfactant, and 15 bbls of 60/40 per procedure. DSO notified of well status upon departure. Valve Positions - SV/WV/SSV/Hardline= Closed, MV= Open, IA/OA= OTG FWHPs= 330/190/185 Daily Report of Well Operations PBU AGI-10A Pumped 10 bbls of 60/40, 100 bbls() of 180* Diesel, 600 bbls of Fresh Water with 0.2% F-103 Surfactant, and 15 bbls of 60/40 per procedure 7. If perforating: 1. Type of Request: 2. Operator Name: 3. Address: 4. Current Well Class:5. Permit to Drill Number: 6. API Number: 8. Well Name and Number: 9. Property Designation (Lease Number):10. Field: Abandon Suspend Plug for Redrill Perforate New Pool Perforate Plug Perforations Re-enter Susp Well Other Stimulate Fracture Stimulate Alter Casing Pull Tubing Repair Well Other: Change Approved Program Operations shutdown What Regulation or Conservation Order governs well spacing in this pool? Will perfs require a spacing exception due to property boundaries?Yes No 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): PRESENT WELL CONDITION SUMMARY Perforation Depth MD (ft): Perforation Depth TVD (ft):Tubing Size: Tubing Grade: Tubing MD (ft): Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 12. Attachments: 14. Estimated Date for Commencing Operations: 13. Well Class after proposed work: 15. Well Status after proposed work: 16. Verbal Approval: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approcal. Proposal Summary Wellbore schematic BOP SketchDetailed Operations Program OIL GAS WINJ WAG GINJ WDSPL GSTOR Op Shutdown Suspended SPLUG Abandoned ServiceDevelopmentStratigraphicExploratory Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: AOGCC USE ONLY Commission Representative: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Location ClearanceMechanical Integrity TestBOP TestPlug Integrity Other Conditions of Approval: Post Initial Injection MIT Req'd?Yes No Subsequent Form Required: Approved By:Date: APPROVED BY THE AOGCCCOMMISSIONER PBU AGI-10A Water Wash Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 206-135 50-029-22353-01-00 ADL 0034628 , 0028301 9937 Conductor Surface Intermediate Production Liner 8394 76 3690 9408 576 9933 20" 13-3/8" 9-5/8" 7" 8390 36 - 112 35 - 3725 30 - 9439 9359 - 9935 36 - 112 35 - 3381 30 - 7982 7916 - 8392 none 470 2260 4760 5410 none 1490 5020 6870 7240 9485 - 9933 7-5/8" x 7" L-80 27 - 93668020 - 8390 Structural 7" Baker S-3 7" DB-6 9317 / 7883 2174 / 2130 Date: Bo York Operations Manager Dave Bjork David.Bjork@hilcorp.com 904.564.4672 PRUDHOE BAY 3-1-2024 Current Pools: PRUDHOE OIL Proposed Pools: PRUDHOE OIL Suspension Expiration Date: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 Comm. Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Form 10-403 Revised 06/2023 Approved application is valid for 12 months from the date of approval.Submit PDF to aogcc.permitting@alaska.gov By Samantha Coldiron at 9:09 am, Mar 08, 2024 324-151 Digitally signed by Eric Dickerman (4002) DN: cn=Eric Dickerman (4002) Date: 2024.02.07 13:51:29 - 09'00' Eric Dickerman (4002) MGR11MAR24 10-404 A.Dewhurst 08MAR24 DSR-3/11/24*&: Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.03.11 17:43:19 -08'00'03/11/24 RBDMS JSB 031324 Well Work Prognosis Well Name:AGI-10A API Number:50-029-22353-01 Current Status:Gas Injector Leg: Estimated Start Date:March 1, 2024 Rig:N/A Reg. Approval Req’d?10-403 Date Reg. Approval Received: Regulatory Contact:Carrie Janowski Permit to Drill Number:2061350 First Call Engineer:Dave Bjork Office: 907-564-4672 Cell: 907-440-0331 Second Call Engineer: Gas Injection Rate: ~265,000 Mscf/Day Injection Pressure: 3,450 psi Reservoir Pressure (Estimate): 3300 psi Program Objective(s): AGI-10A is a gas cap injection well that has demonstrated a decrease in injectivity. The well has not been water washed since 2020. Water washes are designed to dissolve salts and asphaltenes in the tubing and formation. The objective is to perform a tubing water wash to increase injectivity and perform a general maintenance on Gas Injection Wells. Proposed Program: Pump diesel followed by Fresh Water and Surfactant as per attached pumping template. Well Work Prognosis Well Work Prognosis H2S Value N/A H2S Date N/A Work Desc AFE Date Engineer Phone Job Objective Pump Schedule Stage Fluid Type Pump Into Vol (bbls) Rate (bpm)Max Pres (psi) 1 Spear Methanol / Water TBG 10 1-3 2500 2 Solvent Diesel TBG 100 1-3 2500 3 Over-Flush Fresh Water TBG 600 see below 1800 4 Spear Methanol / Water TBG 15 1-3 1800 5 6 7 Detailed Procedure David Bjork (907) 564-4672 Well AGI-10A GI Water Wash 01/28/24 Increase well injectivity by performing a water wash. -Use 2 full uprights of fresh water mixed with 0.02% F-103 surfactant. Use 100 bbls of diesel from COTU. -Heat diesel to ~120*F -Order FreshWater to be at ~160*F -Freeze Protect contingent on WSL and ambient temp/seasonal pumping 1.) 10 bbl 60/40 MeOH/water spear 2.) 50 bbls COTU diesel (heated to ~120 deg F)at ~1 to 3 bpm. 3.) Pump 600 bbls of fresh water with 0.02% F-103 surfactant per following: a.) Pump 380 bbls of fresh water with 0.02% F-103 surfactant at ~5 bpm. Max pressure during this pumping can reach 1800 psi. Once 380 bbls has been pumped, shut-down pumps and let diesel soak across perfs for 2 hours -this should allow ~ 50 bbls of diesel to be pumped into perfs and a remaining 50 bbls to soak outside the perfs. b.) After 2 hour soak time, resume pumping at max rate/pressure (whichever is hit first) for next 220 bbls of fresh water with 0.02% F-103 surfactant. 4.) 15 bbls of 60/40 MeOH/water freeze protect. 5.) RDMO. Return well to gas injection. if well isnt going to be POI then FP See ~ pumping time schedule and notesbelow COTU diesel has xylene impurities left, treat with proper safety precautions Clear Well Work Prognosis Pump Time Fluid type vol (bbls)rate (bpm)Time (min) time (hours) methanol 10 1 10 0.17 diesel 100 1.5 67 1.11 FW flush 410 5 82 1.37 Soak 2.00 FW flush 190 5 38 0.63 methanol cap 15 1.5 10 0.17 5.44 Soak Time of Diesel/Xylene 1 2 Diesel/Xylene Notes Note 1 Note 2 Note 3 Hot fluids recommended: Note 1 Fresh Water and Surfactant Notes Note 1 Tubing has gas in it prior to pumping, any fluids pumped first will free fall. Soak time - keep at a minimum of ~2 hours; xylene works best with longer soak times (at least on asphaltenes) SBG treatments have a 3 hour soak time as well (just an FYI) Soak time is really a time for diesel/xylene to seep through the perfs vs pushing/rushing through Max pump rates creates turbulence and has contact with the tubing walls. Also cuts down on time Use COTU "diesel" only in these treatments if available. See Craig Graff explanation below. COTU technically can’t make diesel. On good days it can make Jet A or Heating Oil. Neither meet the specs for diesel. The reason they are different is that they have a lot more aromatics and sulfur in them than diesel. Road diesel and ULSD have most of those bad components taken out, which means that they can only dissolve straight chain hydrocarbons (paraffins), and not aromatics. These will make asphaltenes precipitate instead of cleaning them up.COTU “diesel” has enough things like xylene and toluene left in it to make it a pretty good solvent even for asphaltenes. A real refinery would take all of those out to be sold for higher margins in other products. If COTU "diesel"is not available, use other available diesel and xylene at a 50/50 mixture. As you read diesel in instructions below, can substitue with diesel/xylene If xylene is used for a 50/50 diesel/xylene mixture, heated xylene to 80 deg F or higher, use pump rates of 1 to 1.5 bpm. Injectivity results have improved when all fluids pumped are at warmer temps MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Wednesday, June 15, 2022 SUBJECT:Mechanical Integrity Tests TO: FROM:Brian Bixby P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp North Slope, LLC AGI-10A PRUDHOE BAY UNIT AGI-10A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 06/15/2022 AGI-10A 50-029-22353-01-00 206-135-0 G SPT 7882 2061350 1970 3395 3393 3392 3397 103 136 136 135 4YRTST P Brian Bixby 5/22/2022 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 UNIT AGI-10A Inspection Date: Tubing OA Packer Depth 251 2495 2464 2460IA 45 Min 60 Min Rel Insp Num: Insp Num:mitBDB220522153644 BBL Pumped:4.6 BBL Returned:3.2 Wednesday, June 15, 2022 Page 1 of 1 9 9 9 9 9 9 9 9 9 9James B. Regg Digitally signed by James B. Regg Date: 2022.06.15 11:23:43 -08'00' Operator Name:2. Development Exploratory Service 5 Permit to Drill Number:206-135 6.50-029-22353-01-00 PRUDHOE BAY, PRUDHOE OIL Hilcorp North Slope, LLC 5. Well Name and Number:8. 10.Field/Pools: Well Class Before Work4. Present Well Condition Summary:11. Total Depth: measured feet feet Plugs measured feet feet Effective Depth: measured feet feet Packer measured feet feettrue vertical true vertical 9937 9933 8390 9317 None None 7882 Casing: Length: Size: MD: TVD: Burst: Collapse: Structural Conductor 76 20" 36 - 112 36 - 112 1490 470 Surface 3690 13-3/8" 35 - 3725 35 - 3381 5020 2260 Intermediate 9409 9-5/8" 30 - 9439 30 - 7982 6870 4760 Production Perforation Depth: Measured depth: 9485 - 9933 feet True vertical depth:8020 - 8390 feet Tubing (size, grade, measured and true vertical depth)7-5/8" 29.7# x 7" 26# L-80 27 - 9366 27 - 7922 9317 7882Packers and SSSV (type, measured and true vertical depth) 7" Baker S-3 Packer Liner 576 7" 9359 - 9935 7916 - 8392 7240 5410 12. Stimulation or cement squeeze summary: Intervals treated (measured): Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure 3390300 223,195 250 193,919 3390 Representative Daily Average Production or Injection Data Prior to well operation: Subsequent to operation: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Contact Email: David Bjork david.bjork@hilcorp.com Authorized Name:Bo York Authorized Title: Authorized Signature with Date:Contact Phone: Treatment descriptions including volumes used and final pressure: 13. Operations Manager Operations Performed1. Abandon Plug Perforations Fracture Stimulate Pull Tubing GSTOR WINJ WAG GINJ 5 SUSP SPLUG 16. Well Status after work:Oil Gas Exploratory Development Stratigraphic 15. Well Class after work: 5Service WDSPL 14. Attachments: (required per 20 AAC 25.070.25.071, & 25.283) Daily Report of Well Operations Copies of Logs and Surveys Run true vertical measured8394 Sundry Number or N/A if C.O. Exempt: 320-201 7" DB-6 SSSV 2174 2129 Junk Packer Printed and Electronic Fracture Stimulation Data 5 Water Wash Operations shutdown Change Approved Program 5 Senior Pet Engineer:Senior Res. Engineer: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS Suspend Perforate Other Stimulate Alter Casing Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well 3.Address: 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 7.Property Designation (Lease Number):ADL 028301 & 034628 PBU AGI-10A 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): Stratigraphic Other: API Number: Form 10-404 Revised 03/2020 Submit Within 30 days of Operations 564-4672 By Jody Colombie at 8:22 am, Aug 07, 2020 By Jody Colombie at 8:23 am, Aug 07, 2020 Digitally signed by Bo York DN: cn=Bo York, c=US, o=HIlcorp Alaska LLC, ou=Alaska North Slope, email=byork@hilcorp.com Date: 2020.08.06 18:52:20 -08'00' Bo York DSR-8/7/2020MGR07AUG2020 RBDMS HEW 8/7/2020 ACTIVITYDATE SUMMARY 7/15/2020 T/I/O= 2600/250/60 Temp= Inj LRS Unit 76- Tubing Wash/Pickle. Down TBG: 10 bls 50/50 50 bbls 120* diesel 391 bbls FW w/ .02% F-103 Surfactant 2hr soak 187 bbls FW w/ .02% F-103 Surfactant 2 bbls 50/50 Notified DSO to POI, SV WV closed, SSV MV IA OA = open. Final Whp's=100/290/105 Daily Report of Well Operations PBU AGI-10A 7. If perforating: 1. Type of Request: 2. Operator Name: 3. Address: 4. Current Well Class:5. Permit to Drill Number: 6. API Number: 8. Well Name and Number: 9. Property Designation (Lease Number):10. Field: Abandon Suspend Plug for Redrill Perforate New Pool Perforate Plug Perforations Re-enter Susp Well Other Stimulate Fracture Stimulate Alter Casing Pull Tubing Repair Well Other: Change Approved Program Operations shutdown What Regulation or Conservation Order governs well spacing in this pool? Will perfs require a spacing exception due to property boundaries?Yes No 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): PRESENT WELL CONDITION SUMMARY Perforation Depth MD (ft): Perforation Depth TVD (ft):Tubing Size: Tubing Grade: Tubing MD (ft): Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 12. Attachments: 14. Estimated Date for Commencing Operations: 13. Well Class after proposed work: 15. Well Status after proposed work: 16. Verbal Approval: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approcal. Proposal Summary Wellbore schematic BOP SketchDetailed Operations Program OIL GAS WINJ WAG GINJ WDSPL GSTOR Op Shutdown Suspended SPLUG Abandoned ServiceDevelopmentStratigraphicExploratory Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: AOGCC USE ONLY Commission Representative: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Location ClearanceMechanical Integrity TestBOP TestPlug Integrity Other Conditions of Approval: Post Initial Injection MIT Req'd?Yes No Subsequent Form Required: Approved By:Date: APPROVED BY THE AOGCCCOMMISSIONER PBU AGI-10A Water Wash Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 206-135 50-029-22353-01-00 ADL 0034628 , 0028301 9937 Conductor Surface Intermediate Production Liner 8394 76 3690 9408 576 9933 20" 13-3/8" 9-5/8" 7" 8390 36 - 112 35 - 3725 30 - 9439 9359 - 9935 36 - 112 35 - 3381 30 - 7982 7916 - 8392 none 470 2260 4760 5410 none 1490 5020 6870 7240 9485 - 9933 7-5/8" x 7" L-80 27 - 93668020 - 8390 Structural 7" Baker S-3 7" DB-6 9317 / 7883 2174 / 2130 Date: Bo York Operations Manager Dave Bjork David.Bjork@hilcorp.com 904.564.4672 PRUDHOE BAY 3-1-2024 Current Pools: PRUDHOE OIL Proposed Pools: PRUDHOE OIL Suspension Expiration Date: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 Comm. Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Form 10-403 Revised 06/2023 Approved application is valid for 12 months from the date of approval.Submit PDF to aogcc.permitting@alaska.gov By Samantha Coldiron at 1:54 pm, Feb 08, 2024 324-068 Digitally signed by Eric Dickerman (4002) DN: cn=Eric Dickerman (4002) Date: 2024.02.07 13:51:29 - 09'00' Eric Dickerman (4002) MGR13FEB24 DSR-2/13/24 10-404 SFD 2/9/2024*&: Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.02.29 13:57:04 -09'00'02/29/24 RBDMS JSB 062024 Well Work Prognosis Well Name:AGI-10A API Number:50-029-22353-01 Current Status:Gas Injector Leg: Estimated Start Date:March 1, 2024 Rig:N/A Reg. Approval Req’d?10-403 Date Reg. Approval Received: Regulatory Contact:Carrie Janowski Permit to Drill Number:2061350 First Call Engineer:Dave Bjork Office: 907-564-4672 Cell: 907-440-0331 Second Call Engineer: Gas Injection Rate: ~265,000 Mscf/Day Injection Pressure: 3,450 psi Reservoir Pressure (Estimate): 3300 psi Program Objective(s): AGI-10A is a gas cap injection well that has demonstrated a decrease in injectivity. The well has not been water washed since 2020. Water washes are designed to dissolve salts and asphaltenes in the tubing and formation. The objective is to perform a tubing water wash to increase injectivity and perform a general maintenance on Gas Injection Wells. Proposed Program: Pump diesel followed by Fresh Water and Surfactant as per attached pumping template. Well Work Prognosis Well Work Prognosis H2S Value N/A H2S Date N/A Work Desc AFE Date Engineer Phone Job Objective Pump Schedule Stage Fluid Type Pump Into Vol (bbls) Rate (bpm)Max Pres (psi) 1 Spear Methanol / Water TBG 10 1-3 2500 2 Solvent Diesel TBG 100 1-3 2500 3 Over-Flush Fresh Water TBG 600 see below 1800 4 Spear Methanol / Water TBG 15 1-3 1800 5 6 7 Detailed Procedure David Bjork (907) 564-4672 Well AGI-10A GI Water Wash 01/28/24 Increase well injectivity by performing a water wash. -Use 2 full uprights of fresh water mixed with 0.02% F-103 surfactant. Use 100 bbls of diesel from COTU. -Heat diesel to ~120*F -Order FreshWater to be at ~160*F -Freeze Protect contingent on WSL and ambient temp/seasonal pumping 1.) 10 bbl 60/40 MeOH/water spear 2.) 50 bbls COTU diesel (heated to ~120 deg F)at ~1 to 3 bpm. 3.) Pump 600 bbls of fresh water with 0.02% F-103 surfactant per following: a.) Pump 380 bbls of fresh water with 0.02% F-103 surfactant at ~5 bpm. Max pressure during this pumping can reach 1800 psi. Once 380 bbls has been pumped, shut-down pumps and let diesel soak across perfs for 2 hours -this should allow ~ 50 bbls of diesel to be pumped into perfs and a remaining 50 bbls to soak outside the perfs. b.) After 2 hour soak time, resume pumping at max rate/pressure (whichever is hit first) for next 220 bbls of fresh water with 0.02% F-103 surfactant. 4.) 15 bbls of 60/40 MeOH/water freeze protect. 5.) RDMO. Return well to gas injection. if well isnt going to be POI then FP See ~ pumping time schedule and notesbelow COTU diesel has xylene impurities left, treat with proper safety precautions Clear Well Work Prognosis Pump Time Fluid type vol (bbls)rate (bpm)Time (min) time (hours) methanol 10 1 10 0.17 diesel 100 1.5 67 1.11 FW flush 410 5 82 1.37 Soak 2.00 FW flush 190 5 38 0.63 methanol cap 15 1.5 10 0.17 5.44 Soak Time of Diesel/Xylene 1 2 Diesel/Xylene Notes Note 1 Note 2 Note 3 Hot fluids recommended: Note 1 Fresh Water and Surfactant Notes Note 1 Tubing has gas in it prior to pumping, any fluids pumped first will free fall. Soak time - keep at a minimum of ~2 hours; xylene works best with longer soak times (at least on asphaltenes) SBG treatments have a 3 hour soak time as well (just an FYI) Soak time is really a time for diesel/xylene to seep through the perfs vs pushing/rushing through Max pump rates creates turbulence and has contact with the tubing walls. Also cuts down on time Use COTU "diesel" only in these treatments if available. See Craig Graff explanation below. COTU technically can’t make diesel. On good days it can make Jet A or Heating Oil. Neither meet the specs for diesel. The reason they are different is that they have a lot more aromatics and sulfur in them than diesel. Road diesel and ULSD have most of those bad components taken out, which means that they can only dissolve straight chain hydrocarbons (paraffins), and not aromatics. These will make asphaltenes precipitate instead of cleaning them up.COTU “diesel” has enough things like xylene and toluene left in it to make it a pretty good solvent even for asphaltenes. A real refinery would take all of those out to be sold for higher margins in other products. If COTU "diesel"is not available, use other available diesel and xylene at a 50/50 mixture. As you read diesel in instructions below, can substitue with diesel/xylene If xylene is used for a 50/50 diesel/xylene mixture, heated xylene to 80 deg F or higher, use pump rates of 1 to 1.5 bpm. Injectivity results have improved when all fluids pumped are at warmer temps Operator Name:2. Exploratory Development Service 5 Permit to Drill Number:206-135 6.API Number:50-029-22353-01-00 PRUDHOE BAY, PRUDHOE OIL BP Exploration (Alaska), Inc 5. Field/Pools:9. Well Name and Number: ADL 028301 & 034628 Property Designation (Lease Number):10. 8. PBU AGI-10A 7.If perforating: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception? Stratigraphic Current Well Class:4. Type of Request:1.Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Water Wash Op Shutdown GAS GSTOR WAG 5 SPLUG Abandoned Oil WINJ Exploratory Development Stratigraphic 5Service WDSPL 12. Attachments: PRESENT WELL CONDITION SUMMARY 9937 Effective Depth MD: L-80 11. 7/13/2020 Commission Representative: 15. Suspended Contact Name: Brown, Don L. Contact Email: browd2@BP.com Authorized Name: Brown, Don L. Authorized Title:Petroleum Engineer Authorized Signature: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Yes No Spacing Exception Required?Subsequent Form Required: Approved by:COMMISSIONER APPROVED BYTHE COMMISSION Date: 5OtherAlter Casing Pull Tubing Conditions of approval: Notify Commission so that a representative may witness Sundry Number: COMMISSION USE ONLY 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Detailed Operations Program Packers and SSSV Type: 7" DB-6 SSSV Packers and SSSV MD (ft) and TVD (ft): Perforation Depth MD (ft):Tubing Size: Size Total Depth MD (ft):Total Depth TVD(ft): 8394 Effective Depth TVD:Plugs (MD):Junk (MD): Other Stimulate Re-enter Susp Well Suspend Plug for Redrill Perforate Perforate New Pool 9317, 7882 2174, 2129 Date: Liner 576 7"9359 - 9935 7916 - 8392 7240 5410 Well Status after proposed work: 16. Verbal Approval: Change Approved Program 35 - 3725 35 - 3381 14. Estimated Date for Commencing Operations: BOP Sketch 36 - 112 Structural 6870 Proposal Summary 13. Well Class after proposed work: 7" Baker S-3 Packer 9485 - 9933 8020 - 8390 7-5/8" 29.7# x 7" 26#27 - 9366 Production 9933 8390 None None 36 - 112 470 13-3/8" 9-5/8" Contact Phone:+1 9075644675 Date: 4760 76 149020"Conductor 2260 GINJ 5 Post Initial Injection MIT Req'd? Yes No 5 Comm. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 Surface 3690 5020 Intermediate 9408 30 - 9439 30 - 7982 Address:P.O. Box 196612 Anchorage, AK 99519-6612 3. No 5Yes Casing Length MD TVD Burst Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Collapse MPSP (psi): Wellbore Schematic Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Form 10-403 Revised 03/2020 Approved application is valid for 12 months from the date of approval. Brown, Don L.Brown, Don L. 2020.05.12 17:33:14 -08'00' By Samantha Carlisle at 11:57 am, May 13, 2020 320-201 X 10-404 DLB 5/13/2020 DSR-5/13/2020MGR13MAY20 Yes Required? Comm 5/14/2020 dts 5/14/2020 JLC 5/14/2020 RBDMS HEW 5/15/2020 10-403 Sundry Application for Well PBU AGI-10A PTD #206-135 BP Exploration (Alaska) , Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Expected Start Date: July 13, 2020 Current condition of well: Gas Injection Well, Operable, Online: Gas Injection Rate: 202524 Mscf/Day Injection Pressure: 3361 psi Reservoir Pressure (Estimate): 3500 psi Program Objective(s): AGI-10A is a gas injection well with a decreased injectivity over the past 5 years. The well has been subject to successful to these water washes in the past (Oct-2015 and Sept-2018) and are designed to dissolve salts and asphaltenes in the tubing and formation. The objective is to subject the well to another tubing water wash to once more increase injectivity and perform a general maintenance on Gas Injection Wells. Proposed Program: Pump diesel followed by Fresh Water and Surfactant as per attached pumping template. 10-403 Sundry Application for Well PBU AGI-10A PTD #206-135 BP Exploration (Alaska) , Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Pump Schedule: 10-403 Sundry Application for Well PBU AGI-10A PTD #206-135 BP Exploration (Alaska) , Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Wellbore Schematic: MEMORANDUt State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE:Wednesday,May 23,2018 P.I.Supervisor (Se1 1Z�It— SUBJECT:Mechanical Integrity Tests BP EXPLORATION(ALASKA)INC. AGI-10A FROM: Austin McLeod PRUDHOE BAY UNIT AGI-10A Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry 12-- NON-CONFIDENTIAL Comm Well Name PRUDHOE BAY UNIT AGI-10A API Well Number 50-029-22353-01-00 Inspector Name: Austin McLeod Permit Number: 206-135-0 Inspection Date: 5/9/2018 Insp Num: mitSAM18050915142! Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min ,, Well AGI-10A Type Inj G TVD 7882 - Tubing 3334 I 3334 3341 3343' 3342" 3348 PTD 2061350 I Type Test SPT Test psi 1970 IA 85 I 2500 ' 2500 2513 " 2516 - 2523 ' BBL Pumped: 2.8 - [BBL Returned: j 3] • OA 95 113 . 114 115 - 115 - 116 - Interval 4YRTST P/F I Notes: MIT-IA to 2500 psi as per operator request.86 start temp-87.5 end temp SCANNED :UN 0 1 2n Wednesday,May 23,2018 Page 1 of 1 State of Alaska MEMORANDA Alaska Oil and Gas Conservation Commission DATE: Tuesday,May 22,2018 TO: Jim Regg 51Z-5116.3 P.I.Supervisor —11 SUBJECT: Mechanical Integrity Tests BP EXPLORATION(ALASKA)INC. AGI-10A FROM: Adam Earl PRUDHOE BAY UNIT AGI-10A Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry NON-CONFIDENTIAL Comm Well Name PRUDHOE BAY UNIT AGI-10A API Well Number 50-029-22353-01-00 Inspector Name: Adam Earl Permit Number: 206-135-0 Inspection Date: 5/15/2018 Insp Num: mitAGE180515144823 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well AGI-10A Type Inj G TVD 7882 'I Tubing 3297 3305 - 3316 3318 - PTD 2061350 'Type Test SPT Test psi 1970 ' i IA 133 2500 - 2490 - 2488 - BBL Pumped: 2.6 BBL Returned: 2.8 OA 95 111 _ 112 112 _ Interval 4YRTST ;P/F P Notes: MIT/IA SCANNED JUN 0 1 ?D)I Tuesday,May 22,2018 Page 1 of 1 • • Wallace, Chris D (DOA) From: AK, GWO Well Integrity Engineer <AKGWOWellSiteEnginee@bp.com> Sent: Wednesday, May 9, 2018 2:17 PM To: Wallace, Chris D (DOA) Cc: AK, GWO Well Integrity Well Information;AK, GWO Projects Well Integrity;AK, GWO SUPT Well Integrity Subject: Injector AGI-10 (PTD#2061350) Inconclusive AOGCC Witnessed MIT-IA Attachments: MIT PBU AGI-10A 05-09-2018.xlsx;AGI-10 30 day TIO jpg;AGI-10 Temp trend during M IT.J PG Hi Chris, DHD performed an inconclusive AOGCC Witnessed MIT-IA on gas injector AGI-10(PTD#2061350). The test was dee ed inconclusive due to a small pressure gain on the inner annulus during the test. I took a deep review of the pressure trend and have concluded that the annuli pressures for this well are very sensitive to gas injection temperature (as wi h most of the gas injectors). Additionally I did not find anything that would indicate an integrity issue. Looking at the streaming data from the well during the MIT-IA I found that the injection temperature rose during the test and the gaining pressure trend can be seen on the outer annulus as well. In summary I believe the inner annulus gained pressure during the MIT was due to 1.Cold diesel being pumped into tine annulus, and 2.The gas injection temperature rising during the test. The current plan forward is to reschedule the MIT- IA on the 13th I've attached the 10-426 and a couple of TIO trends that should help illustrate the thermal behavior of this well. If you have any questions or concerns please email or call. Thanks, Joshua Stephens Well Integrity Engineer SCANNED 14, Office: 907-659-8110 Cell: 907-341-9068 wo 1 STATE OF ALASKA • LASKA OIL AND GAS CONSERVATION COMM!, REPORT OF SUNDRY WELL OPERATIONS 1. Operations Performed Abandon 0 Plug Perforations 0 Fracture Stimulate 0 Pull Tubing 0 Operations shutdown 0 Suspend 0 Perforate 0 Other Stimulate 11 Alter Casing 0 Change Approved Program 0 Plug for Redrill 0 Perforate New Pool 0 Repair Well 0 Re-enter Susp Well 0 Other:Water Wash Stim I1 2. Operator Name: BP Exploration(Alaska),Inc 4. Well Class Before Work 5. Permit to Drill Number: 206-135 3. Address: P.O.Box 196612 Anchorage, Development 0 Exploratory 0 AK 99519-6612 Stratigraphic 0 Service H 6. API Number: 50-029-22353-01-00 7. Property Designation(Lease Number): ADL 0034628 8. Well Name and Number: PBU AGI-10A 9. Logs(List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pools: PRUDHOE BAY,PRUDHOE OIL 11.Present Well Condition Summary: RECEIVED Total Depth: measured 9937 feet Plugs measured feet Nov 2 4 2015 true vertical 8394 feet Junk measured feet Effective Depth: measured 9325 feet Packer measured 9317 feet C�/"�� true vertical 7889 feet Packer true vertical 7882.22 feet '" " "� Casing: Length: Size: MD: TVD: Burst: Collapse: Structural Conductor 80 20"91.5#H-40 33-113 33-113 1490 470 Surface 3693 13-3/8"68#NT-80 32-3725 32-3381 5020 2260 Intermediate 9407 9-5/8"47#L-80 29-9436 29-7980 6870 4760 Production Liner 576 7"26#L-80 9356-9933 7915-8390 7240 5410 Perforation Depth: Measured depth: 9485-9933 feet True vertical depth: 8020-8390 feet iicANNEP, k j i L i)F t Tubing(size,grade,measured and true vertical depth) See Attachment See Attachment See Attachment Packers and SSSV(type,measured and See Attachment See Attachment See Attachment true vertical depth) 7"DB-1A ISSSV 2174 2129 12.Stimulation or cement squeeze summary: Intervals treated(measured): 9485-9933 Treatment descriptions including volumes used and final pressure: 203 Bbls 50/50 Diesel-Xylene,20 Bbls Neat Methanol,726 Bbls Fresh Water+F-103,105 psi. 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 250883 260 3404 Subsequent to operation: 248118 260 3372 14.Attachments:(required per 20 AAC 25.070.25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations ® Exploratory 0 Development 0 Service H Stratigraphic 0 Copies of Logs and Surveys Run 0 16.Well Status after work: Oil 0 Gas 0 WDSPL 0 Printed and Electronic Fracture Stimulation Data 0 GSTOR ❑ WINJ 0 WAG 0 GINJ H SUSP 0 SPLUG 0 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 315-238 Contact Catron,Garry R(Wipro) Email Garry.Catron@bp.com Printed Name Catron,Garry R(Wipro) Title PDC Principal Engineer Signature j„",..,1 6,76K--- Phone +1 907 564 4424 Date 11/23/15 Form 10-404 Revised 5/2015 r II' Phone RBDMS,S(BGI, 0 2015 Submit Original Only • m Q o 0 0 0 O_ 0 0 (0 (0 O N-- - N N d' L() Ln V in U N o 0 0 co co co 0 O N N- 't 6) V 0 CO N N CO N CO x- L0 (0 ti N- O r-- = = 0 0 0 CO N CO co O t L() N CO O CO c- CO O CO I- CO NCI N- I- LC) O co CO N 6) '- N- V LC) CO Cr) N O N CO N- N N- 0) Ln co M Ln N (O N CO CO CO CO CO r- V O N CO `- M 0) 0) N O 0) • Q 2 I I I I I Q CO10 N 0) Lo N- co cco M M N M N = N CI)= 0 6) N 6) I—• CO O O a O co O Z J 00 co co J J Zo • N p) - N N N N N c O) co h- 8)▪ O O O O LI) p) cr C 00 (0 d '- O M J M O N ti LU CI)O • I- W I-' ' U W UO � IYIrZZZ Z c W W m CO CO O j I; Z D > OU) ZJI— IH • • Packers and SSV's Attachment PBU AGI-10A SW Name Type MD TVD Depscription AGI-10A SSSV 2174 2129.42 7" DB-1A ISSSV AGI-10A TBG PACKER 9317.12 7882.22 7" Baker S-3 Packer AGI-10A PACKER 9368.04 7924.05 7" Baker ZXP Top Packer • • m• ai . C U U Q 0 Q- O • O _c co a) L E O Q a) C C u) Q o E O O n '- Cl)C) LL CD SCJ Lu) O a) O 0) U) LL C C a) a) .3 a' O >- Q (13E Co < - ToE a) I.- 2 a) -0 a) CO Q a 2 0co io � I— O QD a (1 -1J 70 C \ N L.L Q) V) E E 0- CID 14- "•••4 ....0 • _ 't ~ -, a m `�• a X = a • ECL C � >+ E � � X w a) O 0 o Eno + N u-) Q C L O _o a) N a) I- Lo O N L N No II 0 L CO Q L to t/) H N O in OZ a) Li W Q U) o H N _IT) O O N 5 N m N N N- H O 0 Q !NEE= 3-318"BOREII WEILHEA� FMC hSBB AGI-1 0A S�CTY NOTES: WELL REQUIRES A SSSV. `ACTUATOR= BAKER C KB.H-EV= 46.5' ELEV= 3725' 7"TBG,264,L-80,TC-1, H 31' \� 31' 1-17"X 7-5/8"XO,13=6.276" Max Angie= 41©3240' .0383 bpf,ID=6.276" Datum MD= 10483' Datum11/13 8800.SS I 2163' H7-5/8"X 7"XO,D=6.276" 7-5/8"TBG,29.7#,L-80,PC VAM TOP, H 2163' 4r/ - 0459 bpf,D 6.875. 2174' —17"CAMCO DB LANDING NP,13=6.00" 2185' H 7"X 7-5/8"XO,13=6.276" 7"TBG,26#,L-80,TC-1,.0383 bpf,D=6.276" H 2185' Minimum ID = 5.770" @ 9344' 7" HES RN NIPPLE 13-3/8"MLLOUT WINDOW (AGI-10A)37254-3749' 13-3/8"WHPSTOCK(10/27/06) —I 3725' 13-3/8"EZSVB(10/26/06) 1—H 3754' 13-318"CSG,68#, H 3846' 5160' H ESTMA TED TOP OF CEMENT NT-80,D=12.415" \ , • ,•�♦,• '�♦� 92$2' ;:::::• • Vt 9293' • error • itt "•••' • . 9317' —9-5/8"X 7"BKR S-3 PKR, .nnnnn,• ♦ �!�♦� D=6.00" uour �iiiiiii,-�• '♦♦ fit iiiiiinnn. '♦♦ A •♦ •;n;;!! 7-5/8"TBG,29.7#,L-80, —1 9282' 1 ♦j,� �j! �.. ♦ ♦ 9344' —Ir FES RN NP,D=5.770" •• PCVAMTOP, *44 �i .0459 bpf,D=6.875" A *4 9359' —9-518"X 7"BKR ZXP • A •• LIP,D=6.23' TC-1, --.1 9366' ,% ♦� 9377 —9-5/8"X 7"BKR HMC 7"TSG,26#,L-80,T �♦, 7'; ♦. LNR HGR,D=6.32" .0383 bpf,D=6276" *♦A vi, 1. •♦A 9366' —17"MULE SHOE, • v• 13=6.276" t 9-5/8"CSG,47#,L-80,TC-1,13=8.681" H I 9439' I PERFORATION St/AVIARY \ REF LOG:LWD ON 11/07/06 ANGLE AT TOP P82F: 35 @ 9485' 7"SOLD LM,26#,L-80, —i 94$5' r— \ Note:Refer to Production DB for historical pert data BTC-M,.0383 bpf,D=6.276" \ \ SIZE SPF INTERVAL Opn/Sgz DATE \ \ SLOI FEU 9485-9564 0 11/07/06 \ 1" 18 9564-9933 0 11107/0611 7"SLID LNR,26#,L-80, -j 9565' ,—\ \ BTC-M,.0383 bpf,13=6.276" \ \ \ 7"PERFORATED LW,26#,L-80,BTC-M,.0383 bpf,ID=6.276' —j 9933' I—Ift;i4vk 7"LNR,26#,L-80, BTC-M,.0383 bpf,D=6.276" —{ 9937' DATE REV BY COMMENTS ' DATE REV BY COMMENTS NITS PRUDHOE BAY INT 04/01/93 ORIGINAL COMPLETION WELL: AGF-10A 11/12/06 N2ES SIDETRACK"A" PERMTNo:'2061350 01/12/07 JAF/PJC DRLG DRAFT CORRECTIONS AR No: 50-029-22353-01 03/09/07 MVVSIPJC DRLG DRAFT CORRECTIONS Sec.36,T12N R14E,2808.63 FE.5240.67 FNL 02/11/11 MB/JMD ADDED SSSV SAFETY NOTE BP Exploration(Alaska) 20Co- f33 T�. • ,,i, 1�1/j,�s� THE STATE Alaska Oil and Gas 77,<oF =� ' of Conservation Commission :; - - ALASI�:A iiri x-'- .r.-:--, 333 West Seventh Avenue GOVERNOR BILL WALKER �� Anchorage, Alaska 99501-3572 O � �� t*, Main: 907.279.1433 F ALAS*� Pp `� Fax: 907.276.7542 ��� www.aogcc.alaska.gov Spencer Morrison 3 Petroleum Engineer ao(0.- 5 BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Prudhoe Bay Field, Prudhoe Bay Oil Pool, PBU AGI-10A Sundry Number: 315-238 Dear Mr. Morrison: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, atl f4,--r Cathy . Foerster Chair DATED this Z7 day of April, 2015 Encl. STATE OF ALASKA APR R 20t , ALASKA OIL AND GAS CONSERVATION COMMISSION 071S ', I 7I APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request Abandon Plug for Redrill❑ Perforate New Pool❑ Repair Well❑ Change Approved Program Suspend ID Plug Perforations❑ Perforate❑ Pull Tubing❑ Time Extension❑/. Operations Shutdown Re-enter Susp.Well❑ Stimulate❑ Alter Casing❑ Other L,'Jr 1^.).•6A 2 2 Operator Name: 4.Current Well Class: 5.Permit to Dnll Number 04 ZZ/r, BP Exploration(Alaska),Inc. Exploratory ❑ Development ❑ 206-135-0•, 3 Address Stratigraphic ❑ Service C K 6.API Number: P.O.Box 196612,Anchorage,AK 99519-6612Vy, 50-029-22353-01-00 • 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? PBU AGI-10A • Will planned perforations require a spacing exception? Yes ❑ No ❑ 9.Property Designation(Lease Number). 10.Field/Pool(s): ADL0034628 ` PRUDHOE BAY, PRUDHOE OIL' 11 PRESENT WELL CONDITION SUMMARY Total Depth MD(ft). Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth ND(ft): Plugs(measured): Junk(measured): 9937. 8394 . 9325 7889 None None Casing Length Size MD TVD Burst Collapse Structural Conductor 80 20"91.5#H-40 32.9-112.9 32.9-112.9 Surface 3693 • 13-3/8"68#NT-80 32.4-3725 32.4-3381.24 5020 2260 Intermediate 9407 9-5/8"47#L-80 29 24-9436.36 29.24-7980 22 6870 4760 Production None None None None None None Liner 576 7"26#L-80 9356.44-9932.64 7914 51-8389.9 7240 5410 Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 9485-9933 8020.15-8390.2 See Attachment See Attachment See Attachment Packers and SSSV Type• See Attachment for Packer Types Packers and SSSV MD(ft)and TVD(ft): See Attachment for Packer Depths 7"DB-1A ISSSV 2174',2129.42' 12.Attachments: Description Summary of Proposal ❑ 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Development ❑ Service 14.Estimated Date for 15.Well Status after proposed work: 6/10/15 Commencing Operations: Oil ❑ Gas ❑/ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ ❑ GINJ Q1 /'�IZ �5 WAG ❑ Abandoned ❑ Commission Representative: /it GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Spencer Morrison Email Spencer.Morrison@BP.Com Printed Name Spencer Morrison Title Petroleum Engineer SignatureP hone 564-5773 Date Prepared by Garry Catron 564-4424 L1/2(//5-- COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: lc - 2_31( Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Spacing Exception Required? Yes ❑ No d Subsequent Form Required: / —4 C 4 APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date' 1-. a7-/s" vTL 41/ 3/1, -- L /1 fiplra1 Nf,Lr5�0pP tForm 10-403 Revised 10/2012 lits ion is valid for 12 months from the date approval. Submit Formattachments m u�te RBDMSk APR 2 9 2015 - 'S a O O 0'0000 O OIO • 0o 00 i 00 0o 00 O Z J J J a) Q O O O O O O O fe V N V V f� o V LO N U) Ln V U N o 0 0 0 0 0 0 L o) N V V o) V CO N O N N 00 CO v— CO N- (n N- N- CO IL I U, CO 00 CA Co V N In CT co co CA 0o Q ( M O ~ CO CA — N N CO Q CO N CA CO N CO N- N L � CO CO E (NI a) E O N co O el CC) C0 CO N CO CO CO N CO CO CO U) O Q `- 0) O CO N (A cm � p 2 0 (� eL H M O o N r CO CO U Q M N CO CO N N o) CA N O O O O Co 00 O FL O O = J co Z co co • �$ J J J N co 4t 0, op N CO N N CV N 07 L co 0o f- co O O o) LO V CA CO Cr (o r'• Co O J o) CO N N- LU Q I-1-1 U O p CC C Z Z Z Z W W m m m 0 �' zDDDD U Z Packers and SSV's Attachment ADL0034628 Well Facility Type MD Top_ Description TVD Top AGI-10A SSSV 2174 7" DB-1A ISSSV 2129 AGI-10A PACKER 9317 7" Baker S-3 Packer 7882 AGI-10A PACKER 9368 '7" Baker ZXP Top Packer 7924 ALASKA WELL ACTIVITY STATEMENT OF REQUIREMENTS (V1.9,DBR,LHD,EAZ 01/15/15) General Information Well Name: AGI-10 Well Type: Gas Injection Well API Number: 50-029-22353-01 Well Activity Conventional 4 Classification: Activity Description: Water wash Cost Code/AFE: APBINJEC Field/Reservoir: PRUDHOE IVISHAK 12 Month Avg IOR, bopd: Job Type: TREAMENTS Estimated Cost, $K: AWGRS Job Scope: TUBING WASH/PICKLE Other regulatory None requirements? Sundry Form 10-403 Required? Yes — Sundry Form 10-404 Yes Primary Secondary Required? Engineer: Spencer Morrison Contact numbers: (907) 564-5773 (713) 557-281 Well Intervention Engineer: Contact numbers: No Data No Data Lead Engineer: Chris Stone Contact numbers: (907) 564-5518 (907)440-401 Date Created: April 6, 2015 Revisions(date,who,what changed): Current Well Status Information Water Rate or Gas Rate or Oil Rate Inj Rate Gas Injection GOR Gas Lift Rate FTP or Injectic Date Pressure (bopd) (bwpd)Water Rate (scf/stbo) Choke Setting (Mscf/Day) (psi) Cut(%) (Mscf/Day) 4/6/2015 255,659 3,391 Current Status: Operable Flowing Inclination>70°at Depth(ft) Maximum Deviation (Angle and Recent H2S (date,ppm) - None Depth) 41° 3,240' MD — Datum depth,ft TVDss 8,800' TVDss Dogleg Severity(Angle and Depth) 4° 1,978' MD Reservoir pressure(date, 3,400 psi Minimum ID and Depth 5.770"@ 9,344' psig) Reservoir Temp, F 130° F Shut-in Wellhead Pressure 2,400 psi Known mech. integrity None, passing MIT-IA and MIT-T problems(specifics) Last downhole operation (date, 5/11/2014 Pressure test for integrity, set plug @ 9,344' and pulled after operation) Most recent TD tag (date,depth, 7/17/2008 9,868' 4.5"Centralizer toolstring OD) Surface Kit Fit-for-Service? YES If No,Why? Comments,well history, AGI-10 has had 2 water washes. The most recent on 10/19/2012 we pumped 204 bbls of D/X with 240 bbls background information, of 110 F FW at 5 BPM. The earlier water wash was on 9/14/2011 where we pumped 294 bbls of diesel etc: with 405 bbls of FW with surfactant. Both water washes were successfful (see attached injection plots)and they were only exectued a year apart. IL oeen 3 years since me last water wasn ana i eh, .t similar oenents to me past wasnes. This summer there will be an NGI restoration project that will include significant down time for the NGI wells. I have included the tentative schedule below.To reduce the impact of having the NGI wells shut in for work,water washes are needed on good candidates on AGI and WGI. �1 NGI Restoration schedule: 1.Well lateral line work starts April 15 when we will take 2 NGI wells down at a time for repairs lasting 7-9 days per set. We will start with wells 13/14 and work south until complete with pre-TAR scope. 2. Starting on June 26th we will take down NGI wells 1-12 to support blinding and repairs in the vicinity of FV6302/6203 for 9 days-This is outage one. 3. Following outage one and roughly on July 4th we will restart NGI wells 8-12 (13 and 14 were already on line)and wells 1-7 will remain down for approximately 30 days for outage 2. 4. Following completion of outage 2 we will restart wells 1-7 and take down NGI wells 8-14 and begin repairs on the north end of NGI headers/laterals. This is outage 3 and duration is roughly 30 days. 5. Following outage 3 we will need to restart NGI wells 11-14 and take down NGI wells 1-10 to allow for blind removal at FV6302/6203. This is outage 4 and I estimate 2 days for this outage. 6. Finally we then will restart all of the NGI pipelines and wells that were down for blind removal and be back to normal with repairs in place. This is the base schedule and if we find additional corrosion damage the extends our scope of work then we could have some wells off line for longer duration. If the water washes go to plan,we will improve injectivity by dissolving salts and possibly asphaltenes in the tubing and formation. Diesel/Xylene washes have been used successfully in the past on the NGI/WGI/AGI gas injectors to improve injectivity. Well Intervention Details Suspected Well Problem: Oragnic deposition Specific Intervention or Well Objectives: 1 Increase well injectivity by cleaning the tubing and perforations 2 3 Key risks,critical issues: Mitigation plan: 1 2 3 Summary Service Line Activity Step# 1 Pump Water Wash as per attached template 2 3 Detailed work scope(If no RP/SOP exists for the intervention type,a well-specific procedure is required in addition to the SOR): 1 2 3 Performance Expectations(may be NA if no change anticipated due to the intervention) BOPD: MMSCFD: BWPD: Expected Production Rates: FTP(psi): Choke setting: Post job POP instructions: Bring back well to injection Attachments-include in separate excel worksheets Required attachments: Current wellbore schematic As needed: Perf form,logging form,well test chart,annotated mini log,annotated log section,tubing/casing tallies,Wellhead info,etc Approvals Management Approval: Date: Wells Approval: Date: Image Project Well History File hover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. p~ (~ ~j - ~ ~S' Well History File Identifier Organizing (done) RE CAN Color Items: ~reyscale Items: I ~p V ^ Poor Quality Originals: ^ Other: NOTES: BY: ,.o,~ea iiiuiuiuiuuiu DIGITAL DATA ^ Diskettes, No. f ^ Other, No/Type: Date: o Re,~.~~e~ea iuuiiiiuiiuuu OVERSIZED (Scannable) ^ Maps: ^ Other Items Scannable by a Large Scanner OVERSIZED (Non-Scannable) ^ Logs of various kinds: ^ Other:: /s/ Pp,~~Pro a ~~ tlllllllllllllllll BY: Maria Date: , `~' f 7 / D ~ /s/ / '/ Scanning Preparation _~ x 30 = ~Q_(~ + ~_ =TOTAL PAGES~~ I l (Count does not include cover sheet) BY: _ Maria Date: ~ ~ / ~ ~ ! 0 ~ /s/ ~' III11111111111 IIIII Production Scanning Stage T Page Count from Scanned File: (Count does include cover sheet). Page Count Matches Number in Scanning Preparation: ~ YES NO BY: Maria Date: ~ all ~ lO ~ lsl ~M . ! ~ ~ ~ Y1 Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. II I f I ~l II I II II I I III ReScanned II I II II II ((III I I III BY: Maria Date: /s/ Comments about this file: Quality Checked III II~III IIIIIII III P P P 10/6/2005 Well History File Cover Page.doc STATE OF ALASKA RECEIVED • ALASKA OIL AND GAS CONSERVATION COMMI ON NOV 1 5 2012 REPORT OF SUNDRY WELL OPERATIONS AOGCC 1. Operations Abandon U Repair Well U Plug Perforations U Perforate U Other U Water Wash Performed: Alter Casing ❑ Pull Tubing❑ Stimulate - Frac ❑ Waiver ❑ Time Extension❑ Change Approved Program ❑ Operat. Shutdown❑ Stimulate - Other ❑ Re -enter Suspended Wel° 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: BP Exploration (Alaska), Inc Development❑ Exploratory ❑ — 206 -135 -0 3. Address: P.O. Box 196612 Stratigraphic❑ Service o 6. API Number: Anchorage, AK 99519 -6612 50- 029 - 22353 -01 -00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0034628 .. PBU AGM 0A 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field /Pool(s): J To Be Submitted PRUDHOE BAY, PRUDHOE OIL 11. Present Well Condition Summary: Total Depth measured 9937 feet Plugs measured None feet true vertical 8393.52 feet Junk measured None feet Effective Depth measured 9325 feet Packer measured 9317 feet true vertical 7888.68 feet true vertical 7882.12 feet Casing Length Size MD TVD Burst Collapse Structural None None None None None None 1 Conductor 76 20" 91.5# H-40 30 - 106 30 - 106 1490 470 Surface 3696 13 -3/8" 68# NT -80 29 - 3725 29 - 3381.24 5020 2260 Intermediate None None None None None None Production 9411 9 -5/8" 47# L -80 28 - 9439 28 - 7982.39 6870 4760 Liner 576 7" 26# L -80 9359 - 9935 7916.61 - 8391.86 7240 5410 Perforation depth Measured depth 9485 - 9933 feet SCANNED FEB 2 8 2013. True Vertical depth 8020.15 - 8390.2 feet Tubing (size, grade, measured and true vertical depth) See Attachment See Attachment See Attachment Packers and SSSV (type, measured and true vertical depth) 7" Baker S -3 Packer 9317 7882.12 Packer None None None SSSV 12. Stimulation or cement squeeze summary: Intervals treated (measured): 9485' - 9933' Treatment descriptions including volumes used and final pressure: 204 Bbls Diesel/Xylene Mix, 10 Bbls Meth Spacer, 500 Bbls 110 deg Fresh Water / F -103 Surfactent Mix 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 192648 0 0 3343 Subsequent to operation: 0 194383 0 0 3290 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratoq❑ Development ❑ Service ID Stratigraphic ❑ Daily Report of Well Operations X 16. Well Status after work: Oil ❑ Gas ❑ WDSPLU GSTOR ❑ WINJ ❑ WAG ❑ GINJ 0 SUSP ❑ SPLUG❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: N/A Contact Garry Catron Email Garry BP.Com Printed Name Garry Catron Title PDC PE Signature ga,t a t./... , Phone 564 -4424 Date 11/15/2012 1 REDMS NOV 19 1011 Form 10 -404 Revised 10/2012 / Submit Original Only Casing / Tubing Attachment ADL0034628 Casing Length Size MD TVD Burst Collapse CONDUCTOR 76 20" 91.5# H -40 30 - 106 30 - 106 1490 470 LINER 576 7" 26# L -80 9359 - 9935 7916.61 - 8391.86 7240 5410 PRODUCTION 9411 9 -5/8" 47# L -80 28 - 9439 28 - 7982.39 6870 4760 SURFACE 3696 13 -3/8" 68# NT -80 29 - 3725 29 - 3381.24 5020 2260 TUBING 9255 7 -5/8" 29.7# L -80 27 - 9282 27 - 7853.44 6890 4790 TUBING 84 7" 26# L -80 9282 - 9366 7853.44 - 7922.37 7240 5410 • •I I 1 Daily Report of Well Operations ADL0034628 ACTIVITYDATE ( SUMMARY S= .11 emp= using was •issovesa sasp a Ines •umpe. I ••s me spear followed by 204 bbls of diesel /xylene mix, 10 bbls meth spacer and 240 bbls of 110* freshwater /F -103 surfactant mix. Freeze protect tree with 3 bbls meth. Allow 2 hour soak. Pumped additional 260 bbls of 110* freshwater /F -103 surfactant mix for a rinse and 10 bbls meth freeze 10/19/2012 protect. DSO to put on injection. FWHP's= 100/140/62. • s THEE= 6-3/8" BORE III D= FMC NSBB A G I -10 A SA NOTES: WELL REQUIRES A SSSV. ACTUATORS -- BAKER C KB. B..EV = 46. BF. _ELEit 16' KOP 3725' 7" TBG, 26#, L -80, TGI, —1 31' I I I I 31' J X 7 -5/8" XO, D = 6.276" I Max Angle = 41 3240' .0383 bpf, D = 6.276' Datum MD = 10483' Datum ND= _ 8800. SS 2163' I-17 -518" X 7' XO, D = 6276" I 7 -5/8" TBG, 29.7 #, L -80, PC VAM TOP, H 2163' K 0459 bpf, D = 6.875' I 2174' H7- C CAM O DB LANDING N P, D = 6.00" I I 2185' H7" X 7 -5/8" XO, 0= 6.276' I I7" TBG, 26#, L -80, TC-I, .0383 bpf, D = 6.276" IH 2185' Minimum ID = 6.770" @ 9344' 7" HES RN NIPPLE 13 -3/8" MLLOUT 11411430W (AG! -10A) 3725' - 3749' 113 -3/8" WHIPSTOCK (10/27/06) H 3725' 113 -3/8" EZSVB (10/26/06) IH 3754' ; T - CS — 3846' 5160' —{ ESTIMATED TOP OF CEMHVT I N80, D = 1 2.41 .415" "... • • 4 ,•. ;♦, 9282 —I 7 -::'::1 • • • 9293' H 7 • • A�` ` i ` • 4 t1 931 T 19 -5/8" X 7" BKR S-3 PKR, u.n.r 4 �� ,�� D = 6.00" u•uu• uu.u. • ' u ••u n ..... 7 -5 /8" TBG, 29.7 #, L -80, H 9282' ••, -`�� ... ♦ • I 9344' I—I 7" HES RN NP, .0= 5.770" •- PC VAM TOP, ..-4 ` .0459 bpf, D = 6.875" �� �4 4' I 9359' — 9 -5/8" X 7" BKR ZXP • LTP,D =6.23" 7' TBG, 26#, L-80, TGII, —I 9366' ,% % I 937T — X 7" BKR FMc � * �i; LNR HGR,D =6.32" .0383 bpf, D = 6.276" ■.. • *''A � • ♦ A 9366' — 7" MULE SHOE, , D = 6.276' 1 9-5/8" CSG, 47 #, L-80, TC-I, D = 8.681 " —I 9439' I FERFORATION SUMMARY \ FIEF LOG: L M) ON 11/07/06 ANGLE AT TOP F$ZF: 35 @ 9485' 7" SOLD LNR 26#, L -80, 9485' Note: Refer to Production DB for historical pert data BTC-M, .0383 bpf, D = 6.276" \ SIZE I SPF INTERVAL Opn/Sgz DATE \ \ SLO 1 1W 9485 - 9564 0 11/07/06 1" 18 9564 9933 0 11/07/06 7" SLID LNR, 26#, L -80, —1 9565 I— BTC-M, .0383 bpf, D = 6.276' \ \ \ ak 17" PERFORATED LNR, 26#, L -80, BTC-M, .0383 bpf, ID = 6.276" 1-1 \ N . vi .g f 11 17" LNR, 26#, 1-80, BTC-M, .0383 bpf, D = 6.276' DATE REV BY COMMENTS DATE REV BY COMENTS R21U1OE BAY UNIT 04/01/93 ORIGINAL COMPLETION V L: AGI -10A 11/12/06 N2E6 SIDETRACK "A" PERMT No: "2061350 01/12/07 JAF /PJC DRLG DRAFT CORCfiONS AR Pb: 50- 029 - 22353 -01 03/09/07 MWS/PJC DRL.G DRAFT CORRECTIONS Sec. 36, T12N, R14E, 2808.63 FR. 5240.67 FPL 02/11/11 MB/JMD ADDED SSSV SAFETY NOTE BP Exploration (Alaska) • • ( 9T. rn s P a ft.\\ 1 SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 Javier Farinez Petroleum Engineer / 3' BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519 -6612 Re: Prudhoe Bay Field, Prudhoe Bay Oil Pool, PBU AGI -10A Sundry Number: 312 -230 Dear Mr. Farinez: �� Jot S X01 Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, -0 Cathy P. Foerster Chair DATED this i day of June, 2012. Encl. STATE OF ALASKA RECEIVED • Au., OIL AND GAS CONSERVATION COMMI•N APPLICATION FOR SUNDRY APPROVALS JUN 1 9 2012 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ C eAjogram ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing ❑ Time Extension ❑ Operation Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: Water Wash • El 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: BP Exploration (Alaska), Inc. Development ❑ Exploratory ❑ 206 -1350 • 3. Address: P.O. Box 196612 Stratigraphic ❑ Service El 6. API Number: Anchorage, AK 99519 -6612 50- 029 - 22353 -01 -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: PBU AGI -10A Spacing Exception Required? Yes ❑ No 9. Property Designation (Lease Number): 10. Field / Pool(s): ADL- 034628 . PRUDHOE BAY Field / PRUDHOE BAY Pool ' 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 9937 ' 8394 • 9933 - 8390 NONE NONE Casing Length Size MD TVD Burst Collapse Structural Conductor 76' 20" 91.5# H-40 30' 106' 30' 106' 1490 470 Surface 3696' 13 -3/8" 68# NT -80 29' 3725' 29' 3381' 5020 2270 Production 9411' 9 -5/8" 47# L -80 28' 9439' 28' 7982' 6870 4760 Liner 576' 7" 26# L -80 9359' 9935' 7917' 8392' 7240 5410 Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): SEE ATTACHED - - 7 -5/8" 29.7# L -80 27' 9282' 7" 26# L -80 9282' 9366' - Packers and SSSV Tvoe: 7" Baker S -3 Packer Packers and SSSV MD and TVD (ft): 9317' 7882' 12. Attachments: Description Summary of Proposal 0 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Development ❑ Service El 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 7/2/2012 Oil ❑ Gas ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: WINJ ❑ GINJ 0 • WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Javier Farinez Printed Name Javier Fag Title PE Signature AlOr Phone Date 564 -5043 6/18/2012 Prepared by Nita Summerhays 564 -4035 COMMISSION USE ONLY - Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 31 1 2: 1 23t Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Subsequent Form Required: APPROVED BY Approved by: c / t COMMISSIONER THE COMMISSION Date: C , Z Z ) Z. L � F � P•SP:Y Form 10-403 vised 1/2010 S JUN 2 5_ 2012 S bmit in D upl i cate . (� / z ORIG1mAt 0 / =//2 Li AGM 0A 206 -135 PERF ATTACHMENT Sw Name Operation Date Perf Operation Code Meas Depth Top Meas Depth Base Tvd Depth Top Tvd Depth Base AGI -10A 11/12/06 SL 9,485. 9,933. 8,020.15 8,390.2 AGI -10A 12/19/10 BPS 9,325. 9,933. 7,888.68 8,390.2 AGI -10A 12/20/10 BPP 9,325. 9,933. 7,888.68 8,390.2 AB ABANDONED PER PERF APF ADD PER F RPF REPERF BPP BRIDGE PLUG PULLED 1SL SLOTTED LINER REMOVED BPS CO BLL OUT ISPS !SAND SAND PLUG SE FIL FILL SQF SQUEEZE FAILED • MIR MECHANICAL ISOLATED REMOVED SQZ SQUEEZE MIS MECHANICAL ISOLATED STC STRADDLE PACK, CLOSED MLK MECHANICAL LEAK STO STRADDLE PACK, OPEN OH I OPEN HOLE • Version 1.1 04/28/2010 Fullbore Pumping Design Template Well Name AG-10 Job Scope Solvent Treatment . H2S (ppm /date) WBL Cat IOR 2500 Max Pumping Pressure (psi) Well Type GI AFE APBinjec Main Fluid Type Date 6/14/2012 IOR 30 . 700 Main Fluid Volume (bbls) Engineer Javier Farinez Phone 564 -5043 Methanol (60/40) Freeze Protect Type Job Objective 10 Freeze Protect Volume (bbls) If Applicable Recent Tbg Fluid Level (ft) Improve injectivity by dissolving salts and possibly asphaltenes in the If Applicable Recent IA Fluid Level (ft) tubing and formation. Diesel /Xylene washes have been used If Applicable Recent OA Fluid Level (ft) successfully in the past on the NGIIWGI /AGI gas injectors to improve If Applicable Expected Tbg Fill Up Volume (bbls) injectivity. Ill If Applicable Expected IA Fill Up Volume (bbls) If Applicable Expected OA Fill Up Volume (bbls) 447 Wellbore Volume to Perfs (bbls) Fullbore Pumping Schedule 3300 Anticipated Bottom Hole Pressure (psi) Pump Volume Rate Max Select 1 Tubing /Casing within Pressure Limits? Stage Fluid Type Into (bbls) (bpm) Pressure Size Burst /Collapse 80% Burst /Collapse Tubing Burst (psi) 7.625 6890 / 4790 5512 / 3832 I Pre -Flush 1 Methanol (60/40) I Tbg 1 1 101 1 5 1 2500 Tubing Collapse (psi) size See helpful tips tab Casing Burst (psi) size See helpful tips tab I Solvent 1 1 Select Fluid Type 11 Tbg 11 2001 1 51 2500 Casing Collapse (psi) size _See helpful tips tab Load 1 1 Select Fluid Type 11 Tbg 1 5001 1 5 1 1 25001 Select Input Depth Integrity Issues? No unknown I Freeze Protect 1 Methanol (60/40) 1 Tbg 1 1 10 51 1 2500 No Input Depth I l I 11 1 1 I 1 1 1 Select Stage Select Fluid Type Select No Tubing Caliper? Burst/Collapse ratings may need to be derated based on tubing condition Select I Production Packer within Pressure Limits? Detailed Pumping Procedure Rated Packer dp Max Anticipated dp at Packer 1 10 bbls 60/40 meoh spear 2 200 bbls diesel. Let diesel soak at perfs for two hours I Not Necessary Hold Pressure on Other Strings? 3 500 bbls of fresh water with 0.02% F -103 surfactant Tubing (psi) 4 10 bbls 60/40 meoh IA (psi) 5 RDMO. Return well to gas injection OA (psi) Note: Monitor IA pressure at all times • Fullbore Pumping Program for Field Well Name AGI -10 Job Scope Solvent Treatment - Well Type GI AFE APBinjec Date 6/14/2012 IOR 30 Engineer Javier Farinez Phone 564 -5043 H2S Job Objective Improve injectivity by dissolving salts and possibly asphaltenes in the tubing and formation. Diesel /Xylene washes have been used successfully in the past on the NGI/WGI /AGI gas injectors to improve injectivity. Fullbore Pumping Schedule Stage Fluid Type Pump Into Volume (bbls) Rate (bpm) Max Pressure 1 Pre -Flush Methanol (60/40) Tbg 10 5 2500 2 Solvent Select Fluid Type Tbg 200 5 2500 3 Load 1 Select Fluid Type Tbg 500 5 2500 4 Freeze Protect I Methanol (60/40) Tbg 10 5 2500 5 Select Stage I Select Fluid Type Select Detailed Pumping Procedure 1 10 bbls 60/40 meoh spear 2 200 bbls diesel. Let diesel soak at perfs for two hours 3 500 bbls of fresh water with 0.02% F -103 surfactant 4 10 bbls 60/40 meoh 5 RDMO. Return well to gas injection Note: Monitor IA pressure at all times Additional Details If Applicable Recent Tbg Fluid Level (ft) Integrity Issues? No unknown If Applicable Recent IA Fluid Level (ft) No Input Depth If Applicable Recent OA Fluid Level (ft) • Freeze Protection - see PE manu for additional information Freeze Protect to 2500' TVD in GPB. • Use 60/40 Meth Water for Injectors Use 5 bbl 60/40 Meth Water spear followed by dead crude for Producers Pipe Data (L -80) dimensions mechanical inner capacity outer capacity size lb/ft od id drift id collapse burst bbls /ft ftlbbls bbls /ft ftlbbls 2 375 4.60 2.38 2.00 1.90 11780.00 11200.00 0.00387 258.6 0.00548 182.5 2.875 6.50 2.88 2.44 2.35 11160.00 10570.00 0.00579 172.8 0.00803 124.5 3.188 6.40 3.19 2.81 2.68 11111.00 11111.00 0.00769 130.1 0.00987 101.3 3.500 9.30 3.50 2.99 2.87 10530.00 10160.00 0.00870 115.0 0.01190 84.0 4.500 12.60 4.50 3.96 3.83 7500.00 8430.00 0.01522 65.7 0.01967 50.8 5.000 18.00 5.00 4.28 4.15 10490.00 9910.00 0.01776 56.3 0.02429 41.2 5.500 17.00 5.50 4.89 4.77 6280.00 7740.00 0.02325 43.0 0.02939 34.0 7.000 26.00 7.00 6.28 6.15 5410.00 7240.00 0.03826 26.1 0.04760 21.0 7.000 29.00 7.00 6.18 6.06 7020.00 8160.00 0.03715 26.9 0.04760 21.0 7.625 29.70 7.63 6.88 6.75 4790.00 6890.00 0.04592 21.8 0.05648 17.7 9.625 47.00 9.63 8.68 8.53 4760.00 6870.00 0.07321 13.7 0.08999 11.1 13.375 72.00 13.38 12.35 12.19 2670.00 5380.00 0.14809 6.8 0.17378 5.8 custom 6.000 4.000 0.01561 64.1 0.03497 28.6 Bursts OD GRADE WT Burst 3 1/2" 80 9.3# 10160 4 1/2" 80 12.6# 7500 5 1/2" 80 15.5# 7000 80 17# 7740 7" 80 26# 7240 80 29# 8160 95 29# 9690 110 29# 11220 7 5/8" 80 29.7# 6890 80 33.7# 7900 95 29.7# 8180 9 5/8" 55 36# 3520 55 40# 3950 80 40# 5750 80 43.5# 6330 80 47# 6870 80 53.5# 7930 95 47# 8150 10 3/4" 55 45.5# 3580 80 45.5# 5190 80 55.5# 6450 11 3/4" 95 60# 6920 13 3/8" 55 54.5# 2730 55 61# 3090 55 68# 3450 80 68# 5020 80 72# 5380 1 95 72# 6390 16" 80 84# 4330 18 5/8" 55 96.5# 2510 55 109.3# 2910 20" 40 94# 1530 55 133# 3060 Brine Design Notes Revised: 5/1/00 NaCI KCI CaCI NaBr Design Notes: 8.5 29 8.4 31 8.5 30 8.5 30 8.6 27 8.5 30 9.0 22 9.0 25 Design for -50 degrees from surface to 100', 10 degrees through permafrost (approx. 2500'). 8.7 26 8.7 27 9.5 10 9.5 20 Be careful using McOH /H2H for freeze cap - McOH may mix with brine and dilute 8.8 24 8.9 23 10.0 -9 10.0 14 Don't use Ca based fluids that may come in contact with the formation. 8.9 22 9.1 19 10.5 -36 10.5 6 Be careful using CaCI in IA - may dump on formation 9.0 19 9.3 15 10.7 -51 11.0 -2 Corrosion Inhibitor: mix 25 gal of NEEC EC1124 per 100 bbls brine 9.1 17 9.5 15 10.8 -57 11.5 -11 Note: Inhibitor has a 1 day half -life 9.2 14 9.6 33 10.9 -35 11.7 -16 Be careful allowing very cold diesel to contact KCI - could form a slush 9.3 11 11.0 -19 11.8 -19 9.4 9 11.5 36 11.9 -10 9.5 6 12.0 6 • 9.6 3 12.5 50 9.7 -1 12.7 63 9.8 -5 9.9 5 10.0 25 Crystallization Temperatures for Clear Brines 40 KCI / CaCI ! N aCI / -- • 20 ` ♦`♦ ' `�`� / NaBr ■ -20 /► / N 1 -40 � ' � �( - a - CaCI - \ � / --s---KCI -60 • NaBr 8.5 9 Density, PPG 10.5 11.5 _-__ - 12.5 TREE = ¢8" FMC • A G 1 -10A ip1T3LFiAI� egg SOY NOTES: WELL REQUIRES A SSSV. ACTUATOR= BAKERC KB. B..EV = 46.5' BF ELEV = 16' KOP= 3725' 7" TBG, 26#, L -80, TC-1, --I 31' 1 1 ' ' L 31' H 7" X 7 -5/8" XO, D = 6.276" 1 tv x Angle = 41 © 3240' .0383 bpf, D = 6.276' Datum MD = 10483' DatumTVD= 8800. SS 2163' I-� 7 -518" X T XO, D= 6.276" I 7 -5/8" TBG, 29.7 #, L -80, PC VAM TOP, -j 2163' .0459 bpf, D = 6.875" I 1 2174' H7" CA MCO DB LANDING NP, D= 6.00" I 2186' H 7" X 7 -5/8° XO, ID= 6.276° 17" TBG, 26#, L -80, TC-1, .0383 bpf, ID= 6.276' IH 2185' Minimum ID = 6.770 "@ 9344' 7" HES RN NIPPLE 13 -3/8" MLLOUT W■DOW (AGI -10A) 3725' - 3749' 113-3/8" VVHPSTOCK (10/27106) —1 3725' 13 -3/8" EZSVB (10/26/06) 3754' 13 -3/8" CSG, 68#, H 3846' 5160'1-1 ESTIMATED TOP OF CEMENT NT-80, D = 12.415" '• • , 4 ' 9282' z:::::: • V 4 ` ♦! 9293' � • • • ■ ■ ■�• t � 9317' I— 9-5/8' X 7" BKR S-3 PKR, • ........ " ' , Vitt. ....... 7 -5/8" TBG, 29.7 #, L-80, —1 9282' ♦ 4,O ♦ 9344" — I 7" HES RN NP, D= 5.770' I •' PC VAM TOP, •4 • .0459 bpf, D �4 = 6.875" • � * , 1 9359' I— 9 -5/8" X 7" BKR ZXP ♦ ∎ LTP , D = 6.23" ■ 7' TBG, 26#, L-80, TGi, —I 9366' ,� ♦ : 1 9377' I�9 518' X 7' BKR HuIC i i` l; MR HGR,D =6.32" • .0383 bpf, D = 6.276" *. VA �: • ♦∎ 9366' 1-17" MULE SHOE, 1j D = 6,276' 9-5/8" CSG, 47 #, L -80, TC-I, D = 8.681" IH 9439' 1 PERFORATION SUMMARY \ RE= LOG: LWD ON 11/07/06 ANGLE AT TOP PERF: 35 © 9485 7" SOLD LNR 26#, 1-80, —I 9485' (— Note: Refer to Roduction DB for historical pert data BTC-M, .0383 bpf, D = 6.276' \ SVE 1 SPF INTERVAL Opn/Sqz DATE \ \ SLOTTED 9485 - 9564 0 11/07/06 1" 18 9564 - 9933 0 11/07/06 \ \ 7' SLID LNR, 26#, L -80, —1 9565 (— \ BTC-M, .0383 bpf, D = 6.276" \ 17" PERFORATED LNR, 26#, L -80, BTC-M, .0383 bpf, ID = 6.276" H 9933' I— ` !oli � � , � k 17" LM, 26#, L -80, BTC-M, .0383 bpf, D = 6.276" --I 9937' GATE REV BY COMFITS CATE REV BY OOMSMENTS FRUCHOE BAY LW 04/01/93 ORIGINAL COMPLETION WELL: AGI -10A 11/12106 N2ES SIDETRACK "A" PERMT No: "1061350 01/12/07 JAF/PJC DRLG DRAFT CORRECTIONS AR No: 50- 029 - 22353 -01 03/09/07 MNVSIPJC DRLG DRAFT CORRECTIONS Sec, 36, T12N, R14E, 2808.63 FE_ 5240.67 FNL 02/11 /11 103/J1413 ADDED SSSV SAHHIY NOTE BP Exploration (Alaska) • . MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: DATE: Wednesday, December 29, 2010 Jim Regg P.I. Supervisor 'ee y/ 411( SUBJECT: Mechanical Integrity Tests BP EXPLORATION (ALASKA) INC AGI -10A FROM: John Crisp PRUDHOE BAY UNIT AGI -10A Petroleum Inspector Src: Inspector Reviewed By: P.I. Supry , 0--- -- NON - CONFIDENTIAL Comm Well Name: PRUDHOE BAY UNIT AGI - 10A API Well Number: 50 029 - 22353 - 01 - 00 Inspector Name: John Crisp Insp Num: mitJCr101220075612 Permit Number: 206 - 135 - Inspection Date: 12/17/2010 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. 'Well AGI -10A Type Inj. G ' TVD 7882 ' IA j 540 2500 - 2490 2480 2480 ' p.T.D 2061350 ' TypeTest SPT Test psi 1970 ' OA 320 420 430 430 430 s Interval 4YRTST p/F P Tubing 3325 3325 3325 3325 3325 Notes: 2.4 bbls pumped for test. ' %MOO FEB 4 7 2011 Wednesday, December 29, 2010 Page 1 of 1 MEMORANDUM State of Alaska • Alaska Oil and Gas Conservation Commission TO: Jim Regg ;�J DATE: Friday, December 03, 2010 f s P.I. Supervisor / 1 i ` 1 4 � p SUBJECT: Mechanical Integrity Tests BP EXPLORATION(ALASKA)INC ' AGI -10A FROM: Jeff Jones PRUDHOE BAY UNIT AGI -10A Petroleum Inspector Src: Inspector Reviewed By: P.I. Suprv NON - CONFIDENTIAL Comm Well Name: PRUDHOE BAY UNIT AGI -10A API Well Number: 50- 029 - 22353 -01 -00 Inspector Name: Jeff Jones Insp Num mitJJ101202154510 Permit Number: 206 -135 -0 Inspection Date: 12/2/2010 Rel Insp Num: Packer Depth Pretes Initia 15 Min. 30 Min. 45 Min. 60 Min. Well AGI -loA T i y p e In,j. G TVD 7882 IA ao 2520 2szo� 2470 2400 2260 p T D 2061350'T yp e Test SPT Test psi 1970 ✓ OA 100 420 ago 400 380 320 4YRTST F Tubing 3340 1 3320 3330 3250 3300 3300 Interval _ P/F _ _ gl i � Notes: 5.3 BBLS diesel pumped, IA pressure failed to stabilize. 1 well inspected; no exceptions noted. Friday, December 03, 2010 Page 1 of 1 • ~~` _. ~, ~. ~. ~ ;~ ,~~ x ~~~ ~., ~~ ~ as ~ ~ ~'~r ~° ~+ ~ s h 'wS :~~~ ~ ` MICROFILMED 6/30/2010 D O N OT PLACE ANY NEW MATERIAL. UNDER THIS PAGE C:\temp\Temporary Internet Files\OLK9\Microfilm_Marker.doc DATA SUBMITTAL COMPLIANCE REPORT 10/13/2008 Permit to Drill 2061350 Well Name/No. PRUDHOE BAY UNIT AGI-10A Operator BP EXPLORATION (ALASKA) INC API No. 50-029-22353-01-00 MD 9937 TVD 8394 Completion Date 11/12/2006 Completion Status 1GINJ Current Status 1GINJ UIC Y REQUIRED INFORMATION Mud Log No Samples No Directional Survey es DATA INFORMATION Types Electric or Other Log s Run: MWD, DIR, G R, PWD, USIT, CCL, CBL, Madd Pass (data taken from Logs Portion of Master Well Data Maint Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval OH / Type Med/Frmt Number Name ,Scale Media No Start Stop CH Received Comments Cement Evaluation 5 Col 1 50 9335 Case 1/22/2007 USIT, CBL, CCL, GR 9- Nov-2006 ~/ D Asc ` ' Directional Survey 3711 9937 Open 1/28/2007 D C Las 15482 .E Gamma Ray ~~ ~ 3526 3700 Open 10/3/2007 GR w/EMF Graphics Field / / LIS V if i Data u~st er icat on 3522 9933 Open 6/19/2008 LIS Veri, GR, ROP ~ C Lis 16478 Gamma Ray ~ ~...-. 3522 9933 Open 6/19/2008 LIS Veri, GR, ROP , "ED C Pds 16885 See Notes f~"3-~"'~ 0 0 9/16/2008 TVD and MD GR logs in PDS graphics Q.og Gamma Ray 2 Col 3725 9937 Open 9/16/2008 MD ROP, DGR 9-Nov-2006 og Gamma Ray 2 Col 3381 8393 Open 9/16/2008 I TVD ROP, DGR 9-Nov- -_--- -- 2006 Well Cores/Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comme nts ADDITIONAL INFORMA !ON Well Cored? Y / N~ Daily History Received? ~N Chips Received? 'YTIV Formation Tops ~ N Analysis ~ Y / Received? Comments: DATA SUBMITTAL COMPLIANCE REPORT 10/13/2008 Permit to Drill 2061350 Well Name/No. PRUDHOE BAY UNIT AGI-10A Operator BP EXPLORATION (ALASKA) INC API No. 50-029-22353-01-00 MD 9937 TVD 8394 Completion Date 11/12/2006 Completion Status 1GINJ Current Status 1GINJ UIC Y Compliance Reviewed By: Date: r ~ \~ • WELL LOG TRANSMITTAL To: State of Alaska Alaska Oil and Gas Conservation Comm. Attn.: Librarian 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RE: MWD Formation Evaluation Logs: AGI-l0A September 11, 2008 AK-MW-4693375 AGI-10A: 2" x 5" MD RESISTIVITY & GAMMA RAY Logs: I Color Log 50-029-22353-O1 2" x S" TVD RESISTIVITY & GAMMA RAY Logs: 1 Color Log 50-029-22353-O1 Digital Log Images: 1 CD Rom 50-029-22353-01 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Sperry Drilling Services BP Exploration (Alaska) Inc. Attn: Rob Kalish Petrotechnical Data Center, MB33 6900 Arctic Blvd. 900 E. Benson Blvd. Anchorage, Alaska 99518 Anchorage, Alaska 99508 Date Signed: L~ ~o~ -t3 s~ ~ ~~~ v r WEI..I., L®G TRANSIVIITTAI.. To: State of Alaska June 10, 2008 Alaska Oil and Gas Conservation Comm. Attn.: Librarian 333 West 7~' Avenue, Suite 100 Anchorage, Alaska 99501 RE: MWD Formation Evaluation Data: AGI-l0A AK-MW-4693375 1 LDWG formatted CD rom with verification listing. API#: 50-029-22353-01 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Sperry Drilling Services Attn: Rob Kalish 6900 Arctic Blvd. Anchorage, Alaska 99518 Date: BP Exploration (Alaska) Inc. Petrotechnical Data Center MB33 900 E. Benson Blvd. Anchorage, Alaska 99508 ,~ /'r ~/l ;' Signed: ' 'L/ Date 09-20-2007 Transmittal Numbec92904 BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. (BPXA FIELD LOG DATA) [f you have any questions, please contact Douglas Dortch at the YllC at 564-4y !3 Delivery Contents 1 CD-ROM Containing Field Log Data & Electronic Log Prints for the following wells: __ _ _ AG1-10Aao~- i3S` ~` i5~/~a __ F-01 A aoly a`b'_ . ~ !-3~/~3 +~ ~5~i11`/ F-01 APB1 F-09Bao~-vt3 ~ ~SV~S - ---- _ _ _ F-42A c~U'~- U~3 '~ i 5~~'`S~v L-204Li a~-V~i3 ~ i 5~/~ ~ L-204L2 av(o- bq ~/ '~ -S~/$5( L-204L3 aQ(o-OAS ~r j5~/~ L-204L4 a U(o-p~ ~, +~ ~ Ste! ~ ~ V-205L1 c7U(o - !?f 1 ~'' I S~IcI o`~ V-205L2 aU(o-1 ~a ~ 1 S~3 W-204L1_c2U~C- _59 '~ 1. J S~°i_y _ W-204L2 aU~,_-llo_O *' !S ~/4 5 WG1-09__U_'LC ~a~ - I~!(o ~ tS-~/9l~ Please Sign and Return one copy of this transmittal. Thank You, Douglas Dortch Petrotechnical Data Center Attn: State of Alaska - AOGCC Attn: Christine Mahnken 333 W. 7th Ave, Suite 100 Anchorage, Alaska 99501 Petrotechnical Data Center LR2- l 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519-6612 i b' • • 20-Nov-06 AOGCC Librarian 333 W. 7th Ave. Suite 100 Anchorage, AK 99501 Re: Distribution of Survey Data for Well AGI-10A Dear Dear Sir/Madam: Enclosed is one disk with the *.PTT and *.PDF files. Tie-on Survey: 3,711.13' MD Window /Kickoff Survey: 3,725.00' MD (if applicable) Projected Survey: 9,937.00' MD PLEASE ACKNOWLEDGE RECEIPT BY SENDING AN EMAIL TO Timothy.Allen@HALLIBURTON.COM OR SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Sperry-Sun Drilling Services Attn: Timothy Allen 6900 Arctic Blvd. Anchorage, AK 99518 Date a 8 J,,,~~~~ Signed Please call me at 273-3534 if you have any questions or concerns. Regards, Timothy Allen Survey Manager Attachment(s) 01 /22/2007 >Ii~ifllA~l l~t~~~G1- NO. 4112 Alaska Data & Consulting Services Company: State of Alaska 2525 Gambell Street, Suite 400 t~~ Alaska Oil & Gas Cons Comm Anchorage, AK 99503-2838 ~~ _ ~~V Attn: Christine Mahnken ATTN: Beth 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Prudhoe Bay Woll Jnb ~! 1 nn rlecerin4inn Ila4c RI C:nlnr CD MPS-10A 11076475 CH EDIT SCMT (PDC-GR) 10/17/05 1 15-08CL1 10942196 CH EDIT JEWELRY (PDC-GR) 03/01/05 1 Z-12 11513657 RST 12106106 1 1 L3-11 11533392 RST 12/31/06 1 1 AGI-10A 11485869 USIT 11109106 1 GNI-02A 11485873 USIT 11/15/06 1 GNI-02A 11485874 MDT 12103106 1 12-18 NIA USIT 11/17/06 1 NGI-07A 11212892 USIT 10/13/06 1 DS 12-14AL1 11540230 CORROSION & CBL 12/18/06 1 01-23 11549351 USIT 12/16/06 1 WGI-09 11486172 USIT 12103106 1 YLtASt AI:KNUWLtUht KtGt1Y 1 t3T JI(iNING ANU Kt 1 UKNINLi UNt I:UYY tAGFI I U: BP Exploration (Alaska) Inc. Petrotechnical Data Center LR2-1 900 E. Benson Blvd. Anchorage, Alaska 99508 Date Delivered: Alaska Data & ,Cphslal6rag ~erv~CeS - 2525 Gambell Steed b~uite~'400 I Anchorage, AK 99503-?838 ATTN: Beth Received by: ,~._~. • MEMORANDUM TO: Jim Regg ~~~c~ f~l~~~ P.I. Supervisor FROM: Chuck Scheve Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission DATE: Wednesday, December 13, 2006 StiBJECT: Mechanical Integrity Tests BP EXPLORATION (ALASKA) INC AGI-1 OA PRL~HOE BAY UNIT AGI-l0A Src: Inspector NON-CONFIDENTIAL Reviewed By: P.I. Suprv ~P~-. Comm Well Name: PRUDHOE BAY iJNIT AGI-I OA mitCS061208li3736 Insp Num: Rel Insp Num API Well Number Permit Number: 50-029-22353-01-00 206-135-0 Inspector Name: Chuck Scheve Inspection Date: 12/8/2006 Packer Depth Pretest Initial IS Min. 30 Min. 45 Min. 60 Min. ~ AGI-IOA ~ ~~~ TVD e In ~ Well ~ TYp ~~ ~ 7882 ~ ~~ 120 ii 2520 i ~ 210 ~ 210 i ~ I ~_ ~ 206li50 SPT ~i P.T. T)'peTe9t .Test pSl '~ 1970 5 OA 40 40 ~ - - 40 40 i - I -- -- InteCVal INITr1L Pte` P / _ TUbing 3240 ~ 3240 ~ 3240 3240 Notes pretest pressures observed and found stable. Wednesday, December 13, 2006 Page 1 of 1 STATE OF ALASKA ALASKA AND GAS CONSERVATION COMMI~ON ~~~~~ y r~ AFC d 4 ZtiD6 WELL COMPLETION OR RECOMPLETION REPORT AND L~G asks flit Gas Luna. Corruttissinn 1 a. Well Status: ^ Oil ^ Gas ^ Plugged ^ Abandoned ^ Suspended ^ WAG 20AAC 25.,05 zoAAC zs.,,o ® GINJ ^ WINJ ^ WDSPL No. of Completions One Other 1 b. Well Class. Or8p0 ^ Development ~ Exploratory ^ Stratigraphic ®Service 2. Operator Name: BP Exploration (Alaska) Inc. 5. Date Comp., Susp., or Aband. 11/12/2006 12. Permit to Drill Number 206-135 3. Address: P.O. Box 196612, Anchorage, Alaska 99519-6612 6. Date Spudded 10/29/2006 13. API Number 50-029-22353-01-00 4a. Location of Well (Governmental Section): Surface: ' ' 7. Date T.D. Reached 11/7/2006 14. Well Name and Number: PBU AGI-10A 2634 FNL, 2579 FEL, SEC. 36, T12N, R14E, UM Top of Productive Horizon: 527' FNL, 1562' FWL, SEC. 31, T12N, R15E, UM 8. KB Elevation (tt): 46.50 15. Field /Pool(s): Prudhoe Bay Field / Prudhoe Bay Total Depth: 395' FNL, 1779' FWL, SEC. 31, T12N, R15E, UM 9. Plug Back Depth (MD+TVD) 9933 + 8390 Ft Pool 4b. Location of Well (State Base Plane Coordinates): Surface: x- 688686 y- 5980282 Zone- ASP4 10. Total Depth (MD+TVD) 9937 + 8394 Ft 16. Property Designation: ADL 034628 TPI: x- 692771 y- 5982493 Zone- ASP4 Total Depth: x- 692985 y- 5982631 Zone- ASP4 11. Depth where SSSV set 2174' MD 17. Land Use Permit: 18. Directional Survey ®Yes ^ No 19. Water depth, if offshore N/A MSL 20. Thickness of Permafrost 1900' (Approx.) 21. Logs Run: MWD, DIR, GR, PWD, USIT, CCL, CBL, Madd Pass 22. CASING, LINER AND CEMENTING RECORD CASING SETTING DEPTH MD SETTING DEPTH TVD HOLE AMOUNT SIZE WT. PER FT. GRADE TOP BOTTOM TOP BOTTOM SIZE CEMENTING RECORD PULLED 20" 91.5# H-40 30' 106' 0' 106' 30" 281 cu tt Arctic et 13-318" 68# NT80 38' 7 38' 33 1' 16" 2387 cu tt PF 'E' 484 cu ft CI ss 'G' 9-5/8" 47# L-80 1' 943 ' 1' 79 2' 12-1/4" 11 cu tt Lit rte 71 'G' 7" 26# L-8 9359' 993 ' 7917' 83 2' 8-1/2" Uncemented Slotted Liner 23. Perforations open to Production (MD + TVD of Top and 24. TUBING RECORD Bottom Interval, Size and Number; if none, state "none"): SIZE DEPTH SET MD PACKER SET MD 7" Slotted Liner 7-5/8" x 7", 29.7# x 26#, L-80 9366' 9317' MD TVD MD TVD 9485' - 9933' 8020' - 8390' 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL MD AMOUNT Ht KIND OF MATERIAL USED Freeze Protected with 100 Bbls of Diesel 26. PRODUCTION TEST Date First Production: November 29, 2006 Method of Operation (Flowing, Gas Lift, etc.): Gas Injection Date of Test Hours Tested PRODUCTION FOR TEST PERIOD OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE GAS-OIL RATIO Flow Tubing PreSS. Casing Pressure CALCULATED 24-HOUR RATE• OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY-API (CORK) 27. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary). Submit core chips; if none, state "nor~e~N _~ , " None t ~wl~U-t.~ 3~z s.,.~ 331 ~" ~~_ ~° 4 ~,_\.~ Form 10-407 Revised 12/2003 ONTINUED ON REVERSE SIDE :,~ 1 ~ ~ I C~ 28 GEOLOGIC MARKERS 29. TION TESTS Include and briefly s ~~~marize test results. List intervals tested, N,4ME MD TVD and attach detailed supporting data as necessary. If no tests were conducted state "None". Ugnu 4 5611' 4898' Ugnu 4A 5650' 4929' None Ugnu 3 6193' 5369' Ugnu 1 6756' 5818' West Sak 2 7365' 6296' West Sak 1 7520' 6422' Colville Mudstone 3 7658' 6534' Colville Mudstone 2 8425' 7166' Colville Mudstone 1 8984' 7613' THRZ 9378' 7932' BHRZ 9476' 8013' Top of Put 9476' 8013' LCU 9486' 8021' Top of Sadlerochit 9486' 8021' 42S624A 9525' 8053' TGCL 9542' 8067' BCGL 9610' 8123' 23SB226 9710' 8205' 22TS 9741' 8231' 21 TS22A 9769' 8254' TZ1 B 9866' 8335' 30. List of Attachments: Summary of Daily Drilling Reports, Well Schematic Diagram, Surveys and aLeak-Off Test Summary. 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed So ra Stewma Title Technical Assistant Date f ~ ' ~~~ - ~~ PBU AGI-10A 206-135 Prepared By NameMumber. Sondra Stewman, 564-4750 Well Number Permit No. / A royal No. OriAing Engineer: Joshua Sudderth, 564-4342 INSTRUCTIONS GeNeRa~: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. ITeM 1a: Classification of Service Wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Mukiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. ITeM 4b: TPI (Top of Producing Interval). ITeM 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. ITeM 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). ITeM 20: True vertical thickness. IreM 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. ITeM 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). ITeM 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-In, or Other (explain). ITeM 27: If no cores taken, indicate "None". ITeM 28: list all test information. If none, state "None". Form 10-407 Revised 12/2003 Submit Original Only 3 ~ BP EXPLORATION Page 1 of 19 Operations Summary Report Legal Well Name: AGI-10 Common Well Name: AGI-10 Spud Date: 10/28/2006 Event Name: REENTER+COMPLETE Start: 10/16/2006 End: 11/12/2006 Contractor Name: NABOBS ALASKA DRILLING I Rig Release: 11/12/2006 Rig Name: NABOBS 27E Rig Number: Date Task 'Code NPT Phase rom - o I ours ~~ - _ - 00:00 - 00:00 24.00 10/16/2006 ~ MOB N WAIT PRE 1 ~_ 10/17/2006 100:00 - 00:00 ~ 24.00 MOB I N I WAIT PRE 10/18/2006 100:00 - 04:00 I 4.001 MOB I N I WAIT I PRE 04:00 - 00:00 20.00 MOB P 10/19/2006 100:00 - 08:00 I 8.001 RIGU I P 08:00 - 11:00 I 2.001 RIGU I P 11:00 - 12:00 I 1.001 RIGU I P 12:00-13:00 I 1.OOIWHSURIP 13:00 - 14:00 1.00 WHSUR P 14:00 - 15:30 1.50 WHSUR P 15:30-17:001 i.501WHSURIP 17:00-19:00 I 2.OOIWHSURIP 19:00 - 00:00 I 5.001 KILL I P PRE Description of Operations Rig released from NGI-07A at 24:00 hrs on 10/15/06. Rig down service lines. Separate rig modules. Stand-by for rig move (waiting on pre-rig well work oh AGI-10). Perform rig maintenance & paintinting. Repaired suction valves in pits. Change out cement hose. Change out #2 mud ppump pulsation dampener. Continue to wait on the completion of the pre-rig work on AGI-10 prior to beginning rig move. Continue rig maintenance. Continue to wait on location for completion of pre-rig work on AGI-10 prior to moving rig. Perform rig maintenance while waiting. AGI-10 pre-rig location work completed at 04:00 hrs. Rig down service line Clean up location, removing hecurlite and matting boards Transported Pipe shed, motor complex, pump module, pit module and sub base to AGI Set matting boards and Herculite for Sub Base, Spot Sub over well Set matting boards and Herculite for Pipe Shed, Spot Pipe Shed Set matting boards and Herculite for Pits, Spot Pits Set matting boards and Herculite for Pump Room, Spot Pump Room Set matting boards and Herculite for Motor Room, Spot Motor Room 0 psi on IA & OA PRE Finish Move and rig up over AGI-10 -connect all services lines in disconnect -finish securing berms and spill protection -moved camp & shop: set up gen shack and fuel tank -set Tiogas & berm PRE Rig up skate and function test Complete pre spud list Accept rig ~ 11:00 hrs PRE Take on 300 bbls of 9.6 brine into pits Prep floor, function test draworks and TDS DECOMP Pre-Spud meeting with rig crew, BP WSL and BP Drilling Engineer DECOMP PJSM -Install secondary annulus valve on IA DECOMP PJSM with DSM and rig crews on pulling BPV Install Lubricator o Wellhead, Pull BPV, Rig Down Lubricator DECOMP Connnect lines to squeeze manifold and wellhead. Rig up line to cutting tank DECOMP PJSM on displacing diesel and circulating 9.6 brine around -Pressure test surface lines to 4000 psi, good test DECOMP O psi on the tubing and IA before pumping -Reverse 24 bbls down IA displacing MW directly to cuttings tank, 5 bbl to fill annulus / 3 bbl /min C~ 400 psi -Pump down tubing, taking returns up IA to the choke /gas Printed: 11/13/2006 10:46:09 AM BP EXPLORATION Page 2 of 19 Operations Summary Report Legal Well Name: AGI-10 Common Well Name: AGI-10 Spud Date: 10/28/2006 Event Name: REENTER+COMPLETE Start: 10/16/2006 End: 11/12/2006 Contractor Name: NABOBS ALASKA DRILLING I Rig Release: 11/12/2006 Rig Name: NABOBS 27E Rig Number: Date From - To Hours Task Code I NPT I Phase 10/19/2006 19:00 - 00:00 5.00 KILL P 10/20/2006 00:00 - 00:30 0.50 WHSUR P 00:30 - 01:30 I 1.001 WHSUR I P 01:30 - 02:30 1.00 WHSUR P 02:30 - 03:30 1.00 BOPSU P 03:30 - 05:00 1.50 WHSUR P 05:00 - 07:00 2.00 WHSUR P 07:00 - 10:30 3.50 BOPSU N 10:30 - 22:00 11.50 BOPSU P Description of Operations DECOMP buster pumped 68 bbls C~ 3 BPM = 400 psi, displaced apx. 56 bbl of diesel out before getting 9.8 brine to surface, 1 psi on gas buster CBU (IA x Tubing) ~ 3 BPM / 300 psi increasing to 4 BPM = 700 psi , 0 psi on gas buster Monitor well for 10 min. / no gas or flow Pump Safe Surf-O sweep Surface to surface ~ 4 BPM = 700 psi (0 psi on gas buster) Monitor well for flow for 15 min DECOMP Shut in Wellhead and Remove lines from Tubing and IA, Open up tubing side ,well static Open up IA, well returned 2 bbls then slowed to a trickle, Well static after 15 min. DECOMP PJSM -install TWC and test from above to 1000 psi for 5min, passed DECOMP Rig down squeeze manifold and lines Blow down Choke and choke line DECOMP Rig up to circ. across top of IA -circ out 1 pit, monitor for gains /losses DECOMP Nipple Down Tree and set outside DECOMP -Separate Adapter flange on tree, disconnect SSSV tines -Check LDS, O.K. -Inspect tubing hanger threads, -Screw XO in to hanger 7 1/2 rounds RREP DECOMP Change out cables on DS bridge crane DECOMP N/U BOP stack, choke line /kill lines, drilling nipple, flowline, hole fill line, drip pan covers & turnbuckles 22:00 - 00:00 2.00 BOPSU P DECOMP Install blind/shear rams -Rig to test 10/21/2006 00:00 - 01:00 1.00 BOPSU P DECOMP Finish installing blind rams and nipple up operation on BOPE's 01:00 - 09:00 8.00 BOPSU P DECOMP Conduct BOPE pressure test - 250 low / 4000 high for 5 minutes /test Witness by Dave Newlon (WSL), Wayne Stouts (toolpusher), Witness of Test waived by Jeff Jones (AOGCC) #1 test- blind rams, Manual valve on kill line and #1 & #2 valve on choke manifold #2 test - HCR kill valve, Choke manifold valves 3,4,5,6 #3 test Choke manifold valves 7,8,9 #4 test Choke manifold valves 10,11,12 Valve #10 failed, cycled valve and retest high, OK #5 test Choke manifold valves 13,14,15 P/U 7" test joint #6 Test Upper pipe rams, choke #16, floor TIW safety valve #7 Test Manual choke & dart valve #8 Test HCR choke #9 Test Annular to 250 Low / 3500 High Upper TDS IBOP test failed Printed: 11!13/2006 10:46:09 AM BP EXPLORATION Operations Summary Report. Legal Well Name: AGI-10 Common Well Name: AGI-10 Event Name: REENTER+COMPLETE Contractor Name: NABOBS ALASKA DRILLING I Rig Name: NABOBS 27E Date ~ From - To Hours Task"Code NPT 10/21/2006 101:00 - 09:00 8.00 BOPSUR P Start: 10/16/2006 Rig Release: 11/12/2006 Rig Number: Phase DECOMP Page 3 of 19 Spud Date: 10/28/2006 End: 11 /12/2006 Description of Qperations Conduct BOP Accumulator Test, Starting Pressure 3000 psi, After Closure 1,800 psi, Initial 200 psi Recovery 27 sec, Final Pressure 3000 psi, Full Recovery Time 1 min 45 sec., 8 nitrogen bottles avg. of 2300 psi 09:00 - 10:00 1.00 BOPSU P DECOMP Lay down 7" test joint and blow down Top Drive 10:00 - 13:00 3.00 BOPSU P DECOMP Change out Upper IBOP Valve on Top. Drive (P/U csg .handling equip) 13:00 - 14:00 1.00 BOPSU P DECOMP PJSM -Rig up Lubricator and pull TWC 14:00 - 16:00 2.00 BOPSU N SFAL DECOMP Install Upper IBOP and test, Failed 16:00 - 20:00 4.00 BOPSU N SFAL DECOMP Change Out Upper IBOP (P/U SSSV control line spooler during C/O) 20:00 - 21:00 1.00 BOPSU P DECOMP Test IBOP, -Test to 250 low, passed -Test 4000 high, Failed, cycled valve, Retest, good test R/D test equip. 21:00 - 21:30 0.50 CASE P DECOMP PJSM, P/U 1 joint of 5" DP and XO's and Screw into hanger, M/U Top Drive Back out LDS and pull hanger to floor PPUW 205k with top drive and block weight 21:30 - 22:30 1.00 CASE P DECOMP CBU ~ 5 BPM / 150 psi R/U to UD 7" tubing Monitor well for 15 min. -static 22:30 - 23:00 0.50 CASE P DECOMP UD tubing Hanger and Landing joint 23:00 - 00:00 I 1.001 CASE I P 10/22/2006 100:00 - 05:00 I 5.00 I CASE I P 05:00 - 11:00 6.00 CASE P 11:00 - 12:00 1.00 CASE P 12:00 - 14:30 2.50 BOPSU P 14:30 - 15:00 0.50 BOPSU~ P 15:00 - 16:30 1.50 WHSUR P 16:30 - 19:30 3.00 CLEAN P 19:30 - 00:00 4.50 CLEAN P 10/23/2006 00:00 - 00:30 0.50 CLEAN N 00:30 - 01:00 0.50 CLEAN P 01:00 - 02:30 1.50 CLEAN P DECOMP POH with 7" #26 NT-80 NSCC tubing Spooling SSSV control line DECOMP POH with 7" #26 NT-80 NSCC tuibing Spooling SSSV control line Recovered 31 SS bands DECOMP POH with 7" #26 NT-80 NSCC tuibing 187 jts, SSSV and Pup jts, And cut jt 16.75' DECOMP Clear rig floor of casing handling equipment and tools DECOMP P/U 5" test joint and test plug Conduct BOPE pressure test - 250 low / 4000 high for 5 minutes /test -chart test Witness by Chris Clemens (WSL), Jim Henson (toolpusher), Witness of Test waived by Jeff Jones (AOGCC) #1 test- lower pipe rams, OK #2 test -upper pipe rams, OK #3 test - Annular to 250 / 3500 psi, OK DECOMP UD 5" test jt. and test plug, Clear testing equip. from floor DECOMP Set wear bushing & lock down DECOMP P/U 9 5/8 casing scraper & junk baskets (wiper BHA) P/U 21 jts. of 5" HWDP DECOMP RIH to 4143' picking up 5" DP 1 x 1 DECOMP Repair electrical breaker on pipe skate DECOMP RIH picking up 5" DP 1 x 1 to 4559' DECOMP Pump Safe surf-o sweep around 12 BPM ~ 700 psi Printed: 11/73/2006 10:46:09 AM BP EXPLORATION Page 4 of 19 Operations Summary Report Legal Well Name: AGI-10 Common Well Name: AGI-10 Spud Date: 10/28/2006 Event Name: REENTER+COMPLETE Start: 10/16/2006 End: 11/12/2006 Contractor Name: NABOBS ALASKA DRILLING I Rig Releaser 11/12/2006 Rig Name: NABOBS 27E Rig Number: Date I From - To I Hours I Task ~ Code I NPT I Phase 10/23/2006 101:00 - 02:30 I 1.501 CLEAN I P 02:30 - 05:00 I 2.50 I CLEAN I P 05:00 - 06:00 1.00 CLEAN P 06:00 - 13:30 7.50 DHB P 13:30 - 15:00 1.50 CASE 15:00 - 19:30 4.50 FISH P 19:30 - 20:00 0.50 FISH P 20:00 - 22:00 I 2.001 FISH I P 22:00 - 22:30 I 0.501 FISH I P 22:30 - 00:00 1.50 FISH P 10/24/2006 00:00 - 02:00 2.00 FISH P Description of Operations DECOMP PUW 145k / 130k SOW Monitor well for 10 min., Static Pump Dry job DECOMP POH and UD casing scraper and junk baskets Small amount of scale recovered in baskets, no metal DECOMP PJSM -Service TDS and Draw works DECOMP PJSM - R/U SWS, -RIH with USIT, CCL, & GR log to 4300' 9 5/8 casing cemented to 3800' -UD USIT logging tools - P/U 9 5/8 EZSV and RIH to 4090' and set R/D SWS DECOMP Test 9 5/8" casing to 3500 psi for 30 min. and chart, Good test DECOMP M/U BOT casing cutter and RIH to 3760 DECOMP Space out cutter and Cut Casing ~ 3760' PUW - 130K, SOW - 120K, RtWt - 125k 4 BPM / 600 psi ! 50 RPM/ 2k tq pumps off / 4k pumps on 10 min to complete cut DECOMP PJSM -Close bag and line up OA to cuttings tank Displace 170 bbls diesel /dead crude with 9.6 brine Pump a total of 250 bbls, Held 300 psi back pressure on OA with manual choke Displaced ~ 3 BPM / 500 psi on IA and 800 psi on OA DECOMP Open bag and monitor well for 15 min. -well static /zero psi on OA Pump dry job DECOMP POH with casing cutter DECOMP POH and UD BOT cutting tool and subs Clear floor and UD subs and tools 02:00 - 05:00 I 3.00 I BOPSUFi P 05:00 - 06:00 1.00 BOPSU P 06:00 - 06:30 0.50 BOPSU P 06:30 - 07:00 0.50 STCTPL P 07:00 - 09:30 2.50 STCTPL P 09:30 - 10:30 I 1.001 STCTPL 10:30 - 12:00 1.50 STCTPL P 12:00 - 13:00 1.00 STCTPL P 13:00 - 16:00 3.00 STCTPL P 16:00 - 16:30 0.50 STCTPL P DECOMP Change upper rams to 9 5/8" Pull wear bushing and set test plug Rig up to test DECOMP Conduct ROPE pressure test and chart Witness by Chris Clemens (WSL), Wayne Stouts (toolpusher), Test upper Rams to 250 low / 4000 high 5 min each test Test Annular to 250 low / 3500 high, 5 min each test DECOMP Rig down test equipment DECOMP PJSM and bring all equipment up to the rig floor for spear BHA DECOMP Pick up BHA and Spear 9 5/8" Hanger Casing broke free at 260KIbs PUW=195K DECOMP Circulate Safe-O sweep surface to surface 640 GPM C~ 215 psi Substantial amount of granular material came back through out bottoms up (looked like cement} MW = 9.6 ppg in and out DECOMP Lay down Spear, Hanger, and Pack off DECOMP Monitor Well, well static Rig up 9 5/8" casing equipment DECOMP Pull 9 5/8" casing Lay down 29 joints DECOMP Service rig -Service top drive Printed: 11/13/2006 10:46:09 AM BP EXPLORATION Page 5 of 19 Operations Summary Report Legal Well Common W Event Nam Contractor Rig Name: Date Name: ell Name: e: Name: From - To AGI-10 AGI-10 REENTE NABOB NABOB Hours R+COM S ALASK S 27E Task PLET A DRI Code E LLING NPT Start I Rig Rig Phase . Spud Date: 10/28/2006 : 10/16/2006 End: 11/12/2006 Release: 11/12/2006 Number: Description of Operations 10/24/2006 16:30 - 20:30 4.00 STCTPL P DECOMP Pull 9 5/8" casing Lay down 65 joints plus cut joint for a total of 94 joints out Cut joint = 16.46' 20:30 - 21:30 1.00 STCTPL P DECOMP Rig down 9 5/8" casing equipment and clean rig floor 21:30 - 23:30 2.00 BOPSU P DECOMP Change upper Rams to VBR, 3 1/2" x 6" 23:30 - 00:00 0.50 BOPSU P DECOMP Pull wear bushing Rig up Test joint and test plug 10/25/2006 00:00 - 01:00 1.00 BOPSU P DECOMP RIH with test plug Rig up test equipment 01:00 - 01:30 0.50 BOPSU P DECOMP Conduct BOP pressure test, test upper Rams Low test to 250 psi, high to 4,000 psi tests held for 5 mins each and recorded Test witnessed by Joey LeBlanc WSTL, Wayne Stout NTP 01:30 - 02:30 1.00 BOPSU P DECOMP Rig down test equipment, pull test plug, run wear bushing 02:30 - 04:30 2.00 CLEAN P DECOMP Load pipe shed with all BHA components Bring all components up beaver slide for scraper run PJSM for picking up BHA 04:30 - 09:30 5.00 CLEAN P DECOMP Pick up Casing Scraper BHA 09:30 - 12:00 2.50 CLEAN P DECOMP RIH with 13 3/8" casing scraper and mills picking up 5" drill pipe 1x1 12:00 - 13:00 1.00 CLEAN N RREP DECOMP Rig Repair -Hydraulic seals leaking on pipe skate ejectors 13:00 - 16:00 3.00 CLEAN P DECOMP RIH with 13 3/8" casing scraper and mills picking up 5" drill pipe 1x1 16:00 - 16:30 0.50 CLEAN P DECOMP RIH with stand of drill pipe out of derrick Wash down and tag 9 5/8" stump ~ 3,759' 25 RPMs ~ 4KfUlbs 350 GPM @ 350 psi PUW=160K, SOW=140K, RTW=155K 16:30 - 18:00 1.50 CLEAN P DECOMP Circulate and Reciprocate Hi Vis Sweep 850 GPM @ 1,690 psi, 25 bbls sweep MW=9.6 ppg, Vis=300+ 5% increase on material at bottoms up MW = 9.6 in and out Monitor well, well static Pump Dry job 18:00 - 19:30 1.50 CLEAN P DECOMP POH to BHA 19:30 - 21:30 2.00 CLEAN P DECOMP Rack back 7 stds 5" HWDP and 3 stds 8" collars 21:30 - 23:00 1.50 CLEAN P DECOMP Lay down rest of BHA, left mills screwed together for milling run 23:00 - 00:00 1.00 EVAL P DECOMP Rig up Schlumberger Wireline Services to run gauge rig, junk basket, Gamma Ray, and casing collar locator 10/26/2006 00:00 - 01:00 1.00 EVAL P DECOMP RIH with gauge rig, junk basket, Gamma Ray, and casing collar locator Collar located at 46' above stump, 3,713' drill pipe depth Set Bottom of EZSV C~3 3,751' drill pipe depth Estimated Bottom of Window ~ 3,740' drill pipe depth Estimated Top of Window C~? 3,716' drill pipe depth 01:00 - 01:30 0.50 EVAL P DECOMP Rig down Schlumberger W ireline Services 01:30 - 02:00 0.50 STWHIP P DECOMP PJSM and bring EZSV and running tool up to the rig floor 02:00 - 02:30 0.50 STWHIP P DECOMP Pickup up EZSV and running tool, Ported sub, and RIH with HWDP out of derrick 02:30 - 05:00 2.50 STWHIP P DECOMP RIH with EZSV on drill pipe out of derrick 05:00 - 05:30 0.50 STWHIP P DECOMP Kelly up and wash from 3,746' to 3756' 125 GPM @ 130 psi PUW=128K, SOW=120K, RTW=125K Printed: 11/13/2006 10:46:09 AM BP EXPLORATION Page 6 of 19 Operations Summary Report Legal Well Name: AGI-10 Common Well Name: AGI-10 Spud Date: 10/28/2006 Event Name: REENTER+COMPLETE Start: 10/16/2006 End: 11/12/2006 Contractor Name: NABOBS ALASKA DRILLING I Rig Release: 11/12/2006 Rig Name: NABOBS 27E Rig Number: Date (From - To Hours Task I Code I NPT I Phase Description of Operations 10/26/2006 ~ 05:00 - 05:30 0.50 ~ STW H I P ~ P 05:30 - 07:30 2.00 STWHIP P 07:30 - 08:30 1.00 STWHIP P 08:30 - 09:00 I 0.501 STWHIPI P 09:00 - 11:30 I 2.501 STWHIPI N 11:30 - 13:30 2.00 STWHIP N 13:30 - 14:00 0.50 STWHIP N 14:00-14:30 0.50 STWHIP N 14:30-15:00 0.50 STWHIP N 15:00 - 17:00 2.00 STWHIP N 17:00 - 18:00 1.00 STWHIP N 18:00 - 19:00 I 1.001 STWHIPI N 19:00 - 21:00 2.00 STWHIP N 21:00 - 21:30 0.50 STWHIP N 21:30 - 22:00 I 0.501 STWHIPI N 22:00 - 22:30 I 0.501 STWHIPI N 22:30 - 23:30 I 1.001 STWHIPI N DECOMP Set EZSVB C~? 3,751' Rotate 36 turns to the right, 12 RPMs ~ 2.OKWIbs Pull up in 10K increments, sheared ~ 53KIbs over pull, 181 Klbs hook load Stacked 20KIbs, EZSVB did not move DECOMP POOH with EZSVB setting tool DECOMP Rig up to test casing to 3,500 psi Pre job safety meeting for pressure test DECOMP Pressure test casing pumped 60 strokes 3,500 psi pressure, plug moved down hole and pressure bleed off to 850 psi Attempt second test, 15 strokes pumped 470 psi, bleed off Attempt third test, 21 strokes pumped 600 psi, bleed off DFAL DECOMP Pick up casing scraper and bit to push EZSVB to bottom and attempt another test DFAL DECOMP RIH with casing scraper and bit on drill pipe out of derrick DFAL DECOMP Kelly up and wash down from 3,676', 250 GPM C~ 250 psi PUW=130K, SOW=122, RTW=125 Tag top of EZSVB ~ 3,757' Stack 45KIbs on EZSVB and hold DFAL DECOMP Attempt to test EZSVB again, 17 strokes pumped 720 psi, bleed off 17 strokes pumped 800 psi, bleed off DFAL DECOMP Monitor well, well static Pump dry job Blow down top drive DFAL DECOMP POH with casing scraper and bit to pick up EZSVB #2 DFAL DECOMP PJSM for laying down BHA Lay down BHA and remove pieces from rig floor DFAL DECOMP PJSM - HACL for picking up EZSVB Make up running tool and EZSVB on bottom of running tool DFAL DECOMP RIH to 3,676' with EZSVB #2 on drill pipe out of derrick DFAL DECOMP PJSM for setting EZSVB and testing casing Rig up to test casing and wash area around EZSVB setting depth Wash from 3,744' to 3,754', 130 GPM ~ 110 psi PUW=128K, SOW=122K Tag stump ~ 3,75T DFAL DECOMP PUW=128K, SOW=120K, RTW=125K Slack off and tag stump ~ 3,757', pick up to up weight plug 6 inches Set EZSVB ~ 3,754' Rotate 36 turns to the right, 10 RPMs ~ 1.5KWIbs Pull up in 10K increments, sheared ~ 50KIbs over pull, 178KIbs hook load Pick up 5', rotate 30 times to the right to reposition shear sleeve in running tool. Stack 50KIbs on EZSVB, EZSVB did not move DFAL DECOMP Pressure test casing to 3,500 psi, charted for 30 minutes 58 strokes pressured up to 3,525 psi Test witnessed by Joey LeBlanc WSTL and Wayne Stout NTP PJSM for pulling out of hole while pressure testing DFAL DECOMP Monitor well, well static Printed: 11/13/2006 10:46:09 AM BP EXPLORATION Operations Summary Report Page 7 of 19 Legal Well Name: AGI-10 Common Well Name: AGI-10 Spud Date: 10/28/2006 Event Name: REENTER+COMPLETE Start: 10/16/2006 End: 11/12/2006 Contractor Name: NABOBS ALASKA DRILLING I Rig Release: 11/12/2006 Rig Name: NABOBS 27E Rig Number: Date I From - To I Mours ; Task I Code I NPT I Phase 10/26/200622:30 - 23:30 1.00' STWHIPIN 23:30 - 00:00 0.50 STWHIP N 10/27/2006 00:00 - 00:30 0.50 STWHIP N 00:30 - 01:30 1.00 STWHIP N 01:30 - 03:30 2.00 STWHIP N 03:30 - 04:00 0.50 STWHIP N 04:00 - 05:00 1.00 STWHIP N 05:00 - 06:00 I 1.001 STWHIPI P 06:00 - 12:30 6.50 STWHIP P 12:30-13:30 1.00 STWHIP P 13:30 - 15:30 2.00 STWHIP P 15:30 - 16:00 0.50 STWHIP P 16:00 - 18:00 2.00 STWHIP P 18:00 - 18:30 I 0.501 STWHIPI P 18:30 - 20:00 I 1.501 STWHIPI P 20:00 - 00:00 I 4.001 STWHIPI P 10/28/2006 100:00 - 04:30 I 4.501 STW H I P I P 04:30 - 05:00 0.501 STWHIP P 05:00 - 06:00 I 1.001 STWHIPI P DFAL ~ DECOMP ~ Pump Dry job Description of Operations Blow down Top Drive DFAL DECOMP POH From 3,754 to 2,630' with EZSVB running tool DFAL DECOMP POH From 2,630' to 1,715' with EZSVB running tool DFAL DECOMP Service Rig -Top drive, drawworks, crown RREP DECOMP Spinners on Iron rough neck failed, Repaied Iron Rough Neck DFAL DECOMP POH From 1,715' to 676' with EZSVB running tool DFAL DECOMP Rack back 7 stands 5" HWDP Lay down ported sub and EZSVB running tool WEXIT PJSM for Whipstock BHA Send EZSVB running tool down beaver slide Bring up subs for milling run WEXIT Pick up BHA, Whip stock, milts, 1 Jnt HWDP, and MWD tools WEXIT Orient and up load to MW D tools WEXIT Pick up BHA, bumper sub, crossovers Run 3 stands of 8" drill collars and 7 stands of 5" HWDP out of derrick WEXIT Shallow hole test MWD tool, test good WEXIT RIH from 1,051' to 3,710' on drill pipe out of derrick 1 - 1.5 minutes per stand WEXIT Orient whipstock to 45 deg right of high side Set whipstock ~ 3,754' Bottom anchor set at 28K weight on bit Pulled 25K over to check anchor Brass pin sheared at 54K weight on bit TOW=3,725', BOW=3,749' WEXIT PJSM for Mud displacement Displace from 9.6 brine to 9.1 LSND 850 GPM 1,400 psi, no rotation, reciprocating pipe 28 bbl Hi Vis spacer 540 bbls of 9.1 ppg 12 PV 22 YP WEXIT Mill Window from 3,725' to 3,732' 700 GPM @ 1,057 psi Torque off bottom 8.OKff/Ibs, on bottom 9-13Kft/Ibs ~ 90 RPMs W 06=3-6KIbs PUW=159K, SOW=145K, RTW=150K Increase yield point, 9.1 ppg 10 PV 28 YP 280 Ibs of metal in returns WEXIT Mill Window from 3,732' to 3,762' 700 GPM C~ 1,170 psi Torque off bottom 5Kft/Ibs, on bottom 6-8Kft/Ibs ~ 90 RPMs W 0B=8-12KIbs PUW=159K, SOW=145K, RTW=150K 300 Ibs of metal in returns Total metal for window 590 Ibs WEXIT Lower Mill out of window, Mill from 3,762' to 3,773' 800 GPM @ 1,530 psi WOB = 20-25KIbs PUW=159K, SOW=145K, RTW=150K 110 Ibs of metal in returns Total metal for window 700 Ibs WEXIT Circulate hole clean for FIT Printed: 11/13/2006 10:46:09 AM BP EXPLORATION Page 8 of 19 Operations Summary Report Legal Well Name: AGI-10 Common Well Name: AGI-10 Spud Date: 10/28/2006 Event Name: REENTER+COMPLETE Start: 10/16/2006 End: 11/12/2006 Contractor Name: NABOBS ALASKA DRILLING I Rig Release: 11/12/2006 Rig Name: NABOBS 27E Rig Number: Date ~ From - To ~ Hours Task Code NPT Phase Description of Operations 10/28/2006 05:00 - 06:00 1.00 STWHIP P WEXIT 25 bbl sweep, 9.2 ppg 75 Vis 850 GPM ~ 1,600 psi 140 Ibs of metal in returns Total metal for window 840 Ibs 06:00 - 06:30 0.50 STWHIP P WEXIT Perform F!T Hole depth 3,773' Shoe depth 3,737' Shoe TVD 3,390' MW 9.1 PP9 Test Pressure 340 psi EMW = 11.0 ppg Charted for 10 minutes 06:30 - 07:30 1.00 STW HIP P WEXIT Pump dry job Blow down top drive Madd Pass to obtain tie in data From 3,773' to 3,600' @ 300'/hr 07:30 - 08:30 1.00 STWHIP P WEXIT POH from 3,773' to 1,051' 08:30 - 09:30 1.00 STWHIP P WEXIT Rack back 7 stands of 5" HWDP in the derrick 09:30 - 10:30 1.00 STWHIP P WEXIT Service Rig, top drive PJSM to lay down BHA 10:30 - 14:30 4.00 STWHIP P WEXIT Lay down BHA, 9 Drill Collars, Bumper Sub, MWD, Crossovers and Mills Upper Mill Full gauge 14:30 - 16:30 2.00 STWHIP P WEXIT Pull wear ring function rams, pump thru kill line, blow thru choke, MU BOP flushing tool and flush metal cuttings out of ram gates. Install wear ring 16:30 - 19:30 3.00 DRILL P INT1 PJSM for picking up BHA Bring all BHA components up to the rig floor Pick up BHA, Motor, Stab, Float, MWD Orient MWD scribe to Motor bend 19:30 - 20:30 1.00 DRILL N SFAL INT1 Upload to MWD, communications failed 20:30 - 22:00 1.50 DRILL N SFAL INT1 Swap out part of MWD tool, Directional Module 22:00 - 23:00 1.00 DRILL P INTi Upload to MWD and orient new Directional Module to Motor bend 23:00 - 00:00 1.00 DRILL P INT1 Pick up 3 Non Mag Flex Drill collars 10/29/2006 00:00 - 01:00 1.00 DRILL P INT1 RIH with 3 stands HWDP Pick up Jars RIH with 4 stands HWDP laying down top single 01:00 - 01:30 0.50 DRILL P INT1 Shallow hole test MWD ~ 805', good test 01:30 - 05:30 4.00 DRILL P INT1 RIH from 805' to 3,462' 1x1 picking up 5" drill pipe out of pipe shed Pick up 2 Ghost Reamers, 993' and 2,982' behind the bit 05:30 - 08:00 2.50 DRILL P INT1 Pre Job Safety meeting on cutting and slipping drilling line Rig Service -Top drive, drawworks, cut and slip drilling line 08:00 - 09:00 1.00 DRILL P INT1 Obtain ECD baseline data on Milling run MW=9.1, PV=15, YP=22, 90 RPMs - 700 GPM ~ 1,170 psi, CECD=8.77 ppg (from model) AECD=9.35 ppg, Correction is a +0.58 Slow pump rates Orient motor, slide through window without any problems 09:00 - 12:00 3.00 DRILL P INTi Drill ahead from 3,773' to 4,031', Sliding 50% to drill curve Printed: 11/13/2006 10:46:09 AM BP EXPLORATION Operations Summary Report Legal Well Name: AGI-10 Common Well Name: AGI-10 Event Name: REENTER+COMPLETE Contractor Name: NABORS ALASKA DRILLING I Rig Name: NABORS 27E Date From - To Hours ~ Task ~ Code NPT Start: 10/16/2006 Rig Release: 11/12/2006 Rig Number: Phase Page 9 of 19 Spud Date: 10/28/2006 End: 11 /12/2006 Description of Operations 10!29/2006 09:00 - 12:00 3.00 DRILL P INT1 650 GPM ~ 1,325 psi off, 1,400 psi on, OECD=9.44, AECD=9.63, MW=9.2 WOB=SK, PUW=150K, SOW=130K, RWT=137K Torque 4K off, 5K on ~ 80 RPMs back ream full stand at drilling rate going up, 70% coming down Noon update ADT=1.48, AST=0.98, ART=0.5 Control drill <300'/hr for MWD logs 12:00 - 15:30 3.50 DRILL P INT1 Drill ahead from 4,031' to 4,430', Sliding 50% to drill curve 700 GPM @ 1,714 psi off, 1,580 psi on, CECD=9.59, AECD=9.81, MW=9.3 WOB=3-5K, PUW=160K, SOW=140K, RWT=148K Torque 4K off, 5-6K on C~ 80 RPMs back ream full stand at drilling rate going up, 70% coming down Problems with MWD signal, Control drill <250'/hr 15:30 - 21:00 5.50 DRILL P INT1 Drill ahead from 4,430' to 5,070', Rotate ahead, slide Ghost reamer #1 out of window @ 4,720' 800 GPM ~ 2,260 psi off, 2,300 psi on, CECD=9.60, AECD=9.79, MW=9.35 W06=3-15K, PUW=165K, SOW=140K, RWT=155K Torque 4K off, 5K on ~ 80 RPMs back ream full stand at drilling rate going up, 70% coming down 4,507' pumped 25 bbl Hi Vis sweep, 9.3 ppg - 300+Vis, No noticeable increase in cuttings Problems with MWD signal, Control drill <200'/hr, tried various flow rates, strokes, staggering strokes, weight on bit, nothing worked unless you drill with less than 4KIbs weight on the bit 21:00 - 00:00 3.00 DRILL P INT1 Drill ahead from 5,070' to 5,260', Rotate ahead 800 GPM @ 2,260 psi off, 2,300 psi on, CECD=9.52, AECD=9.76, MW=9.35 WOB=3-4K, PUW=174K, SOW=149K, RWT=162K Torque 4K off, 5K on @ 80 RPMs back ream full stand at drilling rate going up, 70% coming down Problems with MWD signal, Control drill <5KIbs WOB, still trying different variations on surface parameters but nothing works unless you drill with less than 5KIbs weight on the bit. Midnight update ADT=6.72, AST=0.91, ART=5.81 10/30/2006 00:00 - 01:30 1.50 DRILL P INT1 Drill ahead from 5,260' to 5,363', Rotate ahead 800 GPM ~ 2,260 psi off, 2,300 psi on, CECD=9.52, AECD=9.76, MW=9.35 WOB=3-4K, PUW=174K, SOW=149K, RWT=162K Torque 3K off, 4K on C 80 RPMs back ream full stand at drilling rate going up, 70% coming down Problems with MWD signal getting worse,. Control drill <4KIbs WOB, ROP down to 60'/hr to maintain sync between MWD and surface computer. 01:30 - 02:00 0.50 DRILL P INT1 Communicate to MWD tool and change transmission parameters from Primary mode to Secondary mode. 02:00 - 06:00 4.00 DRILL P INT1 Signal improved, able to increase weight on bit to 10-12KIbs which increased the ROP up to 200'/hr Drill ahead from 5,363' to 5,900', Rotate ahead 800 GPM ~ 2,500 psi off, 2,700 psi on, CECD=9.57, AECD=9.85, MW=9.35 W0B=8-12K, PUW=178K, SOW=155K, RWT=168K Printed: 11/13/2006 10:46:09 AM BP EXPLORATION Page 10 of 19 Operations Summary Report. Legal Well Name: AGI-10 Common W ell Name: AGI-10 Spud Date: 10/28/2006 Event Nam e: REENTE R+COM PLET E Start : 10/16/2006 End: 11/12/2006 Contractor Name: NABOB S ALAS KA DRI LLING I Rig Release: 11/12/2006 Rig Name: NABOB S 27E Rig Number: Date ~ From - To Hours Task (Code NPT Phase Description of Operations 10/30/2006 02:00 - 06:00 4.00 DRILL P INT1 Torque 4.OK off, 6.5K on ~ 80 RPMs back ream full stand at drilling rate going up, 70% coming down Control drill < 300'/hr for logs 06:00 - 12:00 6.00 DRILL P INT1 Drill ahead from 5,900' to 6,500', Correction slides as needed 850 GPM ~ 2,670 psi off, 2,880 psi on, CECD=9.65, AECD=9.81, MW=9.30 W0B=8-12K, PUW=200K, SOW=164K, RWT=176K Torque 5.OK off, 7-8K on ~ 80 RPMs back ream full stand at drilling rate going up, 70% coming down Control drill < 300'/hr for logs Noon Update ADT=7.29, AST=0.35, ART=6.94 12:00 - 00:00 12.00 DRILL P INTi Drill ahead from 6,500' to 7,400', Correction slides as needed 860 GPM ~ 2,850 psi off, 3,000 psi on, CECD=9.65, AECD=9.72, MW=9.30 W06=5-15K, PUW=214K, SOW=169K, RWT=192K Torque 8.OK off, 11.OK on @ 80 RPMs back ream full stand at drilling rate going up, 70% coming down 6,875' pumped 25 bbl Hi Vis sweep, 9.3 ppg - 300+Vis, 25% increase in cuttings 7,367' pumped 25 bbl Weigthed Hi Vis sweep, 11.4 ppg - 300+ Vis, no noticeable increase in cuttings Midnight Update ADT=7.07, AST=3.13, ART=3.94 10/31/2006 00:00 - 12:00 12.00 DRILL P INT1 Drill ahead from 7,400' to 8,025', Correction slides as needed 860 GPM ~ 2,985 psi off, 3,110 psi on, CECD=9.65, AECD=9.68, MW=9.30 W0B=5-15K, PUW=230K, SOW=181 K, RWT=201K Torque 10-11 K off, 11-14K on ~ 80 RPMs back ream full stand at drilling rate going up, 70% coming down 7,925' pumped 25 bbl Hi Vis sweep with 5 sacks of nut plug 9.3 ppg - 200+ Vis, no noticeable increase in cuttings, came back same as calculated strokes indicating a gauge hole Noon Update ADT=8.06, AST=1.99, ART=6.07 12:00 - 00:00 12.00 DRILL P INT1 Drill ahead from 8,025' to 8,600', Correction slides as needed 860 GPM C~3 2,900 psi off, 3,280 psi on, CECD=9.44, AECD=9.73, MW=9.40 WOB=5-15K, PUW=248K, SOW=192K, RWT=212K Torque S.OK off, 14.OK on ~ 80 RPMs back ream full stand at drilling rate going up, 70% coming down Midnight Update ADT=8.78, AST=4.03, ART=4.75 11/1/2006 00:00 - 11:00 11.00 DRILL P INT1 Drill ahead from 8,600' to 9,445', Correction slides as needed 870 GPM ~ 3,266 psi off, 3,570 psi on, CECD=10.0, AECD=10.23, MW=9.9 WOB=10-15K, PUW=260K, SOW=191 K, RWT=216K Torque 11.OK off, 14-16K on ~ 80 RPMs back ream full stand at drilling rate going up, 70% coming down 8,963' start weight up, blend 290 bbls of 12.6 ppg with 400 bbls of 9.4 ppg to increase weight to 9.8 ppg THRZ @ 9,378', drill 67' into HRZ, assume 15-17' to the Top Sadlerochit if the Put River is truncated out 11:00 - 14:00 3.00 DRILL P INT1 Circulate Hi Vis Sweep with nut plug surface to surface, MW=9.9 Vis=300+ 870 GPM ~ 3,250 psi, 80 RPMs ~ 11KfUlbs, reciprocating pipe Printed: 11/13/2006 10:46:09 AM BP EXPLORATION Page 11 of 19 Operations Summary Report Legal Well Name: AGI-10 Common Well Name: AGI-10 Spud Date: 10/28/2006 Event Name: REENTER+COMPLETE Start: 10/16/2006 End: 11/12/2006 Contractor Name: NABOBS ALASKA DRILLING I Rig Release: 11/12/2006 Rig Name: NABOBS 27E Rig Number: i Date From - To i Nours Task Code j NPT ~ Phase Description of Operations -1- _ _--i -- _ -. _ _ - 11/1/2006 11:00 - 14:00 ~ 3.00 DRILL P ~ ~ INT1 ~ Sweep came back 200 strokes over calculated with a 20% 14:00 - 15:00 I 1.001 DRILL I P I I INT1 15:00 - 15:30 I 0.501 DRILL I P I I INT1 15:30 - 16:30 I 1.001 DRILL I P ( I INTi 16:30 - 18:00 I 1.501 DRILL I P I I INT1 18:00 - 21:00 I 3.001 DRILL I P I I INT1 21:00 - 00:00 ~ 3.001 DRILL P I I INT1 11/2/2006 ~ 00:00 - 04:00 ~ 4.00 ~ DRILL ~ P ~ ~ INTi 04:00 - 04:30 0.50 DRILL P INT1 04:30 - 05:30 1.00 DRILL P INT1 05:30 - 06:00 0.50 DRILL P INT1 06:00 - 08:00 2.00 DRILL P INT1 08:00 - 09:00 1.00 DRILL P INT1 09:00 - 10:00 1.00 BOPSU P INT1 10:00 - 13:30 3.50 BOPSU P INT1 13:30 - 14:00 I 0.501 CASE I P I I INT1 14:00 - 17:00 3.00 CASE P INT1 17:00 - 19:00 2.00 CASE N RREP INT1 19:00 - 20:00 1.00 CASE P INT1 20:00 - 20:30 0.50 CASE P INTi 20:30 - 21:30 1.00 CASE P INTi increase in cuttings MW = 9.9 in and out, CECD=10.01 ppg, AECD=10.02 ppg Monitor well, well static POH from 9,445' to 8,393', less than 20K over pulls and hole taking proper fill Pumps down PUW=265K, SOW=195K Monitor well, well static Pump Dry Job POH from 8,393' to 6,593', first Ghost Reamer up in shoe less than 20K over pulls and hole taking proper fill Monitor well, well static RIH from 6,593' to 9,445', hole slick, getting proper displacement for open ended pipe Circulate Hi Vis Sweep surface to surface, MW=9.9 Vis=300+ 870 GPM @ 3,320 psi, 80 RPMs @ 11Kft/Ibs, reciprocating pipe 300% increase in cuttings around 9,000 strokes, enough cuttings (mostly sand and wall cake, some coal) coming back to increase returns flow level triggering a flow show, Driller picked up and sounded BOP alarm. Shakers cleaned up at bottoms up, 20% increase when sweep came back. Circulated an additional bottoms up, shakers clean. MW = 9.9 in and out, CECD=10.01 ppg, AECD=10.19 ppg Monitor well, well static, Pump dry Job POH from 9,445' to 5,500', less than 10K over pulls and hole taking proper fill Pumps down PUW=270K, SOW=190K POH from 5,500' to 805', less than 10K over pulls and hole taking proper fill Rack back 7 stands 5" HWDP with Jars PJSM for handling BHA Lay down 3 - 8" Drill Collars, Drain Motor Down Load data from MWD tool Lay down rest of BHA, MWD, stab, float, motor, and bit Bit graded 2-3-BT-G-X-1-CT-TD Clean and clear rig floor Remove wear ring and install test plug Change upper rams to 9 5/8" Install test joint Test 9 5/8" upper rams and chart for 5 minutes each test Low test to 250 psi, high test to 4,000 psi Test witnessed by Bill Decker WSTL and Dave Hanson NTP Rig down test equipment Dummy run with 9 5/8" hanger/landing joint, RKB to Hanger=30.5' Rig up to run 9 5/8" casing Stabbig board winch motor failed. Remove winch and motor and secure stabbig board. Service Rig, complete securing Stabbing board Pre-Job Safety Meeting on running 9 5/8" casing Make up first 3 joints, baker lock first two connections Break circulation and check floats Printed: 11/13/2006 10:46:09 AM BP EXPLORATION Page 12 of 19 Operations Summary Report Legal Well Name: AGI-10 Common Well Name: AGI-10 Spud Date: 10/28/2006 Event Name: REENTER+COMPLETE Start: 10/16/2006 End: 11/12/2006 Contractor Name: NABOBS ALASKA DRILLING I Rig Release: 11/12/2006 Rig Name: NABOBS 27E Rig Number: Date From - To Hours Task Code NPT Phase 11/2/2006 21:30 - 22:00 0.50 CASE P INT1 22:00 - 00:00 2.00 CASE N SFAL INT1 11/3/2006 100:00 - 02:30 I 2.501 CASE I N I SFAL I INTi 02:30 - 10:30 I 8.001 CASE I P I I INT1 10:30 - 12:00 1.501 CASE P ~ INT1 12:00 - 00:00 I 12.001 CASE I P I I INT1 11/4/2006 100:00 - 03:00 I 3.001 CASE I P I I INT1 03:00 - 04:30 I 1.501 CASE I P ! I INT1 Description of Operations RIH from 123' to 247' Torque turn each connection Joint #6 to #7 high shouldered Rig up back up tongs Break torque on connection, back out 2 turns Torque turn connection second time, high shoulder Back joint all the way out and check collar and pin, burrs on both Lay down Joint and change collar Remove collar on Joint 6, joint egg shaped Pull Joint 6 and lay down Clean box, pick up replacement for joint 6 Torque turn replacement joint 6, high shoulder Break connection, back out 2 turns Torque turn replacement joint # 6 second time, high shoulder Back connection all the way out, clean box and pin, torque turn for the third time, passed RIH from 245' to 3,718', averaging running speed 0.75 min/joint 1x1 picking up 9 5/8" casing out of pipe shed, filling every joint record pick up and slack off weights every 15 joint Circulate 1.5 bottoms up, 3,328 strokes BPM Ret psi 5.0 43% 300 6.0 46% 345 7.0 50% 400 8.0 53% 460 Calculated displacement 64 bbls, actual displacement 47 bbls RIH from 3,718' to 8,910', averaging 1.5-2.0 minutes per joint in open hole 1x1 picking up 9 5/8" casing out of pipe shed, filling every joint record pick up and slack off weights every 15 joints Circulate 10 minutes on Joints 106, 139, 187, and 229 Std BPM psi CDisp ADisp 106 4.5 195 73bb1 54bb1 139 5.0 220 96bb1 79bb1 187 4.0 170 130bb1 119bb1 Casing drag tracking model, up weights below the 0.35 FF, down weights tracking right on 0.35 FF. RIH from 8,910' to 9,439, averaging 1.5-2.0 minutes per joint in open hole 1x1 picking up 9 5/8" casing out of pipe shed, filling every joint record pick up and slack off weights every 15 joints Circulate 10 minutes on stand 229 Std BPM psi CDisp ADisp 229 4.0 430 159bb1 147bb1 Casing drag tracking model, up weights below the 0.35 FF, down weights tracking right on 0.35 FF. Circulate bottoms up through franks tool, 5,370 strokes Stage pumps up to 8.0 bbls/min BPM PSI Ret 4.5 466 44% 5.0 482 45% 6.0 520 47% Printed: 11/13/2006 10:46:09 AM BP EXPLORATION Page 13 of 19 Operations Summary Report Legal Well Name: AGI-10 Common Well Name: AGI-10 Event Name: REENTER+COMPLETE Contractor Name: NABOBS ALASKA DRILLING Rig Name: NABOBS 27E Date ~ From - To I Hours ; Task I Code I NPT ------ 11/4/2006 103:00 - 04:30 1.501 CASE ~ P 04:30 - 05:30 1.00 CEMT P 05:30 - 07:00 1.50 CEMT P 07:00 - 11:30 I 4.501 CEMT I P 11:30 - 16:30 I 5.001 CEMT I P 17:30 - 19:30 2.00 BOPSUR P 19:30 - 00:00 I 4.501 BOPSUFi P Spud Date: 10/28/2006 Start: 10/16/2006 End: 11 /12/2006 I Rig Release: 11/12/2006 Rig Number: Phase j Description of Operations INT1 7.0 660 50% 8.0 670 53% INT1 Rig up cement head INTi Circulate through cement head to condition mud 8.0 bpm ~ 650 psi, circulate 2 bottoms up yield point down to 16 in and out PUW=465K, SOW=270K Full returns with no losses while circulating. Held Pre-job safety meeting for cementing INT1 Pressure test cement lines to 4,500 psi Pump 60 bbls of MudPUSH II ~ 10.6 ppg 5 BPM ~ 420 psi Drop bottom plug, positive indication plug left Pump 208 bbls of LiteCRETE Lead ~ 11.6 ppg average, started out 12.0 ppg but could not maintain, plugged up batch mixer 3 times during cement job trying to maintain 12.0 ppg. Shut down for a total of 56 minutes during lead slurry. 5.5 BPM ~ 300 psi Pump 127 bbls of Class G tail C~ 15.8 ppg 5.3 BPM @ 350 psi kick top plug out, positive indication plug left cement head Switch over to rig and displace cement as per Schlumberger pumping schedule. 3,850 strokes to catch cement 11 BPM ~ 590 psi 4,300 strokes drag increasing, park mandrel hanger for rest of cement job 8.0 BPM @ 550 psi 6,956 strokes to bump the plug, bumped plug with 1,700 psi Held for 5 minutes, release pressure and floats held Full returns throughout cement job, no losses to well. INTi Rig down Cement head Close annular and pump down the 13 3/8" x 9 5/8" OA Rate Strokes PSI 2 BPM 100 760 Break down 2 BPM 150 600 Inject in annulus Lay down Landing joint Clean and Clear rig floor of unneeded subs Drain stack, clean pits, install new iron rough neck track INT1 Instali 9 5/8" pack off and test to 5000 psi INTi Change out top rams from 9 5/8" to 5" Install bails and elevators install test plug and test joint rig up BOP test equipment INT1 Test BOPs BOP test witnessed by Joey LeBlanc WSTL, Dave Richards NTP, John Crisp AOGCC Low test pressure 250 psi, High test pressure 4,000 psi #1 Annular #2 Upper Well Control Valve, Top Pipe Rams, choke 1, 2, Kill HCR #3 Choke 3,4,5,6, Manual Kiil, Lower Well Control Valve #4 Choke 7,8,9, TIW #5 Choke 10,11,12 Valve #10 leaked, cycled valve and passed test #6 Choke 13,14,15, 16 #7 Manual Choke Printed: 11/13/2006 10:46:09 AM r BP EXPLORATION Page 14 of 1 s Operations Summary Report Legal Well Name: AGI-10 Common W ell Name: AGI-10 Spud Date: 10/28/2006 Event Nam e: REENTE R+COM PLET E Start : 10/16/2006 End: 11/12/2006 Contractor Name: NABOB S ALASK A DRI LLING I Rig Release: 11/12/2006 Rig Name: NABOB S 27E Rig Number: ate From - To Hours Task Code, NPT Phase ~ Description of Operations 11/4/2006 19:30 - 00:00 4.50 BOPSU P INT1 #8 Choke HCR Accumulator test 1,700 psi after functioning all valves, 25 sec for 200 psi, 2 min 4 sec for full recovery to 3,100 psi Average charge for 8 bottles of Nitrogen is 2,325 psi #9 Lower Pipe Rams and Dart Valve Pump down annulus Time BPM PSI Strokes 20;00 2.5 780 100 22:30 2.5 730 50 11/5/2006 00:00 - 00:30 0.50 BOPSU P INT1 Test BOPs BOP test witnessed by Joey LeBlanc WSTL, Dave Richards NTP, John Crisp AOGCC Low test pressure 250 psi, High test pressure 4,000 psi #10 Blind Rams Pump down annulus Time BPM PSI Strokes 00:15 2.5 750 65 00:30 - 01:00 0.50 BOPSU P INT1 Rig down test equipment Pull test plug install wear ring 01:00 - 02:00 1.00 DRILL P PROD1 Bring all subs and MW D for BHA up to rig floor Pre Job Safety meeting for picking up BHA 02:00 - 05:00 3.00 DRILL P PROD1 Pick up BHA -Rock Bit, Motor, Stab, MWD, and 3-Drill Collars Orient and up load MWD RIH with 7 stands of HWDP/Jars out of derrick Simops Little Red Services pumping 135 bbls of dead crude down 13 3/8" x 9 5/8" OA to freeze protect BPM bbls psi 2.0 0 630 2.0 25 600 2.0 75 700 2.0 135 900 05:00 - 05:30 0.50 DRILL P PROD1 Shallow hole test MWD 550 GPM ~ 1,620 psi 05:30 - 09:30 4.00 DRILL P PROD1 RIH with 5" drill pipe out of derrick from 791' to 8,369' filling pipe every 3,000' 09:30 - 11:30 2.00 DRILL P PROD1 Pre-Job safety meeting Stripping Drill crew, toolpusher, and WSTL 11:30 - 13:30 2.00 DRILL P PROD1 RIH with 5" drill pipe out of derrick from 8,369' to 9,357', tag float collar 13:30 - 14:30 1.00 CASE P PROD1 Casing test to 4,000 psi 25 stks 943 psi 50 stks 1,605 psi 75 stks 3,340 psi 90 stks 4,100 psi Charted for 30 minutes, 50 psi pressure loss over 30 minutes 14:30 - 15:30 1.00 DRILL P PROD1 Drill Cement from 9,357' to 9,445' 60 RPMs C~ 12-14 Kft/Ibs 550 GPM @ 2,487 psi W 06=20KIbs 15:30 - 17:00 1.50 DRILL P PROD1 Displace mud to FloPro system Printed: 11/13/2006 10:46:09 AM BP EXPLORATION Page 15 of 19 Operations Summary Report Legal Well Name: AGI-10 Common Well Name: AGI-10 Spud Date: 10/28/2006 Event Name: REENTER+COMPLETE Start: 10/16/2006 End: 11/12/2006 Contractor Name: NABOBS ALASKA DRILLING I Rig Release: 11/12/2006 Rig Name: NABOBS 27E Rig Number: Date From - To Hours Task i Code NPT Phase i Description of Operations 11/5/2006 15:30 - 17:00 1.50 DRILL P PROD1 25 bbl hi vis spacer MW=8.55 ppg 530 GPM @ 2,430 psi 17:00 - 18:00 1.00 DRILL P PROD1 Drill from 9,445' to 9,475', Rotate 30' of new hole to perform FIT 550GPM ~ 1,650 psi off, 1,770 psi on bottom W06=14-19K, Tq 5K off, 6.2K on @ 80 RPMs PUW=230K, SOW=193K, RWT=210K 18:00 - 00:00 6.00 DRILL P PROD1 Circulate and condition mud well static, mud aerated in suction pit, lost 200 psi of pressure then MWD turning off, pumps sucking air, kelly hose jumping Weight up to 8.6, add defoamer and screen clean gas never exceeded 269 units 11/6/2006 00:00 - 00:30 0.50 DRILL P PROD1 Circulate and condition mud well static, increase of 200 psi pressure then MWD turned on, add screen clean MW= 8.6 in and out 00:30 - 01:00 0.50 DRILL P PROD1 Hold Pre-Job Safety Meeting -Preform FIT To 10.0 PPG EMW Closed Top Pipe Rams And Performed FIT. Strokes Pmp'd Pressure 5 50 psi 10 200 psi 15 400 psi 20 600 psi Held Test for 10 minutes with 20 Psi. Pressure Loss. MW 8.6 ppg, Shoe ND 7,982' Pressure 600 psi = 10.05 PPG. EMW. Bleed Pressure To 0 Psi. -Open Top Pipe Rams 01:00 - 01:45 0.75 DRILL P PROD1 Obtain ECD baseline data MW=8.6, PV=6, YP=19, 0 RPMs - 600 GPM @ 2,135 psi, CECD=9.22 (from model), AECD=9.25 100 RPMs - 600 GPM ~ 2097 psi, CECD=9.22 (from model), AECD=9.27 Drill as per DD from 9,475' to 9,505' 650GPM @ 2,100 psi off, 2,180 psi on bottom WOB=10K, Tq 5.3K off, 7.OK on C~ 100 RPMs PUW=240K, SOW=200K, RWT=220K 01:45 - 02:30 0.75 DRILL P PROD1 Gas increasing to 2,000 units Stop drilling and check for flow, well static MW going in, 8.7 pressurized, 7.8 non pressurized MW coming out, 8.7 pressurized, 8.1 non pressurized Go back to drilling, drill from 9,505' to 9,507' Gas increasing to 4,500 units Stop drilling and check for flow, well static 02:30 - 04:30 2.00 DRILL P PROD1 Increase MW from 8.7 to 8.8 ppg Monitor well, well static MW 8.8 in and out pressurized Gas 200 units Go back to drilling 04:30 - 05:00 0.50 DRILL P PROD1 Drill as per DD from 9,507' to 9,548' 625GPM ~ 2,140 psi off, 2,240 psi on bottom mud still aerated from hopper, trouble with MW D turning off Printed: 11/13/2006 10:46:09 AM BP EXPLORATION Page 16 of 19 Operations Summary Report Legal Well Name: AGI-10 Common Well Name: AGI-10 Spud Date: 10/28/2006 Event Name: REENTER+COMPLETE Start: 10/16/2006 End: 11/12/2006 Contractor Name: NABORS ALASKA DRILLING I Rig Release: 11/12/2006 Rig Name: NABORS 27E Rig Number: Date ~ From - To Hours ~ Task I Code I NPT Phase ~ I 11/6/2006 04:30 - 05:00 0.50 DRILL P PROD1 05:00 - 06:00 1.00 DRILL N DFAL PROD1 06:00 - 06:30 ~ 0.501 DRILL N I DFAL ~ PROD1 06:30 - 10:30 4.00 DRILL N DFAL PROD1 10:30 - 12:00 1.50 DRILL N DFAL PROD1 12:00 - 16:00 I 4.001 DRILL I N I DFAL I PROD1 16:00 - 20:30 4.50 DRILL N DFAL PRODi 20:30 - 22:30 2.00 DRILL P PROD1 22:30 - 00:00 I 1.501 DRILL I P I I PROD1 11/7/2006 ~ 00:00 - 05:30 ~ 5.50 ~ DRILL ~ P ~ ~ PROD1 05:30 - 11:30 I 6.001 DRILL I N I HMAN I PROD1 Description of Operations WOB=10K, Tq 7.5K off, 9.5K on ~ 100 RPMs PUW=240K, SOW=200K, RWT=220K MWD not turning on, tried multiple flow rates, switched modes, added more ScreenKleen to system, MW D would not stay on - Determined this is not a mud problem, tool failure MW = 8.8 ppg in and out CECD=9.21 ppg, AECD=9.37 ppg POH from 9,548' to 9,319' Monitor well while building dry job, well static PJSM for pulling out of hole Pump dry job POH from 9,319' to 791' PJSM for handling BHA Rack back 7 stands of HWDP Rack back collar stand Change out MWD Orient to motor Upload to MWD RIH with collar stand and 1 stand 5" HWDP Shallow hole test MWD, test good RIH with rest of 5" HWDP RIH from 791' to 9,319' on drill pipe out of derrick Fill pipe every 3,000' and pulse test MWD Cut and slip drilling line, inspect brakes Rig service -Lubricate Rig, Top drive, drawworks, and install blower hose Obtain ECD baseline data MW=8.9, PV=5, YP=20, 0 RPMs - 600 GPM ~ 2,030 psi, CECD=9.20 (from model), AECD=9.34 100 RPMs - 600 GPM ~ 2030 psi, CECD=9.20 (from model), AECD=9.36 Drill as per DD from 9,548' to 9,584' 600GPM @ 2,070 psi off, 2,200 psi on bottom WOB=10K, Tq 7.OK off, 10.OK on C 100 RPMs PUW=235K, SOW=196K, RWT=218K 11:50 Flow increased by 10%, stop and check for flow, gas present but well static, trip gas from bottoms up, mud loggers registered 300 units of gas Drill as per DD from 9,584' to 9,823' 600GPM ~ 2,000 psi off, 2,100 psi on bottom W06=10-25K, Tq 7.5K off, 10.5K on ~ 100 RPMs PUW=245K, SOW=202K, RWT=218K Back ream full stand, drilling rate going up, 70% coming down 01:10 Flow increase by 4%, stop and check for flow, well static, mud loggers registered 450 units of gas Mud weight had come up from 8.8 ppg. to 9 ppg. with no remedial action taken until night WSL directed pit watcher & night mud man to start adding water. We drilled ahead with the 9 ppg mud to 9823' where the wellbore started taking mud C~ 80 bbls/hr, -reduced flow rate to 450 GPM, Slowed losses to 60 bbls/hr, -stop drilling, decrease flow to 350 GPM and mix 80 bbl LCM Printed: 11/13/2006 10:46:09 AM a ~ BP EXPLORATION Page 17 of 19 Operations Summary Report Legal Well Name: AGI-10 Common Well Name: AGI-10 Spud Date: 10/28/2006 Event Name: REENTER+COMPLETE Start: 10/16/2006 End: 11/12/2006 Contractor Name: NABORS ALASKA DRILLING I Rig Release: 11/12/2006 Rig Name: NABORS 27E Rig Number: ~ Date From - To Hours Task Code NPT Phase Description of Operations 11/7/2006 05:30 - 11:30 6.00 DRILL N HMAN PROD1 pill, losses slowed to 40 bbl/hr -Spot LCM pill & POH to shoe @ 9430, Rate of Mud loss down to 10 bbl/hr -Circulated & condition mud to 8.8 ppg in /out RIH to 9854', no problems RIH 11:30 - 13:30 2.00 DRILL P PROD1 Drill from 9,823'to TD ~ 9937' (8394' tvd) 475 GPM @ 1300 psi off, 1400 psi on bottom WOB=25K, Tq 6K off, 8K on ~ 100 RPMs PUW=250K, SOW=200K, RWT=220K Mud Loss ~ 28 bbl/hr TD fp? 13:30 hrs 13:30 - 15:30 2.00 DRILL P PROD1 Circulate 27 bbl Hi-Vis /LCM pill ~ 650 gpm & 100 rpm to clean hole -180 vis, 8.8 ppg, -shakers showed 100% cutting incresed when sweep returned CBU C~ 475 gpm for 1x Bottoms up 15:30 - 20:00 4.50 DRILL P PROD1 POH to shoe, pump slug & drop drift, blow down top drive, POH to HWDP 20:00 - 21:30 1.50 DRILL P PROD1 Lay down 11 HWDP,Jars and flex DC's 21:30 - 22:30 1.00 DRILL P PROD1 Download recorded data from HES MWD/LWD 22:30 - 00:00 1.50 DRILL P PROD1 Lay down MWD, LWD, stab, Break bit and UD Mud motor 11/8/2006 00:00 - 01:30 1.50 CASE P LNR1 PJSM, Clear floor and rig up 7" casing handling equip 01:30 - 04:00 2.50 CASE P LNR1 P/U 13 jts of 7" 26# production liner -9 joints of Perforated liner, 2 joints of slotted liner, 2 joints of solid liner plus 1- 20' solid Pup Joint - Total 551.69' of liner P/U Make up Baker liner hanger and packer RIH with 1 stand of 5" DP Circ @ 3 bpm / 70 psi, Liner hanging wt = 16k 04:00 - 10:00 6.00 CASE P LNR1 RIH with 7" Production liner break circ. every 2000 ft. 10:00 - 10:30 0.50 CASE P LNR1 Circ. DP volume ~ 6 bpm / 790 psi PUW = 225 /SOW = 190k 10:30 - 13:30 3.00 CASE P LNR1 Run 7" into open hole, tag ~ 9937', Pick up to 9935' Fill DP, Drop ball to set hanger & packer circ. ball down to packer ~ 6 bpm // 790 psi, slowed to 2 bpm and seat ball set packer as per BOT representive, test backside to 1500 psi f/ 15 min.O.K. Pull out of packer 13:30 - 16:30 3.00 CASE P LNR1 Displace flo-pro mud with 8.8 ppg brine 10 bpm / 500 psi Clean shakers & surface equipment 16:30 - 00:00 7.50 CASE P LNR1 Lay down 5" Drill pipe Brine loss to formation C~J 10 bbl / hr 11/9/2006 00:00 - 02:30 2.50 CASE P LNR1 UD 5" DP and 7" C-2 hyd. running tool 02:30 - 03:00 0.50 BOPSU P OTHCMP Clear floor and have PJSM on changing Pipe Rams 03:00 - 05:00 2.00 BOPSU P OTHCMP Change out upper set of rams to 7 5/8" Monitor well during change out operations Circulated through kill Tine to the gasbuster with the blind rams closed 05:00 - 05:30 0.50 BOPSU P OTHCMP Pulled wear bushing and set test joint, R/U test equip. Printed: 11/13/2006 10:46:09 AM BP EXPLORATION Operations Summary Report. Legal Well Name: AGI-10 Common Well Name: AGI-10 Event Name: REENTER+COMPLETE Contractor Name: NABOBS ALASKA DRILLING Rig Name: NABOBS 27E Date From - To Hours Task Cade NPT 11/9/2006 05:30 - 07:00 1.50 BOPSU P 07:00 - 07:30 0.50 BOPSU P 07:30 - 08:30 1.00 EVAL P 08:30 - 10:00 1.50 EVAL N WAIT 10:00 - 16:30 .6.50 EVAL P 16:30 - 17:00 17:00 - 19:00 19:00 - 19:30 19:30 - 00:00 Page 18 of 19 Spud Date: 10/28/2006 Start: 10/16/2006 End: 11 /12/2006 I Rig Release: 11 /12/2006 Rig Number: Phase ~ Description of Operations OTHCMP Conduct BOPE pressure test on upper rams with 7 5/8" test joint 250 low / 4000 high for 5 minutes Witness by Bill Decker (BP WSL), Jim Henson (NAD Toolpusher) OTHCMP Pulled test joint and set wear bushing for logging operations OTHCMP Cleared floor and service rig -Inspected iron roughneck for cracks and wear OTHCMP Wait on SWS to arrived Clean out under rig floor and suck solids out of drip pan OTHCMP PJSM, Rig up SWS and E-line log Run CBL & USIT log R/D SWS Circulated across top of hole to monitor losses 0.50 BUNCO RUNCMP Pulled wear bushing 2.00 BUNCO RUNCMP Rig up to run 7 5/8" tubing completion M/U landing joint to hanger 0.501 RU 4.501 RU RUNCMP PJSM on running 7 x 7 5/8 completion tubing *BOT and Vam reps. In Attendance at meeting RUNCMP M/U, Mule shoe, 7" "RN" nipple, 7 x 9 5/8" Baker S-3 Packer, 7" "R" Hippie *RIH with 45 Jts. of 29.7# 7 5/8" VAM TOP HC Tubing RUNCMP RIH with 174 jts (224 jts total) Completion Tubing- 29.7# / 7 5/8" VAM TOP HC Tubing RUNCMP RIH and Tag ~ 22' in on jt #225, -Rt. 180 deg. and RIH, tag tie-back ~ 32' in on Jt #225, -UD jt #225, M/U 5" DP & XO to Top Drive, Wash down ~ 3 bpm / 100 psi - Tag @ same depth UD 5" DP & Jt #224 RUNCMP Space Out Tubing -UD jt #223 - P/U 19.9' Pup, 9.93' Pup & 5.53 Pup jt -M/U Jt #223 Tubing PUW = 300k / 210k SOW 11/10/2006 00:00 - 12:00 12.00 RU 12:00 - 14:00 2.00 RU 14:00 - 16:30 2.50 RU 16:30 - 18:00 1.50 RU 18:00 - 19:00 1.00 RU 19:00 - 21:00 RUNCMP Make up Tubing Hanger and Landing Joint, RIH and Rotate into tie-back recepticle and Land Tubing at depth Run Lock Down Screws as per FMC RUNCMP PJSM, R/U to Reverse Circ. Pump 30 bbls of Corrosion Inhibited brineinto IA ~ 3bbl/min / 260 psi ICP - 480 FCP Pump 36 bbl of Diesel ~ 3 bbl /min 110 psi ICP - 575 FCP (pumped with Little Red Services) 2.00 BUNCO RUNCMP Drop Ball & Rod, and Set Packer -Test Tubing to 4000 psi for 30 min. -chart test Bleed Tubing off to 2000 psi, Pressure up on 7 5/8 x 9 5/8 annulus to 4000 psi for 30 min - Printed: 71/13/2006 10:46:09 AM BP EXPLORATION Operations Summary Report Legal Well Name: AGI-10 Common Well Name: AGI-10 Event Name: REENTER+COMPLETE Start: 10/16/2006 Contractor Name: NABOBS ALASKA DRILLING I Rig Release: 11/12/2006 Rig Name: NABOBS 27E Rig Number: Date I From - To 11/10/2006 19:00 - 21:00 21:00 - 21:30 21:30 - 22:30 22:30 - 00:00 11 /11 /2006 100:00 - 02:00 02:00 - 06:30 06:30 - 10:00 10:00 - 11:30 11:30 - 13:30 13:30 - 16:30 16:30 - 18:30 18:30 - 19:30 19:30 - 20:00 20:00 - 20:30 20:30 - 00:00 11/12/2006 00:00 - 01:00 01:00 - 02:30 02:30 - 03:30 03:30 - 05:00 Hours Task Code NPT Phase 2.00 RUNCMP ~ chart test Page 19 of 19 Spud Date: 10/28/2006 End: 11 /12/2006 Description of Operations 0.50 BOPSU P RUNCMP PJSM on Setting TWC and changing upper pipe rams 1.00 BOPSU P RUNCMP Set TWC and test to 1000 psi, good test 1.50 BOPSU P RUNCMP Blow Down Mud and services lines R/U and suck out BOP stack R/U to Change Rams 2.00 BOPSU P RUNCMP Change out upper pipe rams, replaced 7 5/8" rams w/ 3 x 6 variables rams 4.50 BOPSU P RUNCMP N/D Flowline and riser, turnbuckles, drip pan, choke and kill lines and Set back BOP stack & secure on pedestal 3.50 WHSUR P RUNCMP Nipple up tree *Tested Tubing hanger to 5000 psi for 15 min., Passed test 1.50 WHSUR P RUNCMP R/U and test Tree & Adaptor flange Unable to test, fluid leaking past TWC (~ 1500 psi 2.00 WHSUR N SFAL RUNCMP Mobilize DSM to change out TWC 3.00 WHSUR N SFAL RUNCMP PJSM w/ DSM personel, Lubricate TWC out - 1500 psi on back side -set new TWC and R/D Lubricator 2.00 W HSUR P RUNCMP PJSM -Test Double valve tree with test pump, unable to pump over 1500 psi R/U Little Red and pressure up to 5000 psi Test for 5min. ,test pass 1.00 WHSUR N WAIT RUNCMP Wait on DSM to crew change 0.50 WHSUR P RUNCMP Lubricate TWC out - TWC had 1100 psi on back side 0.50 W HSUR P RUNCMP Bleed 1100 psi off of tubing to bleed tank, Fluid with minimal gas *Bleed to zero, monitored for pressure build up 3.50 BUNCO RUNCMP PJSM with SWS slick line - R/U slick line, BOPs and extensions on top of Tree, - Surface test Slick line equip. to 3500 psi f/5min - RIH and Latched on to Bali & Rod ~ 9343 - POH with Slick line and R/D Slick line unit and BOP's 1.00 WHSUR P RUNCMP PJSM - R/D SWS slick tine unit and clear equip from Rig floor 1.50 WHSUR P RUNCMP PJSM - w/ Little Red Services -R/U and test Little Red surface lines and equipment -Tested to 3000 psi for 5min. Pump 100 bbls of diesel down 7 5/8" tubing (2200' of Diesel) Bullheaded C~3 2.5 bbl/min 150 psi R/D LRS and circ. manifold 1.00 WHSUR P RUNCMP PJSM - w/ DSM R/U DSM lubricator Lubricate BPV in with DSM R/D DSM 1.50 WHSUR P RUNCMP Secure Well Final pressure on OA = 75 psi, IA- 25 psi and zero on tubing Release Rig @ 05:00 11-12-2006 Printed: 11/13/2006 10:46:09 AM WELLHEAD= FMC ACTUATOR = KB. ELEV = 46.5 BF. ELEV = 16 KOP = 3725 Max Angle = 40 @ 3777' Datum MD -. Datum TV D = ?~??? ~ AGI-10A DRLG DRAFT Minimum ID = 5.770" @ 9344' 7" HES RN NIPPLE 13-3/8"whipstock. Window cut 3725' - 3749'. 13-3/8" Whipstock 3754' ~13-3/8" ¢SVB~ 3754' TOP OF 9 5/8" 3760' 13-3/8" CSG, 68#, L-80, ID = 12.415" 3846' 9 5/8" ¢SV 4090' Top of 7" 4500' 7" EZSV -5000' TOP OF 7" LNR 9409' 9-5/8" CSG, 47#, NT-80-S, ID = 8.681" 9661' PERFORATION SUMMARY REF LOG: BHCS 03/28/93 ANGLE AT TOP PERF: 37 @ 9860' Note: Refer to Production DB for historical perf data SIZE SPF INTERVAL Opn/Sqz DATE 1" 18 9564 - 9933 O 11/07/06 Slotted 9485 - 9564 O 11/07/06 7" LNR, 29#, L-80, .0371 bpf, ID = 6.184" 10251' 9933' 7" 26# L-80 Slotted PBTD 9937' 7" 26# TD DATE REV BY COMMENTS DATE REV BY COMMENTS 04!01193 Original Completion 05/23/01 RWKAK Corrections 03/18/03 AS/TLH Add IPC and thread for tubing 11/11/06 BD FINAL after Sidetrack 11/15/06 DAV/TL CORRECTIONS 11/24!06 CJWPAG LANDING NIP CORRECTION PRUDHOE BAY UNfT WELL: AGI-10A PERMIT No: 206135 API No: 50-029-22353-01 SEC 36, T12N, R14E, 2808.63' FEL & 5240.67' FNL BP Exploration (Alaska) SAFETY NOTES: 2163' 7 5/8" x 7" XO 2174' 7 CAMCO DB LANDING NIP, ID = 6.0" TG II TO V A M TOP HC X-OVER 2185' 7" x 7 5/8" XO 7 5/8" TBG, 29.7#, L-80-IPC, VAM TOP HC, ID = 6.875", 0.04591 BBL/FT 9282' -~ 7 5/8" x 7" XO i 9293' 7" R Nipple, ID = 5.963" 9317' 9 5/8" x 7" BKR S-3 PKR, ID 6.0" 9344' 7" RN Nipple, ID = 5.770" 7" HMC Liner hanger/ ZXP 9359' Packer w/ 10' TBS (7.5" ID) 26# BTC 9366' 7" WLEG 9439' ( I TG II, ID = 8.681 ", 0.07321 BBL/FT BP EXPLORATION Page 1 ofi 1 Leak-Off Test Summary Legal Name: AGI-10 Common Name: AGI-10 Test Date Test Type Test Depth (TMD) Test Depth (TVD) AMW ~ Surface Pressure ~ Leak Off Pressure (BHP) EMW 10/28/2006 FIT 3,737.0 (ft) 3,390.0 (ft) 9.10 (ppg) 340 (psi) 1,943 (psi) 11.03 (ppg) 11/6/2006 FIT 9,439.0 (ft) 7,982.0 (ft) 8.60 (ppg) 600 (psi) 4,166 (psi) 10.05 (ppg) Printed: 11/13/2006 10:48:00 AM ~alliburton Company Survey Report Comp~m~~: BP Amoco ~ Date 11 ~20i~006 finre: 10:43 58 Pa~;c 1 I~icld: Prudhoe Ba y (various) Cu-urdmatciAF i Kefcrencr. We ll: ACI 1Q TPUB North Site: AGI VerUa~l (1 VU~ Itefer eiuc AG I-10A. ~i 46.5 (AGI-10.) 46.5 ~ I 11'dl: AGI-10 Sertiou (~'S) Nc[crence: We ll (O.OON,O.OOE62.80Azi) ~~'cllpath: AGI-10A Sune} Ctilcul:~tion Method: Min imum Curvature Db: Orade Field: Prudhoe Bay (various) Map System:US State Plane Coordinate System 19 27 Map Zone: Alaska, Zone 4 Geo Datum: NAD27 (C larke 1866) Coordinate System: Well Centre Sys Datum: Mean Sea Level Geomagnetic Model: bggm2006 Well: AGI-10 Slot Name: AGI-10 Well Position: +N/-S 6901.07 ft Northing: 5980281.94 ft Latitude: 70 21 3.130 N +E1-W 3850.84 ft Easting : 688686.10 ft Longitude: 148 28 4.511 W Position Uncertainty: 0.00 ft Wellpath: AGI-10A Drilled From: AGI-1 0 500292235301 Tie-on Depth: 3711.13 ft Current Datum: AGI-10A: @ 46.5 (AGI-10:) Height 46.50 ft Above System Datum: Mean Sea Level Magnetic Data: 10/23/2006 Declination: 24.30 deg Field Strength: 57662 nT Mag Dip Angle: 80.97 deg Vertical Section: Depth From (TVD) +N/-S +E/-W Direction ft ft ft deg 32.90 0.00 0.00 62.80 Survey Program for Definitive Wellpath Date: 11/20/2006 Validated: No Version: 6 Actual From To Survey Toolcode Tool Name ft ft 48.10 3711.13 1 : Schlumberger GCT multishot GCT-MS Schlumberger GCT multishot 3725.00 9882.28 AGI-10A (3725 .00-9882.28) MWD+IFR+MS MWD +IFR + Multi Station Survey MD Incl Azim TVD Sys TVD N/S h7~1' MapN MapE Tool ft deg deg ft ft ft tt ft ft 32.90 0.00 0.00 32.90 -13.60 0.00 0.00 5980281.94 688686.10 TIE LINE 48.10 0.22 142.90 48.10 1.60 -0.02 0.02 5980281.92 688686.12 GCT-MS 51.09 0.21 123.29 51.09 4.59 -0.03 0.03 5980281.91 688686.13 GCT-MS 65.58 0.20 114.49 65.58 19.08 -0.06 0.07 5980281.89 688686.17 GCT-MS 81.53 0.22 116.27 81.53 35.03 -0.08 0.12 5980281.86 688686.23 GCT-MS 98.21 0.22 112.56 98.21 51.71 -0.11 0.18 5980281.84 688686.28 GCT-MS 114.96 0.21 109.62 114.96 68.46 -0.13 0.24 5980281.82 688686.34 GCT-MS 129.93 0.20 107.47 129.93 83.43 -0.15 0.29 5980281.80 688686.39 GCT-MS 146.36 0.19 109.90 146.36 99.86 -0.17 0.34 5980281.78 688686.45 GCT-MS 163.17 0.15 112.81 163.17 116.67 -0.18 0.39 5980281.77 688686.50 GCT-MS 180.06 0.13 121.65 180.06 133.56 -0.20 0.43 5980281.75 688686.53 GCT-MS 196.86 0.14 135.57 196.86 150.36 -0.23 0.46 5980281.73 688686.56 GCT-MS 213.59 0.15 146.00 213.59 167.09 -0.26 0.48 5980281.69 688686.59 GCT-MS 230.27 0.17 148.66 230.27 183.77 -0.30 0.51 5980281.65 688686.62 GCT-MS 246.96 0.18 149.40 246.96 200.46 -0.34 0.54 5980281.61 688686.64 GCT-MS 263.78 0.20 151.50 263.78 217.28 -0.39 0.56 5980281.56 688686.67 GCT-MS 280.50 0.22 153.14 280.50 234.00 -0.44 0.59 5980281.51 688686.70 GCT-MS 297.19 0.26 151.97 297.19 250.69 -0.51 0.62 5980281.45 688686.74 GCT-MS 313.87 0.29 148.96 313.87 267.37 -0.58 0.66 5980281.38 688686.78 GCT-MS 330.63 0.31 148.85 330.63 284.13 -0.65 0.71 5980281.31 688686.83 GCT-MS 347.28 0.33 146.09 347.28 300.78 -0.73 0.76 5980281.23 688686.88 GCT-MS 364.03 0.35 143.36 364.03 317.53 -0.81 0.82 5980281.15 688686.94 GCT-MS 380.58 0.38 139.72 380.58 334.08 -0.89 0.88 5980281.07 688687.00 GCT-MS 397.39 0.40 138.87 397.39 350.89 -0.98 0.96 5980280.98 688687.08 GCT-MS 413.99 0.41 137.16 413.99 367.49 -1.07 1.04 5980280.90 688687.16 GCT-MS 430.63 0.45 135.23 430.63 384.13 -1.16 1.12 5980280.81 688687.25 GCT-MS 447.38 0.47 131.52 447.38 400.88 -1.25 1.22 5980280.72 688687.35 GCT-MS 463.99 0.54 122.76 463.98 417.48 -1.34 1.34 5980280.64 688687.47 GCT-MS 480.67 0.59 120.69 480.66 434.16 -1.42 1.48 5980280.55 688687.61 GCT-MS ~alliburton Company Survey Report Company: BP AI7l000 Field: Pruahoe Bay (various) Site: AGI Well: AGI-10 Wcllpath: AGI-10A Survey MD Ind Acim ft deg deg -- VD ft ------- ys TVD ft --- --- Date: ~1 1120:2006 Time 10:43:5° Page: 2 Ca-ordina[e~NEl Reference: Well: AGI-1 D, True North Vertical (TVD) Reference: AGI-10A: t~ 46.5 MAGI-10:) 46.5 Section (VS) Reference: Weil (O.OON,O.OOE,62.SOAzi) Survey Calculaliun Method: Minimum Curvat~ire Db: Oracle N/S F:/~V MapN MapE Tool ft ft ft ft 497.12 0.63 117.41 497.11 450.61 -1.51 1.63 5980280.47 688687.77 GCT-MS 513.56 0.64 115.79 513.55 467.05 -1.59 1.79 5980280.40 688687.93 GCT-MS 529.96 0.71 109.95 529.95 483.45 -1.66 1.97 5980280.33 688688.11 GCT-MS 546.17 0.79 102.95 546.16 499.66 -1.72 2.17 5980280.27 688688.32 GCT-MS 562.31 0.90 96.43 562.30 515.80 -1.76 2.41 5980280.24 688688.55 GCT-MS 578.50 1.17 90.13 578.49 531.99 -1.78 2.70 5980280.23 688688.84 GCT-MS 594.62 1.43 87.21 594.60 548.10 -1.77 3.07 5980280.25 688689.21 GCT-MS 610.70 1.73 82.84 610.67 564.17 -1.73 3.51 5980280.30 688689.65 GCT-MS 626.95 2.09 78.87 626.92 580.42 -1.64 4.04 5980280.40 688690.18 GCT-MS 643.53 2.38 75.06 643.48 596.98 -1.49 4.67 5980280.56 688690.81 GCT-MS 659.74 2.76 72.38 659.68 613.18 -1.29 5.37 5980280.79 688691.50 GCT-MS 675.78 3.00 70.64 675.70 629.20 -1.03 6.13 5980281.06 688692.25 GCT-MS 691.81 3.28 68.99 691.70 645.20 -0.73 6.95 5980281.39 688693.07 GCT-MS 707.87 3.49 67.77 707.73 661.23 -0.38 7.84 5980281.76 688693.94 GCT-MS 724.00 3.69 66.67 723.83 677.33 0.01 8.77 5980282.17 688694.86 GCT-MS 740.07 3.94 65.71 739.87 693.37 0.44 9.75 5980282.63 688695.83 GCT-MS 756.23 4.05 64.82 755.99 709.49 0.92 10.77 5980283.13 688696.84 GCT-MS 772.29 4.23 64.26 772.01 725.51 1.41 11.81 5980283.65 688697.87 GCT-MS 788.31 4.38 63.32 787.98 741.48 1.95 12.89 5980284.21 688698.94 GCT-MS 804.43 4.50 62.42 804.05 757.55 2.51 14.00 5980284.81 688700.04 GCT-MS 820.54 4.69 61.83 820.11 773.61 3.12 15.14 5980285.44 688701.16 GCT-MS 836.63 4.82 61.44 836.15 789.65 3.75 16.32 5980286.10 688702.32 GCT-MS 852.67 5.07 60.94 852.13 805.63 4.42 17.53 5980286.80 688703.51 GCT-MS 868.70 5.28 60.63 868.09 821.59 5.12 18.79 5980287.53 688704.76 GCT-MS 884.85 5.57 60.55 884. i 7 837.67 5.87 20.12 5980288.32 688706.07 GCT-MS 900.90 5.90 60.68 900.14 853.64 6.66 21.52 5980289.14 688707.44 GCT-MS 916.94 6.17 60.51 916.09 869.59 7.49 22.99 5980290.00 688708.89 GCT-MS 933.07 6.60 61.06 932.12 885.62 8.36 24.55 5980290.92 688710.43 GCT-MS 949.01 6.93 61.26 947.95 901.45 9.27 26.20 5980291.87 688712.06 GCT-MS 964.88 7.23 61.06 963.70 917.20 10.21 27.91 5980292.85 688713.74 GCT-MS 980.86 7.46 61.33 979.55 933.05 11.20 29.70 5980293.88 688715.51 GCT-MS 997.30 7.61 61.61 995.84 949.34 12.23 31.60 5980294.96 688717.38 GCT-MS 1013.49 7.81 61.48 1011.89 965.39 13.26 33.51 5980296.04 688719.26 GCT-MS 1030.80 7.92 61.68 1029.03 982.53 14.39 35.59 5980297.22 688721.31 GCT-MS 1047.06 8.08 61.71 1045.14 998.64 15.46 37.58 5980298.34. 688723.28 GCT-MS 1063.29 8.20 61.96 1061.20 1014.70 16.55 39.61 5980299.48 688725.28 GCT-MS 1079.52 8.32 61.89 1077.26 1030.76 17.64 41.67 5980300.63 688727.31 GCT-MS 1095.69 8.43 62.02 1093.26 1046.76 18.75 43.74 5980301.79 688729.36 GCT-MS 1111.77 8.55 62.29 1109.17 1062.67 19.86 45.84 5980302.95 688731.43 GCT-MS 1127.89 8.66 62.40 1125.10 1078.60 20.98 47.98 5980304.12 688733.53 GCT-MS 1144.06 8.76 62.57 1141.09 1094.59 22.11 50.15 5980305.31 688735.68 GCT-MS 1160.23 8.86 62.79 1157.07 1110.57 23.25 52.35 5980306.50 688737.85 GCT-MS 1176.34 8.95 62.89 1172.98 1126.48 24.39 54.57 5980307.69 688740.04 GCT-MS 1192.51 9.04 62.81 1188.95 1142.45 25.54 56.82 5980308.90 688742.26 GCT-MS 1208.62 9.19 62.93 1204.86 1158.36 26.70 59.09 5980310.12 688744.50 GGT-MS 1225.21 9.33 63.01 1221.23 1174.73 27.92 61.47 5980311.39 688746.84 GCT-MS 1241.37 9.50 62.73 1237.18 1190.68 29.12 63.82 5980312.66 688749.16 GCT-MS 1257.48 9.65 62.53 1253.06 1206.56 30.35 66.20 5980313.95 688751.51 GCT-MS 1273.55 9.88 62.21 1268.90 1222.40 31.62 68.62 5980315.27 688753.89 GCT-MS 1289.65 10.13 61.70 1284.75 1238.25 32.93 71.08 5980316.65 688756.33 GCT-MS 1316.16 10.67 60.79 1310.83 1264.33 35.24 75.28 5980319.06 688760.46 GCT-MS 1354.23 11.33 60.36 1348.20 1301.70 38.81 81.61 5980322.79 688766.70 GCT-MS ~alliburton Company Survey Report Cump:my: BP AIneCO ~~ Hicltl: Prudhoe Bay (various) tine: AGI ~~~ell: AGI -10 ~~'cllpath: AGI- t0A Sur~c~ ~1ll incl Azim ft deg deg 1390.99 11.90 60.85 1427.49 12.43 61.73 1463.88 12.80 62.38 1500.16 13.01 62.73 1536.38 13.17 63.57 1572.95 13.41 64.06 1609.40 13.92 64.06 1645.82 15.02 62.38 1682.41 15.68 60.90 1719.02 15.85 60.41 1755.78 15.80 60.77 1792.69 15.63 62.29 1829.16 15.98 62.92 1866.07 17.12 62.66 1903.99 18.35 61.49 1940.73 19.45 59.65 1977.78 20.72 56.98 2014.71 22.04 55.05 2051.46 23.40 54.55 2088.21 24.24 54.84 2125.23 25.02 55.73 2162.30 25.88 56.87 2199.01 26.80 57.73 2235.33 27.98 58.58 2271.81 28.69 59.25 2308.52 29.13 59.70 2345.11 29.48 60.14 2381.81 29.99 60.66 2419.57 30.72 61.33 1384.21 1337.71 1419.89 1373.39 1455.40 1408.90 1490.76 1444.26 1526.04 1479.54 1561.63 1515.13 1597.05 1550.55 1632.31 1585.81 1667.60 1621.10 1702.83 1656.33 1738.20 1691.70 1773.73 1727.23 1808.82 1762.32 1844.20 1797.70 1880.32 1833.82 1915.08 1868.58 1949.87 1903.37 1984.26 1937.76 2018.16 1971.66 2051.78 2005.28 2085.43 2038.93 2118.90 2072.40 2151.80 2105.30 2184.05 2137.55 2216.16 2169.66 2248.29 2201.79 2280.20 2233.70 2312.07 2265.57 2344.65 2298.15 N/ti ft 42.44 46.13 49.85 53.59 57.29 61.00 64.77 68.87 73.48 78.35 83.27 88.04 92.61 97.42 102.83 108.68 115.37 122.90 131.08 139.66 148.45 157.28 166.08 174.89 183.83 192.84 201.82 210.81 220.06 FJ1~' MapN tt ft 88.05 5980326.58 94.80 5980330.44 101.82 5980334.34 109.01 5980338.25 116.33 5980342.14 123.88 5980346.04 131.62 5980350.00 139.74 5980354.31 148.26 5980359.12 156.93 5980364.21 165.66 5980369.35 174.45 5980374.34 183.27 5980379.13 192.62 5980384. i 7 202.82 5980389.84 213.18 5980395.95 224.00 5980402.91 235.16 5980410.72 246.76 5980419.19 258.87 5980428.07 271.55 5980437.17 284.81 5980446.33 298.52 5980455.47 312.71 5980464.64 327.54 5980473.95 342.83 5980483.34 358.32 5980492.71 374.15 5980502.09 390.84 5980511.76 N1apF, ft 'fool 688773.05 GCT-MS 688779.70 GCT-MS 688786.63 GCT-MS 688793.72 GCT-MS 688800.94 GCT-MS 688808.39 GCT-MS 688816.04 GCT-MS 688824.05 GCT-MS 688832.46 GCT-MS 688841.00 GCT-MS 688849.60 GCT-MS 688858.27 GCT-MS 688866.97 GCT-MS 688876.19 GCT-MS 688886.26 GCT-MS 688896.47 GCT-MS 688907.11 GCT-MS 688918.08 GCT-MS 688929.47 GCT-MS 688941.36 GCT-MS 688953.81 GCT-MS 688966.84 GCT-MS 688980.32 GCT-MS 688994.29 GCT-MS 689008.89 GCT-MS 689023.94 GCT-MS 689039.21 GCT-MS 689054.80 GCT-MS 689071.25 GCT-MS 689089.25 GCT-MS 689107.79 GCT-MS 689126.34 GCT-MS 689144.51 GCT-MS 689162.66 GCT-MS 689180.89 GCT-MS 689199.29 GCT-MS 689217.77 GCT-MS 689236.77 GCT-MS 689255.66 GCT-MS 689274.91 GCT-MS 689294.41 GCT-MS 689314.39 GCT-MS 689334.71 GCT-MS 689355.04 GCT-MS 689375.52 GCT-MS 689396.35 GCT-MS 689417.78 GCT-MS 689439.43 GCT-MS 689461.45 GCT-MS 689483.82 GCT-MS 689506.01 GCT-MS 689528.23 GCT-MS 689550.42 GCT-MS 2459 .80 31 .29 62.15 2379.13 2332 .63 229. 87 409. 09 5980522. 03 2500 .42 31 .57 62. 85 2413.79 2367 .29 239. 65 427. 88 5980532. 28 2540 .63 31 .78 63. 08 2448.01 2401 .51 249. 25 446. 69 5980542. 34 2579 .63 32 .21 62. 90 2481.09 2434 .59 258. 63 465. 10 5980552. 19 2618 .27 32 .79 61. 93 2513.68 2467 .18 268. 25 483. 50 5980562. 26 2656 .89 33 .29 60. 96 2546.05 2499 .55 278. 31 501. 99 5980572. 79 2695 .69 33 .84 60. 03 2578.38 2531 .88 288. 88 520. 66 5980583. 82 2734 .45 34 .50 59. 10 2610.45 2563 .95 299. 91 539. 43 5980595. 32 2773 .94 35 .07 58. 78 2642.89 2596 .39 311. 53 558. 73 5980607. 42 2812 .79 35 .50 58. 73 2674.60 2628 .10 323. 17 577. 91 5980619. 54 2851 .91 36 .07 58. 80 2706.33 2659 .83 335. 03 597. 47 5980631. 89 2890 .81 36 .94 58. 96 2737.60 2691 .10 346. 99 617. 28 5980644. 35 2929 .90 37 .55 59. 11 2768.72 2722 .22 359. 17 637. 57 5980657. 03 2969 .18 37 .90 59. 29 2799.79 2753 .29 371. 47 658. 22 5980669. 85 3008 .00 38 .28 59. 75 2830.34 2783 .84 383. 62 678. 85 5980682. 51 3046 .58 38 .67 60. 32 2860.54 2814 .04 395. 61 699. 65 5980695. 02 3085 .12 39 .22 61. 15 2890.52 2844 .02 407. 45 720. 78 5980707. 39 3123 .93 39 .84 62. 09 2920.45 2873 .95 419. 19 742. 52 5980719. 67 3162 .39 40 .33 62. 68 2949.88 2903 .38 430. 67 764. 46 5980731. 70 3201 .03 40 .66 62. 97 2979.26 2932 .76 442. 13 786. 78 5980743. 71 3240 .03 40 .80 62. 94 3008.82 2962 .32 453. 70 809. 45 5980755. 85 3278 .89 40 .40 62. 63 3038.32 2991 .82 465. 26 831. 94 5980767. 98 3318 .13 40 .12 62. 67 3068.27 3021 .77 476. 91 854. 46 5980780. 19 3357 .55 39 .96 62. 30 3098.45 3051 .95 488. 63 876. 95 5980792. 47 llatc: 11/20.2006 Time: 10:43:58 P~gc ? Co-ordinatc(NE) Reference: Well: AGI-10, True North ~crtical (TVD) Reference: AGI-10A: @ 46.5 (AGI-10:1 46.5 Sectiu^ IVS)Referenee: VJeII (O.OON,O.OOE_62.SOAzI) tiur~cc Calculation Melhikt: Minimum Curvature llb: Oracle T`~ U ti~s'I'VI) i[ tt ' ~alliburton Company Survey Report Company: BP Amoco Field: Prudhoe Bay (various) Site: AGI Well: AGI-10 Wellpath: AGI-10A Survev MD [ncl~~ ~ Azim ft deg deg 3396.50 3435.89 3475.38 3514.45 3553.78 3593.32 3632.68 3671.93 3711.13 3725.00 3776.94 3871.58 3966.11 4060.50 4153.38 4248.71 4340.37 4432.19 4538.99 4633.57 4727.20 4817.77 4918.75 5010.45 5107.07 5200.03 5298.49 5393.61 5486.64 5582.45 5677.69 5773.79 5866.59 5962.77 6057.27 6151.87 6247.51 6342.09 6436.38 6529.61 6624.31 6718.73 6811.39 6906.95 7000.22 7094.57 7188.46 7283.66 7379.54 7474.82 7570.09 7665.24 39.73 39.62 39.53 39.53 39.48 39.53 39.66 39.88 40.08 40.16 40.35 38.26 36.73 37.43 36.64 36.21 36.35 36.63 36.83 37.01 36.89 35.65 35.79 36.08 35.49 35.25 35.21 34.98 35.48 35.79 36.05 36.60 36.59 36.71 34.91 34.54 35.43 36.76 35.99 37.38 38.68 39.11 39.54 40.49 39.71 38.64 36.75 35.21 35.02 35.46 35.95 35.38 61.57 61.41 61.59 61.81 62.09 62.34 62.52 62.74 62.91 62.99 65.23 69.59 74.31 69.51 63.91 62.50 65.49 65.02 64.84 63.72 65.17 66.01 65.50 65.91 64.82 64.47 64.11 63.93 63.61 63.07 63.08 62.64 62.43 62.01 62.41 62.92 63.76 65.79 67.33 67.99 66.11 63.83 60.59 60.50 59.87 60.76 61.08 61.97 63.01 63.32 63.19 62.31 1'~U ti~s'1'~~U ft ft 3128.35 3081.85 3158.67 3112.17 3189.11 3142.61 3219.24 3172.74 3249.59 3203.09 3280.10 3233.60 3310.42 3263.92 3340.59 3294.09 3370.63 3324.13 3381.24 3334.74 3420.88 3374.38 3494.12 3447.62 3569.13 3522.63 3644.45 3597.95 3718.62 3672.12 3795.32 3748.82 3869.22 3822.72 3943.04 3896.54 4028.64 3982.14 4104.25 4057.75 4179.08 4132.58 4252.10 4205.60 4334.08 4287.58 4408.33 4361.83 4486.71 4440.21 4562.51 4516.01 4642.94 4596.44 4720.77 4674.27 4796.76 4750.26 4874.63 4828.13 4951.76 4905.26 5029.18 4982.68 5103.69 5057.19 5180.85 5134.35 5257.48 5210.98 5335.24 5288.74 5413.59 5367.09 5490.02 5443.52 5565.94 5519.44 5640.70 5594.20 5715.30 5668.80 5788.79 5742.29 5860.47 5813.97 5933.66 5887.16 6005.00 5958.50 6078.14 6031.64 6152.43 6105.93 6229.47 6182.97 6307.90 6261.40 6385.72 6339.22 6463.08 6416.58 6540.38 6493.88 N/S it 500.37 512.37 524.38 536.17 547.93 559.66 571.27 582.81 594.32 598.38 613.03 636.09 653.95 671.63 693.70 719.22 742.99 765.84 792.91 817.56 841.84 863.99 888.20 910.34 933.89 956.93 981.57 1005.52 1029.24 1054.29 1079.59 1105.56 1131.08 1157.83 1183.62 1208.36 1232.96 1256.69 1278.94 1300.10 1322.86 1347.95 1375.32 1405.54 1435.41 1464.93 1492.83 1519.50 1544.98 1569.79 1594.82 1620.21 E/W ~lap'V - ~9apH Tool ft ft ft 898.97 --- 5980804.76 689572.13 GCT-MS 921.07 5980817.31 689593.92 GCT-MS 943.18 5980829.87 689615.72 GCT-MS 965.08 5980842.21 689637.31 GCT-MS 987.16 5980854.52 689659.09 GCT-MS 1009.41 5980866.80 689681.04 GCT-MS 1031.65 5980878.97 689702.97 GCT-MS 1053.94 5980891.07 689724.97 GCT-MS 1076.35 5980903.13 689747.08 GCT-MS 1084.31 5980907.40 689754.94 MWD+IFR+MS 1114.50 5980922.80 689784.75 MWD+IFR+MS 1169.80 5980947.25 689839.44 MWD+IFR+MS 1224.46 5980966.47 689893.63 MWD+IFR+MS 1278.51 5980985.51 689947.22 MWD+IFR+MS 1329.86 5981008.87 689997.99 MWD+IFR+MS 1380.39 5981035.64 690047.86 MWD+IFR+MS 1429.12 5981060.63 690095.97 MWD+IFR+MS 1478.71 5981084.73 690144.97 MWD+IFR+MS 1536.56 5981113.24 690202.12 MWD+IFR+MS 1587.75 5981139.18 690252.66 MWD+IFR+MS 1638.52 5981164.72 690302.81 MWD+IFR+MS 1687.31 5981188.09 690351.02 MWD+IFR+MS 1741.06 5981213.64 690404.14 MWD+IFR+MS 1790.11 5981237.01 690452.61 MWD+IFR+MS 1841.47 5981261.84 690503.36 MWD+IFR+MS 1890.09 5981286.10 690551.39 MWD+IFR+MS 1941.27 5981312.02 690601.92 MWD+IFR+MS 1990.43 5981337.20 690650.46 MWD+IFR+MS 2038.57 5981362.13 690697.98 MWD+IFR+MS 2088.45 5981388.42 690747.22 MWD+IFR+MS 2138.27 5981414.97 690796.38 MWD+IFR+MS 2188.93 5981442.20 690846.36 MWD+IFR+MS 2238.01 5981468.94 690894.79 MWD+IFR+MS 2288.81 5981496.97 690944.89 MWD+IFR+MS 2337.72 5981523.97 690993.13 MWD+IFR+MS 2385.59 5981549.91 691040.36 MWD+IFR+MS 2434.59 5981575.74 691088.73 MWD+IFR+MS 2485.00 5981600.73 691138.52 MWD+IFR+MS 2536.30 5981624.26 691189.24 MWD+IFR+MS 2587.82 5981646.71 691240.21 MWD+IFR+MS 2641.53 5981670.82 691293.32 MWD+IFR+MS 2695.24 5981697.25 691346.38 MWD+IFR+MS 2747.17 5981725.92 691397.60 MWD+IFR+MS 2800.67 5981757.47 691450.32 MWD+IFR+MS 2852.79 5981788.64 691501.67 MWD+IFR+MS 2904.57 5981819.45 691552.69 MWD+IFR+MS 2954.73 5981848.61 691602.13 MWD+IFR+MS 3003.89 5981876.51 691650.60 MWD+IFR+MS 3052.81 5981903.20 691698.85 MWD+IFR+MS 3101.86 5981929.25 691747.27 MWD+IFR+MS 3151.51 5981955.51 691796.27 MWD+IFR+MS 3200.83 5981982.14 691844.93 MWD+IFR+MS llatc: 11;20;2006 Time: 10:43:58 1'a~;c: 4 Co~~rdinatelNh;i Reterence: Well: AGI-10, True North ~crtical ('I'~'Dl ltct'crcnce: AGI-10A: cr X76.5 (AGI-10_) 46.5 ticction (VS) Reference: Well (O.OON,O.OOE,62.80Azi) tiurvey Calculation Merhod: Minimwn Curvature llb: Oracle ' ~alliburton Company Survey Report Compau~~: BP Amoco Date: 7 1.20;'2006 Cime: 10:43:58 Nar;e: 5 Feld: Prudhoe Bay (various) Coi,rdinate~AF:~ Ke[ cre^cc W ell: AGI 10, True North Site: AGI ~'ertic:al (TVllI Reference: AGI-10A: @ 46.5 (AGI-10:) 46.5 ~1'cll: AGI -10 Section fVS) Referen ce: W ell (O.OON,O.OOE,62.80Azi) ~~'dlpadh: AGI-10A Sur~c~ C.~Iculatian A feth~xl: Mi nimwn Curvature Db: OraC(e Survey 11D Incl Azim l VU Sys ~fVD - - N/S - PJ1v ~ ~~ ~ Jlapti ~ P1ap1~: Tool ft deg deg ft ft ft ft ft ft 7759.87 35.68 61.93 6617.40 6570.90 1645.93 3249.44 5982009.07 691892.87 MWD+IFR+MS 7855.25 36.49 61.82 6694.48 6647.98 1672.41 3298.99 5982036.79 691941.73 MWD+IFR+MS 7950.64 35.59 61.78 6771.61 6725.11 1698.93 3348.45 5982064.54 691990.51 MWD+IFR+MS 8045.11 33.39 61.84 6849.47 6802.97 1724.20 3395.59 5982090.99 692037.00 MWD+IFR+MS 8138.79 33.20 62.14 6927.77 6881.27 1748.35 3440.99 5982116.28 692081.78 MWD+IFR+MS 8233.71 33.62 61.90 7007.01 6960.51 1772.87 3487.15 5982141.95 692127.30 MWD+IFR+MS 8328.34 33.99 61.73 7085.64 7039.14 1797.74 3533.56 5982167.98 692173.06 MWD+IFR+MS 8423.11 34.09 62.27 7164.17 7117.67 1822.65 3580.40 5982194.05 692219.25 MWD+IFR+MS 8516.88 35.22 63.53 7241.30 7194.80 1846.93 3627.86 5982219.52 692266.09 MWD+IFR+MS 8610.79 36.83 64.68 7317.25 7270.75 1871.04 3677.55 5982244.87 692315.15 MWD+IFR+MS 8702.88 37.23 64.25 7390.77 7344.27 1894.94 3727.59 5982270.03 692364.58 MWD+IFR+MS 8799.76 37.47 64.32 7467.78 7421.28 1920.45 3780.55 5982296.86 692416.87 MWD+IFR+MS 8897.29 37.82 63.93 7545.01 7498.51 1946.44 3834.14 5982324.19 692469.79 MWD+IFR+MS 8992.81 38.40 62.86 7620.17 7573.67 1972.85 3886.85 5982351.91 692521.81 MWD+IFR+MS 9087.08 36.49 62.69 7695.01 7648.51 1999.07 3937.81 5982379.41 692572.10 MWD+IFR+MS 9183.01 35.48 62.05 7772.63 7726.13 2025.20 3987.75 5982406.79 692621.36 MWD+IFR+MS 9277.93 35.09 62.22 7850.11 7803.61 2050.83 4036.23 5982433.63 692669.17 MWD+IFR+MS 9373.35 34.61 62.18 7928.42 7881.92 2076.26 4084.46 5982460.26 692716.74 MWD+IFR+MS 9430.50 34.76 61.94 7975.41 7928.91 2091.50 4113.19 5982476.22 692745.08 MWD+IFR+MS 9488.17 34.91 61.69 8022.75 7976.25 2107.06 4142.23 5982492.50 692773.71 MWD+IFR+MS 9542.89 35.07 61.30 8067.58 8021.08 2122.03 4169.80 5982508.17 692800.90 MWD+IFR+MS 9645.45 34.31 58.99 8151.91 8105.41 2151.07 4220.42 5982538.47 692850.77 MWD+IFR+MS 9740.67 33.98 57.26 8230.72 8184.22 2179.29 4265.80 5982567.82 692895.42 MWD+IFR+MS 9836.51 34.07 56.37 8310.15 8263.65 2208.64 4310.68 5982598.29 692939.55 MWD+IFR+MS 9882.28 33.90 56.39 8348.10 8301.60 2222.81 4331.99 5982612.99 692960.49 MWD+IFR+MS 9937.00 33.90 56.39 8393.52 8347.02 2239.70 4357.41 5982630.52 692985.47 PROJECTED to TD AI.ASI~ OII, ~ G~15 COI~TSERQATIOI~T COAIIriISSI011T Dave Wesley Senior Drilling Engineer BP Exploration (Alaska) Inc. PO Box 196612 Anchorage, AK 99519-6612 i FRANK H. MURKOWSKI, GOVERNOR 333 W. T" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Prudhoe Bay Field, Prudhoe Bay Oil Pool, PBU AGI- l0A BP Exploration (Alaska) Inc. Permit No: 206-135 Surface Location: 2634' FNL, 2579' FEL, SEC. 36, T12N, R14E, UM Bottomhole Location: 440' FNL, 1763' FWL, SEC. 31, T12N, R15E, UM Dear Mr. Wesley: Enclosed is the approved application for permit to redrill 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 (907) 659-3607 (pager). DATED this day of September, 2006 cc: Department of Fish 8v Game, Habitat Section w/ o encl. Department of Environmental Conservation w/o encl. STATE OF ALASKA ALASK~L AND GAS CONSERVATION COMMIS~N PERMIT TO DRILL 20 AAC 25.005 WG/4 4/L4jZO°G' ~~D~NVED SEP 2 2 2006 Alacb~ n:. o ,. 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 pro 486. COR1R11SSj0 ^ Coalbed Methane ~~~drates ^ Shale Gas 2. Operator Name: BP Exploration (Alaska) Inc. 5. Bond: ®Blanket ^ Single Well Bond No. 6194193 11. Well Name and Number: / PBU AGI-10A 1I~L(z°O~ 3. Address: P.O. Box 196612, Anchorage, Alaska 99519-6612 6. Proposed Depth: MD 9932 TVD 8416 12. Field /Pool(s): Prudhoe Bay Field / Prudhoe Bay 4a. Location of Well (Governmental Section): Surface: 2634' FNL 2579' FEL SEC R14E UM 36 T12N 7. Property Designation: ADL 034628 Pool , , . , , , Top of Productive Horizon: 440' FNL, 1763' FWL, SEC. 31, T12N, R15E, UM 8. Land Use Permit: 13. Approximate Sp Date: Novem er 7,006 Total Depth: 440' FNL, 1763' FWL, SEC. 31, T12N, R15E, UM 9. Acres in Property: 2560 14. Distance to Nearest Property: 11,000' 4b. Location of Well (State Base Plane Coordinates): Surface: x-688686 y-5980282 Zone-ASP4 10. KB Elevation Plan (Height above GL): 49 feet 15. Distance to Nearest Well Within Pool: 700' 16. Deviated Wells: Kickoff Depth: 3860 feet Maximum Hole An le: 40 de rees 17. Maximum Anticipated Pressures in psig (see 20 .035) Downhole: 3578 Surface: 277 18. Casin Pro ram: S ecifii;atio ns To - S ttin De th - Bo om uantit o C ent c.f. or sacks Hole Casin Wei ht Grade Cou lin Len th MD TVD MD TVD includin sta a data 12-1/4" 9-5/8" 47# L-80 TC-II 9475' Surface Surface 9475' 8046' 1465 cu ft LiteCrete 803 cu ft'G' r 8-1/2" 7" 26# L-80 BTC-M 555' 9380' 7969' 9932' 8416' Uncemented Slotted Liner 19. PRESE NT WELL CONDITION S UMMARY (To be completed for.Redrill and Re-entry Operations) Total Depth MD (ft): 10251 Total Depth TVD (ft): Plugs (measured): 8447 None Effective Depth MD (ft): 10230 Effective Depth TVD (ft): 8431 Junk (measured): None :Casing Length Size Cement Volume MD TVD Conductor /Structural 76' 20" 281 cu Arcticset 106' 106' Surface 3808' 13-3/8" 2387 cu ft PF'E' 464 cu ft Class'G' 3846' 3474' Intermediate 9627' 9-5/8" 575 cu ft Class'G' 661' 7976' Pr du i n Liner 842' 7" Uncemented 9409' - 10251' 7774' - 8447' Perforation Depth MD (ft): 9860' - 10176' Perforation Depth TVD (ft): 8135' - 8388' 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 foregoing is true and correct. Contact Joshua Sudderth, 56a-4342 Printed Name ave Wesley Title Senior Drilling Engineer / ~ Prepared By Name/Number: Si nature ''~C~~' ~" ~'~ Phone 564-5153 Date/ ~=~~` ~ Terrie Hubble, 564-4628 Commission Use Onl Permit To Drill Number:~G7 ~~~ API Number: 50-029-22353-01-00 Permit proval See cover letter for Date: other re uirements Conditions ofApproyal: If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained shales: '!? S-~ j~ D ~~ ~ n ~. 000 r ~ ~ Samples Req'd: ^ Yes ~No Mud Log Req'd: ^ Yes ~No ~/~, ~'[- ~',Q lvt p~vt.~ LLs~,(.t, `Q! V ~ t'`~' ~ , HZS Measures: ,Yes ^ No Dire ~onal Survey Req'd: ~ Yes ^ No 1 1 O er: 0.w a ZO /''~1: 2) . ~ ~ 1 ~k ~ ~~ a,l Ce ~ w~.~'e RD P~ ~f-S~ 1~ ~ S a~j~ 1~t! ~ d. , P OVED BY THE COMMISSION Date • ~ V ,COMMISSIONER Form 10-401 Revised 12/2005 ~ R ~ G 1 N A ~ Submit In Duplicate • • To: Winton Aubert, Petroleum Engineer Alaska Oil & Gas Conservation Commission From: Joshua Sudderth, 27E Drilling Engineer Date: September 22, 2006 Re. AGI-l0A Sidetrack Permit to Drill Approval is requested for the permit to drill for well AGI-10A. The AGI-l0A sidetrack is currently scheduled for Nabors 27E beginning the second week of November, 2006. Well AGI-10~ is an Ivishak gas injector that is currently shut in due to a leak in the 9 5/8" production casing at 7,220 ft MD (6,008 ft TVDSS). The well failed MIT-IA that was performed for regulatory compliance on August 23, 2005. After a second MIT-IA failed on August 29, 2005, a liquid leak rate was established down the inner annulus (IA). The well was shut in and secured with a tubing tail plug (TTP). The tubing was pressure tested to 3,000 psi against this plug. A leak detect log was run on September 5, 2005 and confirmed a cretaceous leak at the aforementioned depth. The plan is to pull the existing tubing string, set an EZSV in the 9 5/8" casing at 4,1.00 ft MD and cut and pull the 9-5/8" casing just above the bridge plug. A cement kick off plug will be set on top of the EZSV and into the surface casing. The well will be sidetracked at 3,860 ft MD to the 12-1/4" TD at 9,475' MD. A 9-5/S" / production casing will be run and cemented to 4000' TVD. The 9-5/8" x 13-3/8" annulus will be freeze protected from 2200' TVD to surface. The production zone will be drilled to 9,932 ft MD and completed with 7" slotted liner. A 7-5/8" IPC tubing string will be run for gas injection. Planned Well Summary Well AGI-10A Well Gas Injector Target Ivishak T e Rota Sidetrack Ob'ective AFE Number: PBD 4P 9329 Surface Northin Eastin Offsets TRS Location 5,980,281.94 688,686.10 2646' FSL / 2579' FEL 12N, 14E, 36 API Number: 50-029-22353-01 Target Northing Easting Offsets TRS Locations 5,982,585 692,970 440' FNL / 3100' FEL 12N, 15E, 31 Bottom Northin Eastin Offsets TRS Location 5,982,585 692,970 440' FNL / 3100' FEL 12N, 15E, 31 Planned KOP: 3,860'md / 3,485' tvd Planned TD: 9,932' and / 8,416' tvd _~ Ri Nabors 7 RTE: 49' AGI-10A Permit to Drill Application Page 1 • • Surface and Anti Collisioin Surface Shut-in Wells: There are no wells requiring surface shut-in prior to moving onto the well. Close Approach Shut-in Wells: None Area of Review Wells within 1/a mile of this injection well at the reservoir top Well Name Dist ft Annulus Inte rit Comments f 9 3 0 ~9 AGI -10 550 N/A ~ Z¢~ Zg WBEACH-01 ' 700 None Identified ~ g 3 0 3~ AGI-09 ! 1150 None Identified Well Control Well control equipment consisting of 5,000 psi working pressure pipe rams (2), blind shear rams, and an annular preventer will be installed and is capable of handling maximum potential surface pressures. BOPE and drilling fluid system schematics are currently on file with the AOGCC. Well Interval: 121/a" Intermediate Hole Maximum antici ated BHP: 3,578 si at 8,000' TVDSS. (8.6 g max ore ressure) Maximum surface pressure: 2,778 psi (based upon BHP and a full column of gas from TD @ 0.10 psi/ft) Calculated kick tolerance: 127 bbls with 10.5 EMW FIT and 9.9 g MW Planned BOPE test pressure: 250 psi low / 4,000 psi high / 7 day test cycle (Pre drilling phase) 14 da test c cle (Drillin o erations) Well Interval: 81h" roduction interval Maximum antici ated BHP: 3,381 si at 8,400' TVDss. Maximum surface ressure: 2,541 si (based u on BHP and a full column of as from TD @ 0.10 si/ft) Calculated kick tolerance: Infinite with 9.5 EMW FTI'. Planned BOPE test pressure: 250 psi low / 4,000 psi high 14 da test c cle (Drillin o erations) Planned com letion fluid: 8.6 seawater / 7.1 Diesel BPXA requests a variance to the provisions of 20 AAC 25.035 (e)(10)C regarding the function pressure test \ ~ requirement after the use of BOP ram type equipment for other than well control or equivalent purposes, except ~"' when the routine use of BOP ram type equipment may have compromised their effectiveness. (Example would be when pipe rams are inadvertently closed on a tool joint during routine operations.) The activities associated with this request will not compromise the integrity of the BOP equipment. H2S AGI i no designated as an H2S site as this is an injection pad. Standard Operating Procedures for H2S preca s should be followed at all times. Recent H2S data from the pad is as follows: Closest well to SHL Latest H2S reading Closest well to BHL Latest H2S reading AGI-08 None -Gas Injector AGI-08 None -Gas Injector AGI-09 None -Gas Injector AGI-09 None -Gas Injector AGI-10A Permit to Drill Application Page 2 • • Directional Program Kick Off Point 3,860 ft MD Maximum Hole Inclination: --40° in the lanned KOP. Proximit Issues: All wells ass ma'or risk criteria. Surve Pro ram: Standard MWD + IFR/MS/Cassandra Nearest Well within ool: Well WBeach-O1 at 700 ft i Nearest Pro ert Line 11,000' Logging Program Hole Section: Re wired Sensors /Service l2 1/4" intermediate: Real time MWD Dir/GR/PWD 8 1/2" roduction: Real time MWD Dir/GR/PWD Cased Hole: USIT\GR\CCL (9 5/8" Casin ) O en Hole: None lanned Mud Program Hole Section / o eration: Cut & Pull tubin and Casin .Set EZSV and KO plu T e Densit MBT PV YP API FL H BRINE 9.8 N/A 9.0 -10.0 Hole Section / o eration: Drillin 12 1 /4" interval from 3,860' and to 9,475' and T e Densit Chlorides PV YP API FL H LSND 9.1 9.9 % <600 15-22 20-24 4.0 - 6.0 9.0 -10.0 Hole Section / o eration: Drillin 8 1 /2" production interval to TD ~9,932'MD T e Densit LSRV PV YP API FL H FloPro SF 8.4 - 8.6 >20,000 8 - 15 22 - 30 6 - 9 9.0 -10.0 Casing /Tubing Program Hole Casing/Tubing Wt. Grade Connection Length Top Bottom Size Size / ~ and / tvd and / tvd 12 ~/a" 9 5/8" 47# L-80 TC-II 9,475' Surface 9,475' / 8,046' 8'/z" 7" 26# L-80 slotted BTC-M 555' 9,380' / 7,969' 9,932' / 8,416' Tubing 7 5/8" 29.7# CPC Vam Top HC 9,266' Surface 9,315' / 7,917' Tubing 7" 26# L-80 TC-II 69' 9,315' / 7,917' 9,384' / 7,973' AGI-10A Permit to Drill Application Page 3 • Casing /Formation Integrity Testing • Test Test Point Test Type Test pressure 13 3/8" casing w/KO plug Top cmt KO Plug C~ 3650' MD 30 min recorded 3,500 psi surface 13 3/8" casing shoe (12'/a" OH) 20' new formation FIT 11 ppg EMW 9 5/8" casing Float equipment to surface 30 min recorded 4,000 psi surface 9 5/8" casing shoe (8'/z" OH) 20' new formation beyond FIT 9.5 ppg EMW 7 5/8" X 7" Tubing Packer C«~ 9340' MD 30 min recorded 4,000 psi surface 7 5/8" tbg x 9 5/8" csg annulus Tubing-Casing annulus from acker C~ 9340 MD 30 min recorded 4,000 psi surface w/2,000 si on Tb Cementing Program Casin Strin 9 5/8" 47# L-80, TC-It, Production casin Slurry Design Basis: Lead slurry: 3,600' of 9 5/8" x 12'/a" annulus with 40% excess. Lead TOC ~ 4,000' MD. ~ ° Tail slurry: 1,800 of 9 5/8 x 12 /a annulus with 40 /° excess plus ~90 of 9 5/8" 47# casin shoe track. Tail TOC @7,599' MD. Fl i S acer 40 bbls MudPush II at 10.9 u ds Sequence /Volume: Lead Slur 12.5 LiteCrete - 261 bbls 2.25 cu ft/sk 651 sx Tail Slurry 15.8 ppg Class G -143 bbls (1.17 cu ftlsk)..6~sx. Disposal ~$C~ 1~-~~"r" Annular Injection: No annular injection in this well. Cuttings Handling• Cuttings generated from drilling operations are to be hauled to the Grind and Inject station at DS-04. An metal cuttin s should be sent to the North Slo a Borou h. Fluid Handling: All drilling and completion fluids and other Class II wastes are to be hauled to DS-04 j for in ection. All Class I wastes are to be hauled to Pad 3 for dis osal. AGI-10A Permit to Drill Application Page 4 • • Geologic Prognosis Formation Tops(TVDss) and Estimated Pore Pressures Est. Formation To s Uncertain Commercial Hydrocarbon Bearin Est. Pore Press. Est. Pore Press. Formation (TVDss) (eet) (Yes/No) (Psi) ( 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 SV6 1735 100 EOCU 2450 50 SV5 3210 50 *** KOP 3860'MD *** SV4 3455 20 SV3 3850 20 SV2 4010 20 SV1 4405 20 UG4 4845 20 UG4A 4875 20 UG3 5330 20 UG 1 5770 20 WS2 6245 20 WS1 6370 20 CM3 6480 20 CM2 7135 20 CM 1 7610 20 TH RZ 7795 20 LCU 7960 20 Kingak Sag River Missing Tops/Section -Truncated by LCU TSAD 42SB 8000 20 Yes TCG L 8020 20 Yes BCG L 8075 20 Yes 23SB 8145 20 Yes 22TS 8165 20 Yes 21TS 8200 20 Yes TZ1 B 8280 20 Yes TDF 8315 20 Yes 3383 psi BSAD 8340 20 TD Criteria: Reach planned TD unless drilling conditions deteriorate. Final TD TBD by both rig and town geologist. Wellbore maybe extended to meet minimum 500' perforation requirement. AGI-10A Permit to Drill Application Page 5 • • Fault Prognosis No faults are anticipated to be crossed by the AGI-l0A injector well. Several faults, however, are in the proximity of the proposed well. The two closest faults are given below. The first fault is a SW-NE trending fault with 30-40 ft. of throw down to the N anticipated. Fault #1 is located approximately 240 ft. north of the polygon. The second fault is a NW-SE trending fault with 20-40 ft. of throw down to the NE anticipated. The tip out of this fault is located approximately 275 ft. to the SE of the polygon. The AGI-10 parent well did not experience any lost circulation. In the vicinity of the proposed AGI-10A, four wells experienced significant lost circulation (>100 bbls). These wells included LGI-10, LGI-08, AGI-06, and LGI-12. The majority of the lost circulation events in these wells occurred below the BSAD. The exceptions are AGI-06 which took losses of 1.100 bbls and 375 bbls both in Zone 2 and LGI-10 which had losses of 145 bbls in Zone 3. The losses below the BSAD were as follows: LGI-10 188 bbls at 8334 ft. TVD, 105 bbls at 8364 ft. ~" TVD, and 513 bbls at 8499 ft. TVD, LGI-08 with 138 bbls at 8429 ft. TVD and 210 bbls at 9337 ft. TVD, and LGI-12 with 170 bbls at 8740 ft. TVD, 156 bbls at 8880 ft. TVD, and 106 bbls at 8966 ft. None of the losses appear to be fault related. Overall, the depth conversion is well constrained, and the fit of the structure to the well picks is good. On the other hand, AGI-l0A is located at the edge of the seismic data, and as a result, there could be complications from being close to the edge of the data (e.g., noise, migration artifacts and faults not seen on the seismic). AGI-10A Permit to Drill Application Page 6 Operations Summary Current Status: - Tubing tail plug at 9423' MD. - MIT-T & MIT-OA to 2500 psi -BOTH FAILED 02/08/06 a. Maximum injection pressure was 3630 psi, 6/21/05 b. 4350 psi is 87% of surface casing burst Pre-Riq Operations: 1. SLICKLINE: Pull Tailpipe plug at 9423' MD. 2. WIRELINE: Run static pressure survey to determine BHP for proper MW during drilling operations. 3. COIL TUBING: Plug and abandon the open perforations with ~32 bbls of 15.8 ppg cement, leaving the TOC just above the 7" x 5-1/2" crossover. Cement volume based on the following calculations: a. 796' of 7" liner (cap. = 0.0371 bbl/ft) = 29.5 bbls b. 110' of 5-1/2" tubing tail (cap. = 0.0232 bbl/ft) = 2.5 bbls 4. SLICKLINE/WIRELINE: Drift tubing to estimated TOC. Tag cement to verify TOC depth. 5. SLICKLINE/WIRELINE: Run dummy SSSV. Attempt to pressure test cement plug to 3500 psi for 30 minutes. 6. COIL TUBING: If dummy SSSV does not result in tested cement plug, follow the steps below: a. Run an inflatable plug (from Baker) to the tubing tail. b. Open the pump through port. c. Pump through the plug, pressure up to 3500 psi for 30 minutes d. Retrieve the plug, POOH. **If this test does not pass, contact Drilling Engineer. 7. WIRELINE: Hole punch tubing at 9300' (above TOC). 8. OTHER: Circulate tubing and IA to 9.8 ppg brine. a. 9.8 ppg brine required for kill weight fluid for production casing leak b. Ensure no differential pressure for upcoming chemical cut. 9. COIL TUBING: Locate approximate tubing leak depth. Set IBP at 6,000' MD and test CT-TBG annulus above IBP to 3,500 psi for 5 mins and monitor the 9 5/8"XTBG annulus. If tubing does not test, move up 250 ft and retest. Repeat until tubing tests or until test depth is less than 5,000 ft MD. 10. WIRELINE: Set EZSV at 6,000' MD or at depth of successful tubing test. Test above EZSV to 3,500 psi. 11. OTHER: Bleed casing and annulus pressures to zero. Freeze protect to 2,200' MD with diesel. 12. OTHER: Function all tubing and casing lock down screws. Repair and replace as necessary. Test 9-5/8" packoff to 5,000 psi for 30 minutes. 13. OTHER: Set a BPV. Remove well house and flow line. Level the pad as necessary. Riq Operations: 1. MIRU Nabors rig 27E. 2. Pull BPV. 3. Run and test TWC. 4. Nipple down tree. Nipple up and test BOPE to 4,000psi high, 250 psi low. Pull TWC. a. Ensure one set of rams are equipped to close around 7" tubulars. 5. Rig up E-Line. 6. Run in hole and jet cut tubing at 4,500' MD. AGI-10A Permit to Drill Application Page 7 • • 7. Circulate out freeze protect by circulating 9.8 ppg brine around tubing cut. i 8. Unseat hanger. „ , 9. Pull and lay down 7 tubing from the cut at 4,500 MD. 10. Rig up E-line. 11. Make up gauge ring /junk basket to drift 9-5/8" casing for EZSV. RIH and tag tubing stump. POH. 12. Make up USIT\GR\CCL. RIH, log from tubing stump to surface. 13. Make up EZSV for 9-5/8" 47# casing. RIH and set at --4100' MD, assuming no cement above this point. a. Set EZSV ~5' above a collar. 14. Rig down E-line. 15. Change out one set of rams to 9-5/8". Test to 4000 psi high, 250 psi low. 16. Make up 9-5/8" casing cutter. RIH (picking up singles) to approximately 3950' MD (100' below 13-3/8" casing shoe). Cut 9-5/8" casing, DO NOT cut in a collar. 17. Establish circulation through 13-3/8" x 9-5/8" annulus to verify cut. POOH. 18. Spear 9-5/8" 47# casing. Circulate as required to clear annulus, records indicate annulus should be free of arctic pack. Pull and lay down same. 19. Change rams back to variables. Test to 4000 psi high, 250 psi low. 20. Pick up 12-1/4" bit and 13-3/8" casing scraping assembly. RIH, scraping 13-3/8" casing and cleaning out to the 9-5/8" stump. Space out the casing scraper as required. POOH, lay down assembly. 21. RIH with 5" DP to the top of the EZSV at 4100'. Lay in a cement plug with open ended 5" drill pipe. Approximately 70 barrels of cement will be placed from EZSV (4100') to 200' inside of the 13-3/8" surface ~ casing (3650' MD). POOH. a. Cement volumes based on the following calculations: i. 100' of 9-5/8" 47# casing (cap = 0.0732 bpf): 7.3 bbls ii. 150' of 12-1/4" OH (cap = 0.1458 bpf) + 50% excess: 32.8 bbls iii. 200' of 13-3/8" 68# casing (cap = 0.1497 bpf): 30 bbls ~' 22. Pick up the remainder of the drill pipe and rack in derrick while waiting on cement to reaches 3000 psi compressive strength. The Kick-off Plug RP recommends waiting a minimum of 12 hours. ~ 23. Make up and RIH with 12-1/4" drilling assembly. d`- 24. Circulate the hole to 9.1 ppg mud. Test the casing and cement top to 3500 psi. Chart for 30 minutes. ~ 25. Dress off cement plug to kick off point at 3870' MD. Time mill to kick off. Drill 20' of new formation. ~ 26. Conduct Leak-off Test. Targeting a minimum FIT of 11.0 ppg. 27. Drill the 12-1/4" intermediate hole to the BHRZ at approximately 9475' MD. Increase MW as nec ry until ~,. 200 ft above the HRZ. At 200 ft above the HRZ, the MW must be adjusted to a minimum weight ofpg. '~, ~ 28. At casing point, circulate the well clean. POOH. ' 29. Change out one set of rams to 9-5/8". Test to 4000 psi high, 250 psi low. /- 30. Run 9-5/8" production casing, with premium threads to TD. Land same. 31. Cement 9-5/8" production casing to 4000' MD. Pump freeze protection down the outer annulus. ~ 32. Change rams back to variables. Test to 4000 psi high, 250 psi low. ~ 33. Make up and RIH to the landing collar with the 8-1/2"drilling assembly. 34. Test the 9-58" casing to TD to 4000 psi (4500 psi equivalent). Chart test for 30 minutes. 35. Drill out the 9-5/8" float equipment to the shoe. 36. Circulate the well over to 8.6 ppg solids free Flo Pro drilling fluid. 37. Drill out the shoe, plus 20' of new formation. 38. Conduct FIT to 10.0 ppg EMW. / 39. Drill 8-1/2" hole to TD at 9932' MD. ~ 40. Circulate the well bore clean, short tip to the shoe. Circulate bottoms up. POOH. 41. Pickup and RIH with 7" slotted/perforated production liner. 42. At TD, release from liner. Set lin r t p hanger/packer. POOH. 43. Change out one set of rams to -5/8' for Schlumberger lubricator. Test to 4000 psi high, 250 psi low. AGI-10A Permit to Drill Application Page 8 • • 44. Rig up E-line. Run 9-5/8" USIT\GR\CCL from 7" liner top to surface. Rig down E-line. /~ 45. Change out the 9-5/8" rams to 7-5/8" for running tubulars. Test to 4000 psi high, 250 psi low. 46. Make up and run 7-5/8" internally plastic coated (IPC) completion string. 47. Reverse circulate corrosion inhibitor and diesel freeze protection sufficient for annular freeze protection to 2200' MD. 48. Drop the ball and rod. Set the packer and immediately bring pressure up to tubing test pressure of 4000 psi. Chart this test for 30 minutes. Bleed the tubing pressure to 2000 psi. Increase the annular pressure to 4000 ~- psi. Chart this test for 30 minutes. Notify the AOGCC to witness tubing and annular pressure test. 49. Bleed the annulus pressure to zero. Bleed the tubing pressure to zero. 50. Set and test a TWC to 1000 psi. 51. Change rams back to variables. Nipple down the BOPE. 52. Nipple up and test the tree to 5000 psi. Lubricate out the TWC. 53. Rig up slickline. Pull the ball and rod. Rig down slickline. 54. Bullhead diesel freeze protection fluid down the tubing, sufficient to freeze protect 2200' of 7-5/8" tubing. 55. Secure the well with a BPV. RDMO. Post-Rig Operations: 1. Set SSSV injection valve. 2. Install well house and instrumentation AGI-10A Permit to Drill Application Page 9 • ~ Drilling Hazards and Contingencies POST THIS NOTICE IN THE DOGHOUSE I. Well Control A. The Ivishak in this fault block is expected to be under-pressured at 8.1 ppg EMW. This pressure is estimated based on offset well pressures. II. Lost Circulation/Faults A. No faults are anticipated to be crossed by the AGI-10A injector well. Several faults, however, are in the proximity of the proposed well. The two closest faults are given below. The first fault is a SW-NE trending fault with 30-40 ft. of throw down to the N anticipated. Fault #1 is located approximately 240 ft. north of the polygon. The second fault is a NW-SE trending fault with 20-40 ft. of throw down to the NE anticipated. The tip out of this fault is located approximately 275 ft. to the SE of the polygon. III. Kick Tolerance/Integrity Testing A. The Kick Tolerance for the intermediate hole section is 161 bbls with 9.9 ppg mud, 11 ppg FIT, and an 8.9 ppg pore pressure the casing shoe. This FIT should prove up adequate formation strength for expected ECD's. B. Recent sidetrack AGI-07A experienced gas cut mud in the reservoir, although reservoir pressure was predicted at 7.7 ppg. After weighting up to 9.0+ ppg the gas ceased, but minor static losses ensued and did not cease throughout the remainder of the well and completion. Gas-detection/mud logging equipment will be available to aid the mud weight decision c ss if gas cut mud occurs in this well. C. The Kick Tolerance for the production hole section is i finite ith 8.6 ppg mud, 9.5 ppg FIT, and an 8.1 ppg pore pressure. This FIT should prove up adequa ation strength for expected ECD's. IV. Integrity Testing Test Point Test Depth Test type EMW (Ibl al) 121/a" KO 20-ft min new formation FIT 11.0 min 9 5/8" shoe 20-ft minimum from the 7" shoe FIT 9.5 min V. Stuck Pipe A. Stuck pipe not anticipated. B. There could be slight differential sticking issues within the reservoir, though risk is considered minimal with the short, vertical, slotted liner completion. VI. Hydrogen Sulfide A. AGI is not esignated as an N2S site since samples are not taken on the pad, however Standard Operating Procedures for H2S precautions should be followed at all times. VIII. Anti-Collision Issues A. All wells pass major risk close approach criteria. The closest well is AGI-09 at 177' ctr-ctr (57' allowable deviation) at 3,875' planned MD. AGI-10A Permit to Drill Application Page 10 ELLHEAb= CM/ ACTUATOR= BAKER C KB. ELEV = 49' BF. ELEV = KOP = 1300' - Max Angle = _. 43 @ 6323' Datum MD = 10741' Datum TV D= 8800' SS NOTES: LINER NOT CEMENTED. A G I.1 O ALL TBG IS IPC W ITH NSCC THREAD. 2205' 7" CAMCO BAL-O SSSV NIP, ID = 5.937" 13-3/8" CSG, 68#, NT-80, ID = 12.415" 3846' I7" TBG, 26#, NT-80-IPC, NSCC, .0383 bpf , ID = 6.276"~ 9351' TOP OF 5-1/2" TBG 9351' Minimum ID = 4.455" @ 9423' 5-1 /2" OTIS XN NIPPLE TOP OF 7" LNR ~~ 9409' 93517" X 5-1 /2" XO, ID = 4.875" 9355' 9-5/8" X 5-1/2"BKR SB-3A HYDROSET PERM PKR, ID = 4.875" 9402' I~ 5-1/2" PARKER SWS NIP, ID = 4.562" 5-1/2" OTIS XN NIP, ID = 4.455" 5-1/2" TBG, 17#, NT-80-IPC, NSCC, .0232 bpf, ID = 4.892"~-I 9434' 9-5/8" CSG, 47#, NT-80, ID = 8.681" I~ 9661' PERFORATION SUMMARY REF LOG: BHCS 03/28/93 ANGLE AT TOP PERF: 37 @ 9860' Note: Refer to Production DB for historical perf data SIZE SPF INTERVAL Opn/Sqz DATE 3-3/8" 6 9860 - 9880 O 06/18/93 3-3/8" 6 9910 - 9930 O 06/18/93 3-3/8" 6 9942 - 9952 O 06/18/93 3-3/8" 6 10007 - 10017 O 06/18/93 3-3/8" 6 10090 - 10110 O 06/18/93 3-3/8" 6 10156 - 10176 O 06/18/93 PBTD 10230' 7" LNR, 29#, L-80,.0371 bpf, ID = 6.184" 10251' 9434' I~ 5-1/2" WLEG, ID = 4.892" 9415' ELMD TT LOGGED 06/18/93 DATE REV BY COMMENTS DATE REV BY COMMENTS 04/01/93 ORIGINAL COMPLETION 01/29/01 SIS-MD FINAL 05/23/01 RN/KAK CORRECTIONS 03/18!03 AS/TLH ADD 1PC/THREAD FOR TBG PRUDHOE BAY UNff WELL: AGI-10 PERMIT No: 1930390 API No: 50-029-22353-00 Sec. 36, T12N, R14E, 2808.63 FEL 5240.67 FNL BP Exploration (Alaska) TREE _ (IVELLHEA'D = CNV ACTUATOR= BAKERC KB. ELEV..- 49' BF. ELEV..- KOP = 1300' Max Angle = 43 @ 6323' Datum MD = 10741' Datum TV D = 8800' SS AG~ OA Proposed 13-3/8" CSG, 68#, L-80, ID = 12.415" 3846' Minimum ID = 5.770" @ 9360' 7" HES RN NIPPLE TOP OF 9 5/8" 4000' 9 5/8" ¢SV 4100' Top of 7" 4500' 7" EZSV -5000' NOTES: 2160' 7 5/8" x 7" XO 2200' 7 CAMCO DB SSSV NIP, ID = 6.0" TGII TO VA M TOP HC X-OVER 2240' 7" x 7 5/8" XO 7 5/8" TBG, 29.7#, L-80-IPC, VAM TOP HC, ID = 6.875", 0.04591 BBL/FT 7 5/8" x 7" 26# TGII TO VAM 9250' TOP HC XO 9260' 7" R Nipple, ID = 5.963" 9 5/8" x 7" Baker S-3 Pkr, 7" 9280' \ 9300' 26# TGII, ID = 6.059" 7" RN Nipple, ID = 5.770" \ \ 9325' Packer w / 10' TBS (7.5" ID) \1 26# BTC TOP OF 7" LNR 9409' ~ 9329' 7" 26# TGII WLEG 9-5/8" CSG, 47#, NT-80-S, ID = 8.681" 9661' J I r ~ l ~ ` ` I 9475' I~ 0 0732D1 BB $~. L-80, PERFORATION SUMMARY REF LOG: BHCS 03/28/93 ANGLE AT TOP PERF: 37 @ 9860' Note: Refer to Production DB for historical pert data SIZE SPF INTERVAL Opn/Sqz DATE 7" LNR, 29#, L-80, .0371 bpf, ID = 6.184" ~ 10251' DATE REV BY COMMENTS DATE REV BY COMMENTS 04/01/93 Original Completion 01/29/01 SIS/MD Final 05/23/01 RWKAK Corrections 03/18/03 AS/TLH Add IPC and thread for tubing 9855' 7" 26# L-80 Slotted PBTD 9932' 7" 26# TD PRUDHOE BAY UNff WELL: AGI-10A PERMff No: 1930390 API No: 50-029-22353-01 SEC 36, T12N, R14E, 2808.63' FEL & 5240.67' FNL BP Exploration (Alaska) 0 . F < ~ ~ Q ~ F p 7.nN-v 7.n-N-nN-'yy~CaJUmv, rnm[a,~ »»UC:VC~vl v'~~~2~NUUn~1 ~-NOv¢i r ~ .r t-. 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Z ~c~.J~ LtJ N .Drrrl .._ c T ~Yt~ nt ., - _ ve p LTx . - F 7rlx.D xMa- Y r x Y MMM•z naa .._ zr`in M: ~ D 'r• p =- L _ ~~na QQa -NMv °o N } d ~.. i:l 3 x ~:. ~~ T ~ - =r r • S err -Sun P Y BP Planning Report Company: BP Amoco Date: 9/13/2006 "Lyme: 14:09:36 Page: 1 Field: Prudhoe Bay (various) Co-ordinate(NE) Reference: WeIL AGl-10, True North Site: AGI Vertical (TVD) Reference:. 32.5 + 13.6 46.1 Well: .AGI-10 Section (VS) Reference: Well (O.OON,O.OOE,63.18Azi) Wellpath: Plan AGI-10A Survey Calculation Method: Minimum Curvature Db: Oracle Plan: AGI-10A wp02 Date Composed: 5/23/2006 Version: 8 Principal: Yes Tied-to: From: Definitive Path Field: Prudhoe Bay (various) Map System: US State Plane Coordinate System 1927 Map Zone: Alaska, Zone 4 Geo Datum: NAD27 (Clarke 1866) Coordinate System: Well Centre Sys Datum: Mean Sea Level Geomagnetic Model: bggm2005 Site: AGI TR-12-14 UNITED STATES :North Slope Site Position: Northing: 5973288.42 ft Latitude: 70 19 55.268 N From: Map Easting: 685006.87 ft Longitude: 148 29 57.054 W Position Uncertainty: 0.00 ft North Reference: True Ground Level: 0.00 ft Grid Convergence: 1.41 deg Well: AGI-10 Slot Name: AGI-10 Well Position: +N/-S 6901.07 ft Northing: 5980281.94 ft Latitude: 70 21 3.130 N +E/-W 3850.84 ft Easting : 688686.10 ft Longitude: 148 28 4.511 W Position Uncertainty: 0.00 ft Casing Points MD TVD Diameter Hole Size Name ft ft in in 9475.01 8046.10 9.625 12.250 9 5/8" 9931.10 8415.65 7.000 8.500 7" Formations MD TVD Formations Lithology Dip Angle Dip Direction ft ft deg deg 3881.98 3501.10 SV4 0.00 0.00 4353.12 3896.10 SV3 0.00 0.00 4550.58 4056.10 SV2 0.00 0.00 5038.09 4451.10 SV1 0.00 0.00 5581.13 4891.10 UG4 0.00 0.00 5618.16 4921.10 UG4A 0.00 0.00 6179.72 5376.10 UG3 0.00 0.00 6722.76 5816.10 UG1 0.00 0.00 7309.00 6291.10 WS2 0.00 0.00 7463.28 6416.10 WS1 0.00 0.00 7599.04 6526.10 CM3 0.00 0.00 8407.43 7181.10 CM2 0.00 0.00 8993.67 7656.10 CM1 0.00 0.00 9222.00 7841.10 THRZ 0.00 0.00 9425.64 8006.10 LCU 0.00 0.00 9475.01 8046.10 42S6 0.00 0.00 9499.69 8066.10 TCGL 0.00 0.00 9567.57 8121.10 BCGL 0.00 0.00 9653.97 8191.10 23S6 0.00 0.00 9678.65 8211.10 22TS 0.00 0.00 9721.85 8246.10 21TS 0.00 0.00 9820.58 8326.10 TZ1 B 0.00 0.00 9863.78 8361.10 TDF 0.00 0.00 9894.63 8386.10 BSAD 0.00 0.00 Targets Map Map ~-- Latitude. --> <-.Longitude -> Name Description TVD +N/-S +E/-W Northing Easting Deg Min.. Sec Deg Min Sec , Dip. Dir. ft ft ft ft ft AGI-10A T1 8416.10 2194.59 4340.80 5982585.01 692970.00 70 21 24.701 N 148 25 57.613 W -Circle (Radius: 300) Sperry-Sun BP Planning Report Company: BP Amoco Date: 9/13/2006 Timer 14:09:36 Pager 2 Field: Prudhoe Bay{various) Co-ordinate(NE) Reference: WeIL' AGI-10, True North Site: AGI Vertical (TVD) Reference:. 32. 5 + 13.fi 46:1 Well: AGI-10 Section (VS) Reference: Well (O.OON,O.OOE;63.18Azi) Wellpath: Plan AGI-10A Survey Calculation Method: Minimum Curvature . Db: draGe Targets Map Map <-- Latitude --> <- Longitude -> Name Description TVD +N/-S +E/-W Northing Easting Deg Min Sec 'Deg Mi n Sec Dip. Dir. ft ft ft ft ft -Plan hit target AGI-10A Fault 1 8416 .10 2370.57 2914.69 5982725.01 691540.00 70 21 26.439 N 148 26 39.301 W -Polygon 1 8416 .10 2370.57 2914.69 5982725.01 691540.00 70 21 26.439 N 148 26 39.301 W -Polygon 2 8416 .10 2549.76 3386.38 5982916.01 692007.00 70 21 28.199 N 148 26 25.509 W -Polygon 3 8416 .10 2692.13 5041.59 5983100.01 693658.00 70 21 29.590 N 148 25 37.116 W -Polygon 4 8416 .10 2549.76 3386.38 5982916.01 692007.00 70 21 28.199 N 148 26 25.509 W -Plan out by 1436.92 at 8416 .10 2194.59 4340.80 5982585.01 692970.00 70 21 24.701 N 148 25 57.613 W AGI-10A Fault 2 8416 .10 1785.07 4196.43 5982172.01 692836.00 70 21 20.674 N 148 26 1.840 W -Polygon 1 8416 .10 1785.07 4196.43 5982172.01 692836.00 70 21 20.674 N 148 26 1.840 W -Polygon 2 8416 .10 1332.57 4448.13 5981726.01 693099.00 70 21 16.223 N 148 25 54.490 W -Polygon 3 8416 .10 894.43 4844.25 5981298.01 693506.00 70 21 11.911 N 148 25 42.919 W -Polygon 4 8416 .10 1332.57 4448.13 5981726.01 693099.00 70 21 16.223 N 148 25 54.490 W -Plan out by 434 .22 at 8416 .10 2194.59 4340.80 5982585.01 692970.00 70 21 24.701 N 148 25 57.613 W Plan Section Information MD Incl Azim TVD +N/-S +E/-W DLS Build Turn TFO Target ft deg deg ft ft ft deg/100ft deg/100ft deg/100ft deg 3860.00 40.05 63.50 3484.16 637.70 1162.48 0.00 0.00 0.00 0.00 4160.00 28.05 63.50 3732.29 712.52 1312.51 4.00 -4.00 0.00 180.00 4355.92 35.88 63.93 3898.38 758.38 1405.45 4.00 4.00 0.22 1.86 9931.66 35.88 63.93 8416.10 2194.59 4340.80 0.00 0.00 0.00 0.00 AGI -10A T1 Survey MD Incl Azim TVD Sys TVD VS N/S E/W DLS MapN MapE TooUCo ft deg deg ft ft ft ft ft deg/100ft ft ft 3857.10 40.06 63.49 3481.95 3435.85 1323.29 636.87 1160.81 0.00 5980947.80 689830.44 Start Dir 4/ 3860.00 40.05 63.50 3484.16 3438.06 1325.15 637.70 1162.48 0.56 5980948.67 689832.08 MWD+IFR 3881.98 39.17 63.50 3501.10 3455.00 1339.17 643.96 1175.02 4.00 5980955.24 689844.46 SV4 3900.00 38.45 63.50 3515.14 3469.04 1350.46 648.99 1185.12 4.00 5980960.53 689854.44 MWD+IFR 4000.00 34.45 63.50 3595.57 3549.47 1409.85 675.50 1238.28 4.00 5980988.36 689906.90 MWD+IFR 4100.00 30.45 63.50 3679.94 3633.84 1463.49 699.44 1286.28 4.00 5981013.50 689954.28 MWD+IFR 4160.00 28.05 63.50 3732.29 3686.19 1492.80 712.52 1312.51 4.00 5981027.24 689980.18 MWD+IFR 4200.00 29.65 63.60 3767.32 3721.22 1512.10 721.11 1329.79 4.00 5981036.27 689997.23 MWD+IFR 4300.00 33.64 63.82 3852.44 3806.34 1564.55 744.34 1376.82 4.00 5981060.67 690043.66 MWD+IFR 4352.79 35.75 63.92 3895.84 3849.74 1594.60 757.57 1403.80 4.00 5981074.57 690070.30 End Dir 4353.12 35.77 63.92 3896.10 3850.00 1594.79 757.65 1403.97 4.00 5981074.66 690070.47 SV3 4355.92 35.88 63.93 3898.38 3852.28 1596.43 758.38 1405.45 4.00 5981075.42 690071.92 MWD+IFR 4400.00 35.88 63.93 3934.09 3887.99 1622.26 769.73 1428.65 0.00 5981087.35 690094.83 MWD+IFR 4500.00 35.88 63.93 4015.11 3969.01 1680.87 795.49 1481.30 0.00 5981114.43 690146.81 MWD+IFR 4550.58 35.88 63.93 4056.10 4010.00 1710.51 808.52 1507.93 0.00 5981128.12 690173.10 SV2 4600.00 35.88 63.93 4096.14 4050.04 1739.47 821.25 1533.94 0.00 5981141.50 690198.79 MWD+IFR 4700.00 35.88 63.93 4177.16 4131.06 1798.08 847.01 1586.59 0.00 5981168.58 690250.76 MWD+IFR 4800.00 35.88 63.93 4258.19 4212.09 1856.68 872.76 1639.23 0.00 5981195.65 690302.74 MWD+IFR 4900.00 35.88 63.93 4339.21 4293.11 1915.28 898.52 1691.88 0.00 5981222.72 690354.72 MWD+IFR 5000.00 35.88 63.93 4420.24 4374.14 1973.89 924.28 1744.52 0.00 5981249.80 690406.69 MWD+IFR 5038.09 35.88 63.93 4451.10 4405.00 1996.21 934.09 1764.58 0.00 5981260.11 690426.49 SV1 5100.00 35.88 63.93 4501.26 4455.16 2032.49 950.04 1797.17 0.00 5981276.87 690458.67 MWD+IFR 5200.00 35.88 63.93 4582.29 4536.19 2091.09 975.80 1849.81 0.00 5981303.95 690510.65 MWD+IFR 5300.00 35.88 63.93 4663.31 4617.21 2149.70 1001.56 1902.46 0.00 5981331.02 690562.62 MWD+IFR 5400.00 35.88 63.93 4744.34 4698.24 2208.30 1027.31 1955.10 0.00 5981358.10 690614.60 MWD+IFR 5500.00 35.88 63.93 4825.36 4779.26 2266.91 1053.07 2007.75 0.00 5981385.17 690666.58 MWD+IFR 5581.13 35.88 63.93 4891.10 4845.00 2314.45 1073.97 2050.46 0.00 5981407.14 690708.75 UG4 5600.00 35.88 63.93 4906.39 4860.29 2325.51 1078.83 2060.39 0.00 5981412.24 690718.55 MWD+IFR 5618.16 35.88 63.93 4921.10 4875.00 2336.15 1083.51 2069.95 0.00 5981417.16 690727.99 UG4A 5700.00 35.88 63.93 4987.41 4941.31 2384.11 1104.59 2113.04 0.00 5981439.32 690770.53 MWD+IFR Went S err -Sun P Y BP Planning Report Company: BP Amoco Date: 9/13/2006 Time: 14:09:36 Pager 3 Field: Prudhoe Bay (various) Co-ordinate(NE) Reference: Well: AGI-10, True North Site: AG I Vertical (TVD) Reference: 32. 5 + 13.6 46:1 Well; AG I-10 Section (VS) Reference: Well (O.OON,O.OOE,63.18Azi) Wellpath: Plan AGI-10A Survey Calculation Method: Minimum Curvature Db: . Oracle Survey MD Incl Azim TVD Sys TVD VS N/S E/W DLS MapN MapE Tool/Co ft deg deg ft ft ft ft ft deg/100ft ft ft 5800.00 35.88 63.93 5068.44 5022.34 2442.72 1130.35 2165.68 0.00 5981466.39 690822.51 MWD+IFR 5900.00 35.88 63.93 5149.46 5103.36 2501.32 1156.11 2218.33 0.00 5981493.47 690874.48 MWD+IFR 6000.00 35.88 63.93 5230.48 5184.38 2559.93 1181.86 2270.97 0.00 5981520.54 690926.46 MWD+IFR 6100.00 35.88 63.93 5311.51 5265.41 2618.53 1207.62 2323.62 0.00 5981547.62 690978.44 MWD+IFR 6179.72 35.88 63.93 5376.10 5330.00 2665.25 1228.16 2365.59 0.00 5981569.20 691019.87 UG3 6200.00 35.88 63.93 5392.53 5346.43 2677.13 1233.38 2376.26 0.00 5981574.69 691030.41 MWD+IFR 6300.00 35.88 63.93 5473.56 5427.46 2735.74 1259.14 2428.91 0.00 5981601.76 691082.39 MWD+IFR 6400.00 35.88 63.93 5554.58 5508.48 2794.34 1284.90 2481.55 0.00 5981628.84 691134.37 MWD+IFR 6500.00 35.88 63.93 5635.61 5589.51 2852.94 1310.66 2534.20 0.00 5981655.91 691186.34 MWD+IFR 6600.00 35.88 63.93 5716.63 5670.53 2911.55 1336.41 2586.84 0.00 5981682.99 691238.32 MWD+IFR 6700.00 35.88 63.93 5797.66 5751.56 2970.15 1362.17 2639.49 0.00 5981710.06 691290.30 MWD+IFR 6722.76 35.88 63.93 5816.10 5770.00 2983.49 1368.04 2651.47 0.00 5981716.22 691302.13 UG1 6800.00 35.88 63.93 5878.68 5832.58 3028.76 1387.93 2692.13 0.00 5981737.14 691342.27 MWD+IFR 6900.00 35.88 63.93 5959.71 5913.61 3087.36 1413.69 2744.78 0.00 5981764.21 691394.25 MWD+IFR 7000.00 35.88 63.93 6040.73 5994.63 3145.96 1439.45 2797.42 0.00 5981791.28 691446.23 MWD+IFR 7100.00 35.88 63.93 6121.76 6075.66 3204.57 1465.21 2850.07 0.00 5981818.36 691498.20 MWD+IFR 7200.00 35.88 63.93 6202.78 6156.68 3263.17 1490.96 2902.71 0.00 5981845.43 691550.18 MWD+IFR 7300.00 35.88 63.93 6283.81 6237.71 3321.78 1516.72 2955.36 0.00 5981872.51 691602.16 MWD+IFR 7309.00 35.88 63.93 6291.10 6245.00 3327.05 1519.04 2960.10 0.00 5981874.94 691606.84 WS2 7400.00 35.88 63.93 6364.83 6318.73 3380.38 1542.48 3008.00 0.00 5981899.58 691654.13 MWD+IFR 7463.28 35.88 63.93 6416.10 6370.00 3417.46 1558.78 3041.32 0.00 5981916.71 691687.02 WS1 7500.00 35.88 63.93 6445.86 6399.76 3438.98 1568.24 3060.65 0.00 5981926.65 691706.11 MWD+IFR 7599.04 35.88 63.93 6526.10 6480.00 3497.02 1593.75 3112.79 0.00 5981953.47 691757.59 CM3 7600.00 35.88 63.93 6526.88 6480.78 3497.59 1594.00 3113.29 0.00 5981953.73 691758.09 MWD+IFR 7700.00 35.88 63.93 6607.90 6561.80 3556.19 1619.76 3165.94 0.00. 5981980.80 691810.06 MWD+IFR 7800.00 35.88 63.93 6688.93 6642.83 3614.79 1645.51 3218.59 0.00 5982007.88 691862.04 MWD+IFR 7900.00 35.88 63.93 6769.95 6723.85 3673.40 1671.27 3271.23 0.00 5982034.95 691914.02 MWD+IFR 8000.00 35.88 63.93 6850.98 6804.88 3732.00 1697.03 3323.88 0.00 5982062.03 691965.99 MWD+IFR 8100.00 35.88 63.93 6932.00 6885.90 3790.61 1722.79 3376.52 0.00 5982089.10 692017.97 MWD+IFR 8200.00 35.88 63.93 7013.03 6966.93 3849.21 1748.55 3429.17 0.00 5982116.17 692069.95 MWD+IFR 8300.00 35.88 63.93 7094.05 7047.95 3907.81 1774.31 3481.81 0.00 5982143.25 692121.92 MWD+IFR 8400.00 35.88 63.93 7175.08 7128.98 3966.42 1800.06 3534.46 0.00 5982170.32 692173.90 MWD+IFR 8407.43 35.88 63.93 7181.10 7135.00 3970.77 1801.98 3538.37 0.00 5982172.34 692177.76 CM2 8500.00 35.88 63.93 7256.10 7210.00 4025.02 1825.82 3587.10 0.00 5982197.40 692225.88 MWD+IFR 8600.00 35.88 63.93 7337.13 7291.03 4083.63 1851.58 3639.75 0.00 5982224.47 692277.85 MWD+IFR 8700.00 35.88 63.93 7418.15 7372.05 4142.23 1877.34 3692.39 0.00 5982251.55 692329.83 MWD+IFR 8800.00 35.88 63.93 7499.18 7453.08 4200.83 1903.10 3745.04 0.00 5982278.62 692381.81 MWD+IFR 8900.00 35.88 63.93 7580.20 7534.10 4259.44 1928.86 3797.68 0.00 5982305.69 692433.78 MWD+IFR 8993.67 35.88 63.93 7656.10 7610.00 4314.33 1952.98 3847.00 0.00 5982331.06 692482.47 CM1 9000.00 35.88 63.93 7661.23 7615.13 4318.04 1954.61 3850.33 0.00 5982332.77 692485.76 MWD+IFR 9100.00 35.88 63.93 7742.25 7696.15 4376.64 1980.37 3902.97 0.00 5982359.84 692537.74 MWD+IFR 9200.00 35.88 63.93 7823.28 7777.18 4435.25 2006.13 3955.62 0.00 5982386.92 692589.71 MWD+IFR 9222.00 35.88 63.93 7841.10 7795.00 4448.14 2011.80 3967.20 0.00 5982392.87 692601.15 THRZ 9300.00 35.88 63.93 7904.30 7858.20 4493.85 2031.89 4008.26 0.00 5982413.99 692641.69 MWD+IFR 9400.00 35.88 63.93 7985.32 7939.22 4552.46 2057.65 4060.91 0.00 5982441.07 692693.67 MWD+IFR 9425.64 35.88 63.93 8006.10 7960.00 4567.48 2064.25 4074.40 0.00 5982448.01 692706.99 LCU 9475.01 35.88 63.93 8046.10 8000.00 4596.41 2076.97 4100.39 0.00 5982461.37 692732.65 9 5/8" 9499.69 35.88 63.93 8066.10 8020.00 4610.88 2083.33 4113.39 0.00 5982468.06 692745.48 TCGL 9500.00 35.88 63.93 8066.35 8020.25 4611.06 2083.41 4113.55 0.00 5982468.14 692745.64 MWD+IFR 9567.57 35.88 63.93 8121.10 8075.00 4650.66 2100.81 4149.13 0.00 5982486.43 692780.76 BCGL 9600.00 35.88 63.93 8147.37 8101.27 4669.6& 2109.16 4166.20 0.00 5982495.21 692797.62 MWD+IFR 9653.97 35.88 63.93 8191.10 8145.00 4701.29 2123.07 4194.61 0.00 5982509.82 692825.67 23SB 9678.65 35.88 63.93 8211.10 8165.00 4715.76 2129.42 4207.60 0.00 5982516.51 692838.50 22TS Went ~S ~S ~S 4S 4S ~S ~S 4S ~S ~S 1S 1S 1S 1S 1S 4S 4S ~S ~S 7S 4S 4S qS 4S ~S ~S 1S 7S 7S 1S 7S 7S 7S 4S 4S ~S 4S ~S AS Sperry-Sun BP Planning Report Company: BP Amoco Date: 9/13/2006 Time: 14;09:36 Page: 4 Field: Prudhoe Bay (various) Co-ordinate(NE) Reference: Well: AGI-10, True Nortl~ Site:. AGI Vertical (TVD) Reference: 32.5 + 13.6 46.1 Well: AGI-10 Section (VS) Reference: Well (O.OON,O.OOE,63.18Azi) Wellpath: Plan AGI-10A Survey Calculation Method: Minimum Curvature Db: Oracle Survey MD Incl Azim TVD Sys TVD VS N/S E/W DLS MapN MapE TooUCo ft deg deg ft ft ft ft ft deg/100ft ft ft 9700.00 35.88 63.93 8228.40 8182.30 4728.27 2134.92 4218.84 0.00 5982522.29 692849.60 MWD+IFR 9721.85 35.88 63.93 8246.10 8200.00 4741.07 2140.55 4230.34 0.00 5982528.20 692860.95 21TS 9800.00 35.88 63.93 8309.42 8263.32 4786.87 2160.68 4271.49 0.00 5982549.36 692901.57 MWD+IFR 9820.58 35.88 63.93 8326.10 8280.00 4798.93 2165.98 4282.32 0.00 5982554.93 692912.27 TZ1 B 9863.78 35.88 63.93 8361.10 8315.00 4824.25 2177.11 4305.06 0.00 5982566.63 692934.72 TDF 9894.63 35.88 63.93 8386.10 8340.00 4842.33 2185.06 4321.31 0.00 5982574.98 692950.76 BSAD 9900.00 35.88 63.93 8390.45 8344.35 4845.48 2186.44 4324.13 0.00 5982576.44 692953.55 MWD+IFR 9931.10 35.88 63.93 8415.65 8369.55 4863.70 2194.45 4340.50 0.00 5982584.86 692969.71 7" 9931.66 35.88 63.93 8416.10 8370.00 4864.03 2194.59 4340.80 0.00 5982585.01 692970.00 AGI-10A T • • -Terri Hubble ss-si,ssz .303 BP Exploration AK lnc. °nnasLercard-Check" PO Box_196612 MB 7-5 .Anchorage, AK 9951:.9 ~-, a~'~~p DATE PAY TO THE ~ /~ + `~ O R OF !/ W DOLLARS Fir National Bank: Alaska Anchorage AK:I99501 MEMO- _ 1 ~ (~ ~: ~ 25 200060x:99 L46 2227 L-55.611' 0303 • • TRANSMITTAL LETTER CI-IECKLIST WELL NAME _~~~/ /9 f -- ~0~~_ PTD# 2 ~~ = ~-~~ Development ~ Service Exploratory Stratigraphic Vest Non-Conventional Well Circle Appropriate Letter /Paragraphs to be Included in Transmittal Letter CHECK j ADD-ONS ! TEXT FOR APPROVAL LETTER WHAT ~ (OPTIONS) j APPLIES MliLTI LATERAL I The permit is for a new wellbore segment of existing ~ well j j (If [ast two digits in API number are ~ Permit No. , API No. 50- - _ i between 60-69) Production should continue to be reported as a function of the original API number stated above. PILOT HOLE In accordance with 20 AAC 25.00~(f), all records, data and togs I acquired for the pilot hole must be clearly differentiated in both I i i well name ( PH) and API number ~ ! (~0- - -_) from records, data and logs j 1 I acquired for well i i SPACING EXCEPTION i I ~ The permit is approved subject to full compliance with 20 AAC ~ ~ 25.055. Approval to perforate and roduce / in'ect 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 j 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. i ~ Non-Conventional i Please note the following special condition of this permit: , ~ Well production or production testing of coal bed methane is not allowed ~ for (name of well) until after (Companv Name) has designed and j implemented a water well testing program to provide baseline data ~ ; on water quality and quantity. Company Name) must contact the Commission to obtain advance approval of such water well testing j Rev: 1 125/06 C:`~jodyltransmittal checklist WELL PERMIT CHECKLIST Field & Pool PRUDHOE BAY, PRUDHOE OIL - 640150 _ __ Well Name: PRUDHOE BAY. UNIT AGI-10A Program SER _ _ Well bare seg ` ', PTD#:2061350 Company BP EXPLORATION (ALASKA) INC __. ___ _ _______ Initial Class/Type _ SER 11GINJ GeoArea 890_... __ ___ Unit 11650_..___ _ OnlOff Shore On Annular Disposal _', Administration '1 Permit fee atkached Yes ',2 -Lease number appropriate Yes ~,3 Unique well-name and number Yes 4 Well located in a defined pool - - - - Yes X15 Well located proper distance from drilling unit boundary Yes '6 Well located proper distance from other wells Yes 7 Sufficient acreage available in drilling unit- - - Yes ~I8 If deviated, is_wellbore plat included Yes _ ',9 Operator only affected party _ Yes _ _ 10 Operator has-appropriate bond in force Yes X11 Permit. can be issued without conservation order- - - Yes 12 Permit can be issued without administrative approval - Yes - - Appr Date '13 Can permit be approved before 15-day wait Yes RPC 9125/2006 14 Well located within area and strata authorized by Injection Order # (put-IO# in comments). (For Yes AIO 4C '15 All wells within 1!4_mile area of review identified (For service well only) Yes AGI-10, AGI-9, AGI.7A, LGI.12, W. BEACH 1-A 116 Pre-produced injector:. duration ofpre-production less than 3 months (Far ervice well only) NA X17 Nonconuen, gas conforms to AS31,05.030(~.1.A),(j,2.A-D) _ _ - - No- - - - - - - 18 Conductor String_provided NA- - _ __ - -- Engineering 1,19 Surface casing protects. all known USDWs NA - i20 CMT vol_ adequate. to circulate on conductor-& surf csg - NA - !21 CMT vol-adequate-to tie-in long string to-surf csg- Yes - - ',22 CMT will cover all known productive horizons No- - 123 Casing designs adeguaie for C, T, B &-permafrost- - - Yes X24 Adequate tankage-o_r reserve pit - Yes Nabors-27E, '25 If a-re-drill, has a 1 Q-403 for abandonment been approved Yes - 9!12/2006.. !,26 Adequate wellbore separation proposed- - - - - Yes - - - ~27 If diverterrequired; does it meet regulations- NA- _ _ ...Sidetrack.. ~i28 Drilling fluid program schematic & equip list adequate_ Yes Max MW 9,9 ppg. Appr Date 'x,29 BOPEs, do they meet regulation Yes - - WGA 9/29/2006 '30 BOPE press rating appropriate; test to-(pul prig in comments)- Yes Test to 40Q0 psi. MSP 2778 psi.- 131 1 Choke manifold complies w/API RP-53 (May 84) Yes 132 Work will occur without operation shutdown - Yes - - - _ _ ',33 Is presence_of H2S gas probable - _No- _ Not an H2$ pad. 34 Mechanical condition of wells within AOR verified (For service well only) Yes All AOR wells reviewed.. x,35 Permit can be issued w/o hydrogen sulfide measures No ---- Geology 136 Data. presented on-potential overpressure zones _ - NA x,37 Seismic analysisof shallow gas.zones NA _ Appr Date 38 Seabed condition survey (if cff-shore) NA- - - - - RPC 9/2512006 '39 Contact namelpho_ne for weekly-progress reports_[exploratoryon/y] NA_ - Geologic Engineering Date: c Date Date C Commissioner: Commissioner: l ?n, o mi er f • Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history. file. To improve the readability of the Well History file and to simplify finding infom~ation, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made 1o chronologically organize this category of information. i i agi-l0a.tapx Sperry-Sun Drilling Services LIS Scan utility $Revision: 3 $ LisLib $Revision: 4 $ Fri Jun 06 16:58:15 2008 Reel Header Service name .............LISTPE Date . ...................08/06/06 Ori 9in ...................STS Reel Name. .... ........UNKNOWN Continuation Number......01 Previous Reel Name.......UNKNOWN Comments .................STS LIS Writing Library. Tape Header Service name .............LISTPE Date . ...................08/06/06 Origin ...................STs Tape Name. .... ........UNKNOWN Continuation Number......01 Previous Tape Name.......UNKNOWN Comments .................STS LIS Writing Physical EOF scientific Technical services Library. scientific Technical services comment Record TAPE HEADER Greater Prudhoe say MWD/MAD LOGS WELL NAME: AGI-l0A API NUMBER: 500292235301 OPERATOR: BP Exploration (Alaska ) Inc. LOGGING COMPANY: Sperry Drilling Services TAPE CREATION DATE: 06-JUN-OS JOB DATA MWD RUN 1 MWD RUN 2 MWD RUN 3 JOB NUMBER: w-0004693375 w-0004693375 w-0004693375 LOGGING ENGINEER: N. WHITE N. WHITE B. TRANI OPERATOR WITNESS: C. CLEMENS C. CLEMENS B. DECKER MWD RUN 4 JOB NUMBER: w-0004693375 LOGGING ENGINEER: B. CARTWRIGH OPERATOR WITNESS: B. DECKER SURFACE LOCATION SECTION: 36 TOWNSHIP: 12N RANGE: 14E FNL: FSL: 2646 FEL: 2579 FWL: Page 1 V=~ ao~- l3S #~~ Y~~ agi-l0a.tapx ELEVATION (FT FROM MSL 0) KELLY BUSHING: DERRICK FLOOR: 46.50 GROUND LEVEL: 13.60 WELL CASING RECORD OPEN HOLE CASING DRILLERS BIT SIZE (IN) SIZE (IN) DEPTH (FT) 1sT STRING 12.125 13.375 3725.0 2ND STRING 8.500 9.625 9445.0 3RD STRING PRODUCTION STRING REMARKS: 1. ALL DEPTHS ARE MEASURED DEPTH (MD) UNLESS OTHERWISE NOTED. THESE DEPTHS ARE BIT DEPTHS. 2. ALL VERTICAL DEPTHS ARE TRUE VERTICAL DEPTH (TVD). 3. THIS WELLBORE EXITS THE AGI-10 WELLBORE BY MEANS OF A WHIPSTOCK, THE TOP OF WHICH WAS AT 3725'MD/3381'TVD. THE WHIPSTOCK WAS POSITIONED, THE WINDOW WAS MILLED, AND A BIT OF RAT HOLE WAS DRILLED DURING MWD RUN 1. 4. MWD RUNS 1-4 COMPRISED DIRECTIONAL, DUAL GAMMA RAY (DGR), UTILIZING GEIGER-MUELLER TUBE DETECTORS, AND PRESSURE WHILE DRILLING (PWD). UPHOLE MAD SGRC TIE-IN DATA WERE MERGED WITH RUN 1 MWD DATA. 5. LOG AND MERGED DIGITAL DATA ONLY (LDWG) WERE BLOCK-SHIFTED 4' UPHOLE, PER E-MAIL FROM DOUG DORTCH (SAIC/BP) DATED 6 JUNE 2008, AS AUTHORIZED BY DOUG STONER (BP). ALL LOG HEADER DATA RETAIN ORIGINAL DRILLER'S DEPTH REFERENCES. THIS SHIFTED MWD LOG BECOMES THE PDCL FOR AGI-lOA. 6. MWD RUNS 1-4 REPRESENT WELL AGI-lOA WITH API# 50-029-22353-01. THIS WELL REACHED A TOTAL DEPTH (TD) OF 9937'MD/8393'TVD. SROP = SMOOTHED RATE OF PENETRATION WHILE DRILLING. SGRC = SMOOTHED GAMMA RAY COMBINED. SLIDE = NON-ROTATED INTERVALS REFLECTING BIT DEPTHS. ALL DATA CURVES ARE SMOOTHED TO A STEP OF 0.5 FT, WITH A WINDOW OF 0.6 FT, EXCEPT FOR SROP AND SGRC. THESE CURVES ARE SMOOTHED WITH A 1.1 FT WINDOW. GAP FILL IS SET TO 5 FT FOR ALL CURVES. File Header Service name... .......STSLIB.001 Service sub Level Name... version Number. ........1.0.0 Date of Generation.......08/06/06 Page 2 • agi-l0a.tapx Maximum Physical Record..65535 ... File Type. ............LO Previous File Name.......STSLI6.000 comment Record FILE HEADER FILE NUMBER: 1 EDITED MERGED MWD Depth shifted and clipped curves; all bit runs merged. DEPTH INCREMENT: .5000 FILE SUMMARY PBU TOOL CODE START DEPTH STOP DEPTH GR 3522.5 9897.5 ROP 3721.0 9933.0 BASELINE CURVE FOR SHIFTS: CURVE SHIFT DATA (MEASURED DEPTH) --------- EQUIVALENT UNSHIFTED DEPTH --------- BASELINE DEPTH GR 3522.5 3526.5 $9933.0 9937.0 MERGED DATA SOURCE PBU TOOL CODE MWD MWD MWD MWD BIT RUN NO MERGE TOP 1 3526.5 2 3773.0 3 9445.0 4 9542.0 MERGE BASE 3773.0 9445.0 9542.0 9937.0 REMARKS: MERGED MAIN PASS. Data Format specification Record Data Record Type... ..........0 Data Specification Block Type.....0 Logging Direction .................DOwn Optical log depth units...........Feet Data Reference Point ..............undefined Frame Spacing....... ............60 .lIN Max frames per record .............undefined Absent value ......................-999 Depth Units. .. .. ..... Datum specification Block sub-type...0 Name service order units size Nsam Rep Code offset Channel DEPT FT 4 1 68 0 1 GR MWD API 4 1 68 4 2 ROP MWD FT/H 4 1 68 8 3 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 3522.5 9933 6727.75 12822 3522.5 9933 GR MwD API 11.37 404.86 82.6799 12751 3522.5 9897.5 ROP MWD FT/H 0.03 489.57 167.804 12425 3721 9933 First Reading For Entire File..........3522.5 Page 3 • agi-l0a.tapx Last Reading For Entire File...........9933 File Trailer Service name... .......STSLIB.001 service sub Level Name... version Number. ........1.0.0 Date of Generation.......08/06/06 Maximum Physical Record..65535 File TyL~e ................L0 Next File Name...........STSLIB.002 Physical EOF File Header Service name... .......STSLI6.002 service Sub Level Name... version Number. ........1.0.0 Date of Generation.......08/06/06 Maximum Physical Record..65535 File Type. ............LO Previous File Name.......STSLIB.001 Comment Record FILE HEADER FILE NUMBER: 2 RAW MWD Curves and log header data for each bit run in separate files. BIT RUN NUMBER: 1 DEPTH INCREMENT: .5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH STOP DEPTH GR 3526.5 3703.0 ROP 3725.0 3773.0 LOG HEADER DATA DATE LOGGED: 27-OCT-06 SOFTWARE SURFACE SOFTWARE VERSION: Insite DOWNHOLE SOFTWARE VERSION: 72.13 DATA TYPE (MEMORY OR REAL-TIME): Memory TD DRILLER (FT): 3773.0 TOP LOG INTERVAL (FT): 3725.0 BOTTOM LOG INTERVAL (FT): 3773.0 BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: 40.0 MAXIMUM ANGLE: 40.0 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE TOOL NUMBER DGR DUAL GAMMA RAY 76571 BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): 12.125 DRILLER'S CASING DEPTH (FT): 3725.0 BOREHOLE CONDITIONS Page 4 e • agi-l0a.tapx MUD TYPE: Fresh Water Gel MUD DENSITY (LB/G): 9.10 MUD VISCOSITY (S): 55.0 MUD PH: 9,5 MUD CHLORIDES (PPM): 13000 FLUID LOSS (C3): 3.0 RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT): .000 .O MUD AT MAX CIRCULATING TERMPERATURE: .000 110.0 MUD FILTRATE AT MT: .000 .O MUD CAKE AT MT: .000 .O NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF (IN): EWR FREQUENCY (HZ): REMARKS: Data Format specification Record Data Record Type... ..........0 Data specification Block Type.....0 Logging Direction .................DOwn optical log depth units...........Feet Data Reference Point ..............undefined Frame Spacing....... ............60 .lIN Max frames per record .............undefined Absent value ......................-999 Depth Units. .. .. ..... Datum Specification Block sub-type...0 Name Service order units size Nsam Rep code offset channel DEPT FT 4 1 68 0 1 GR MWDO10 API 4 1 68 4 2 ROP MWDO10 FT/H 4 1 68 8 3 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 3526.5 3773 3649.75 494 3526.5 3773 GR MWDO10 API 22.49 71.12 41.7229 354 3526.5 3703 ROP MWDO10 FT/H 0.03 38.56 13.3738 97 3725 3773 First Reading For Entire File..........3526.5 Last Reading For Entire File...........3773 File Trailer Service name... .......STSLI6.002 service sub Level Name... version Number. ........1.0.0 Date of Generation.......08/06/06 Maximum Physical Record..65535 File TyC~e ................L0 Next File Name...........STSLIB.003 Page 5 • Physical EOF File Header Service name... .......STSLIB.003 service sub Level Name... version Number. ........1.0.0 Date of Generation.......08/06/06 Maximum Physical Record..65535 File Type. ............LO Previous File Name.......sTSLIB.002 comment Record FILE HEADER FILE NUMBER: 3 RAW MWD agi-l0a.tapx i Curves and log header data for each bit run in separate files. BIT RUN NUMBER: 2 DEPTH INCREMENT: .5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH GR 3703.5 ROP 3773.5 LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME): TD DRILLER (FT): TOP LOG INTERVAL (FT): BOTTOM LOG INTERVAL (FT): BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: MAXIMUM ANGLE: TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE DGR DUAL GAMMA RAY BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER'S CASING DEPTH (FT): BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S): MUD PH: MUD CHLORIDES (PPM): FLUID LOSS (C3): RESISTIVITY (OHMM) AT TEMPERATURE (DEG F) MUD AT MEASURED TEMPERATURE (MT): MUD AT MAX CIRCULATING TERMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: NEUTRON TOOL STOP DEPTH 9399.5 9445.0 Page 6 28-NOV-06 Insite 72.13 Memory 9445.0 3773.0 9445.0 33.2 40.5 TOOL NUMBER 76571 12.250 3725.0 Fresh water Gel 9.10 55.0 9.5 13000 6.0 .000 .0 .000 110.0 .000 .0 .000 .0 agi-l0a.tapx MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF (IN): EWR FREQUENCY (HZ): REMARKS: Data Format specification Record Data Record Type... ..........0 Data specification Block Type.....0 Logging Direction .................Down Optical log depth units...........Feet Data Reference Point ..............undefined Frame Spacing....... ............60 .lIN Max frames per record .............undefined Absent value ......................-999 Depth Units. .. .. ..... Datum Specification Block sub-type...0 • Name service order units Size Nsam Rep Code offset Channel DEPT FT 4 1 68 0 1 GR MWD020 API 4 1 68 4 2 ROP MWD020 FT/H 4 1 68 8 3 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 3703.5 9445 6574.25 11484 3703.5 9445 GR MWD020 API 11.37 331.77 85.1616 11393 3703.5 9399.5 ROP MWD020 FT/H 0.34 489.57 174.229 11344 3773.5 9445 First Reading For Entire File..........3703.5 Last Reading For Entire File...........9445 File Trailer service name... .......STSLIB.003 service sub Level Name... version Number. ........1.0.0 Date of Generation.......08/06/06 Maximum Physical Record..65535 File Type ................LO Next File Name...........STSLIB.004 Physical EOF File Header Service name... .......STSLIB.004 service sub Level Name... version Number. ........1.0.0 Date of Generation.......08/06/06 Maximum Physical Record..65535 File Type. ............LO Previous File Name.......sTSLIB.003 Comment Record Page 7 • agi-l0a.tapx FILE HEADER FILE NUMBER: 4 RAW MWD Curves and log header data for each bit run in separate files. BIT RUN NUMBER: 3 DEPTH INCREMENT: .5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH STOP DEPTH GR 9400.0 9507.0 RoP 9445.5 9542.0 LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME): TD DRILLER (FT): TOP LOG INTERVAL (FT): BOTTOM LOG INTERVAL (FT): BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: MAXIMUM ANGLE: TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE DGR DUAL GAMMA RAY BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER'S CASING DEPTH (FT): BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S): MUD PH: MUD CHLORIDES (PPM): FLUID LOSS (C3): RESISTIVITY (OHMM) AT TEMPERATURE (DEG F) MUD AT MEASURED TEMPERATURE (MT): MUD AT MAX CIRCULATING TERMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF (IN): EWR FREQUENCY (HZ): REMARKS: Data Format specification Record Data Record Type... ..........0 Data Specification Block Type.....0 06-Nov-06 Insite 72.13 Memory 9542.0 9445.0 9542.0 34.6 34.6 TOOL NUMBER 132482 8.500 9445.0 Fresh water Gel 9.80 49.0 8.9 55000 4.9 .000 .0 .000 110.0 .000 .0 .000 .0 Page 8 • agi-l0a.tapx Logging Direction .................DOwn optical log depth units...........Feet Data Reference Point ..............undefined Frame Spacing....... ............60 .lIN Max frames per record .............undefined Absent value ......................-999 Depth units. .. .. ..... Datum Specification Block sub-type...0 Name service order units size Nsam Rep Code offset Channel DEPT FT 4 1 68 0 1 GR MWD030 API 4 1 68 4 2 ROP MWD030 FT/H 4 1 68 8 3 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 9400 9542 9471 285 9400 9542 GR MWD030 API 20.97 404.86 156.736 215 9400 9507 ROP MWD030 FT/H 6.34 222.05 120.705 194 9445.5 9542 First Reading For Entire File..........9400 Last Reading For Entire File...........9542 File Trailer Service name... .......STSLIB.004 Service Sub Level Name... version Number. ........1.0.0 Date of Generation.......08/06/06 Maximum Physical Record..65535 File TyPe ................L0 Next File Name...........STSLIB.005 Physical EOF File Header Service name... .......STSLIB.005 Service Sub Level~Name... version Number. ........1.0.0 Date of Generation.......08/06/06 Maximum Physical Record..65535 File Type. ............Lo Previous File Name.......STSLIB.004 Comment Record FILE HEADER FILE NUMBER: 5 RAW MWD Curves and log header data for each bit run in separate files. BIT RUN NUMBER: 4 DEPTH INCREMENT: .5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH STOP DEPTH GR 9507.5 9901.5 ROP 9542.5 9937.0 Page 9 i • agi-l0a.tapx LOG HEADER DATA DATE LOGGED: 07-NOV-06 SOFTWARE SURFACE SOFTWARE VERSION: Insite DOWNHOLE SOFTWARE VERSION: 72.13 DATA TYPE (MEMORY OR REAL-TIME): Memory TD DRILLER (FT): 9937.0 TOP LOG INTERVAL (FT): 9542.0 BOTTOM LOG INTERVAL (FT): 9937.0 BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: 33.9 MAXIMUM ANGLE: 35.1 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE TOOL NUMBER DGR DUAL GAMMA RAY 175785 BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): 8.500 DRILLER'S CASING DEPTH (FT): 9445.0 BOREHOLE CONDITIONS MUD TYPE: Polymer MUD DENSITY (LB/G): 8.90 MUD VISCOSITY (s): 49.0 MUD PH: $,g MUD CHLORIDES (PPM): 55000 FLUID LOSS (C3): 7.0 RESISTIVITY (OHMM) AT TEMPERATURE (DEG F) MUD AT MEASURED TEMPERATURE (MT): .000 .O MUD AT MAX CIRCULATING TERMPERATURE: .000 138.2 MUD FILTRATE AT MT: .000 .O MUD CAKE AT MT: .000 .O NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF (IN): EWR FREQUENCY (HZ): REMARKS: Data Format specification Record Data Record Type... ..........0 Data specification Block Type.....0 Logging Direction .................DOwn optical log depth units...........Feet Data Reference Point ..............Undefined Frame Spacing....... ............60 .lIN Max frames per record .............undefined Absent value ......................-999 Depth Units. .. .. ..... Datum specification Block sub-type...0 Name service order units size Nsam Rep code offset channel DEPT FT 4 1 68 0 1 GR MWD040 API 4 1 68 4 2 ROP MWD040 FT/H 4 1 68 8 3 Page 10 ~~ agi-l0a.tapx • First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 9507.5 9938 9722.75 862 9507.5 9938 GR MWD040 API 15.44 133.57 45.0412 789 9507.5 9901.5 ROP MWD040 FT/H 1.38 275.02 105.967 792 9542.5 9938 First Reading For Entire File..........9507.5 Last Reading For Entire File...........9938 File Trailer Service name... .......STSLIB.005 service sub Level Name... version Number. ........1.0.0 Date of Generation.......08/06/06 Maximum Physical Record..65535 File Type ................Lo Next File Name...........STSLI6.006 Physical EOF Tape Trailer Service name .............LISTPE Date . ...................08/06/06 Origin ...................STS Tape Name. .... ........UNKNOWN continuation Number......01 Next Tape Name...........UNKNOWN Comments .................STS LIS Writing Library. Reel Trailer Service name .............LISTPE Date . ...................08/06/06 Ori9in ...................STS Reel Name. .... ........UNKNOWN continuation Number......01 Next Reel Name...........UNKNOWN Comments .................STS LIS writing Library. Physical EOF Physical EOF End Of LIS File scientific Technical services scientific Technical Services Page 11
